UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
x | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 2010
OR
o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from ________ to ________
Commission File No. 001-33016
EAGLE ROCK ENERGY PARTNERS, L.P.
(Exact Name of Registrant as Specified in Its Charter)
Delaware | 68-0629883 | |
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification Number) |
1415 Louisiana Street, Suite 2700
Houston, Texas 77002
(Address of principal executive offices, including zip code)
(281) 408-1200
(Registrant's telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class | Name of Each Exchange on Which Registered | |
Common Units of Limited Partner Interests | NASDAQ Global Select Market | |
Warrants to Purchase Common Units of Limited Partner Interests | NASDAQ Global Select Market |
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No x
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes o No x
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 13(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer o | Accelerated Filer x |
Non-accelerated Filer o | Smaller reporting company o |
(Do not check if a smaller reporting company)
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x
As of June 30, 2010, the aggregate market value of the registrant's common units held by non-affiliates of the registrant was $231,932,846, based on the closing sale price as reported on NASDAQ Global Select Market.
The issuer had 85,162,227 common units outstanding as of March 1, 2011.
DOCUMENTS INCORPORATED BY REFERENCE:
Portions of the registrant's definitive proxy statement for its 2011 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission within 120 days of December 31, 2010, are incorporated by reference into Part III of this report for the year ended December 31, 2010.
TABLE OF CONTENTS
Page | ||
PART I | ||
Item 1. | Business | |
Item 1A. | Risk Factors | |
Item 1B. | Unresolved Staff Comments | |
Item 2. | Properties | |
Item 3. | Legal Proceedings | |
Item 4. | [Removed and Reserved] | |
PART II | ||
Item 5. | Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities | |
Item 6. | Selected Financial Data | |
Item 7. | Management’s Discussion and Analysis of Financial Condition and Results of Operations | |
Item 7A. | Quantitative and Qualitative Disclosures About Market Risk | |
Item 8. | Financial Statements and Supplementary Data | |
Item 9. | Changes in and Disagreements With Accountants on Accounting and Financial Disclosure | |
Item 9A. | Controls and Procedures | |
Item 9B. | Other Information | |
PART III | ||
Item 10. | Directors, Executive Officers and Corporate Governance | |
Item 11. | Executive Compensation | |
Item 12. | Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters | |
Item 13. | Certain Relationships and Related Transactions, and Director Independence | |
Item 14. | Principal Accounting Fees and Services | |
PART IV | ||
Item 15. | Exhibits and Financial Statement Schedules | |
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FORWARD-LOOKING STATEMENTS
This report may include forward-looking statements. All statements, other than statements of historical facts, included in this report that address activities, events or developments that we expect, believe or anticipate will or may occur in the future are forward-looking statements. These statements are based on certain assumptions made by us based on our experience and perception of historical trends, current conditions, expected future developments and other factors we believe are appropriate under the circumstances. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond our control, which may cause our actual results to differ materially from those implied or expressed by the forward-looking statements. For a complete description of these risks, please see our risk factors set forth under Item 1A of this annual report. These factors include but are not limited to:
• | Drilling and geological / exploration risks; |
• | Assumptions regarding oil and natural gas reserve levels and costs to exploit and timing of development; |
• | Volatility or declines in commodity prices; |
• | Hedging activities; |
• | Ability to obtain credit and access capital markets; |
• | Ability to remain in compliance with the covenants set forth in our revolving credit facility; |
• | Conditions in the securities and/or capital markets; |
• | Future processing volumes and throughput; |
• | Loss of significant customers; |
• | Availability and cost of processing and transportation of natural gas liquids (“NGLs”); |
• | Competition in the oil and natural gas industry; |
• | Relevant legislative or regulatory changes, including retroactive royalty or production tax regimes, changes in environmental, health and safety regulation, hydraulic fracturing regulation, environmental risks and liability under federal, state and foreign environmental laws and regulations; |
• | Ability to make favorable acquisitions and integrate operations from such acquisitions; |
• | Shortages of personnel and equipment; |
• | Increases in interest rates; |
• | Creditworthiness of our counterparties; |
• | Weather, including the occurrence of any adverse weather conditions and/or natural disasters affecting our business; |
• | Any other factors that impact or could impact the exploration of oil or natural gas resources, including but not limited to the geology of a resource, the total amount and costs to develop recoverable reserves, legal title, regulatory, natural gas administration, marketing and operations factors relating to the extraction of oil and natural gas; and |
• | Tax risk associated with pass-through investment, including potential reduction in tax shield or creation of phantom income in the event distributions are not enough to support the tax burden. |
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GLOSSARY OF OIL AND GAS TERMS
The following is a description of the meanings of some of the oil and gas industry terms that may be used in this report. The definitions of proved reserves, proved developed reserves, and proved undeveloped reserves have been abbreviated from the applicable definitions contained in Rule 4-10(a) (2-4) of Regulation S-X.
Bbl: One stock tank barrel, or 42 U.S. gallons liquid volume, of crude oil or other liquid hydrocarbons.
Bbl/d: One stock tank barrel, or 42 U.S. gallons liquid volume, of crude oil or other liquid hydrocarbons per day.
Bbtu: One billion British thermal units.
Bcf: One billion cubic feet of natural gas.
Bcf/d: One billion cubic feet of natural gas per day.
Bcfe: One billion cubic feet of natural gas equivalent, using a ratio of six Mcf of natural gas to one Bbl of crude oil and NGLs.
Boe: One barrel of oil equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of crude oil.
Boe/d: One barrel of oil equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of crude oil and NGLs per day.
btu: British thermal unit.
development well: A well drilled within the proved area of a natural gas or oil reservoir to the depth of a stratigraphic horizon known to be productive.
dry gas: Natural gas that does not require plant processing prior to delivery to the interstate or intrastate pipeline systems.
dry hole: A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production would exceed production expenses, taxes and future capital.
equity liquids or gallons: Natural gas liquid and condensate production that equates to an entity's contractual share of the production.
exploitation: A drilling, recompletion, workover or other project which may target proven or unproven reserves (such as probable or possible reserves), but which generally has a lower risk than with exploration projects.
exploratory well: A well drilled to find and produce oil or natural gas reserves in an unproved area, to find new reservoir in a field previously found to be productive or oil or natural gas in another reservoir or to extend a known reservoir.
fee-based arrangements: Under these arrangements, the oil and gas producer pays to the gatherer a fixed cash fee per unit volume for performing the gathering and processing service. This fee is directly related to the volume of natural gas that flows through the gatherer's pipeline systems and is not directly dependent on commodity prices.
fee mineral or fee mineral interest: A perpetual ownership of all or a portion of the oil, natural gas and other naturally-occurring substances that lie beneath the surface of the earth in a specific area.
field: An area consisting of a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
finding and development cost (F&D): Total capital costs, including leasing and exploration expenses, spent to place reserves into production; often expressed as a unit cost, such as $/Mcfe or $/Boe, which are derived by dividing the costs by the reserves.
fixed recovery arrangements: Under these arrangements, raw natural gas is gathered from producers at the wellhead, transported through our gathering system, and processed and sold as processed natural gas and/or NGLs at prices based on published index prices. The price paid to the producers is based on an agreed to theoretical product recovery factor to be applied against the wellhead production and then a percentage of the theoretical proceeds based on an index or actual sales prices multiplied to the theoretical production. To the extent that the actual recoveries differ from the theoretical product recovery factor, this will affect the margin.
frac spread: The difference between the value of the NGLs produced and the cost of the processed gas used to replace the thermal equivalent value of those NGLs in a keep-whole arrangement.
gpm: Gallons of natural gas liquids per million cubic feet of gas.
gross acres or gross wells: The total acres or wells, as the case may be, in which a working interest is owned.
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Hp: Horsepower.
keep-whole arrangements: Under these arrangements, raw natural gas is processed to extract NGLs and pay to the producer the full thermal equivalent volume of raw natural gas received from the producer in the form of either processed natural gas or its cash equivalent. The processors are generally entitled to retain the processed NGLs and to sell them for their account. Accordingly, the margin is a function of the frac spread.
LT/d: Long tons per day.
MBbls: One thousand barrels of crude oil or other liquid hydrocarbons.
MBO/d: One thousand barrels of crude oil or other liquid hydrocarbons per day.
MBoe: One thousand barrels of oil equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of crude oil.
MBoe/d: One thousand barrels of oil equivalent per day.
Mcf: One thousand cubic feet of natural gas.
Mcf/d: One thousand cubic feet of natural gas per day.
Mcfe: One thousand cubic feet of natural gas equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of crude oil and NGLs.
MMBbls: One million barrels of crude oil or other liquid hydrocarbons.
MMBoe: One million barrels of oil equivalent.
MMBtu: One million British thermal units.
MMcf: One million cubic feet of natural gas.
MMcf/d: One million cubic feet of natural gas per day.
natural gas liquids or NGLs: The combination of ethane, propane, isobutane, normal butane and natural gasoline that may be removed from natural gas as a liquid under certain levels of pressure and temperature. Most NGLs are gases at room temperature and pressure.
net acres or net wells: The sum of the fractional working interests owned in gross acres or wells, as the case may be.
NYMEX: New York Mercantile Exchange.
oil: Crude oil and condensate.
overriding royalty or overriding royalty interest: A non-cost bearing interest in the production from a well that is carved out of the working interest. It expires when the underlying oil and/or natural gas lease expires.
percent-of-index arrangements: Under percent-of-index arrangements, we purchase wellhead natural gas at either (i) a percentage discount to a specified index price, (ii) a specified index price less a fixed amount or (iii) a weighted average sales price based on natural gas sales. We then gather and deliver the natural gas to third-party pipelines or process the natural gas and sell the resulting NGLs and residue gas to third parties. Generally, if natural gas is delivered directly into a third-party pipeline we resell the natural gas at the index price or at a different percentage discount to the index price. If we process the natural gas, our revenues and net operating margins increase as the price of NGLs increases relative to the price of natural gas and decrease as the price of NGLs decrease relative to the price of natural gas, resulting in commodity exposure to us that is similar to that of a keep-whole arrangement.
percent-of-proceeds arrangements: Under these arrangements, generally raw natural gas is gathered from natural gas producers at the wellhead, moved through the gathering system, processed and sold as processed natural gas and/or NGLs at prices based on published index prices. The price paid to producers is based on an agreed percentage of one of the following: (i) the actual sale proceeds; and (ii) the proceeds based on an index price.
probable locations: Locations that are near proved undeveloped locations, but do not meet the definition of a proved location.
productive well: A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceeds production expenses and taxes.
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proved developed reserves: Proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods.
proved locations: Locations that geological and engineering data demonstrate with reasonable certainty to recover reserves in future years from known reservoirs under existing economic and operating conditions.
proved reserves: The estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based on future conditions.
proved undeveloped reserves or PUDs: Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.
recompletion: The completion for production of an existing wellbore in another formation from that in which the well has been previously completed.
reserve life index: The number of years required to produce the proved reserves at the current annual production rate.
reservoir: A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reserves.
royalty or royalty interest: A non-cost bearing interest in the production from a well that is created from a mineral interest when the minerals are leased to an operator. The royalty interest generally is retained by the mineral interest owner as part of the compensation for leasing the minerals.
standardized measure: The present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC (using prices and costs in effect as of the date of estimation), less future development, production and income tax expenses, and discounted at 10% per annum to reflect the timing of future net revenue. Standardized measure does not give effect to derivative transactions.
Tcf: One trillion cubic feet of natural gas.
undeveloped acreage: Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas or oil regardless of whether or not such acreage contains proved reserves.
unit development cost (UDC): The capital expenditures required to develop proved reserves per unit of reserves added or transferred from undeveloped acreage non-producing acreage to proved developed producing reserves, expressed in $/Mcfe or $/Boe.
West Texas Intermediate or WTI: Light, sweet crude oil with high API gravity and low sulfur content used as the benchmark for U.S. crude oil refining and trading. NYMEX futures contracts for light, sweet crude oil specify the delivery of WTI at Cushing, Oklahoma.
wet gas: Natural gas that requires plant processing in order to meet the interstate and intrastate gas quality specifications.
working interest: The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property/lease and to receive a share of production.
workover: Operations on a producing well to restore or increase production.
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In this report, unless the context requires otherwise, references to “Eagle Rock Energy Partners, L.P.,” “Eagle Rock,” the “Partnership,” “we,” “our,” “us,” or like terms, refer to Eagle Rock Energy Partners, L.P. and its subsidiaries. References to our “general partner” refer to Eagle Rock Energy GP, L.P., and the general partner of Eagle Rock Energy GP, L.P., Eagle Rock Energy G&P, LLC, both of which became wholly-owned subsidiaries of the Partnership on July 30, 2010. References to “Natural Gas Partners” or “NGP” refer to Natural Gas Partners VII, L.P. and Natural Gas Partners VIII, L.P. in the context of any description of our investors, and in other contexts refer to NGP Energy Capital Management, which manages a series of energy investment funds, including Natural Gas Partners VII, L.P. and Natural Gas Partners VIII, L.P. References to the “NGP Investors” refer to Natural Gas Partners and some of our directors and current and former members of our management team. References to “Holdings” or “Eagle Rock Holdings” refer to Eagle Rock Holdings, L.P., the largest holder of our securities . References to our “Board of Directors” or "Board" refer to the board of directors of the general partner of our general partner.
PART I
Item 1. Business.
Overview
We are based in the United States and are a domestically-focused, growth-oriented limited partnership engaged in the business of (i) gathering, compressing, treating, processing and transporting natural gas; fractionating and transporting natural gas liquids (“NGLs”); and marketing natural gas, condensate and NGLs, which collectively we call our “Midstream Business”; and (ii) acquiring, developing and producing interests in oil and natural gas properties, which we call our “Upstream Business.”
Our objective is to grow our business in a manner that enhances our ability to increase cash distributions to our unitholders. To do so, we focus on achieving operational excellence in our businesses and executing accretive low-risk acquisitions and organic growth opportunities. We also may allocate a portion of our cash flows to fund growth-related capital expenditures that would otherwise be paid as distributions. Our quarterly distribution for 2009 and the first three quarters of 2010 was significantly reduced, as compared to amounts distributed in 2007 and 2008, in order to preserve cash and pay down debt. Following the completion of the Recapitalization and Related Transactions, as defined and discussed below, we increased our distribution to our unitholders for the quarter ended December 31, 2010, as discussed in Part II, Item 5. Market for Registrant's Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities.
We are uniquely positioned as a publicly-traded partnership, or master limited partnership (“MLP”), that is engaged in both the midstream and upstream sectors of the oil and natural gas value chain. We have an experienced management team with expertise in gathering and processing natural gas, operating oil and natural gas properties and assets, and evaluating and executing acquisition opportunities. Generally, our MLP structure gives us a lower cost of capital than a corporation through the avoidance of double taxation of our earnings. Our diversification across our businesses was adopted to broaden the spectrum of potential acquisition opportunities, give us an advantage in acquiring asset packages that involve both midstream and upstream assets, provide us with a natural hedge on a portion of our natural gas volumes in our Upstream Business (to the extent of the volumes of natural gas purchased by us under our natural gas purchase agreements in our Midstream Business that is not offset by our long position in our Midstream Business), and exploit vertical integration synergies in selected regions of our operations.
Our Midstream Business is strategically located in five significant natural gas producing regions: (i) the Texas Panhandle; (ii) East Texas/Louisiana; (iii) South Texas; (iv) West Texas; and (v) the Gulf of Mexico. These five regions are productive, mature, natural gas producing basins that have historically experienced significant drilling activity. Eagle Rock’s natural gas gathering systems within these regions are comprised of approximately 5,482 miles of natural gas gathering pipelines with approximately 2,700 well connections, 19 natural gas processing plants with approximately 737 MMcf/d of plant processing capacity and 220,180 horsepower of compression. Our Midstream Business averaged 499 MMcf/d of gathered volumes and 316 MMcf/d of processed volumes during 2010.
Our Upstream Business has long-lived, high working interest properties located in four significant natural gas producing regions: (i) Southern Alabama (where we also operate the associated gathering and processing assets); (ii) East Texas; (iii) South Texas; and (iv) West Texas. As of December 31, 2010, these working interest properties included 273 operated productive wells and 137 non-operated wells with net production to us of approximately 5,017 Boe/d and proved reserves of approximately 38.4 Bcf of natural gas, 8.7 MMBbls of crude oil, and 6.2 MMBbls of natural gas liquids, of which 89% are proved developed.
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On May 24, 2010, as part of the Recapitalization and Related Transactions (discussed below), we sold our Minerals Business, which had been reported as a separate segment in prior filings. As a result of the sale, financial information related to the Minerals Business for 2010 has been classified as discontinued operations and financial information for previous years has been retrospectively adjusted to classify assets and liabilities as held-for-sale and operations as discontinued. For a further discussion of the sale of our Minerals Business, see Note 19 to our consolidated financial statements included in Part II, Item 8. Financial Statement and Supplementary Data starting on page F-1 of this Annual Report.
We report on our businesses in six accounting segments. See Note 13 of our consolidated financial statements included in Part II, Item 8. Financial Statements and Supplementary Data starting on page F-1 of this Annual Report.
Ownership Structure
The diagram below depicts our ownership structure as of March 1, 2011. The ownership percentages shown below are calculated on a fully-diluted basis:
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(a) | For a discussion of management's ownership, see Part III, Item 12 -Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters, incorporating by reference our to-be-filed proxy statement for our 2011 Annual Meeting of Unitholders. |
(b) | "NGP Parties" refers collectively to Natural Gas Partners VII, L.P., a Delaware limited partnership, Natural Gas Partners VIII, L.P., a Delaware limited partnership, Montierra Minerals & Production, L.P., a Texas limited partnership, Montierra Management LLC, a Texas limited liability company, Eagle Rock Holdings, L.P., a Texas limited partnership, and NGP Income Management, LLC, a Texas limited liability company. For a discussion of certain management's ownership in the Montierra entities, see Part III, Item 12 -Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters, incorporating by reference our to-be-filed proxy statement for our 2011 Annual Meeting of Unitholders. |
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Recapitalization and Related Transactions
In December 2009, we entered into (i) a Securities Purchase and Global Transaction Agreement with NGP, and (ii) a Purchase and Sale Agreement (the “Minerals Business Sale Agreement”) with Black Stone Minerals Company, L.P. ("Black Stone") for the sale of our Minerals Business. The Securities Purchase and Global Transaction Agreement was amended and restated on January 12, 2010 to allow for greater flexibility in the payment of a contemplated transaction fee to Eagle Rock Holdings, L.P. ("Holdings"), which is controlled by NGP (we refer to the amended Securities Purchase and Global Transaction Agreement throughout this document as the “Global Transaction Agreement”).
On May 21, 2010, a majority of our unitholders who were not affiliated with our general partner approved, among other things, the Global Transaction Agreement, which contemplated a series of transactions including:
• | the simplification of our capital structure through the contribution, and resulting cancellation, of our incentive distribution rights and 20,691,495 subordinated units held by Holdings, which occurred on May 24, 2010; |
• | the sale of all of our fee mineral and royalty interests, as well as our equity investment in Ivory Working Interests, L.P., (collectively "the Minerals Business") to Black Stone, which was completed on May 24, 2010 and for which we received net proceeds of $171.6 million. We retained approximately $2.9 million of cash received from net revenues received from the Minerals Business after the effective date of the sale, making our total proceeds from the Minerals Business $174.5 million from January 1, 2010 through the date of sale; |
• | a rights offering, which was launched on June 1, 2010 and expired on June 30, 2010, and for which we received gross proceeds of $53.9 million and issued 21,557,164 common units and 21,557,164 warrants; |
• | an option, exercisable by the issuance of 1,000,000 newly-issued common units to Holdings, to capture the value of the controlling interest in us through (a) acquiring our general partner entities from Holdings and immediately thereafter eliminating our 844,551 outstanding general partner units owned by Holdings and (b) reconstituting our Board to allow our common unitholders not affiliated with NGP to elect the majority of our directors (the "GP Acquisition Option"). On July 30, 2010, we completed the GP Acquisition Option, and our board of directors was expanded to include two additional independent directors who were appointed by the conflicts committee on July 30, 2010; and |
• | the obligation of NGP, at the sole discretion of our conflicts committee, to purchase up to $41.6 million of our common units at a price of $3.10 per unit. Our conflicts committee subsequently determined that it was not in our best interests to require NGP to purchase equity at the $3.10 per unit price, and the obligation expired on September 21, 2010. |
Business Strategies
Our primary business objective is to increase our cash distribution per unit potential over time. We intend to accomplish this objective by continuing to execute the following business strategies:
• | Expanding our operations through organic growth projects. In our Midstream Business, we intend to leverage our existing infrastructure and customer relationships by expanding our existing asset base to meet new or increased demand for midstream services. We also look for opportunities to invest in attractive “Greenfield” projects in areas outside our existing asset base. In our Upstream Business, we intend to continue to identify and execute infill drilling and recompletion opportunities as the primary source of organic growth. We employ sound petroleum engineering practices to identify and quantify these opportunities, and we pursue the opportunities in a manner that reduces risk and cost. We measure the success of these projects by unit development cost and internal rate of return. We currently target an 18% internal rate of return or higher for our Midstream Business's projects and commercial contracts and a 20% internal rate of return or higher for our Upstream Business's infill drilling, recompletion and workover activities. |
• | Pursuing acquisitions. We continue to employ an acquisition strategy that capitalizes on the operational experience of our management team as well as bringing new expertise to the Partnership. Strategically, we focus our acquisition efforts on midstream and upstream assets which we believe are best-suited to accomplish our objective of growing our distributable cash flow. |
In our Midstream Business, we generally seek to acquire assets that: (i) serve producing areas with high levels of drilling activity; (ii) have a stable contract mix profile characterized by relatively low commodity price exposure and relatively long contract terms; (iii) are complementary to our existing asset base and which provide operating cost savings, diversified market outlets and a diversified customer base; and (iv) allow us to serve as operator, which gives us greater flexibility with respect to future capital investments and allows us to better manage the associated risks.
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In our Upstream Business, we generally seek to acquire assets that: (i) have shallow decline rates; (ii) have at least 50 percent or more of developed producing reserves; (iii) have meaningful low to medium risk development opportunities; (iv) contain a mix of oil and natural gas current production and future reserves; (v) serve attractively priced markets; (vi) produce from numerous wellbores so as to minimize the impact of a single negative well event; and (vii) allow us to serve as operator of a substantial portion of current and future production and reserves, which gives us greater flexibility with respect to future capital investments and allows us to better manage the associated risks.
The primary measures we use to assess the success of our acquisition program are sustained accretion and internal rate of return.
• | Maximizing the profitability of our existing assets. In our Midstream Business, we intend to maximize the profitability of our existing assets by marketing to, and contracting with, new customers to add new volumes of natural gas to our gathering and processing assets under economically favorable terms. We strive to provide superior customer service while undertaking additional initiatives to enhance utilization, minimize excess processing capacity, and improve operating margins and efficiencies across our midstream assets. We also seek to realize higher net realized prices for our producer customers' and our equity production of natural gas, natural gas liquids, condensate and crude oil through our marketing efforts, which include taking steps to access premium end markets and to improve product quality. In our Upstream Business, we strive to improve the recoveries of oil and natural gas from our existing wellbores, as well as focus on reducing our overall and per unit operating expenses. We manage our assets to maximize the amount of hydrocarbons and valuable by-products we can profitably extract. We attempt to maintain constant or slightly growing production rates and cash flows. The performance measures we use to assess the success of our asset performance and production enhancement activities are increased throughput volumes, improved run times on our equipment, internal rate of return and unit operating cost. |
• | Maintaining a disciplined financial policy. We will pursue a disciplined financial policy by maintaining a prudent capital structure and managing our exposure to interest rate and commodity price risk. We target a total leverage ratio, both from a total company perspective and as defined in our revolving credit facility, of 3.50 or less on a sustained basis. Maintaining a balanced capital structure may allow us to use our available capital to selectively pursue accretive investments or acquisition opportunities. |
• | Continuing to reduce our exposure to commodity price risk. We intend to continue to operate our business in a manner that reduces our exposure to commodity price risk in the near term and on an opportunistic basis over the long term. We manage our portfolio of equity volumes from our two lines of business as a single portfolio. As a result, the volumes of natural gas that we purchase in conjunction with our midstream keep-whole arrangements are more than offset by our long natural gas position associated with midstream percent-of-proceeds arrangements and natural gas production from our upstream assets. We use a variety of hedging instruments to accomplish our risk management objectives. We actively monitor our hedge portfolio for opportunities to enter into additional hedges to support our cash flow objectives. Our hedging strategy also may include resetting existing hedges to higher price levels in order to meet our cash flow requirements, stay in compliance with our credit facility covenants and continue to execute on our distribution objectives. |
Competitive Strengths
We believe that we are well positioned to execute our business strategies successfully because of the following competitive strengths:
• | We have a diversified business model. The combination of our Midstream and Upstream Businesses along the oil and gas value chain provides us with significant benefits. While the Midstream Business provides us with relatively stable, and potentially growing, throughput volumes and cash flows, the performance of gathering and processing assets is tied, among other things, to our gas-producing customers’ drilling plans, well performance and financial situation. Each of these factors is beyond our control. In contrast, in our Upstream Business we are able to manage our infill drilling plans, recompletion and workover activities to varying degrees with a company-wide view of maximizing and/or stabilizing our overall cash flow. |
An additional benefit to our diversified business model is our ability to target acquisition opportunities which include assets or properties in two or more of our segments and potentially in two or more of our businesses. This provides us with a competitive advantage against other potential single-focus bidders, as we are able and willing to assign value
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and identify potential operational improvements of all the assets included in the package.
• | We have an experienced, knowledgeable management team with a proven record of performance. Our management team has a proven record of enhancing value through the investment in, and the acquisition, exploitation and integration of, natural gas midstream and upstream assets. Our senior management team has an average of approximately 20 years of industry-related experience and a substantial economic interest in us through direct ownership of our common units and, in certain cases, indirect ownership through Holdings and Montierra Minerals & Production, L.P. ("Montierra"). Our senior management team’s extensive experience and contacts within the energy industry provide a strong foundation for managing and enhancing our operations, accessing strategic acquisition opportunities and constructing new assets. We have a staff of engineers, commercial, operational and support staff who are experts at drilling and operating oil and gas wells and managing gathering and processing assets. |
• | We have a highly flexible and low cost credit facility in place. We currently have an $871 million senior secured revolving credit facility that expires in December 2012, carries an attractive borrowing rate and offers us financial flexibility. The credit facility accommodates, through the use of a borrowing base for our Upstream Business and traditional cash-flow based covenants for our Midstream Business, the allocation of indebtedness to either our Upstream Business (to be measured against the borrowing base) or to our Midstream Business (to be measured against the cash-flow based covenant). As of December 31, 2010, we had a well-diversified lender group consisting of 19 domestic and international financial institutions with the highest concentration in any one financial institution being 13.9% of aggregate commitments. We have the ability to upsize total commitments by an additional $19.5 million, in addition to the $180 million upsizing we executed during 2008. As of December 31, 2010, we had approximately $341 million of available capacity under our credit facility based on total commitments. |
• | We are affiliated with NGP. Founded in 1988, Natural Gas Partners represents a $7.2 billion family of investment funds organized to make direct equity investments in private energy enterprises. Natural Gas Partners owns a significant equity position in us through Holdings,, Montierra, and several funds. For more information see Part III, Item 12. " Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters." Historically, we have benefited from increased exposure to acquisition opportunities through our affiliation with Natural Gas Partners, including the consummation of several transactions with portfolio companies of Natural Gas Partners. We expect that our relationship with Natural Gas Partners will continue to provide us with several significant benefits, including increased exposure to acquisition opportunities and access to a significant group of transactional and financial professionals with a successful track record of investing in energy assets. |
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History
Our Partnership, formed in May 2006, is the legal successor to Eagle Rock Pipeline, L.P. (“Eagle Rock Pipeline”) as a result of our initial public offering in October 2006. We have historically grown through acquisitions and organic growth projects.
The following is a table that depicts our acquisitions/dispositions by date, transaction type, cost, financing sources and business over the past five years:
Table of Acquisitions/Dispositions in the Past Five Years
Closing Date | Transactions | Amount ($ in Millions) | Financing Sources ($ in Millions) | Business | ||||||||||||||||||||
Cash | Debt | Equity to Sellers | Cash from private equity/ PIPEs(a) | |||||||||||||||||||||
Acquisitions: | ||||||||||||||||||||||||
3/31/06 & 4/07/06 | Brookeland Acquisition | $ | 95.8 | $ | — | $ | — | $ | — | $ | 98.3 | Midstream | ||||||||||||
6/2/2006 | Midstream Gas Services Acquisition | $ | 25.0 | $ | 4.7 | $ | — | $ | 20.3 | $ | — | Midstream | ||||||||||||
4/30/2007 | Montierra Acquisition | $ | 139.2 | $ | — | $ | — | $ | 133.8 | $ | 5.4 | Minerals | ||||||||||||
5/3/2007 | Laser Acquisition | $ | 142.6 | $ | — | $ | — | $ | 29.2 | $ | 113.4 | Midstream | ||||||||||||
6/18/2007 | MacLondon Acquisition | $ | 18.2 | $ | 0.1 | $ | — | $ | 18.1 | $ | — | Minerals | ||||||||||||
7/31/2007 | Escambia Acquisition | $ | 241.8 | $ | — | $ | 113.0 | $ | 17.2 | $ | 111.6 | Upstream | ||||||||||||
7/31/2007 | Redman Acquisition | $ | 192.8 | $ | — | $ | — | $ | 108.2 | $ | 84.6 | Upstream | ||||||||||||
4/30/2008 | Stanolind Acquisition | $ | 81.9 | $ | 5.9 | $ | 76.0 | $ | — | $ | — | Upstream | ||||||||||||
10/1/2008 | Millennium Acquisition | $ | 212.9 | $ | 7.2 | $ | 176.4 | $ | 29.3 | $ | — | Midstream | ||||||||||||
9/30/2010 | Indigo Acquisition | $ | 4.1 | $ | 4.1 | $ | — | $ | — | $ | — | Upstream | ||||||||||||
10/19/2010 | Centerpoint Acquisition | $ | 27.0 | $ | 27.0 | $ | — | $ | — | $ | — | Midstream | ||||||||||||
Dispositions: | ||||||||||||||||||||||||
5/24/2010 | Minerals Business Disposition | $ | 174.5 | $ | 174.5 | — | — | — | Minerals | |||||||||||||||
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(a) Private Investment in Public Equity (“PIPE”) by institutional investors.
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The following is a table that depicts our organic growth projects by date, project, cost, and reportable segment over the past five years:
Table of Significant Organic Growth Projects in the Past Five Years
Date | Project | Cost ($ in Millions) | Segment | |||||
Midstream: | ||||||||
Q1 2006 | Tyler County Pipeline | $ | 8.0 | East Texas | ||||
Q3 2006 | Quinduno Pipeline connecting East to West | 3.1 | Panhandle | |||||
Q1 2007 | Tyler County Pipeline Extension | 24.2 | East Texas | |||||
Q2 2007 | Red Deer Processing Plant Construction | 16.2 | Panhandle | |||||
Q3 2008 | Stinnett-Cargray Consolidation Project | 6.1 | Panhandle | |||||
Q4 2010 | Phoenix Plant | 24.3 | Panhandle | |||||
Q4 2010 | Roberts County Compressor Station | 1.7 | Panhandle | |||||
Q4 2010 | Cargray Stabilizer | 2.2 | Panhandle | |||||
Upstream: | ||||||||
2008 | Drilling projects | 6.5 | Upstream | |||||
2009 | Drilling projects | — | Upstream | |||||
2010 | Drilling projects | 9.3 | Upstream | |||||
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The following graph depicts our historical trends in Adjusted EBITDA and quarterly distribution rate per common unit from our initial public offering on October 24, 2006 to December 31, 2010:
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Note: Q4 2006 represents a prorated distribution to the common unitholders from the IPO date of October 24, 2006 through December 31, 2006. In addition, "hedge resets " (as defined below) contributed $4.2 million, $46.8 million and $2.2 million to Adjusted EBITDA for the fourth quarter 2008, the year ended December 31, 2009 and the first quarter of 2010, respectively.
For a definition of Adjusted EBITDA and reconciliation to GAAP, see Part II, Item 6. Selected Financial Data-Non-GAAP Financial Measures.
From the time of our initial public offering through the third quarter of 2008, we increased our Adjusted EBITDA and the distribution per unit paid to our unitholders. Our financial results during this period benefited from our acquisition activity, as described above, and from the positive impact of increasing commodity prices, including the resulting increased producer drilling activity in our core Midstream Business areas. Beginning in the third quarter of 2008, however, commodity prices began to fall significantly. This downward trend in commodity prices continued throughout the first quarter of 2009, and resulted in a substantial slowdown in the drilling activity of virtually all the major producer customers of our Midstream Business. Against this backdrop of declining midstream volumes and cash flows, our board of directors elected to substantially reduce our distribution beginning with the distribution with respect to the first quarter of 2009 and continuing through the distribution for the first three quarters of 2010. This decision was made in order to enhance our liquidity and financial flexibility, and to avoid breaching the covenants in our revolving credit facility. Due to our enhanced liquidity position resulting from the Recapitalization and Related Transactions, our debt reduction efforts and improved economic conditions, we increased our distribution for the fourth quarter of 2010, and it is our current intention to recommend to our board of directors further quarterly increases in the distribution throughout 2011 with the intention of reaching an annualized $.75/ unit distribution by the distribution for the fourth quarter of 2011. Our Adjusted EBITDA benefited substantially in 2009 from our hedge portfolio, including from “hedge resets,” in which we pay our hedge counterparties to increase the strike price of existing swaps. Such hedge resets contributed approximately $46.8 million to our Adjusted EBITDA in 2009 and contributed $4.2 million and $2.2 million in 2008 and 2010, respectively.
An investment in our common units involves risks associated with our business, regulatory and legal matters, our limited partnership structure and the tax characteristics of our common units. Please read carefully the risks described under Part I, Item 1A. Risk Factors.
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Our Two Lines of Business and Our Six Reporting Segments
Midstream Business
Midstream Industry Overview
General. Raw natural gas produced from the wellhead is gathered and delivered to a processing plant or markets located near the production field, where it is treated, dehydrated, and/or processed. Processing natural gas involves the separation and treating of raw natural gas resulting in a pipeline quality natural gas, primarily methane, mixed NGLs and condensate for sale. Natural gas treating entails the removal of impurities, such as water, sulfur compounds, carbon dioxide and nitrogen. Interstate and intrastate pipelines deliver the processed natural gas to markets. Mixed NGLs are typically transported via NGL pipelines or by truck to a fractionator which separates the NGLs into its components such as ethane, propane, normal butane, isobutane and natural gasoline. The component NGLs are then sold to end users.
The following diagram shows the process of gathering, processing, marketing and transporting natural gas, NGLs and condensate.
_________________________Note: The shaded area above represents processes in which we are directly involved in our Midstream Business and for which we own the underlying assets.
Gathering. A gathering system typically consists of a network of small diameter pipelines and a compression system which together collect natural gas from producing wells and delivers it to larger pipelines for further transportation. We own and operate large gathering systems in four geographic regions of the United States.
Compression. Gathering systems are operated at design pressures that seek to maximize the total throughput volumes from all connected wells. Since wells produce at progressively lower field pressures as they age, the raw natural gas must be compressed to deliver the remaining production against higher pressure that exists in the connected gathering system or transport pipelines. Natural gas compression is a mechanical process in which a volume of natural gas at a lower pressure is boosted, or compressed, to a desired higher pressure, allowing natural gas that no longer naturally flows into a higher pressure downstream pipeline to be brought to market. Field compression is used to lower the wellhead pressure while maintaining the exit pressure of a gathering system to deliver natural gas into higher pressure downstream pipelines. We own and operate compression on a number of our systems.
Treating and processing. Raw natural gas produced at the wellhead is often unsuitable for pipeline transportation or commercial use and must be processed and/or treated to remove the heavier hydrocarbon components and/or contaminants. The principal components of pipeline-quality natural gas are methane and ethane, but most raw natural gas also contains
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varying amounts of heavier hydrocarbon components (such as propane, normal butane, isobutane, and natural gasoline) and impurities, such as water, sulfur compounds, carbon dioxide, or nitrogen. We own and operate natural gas processing and/or treating plants in five geographic regions.
Fractionation. NGL fractionation facilities separate mixed NGL streams into discrete NGL products: ethane, propane, normal butane, isobutane and natural gasoline. Ethane is primarily used in the petrochemical industry as feedstock for ethylene, one of the basic building blocks for a wide range of plastics and other chemical products. Propane is used both as a petrochemical feedstock and as a heating fuel, an engine fuel and an industrial fuel. Normal butane is used as a petrochemical, and as a blend stock for motor gasoline. Isobutane is typically fractionated from mixed butane (a stream of normal butane and isobutane in solution), principally for use in enhancing the octane content of motor gasoline. Natural gasoline, a mixture of pentanes and heavier hydrocarbons, is used primarily as motor gasoline blend stock or petrochemical feedstock. We operate a fractionation facility to produce propane at one of our facilities in the Texas Panhandle Segment. In our Gulf of Mexico Segment we own a 1.67% interest in the Tebone Fractionator, a fractionation facility operated by Enterprise Products Partners L.P. in southern Louisiana, acquired as a part of our Millennium Acquisition.
Condensate Stabilization. Natural gas condensate is a low-density mixture of hydrocarbon liquids found in the raw natural gas stream. Condensate stabilization is a process by which the vapor pressure of the condensate is reduced by removing the lighter hydrocarbons, which are retained and sold. The remaining condensate with lower vapor pressure is better positioned to meet transportation and end-user specifications. We own and operate condensate stabilization facilities in our Texas Panhandle Segment.
Marketing. Natural gas marketing involves the sale of the pipeline-quality natural gas either produced by processing plants or purchased from gathering systems or other pipelines. NGL marketing involves the sale of the unfractionated or y-grade products or fractionated products recovered at the processing plants. We market natural gas, NGLs and condensate for our own account and for the benefit of certain of our producer customers in our Midstream Business and for certain working interest owners in our Upstream Business. In the fourth quarter of 2010, we created a marketing subsidiary to develop, implement, and launch marketing uplift strategies surrounding crude and condensate in Alabama and in the Texas Panhandle. Strategies include marketing, transportation, and product blending to enhance product net-back prices. Currently, our Marketing subsidiary does not own marketing related natural gas or natural gas liquid pipelines, storage or other transportation assets, nor do we utilize financial derivatives in the marketing of our products.
Transportation. Natural gas transportation consists of moving pipeline-quality natural gas from gathering systems, processing plants and other pipelines and delivering it to wholesalers, utilities and other pipelines. Other than our North and Central systems, we do not own any natural gas transportation assets. NGL transportation consists of moving the raw natural gas stream to fractionation facilities and discrete NGL products to end markets. We own NGL transportation assets in our East Texas/Louisiana Segment. Condensate is typically transported locally by truck and aggregated into storage tanks before being delivered to end markets via a range of transportation alternatives, including truck, rail, barge or pipeline.
Natural gas is gathered and processed in the industry pursuant to a variety of arrangements generally categorized (by the nature of the commodity price risk) as fee-based, percent-of-proceeds, fixed recovery, percent-of-index and keep-whole, described in greater detail as follows:
• | Fee-Based Arrangements. Under these arrangements, we generally are paid a fixed cash fee per unit volume for performing the gathering and processing service. This fee is directly related to the volume of natural gas that flows through our systems and is not directly dependent on commodity prices. A sustained decline, however, in commodity prices could result in a decline in volumes and, thus, a decrease in fee revenues. These arrangements provide stable cash flows, but minimal, if any, upside in higher commodity price environments. |
• | Percent-of-Proceeds Arrangements. Under these arrangements, generally raw natural gas is gathered from producers at the wellhead, moved through the gathering system, and processed and sold at prices based on published index prices. Producers are paid a portion of the sale price. These arrangements provide upside in high commodity price environments, but result in lower margins in low commodity price environments. The price paid to producers is based on an agreed percentage of the products produced multiplied by one of the following: (i) the actual sale price; or (ii) the index price. Contracts in which the gatherer/processor shares only in specified percentages of the proceeds from the sale of NGLs and in which the producer receives 100% of the proceeds from natural gas sales, are referred to as “percent-of-liquids” arrangements. Under percent-of-proceeds arrangements, the margin correlates directly with the prices of natural gas and NGLs; under percent-of-liquids arrangements, the margin correlates directly with the price of NGLs. |
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• | Fixed Recovery Arrangements. Under these arrangements, raw natural gas is gathered from producers at the wellhead, moved through our gathering system and processed and sold as processed natural gas and/or NGLs at prices based on published index prices. The price paid to the producers is calculated as the product of an agreed theoretical product recovery factor and an index price or the actual sales price. To the extent that the actual recoveries differ from the theoretical product recovery factor, the margin the processor receives will be affected. These arrangements provide upside in high commodity price environments, but result in lower margins in low commodity price environments. |
• | Percent-of-Index Arrangements. Under percent-of-index arrangements, we purchase wellhead natural gas at either (i) a percentage discount to a specified index price, (ii) a specified index price less a fixed amount or (iii) a weighted average sales price based on natural gas sales. We then gather and deliver the natural gas to third-party pipelines or process the natural gas and sell the resulting NGLs and residue gas to third parties. Generally, if natural gas is delivered directly into a third-party pipeline we resell the natural gas at the index price or at a different percentage discount to the index price. If we process the natural gas, our revenues and net operating margins increase as the price of NGLs increases relative to the price of natural gas and decrease as the price of NGLs decrease relative to the price of natural gas, resulting in commodity exposure to us that is similar to that of a keep-whole arrangement. |
• | Keep-Whole Arrangements. Under these arrangements, raw natural gas is processed to extract NGLs, and the processor pays the producer the full thermal equivalent volume of raw natural gas received from the producer in the form of either processed natural gas or its cash equivalent. Processors are generally entitled to retain the processed NGLs and to sell them for their account. Margin is a function of the difference between the value of the NGLs produced and the cost of the natural gas needed to replace the thermal equivalent volume of natural gas used in processing (i.e. the frac spread). The profitability of these arrangements is subject not only to the commodity price risk of natural gas and NGLs, but also to the price of natural gas relative to NGL prices. These arrangements can provide improved profit margins in favorable commodity price environments, but also can be subject to losses if the cost of natural gas exceeds the value of its thermal equivalent of NGLs. Many keep-whole arrangements include provisions that reduce commodity price exposure, including (i) conditioning floors that require the keep-whole arrangements to convert to a fee-based arrangement if the NGLs have a lower value than their thermal equivalent in natural gas, (ii) discounts to the applicable natural gas index price used to reimburse the producer an amount in cash for the thermal equivalent volume of raw natural gas acquired from the producer, or (iii) fixed cash fees for ancillary services, such as gathering, treating and compressing. |
Midstream Business Overview
We own natural gas gathering and processing assets in five significant natural gas producing regions: the Texas Panhandle, East Texas/Louisiana, West Texas, South Texas and the Gulf of Mexico. During 2010, we remained focused on contracting new gas to our systems and continuing our cost reduction efforts. We executed on a number of large and small organic growth projects during the 2010 calendar year which included installing the Phoenix-Arrington Ranch cryogenic plant (the "Phoenix Plant") in the Texas Panhandle, additional gathering lines in East Texas and compressors where drilling activity was occurring. Our Phoenix Plant provides us the increased processing capacity to handle production in those areas where our producer customers are drilling liquids-rich hydrocarbons in the Granite Wash and Cleveland Plays of the Texas Panhandle. Our acquisition of the East Hemphill System from Centerpoint Energy Field Services ("CEFS") links our producer customers' Granite Wash production to our Phoenix Plant. We are also continuing to gather liquids-rich production from the Austin Chalk Play and delivering it to our Brookeland System in East Texas.
Within our geographic areas of operation, we strive to be a competitive and low cost natural gas gatherer and processor. To achieve this end, we coordinate the operations and commercial activities of our gathering and processing assets to provide better customer service. From an operations perspective, our key strategy is to provide our customers safe and reliable service at reasonable costs and to improve our competitiveness through more efficient operations to assist in securing new customers. From a commercial perspective, our focus is to assist our customers in maximizing the value of their production by providing options and capacity for the movement and marketing of their natural gas and natural gas liquids. We are well positioned to take advantage of expansion opportunities in the Texas Panhandle Granite Wash play and in East Texas for the Haynesville, James Lime and Petit plays in Angelina and Nacogdoches counties and the Austin Chalk play in Tyler, Polk, Newton and Jasper counties. We gather and process natural gas pursuant to a variety of arrangements generally categorized (by the nature of the commodity price risk) as fee-based, percent-of-proceeds, fixed recovery, percent-of-index or keep-whole, as described more fully under “Midstream Industry Overview” above. As of December 31, 2010, the percentage of natural gas throughput volumes under various contractual arrangements were 8% fixed recovery, 26% fee-
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based, 51% percent-of-proceeds and 15% percent-of-index.
As of December 31, 2010, our Midstream Business consists of the following:
Asset | Length (miles) | Available Compression (Horsepower) | Processing Plant Through-put Volume Capacity (MMcf/d) | ||||||
Texas Panhandle Segment | 3,963 | 141,000 | 180 | ||||||
East Panhandle System | 1,320 | 65,000 | 119 | ||||||
Canadian cryogenic plant and gathering system | 359 | 25 | |||||||
Phoenix-Arrington Ranch Plant cryogenic plant ("Phoenix Plant") and gathering system | 537 | 50 | |||||||
Red Deer cryogenic plant (a)(b) | n/a | 24 | |||||||
Roberts County refrigeration plant and gathering system (a)(c) | 14 | 20 | |||||||
System 97 gathering system (d) | 77 | n/a | |||||||
Buffalo Wallow gathering system (d) | 113 | n/a | |||||||
East Hemphill | 220 | n/a | |||||||
West Panhandle System | 2,643 | 76,000 | 61 | ||||||
Cargray cryogenic plant and gathering system (a) | 905 | 30 | |||||||
Gray cryogenic plant and gathering system (a) | 615 | 20 | |||||||
Lefors cryogenic plant and gathering system | 663 | 11 | |||||||
Stinnett gathering system | 451 | n/a | |||||||
Turkey Creek gathering system | 9 | n/a | |||||||
East Texas/Louisiana Segment | 1,213 | 49,700 | 188 | ||||||
Brookeland cryogenic plant and gathering system | 404 | 100 | |||||||
Indian Springs cryogenic plant (25% non-operated) and Camp Ruby gathering system (20% non-operated) (e) | n/a | 36 | |||||||
Tyler County gathering system | 75 | n/a | |||||||
Panola gathering system (a) | 33 | n/a | |||||||
Quitman gathering system | 51 | n/a | |||||||
Rosewood JT plant and gathering system (a) | 36 | 10 | |||||||
Vixen gathering system (d) | 7 | n/a | |||||||
Belle Bower JT plant and gathering system (a) | 68 | 20 | |||||||
Simsboro gathering system (d) | 30 | n/a | |||||||
Sligo gathering system (d) | 10 | n/a | |||||||
ETML gathering system and JT Plant (d) | 221 | 15 | |||||||
Douglas East gathering system (d) | 14 | n/a | |||||||
BGS gathering system (d) | 28 | n/a | |||||||
Robertson County gathering system (d) | 34 | n/a | |||||||
North JT plant and gathering system | 85 | 5 | |||||||
Central JT plant and gathering system | 102 | 2 | |||||||
New Ulm gathering system | 15 | n/a | |||||||
South Texas Segment | 266 | 15,300 | 87 | ||||||
Phase 1 gathering system | 70 | n/a | |||||||
Raymondville gathering system (a) | 48 | n/a | |||||||
Raymondville JT plant | n/a | 40 | |||||||
San Ignacio gathering system (a) | 6 | n/a | |||||||
TGP McAllen JT plant and gathering system | 13 | 40 | |||||||
Merit JT plant | n/a | 7 | |||||||
Wildhorse gathering system | 113 | n/a | |||||||
Sweeny gathering system (50% non-operated) | 16 | n/a | |||||||
Gulf of Mexico Segment | 40 | 14,180 | 282 | ||||||
Yscloskey refrigerated lean oil plant (11.45% non-operated) (f) | n/a | 212 | |||||||
North Terrebonne refrigerated lean oil plant (1.67% non-operated) (f) | n/a | 70 | |||||||
Tebone Fractionator (1.67% non-operated) (g) | n/a | n/a | |||||||
Galveston Bay gathering (50% non-operated) | 12 | n/a | |||||||
CMA Pipeline segments (non-operated) | 28 | n/a | |||||||
TOTAL Midstream Businesses | 5,482 | 220,180 | 737 | ||||||
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(a) The plant is owned by us, but we lease the plant site.
(b) The plant processes gas from the Canadian gathering system.
(c) The Roberts County Plant has 21 MMcf/d of capacity but currently only has installed compression to process 20 MMcf/d.
(d) The systems gather dry natural gas that does not require processing to meet pipeline hydrocarbon dew point quality specifications.
(e) Our net plant capacity is based on the plant expansion to 145 MMcf/d total capacity in February 2008.
(f) Our ownership capacity is subject to change in January, in the case of North Terrebonne, and in September, in the case of Yscloskey each year for the upcoming year based upon the ratio of our equity gas and/or natural gas liquids volumes to the total equity gas and/or natural gas liquids volumes processed and/or produced at the plant for the immediately preceding year. The capacity shown is net to our ownership share. Our ownership interest in Yscloskey changed in September 2010 to 11.45% from 13.78%. Our ownership interest in North Terrebonne changed in January 2011 to 2.63%.
(g) The Tebone Fractionator has 30,000 Bbl/d of capacity. Our ownership share is tied to our ownership percentage in the North Terrebonne Plant which changed to 2.63% in January 2011.
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The following graph depicts plant processing capacity and utilization by month and includes the October 2008 Millennium Acquisition, the shutdown and consolidation of the Stinnett Plant into the Cargray Plant in July 2008, and the start-up of the Phoenix Plant in 2010 (as discussed further below). The volumes shown include only the gas volumes that we gathered that required processing in order to meet the interstate or intrastate gas quality specifications (we refer to such natural gas as wet gas) and excludes the gas volumes that we gathered that did not require plant processing prior to delivery to the interstate or intrastate pipeline systems (we refer to such natural gas as dry gas).
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Note. The reduction in plant capacity in July 2008 was due to the shutdown of the Panola JT Plant. The significant increase in processing capacity in October 2008 was due to the addition of our share of the North Terrebonne Plant and the Yscloskey Plant acquired through the Millennium Acquisition. Both plants were impacted by hurricanes Ike and Gustav. The North Terrebonne Plant returned to operations in November 2008. The Yscloskey Plant did not restart until January 2009. The reduction in plant capacity in September 2009 and October 2010 was due to the adjustment of plant ownership at the Yscloskey Plant.
Texas Panhandle Segment
Our Texas Panhandle Segment covers ten counties in Texas and two counties in Oklahoma and consists of our East Panhandle System and our West Panhandle System. The facilities are primarily located in Wheeler, Hemphill, Roberts, Moore, Potter, Hutchinson, Carson, Gray and Collingsworth Counties. Through these systems, we offer midstream wellhead-to-market services, including gathering, compressing, treating, processing and selling of natural gas and fractionating and selling of NGLs. The Texas Panhandle Segment averaged gathered volumes for the fourth quarter of 2010 of approximately 132.3 MMcf/d. As of December 2010, Chesapeake Energy and Cimarex Energy Co. (formerly Prize Operating Company) represented 19% and 12%, respectively, of the total volumes of our Texas Panhandle Segment. The following is a map of our Texas Panhandle Segment.
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15
Below is a graph showing processing plant utilization for the Texas Panhandle Segment. The volumes include only the wet gas volumes that were gathered and processed prior to delivery to the interstate or intrastate pipeline systems.
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Note: The Stinnett Plant was consolidated into the Cargray Plant in July 2008 resulting in a reduction of 40 MMcf/d of processing capacity for the Texas Panhandle Segment. Panhandle Plant capacity increases in 2010 are the result of Roberts Co ( January) and Phoenix Plant (October) .
Our Texas Panhandle Systems are located in the Texas Railroad Commission (the “TRRC”) District 10, which has experienced significant growth since 2002. According to the EIA, total proved dry natural gas reserves have remained flat at 6.9 Tcf from year-end 2008 to year-end 2009 in District 10. This area experienced significant drilling activity from 2006 through early 2009 but saw a reduction in drilling activity during late 2009 and early 2010 as a result of reduced commodity prices. Starting in late 2010 this area has experienced an increase in drilling activity.
System Description. The Texas Panhandle Segment consists of:
• | approximately 3,963 miles of natural gas gathering pipelines, ranging from two inches to 24 inches in diameter, with approximately 141,000 horsepower of compression; |
• | seven active natural gas processing plants with an aggregate capacity of 180 MMcf/d; |
• | a propane fractionation facility with capacity of 1.0 MBbls/d; |
• | two condensate collection and stabilization facilities; and |
• | average gathered volumes of both wet and dry gas of approximately 131.9 MMcf/d for 2010. |
East Panhandle System
The East Panhandle System gathers and processes natural gas produced in the Morrow and Granite Wash reservoirs of the Anadarko basin in Wheeler, Hemphill and Roberts counties. This area has experienced substantial drilling and reserve
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growth since 2002. Producers are increasing their use of horizontal drilling in the Granite Wash play. The enhanced economics associated with horizontally drilled wells and the relatively high levels of liquids found in the reservoir, has led to an overall increase in the number of wells permitted from 393 in 2009 to 649 in 2010 for the greater Granite Wash Play, representing a 65% increase year-over-year. We anticipate that this trend will continue, resulting in higher initial production rates but steeper decline curves during the first year.
The processing plants in our East Panhandle System currently have sufficient processing capacity to accommodate our customers’ current needs. In order to provide processing capacity to accommodate future anticipated demand in the area, we initiated a project to refurbish and relocate the Stinnett cryogenic processing plant, located in the West Panhandle System, to the East Panhandle System to replace the existing Arrington lean oil processing plant, resulting in additional processing capacity and improved processing economics. This project was temporarily postponed in early 2009. On February 15, 2010, we announced our plans to complete the project. The refurbished Stinnett plant, now renamed the Phoenix Plant, replaced the former Arrington plant, resulting in improved efficiencies for existing volumes and increased capacity to serve the need for future processing capacity as the horizontal drilling activity in the Granite Wash play continues in the East Panhandle area. The startup of the Phoenix Plant was completed in October 2010. The plant is currently configured to process 50 MMcf/d and may be expanded up to 80 MMcf/d of total capacity largely through additional compression.
System Description. The East Panhandle System consists of the following:
• | approximately 1,320 miles of natural gas gathering pipelines, ranging from 4 inches to 12 inches in diameter with approximately 65,000 horsepower of compression; |
• | four active natural gas processing plants with an aggregate capacity of 119 MMcf/d; |
• | a gas treating facility with a capacity of 26 MMcf/d; and |
• | average gathered volumes of both wet and dry gas of approximately 95.2 MMcf/d for 2010. |
Phoenix Plant: The startup of the Phoenix Plant was completed in October 2010. The plant improved efficiencies on existing volumes and increased capacity. As drilling activity increases in the Granite Wash Play, the Phoenix Plant will provide a competitive edge over the previous lean oil absorption plant. By adding deeper hydrocarbon extraction capabilities, the Phoenix Plant will continue to add to the value chain for Eagle Rock.
East Hemphill System: The East Hemphill System, acquired from CEFS, was fully integrated within our existing assets by January 2011. This acquisition increased our gathering footprint in the very active Wheeler county area, connecting liquid-rich volumes from the Granite Wash Play with our Phoenix Plant. The system provides both mid and low pressure service, which has become necessary to accommodate higher initial production rates from horizontal Granite Wash wells, Utilizing the system in this manner allows for optimal usage of pipeline capacity.
Canadian System: The system consists of 359 miles of natural gas gathering pipelines and two cryogenic natural gas processing plants referred to as the Red Deer Plant and the Canadian Plant. The Red Deer Plant was refurbished and placed back in service in June 2007; capable of processing 25 MMCF/d of natural gas. The Canadian system gathers raw natural gas from producers and delivers the gas to the Canadian Plant, the Red Deer Plant, the Cargray System or the Arrington System.
Arrington System: The system consists of 537 miles of natural gas gathering pipelines and a cryogenic natural gas processing plant, i.e. the Phoenix Plant.
System 97 Gathering System: The System 97 Gathering System consists of 77 miles of natural gas gathering pipelines. The system gathers raw natural gas from producers and delivers the gas to the interstate pipeline grid. This natural gas is dry gas and does not require processing prior to delivery to the pipeline grid.
Buffalo Wallow Gathering System: The Buffalo Wallow Gathering System consists of 113 miles of natural gas gathering pipelines. The system gathers raw natural gas from producers and delivers the gas to the interstate pipeline system. This natural gas is dry gas that does not require processing prior to delivery to the pipeline grid; however, a portion of the natural gas contains hydrogen sulfide and carbon dioxide that is removed prior to delivering the gas to the interstate pipeline grid.
Goad Treater. The installation of a new 26 MMcf/d treating facility was completed in November of 2010. This facility removes hydrogen sulfide and carbon dioxide from the natural gas prior to delivery to interstate pipelines.
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Natural Gas Supply. As of December 31, 2010, approximately 136 producers and 545 wells and central delivery points were connected to our East Panhandle System. The primary producers connected to the East Panhandle System being Cimarex Energy Co., Chesapeake Energy, Devon Energy Production Company, L.P., and Chevron Texaco Exploration & Production, which represents 16%, 11%, 10% and 10%, respectively, of total volumes on the system. The Anadarko basin, from where this natural gas is produced, extends from the western portion of the Texas Panhandle through most of central Oklahoma. The East Panhandle System averaged gathered volumes of approximately 106 MMcf/d during the fourth quarter of 2010.
Natural gas from new wells located in the area served by the East Panhandle System generally have an initial annual production decline rate of approximately 75%. After the first year of production, the decline rates generally decrease to approximately 30% to 35%. The decline rates generally continue to decrease over time and stabilize at 10% to 15% after several years of production. Approximately 75% of the natural gas gathered on our East Panhandle System is processed to recover the NGL content, which generally ranges from 4.0 to 5.0 gpm. Approximately 25% of the natural gas gathered in the East Panhandle System is not processed but is treated for removal of carbon dioxide and hydrogen sulfide to make the natural gas marketable. This natural gas can be isolated and sent to treating facilities while the remaining system is used to gather the natural gas into the processing plants.
On the East Panhandle System, natural gas is contracted at the wellhead primarily under percent-of proceeds and fee-based arrangements that range from one to five years in term. As of December 31, 2010, approximately 49%, 26%, 7%, and 19% of our total throughput in the East Panhandle System was under percent-of-proceeds, fee-based, fixed recovery and percent-of-index arrangements, respectively.
Competition. With the production growth in the Granite Wash play, a number of midstream companies have built plants in the area. Our primary competitor in this area is Enbridge Energy Partners, L.P. The key drivers in this high growth area, in order to continue to connect producer wells, are the ability to provide low pressure gathering services, to provide outlet capacity for the natural gas as it is brought into producing status and to provide high value efficient plant processing. We have extensive gathering systems that are situated in the Granite Wash play. We expanded these systems during 2007 by approximately 24 MMcf/d of processing capacity by refurbishing and restarting the Red Deer cryogenic plant. In 2009, we added additional compression at our Roberts County plant to expand gathering capacity from 14 MMcf/d to 21 MMcf/d and accommodate additional Granite Wash production. In 2010, we added three additional compressors at our Roberts County Plant. This compression will allow for future integration of the Roberts County system to the Phoenix system.
We continue to review additional projects to remain competitive in connecting new natural gas.
West Panhandle System
The West Panhandle System gathers and processes natural gas produced from the Anadarko basin in Moore, Potter, Hutchinson, Carson, Roberts, Gray, Wheeler and Collingsworth Counties located in the western part of the Texas Panhandle.
System Description. The West Panhandle System consists of:
• | approximately 2,643 miles of natural gas gathering pipelines, ranging from two inches to 24 inches in diameter, with approximately 76,000 horsepower of compression; |
• | three active natural gas processing plants with an aggregate capacity of 61 MMcf/d; |
• | a propane fractionation facility with capacity of 1.0 MBbls/d; |
• | two condensate collection and stabilization facilities; and |
• | average gathered volumes of wet gas of approximately 36.7 MMcf/d for 2010. |
Cargray System: Consists of 905 miles of natural gas gathering pipelines and a cryogenic natural gas processing plant ("Cargray Plant"). The system includes a propane fractionation facility for producing specification propane for sales into local markets. The system is a vacuum pressure gathering system, gathering natural gas from very low volume wells.
Gray System: Consists of 615 miles of natural gas gathering pipelines and a cryogenic natural gas processing plant
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("Gray Plant"). The gathering system is a vacuum pressure gathering system, gathering natural gas from very low volume wells.
Lefors System: Consists of 663 miles of natural gas gathering pipelines and a cryogenic natural gas processing plant ("Lefors Plant"). The gathering system is a vacuum pressure gathering system, gathering natural gas from very low volume wells.
Stinnett Gathering System: Consists of 451 miles of natural gas gathering pipelines. The gathering system is a vacuum pressure gathering system gathering natural gas from very low volume wells. In July 2008, the cryogenic plant ("Stinnett Plant") that was a part of the Stinnett System was shutdown, and we began redirecting the Stinnett System gas to the Cargray System. The Stinnett plant was refurbished and relocated to our East Panhandle system as our Phoenix Plant in 2010.
Turkey Creek Gathering System: Consists of nine miles of natural gas gathering pipelines. The system gathers raw natural gas from producers and delivers the gas to the Cargray Plant. The gathering system is a vacuum pressure gathering system gathering natural gas from very low volume wells.
Super Drip & Cargray Condensate Stabilization Facilities: The Super Drip and Cargray condensate stabilization facilities receive condensate collected from various gathering systems where it is then separated from the collected water and treated.
Natural Gas Supply. As of December 31, 2010, approximately 1,400 wells and central delivery points were connected to our West Panhandle System. There are approximately 118 producers, with the primary producers connected to the West Panhandle System being Chesapeake Energy Marketing, Inc. and Pantera Energy, Co., which represents 41% and 12%, respectively, of total volumes. The West Panhandle System, from where this natural gas is produced, extends through the western and southern part of the Texas Panhandle. The West Panhandle System averaged throughput of approximately 36 MMcf/d during the fourth quarter of 2010.
Natural gas production from wells located within the area served by the West Panhandle System generally are low volume wells being gathered at very low pressure. Natural gas from wells located in the area generally have an annual rate of decline of 6% to 9%. This natural gas is processed to recover the NGL content which generally ranges from 8.0 to 18.0 gpm. These low volume, high gpm wells are susceptible to interruptions during winter freezing conditions. We produce over 2,000 barrels per day of condensate in the West Panhandle systems. We currently stabilize approximately 2,000 barrels per day combined at our Superdrip and Cargray Stabilizers. The Cargray Stabilizer became operational in October 2010 and has increased our stabilization capacity by 2,400 barrels per day. The additional condensate stabilization capacity at Cargray also allows us to increase operating efficiencies at the Superdrip Stabilizer. Condensate stabilization lowers the product's vapor pressure, resulting in a higher value product for sale. We continue to review additional condensate stabilization projects that may provide an opportunity to handle third party condensate on a fee basis. We continue to review additional plant consolidation projects in order to rationalize plant processing capacity and operating costs in an area where the gas decline continues in the range of 6% to 8% per year.
On the West Panhandle System, natural gas is purchased at the wellhead primarily under (i) percent-of-proceeds and (ii) percent-of-index arrangements that range from one to five years in term. As of December 31, 2010, approximately 55%, and 45% of our total throughput in the West Panhandle System was under percent-of-proceeds and percent-of-index arrangements, respectively.
Competition. Our primary competition in the West Panhandle is DCP Midstream, LLC . The key drivers in this low growth area are to continue to improve operating efficiencies, provide low pressure gathering services and to maintain equipment reliability for improved on-line operations.
Texas Panhandle Markets. Our residue gas is marketed primarily to large trading companies who buy gas at the tailgate of our plants. Our NGLs are marketed primarily to ONEOK Hydrocarbons. In addition, condensate produced on the system is exchanged by Petro Source Partners, LP to Cushing, Oklahoma where we sell it to various parties. The condensate is sold under contract terms of one year or less. In addition, condensate produced and stabilized is sold to regional markets on a multi-month basis.
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Eagle Rock Marketing, LLC
During the fourth quarter of 2010, we formed a marketing company, Eagle Rock Marketing, LLC ("Eagle Rock Marketing"), which initiated a marketing operation that involves developing, implementing, and launching marketing uplift strategies surrounding crude and condensate production in Alabama and in the Texas Panhandle. These strategies may include marketing, transportation, and product blending to enhance product net-back prices for our own equity production as well as third-party production.
Alabama: Our Upstream Segment owns and controls certain condensate produced in the Big Escambia Creek, Fanny Church and Flomaton fields in Escambia County, Alabama. Eagle Rock Marketing was formed to create alternative market outlets for the condensate produced from these Alabama fields (both by our Upstream Segment and by other working interest owners) and to take advantage of these alternative market outlets to benefit our Upstream Segment, the other working interest owners in the fields and our Midstream Business. To do this, Eagle Rock Marketing purchases product from our Upstream Segment and the other working interest owners in the fields, at an uplift to the highest price that could have been received from existing markets for the product as it exists prior to the purchase by Eagle Rock Marketing. Eagle Rock Marketing is able to pay more for the product on account of Eagle Rock Marketing's business strategy, which includes (i) blending the purchased condensate to lower the concentration of contaminants and create a new and improved condensate that is more marketable when relocated to an appropriate market and (ii) transporting the new and improved condensate to a better market location for further resale. In this regard, neither our Upstream Segment nor the other working interest owners in the fields bear any of the increased risk in blending and relocating, including the heightened risk of loss in transporting the product for blending and further resale or the market risk with respect to resale of the improved product, all of which is born by Eagle Rock Marketing within our Midstream Business. Eagle Rock Marketing launched this project in November 2010, and Eagle Rock Marketing has been successful, so far, in blending and relocating the product to create market optionality. As a result, Eagle Rock Marketing has enhanced the price received by our Upstream Segment and the other working interest owners in the Alabama fields, while realizing a good return for its own investment and efforts. Eagle Rock Marketing currently takes delivery of the unimproved condensate at a newly-constructed truck loading facility at our Big Escambia Creek processing plant and delivers it to a leased storage facility at Mobile, Alabama where the condensate is blended to lower the concentration of contaminants and create an improved condensate product. Thereafter, the improved product is relocated to a suitable market for resale at an improved price.
Texas Panhandle: In the Texas Panhandle, many dynamics are impacting natural gas liquids and condensate prices, especially product quality and location. Our Midstream Business has seen increased price erosion in these products due to the gravity, vapor pressure and over-supply of condensate in the Granite Wash and other shale plays in Texas. Eagle Rock Marketing's strategy for Texas Panhandle condensate is again an organic growth initiative in our Midstream Business. In October 2010, we installed a new stabilizer at our Cargray Plant to lower the vapor pressure of our equity and third-party condensate, thereby increasing our and our customer's received price for the condensate. In addition, we are currently evaluating various storage and transportation opportunities to aggregate our product along with other third-party condensate and move it to more attractive markets outside the Panhandle.
East Texas/Louisiana Segment
Our East Texas/Louisiana operations are located primarily in Angelina, Nacogdoches, Rusk, Cherokee, Smith, Harris, Waller, Montgomery, Austin, Colorado, Robertson, Grimes, Washington, Polk, Tyler, Jasper, Newton, Upshur, Gregg, Wood and Panola Counties, Texas and Vernon, DeSoto, Lincoln, Jackson, Bienville, Caldwell and Bossier Parishes, Louisiana. Through our East Texas/Louisiana Segment, we offer producers natural gas gathering, treating, processing and transportation and NGL transportation. Our East Texas/Louisiana systems are located in the Texas Railroad Commission (the “TRRC”) Districts 3, 5 and 6, which have experienced significant growth activity since 2002. According to the EIA, total proved natural gas reserves have grown from 35.2 Tcf at year-end 2008 to 37.7 Tcf at year-end 2009. The following is a map of our East Texas/Louisiana Segment:
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Below is a graph showing processing plant utilization for the East Texas/Louisiana Segment. The volumes include only the wet gas volumes that were gathered and processed prior to delivery to the interstate or intrastate pipeline systems.
_______________________________Note: The drop in capacity in July 2008 was due to the shutdown of the Panola JT Plant. The increase in processing capacity in October 2008 was due to the Millennium Acquisition. The September 2008 drop in volume processed was due to the impact of Hurricanes Ike and Gustav that resulted in the shut-in of production as a safety precaution and the resulting damage to third party NGL infrastructure downstream from our plants. Volumes exceeding capacity in July and October 2008 was the result of prior period adjustments.
Systems Description. The facilities that comprise our East Texas/Louisiana operations consist of:
• | approximately 1,213 miles of natural gas gathering pipelines, ranging from two inches to 12 inches in diameter, with approximately 49,700 horsepower of compression; |
• | a 100 MMcf/d cryogenic processing plant; |
• | a 145 MMcf/d cryogenic processing plant, in which we own a 25% undivided interest; |
• | five JT/refrigeration processing plants with an aggregate capacity of 52 MMcf/d; |
• | a 19-mile NGL pipeline; and |
• | average gathered volumes of both wet and dry gas of approximately 205.9 MMcf/d for 2010. |
Brookeland System: Consists of 404 miles of natural gas gathering pipelines and a cryogenic natural gas processing plant ("Brookeland Plant").
Indian Springs Plant: The Indian Springs plant is a cryogenic natural gas processing plant that processes raw natural gas gathered on the Camp Ruby and Tyler County Gathering Systems. We have a 25% non-operated ownership position in the plant. The plant is operated by Enterprise Products Partners, LP.
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Camp Ruby Gathering System: The system gathers raw natural gas from producers and delivers the gas to the Indian Springs Plant. We have a 20% non-operated ownership position in the gathering system. This system is operated by TECO Gas Processing, LLC, a subsidiary of Enterprise Products Partners, L.P.
Tyler County Gathering System: Tyler County Gathering System consists of 75 miles of natural gas gathering pipelines ranging in size from two inches to 10 inches in diameter. The system gathers raw natural gas from producers and delivers the gas to the Brookeland Plant and to the Indian Springs Plant.
Panola Gathering System: This system consists of 33 miles of natural gas gathering pipelines. In July 2008, the Panola JT plant was shutdown and a connection was made to Markwest Energy Partners, LP for natural gas processing prior to delivery to the interstate pipeline grid.
Rosewood System: This system consists of 36 miles of natural gas gathering pipelines and a refrigeration natural gas processing plant that processes the raw natural gas to meet the minimum interstate pipeline gas quality specifications.
Belle Bower System: This system consists of 68 miles of natural gas gathering pipelines. The raw natural gas is dry gas and does not require processing prior to delivery to the pipeline grid.
Vixen Gathering System: The Vixen Gathering System consists of seven miles of natural gas gathering pipelines. The system gathers raw natural gas from producers. The raw natural gas is dry gas and does not require processing prior to delivery to the pipeline grid.
Sligo Gathering System: The Sligo Gathering System consists of ten miles of natural gas gathering pipelines. The system gathers raw natural gas from producers. The raw natural gas is dry gas and does not require processing prior to delivery to the pipeline grid.
Simsboro Gathering System: The Simsboro Gathering System consists of 30 miles of natural gas gathering pipelines. The system gathers raw natural gas from producers. The raw natural gas is dry gas and does not require processing prior to delivery to the pipeline grid.
Quitman Gathering System: The Quitman Gathering System consists of 51 miles of natural gas gathering pipelines. The system gathers raw natural gas from producers. The raw natural gas is delivered to a third party for processing.
ETML Gathering System: The ETML Gathering System consists of 221 miles of natural gas gathering pipelines and a 15 MMcf/d J-T plant that processes a small portion of wet gas prior to delivery to the ETML Gathering System. The system gathers raw natural gas from producers. The raw natural gas is dry gas and does not require processing prior to delivery to the pipeline grid.
Douglas East Gathering System: The Douglas East Gathering System consists of 14 miles of natural gas gathering pipelines. The system gathers raw natural gas from producers. The raw natural gas is dry gas and does not require processing prior to delivery to the pipeline grid.
BGS Gathering System: The BGS Gathering System consists of 28 miles of natural gas gathering pipelines. The system gathers raw natural gas from producers. The raw natural gas is dry gas and does not require processing prior to delivery to the pipeline grid.
Robertson County Gathering System: The Robertson County Gathering System consists of 34 miles of natural gas gathering pipelines. The system gathers raw natural gas from producers. The raw natural gas is delivered to third parties for further treating and processing.
North Gathering System: The North Gathering System consists of 85 miles of natural gas gathering pipelines and a 5 MMcf/d JT plant that processes a small portion of wet gas prior to delivery to the North Gathering System. The system gathers raw natural gas from producers. The raw natural gas is dry gas and does not require processing prior to delivery to the pipeline grid. Sections of the system are subject to FERC jurisdiction under Section 311 of the NGPA. There are a number of city gate and industrial deliveries from this system.
Central Gathering System: The Central Gathering System consists of 102 miles of natural gas gathering pipelines and a 2 MMcf/d refrigeration plant that processes a small portion of wet gas prior to delivery to the Central Gathering
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System. The system gathers raw natural gas from producers. The raw natural gas is dry gas and does not require processing prior to delivery to the pipeline grid. Sections of the system are subject to FERC jurisdiction under Section 311 of the NGPA. There are a number of city gate and industrial deliveries from this system.
New Ulm Gathering System: The New Ulm Gathering System consists of 15 miles of natural gas gathering pipelines. The system gathers raw natural gas from producers. The raw natural gas is delivered to a third party for processing.
Natural Gas Supply. As of December 31, 2010, approximately 586 wells and central delivery points were connected to our systems in the East Texas and Louisiana regions. Due to the decline in natural gas prices during 2009, drilling activity in our East Texas and Louisiana operations declined. Our Tyler County and Brookeland Systems are situated in the Austin Chalk drilling play in Polk, Tyler , Newton and Jasper Counties, Texas. Our ETML system is situated in the Angelina River Trend complex that has active development in the James Lime and Travis Peak formations of Angelina and Nacogdoches Counties, Texas. While drilling in these areas has continued, the pace at which the drilling has occurred has not been sufficient to maintain our gathered volume rates at the same levels as 2009. These assets are located in areas that have multiple production horizons and we anticipate that when natural gas prices recover, drilling will increase. The East Texas/Louisiana segment averaged gathered volumes of approximately 194 MMcf/d during the fourth quarter of 2010. As of December 31, 2010, Anadarko Petroleum and Ergon Exploration Inc., represented 17% and 10%, respectively, of the total volumes of our East Texas/Louisiana Segment.
The natural gas supplied to us under our East Texas/Louisiana Systems is generally dedicated to us under individually negotiated long-term and life-of-lease contracts. Contracts associated with this production are generally percent-of-proceeds, which includes percent-of-liquids and percent-of-index, fixed recovery, well head purchases or fee-based arrangements. As of December 31, 2010, the percentage of natural gas under the contract structures were 17% fixed recovery, 36% fee-based, 33% percent of proceeds and 14% percent-of-index arrangements.
Markets. Residue gas remaining after processing or gathering is primarily taken-in-kind by the producer customers into the markets available at the tailgates of the plants or pipeline interconnects. Some of the available markets are Houston Pipeline Company, Natural Gas Pipeline Company, Tennessee Gas Pipeline, Crosstex Energy L.P. and Southern Natural Pipeline. Our NGLs are sold to various companies including Targa Liquids Marketing and Trade and DCP Midstream, LLC.
Competition. Our primary competition in this area includes Anadarko Petroleum, Crosstex Energy, L.P., DCP Midstream, LLC, Energy Transfer Partners, LP and Enterprise Products Partners, L.P. Producers in the area value high run-time rates of the processing assets, connections to premium markets and low pressure gathering services. During 2010, we continued to expand the Brookeland Gathering System and Tyler County gathering system to gather the expanding Austin Chalk Drilling activity by over 12 miles of 4 inch to 8 inch pipeline at a cost of $5.4 million.
South Texas Segment
Our South Texas Segment systems primarily gather natural gas and recover NGLs and condensate from natural gas produced in the Frio, Vicksburg, Miocene, Canyon Sands and Wilcox formations in Hidalgo, Willacy, Brooks, Zapata, Starr, Cameron, Crockett and Colorado Counties in South Texas and in the Permian Basin. The South Texas Segment also provides producer services by purchasing natural gas at the wellhead for sale into third-party pipeline systems. Our South Texas systems are located in the TRRC Districts 4 and 8, which has experienced significant growth activity since 2002, but drilling activity has been significantly reduced due to the decline in natural gas prices. According to the EIA, total proved natural gas reserves have declined from 14.4 TCF at year-end 2008 to 13.4 TCF at year-end 2009. The following is a map of our South Texas Segment.
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Below is a graph showing processing plant utilization for the South Texas Segment. The volumes include only the wet gas volumes that were gathered and processed prior to delivery to the interstate or intrastate pipeline systems.
System Description. The South Texas Segment consists of:• | approximately 266 miles of natural gas pipeline ranging in size from two inches to 20 inches in diameter; |
• | compressor stations with approximately 15,300 aggregate horsepower; |
• | three processing stations consisting of 11 active skids and related facilities for an aggregate capacity of 87 MMcf/d; and, |
• | average gathered volumes of both wet and dry gas of approximately 57.6 MMcf/d for 2010. |
Phase 1 Gathering System: The Phase 1 Gathering System consists of 70 miles of natural gas gathering pipelines. The system gathers raw natural gas from producers and delivers the gas to multiple market outlets.
Raymondville System: The Raymondville System consists of 48 miles of natural gas gathering pipelines and a JT natural gas processing plant. The system gathers both raw and treated natural gas from producers and delivers the gas to multiple market outlets.
San Ignacio Gathering System: The San Ignacio Gathering System consists of six miles of natural gas gathering pipelines. The system gathers raw natural gas from producers and delivers the gas to Tennessee Gas Pipeline. The raw natural gas is dry gas and does not require processing prior to delivery to the pipeline grid.
TGP McAllen Gathering System: The TGP McAllen Gathering System consists of 13 miles of natural gas gathering pipelines. The system gathers raw natural gas from producers and delivers the gas to Tennessee Gas Pipeline. The raw natural gas is of such quality that it does not require processing prior to delivery to the pipeline grid.
Merit JT Plant: The Merit JT plant is a JT natural gas processing plant that processes raw natural gas to meet the
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minimum interstate pipeline gas quality specifications. A JT plant typically recovers less NGL production than a cryogenic plant. The gas from the plant is delivered to the Tennessee Gas Pipeline.
Wildhorse Gathering System: The Wildhorse Gathering System consists of 113 miles of natural gas gathering pipelines located in Crockett County, Texas, in the prolific Permian Basin. The system gathers raw natural gas from producers and delivers the gas to a third party plant for processing.
Sweeny Gathering System: The Sweeny Gathering System consists of 16 miles of natural gas gathering pipelines. The system gathers raw natural gas from producers and delivers the gas to a third party plant for processing. We own a 50% non-operated ownership in the system. We account for this system as an equity method investment.
Producer Services: On April 1, 2009, we sold our producer services business by assigning and novating the contracts under this business to a third-party purchaser. We sold the producer services business because it was a low-margin business that was not core to our operations. We received an initial payment of $0.1 million for the sale of the business and a contingency payment of $0.1 million in October 2009. We have received since April 1, 2009 and will continue to receive a monthly payment equivalent to $0.01 per MMbtu on the volume of gas that flows pursuant to the assigned contracts until March 31, 2011. We have classified the operations from this business as discontinued operations.
Natural Gas Supply. As of December 31, 2010, the South Texas Segment provides gathering and/or marketing services to approximately 33 producers. The South Texas Segment operates approximately 94 meter stations for receipt or delivery of producer gas. The primary producers on the South Texas Segment systems are Chesapeake Energy Corporation (“Chesapeake Energy”) and FIML Natural Resources LLC (“FIML"). Natural gas production from wells located in the area served by the South Texas Segment's systems generally have steep rates of decline during the first few years of production, therefore throughput must be maintained by the addition of new wells. The South Texas Segment averaged gathered volumes of approximately 37 MMcf/d during the fourth quarter of 2010. As of December 31, 2010, Chesapeake Energy and FIML represented 44% and 20%, respectively, of the total volumes of our South Texas Segment. On January 4, 2011, we were notified by FIML that they were terminating our gathering contract with them effective February 28, 2011.
On the South Texas Segment's systems, natural gas is gathered, compressed, dehydrated, and/or processed under fee-based arrangements. The gas is processed primarily for hydrocarbon dewpoint control to satisfy the gas quality requirements of the receiving interstate pipelines such as Tennessee Gas Pipeline Company. As of December 31, 2010, approximately 74% and 26% of our total throughput in the South Texas System was under fee-based and percent-of-index arrangements, respectively.
Markets. The majority of natural gas deliveries from the South Texas systems go to Tennessee Gas Pipeline Company or Enterprise Texas Pipeline. The natural gas is sold primarily at the delivery points into the interstate or intrastate pipeline systems to various customers. Our South Texas Segment's producer services three largest markets were Cypress Pipeline Company, Houston Pipeline Company, and Total Gas & Power North America Company.
Competition. Our primary competition in our South Texas Segment is DCP Midstream, LLC and Enterprise Products Partners, L.P. The key drivers in this area are low pressure gathering and multiple market outlets for the natural gas. Much of the natural gas drilled within the vicinity of our gathering systems is of sufficient wellhead pressure to deliver directly to the interstate pipelines in the 1000 psig range; however, the wells quickly decline in pressure. We operate our systems at lower pressures which offers the producers an alternative to installing their own compression. Many of the interstate pipelines in our area are constrained from time to time. Offering multiple market outlets is important to our customers to insure that they can produce their natural gas.
Gulf of Mexico Segment
Our Gulf of Mexico operations are non-operated ownership interests in pipelines and onshore plants which are all located in southern Louisiana. Our Gulf of Mexico systems primarily process natural gas from the Transco, Gulf South and Tennessee interstate pipelines and recover NGLs and condensate from natural gas produced in the Outer Continental Shelf of the Gulf of Mexico. The Gulf of Mexico Segment's operations also provide producer services by arranging for the processing of producers’ natural gas into third-party processing plants, which we describe as our Mezzanine Processing Services in the Gulf of Mexico Segment. Our Gulf of Mexico Segment's systems have experienced decreased activity since 2002. The following is a map of our Gulf of Mexico Segment.
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Below is a graph showing processing plant utilization for the Gulf of Mexico Segment. The capacity and volumes processed reflect our net interests in the plants. The volumes include only the wet gas volumes that were gathered and processed prior to delivery to the interstate or intrastate pipeline systems.
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Note. The Gulf of Mexico Segment processing utilization was impacted by Hurricanes Ike and Gustav. The North Terrebonne Plant returned to limited operations in November 2008 and the Yscloskey plant did not restart until January 2009. The drop in capacity in September 2009 and October 2010 was due to the annual adjustment of plant ownership at the Yscloskey Plant.
Systems Description. The facilities that comprise our Gulf of Mexico Segment consist of:
• | approximately 40 miles of natural gas gathering pipelines located in the Gulf of Mexico or Galveston Bay, ranging from four inches to 20 inches in diameter, that are operated by others; |
• | a 1.85 Bcf/d cryogenic processing plant in which we own a 11.45% interest; |
• | a 1.35 Bcf/d cryogenic processing plant, in which we own a 1.67% interest; |
• | a 30 MBbl/d NGL fractionator in which we own a 1.67% interest; and |
• | average processed volumes of both wet and dry gas of approximately 103.8 MMcf/d for 2010. |
CMA Pipelines: The CMA Pipelines consist of various interests in 28 miles of offshore natural gas and condensate gathering pipeline segments in the Gulf of Mexico. The pipeline segments gather raw natural gas and condensate generally from a single offshore platform and deliver the gas to pipeline interconnects with Trunkline Pipeline Company. The CMA Pipelines are operated by Trunkline Pipeline Company and Enterprise Products Partners, LP.
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Yscloskey Plant: The Yscloskey Plant is a refrigerated lean oil natural gas processing plant located in Saint Bernard Parish, Louisiana that processes raw natural gas transported on the Tennessee Pipeline. We currently have a 11.45% non-operated ownership interest in the plant. The ownership adjusts in September each year, for the next 12 months based upon the volume of an owner's share of dedicated gas volumes and liquids recovered at the plant compared to that of the other owners of the plant. Targa Resources Inc. operates the plant.
North Terrebonne Plant: The North Terrebonne plant is a refrigerated lean oil natural gas processing plant located in Terrebonne Parish, Louisiana that processes raw natural gas transported on the Transco Pipeline and the Gulf South Pipeline. As of December 31, 2010 we had a 1.67% non-operated ownership interest in the plant. Effective January 1, 2011, our non-operated ownership interest adjusted to 2.63%. The ownership adjusts in January annually based upon the volume of an owner's share of dedicated gas volumes and liquids recovered at the plant compared to that of the other owners of the plant. Enterprise Products Partners, LP operates the plant.
Tebone Fractionator: The Tebone Fractionator is a NGL fractionation plant located in Terrebonne Parish, Louisiana that separates an NGL stream into its specification products of ethane, propane, isobutane, normal butane and natural gasoline which are then sold to various markets. The Tebone Fractionator substantially fractionates the y-grade NGL stream produced from the North Terrebonne Plant. As of December 31, 2010, we had a 1.67% non-operated ownership interest in the fractionator. Effective January 1, 2011, our non-operated ownership interest adjusted to 2.63%. The ownership adjusts in January annually based upon the ownership interest in the North Terrebonne Plant. Enterprise Products Partners, LP operates the Tebone Fractionator.
Galveston Bay Gathering System: The Galveston Bay gathering system consists of 12 miles of natural gas, water and condensate gathering pipeline segments located in Galveston Bay, Texas. These pipeline segments gather water and condensate mixture from a single platform located in state waters and deliver the natural gas to a downstream pipeline for further transportation to an onshore separation facility owned by others. We own a 50% interest in the system, which is operated by Layton Energy, the producer on the system.
Mezzanine Processing Services: Our Mezzanine Processing Services arranges for the processing of producers’ natural gas into third-party processing plants. Typically, these are smaller producers without staffing to handle the management of the processing themselves. The fee we receive for these services is typically a percentage of the NGLs recovered from their natural gas. We have no keep-whole exposure under our contracts with the producers.
Natural Gas Supply. The supply of natural gas into our Gulf of Mexico Segment's assets is highly dependent upon drilling activity over which we have no ownership or control. As of December 31, 2010, the Gulf of Mexico Segment provides processing services to approximately 16 producers. Our processing contracts are specific to producer interests in specific blocks. These producers have also entered into processing agreements with us under a life-of-lease term. We, in turn, enter into processing agreements with the producers whereby we receive a portion of the NGLs as a fee for the services we provide. We have no keep-whole exposure under our direct processing agreements with the producers. We also receive an economic benefit in the Yscloskey and North Terrebonne plants for natural gas that the plant operator contracts for on behalf of the collective plant owners for the benefit of plant owners in proportion to their ownership interest. This may be contracted for directly with various producers or with the pipeline delivering gas to the plant. The primary producers served by our Yscloskey and North Terrebonne systems, in which we have an ownership share, are Stone Energy Corporation, McMoRan Exploration Company and Hall-Houston Exploration. The gas we currently process comes primarily from what is referred to as the Gulf of Mexico Shelf which is an area extending out from the coast of Louisiana approximately 100 miles.
The Yscloskey and North Terrebonne Plants suffered significant damage from hurricanes Gustav and Ike, respectively. The damage resulted in significant downtime for both facilities. North Terrebonne Plant restarted operations in November 2008 and the Yscloskey Plant restarted operations in January 2009. The cost to repair the facilities and the cost of business interruption are being covered by either insurance proceeds or by the sellers under the Millennium Acquisition purchase and sale agreement. In addition to damage to the facilities, the third-party pipelines delivering gas to the plants and the producer platforms suffered damage that has resulted in reduced volumes for processing. Due to the hurricanes, we have permanently lost 26 MMcf/d of contracted volumes due to the producers’ election not to repair pipelines or platforms to restore production. The hurricanes also impacted our Mezzanine Processing Services due to the shut-in of production in the Gulf of Mexico and the impact on third-party plants. Our Mezzanine Processing Services have returned to near pre-hurricane levels.
Our three largest producers in the Mezzanine Processing Services business are Stone Energy Corporation, Hall-
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Houston Exploration and Apex Oil & Gas, Inc.
Natural gas production from wells located in the area served by the Gulf of Mexico Segment generally have steep rates of decline during the first few years of production, therefore throughput must be maintained by the addition of new wells. The Gulf of Mexico Segment averaged processed volumes of approximately 114 MMcf/d during the fourth quarter of 2010. As of December 31, 2010, Stone Energy Corporation, McMoRan Exploration Company and Hall-Houston Exploration represented 64%, 13% and 10%, respectively, of the total volumes of our Gulf of Mexico Segment. On the Gulf of Mexico Segment's gathering systems, natural gas and condensate is gathered under percent-of-proceeds and fee-based arrangements. We do not purchase any natural gas or condensate from producers for purposes of reselling in the Gulf of Mexico Segment's systems.
Markets. The majority of natural gas liquids produced from the Gulf of Mexico Segment's systems are transported by pipelines for fractionation at the Norco, Toca and Tebone fractionators. Once fractionated, the specification products are sold to Enterprise Products Partners L.P. under a year-to-year contract.
Competition. Our competition in the Gulf of Mexico at the Yscloskey Plant and the North Terrebonne Plant is primarily from other owners in those plants as well as the plant operators who are attempting to contract with the producers on behalf of all the plant owners. The owners most active in contracting directly for new supplies of natural gas are Enterprise Products Partners, L.P., as the operator of the North Terrebonne Plant, Targa Resources, Inc., as the operator of the Yscloskey Plant, and DCP Midstream, LLC. In our Mezzanine Processing Services, the primary competition comes from the plant operators at the various third party plants in which we have contracts and from Texon L.P. who provides a similar service as to ours.
Upstream Business
Upstream Business Overview
Our Upstream Business has long-lived, high working interest properties located primarily in Southern Alabama (where we also operate the associated gathering and processing assets), East Texas, South Texas and West Texas. As of December 31, 2010, these working interest properties included 273 operated productive wells and 137 non-operated wells with net production of approximately 5,017 Boe/d and proved reserves of approximately 38.4 Bcf of natural gas, 8.7 MMBbls of crude oil, and 6.2 MMBbls of natural gas liquids, of which 89% are proved developed. The reserve life index is approximately 10 years.
We entered the Upstream Business in August 2007 through the Redman and EAC acquisitions that included operated properties in East Texas, South Texas, Mississippi and Alabama, as well as non-operated properties in East Texas and Louisiana. In April 2008, we closed on the Stanolind Acquisition, which provided our entry to the prolific Permian Basin of West Texas. In September 2010, we acquired certain additional interests in the Big Escambia Creek Field (and the nearby Flomaton and Fanny Church Fields) in wells in which we currently owned significant interests and are nearly 100% operated by us. Our acquisitions are focused on assets with a relatively high percentage of proved developed producing reserves, characterized by low production decline rates, and located in areas providing low risk infill drilling and recompletion opportunities. We pursue operated assets with generally high working interests to better control the development of our reserves and maximize the efficiency of our cost structure. The average working interest of our producing operated properties is 93%. Our properties are diversified in multiple fields and producing basins. Our largest fields, comprising 80% of net production, are the Big Escambia Creek field in Escambia County, Alabama, the Jourdanton field in Atascosa County, Texas, the Ward Estes field in Ward County, Texas, the Ginger/Ginger S.E. fields in Rains County, Texas and the Flomaton and Fanny Church fields in Escambia County, Alabama. The remaining 20% of our fields are located in East Texas, West Texas and Mississippi.
The production in our East Texas and Alabama fields is predominantly from the Smackover formation which contains significant percentages of hydrogen sulfide and carbon dioxide which must be extracted prior to sales. The Alabama assets include two operated treating plants to facilitate the extraction of these contaminants and the sale of elemental sulfur, and one operated processing plant to process and sell natural gas liquids. The Alabama assets also include gathering pipelines, saltwater disposal wells and other equipment to conduct efficient operations. The production from our East Texas assets is treated and processed by Tristream Energy ("Tristream") at its Eustace Plant. Tristream provides gathering, compression, and treating to extract hydrogen sulfide and carbon dioxide prior to residue gas sales. In addition, the gas stream is processed at the plant to extract natural gas liquids and elemental sulfur for sales. The Jourdanton field in Atascosa County, Texas produces from the Edwards formation and contains a significantly lower percentage of hydrogen sulfide (2%) and is treated at Regency Field Services' Tilden Plant.
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The Permian assets acquired in the Stanolind acquisition are characterized by long-lived oil and gas reserves produced from multiple pay horizons with low decline rates. Production from these assets averaged 951 Boe/d in 2010. Since January 2010, we have drilled six wells on these Permian assets with a success rate of 83%. The growth prospects in our core areas are driven primarily by infill drilling, low risk recompletions and workovers of existing formations or shut-in wells located on our properties.
Upstream Significant Properties
Our Upstream business consists of operated and non-operated working interests located in Alabama, Texas, Louisiana and Mississippi. The following table summarizes our holdings as of December 31, 2010.
Field | Location | Average net daily sales in 2010 | Gross productive wells in December 2010 | |||||||||||||
Oil, Bbl/d | Natural gas, Mcf/d | Natural gas liquids, Bbl/d | Operated | Non- Operated | ||||||||||||
Big Escambia Creek | Escambia County, Alabama | 1,141 | 2,997 | 519 | 17 | 1 | ||||||||||
Jourdanton | Atascosa County, Texas | 17 | 2,156 | — | 11 | — | ||||||||||
Ward Estes | Ward County, Texas | 379 | 1,150 | 183 | 103 | — | ||||||||||
Ginger/Ginger SE | Rains County, Texas | 67 | 111 | 128 | 7 | 1 | ||||||||||
Fanny Church | Escambia County, Alabama | 162 | 386 | 75 | 2 | — | ||||||||||
Flomaton | Escambia County, Alabama | 135 | 194 | 54 | 3 | — | ||||||||||
Southern Unit | Crane County, Texas | 23 | 146 | 16 | 24 | — | ||||||||||
Edgewood/Edgewood NE | Van Zandt County, Texas | 32 | 1,133 | 61 | 5 | — | ||||||||||
Fruitvale/Fruitvale E | Van Zandt County, Texas | 24 | 163 | 43 | 6 | — | ||||||||||
Eustace | Henderson County, Texas | 5 | 15 | 48 | 6 | — | ||||||||||
All others | Various | 229 | 1,176 | 71 | 89 | 135 | ||||||||||
Total | 2,214 | 9,627 | 1,198 | 273 | 137 | |||||||||||
Big Escambia Creek. The Big Escambia Creek field, located in Escambia County, Alabama, encompasses approximately 11,568 gross and 7,379 net Eagle Rock operated acres. The field was discovered in 1971 and produces from the Smackover formation at depths ranging from approximately 15,000 to 16,000 feet. Eagle Rock operates seventeen productive wells with an average ownership of 63% working interest and 53% net revenue interest. The reservoir is a sour, gas condensate reservoir in which produced gas and fluids contain a high percentage of hydrogen sulfide and carbon dioxide. These impurities are extracted at the Eagle Rock-operated Big Escambia Creek Treating Facility, and the effluent gas is further processed for the removal of natural gas liquids in the Big Escambia Gas Processing Facility. The operation of the wells and the two facilities is closely connected, and Eagle Rock is the largest owner and operator of the combined assets. In addition to selling condensate, natural gas, and natural gas liquids, we also market elemental sulfur. The sulfur market was depressed during 2009, with prices ranging from $0 to $30 per long ton before price netbacks. The current market for sulfur has strengthened primarily due to an increased demand for fertilizers. Sulfur prices in 2010 were $90 per long ton on February 10, 2010, $145 per long ton on May 3, 2010, $95 per long ton on August 2, 2010 and $160 per long ton on October 25, 2010 at the Tampa, Florida market. Since sulfur is a co-product with our hydrocarbon products, if we were unable to either sell or otherwise dispose of the sulfur we produce, we might be forced to curtail our oil and gas production. This has not happened in the past, however.
Jourdanton. The Jourdanton field, located in Atascosa County, Texas, was originally discovered in 1945 by Humble Oil Company. Eagle Rock's production from the field is primarily from the Edwards carbonates (7,300 to 7,400 feet); however, production has been established in multiple reservoirs above the Edwards interval, predominately the Georgetown, Austin Chalk, and Buda formations. The Jourdanton field originally produced from the “oil leg” at the bottom of the Edwards interval with subsequent production from the higher porosity gas sections at the top of the Edwards. In recent years, production has been established from some of the lower permeability and porosity sections in the middle Edwards interval. In addition, the Eagle Ford shale is productive in the southern portion of Atascosa County, although it has not been widely tested in the immediate vicinity of our wells.
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Eagle Rock operates eleven productive wells with 100% working interest and 88% net revenue interest. Net leasehold ownership in the field is 926 acres. Gas content is relatively dry and contains approximately 7% carbon dioxide and 2% hydrogen sulfide. Production flows from the wellhead full well stream to a central production facility where the liquids are separated and the gas is compressed to pipeline pressures. The gas is delivered to Faraday Pipeline and then to Regency Field Services' Tilden Gas Plant where it is sold to Total Gas & Power, N.A. The oil is transported from our central production facility by truck and sold to Enterprise Crude Oil, LLC.
Ward-Estes. The Ward-Estes Area is located on the western edge of the prolific Central Basin Platform within the Permian Basin and encompasses approximately 10,285 gross and 9,615 net Eagle Rock operated acres. The Central Basin Platform extends from central Lea County in New Mexico to central Pecos County in Texas and encompasses hundreds of individual fields with multiple productive intervals from the Yates-Seven Rivers-Queen through the Ellenburger formations. Eagle Rock operates multiple fields consisting of stacked multi-pay horizons that produce from depths of 2300 feet (Yates) to 9100 feet (Pennsylvanian). The Yates-Queen production is primarily oil production associated with secondary waterflood operations and was discovered in the late 1920s. The San Andres, Holt, Glorieta, Tubb / Clearfork intervals produce oil with associated casinghead gas. The Wichita Albany, Wolfcamp and Pennsylvanian intervals typically are gas wells that produce some associated oil. Our ownership in these wells averages 99% net working interest and 79% net revenue interest. Gas production from the leases are gathered and processed by Targa Gas under a percent-of-proceeds ("POP") contract. Crude oil is sold to Navajo Refining Company, L.P. and Plains Marketing, L.P. Water production from the Yates – Queen secondary recovery operations is treated and re-injected into water injection wells to provide reservoir pressure maintenance.
Ginger/Ginger Southeast. The Ginger/Ginger Southeast fields are located in eastern Rains County, Texas encompassing approximately 2,346 gross and 1,836 net Eagle Rock-operated acres. The fields are positioned on the flanks of a northeast-southwest trending salt-cored anticline that culminates in a graben at its crest. The fields were discovered in 1951 and 1982, respectively, and produce from the Smackover formation at depths of approximately 12,000 feet. We operate seven productive wells in these fields which produce gas that contains approximately 32% hydrogen sulfide and 3.5% carbon dioxide. Eagle Rock's ownership in the wells average 73% working interest and 60% net revenue interest. The full well stream production is gathered by Tristream Energy, LLC and is delivered to Tristream's Ginger Station where it is compressed before flowing to Tristream's Myrtle Springs compressor station for condensate separation and sales. Flow continues to Tristream's Eustace Plant where it is treated for impurities, and natural gas liquids and sulfur is extracted for a combination of fees and percent-of-proceeds. The residue gas is sold to Tristream. Natural gas liquids are sold by Tristream through a marketing arrangement with Targa Liquids Marketing and Trade and condensate is sold to Plains Marketing, L.P. The extracted sulfur is sold to International Chemical Company (“Inter-Chem”).
Fanny Church. The Fanny Church field is located 2 miles east of Big Escambia Creek and produces from the Smackover formation at depths from approximately 15,000 to 16,000 feet. Eagle Rock's ownership includes approximately 1,284 gross and 999 net operated acres that include two productive operated wells with an average ownership of 86% working interest and 66% net revenue interest. Similar to those in the Big Escambia Creek Field, the produced fluids contain a high concentration of hydrogen sulfide and carbon dioxide. The production is treated for the removal of these impurities at the Flomaton Treating Facility, and the treated natural gas is sent to the Big Escambia Processing Facility for the extraction of natural gas liquids.
Flomaton. The Flomaton field is adjacent to and partially underlies the Big Escambia Creek field. The field encompasses approximately 1,280 gross and 1,256 net Eagle Rock operated acres and produces from the Norphlet formation at depths from approximately 15,000 to 16,000 feet. Eagle Rock operates three productive wells with an approximate average 91% working interest and 77% net revenue interest. Production from the Flomaton Field contains significant quantities of hydrogen sulfide and carbon dioxide. The produced fluids from Flomaton are treated in the same manner as those from the Fanny Church Field.
Southern Unit. The Southern Unit field is located on the Central Basin Platform of the Permian Basin in Crane County, Texas. Production is primarily associated with the Waddell Sand formation. The Southern Unit is located in the Running “W” Waddell field discovered in the mid-1930s and produces predominantly oil at depths from approximately 5,750 to 5,900 feet. Eagle Rock operates approximately 6,100 net acres in this area. In addition to the Waddell Sand in the Southern Unit, production is also associated with the shallower McKee Sand gas-bearing interval. Our ownership average in these wells average 89% net working interest and 69% net revenue interest. Gas production from the Southern Unit field is gathered and processed by Targa Permian, L.P. under a percent-of-proceeds contract. The oil is purchased by Plains Marketing, L.P. Produced water on the Southern Unit is re-injected into the Waddell Sand to provide reservoir pressure maintenance.
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Northeast Edgewood/Edgewood. The Northeast Edgewood field is located in Van Zandt County, Texas along the Smackover Trend of East Texas. The reservoir is a northeast-southwest oriented anticline that produces from the Upper Smackover formation at approximately 12,700 feet. Eagle Rock's leasehold includes 4,531 gross acres and 3,691 net acres and we operate four productive wells which produce gas that contains approximately 30% hydrogen sulfide. Eagle Rock's ownership in the wells averages 85% working interest and 75% net revenue interest. The full well stream production is gathered by Tristream and compressed at Tristream's Edgewood compressor station. The gas proceeds to Tristream's Myrtle Springs compressor station for additional compression and separation of condensate before arriving at Tristream's Eustace Plant. At the Eustace Plant the gas stream is separated, treated for impurities and natural gas liquids and sulfur is extracted for a combination of fees and percent of proceeds. The residue gas is sold by Tristream to various markets. Natural gas liquids are sold by Tristream through a marketing arrangement with Targa Liquids Marketing and Trade and the condensate is sold to Plains Marketing, L.P. The extracted sulfur is sold to Inter-Chem. During the fourth quarter 2009, the J.H. Parker #1 was recompleted from the Smackover formation to the Cotton Valley formation in the Edgewood field. The well tested gas from the Cotton Valley and was shut-in pending the installation of production equipment and flowlines. During January 2010 the well was placed to sales and produced gas and condensate until the Eustace Plant was shut-in during August 2010. Because the Cotton Valley gas stream produced from this well does not contain hydrogen sulfide and does not require treating to remove this impurity, arrangements were made to return this well to sales during December 2010. Production from the J.H. Parker #1 is sold to Tristream at the wellhead.
Fruitvale / E. Fruitvale. The Fruitvale and East Fruitvale fields are located in Van Zandt County, Texas and encompass approximately 4,058 gross and 3,925 net Eagle Rock operated acres. The fields were discovered in 1976. The reservoir is on a northeast-southwest oriented anticline that produces from the Upper Smackover formation at approximately 12,700 feet. Eagle Rock operates six productive wells which produce gas that contains approximately 6.5% hydrogen sulfide, 7.5% carbon dioxide and 17% nitrogen. Eagle Rock's ownership in the wells averages 97% working interest and 81% net revenue interest. The full well stream production is gathered by Tristream Energy, LLC and flows to Tristream's Myrtle Springs compressor station for condensate separation and sales. The gas proceeds to Tristream's Eustace Plant for separation, treating for impurities, and extraction of natural gas liquids and sulfur for a combination of fees and percentage of proceeds. Residue gas is sold by Tristream to various markets. Natural gas liquids are sold by Tristream through a marketing arrangement with Targa Liquids Marketing and Trade, and condensate is sold to Plains Marketing, L.P. The extracted sulfur is sold to Inter-Chem.
Eustace. The Eustace field is located in northwestern Henderson County, Texas and includes approximately 2,800 gross and net acres operated by Eagle Rock. The wells produce from the Smackover formation at approximately 12,700 feet. The field was originally discovered in 1973 and began producing in 1981 after Shell Oil Company purchased the field and constructed the Eustace sour gas treating and gas processing plant (currently owned and operated by Tristream Energy, LLC). The reservoir is an elongated anticlinal feature located along the East Texas Smackover Trend. Eagle Rock operates six productive wells in this field that produce gas containing approximately 37% hydrogen sulfide and 5% carbon dioxide. Eagle Rock's ownership in the wells is 100% working interest and 87% net revenue interest. The full well stream production flows through Eagle Rock's flow lines to Tristream's Eustace Plant for separation of condensate, removal of impurities, and extraction of natural gas liquids and sulfur for a combination of fees and percentage of proceeds. The residue gas is sold by Tristream to various markets. Natural gas liquids are sold by Tristream through a marketing arrangement with Targa Liquids Marketing and Trade, and condensate is sold to Plains Marketing, L.P.
Productive Wells
On December 31, 2010 we had under operation 195 gross (184 net) productive oil wells and 78 gross (64 net) productive natural gas wells. On December 31, 2010, we owned non-operated working interests in an additional 17 gross (1.4 net) productive oil wells and 120 gross (3.4 net) productive natural gas wells.
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Developed and Undeveloped Acreage
The following table describes the leasehold acreage we owned as of December 31, 2010.
Developed Acreage(a) | Undeveloped Acreage(b) | Total Acreage | |||||||||||||||
Gross(c) | Net(d) | Gross(c) | Net(d) | Gross | Net | ||||||||||||
Operated | 58,867 | 48,512 | 5,408 | 3,861 | 64,275 | 52,373 | |||||||||||
Non-operated | 27,850 | 1,928 | — | — | 27,850 | 1,928 | |||||||||||
Total | 86,717 | 50,440 | 5,408 | 3,861 | 92,125 | 54,301 | |||||||||||
_____________________________
(a) Developed acres are acres pooled or assigned to productive wells.
(b) Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas or oil, regardless of whether such acreage contains proved reserves.
(c) A gross acre is an acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned.
(d) A net acre is deemed to exist when the sum of the fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres.
Drilling and Recompletion Activity
In 2010, we drilled and completed five successful operated wells in the Upstream segment. We consider a drilled and completed well successful if the cash flows (including capital investment) are forecasted to have a positive net present value from the booked reserves developed from the project. All five wells were drilled and successfully completed in our Ward Estes field in the Permian basin from the Penn and Wolfcamp formations. A sixth operated well was drilled in our Southern Unit Field in the Permian Basin but was unsuccessful. The total program development cost of these six wells was $17.23/Boe. In 2010, of the six wells we drilled, five were proved undeveloped locations. As of December 31, 2010, we were in the process of drilling and completing one additional well in our Big Escambia Creek field.
Recompletions, capital workovers or pipeline projects were conducted on fourteen operated wells across our Upstream Segment during 2010. Eight of the fourteen capital workovers were successful. The program unit development cost for these fourteen operations was $6.27/Boe.
In 2009, we drilled and completed three successful operated wells in the Upstream segment. Two wells were drilled and successfully completed in our Ward Estes field in the Permian basin. These wells were drilled, completed and produced to sales from the Penn and Wolfcamp formations during the fourth quarter 2009. A third operated well was drilled during 2008, but completed and produced to sales in 2009, from the Smackover formation. The total development cost of these three wells was $9.12/Boe. In 2009, of the three wells we drilled, one was a proved undeveloped location. This well cost approximately $1.1 million, and its production performance has been consistent with our expectations. We did not have any active drilling programs in process as of December 31, 2009.
Recompletions and capital workovers were conducted on ten operated wells across our West Texas and Alabama regions during 2009. Nine capital workovers or recompletions were executed in our Permian operations in multiple formations ranging from the shallow Queen formation to the deeper Penn formation. Seven of the nine Permian capital workovers were successful. One successful well sidetrack operation was conducted in our Alabama Big Escambia Creek field targeting the Smackover formation. The unit development cost for these ten operations was $3.66/Boe.
In 2008, we completed the drilling of 21 wells (5.8 net), of which 15 were operated by others. All six wells operated by us were successful. Five operated, successful Permian Basin wells were drilled and completed on leasehold acquired from the Stanolind Acquisition in 2008. Four of these wells were drilled in the Ward-Estes field area on the Louis Richter and American National leases testing the San Andres, Holt and Penn formations. The fifth Permian Basin well was a successful completion in the Penn Sand on our American National lease in the Southern Unit field area. In addition to the Permian program, a successful Smackover test we drilled and completed a successful Smackover test in our Big Escambia Creek field. The fifteen non-operated wells drilled in 2008 were drilled by Stroud Petroleum in various fields of East Texas and North Louisiana. Our average working interest in the Stroud Petroleum program is 3.8%. Two of the non-operated wells were plugged and abandoned, the rest were successful.
Recompletions and capital workovers were conducted on eight operated wells across our South Texas, West Texas and
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Alabama regions during 2008. Five recompletions were executed in our Jourdanton field to complete additional Edwards formation intervals. Three of the five Edwards recompletions were successful. Three successful capital workovers were completed in our Alabama and West Texas operations resulting in significant reserve additions during 2009. The unit development cost for these operations was $10.62/Boe.
Oil and Natural Gas Reserves (Upstream Business)
On December 1, 2008, the SEC announced that it had approved revisions designed to modernize the oil and gas company reserve reporting requirements. The new rules, referred to as the SEC Reserves Reporting Modernization, replaced the rules that had been in effect since 1975. We adopted the rules effective December 31, 2009.
Under the new reserve reporting rules, proved oil and gas reserves are defined in part as “those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.”
Estimates of proved reserves as of December 31, 2010, were based on estimates made by our independent engineers, Cawley, Gillespie & Associates, Inc (“CGA”). In 2010, CGA was engaged by and provided its reports to our senior management team. In order to enhance our controls regarding reserve reporting, in 2009 the Audit Committee charter was amended to grant the Audit Committee the authority to engage an independent reserve engineer. However, management continues to have direct oversight of the independent reserve engineer's activities. For 2011, management recommended, and the Audit Committee approved, our continued engagement with CGA.
We make representations to the independent engineers that we have provided all relevant operating data and documents, and in turn, we review the reserve reports provided by the independent engineers to ensure completeness and accuracy. Our review entails a comparison of the forecasts and other parameters in the reserve report to our internal estimates and our historical results. If discrepancies are identified, we discuss these issues with CGA and provide them with additional information. This process may or may not result in changes to their estimates, but the final report will represent their estimates, based on the data we provided and their engineering judgment. Our Chief Executive Officer makes the final decision, based on recommendations from our Senior Vice President - Technical Evaluations and other staff members, on booked proved reserves by incorporating the proved reserves from the independent engineers’ reports into our financial statements and disclosures.
Qualifications of Reserve Estimators
Our reserves reporting process involves two major steps; the population of a reserves database by our Technical Evaluations staff, and the preparation of an independent reserve report which uses the database as its starting point. The independent reserves report is prepared by CGA, which is a Texas Registered Engineering Firm (F-693). The engineer on our account is Mrs. Kellie Jordan who works under the supervision of Mr. Robert Ravnaas, Executive Vice President. Mr. Ravnaas is a State of Texas Licensed Professional Engineer (License #61304). Cawley Gillespie's report is attached as Exhibit 99.1 to this Annual Report on Form 10-K.
In the preparation of its report, CGA relies on engineering and other data provided by our staff and overseen by our Senior Vice President - Technical Evaluations, Mr. Steven Hendrickson. Mr. Hendrickson is a State of Texas Licensed Professional Engineer (License #65951) with over 27 years of experience in petroleum engineering, operations, economics, finance, acquisitions and risk management. He holds a bachelors of science degree in chemical engineering from the University of Texas and a masters of science degree in finance from the University of Houston. He is a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers.
Internal Controls Over Reserve Estimation
One of our primary controls with respect to reserve reporting is the independent reserve report; however, we also have various internal controls to ensure that the data we supply to CGA is accurate. These controls are tested by our internal auditors and our independent accounting auditors, and they have concluded that these controls are effective. Among other things, our internal controls include the following items:
• | A process to identify all of the newly-drilled producing wells and add them to our database. |
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• | A process to retrieve production data from our IHS Software Application to use as the basis of our decline curve forecasts. |
• | A process to estimate various economic parameters, such as operating costs; price differentials; gas shrinkages; and condensate, NGL and sulfur yields. This process relies on historical data provided by our accounting department and our operations engineers. |
• | A process to check the working and net revenue interests in our reserves database to ensure they are consistent with our land and revenue accounting records. |
• | A process to identify and document the engineering and geological support for our developed non-producing and undeveloped reserves. |
• | Processes to estimate future capital expenditures and abandonment costs that are based on our prior experiences and engineering judgment. |
We use the data gathered and estimated in the processes above to populate our reserves database. Our Technical Evaluations staff prepares a reserves estimate for each well in which we own an interest (including non-producing and undeveloped locations). This database is then provided to CGA, along with any additional supporting information they request, and forms the primary basis for their reserve estimates.
After CGA has made their preliminary reserves estimate, the Senior Vice President – Technical Evaluations reviews their results and compares them to our historic production rates, operating costs, price differentials, severance tax rates and ad valorem tax rates. If they are not consistent with our historical results, the database is scrutinized to identify and correct possible sources of error. The Senior Vice President – Technical Evaluations and his staff also review the production forecasts prepared by CGA for possible errors, omissions or significant differences in engineering judgment. In those instances, the issue is discussed with CGA and additional supporting data is provided, if needed. Capital costs and investment timing are also reviewed to ensure that they are consistent with our five year development plan and our approved budget.
After CGA has completed their report, our Technical Evaluations group prepares the reserves reconciliation. During this process, we occasionally identify small discrepancies that we believe should be corrected and these discrepancies are discussed and resolved with CGA.
General Reserve Estimation Methods
Because the majority of our proved reserves are classified as proved producing reserves, we use production performance methods (decline curve analysis) extensively in the preparation of our proved reserves estimates. Our estimates of proved undeveloped and proved developed non-producing reserves are based on volumetric methods and analogy to offset producers. Where applicable, we occasionally use material balance methods to estimate reserve quantities. We have not used reservoir simulation or proprietary methods to prepare our reserves estimates.
The revised SEC rules permit the optional disclosure of probable and possible reserves. We have elected to not disclose these quantities at this time.
Proved Reserves
The following table presents our estimated net proved natural gas and oil reserves in the Upstream Business on December 31, 2010. These values are based on independent reserve reports prepared by Cawley, Gillespie & Associates, Inc.
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As of December 31, 2010 | ||
Reserve Data: Upstream Business | ||
Estimated net proved reserves: | ||
Natural gas (Bcf) | 38.4 | |
Oil (MMBbls) | 8.7 | |
Natural Gas Liquids (MMBbls) | 6.2 | |
Total (Bcfe) | 127.8 | |
Proved developed (Bcfe) | 114.3 | |
Proved developed reserves as % of total proved reserves | 89 | % |
Estimated net undeveloped reserves: | ||
Natural gas (Bcf) | 8.7 | |
Oil (MMBbls) | 0.4 | |
Natural Gas Liquids (MMBbls) | 0.4 | |
Total (Bcfe) | 13.5 | |
Proved undeveloped (Bcfe) | 13.5 | |
Proved Undeveloped Reserves
We have a relatively modest level of proved undeveloped reserves. As a master limited partnership, we grow primarily through acquisitions of producing properties and subsequently conduct development activities on those properties to maintain our production rates. The acquisition candidates that meet our investment criteria often have a high ratio of developed to undeveloped reserves, and we rarely conduct exploration activities.
We approach the development of our undeveloped reserves in a measured pace, in order to hold our production rate fairly constant or slightly inclining. The development plan in our proved reserves report contemplates the drilling of all of our undeveloped locations within five years.
Our undeveloped drilling locations are primarily located in the North Ward Estes Field, Ward County, Texas. The primary targets of these wells are the Penn, Wolfcamp, and Wichita Albany formations. We also have a small number of undeveloped locations in the Jourdanton Field, Atascosa County, Texas in the Edwards formation. There is additional detail regarding these fields and our recent development activity in the Upstream Business Section.
For detail and discussion of our net production and realized prices by product for the years ended December 31, 2010, 2009 and 2008, see our discussion of the results of operations for our Upstream Business within Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Year Ended December 31, 2010 Compared with Year Ended December 31, 2009 and Year Ended December 31, 2009 Compared with Year Ended December 31, 2008. Production costs, excluding ad valorem and severance taxes for our Upstream Business for the years ended December 31, 2010, 2009 and 2008 were $13.08/Boe, $9.60/Boe and $11.16/Boe, respectively.
Regulation of Our Operations
Safety and Maintenance Regulation
Midstream Business
Our Midstream Business, other than our pipelines, is subject to federal safety standards developed under the Occupational Health and Safety Act of 1970, as amended (“OSHA”). The OSHA standards focus on protection of employee health and safety and the maintenance and safe operation of our facilities. The facilities covered by these safety regulations in our Midstream Business are our natural gas plants, compressor stations, and natural gas treatment facilities. Safety matters associated with our pipelines are regulated by the U.S. Department of Transportation (“DOT”), Office of Pipeline Safety (“OPS”). We incur costs related to all of these regulations for monitoring and maintaining our facilities in safe operating conditions. We also have costs associated with training our workforce in safety, record keeping, reporting, and inspecting our operations. Consequences of non-compliance with these regulations are potential fines from the federal or state government agencies and disruption of operations due to injuries or equipment failure.
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OSHA process safety management (“PSM”) standards apply to our natural gas plants, compressor stations, and natural gas treatment facilities. The PSM standards address ways in which our Midstream Business maintains process safety information, evaluates the hazards associated with these operations, develops procedures for ensuring their safe operation, maintains the integrity of our operations, and manages contractors on-site. PSM standards apply because each of these sites processes and stores (under pressure) flammable liquids or gas in excess of 10,000 pounds. In addition, those of our facilities that handle hydrogen sulfide in quantities exceeding 1,500 pounds are subject to further PSM requirements. The PSM standard also requires us to conduct compliance audits every three years. We are on schedule to timely complete these audits.
More general OSHA standards also apply to these operations. These include regulations governing safety sensitive issues, such as means of egress, fire protection, materials handling and storage, confined space entry, servicing and maintaining machines and equipment, and electrical, that have more application to our Midstream Business than our Upstream Business due to the nature of our Midstream Business facilities.
Our pipeline operations within our Midstream Business, specifically the gathering and transportation of natural gas and hazardous liquids, are subject to DOT regulatory requirements as promulgated by the OPS, specifically 49 CFR 192 (natural gas) and 49 CFR 195 (hazardous liquids). The extent to which our gathering pipelines are regulated primarily depends on their location. There is a sliding scale of regulation ranging from basic safety precautions to more rigorous inspection and reporting depending upon the population density and other factors within proximity of the specific pipeline. Where applicable, these DOT regulations direct our activities with respect to design and construction of pipelines, corrosion control, testing requirements, operations, maintenance, emergency response, and qualification of pipeline personnel.
The safety of our pipelines is also regulated by the states in which we operate. These regulations in general, focus on reporting, recordkeeping, and notification obligations.
Upstream Business
Our Upstream Business implicates safety matters with respect to the exploration and production of hydrocarbons and carries consequences of non-compliance consistent with those discussed above under the safety matters for the Midstream Business. This segment of our business is also subject to OSHA standards. The actual production of oil and gas is subject to OSHA PSM requirements but, through agency internal policy, PSM standards are not currently enforced. OSHA has specifically exempted oil and gas well drilling and servicing from standards covering the control of hazardous energy and the PSM standard as they relate to highly hazardous chemicals. If agency policy changes, additional compliance, reporting, and training costs could be incurred in our Upstream Business.
Our Upstream Business is also subject to safety rules and regulations promulgated by state agencies, such as the Alabama State Oil and Gas Board, Louisiana Department of Conservation, Mississippi Oil and Gas Board, New Mexico Oil Conservation Division, and Texas Railroad Commission. While these agencies have established some regulations designed to protect worker and community health and safety, their primary focus is on environmentally sound well drilling, servicing, and production operations.
FERC and Similar State Regulations
Under the Natural Gas Act of 1938, or NGA, as amended by the Energy Policy Act of 2005, or EPAct 2005, the Federal Energy Regulatory Commission (“FERC”) has jurisdiction over the transportation of natural gas in interstate commerce and the sale of natural gas for resale in interstate commerce, and entities engaged in such activities. FERC also possesses regulatory oversight over natural gas markets, including the purchase, sale and transportation activities of non-interstate pipelines and other natural gas market participants. FERC possesses substantial enforcement authority for violations of the NGA, including the ability to assess civil penalties, order disgorgement of profits and recommend criminal penalties. FERC also regulates intrastate pipelines that engage in interstate transportation activities under Section 311 of the Natural Gas Policy Act, or NGPA.
Our natural gas gathering operations are generally exempt from direct FERC regulation under the NGA; however, FERC has enforcement authority over certain aspects of our business through its jurisdiction over natural gas markets and intrastate pipelines that engage in interstate transportation services.
FERC exercises authority over the rates, terms and conditions of service of intrastate pipelines to the extent that such pipelines transport gas in interstate commerce under Section 311 of the NGPA. Rates for Section 311 transportation service must be fair and equitable, and amounts collected in excess of fair and equitable rates are subject to refund with interest. Our
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Eagle Rock DeSoto Pipeline, L.P., (“DeSoto Pipeline”) transports gas in interstate commerce on its Central and North Texas Systems and is therefore subject to FERC regulation under Section 311 of the NGPA. Any failure on our part to comply with the rates approved by the FERC, the terms and conditions of service established in our FERC-approved Statement of Operating Conditions, or applicable FERC regulations, the NGPA, or applicable state laws and regulations could result in an alteration of the jurisdictional status of the DeSoto Pipeline or the imposition of civil and/or criminal penalties.
In October 2008, DeSoto Pipeline filed a request for FERC approval to continue to use DeSoto Pipeline's currently-effective rate for NGPA Section 311 service, which is based on a city-gate transportation rate approved by the TRRC as being fair and equitable and not in excess of a cost-based rate. In March 2009, FERC approved a settlement authorizing DeSoto Pipeline to continue to charge the currently-effective rate for NGPA Section 311 service, subject to a requirement that on or before May 1, 2010, DeSoto Pipeline must either file a new application for rate approval with FERC or file an election to use its then-effective rates for intrastate city-gate transportation service on file with the TRRC. If the latter, then DeSoto Pipeline is required to make a filing with the TRRC for a cost-based rate determination. On September 14, 2010, the FERC granted an extension of time to May 1, 2012 for DeSoto Pipeline to file a new application for rate approval or to file the election. DeSoto Pipeline is currently evaluating its options under the terms of the settlement. Any failure on our part to comply with the rates approved by the FERC for Section 311 service, to comply with the terms and conditions of service established in our FERC-approved Statement of Operating Conditions, or to comply with applicable FERC regulations, the NGPA, or certain state laws and regulations could result in an alteration of the jurisdictional status of DeSoto Pipeline or the imposition of civil and/or criminal penalties.
EPAct 2005 amended the NGA to grant FERC new authority to facilitate price transparency in markets for the sale or transportation of physical natural gas in interstate commerce, and to prohibit market manipulation. FERC's anti-manipulation regulations apply to FERC jurisdictional activities, which has been broadly construed by the FERC.. Should we fail to comply with all applicable FERC-administered statutes, rule, regulations and orders, we could be subject to substantial civil and criminal penalties, including civil penalties of up to $1.0 million per day, per violation.
In 2008, FERC took additional steps to enhance its market oversight and monitoring of the natural gas industry. Order No. 704, as clarified in orders on rehearing, requires buyers and sellers of natural gas above a de minimis level, including entities not otherwise subject to FERC jurisdiction, to submit an annual report to FERC describing their wholesale physical natural gas transactions that use an index or that contribute to or may contribute to the formation of a gas index. Order No. 720, as clarified in orders on rehearing, requires “major non-interstate” pipelines (defined as pipelines, including certain gathering pipelines not otherwise subject to FERC jurisdiction, with annual deliveries of more than 50 million MMBtu) to post on the internet the daily volumes scheduled for each receipt and delivery point on their systems with a design capacity of 15,000 MMBtu per day or greater.
In 2010, the FERC issued Order No. 735, to be effective April 1, 2011, which requires intrastate pipelines providing transportation services under Section 311 of the NGPA to report on a quarterly basis more detailed transportation and storage transaction information, including: rates charged by the pipeline under each contract; receipt and delivery points and zones or segments covered by each contract; the quantity of natural gas the shipper is entitled to transport, store, or deliver; the duration of the contract; and whether there is an affiliate relationship between the pipeline and the shipper. Order No. 735 further requires that such information be supplied through a new electronic reporting system and will be posted on FERC's website, and that such quarterly reports may not contain information redacted as privileged. Order No. 735 also extends the Commission's anticipated periodic review of the rates charged by the subject pipelines from three years to five years. On December 16, 2010, the Commission issued Order No. 735-A, clarifying and generally reaffirming Order No. 735.
FERC recently issued a Notice of Inquiry on October 21, 2010 requesting comment s on whether and how holders of firm capacity on intrastate pipelines providing transportation services under Section 311 of the NGPA should be permitted to allow others to make use of their firm intrastate capacity. FERC has also questioned whether buy/sell transactions on such pipelines should be allowed. We have no way to predict with certainty whether and to what extent the Notice of Inquiry will result in regulations that fall within the scope of our business.
Midstream Business
Regulation of pipeline gathering and transportation services, natural gas sales and transportation of NGLs may affect certain aspects of our business and the market for our products and services.
Gathering Pipeline Regulation. Section 1(b) of the NGA exempts natural gas gathering facilities from direct regulation by the FERC, but does not define or provide any guidance as to what constitutes “gathering.” FERC has developed tests for determining which facilities constitute gathering facilities exempt from FERC jurisdiction under the NGA. From time to time,
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FERC may reconsider the elements of such tests. We cannot predict when and under what circumstances FERC may elect to re-examine activities that could fall within the scope of our business with respect to gathering.
We believe that, currently, the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline's status as a gatherer not subject to FERC jurisdiction. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of substantial, on-going litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC and the courts. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements, and in some instances complaint-based rate regulation.
Our purchasing and gathering operations are subject to ratable take and common purchaser statutes. The ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply. These statutes have the effect of restricting our right as an owner of gathering facilities to decide with whom we contract to purchase or gather natural gas. Texas and Louisiana have adopted a complaint-based form of regulation of natural gas gathering activities, which allows natural gas producers and shippers to file complaints to resolve grievances relating to natural gas gathering access and rate discrimination. The TRRC has authority to enforce its statutory duty to prevent discrimination in natural gas gathering and transportation, to enforce the requirement that parties participate in an informal complaint process, and to punish purchasers, transporters, and gatherers for taking discriminatory actions against shippers and sellers through the imposition of administrative, civil and criminal penalties.
Louisiana's Pipeline Operations Section of the Department of Natural Resources’ Office of Conservation is generally responsible for regulating gathering facilities in Louisiana, and has authority to review and authorize the construction, acquisition, abandonment and interconnection of physical pipeline facilities. Historically, apart from pipeline safety, it has not acted to exercise this jurisdiction respecting gathering facilities.
The majority of our gathering systems in Texas have been deemed non-utilities by the TRRC, with the exception being our Turkey Creek gathering system, which is regulated as a utility by the TRRC. Our Hesco Pipeline Company, LLC and the East Texas segment of our DeSoto Pipeline are also regulated by the TRRC. Under Texas law, non-utilities are not subject to rate regulation by the TRRC. Should the status of these non-utility facilities change, they would become subject to rate regulation by the TRRC, which could adversely affect the rates that our facilities are allowed to charge their customers. Texas also administers federal pipeline safety standards under the Pipeline Safety Act of 1968. The non-jurisdictional gathering exemption under the Natural Gas Pipeline Safety Act of 1968 presently exempts most of our gathering facilities from jurisdiction under that statute. The “rural gathering exemption,” however, may be restricted in the future. As a result of recent pipeline incidents in other parts of the country, Congress and the Department of Transportation have passed or are considering imposing more stringent pipeline safety requirements.
The DOT regulates the design, installation, testing, construction, operation, replacement, and management of our pipeline facilities. In addition, we must permit access to and copying of records, and must make certain reports and provide information, as required by the Secretary of Transportation. The states in which we have pipelines have comparable regulations.
We are subject to regulation by the DOT under the Accountable Pipeline and Safety Partnership Act of 1996, sometimes referred to as the Hazardous Liquid Pipeline Safety Act (“HLPSA”), and comparable state statutes relating to the design, installation, testing, construction, operation, replacement and management of our pipeline facilities. The HLPSA covers petroleum and petroleum products. The HLPSA requires any entity that owns or operates pipeline facilities to (i) comply with such regulations, (ii) permit access to and copying of records, (iii) file certain reports and (iv) provide information as required by the Secretary of Transportation. We believe that we are in material compliance with these HLPSA regulations.
We are subject to the DOT regulation requiring qualification of pipeline personnel. The regulation requires pipeline operators to develop and maintain a written qualification program for individuals performing covered tasks on pipeline facilities. The intent of this regulation is to ensure a qualified work force and to reduce the probability and consequence of incidents caused by human error. The regulation establishes qualification requirements for individuals performing covered tasks. We believe that we are in material compliance with these DOT regulations.
We are also subject to the DOT Integrity Management regulations, which specify how companies should assess, evaluate, validate and maintain the integrity of pipeline segments that, in the event of a release, could impact High
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Consequence Areas (“HCAs”). HCAs are defined to include populated areas, unusually sensitive environmental areas and commercially navigable waterways. We are required to develop and implement an Integrity Management Program (“IMP”) that utilizes internal pipeline inspection, pressure testing, or other equally effective means to assess the integrity of HCA pipeline segments. We are also required to periodically review HCA pipeline segments to ensure adequate preventative and mitigative measures exist and take prompt action to address integrity issues raised by the assessment and analysis.
We are also subject to the EPA’s Risk Management Plan (“RMP”) regulations at certain facilities. These regulations are intended to work with the OSHA Process Safety Management regulations to minimize the offsite consequences of catastrophic releases. The regulations required us to develop and implement a risk management program that includes a five-year accident history, an offsite consequence analysis process, a prevention program and an emergency response program. We believe we are operating in material compliance with our risk management program.
We note that the TRRC is subject to a sunset condition. If the Texas Legislature does not continue the TRRC, the TRRC will be abolished effective September 1, 2011, and will begin a one-year wind-down process. The Sunset Advisory Commission has recommended certain organizational changes be made to the TRRC. We cannot tell what, if any, changes will be made to the TRRC as a result of the pending regular session or any called sessions of the Texas Legislature in 2011, but we do not believe that any such changes would affect our business in a way that would be materially different from the way such changes would affect our competitors.
Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels. Our gathering operations could be adversely affected should they be subject in the future to increased regulation of rates and services. Our gathering operations also may be or become subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.
Intrastate Pipeline Regulation. Our DeSoto Pipeline transports natural gas both in intrastate commerce and in interstate commerce on its North and Central Texas Systems. The TRRC has authority over the rates, terms and conditions of service for DeSoto Pipeline's intrastate transportation activities. FERC exercises authority over the rates, terms and conditions of service for DeSoto Pipeline's interstate transportation activities. Pursuant to Section 311 of the NGPA, rates for such transportation must be “fair and equitable,” and amounts collected in excess of “fair and equitable” rates are subject to refund with interest.
Sales of Natural Gas. Our sales for resale of natural gas are conducted pursuant to a blanket marketing certificate issued by the FERC. The price at which we buy and sell natural gas currently is not subject to federal regulation and, for the most part, is not subject to state regulation. Our sales of natural gas are affected by the availability, terms and cost of pipeline transportation. As noted above, the price and terms of access to pipeline transportation are subject to extensive federal and state regulation. The FERC is continually proposing and implementing new rules and regulations affecting the natural gas industry. These initiatives may affect the intrastate transportation of natural gas under certain circumstances. FERC has imposed an annual reporting requirement on all industry participants, including otherwise non-jurisdictional entities, engaged in wholesale physical natural gas sales and purchases in excess of a de minimis level. Further, our physical purchases and sales of natural gas, our gathering and/or transportation of natural gas, and any related hedging activities that we undertake are subject to anti-market manipulation regulation by FERC and/or the Commodity Futures Trading Commission. These agencies hold substantial enforcement authority, including the ability to assess substantial civil penalties, to order disgorgement of profits, and to recommend criminal penalties for violations of anti-market manipulation laws and related regulations. Violation of the anti-market manipulation laws and regulations could also subject us to related third-party damage claims. We do not believe that we will be affected by these anti-market manipulation requirements materially differently than other natural gas marketers with whom we compete.
Intrastate NGL Pipeline Regulation. We do not own any NGL pipelines subject to FERC regulation. We do own and operate an intrastate common carrier NGL pipeline subject to the regulation of the TRRC. The TRRC requires that intrastate NGL pipelines file tariff publications that contain all the rules and regulations governing the rates and charges for service performed. The applicable Texas statutes require that NGL pipeline rates provide no more than a fair return on the aggregate value of the pipeline property used to render services. State commissions have generally not been aggressive in regulating common carrier pipelines and have generally not investigated the rates or practices of NGL pipelines in the absence of shipper complaints. Complaints to state agencies have been infrequent and are usually resolved informally. Although we cannot assure you that our intrastate rates would ultimately be upheld if challenged, we believe that, given this history, the tariffs now in effect are not likely to be challenged or, if challenged, are not likely to be ordered to be reduced.
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Upstream Business
The natural gas and oil industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the natural gas and oil industry is constantly evolving, frequently increasing the regulatory burden. Numerous departments and agencies, both federal and state, are authorized by statute to issue new and revised rules and regulations, some of which carry substantial penalties for failure to comply which could be applicable to our business. Although the regulatory burden on the natural gas and oil industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.
Legislation continues to be introduced in Congress and development of regulations continues in the Department of Homeland Security and other agencies concerning the security of industrial facilities, including natural gas and oil facilities. Our operations may be subject to such laws and regulations. Presently, it is not possible to accurately estimate the costs we could incur to comply with any such laws or regulations, but such expenditures could be substantial.
Drilling and Production. The activities conducted by us and by the operators on our properties are subject to significant regulation at the federal, state and local levels. These regulations include requiring permits for the drilling of wells, posting of drilling bonds and filing reports concerning operations. Most states, and some counties and municipalities, in which we operate also regulate one or more of the following:
• | the location of wells; |
• | the method of drilling and casing wells; |
• | the surface use and restoration of properties upon which wells are drilled; |
• | the disposal of fluids and solids used in connection with our operations; |
• | air emissions associated with our operations; |
• | the plugging and abandoning of wells; and |
• | notice to surface owners and other third parties. |
State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of natural gas and oil properties. Some states allow forced pooling or integration of tracts to facilitate exploitation while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from natural gas and oil wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of natural gas and oil we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction. Additionally, some municipalities also impose property taxes on oil and natural gas interests, production equipment, and our production revenues.
Federal Regulation. The availability, terms and cost of transportation significantly affect sales of natural gas. The interstate transportation and sale for resale of natural gas are subject to federal regulation, including regulation of the rates, terms and conditions of service for interstate transportation, storage and various other matters, primarily by the FERC. Our sale of gas in interstate markets is subject to FERC authority and rules prohibiting market manipulation. Further, FERC has imposed new reporting requirements on entities engaged in wholesale physical natural gas transactions as part of FERC’s initiatives to facilitate price transparency. Federal and state regulations govern the price and terms for access to natural gas pipeline transportation. The FERC’s regulations for interstate natural gas transmission in some circumstances may also affect the intrastate transportation of natural gas.
Although natural gas prices are currently unregulated, Congress historically has been active in the area of natural gas regulation. We cannot predict whether new legislation to regulate natural gas prices or market participants might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on the operations of the underlying properties. Sales of condensate and natural gas liquids are not
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currently regulated and are made at market prices.
State Regulation. The various states regulate the drilling for, and the production, gathering and sale of, natural gas, including imposing severance taxes and requirements for obtaining drilling permits. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but there can be no assurance that they will not do so in the future. The effect of these regulations may be to limit the amounts of natural gas that may be produced from our wells, and to limit the number of wells or locations we can drill.
The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to occupational safety, resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect upon the unitholders.
Environmental Matters
Midstream Business
We operate pipelines, plants, and other facilities for gathering, compressing, treating, processing, fractionating, or transporting natural gas, NGLs, and other products that are subject to stringent and complex federal, state, and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection or safety. These laws and regulations can adversely affect our capital expenditures, earnings and competitive position in many ways, such as requiring the acquisition of permits to conduct regulated activities; restricting the manner in which we can release materials into the environment; requiring remedial activities or capital expenditures to mitigate pollution from former or current operations, including accidental releases and spills; and imposing substantial liabilities on us for pollution resulting from our operations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, and the issuance of injunctions limiting or prohibiting our activities. We have programs and policies designed to keep our pipelines, plants, and other facilities in compliance with existing environmental laws and regulations. The trend in environmental regulation, however, is to place more restrictions on activities that may affect the environment, and thus, any changes in environmental laws and regulations that result in more stringent and costly waste handling, storage, transport, disposal, or remediation requirements could have a material adverse effect on our operations and financial position. We may be unable to pass on such increased compliance costs to our customers.
The following is a summary of the more significant existing environmental laws and regulations to which our business operations are subject.
The Comprehensive Environmental Response, Compensation and Liability Act, as amended, also known as “CERCLA” or “Superfund,” and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. Under CERCLA, these “responsible persons” may be subject to joint and several, strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances into the environment. We generate materials in the course of our operations that may be regulated as hazardous substances We also may incur liability under the Resource Conservation and Recovery Act, as amended, also known as “RCRA,” which imposes requirements related to the handling and disposal of solid and hazardous wastes, as well as similar state laws. In the course of our operations we may generate petroleum product wastes and ordinary industrial wastes that may be regulated as solid and hazardous wastes under RCRA.
We currently own or lease, and have in the past owned or leased, properties that for many years have been used for midstream natural gas and NGL activities. Although we used operating and disposal practices that were standard in the industry at the time, petroleum hydrocarbons or wastes may have been disposed of or released on or under the properties owned or leased by us or on or under other locations where such wastes have been taken for disposal. In addition, some of these properties have been operated by third parties whose treatment and disposal or release of petroleum hydrocarbons and wastes were not under our control. These properties and the materials disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of by prior owners or operators) or contaminated property (including ground water contamination), or to perform activities to prevent future contamination.
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The Federal Clean Air Act, as amended, and comparable state laws restrict the emission of air pollutants from many sources, including our processing plants and compressor stations. These laws and any implementing regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to emit new pollutants or increased existing pollutants, obtain and comply with air permits containing various emission and operational limitations, and utilize specific equipment or technologies to control emissions. We may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. Please refer to our discussion under the heading Legal Proceedings for further information on this subject. In 2010, the EPA adopted final rules making more stringent the National Ambient Air Quality Standards (“NAAQS”) for sulfur dioxide and nitrogen dioxide. Further, EPA has proposed to lower the ozone NAAQS, and has projected a final action in 2011. Attainment of these new NAAQS will likely require us to install more stringent controls at our facilities, which would result in increased capital expenditures.
Federal regulations limiting greenhouse gas ("GHG") emissions or imposing reporting obligations with respect to such emissions have been proposed or finalized. On October 30, 2009, EPA published a final rule (GHG Mandatory Reporting Rule ("MRR") Subpart C- Combustion) requiring the reporting of GHG emissions from specified sources in the United States beginning in 2011 for emissions occurring in 2010. We have ten facilities that are reporting as required by this rule. In addition, on December 15, 2009, EPA published Final Endangerment findings that current and projected concentrations of six key GHGs in the atmosphere threaten public health and welfare of current and future generations. EPA also found that the combined emissions of these GHGs from new motor vehicles and new motor vehicle engines contribute to the GHG pollution that threatens public health and welfare. These findings do not impose any requirements on industry or other entities directly; however, after the rule's January 14, 2010 effective date, EPA finalized the motor vehicle GHG standards, the effect of which requires an increase in fuel efficiency thereby reducing demand for motor fuels refined from crude oil. Finally, the motor vehicle GHG standard triggered construction and operating permit requirements for stationary sources. As a result, EPA has published a GHG tailoring rule such that only stationary sources that emit over 75,000 tons of GHGs per year are subject to Prevention of Significant Deterioration (PSD) air permitting requirements. Future expansions or physical changes to our facilities will be subject to more stringent air permitting regulations as a result of this rule. Any limitation on emissions of GHGs from our equipment or operations could require us to incur costs to reduce such emissions. In addition, on November 30, 2010, EPA issued the GHG MRR final rule for Subpart W-Petroleum and Natural Gas Systems. Subpart W establishes a new comprehensive scheme requiring midstream operators of stationary sources above a designated threshold to report their GHG emissions annually. Legislation has also been introduced in the United States Congress that would establish measures restricting greenhouse gas emissions in the United States.
Although it is not possible at this time to predict how legislation enacted to address climate change may impact our business, any future federal laws or implementing regulations that may be adopted to address greenhouse gas emissions, as well as future climate change litigation against us or our customers for GHG emissions, could result in increased compliance costs or additional operating restrictions. Moreover, new legislation or rules establishing mandates or incentives to conserve energy or use alternative energy sources could have an adverse effect on demand for the oil and natural gas we produce and distribute.
In addition to the effects of future regulation, the meteorological effects of global climate change could pose additional risks to our operations in the form of more frequent and/or more intense storms and flooding, which could in turn adversely affect our cost of doing business.
The Federal Water Pollution Control Act of 1972, as amended, also known as the “Clean Water Act,” and analogous state laws impose restrictions and controls on the discharge of pollutants into federal and state waters. Pursuant to these laws and regulations, we are required to obtain and maintain approvals or permits for certain wastewater and stormwater discharges and discharges of dredged or fill material in wetlands and other waters of the United States, as well as develop and to implement spill prevention, control and countermeasure plans, also referred to as “SPCC plans,” in connection with on-site storage of greater than threshold quantities of oil.
The primary federal law for oil spill liability is the Oil Pollution Act of 1990 (“OPA”), which addresses three principal areas of oil pollution—(a) prevention, (b) containment and cleanup, and (c) liability. OPA applies to vessels, offshore platforms and onshore facilities, including terminals, pipelines and transfer facilities, and subjects owners of such facilities to strict liability for containment and removal costs, natural resource damages and certain other consequences of an oil spill, where such spill is into waters of the U.S. Any unpermitted release of petroleum or other pollutants from our operations could result in penalty liability. Some states maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. These programs may also require remedial activities or capital expenditures to mitigate groundwater contamination along our pipeline systems as a result of past or current operations. Contamination of groundwater resulting from spills or releases of oil or gas is an inherent risk within our industry.
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The federal Endangered Species Act, as amended, or “ESA,” restricts activities that may affect endangered or threatened species or their habitats. While some of our facilities may be located in areas that are designated as habitat for endangered or threatened species, we believe that we are in substantial compliance with the ESA. However, the designation of previously unidentified endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas.
In addition to claims arising under state and federal statutes, where a release or spill of hazardous substances, oil and gas, or oil and gas wastes have occurred, private parties or landowners may bring lawsuits under state law. The plaintiffs in such lawsuits may seek property damages, personal injury damages, remediation costs or injunctions to require remediation or restoration of contaminated environmental media, including soil, sediment, groundwater or surface water. Some of our, oil and gas operations are located near populated areas and routine emissions or accidental releases could affect the surrounding properties and population.
Upstream Business
Our Upstream Business involves acquiring, developing and producing oil and natural gas working interests.
Our and our lease operators’ operations are subject to stringent and complex federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection or safety. Our Upstream Business is subject to the same environmental laws and regulations that are discussed in our Midstream Business section above. Like our Midstream Business, our Upstream Business could be impacted by any legislation or regulations that are adopted to address greenhouse gas emissions in the United States. For further discussion of these environmental laws and regulations, including greenhouse gas, see “-Midstream Business” above.
On our working interest properties, and particularly our operated properties, we are responsible for conducting operations in a manner that complies with applicable environmental laws and regulations. These laws and regulations can adversely affect our capital expenditures, earnings and competitive position in many ways, such as:
• | requiring the acquisition of various permits before drilling commences; |
• | requiring the installation of expensive pollution control equipment; |
• | restricting the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities; |
• | limiting or prohibiting drilling activities on lands lying within wilderness, wetlands and other protected areas; |
• | requiring remedial measures to prevent pollution from former operations, such as pit closure and plugging of abandoned wells; |
• | imposing substantial liabilities for pollution resulting from our operations; |
• | with respect to operations affecting federal lands or leases, requiring preparation of a Resource Management Plan, an Environmental Assessment, and/or an Environmental Impact Statement; and |
• | restricting the rate of natural gas and oil production below the rate that would otherwise be possible. |
Consistent with normal industry practices, substantially all of our oil and gas leases require that, upon termination of economic production, the working interest owners’ plug and abandon non-producing wellbores, remove tanks, production equipment and flow lines and restore the wellsite. We have recorded liabilities for these asset retirement obligations in accordance with authoritative guidance which applies to obligations associated with the retirement of tangible long-lived assets that result from the acquisition, construction and development of the assets. The guidance requires that we record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset.
Federal regulations limiting greenhouse gas ("GHG") emissions or imposing reporting obligations with respect to such emissions have been proposed or finalized. On December 15, 2009, EPA published the Final Endangerment findings that current and projected concentrations of six key GHGs in the atmosphere threaten public health and welfare of current and future generations. EPA also found that the combined emissions of these GHGs from new motor vehicles and new motor vehicle engines contribute to the GHG pollution that threatens public health and welfare. This Final Rule does not impose any
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requirements on industry or other entities directly; however, after the rule's January 14, 2010 effective date, EPA finalized the motor vehicle GHG standards, the effect of which requires the increase in fuel efficiency thereby reducing demand for motor fuels refined from crude oil. Finally the motor vehicle GHG standard triggered construction and operating permit requirements for stationary sources. As a result, EPA has published a GHG tailoring rule such that only stationary sources, including refineries that emit over 75,000 tons of GHGs per year are subject to Prevention of Significant Deterioration (PSD) air permitting requirements. Any limitation on emissions of GHGs from our equipment or operations could require us to incur costs to reduce such emissions. In addition, on November 30, 2010, EPA issued the GHG MRR final rule for Subpart W- Petroleum and Natural Gas Systems. Subpart W establishes a new comprehensive scheme requiring upstream operators with GHG emissions of 25,000 tpy COe to report their GHG emissions annually by Basin as defined by the American Association of Petroleum Geologists. Although it is not possible at this time to predict how legislation enacted to address climate change may impact our business, any future federal laws or implementing regulations that may be adopted to address greenhouse gas emissions, as well as future climate change litigation against us or our customers for GHG emissions, could result in increased compliance costs or additional operating restrictions. Moreover, new legislation or rules establishing mandates or incentives to conserve energy or use alternative energy sources could have an adverse effect on demand for the oil and natural gas we produce and distribute.
While we believe that our operations are in substantial compliance with existing environmental laws and regulations will not have a material adverse effect on our capital expenditures, earnings and competitive position and that continued compliance with current requirements would not have a material adverse effect on us, there is no assurance that this trend will continue in the future.
Title to Properties and Rights-of-Way
Midstream Business
Our midstream real property falls into two categories: (1) parcels that we own in fee simple and (2) parcels in which our interest derives from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities permitting the use of such land for our operations. Portions of the land on which our plants and other major facilities are located are owned by us in fee title, and we believe that we have satisfactory title to these lands. The remainder of the land on which our plant sites and major facilities are located are held by us pursuant to ground leases between us, as lessee, and the fee owner of the lands, as lessors. We, or our predecessors, have leased these lands for many years without any material challenge known to us relating to the title to the land upon which the assets are located, and we believe that we have satisfactory leasehold estates to such lands. We have no knowledge of any challenge to the underlying fee title of any material lease, easement, right-of-way, permit or license held by us or to our title to any material lease, easement, right-of-way, permit or lease, and we believe that we have satisfactory title to all of our material leases, easements, rights-of-way, permits and licenses.
Upstream Business
As is customary in the natural gas and oil industry, we initially conduct only a cursory review of the title to our properties on which we do not have proved reserves. Prior to completing an acquisition of producing natural gas properties, we perform title reviews on the most significant leases and, depending on the materiality of properties or irregularities we may observe in the title chain, we may obtain a title opinion or review previously obtained title opinions. As a result, we have obtained or reviewed title opinions on a significant portion of our natural gas properties and believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the natural gas and oil industry. Our natural gas properties are subject to customary royalty and other interests, liens for current taxes and other burdens which we believe do not materially interfere with the use of or affect our carrying value of the properties.
Employees
To carry out our operations, as of December 31, 2010, Eagle Rock Energy G&P, LLC or its affiliates employed approximately 367 people who provide direct support for our operations. None of these employees are covered by collective bargaining agreements. Eagle Rock Energy G&P, LLC considers its employee relations to be good.
Available Information
Eagle Rock provides access free of charge to all of its SEC filings, as soon as reasonably practicable after filing or furnishing it, on its internet site located at www.eaglerockenergy.com. The Partnership will also make available to any unitholder, without charge, copies of its Annual Report on Form 10-K as filed with the SEC. For copies of this, or any other filing, please contact: Eagle Rock Energy Partners, L.P., General Counsel or Chief Financial Officer, 1415 Louisiana Street,
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Suite 2700, Houston, TX 77002, or call 281-408-1200. Unless explicitly stated otherwise herein, the information on our website is not incorporated by reference into this Annual Report on Form 10-K.
In addition, the public may read and copy any materials Eagle Rock files with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC maintains an internet site (www.sec.gov) that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC.
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Item 1A. Risk Factors.
Limited partner interests are inherently different from capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in similar businesses.
If any of the following risks were actually to occur, our business, financial condition or results of operations could be materially adversely affected. In that case, we might not be able to pay a distribution on our common units, the trading price of our common units could decline and you could lose all or part of your investment.
Certain risks apply to both our midstream business and our upstream business. To the extent any risk applies to one or the other, we have indicated the specific risk in the appropriate risk factor.
Risks Related to Our Business
Because of the natural decline in production from existing wells, our success depends on our ability to obtain new sources of production and supplies of oil, natural gas and NGLs, which are dependent on certain factors, many of which are beyond our control. Our success is also dependent on developing current reserves. Any decrease in production or supplies of oil, natural gas or NGLs could adversely affect our business and operating results.
The volume of gas that we gather, process and/or produce is dependent on the level of production from hydrocarbon-producing wells. The production rate of these wells naturally will decline over time, and as a result, our cash flows associated with them will also decline over time. In order to maintain or increase the throughput levels of our assets we must continually obtain new supplies of natural gas to offset these declines.
In our Midstream Business, the primary factors affecting our ability to obtain new supplies of natural gas and NGLs and attract new customers to our assets include: (i) the level of successful drilling activity by producers near our systems and (ii) our ability to compete for volumes from successful new wells. The level of drilling activity is dependent on economic and business factors that are beyond our control. The primary factor that impacts producers’ drilling decisions is natural gas prices. A sustained decline in natural gas prices could result in a decrease in exploration and development activities in the fields served by our gathering systems and our natural gas treating and processing plants, which would lead to reduced utilization of these assets. Other factors that impact production decisions include producers’ capital budgets, the ability of producers to obtain capital and necessary drilling and other governmental permits and regulatory changes. Because of these factors, even if new natural gas reserves are discovered in areas served by our assets, we and other producers may choose not to develop those reserves.
In our Upstream Business, we also have risks inherent with declining reserves. Our producing reservoirs experience production rate declines that vary depending upon reservoir characteristics and other factors. The overall production decline rate of our upstream business may change when additional wells are drilled, make acquisitions and under other circumstances. Our future cash flows and income, and our ability to maintain and to increase distributions to unitholders, are partly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs, which would adversely affect our business, financial condition and results of operations. Factors that may hinder our ability to acquire additional reserves or develop current reserves include competition, access to capital, prevailing oil and natural gas prices, the costs incurred by us to develop and exploit current and future oil and natural gas reserves, and the number and attractiveness of properties for sale.
Natural gas, NGLs, crude oil and other commodity prices are volatile, and an adverse movement in these prices could adversely affect our cash flow and our ability to make distributions.
We are subject to risks due to frequent and often substantial fluctuations in commodity prices. In the past, the prices of natural gas, NGLs and crude oil have been extremely volatile, and we expect this volatility to continue. A drop in prices can significantly affect our financial results and impede our growth, including our ability to maintain or increase our borrowing capacity, to repay current or future indebtedness and to obtain additional capital on attractive terms, all of which can affect our ability to pay distributions.
Changes in natural gas, NGL and crude oil prices have a significant impact on the value of our reserves and on our cash flows. In 2010, the settlement price of the prompt month NYMEX natural gas contract ranged from $3.29 per MMBtu to $6.01 per MMBtu, and the settlement price of prompt month NYMEX crude oil contract ranged from $68.01 per barrel to $91.51 per barrel.
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The prices for natural gas, NGLs and crude oil depend upon the supply and demand for these products, which in turn depend on a large number of complex, interrelated factors that are beyond our control. These factors include:
• | the overall level of economic activity in the United States and the world; |
• | the impact of weather or other force majeure events; |
• | political and economic conditions and events in, as well as actions taken by, foreign oil and natural gas producing nations; |
• | significant crude oil or natural gas discoveries; |
• | application of new technologies that make the development of large resource plays economically attractive; |
• | the availability of local, intrastate and interstate transportation systems including natural gas pipelines and other transportation facilities to our production; |
• | the availability and marketing of competitive fuels; |
• | delays or cancellations of crude oil and natural gas drilling and production activities; |
• | the impact of energy conservation efforts, including technological advances affecting energy consumption; and |
• | the extent of governmental regulation and taxation. |
Lower natural gas, NGLs or crude oil prices may not only decrease our revenues and net proceeds, but also reduce the amount of natural gas, NGLs or crude oil that we, and other producers using our midstream assets, can economically produce. As a result, the operators may, especially during periods of low commodity prices, decide to shut in or curtail production, or to plug and abandon marginal wells.
Low commodity prices may result in additional write-downs of our asset carrying values.
In our Upstream Business, low oil and natural gas prices may result in substantial downward adjustments to our estimated proved reserves. Furthermore, if our estimates of development costs increase, production data factors change or drilling results deteriorate, accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties. Low oil and natural gas prices also may result in reduced drilling activity and declines in future cash flows within our Midstream Business.
We are required to perform impairment tests on our assets periodically and whenever events or changes in circumstances warrant a review of our assets. To the extent such tests indicate a reduction of the estimated future cash flows of our assets, the carrying value may not be recoverable and therefore may require a write-down. During the year ended December 31, 2010, we incurred total impairment charges of $32.9 million primarily as a result of contract terminations notifications by significant producers in our South Texas Segment. During the year ended December 31, 2009, we incurred total impairment charges of $21.8 million primarily as a result of lower drilling activity due to lower natural gas prices. During the year ended December 31, 2008, we incurred total impairment charges of $173.1 million primarily as a result of lower commodity prices. We may incur additional impairment charges in the future, which could have a material adverse effect on our results of operations and financial position in the period incurred.
The loss of any of our significant customers could result in a decline in our volumes, revenues and cash available for distribution.
In our Midstream Business, we rely on certain natural gas producer customers for a significant portion of our natural gas and NGL supply. The number and relative significance of gas suppliers can change based upon a number of reasons, including the relative success of the producers’ drilling programs, additions or cancellations of gathering and processing agreements, and the acquisition of new systems. We may be unable to negotiate new long-term contracts, or extensions or replacements of existing contracts, on favorable terms, if at all. The loss of even a portion of the natural gas volumes supplied by our significant customers, as a result of competition or otherwise, could have an adverse effect on our business, results of operations and financial condition, unless we were able to acquire comparable volumes from other sources.
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In our Upstream Business, if a significant customer reduces the volume of its purchases from us, we could experience a temporary interruption in sales of, or lower prices for, our production. As a result our revenues and cash available for distribution could decline which may adversely affect our ability to make cash distributions to our unitholders.
Our hedging activities may have a material adverse effect on our earnings, profitability, cash flows and financial condition.
Because we are exposed to risks associated with fluctuating commodity prices, we utilize various financial instruments (swaps, collars, and puts) to mitigate these risks. Nevertheless, it is possible that these hedging activities may not be effective in reducing our exposure to commodity price risk. For instance, we may not produce or process sufficient volumes to cover our hedges, we may fail to hedge a sufficient portion of our future production or the instruments we use may not adequately correlate with changes in the prices we receive. Our current hedging position is presented in Part II, Item 7A. Qualitative and Quantitative Disclosure About Market Risk.
To the extent we hedge our commodity price and interest rate risk, we may forego the benefits we would otherwise experience when commodity prices or interest rates improve. Furthermore, because we have entered into derivative transactions related to only a portion of the commodity volumes and outstanding debt to which we have price and interest rate exposure, we will continue to have direct commodity price and interest rate risk on the unhedged portion. Our actual future supply and production may be significantly higher or lower than we estimated at the time we entered into the commodity derivative transactions for that period. If the actual amount is higher than we estimated, we will have more commodity price risk than we intended. If the actual amount is lower than the amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the underlying physical commodity, resulting in a reduction of our liquidity.
As a result of these factors, our hedging activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain extreme circumstances might actually increase the volatility of our cash flows. In addition, hedging activities may result in substantial losses. Such losses could occur under various circumstances, such as when a counterparty fails to perform its obligations under the applicable hedging arrangement, the hedging arrangement is imperfect or ineffective, or our hedging policies and procedures are not properly followed or otherwise do not work as planned. The steps we take to monitor our hedging activities may not detect and prevent violations of our risk management policies and procedures, particularly if deception or other intentional misconduct is involved.
As a result of our hedging activities and our practice of marking to market the value of our hedging instruments, we will also experience significant variations in our unrealized derivative gains and losses from period to period. These variations in our unrealized gains and losses from period to period may be due to several factors including the settlement of derivative instruments during the period, the addition of new derivative positions during the period, changes in the forward curves of the underlying commodities and interest rates from the beginning of the period to the end of the period relative to the strike price of our derivative contracts, changes in interest rates used in the mark to market calculations from the beginning of the period to the end of the period, and the passage of time. These unrealized gains and losses impact our earnings and other profitability measures. To illustrate, during the year ended December 31, 2010, we recorded an unrealized gain of $5.0 million as compared to the year ended December 31, 2009, in which we recorded an unrealized loss of $128.7 million. Unrealized gains and losses have no impact on our cash activities and are excluded by definition from our calculation of Adjusted EBITDA. For additional information regarding our hedging activities, please read Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations and Part II, Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
We have significant indebtedness under our revolving credit facility, which may limit our flexibility in obtaining additional financing and in pursuing other business opportunities. In addition, we may incur substantial debt in the future to enable us to maintain or increase our reserve and production levels and to otherwise pursue our business plan. This debt may restrict our ability to make distributions.
As of December 31, 2010, we had $530.0 million outstanding under our senior secured credit facility. We had approximately $341 million of unused capacity under the senior secured credit facility (before taking into account covenant-based capacity limitations but after considering the approximately $9.1 million of unfunded commitments from Lehman Brothers that is no longer available after Lehman Brothers' bankruptcy filing) as of December 31, 2010. Our level of outstanding debt could have important consequences to us, including the following:
• | our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms; |
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• | we will need a portion of our cash flow to make interest payments on our debt, reducing the funds that would otherwise be available for operations, future business opportunities and distributions to unitholders; |
• | our debt level will make us more vulnerable to competitive pressures or a downturn in our business or the economy generally; and |
• | our debt level may limit our flexibility in responding to changing business and economic conditions. |
Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. In addition, our ability to service debt under our credit facility will depend on market interest rates, since we anticipate that the interest rates applicable to our borrowings will fluctuate with movements in interest rate markets. If our operating results are not sufficient to service our current or future indebtedness or comply with our financial covenants under our existing credit facility, we will be forced to take actions such as eliminating, reducing or further reducing distributions, reducing or delaying our business activities and expenses, acquisitions, investments or capital expenditures, selling assets, restructuring or refinancing our debt, or seeking additional equity capital. We may not be able to affect any of these actions on satisfactory terms, or at all.
Our Upstream Business requires a significant amount of capital expenditures to maintain and grow production levels. If commodity prices were to decline for an extended period of time, if the costs of our acquisition and drilling and development operations were to increase substantially, or if other events were to occur which reduced our revenues or increased our costs, we may be required to borrow significant amounts in the future to enable us to finance the expenditures necessary to replace the reserves we produce. The cost of the borrowings and our obligations to repay the borrowings will reduce amounts otherwise available for distributions to our unitholders.
Low commodity price levels have resulted in, and may result in further, decreases of our borrowing base under our credit facility, impacting our covenant compliance.
Our credit facility accommodates, through the use of a borrowing base for our Upstream Business and traditional cash-flow based covenants for our Midstream Business, the allocation of indebtedness to either our Upstream Business (to be measured against the borrowing base) or to our Midstream Business (to be measured against the cash-flow based covenant). As of December 31, 2010, our borrowing base under our credit facility for our Upstream Business was $140 million. A decrease in our borrowing base would result in a higher allocation of indebtedness to our Midstream Business and a rise in our leverage ratio which may impact our availability under our credit facility and, potentially, put us at risk of breach covenants.
Restrictions in our credit facility limit our ability to make distributions in certain circumstances and limit our ability to enter into certain types of acquisitions and other business opportunities.
Our credit facility contains covenants limiting our ability to make distributions, incur indebtedness, grant liens, make acquisitions, investments or dispositions and engage in transactions with affiliates. Furthermore, our credit facility contains covenants requiring us to maintain certain financial ratios and tests. Any subsequent replacement, restatement or amendment of our credit facility or any new indebtedness could impose similar or greater restrictions.
We may not be able to execute our business strategy if we encounter illiquid capital and commercial credit markets.
One component of our business strategy contemplates pursuing opportunities to acquire assets where we believe growth opportunities are attractive and our business strategies could be applied. We regularly consider and enter into discussions regarding strategic transactions that we believe will present opportunities to pursue our growth strategy.
We will require substantial new capital to finance strategic acquisitions. Any limitations on our access to capital or commercial credit will impair our ability to execute this component of our growth strategy. If the cost of such capital or credit becomes too expensive, our ability to develop or acquire accretive assets will be limited. We may not be able to raise the necessary funds on satisfactory terms, if at all. The primary factors that influence our cost of capital include our units’ market performance, conditions in the commercial credit, debt and equity markets and offering or borrowing costs such as interest rates or underwriting discounts.
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Our operations will require substantial capital expenditures, which will reduce our cash available for distribution. We may be unable to obtain needed capital or financing on satisfactory terms or at all, which could lead to a decline in our cash flows.
The oil and natural gas industry is capital intensive. We expect to continue to make substantial capital expenditures in our business for the maintenance, construction and acquisition of midstream assets and oil and natural gas reserves. We intend to finance our future capital expenditures with cash flows from operations, borrowings under our credit facility and the issuance of debt and equity securities, when market conditions allow. The incurrence of debt will require that a portion of our cash flows from operations be used for the payment of interest and principal on our debt, thereby reducing our ability to use cash flows to fund working capital, capital expenditures and acquisitions. Our cash flows from operations and access to capital are subject to a number of variables, including:
• | volume throughput through our pipelines and processing facilities; |
• | the estimated quantities of our oil and natural gas reserves; |
• | the amount of oil and natural gas produced from existing wells; |
• | the prices at which we sell our production or that of our midstream customers; |
• | the strike prices of our hedges; |
• | our operating and general and administrative expenses; and |
• | our ability to acquire, locate and produce new reserves. |
If our revenues or the borrowing base under our credit facility decrease as a result of lower commodity prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels, or to pursue our growth strategy. Our credit facility may restrict our ability to obtain new financing. If additional capital is needed, we may not be able to obtain debt or equity financing on terms favorable to us, or at all. If cash generated by operations or available under our credit facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our capital projects, which in turn could lead to a possible decline in our gathering and processing available capacity or in our natural gas and crude oil reserves and production, which could adversely effect our business, results of operation, financial conditions and ability to make distributions to our unitholders. In addition, we may lose opportunities to acquire oil and natural gas properties and businesses.
To fund our capital expenditures, we will be required to use cash generated from our operations, additional borrowings or the issuance of additional partnership interests, or some combination thereof.
In 2011, our capital program is expected to be approximately $78 million, excluding acquisitions. Use of cash generated from operations to fund future capital expenditures will reduce cash available for distribution to our unitholders. Our ability to obtain bank financing or to access the capital markets for future equity or debt offerings to fund future capital expenditures may be limited by our financial condition at the time of any such financing or offering and the covenants in our debt agreements, as well as by oil and natural gas prices, the value and performance of our equity securities, and adverse market conditions resulting from, among other things, general economic conditions and contingencies and uncertainties that are beyond our control. Our failure to obtain the funds for necessary future capital expenditures could have a material adverse effect on our business, results of operations, financial condition and ability to pay distributions. Even when we are successful in obtaining the necessary funds, the terms of such financings could limit our ability to pay distributions to our unitholders. In addition, incurring additional debt may significantly increase our interest expense and financial leverage, and issuing additional partnership interests may result in significant unitholder dilution which could have a material adverse effect on our ability to pay distributions at the then-current distribution rate.
If we do not make acquisitions on economically acceptable terms, our future growth will be limited.
Our ability to grow our business depends, in part, on our ability to make acquisitions that are accretive to our cash available for distributions on a per unit basis. If we are unable to make these accretive acquisitions because we are: (1) unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them, (2) unable to obtain financing for these acquisitions on economically acceptable terms, or (3) outbid by competitors, then our future growth and ability to
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increase distributions will be limited. Furthermore, even if we do make acquisitions that we believe will be accretive, these acquisitions may nevertheless result in a decrease in the cash generated from operations per unit because of unforeseen circumstances.
All acquisitions involve potential risks, including, among other things:
• | mistaken assumptions about future prices, volumes, revenues and costs of oil and natural gas, including synergies and estimates of the oil and natural gas reserves attributable to a property we acquire; |
• | an inability to integrate successfully the businesses we acquire; |
• | inadequate expertise for new geographic areas, operations or products and services; |
• | inefficiencies and complexities that can arise because of unfamiliarity with new assets and the businesses associated with them, including their markets; |
• | the assumption of unknown liabilities for which we are not indemnified or for which our indemnity is inadequate; |
• | limitations on rights to indemnity from the seller; |
• | mistaken assumptions about the overall costs of equity or debt; |
• | decrease in our liquidity as a result of our using a significant portion of our available cash or borrowing capacity to finance the acquisition; |
• | a significant increase in our interest expense or financial leverage if we incur additional debt to finance the acquisition; |
• | the diversion of management's and employees’ attention from other business concerns; |
• | customer or key employee losses at the acquired businesses; and |
• | establishment of internal controls and procedures that we are required to maintain under the Sarbanes-Oxley Act of 2002. |
If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and our limited partners will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider.
Our ability to derive benefits from our acquisitions will depend on our ability to successfully integrate the acquired operations.
Achieving the anticipated benefits from acquisitions depends in part upon whether we are able to successfully integrate the assets or businesses of these acquisitions, in an efficient and effective manner. The difficulties combining businesses or assets potentially will include, among other things:
• | geographically separated organizations and possible differences in corporate cultures and management philosophies; |
• | significant demands on management resources, which may distract management's attention from day-to-day business; |
• | differences in the disclosure systems, accounting systems, and accounting controls and procedures of the two companies, which may interfere with our ability to make timely and accurate public disclosure; and |
• | the demands of managing new lines of business acquired. |
Any inability to realize the potential benefits of the acquisition, as well as any delays in integration, could have an adverse effect upon the revenues, level of expenses and operating results of the company, after the acquisitions, which may affect the value of our common units after the acquisition.
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Failure of the natural gas, NGLs, condensate or other products produced at our plants or shipped on our pipelines to meet the specifications of interconnecting pipelines or markets could result in curtailments by the pipelines or markets.
The markets and pipelines to which we deliver natural gas, NGLs, condensate or other products typically establish specifications for the products that they are willing to accept. These specifications include requirements such as hydrocarbon dewpoint, compositions, temperature, and foreign content (such as water, sulfur, carbon dioxide, and hydrogen sulfide), and these specifications can vary by product, pipeline or markets. If the total mix of a product that we deliver to a pipeline or market fails to meet the applicable product quality specifications, the pipeline or market may refuse to accept all or a part of the products scheduled for delivery to it or may invoice us for the costs to handle the out-of-specification products. In those circumstances, we may be required to find alternative markets for that product or to shut-in the producers of the non-conforming natural gas that is causing the products to be out of specification, potentially reducing our through-put volumes or revenues.
We may encounter obstacles to marketing our oil, natural gas, NGLs and sulfur, which could adversely impact our revenues.
Access to markets is, in many respects, beyond our control. Access to markets for our production will depend in part upon the availability, proximity and capacity of natural gas gathering systems, pipelines, fractionators, storage and transportation facilities owned by third parties. The amount of oil, natural gas and NGLs that can be produced and sold is subject to limitation in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage to the gathering or transportation system, or lack of contracted capacity on such systems. The curtailments arising from these and other circumstances may last from a few days to several months, and in many cases, we are only provided with limited, if any, notice as to when these circumstances will arise and their duration. Our access to transportation options can also be affected by U.S. federal and state regulation of oil and natural gas production and transportation, general economic conditions, and changes in supply and demand. If market factors dramatically change, the impact on our revenues could be substantial and could adversely affect our ability to produce and market oil and natural gas, the value of our units and our ability to pay distributions on our units. Sulfur is a by-product associated with substantially all of the natural gas production in our upstream operations in Alabama and East Texas and we have a limited ability to store it at our facilities. If we were unable to either sell or dispose of the sulfur we produce in these areas, we may be forced to curtail our oil and gas production.
We may not successfully balance our purchases and sales of natural gas, which would increase our exposure to commodity price risks.
We purchase from producers and other customers a substantial amount of the natural gas that flows through our natural gas gathering, processing and transportation systems for resale to third parties, including natural gas pipelines, marketers and a reduced number of end-users. We may not be successful in balancing our purchases and sales. A producer or supplier could fail to deliver contracted volumes or deliver in excess of contracted volumes, or a purchaser could purchase less than contracted volumes. Any of these actions could cause our purchases and sales to be unbalanced. If our purchases and sales are unbalanced, we will face increased exposure to commodity price risks and could have increased volatility in our operating income and cash flows.
Our Upstream Business depends in part on gathering, transportation and processing facilities. Any limitation in the availability of, or our access to, those facilities would interfere with our ability to market the oil, natural gas and NGLs we produce, and could reduce our cash available for distribution and adversely impact expected increases in oil, natural gas and NGL production from our drilling program.
The marketability of our oil, gas and NGL production depends in part on the accessibility, availability, proximity and capacity of gathering, processing and pipeline systems. The amount of oil, natural gas and NGLs that can be produced and sold is subject to limitation in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage to the gathering, processing or transportation system, weather, or lack of contracted capacity on such systems. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we are provided only with limited, if any, notice as to when these circumstances will arise and their duration. In addition, some of our wells may be drilled in locations that are not serviced by gathering, processing and transportation facilities, or the gathering and transportation pipelines in the area may not have sufficient capacity to transport additional production. As a result, we may not be able to sell the oil, gas and NGL production from these wells until the necessary gathering, processing and transportation facilities are constructed. Any significant curtailment in gathering system or pipeline capacity, or significant delay in the construction of necessary gathering, processing and transportation facilities, would interfere with our ability to market the oil, gas and NGLs we produce, and could reduce our cash available for distribution and
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adversely impact expected increases in oil and gas production from our drilling program. Our access to transportation options can also be affected by U.S. federal and state regulations of oil and natural gas production and transportation and other general economic conditions beyond our control.
The prolonged shut-down of the third-party owned and operated Eustace Processing Plant may result in us not being able to bring our shut-in wells back on-line.
Oil and gas production from the Ginger/Ginger Southeast, Northeast Edgewood/Edgewood, Fruitvale/East Fruitvale and Eustace fields are processed by the Eustace processing facility, which is owned and operated by a third-party. On August 11, 2010, the Eustace processing facility was shut-down due to events stemming from an electrical failure. As a result of this shut-down, we were forced to shut-in our wells in these fields. As of March 10, 2011, the third-party operator was in the process of returning the facility to service. As a result of the prolonged shut-down of the facility, we may not be able to bring all of our wells back on-line, which could negatively impact our revenues and cash available for distributions to our unitholders.
If third-party pipelines and other facilities interconnected to our midstream systems become unavailable to transport or produce natural gas and NGLs, our revenues and cash available for distribution could be adversely affected.
We depend upon third-party pipelines, natural gas gathering systems and other facilities that provide delivery options to and from our pipelines and facilities for the benefit of our midstream customers. Since we do not own or operate any of these pipelines or other facilities, their continuing operation is not within our control. If any of these third-party pipelines and other facilities become unavailable or limited in their ability to transport or produce natural gas and NGLs, our revenues and cash available for distribution could be adversely affected.
Our industry is highly competitive, and increased competitive pressure could adversely affect our business and operating results.
We compete with similar enterprises in our respective areas of operation. Some of our competitors are large oil and natural gas companies that have greater financial resources and access to supplies of natural gas and NGLs than we do.
In our Midstream Business, some of our competitors may expand or construct gathering, processing and transportation systems that would create additional competition for the services we provide to our customers. In addition, our customers who are significant producers of natural gas may develop their own gathering, processing and transportation systems in lieu of using ours. Likewise, our customers who produce NGLs may develop their own processing facilities in lieu of using ours. Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain current revenues and cash flows could be adversely affected by the activities of our competitors and our customers. All of these competitive pressures could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions.
In our Upstream Business, our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Many of our larger competitors not only drill for and produce oil and natural gas, but also conduct refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for natural gas properties and evaluate, bid for and purchase a greater number of properties than our financial or human resources permit. In addition, these companies may have a greater ability to continue drilling activities during periods of low oil and natural gas prices, to contract for drilling equipment, to secure trained personnel and to absorb the burden of present and future federal, state, local and other laws and regulations. The oil and natural gas industry has periodically experienced shortages of drilling rigs, equipment, pipe and personnel, which has delayed development drilling and other exploitation activities and has caused significant price increases.
In both the Midstream and Upstream Businesses, competition has been strong in hiring experienced personnel, particularly in the engineering, accounting and financial reporting, tax and land departments. In addition, competition is strong for attractive midstream assets, natural gas producing properties, oil and natural gas companies and undeveloped leases and drilling rights. We may be often outbid by competitors in our attempts to acquire assets, properties or companies. Our inability to compete effectively with larger companies could have a material adverse impact on our business activities, financial condition and results of operations.
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We are exposed to the credit risk of our customers and other counterparties, and a general increase in the nonperformance by counterparties could have an adverse impact on our cash flows, results of operations and financial condition.
We are subject to risks of loss resulting from nonperformance by our customers and other counterparties, such as our lenders and other hedge counterparties. Any deterioration in the financial health of our customers and counterparties or any factors causing reduced access to capital for them may result in the reduction in their ability to pay or otherwise perform on their obligations to us. Furthermore, some of our customers may be highly leveraged and subject to their own operating and regulatory risks, which increases the risk that they may default on their obligations to us. Any increase in the nonperformance by our counterparties, either as a result of recent changes in financial and economic conditions or otherwise, could have an adverse impact on our operating results and could adversely affect our liquidity.
Our construction of new assets is subject to regulatory, environmental, political, legal and economic risks, and therefore, may not increase revenue as expected; this could adversely affect our results of operations and financial condition.
One of the ways we intend to grow our business is through the construction of new midstream assets. The construction of additions or modifications to our existing systems and the construction of new midstream assets involve numerous regulatory, environmental, political and legal uncertainties beyond our control and may require the expenditure of significant amounts of capital. If we undertake these projects, they may not be completed on schedule or at the budgeted cost, or at all.
Our revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if we expand a pipeline, the construction expenditures may occur over an extended period of time, yet we will not receive any material increases in revenues until the project is completed. Also, we may construct facilities to capture anticipated future growth in production in a region in which such growth does not materialize. To the extent we rely on estimates of future production in our decision to construct additions to our systems, such estimates may prove to be inaccurate. As a result, new facilities may not be able to attract enough throughput to achieve our expected investment return, which could adversely affect our results of operations and financial condition.
The construction of additions to our existing gathering and transportation assets may require us to obtain new rights-of-way prior to constructing new pipelines. We may be unable to obtain such rights-of-way to connect new natural gas supplies to our existing gathering lines or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for us to obtain new rights-of-way or to renew existing rights-of-way. If the cost of renewing or obtaining new rights-of-way increases, our cash flows could be adversely affected.
We do not own all of the land on which our pipelines and facilities are located, so our operations could be disrupted by actions of the landowners.
We do not own all of the land on which our pipelines and facilities have been constructed, and we are therefore subject to the possibility of more onerous terms or increased costs to retain necessary land use if we do not have valid rights of way or if such rights of way lapse or terminate. We obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies for a specific period of time. Our loss of these rights, through our inability to renew right-of-way contracts or otherwise, could have a material adverse effect on our business, results of operations and financial condition and our ability to make cash distributions.
Our business involves many hazards and operational risks, some of which may not be partially or fully insured or insurable. If a significant accident or event occurs that is not fully insured or interrupts normal operations, our operations and financial results could be adversely affected.
Our operations are subject to many hazards inherent in the drilling, producing, gathering, compressing, treating, processing and transporting of oil, natural gas and NGLs, including:
• | damage to production equipment, pipelines and plants, related equipment and surrounding properties caused by hurricanes, tornadoes, floods, fires and other natural disasters and acts of terrorism; |
• | inadvertent damage from construction, farm and utility equipment; |
• | leaks of natural gas, poisonous hydrogen sulfide gas, NGLs and other hydrocarbons or losses of natural gas or NGLs as a result of the malfunction of pipeline, equipment or facilities; |
• | fires and explosions; and |
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• | other hazards that could also result in personal injury and loss of life, pollution and suspension of operations, such as the uncontrollable flow of oil or natural gas or well fluids. |
These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage and attorney's fees and other expenses incurred in the prosecution or defense of litigation and may result in curtailment or suspension of our related operations. A natural disaster or other hazard affecting the areas in which we operate could have a material adverse effect on our operations and ability to pay distributions to our unitholders.
As is customary in the industry, we maintain insurance against some but not all of these risks. Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could therefore occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. We are not fully insured against all risks inherent to our business. For example, we are not fully insured against all environmental accidents which may include toxic tort claims. If a significant accident or event occurs that is not fully insured, it could adversely affect our operations and financial condition. In addition, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies have increased substantially, and could escalate further. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. Additionally, we may be unable to recover from prior owners of our assets, pursuant to our indemnification rights, for potential environmental liabilities. The occurrence of an event that is not fully covered by insurance could have a material adverse impact on our business activities, financial condition, results of operations and ability to pay distributions to our unitholders.
Increases in interest rates could adversely impact our unit price and our ability to issue additional equity, to incur debt to make acquisitions or for other purposes or to make cash distributions at our intended levels.
Credit markets recently have experienced record lows in interest rates. Interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, our unit price is impacted by the level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank related yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse impact on our unit price and our ability to issue additional equity, to incur debt to make acquisitions or for other purposes or to make cash distributions at our intended levels.
Shortages of drilling rigs, equipment and crews could delay our operations and reduce our cash available for distribution.
Under normal market conditions, higher oil and natural gas prices generally increase the demand for drilling rigs, equipment and crews and can lead to shortages of, and increasing costs for, drilling equipment, services and personnel. Shortages of, or increasing costs for, experienced drilling crews and oil field equipment and services could restrict our and other operators’ ability to drill the wells and conduct the operations currently planned. Any delay in the drilling of new wells or significant increase in drilling costs could reduce our revenues and cash available for distribution.
Our and other operators’ drilling operations may be curtailed, delayed or cancelled as a result of a variety of factors.
Drilling for oil and gas involves numerous risks, including the risk that we will not encounter commercially productive oil or gas reservoirs. Our and other operators’ drilling operations may be curtailed, delayed or cancelled as a result of a variety of factors, including:
• | unexpected drilling conditions; |
• | drilling, production or transportation facility or equipment failure or accidents; |
• | shortages or delays in the availability of drilling rigs and other services and equipment; |
• | adverse weather conditions; |
• | compliance with environmental and governmental requirements; |
• | title problems; |
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• | unusual or unexpected geological formations; |
• | pipeline ruptures; |
• | fires, blowouts, craterings and explosions; and |
• | uncontrollable flows of oil or natural gas or well fluids. |
Any curtailment to the gathering systems we use to deliver our oil and gas production for processing, storage or further delivery to end markets could require us to find alternative means to transport the oil and natural gas production from the underlying properties, which alternative means could require us to incur additional costs. We do not provide midstream services to all of our upstream activities.
Any such curtailment, delay or cancellation may limit our ability to make cash distributions to our unitholders.
Due to our limited industry and geographic diversification in our midstream operations and in our upstream operated properties, adverse developments in our operations or operating areas would reduce our ability to make distributions to our unitholders.
All of our midstream assets are located in the Texas Panhandle, East, West and South Texas and Louisiana, and all of our upstream operated properties are located in West, East and South Texas and Alabama. Due to our limited diversification in industry type and location, an adverse development in one of these businesses or operating areas would have a significantly greater impact on our financial condition and results of operations than if we maintained more diverse assets and operating areas.
Our estimated oil and natural gas reserve quantities and future production rates are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or the underlying assumptions will materially affect the quantities and present value of our reserves.
Numerous uncertainties are inherent in estimating quantities of oil and natural gas reserves. The process of estimating oil and natural gas reserves is complex, requiring significant decisions and assumptions in the evaluation of available geological, engineering and economic data for each reservoir. Reserve reports rely upon many assumptions, including future oil and natural gas prices, production levels and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and the estimated timing of development expenditures may prove to be inaccurate. Over time, we may make material changes to reserve estimates that reflect the actual results of drilling and production. Any significant change in our assumptions or actual performance of our wells could affect our estimates of reserves, the classifications of the reserves and our estimates of the future net cash flows associated with the reserves. In addition, since many of our wells are mature and have low production rates, changes in future production costs assumptions could have a significant effect on our proved reserve estimates.
The standardized measure of discounted future net cash flows of our estimated net proved reserves is not the same as the current market value of our estimated net proved reserves. We base the discounted future net cash flows from our estimated net proved reserves on average prices observed in the previous twelve months and on cost estimates we believe reflect the costs at the end of the period. Actual prices received for production and actual costs of such production will be different than these assumptions, perhaps materially.
The timing of both our production and our incurrence of expenses in connection with the development and production of our properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on actual interest rates and the risks associated with our firm in particular or the natural gas and oil industry in general. Any material inaccuracy in our reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves which could adversely affect our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.
An increased risk of terrorist attacks could result in increased costs to our business.
Increased security measures taken by us as a precaution against possible terrorist attacks have resulted in increased costs to our business. If the risk of terrorist attacks were to increase, it is possible that our costs to prepare for and mitigate
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these risks would also increase. For instance, increased risk of terrorist attacks could cause changes in the insurance markets which may make certain types of insurance more difficult for us to obtain, and the insurance that may be available to us may be significantly more expensive than our existing insurance coverage. Instability in the financial markets as a result of terrorism or war could also affect our ability to raise capital.
Our ability to manage and grow our business effectively may be adversely affected if we lose key management or operational personnel.
We depend on the continuing efforts of our executive officers. The departure of any of our executive officers could have a significant negative effect on our business, operating results, financial condition, and on our ability to compete effectively in the marketplace. Additionally, our ability to hire, train, and retain qualified personnel will continue to be important and will become more challenging as we grow and if energy industry market conditions are positive. When general industry conditions are good, the competition for experienced operational and field technicians increases as other energy and manufacturing companies’ needs for the same personnel increases. Our ability to grow and perhaps even to continue our current level of service to our current customers will be adversely impacted if we are unable to successfully hire, train and retain these important personnel.
Risks Inherent in an Investment in Us
We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner, to enable us to make cash distributions at any particular level or at all.
We may not have sufficient available cash from operating surplus each quarter to enable us to make cash distributions at any particular level or at all. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:
• | the fees we charge and the margins we realize for our services; |
• | the prices and level of production of and demand for, oil, natural gas, NGLs and condensate that we and others produce; |
• | the volume of natural gas we gather, treat, compress, process, transport and sell, the volume of NGLs we transport and sell, and the volume of oil and natural gas we and others produce; |
• | our operators’ and other producers’ drilling activities and success of such programs; |
• | the level of competition from other upstream and midstream energy companies; |
• | the level of our operating and maintenance and general and administrative costs; |
• | the relationship between oil, natural gas and NGL prices; and |
• | prevailing economic conditions. |
In addition, the actual amount of cash we will have available for distribution will depend on other factors, some of which are beyond our control, including:
• | the level of capital expenditures we make; |
• | the cost of acquisitions; |
• | our debt service requirements and other liabilities; |
• | fluctuations in our working capital needs; |
• | our ability to borrow funds and access capital markets; |
• | our need to reduce outstanding indebtedness; |
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• | restrictions contained in our debt agreements; and |
• | the amount of cash reserves established by our general partner. |
Due to a lack of liquidity as a result of our high leverage levels and restricted access to the capital markets, our Board of Directors determined to reduce the quarterly distribution with respect to each quarter of 2009 and the first three quarters of 2010 to $0.025 per common and general partner (until cancellation date) unit, as compared to $0.41 per common, subordinated and general partner unit paid with respect to the fourth quarter of 2008.
The amount of cash we have available for distribution to holders of our common units depends primarily on our cash flow and not solely on profitability.
The amount of cash we have available for distribution depends primarily upon our cash flow and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses for financial accounting purposes and may not make cash distributions during periods when we record net earnings for financial accounting purposes.
NGP controls a substantial portion of our common units and appoints three of our directors, and thus it could exert certain significant influence over us.
Currently, NGP beneficially owned approximately 20,083,324 common units and 4,978,550 warrants to purchase additional common units, representing over 20% of our outstanding common units. In addition, pursuant to our partnership agreement, NGP is entitled to appoint three of the nine members of our board of directors. As a result, NGP could exert certain significant influence over us. NGP may have interests that do not align with our interests and with the interests of our unitholders, which could have an adverse impact on our results of operations or cash available for distribution to unitholders. In addition, NGP's level of control may make any potential takeover bids more costly or difficult in the future.
Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions.
We expect that we will distribute all of our available cash to our unitholders. As a result, we expect that we will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. As a result, to the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow.
In addition, because we distribute all of our available cash, our growth may not be as fast as businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement or our credit facility on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which in turn may impact the available cash that we have to distribute to our unitholders.
Our partnership agreement contains provisions that modify and limit our general partner's fiduciary duties to our unitholders.
Our partnership agreement contains provisions that modify and limit our general partner's fiduciary duties to our unitholders. Our partnership agreement also contains provisions that restrict the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty. For example, our partnership agreement:
• | provides that whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is required to make such determination, or take or decline to take such other action in good faith, and our general partner will not be subject to any other or different standard imposed by our partnership agreement, Delaware law or any other law, rule or regulation or at equity; |
• | provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith, and our partnership agreement specifies that the satisfaction of |
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this standard requires that our general partner must believe that the decision is in the best interests of our partnership;
• | provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the general partner or those other persons acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and |
• | provides that our general partner will not be in breach of its obligations under the partnership agreement or its fiduciary duties to us or our unitholders if the resolution of a conflict is: |
• | approved by the conflicts committee of our general partner, although our general partner is not obligated to seek such approval; |
• | approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates; |
• | on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or |
• | fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us. |
In connection with a situation involving a conflict of interest, any determination by our general partner involving the resolution of the conflict of interest must be made in good faith, provided that, if our general partner does not seek approval from the conflicts committee and its board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third and fourth bullet points above, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.
Unitholders have less ability to influence management's decisions than holders of common stock in a corporation.
Unlike the holders of common stock in a corporation, unitholders have more limited voting rights on matters affecting our business, and therefore a more limited ability to influence management's decisions regarding our business. Our second amended and restated partnership agreement provides that our general partner may not withdraw and may not be removed at any time for any reason whatsoever. Furthermore, if any person or group other than NGP and its affiliates acquires beneficial ownership of 20% or more of any class of units (without the prior approval of the board of directors), that person or group loses voting rights on all of its units. In addition, if unitholders are dissatisfied with the performance of our general partner, they only have the right to elect five of the nine directors.
Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.
Unitholders’ voting rights are further restricted by the partnership agreement provision providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.
We may issue additional units without limited partner approval, which would dilute ownership interests.
Our partnership agreement does not limit the number of additional limited partner interests that we may issue at any time without the approval of our unitholders. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:
• | our unitholders’ proportionate ownership interest in us will decrease; |
• | the amount of cash available for distribution on each unit may decrease; |
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• | the ratio of taxable income to distributions may increase; |
• | the relative voting strength of each previously outstanding unit may be diminished; and |
• | the market price of the common units may decline. |
Our management team, directors and certain private investors may sell common units in the public markets, which sales could have an adverse impact on the trading price of the common units.
Currently, our management team, directors and the NGP investors and their affiliates (both separately and through their interests in Eagle Rock Holdings and Montierra) hold an aggregate of 21,561,600 common units, including 981,480 common units which are still subject to a vesting requirement, and 5,096,092 warrants to purchase common units that expire on May 15, 2012. The resale of any of these common units in the public markets could have an adverse impact on the price of the common units or on any trading market that may develop.
Liability of a limited partner may not be limited if a court finds that unitholder action constitutes control of our business.
A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. Limited partners could be liable for any and all of our obligations as a general partner if:
• | a court or government agency determined that we were conducting business in a state but had not complied with that particular state's partnership statute; or |
• | the right to act with other unitholders to remove or replace the general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business. |
Unitholders may have liability to repay distributions that were wrongfully distributed to them.
Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted limited partners are liable for the obligations of the assignor to make contributions to the partnership that are known to the substituted limited partner at the time it became a limited partner and for unknown obligations if the liabilities could be determined from the partnership agreement. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.
If we fail to maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential unitholders could lose confidence in our financial reporting, which would harm our business and the trading price of our units.
Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that our efforts to maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to continue to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our units.
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We have the right to borrow to make distributions. Repayment of these borrowings will decrease cash available for future distributions, and covenants in our credit facility may restrict our ability to make distributions.
Our partnership agreement allows us to borrow to make distributions. We may borrow under our credit facility to make distributions. The primary purpose of these borrowings would be to mitigate the effects of short term fluctuation in our cash flow that would otherwise cause volatility in our quarter to quarter distributions.
The terms of our credit facility may restrict our ability to pay distributions if we do not satisfy the financial and other covenants in the facility.
Risks Related to Governmental Regulation
The recent adoption of derivatives legislation by the United States Congress could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.
The United States Congress adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The new legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act, was signed into law by the President on July 21, 2010 and requires the Commodities Futures Trading Commission (the "CFTC") and the SEC to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. The CFTC has established a rulemaking process, which is currently ongoing, which will establish a comprehensive regulatory framework and expanded enforcement authority over swaps markets. Among other things, the CFTC will establish position limits for certain futures and option contracts and their economic equivalent swaps. Certain bona fide hedging transactions or positions would be exempt from these position limits. It is not possible at this time to predict when the CFTC will finalize these regulations. The financial reform legislation may require us to comply with margin requirements and with certain clearing and trade-execution or reporting requirements in connection with our derivative activities, although the application of those provisions to us is uncertain at this time. The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which could impact our ability to enter into derivatives or require us to enter derivatives with a counterparty which may not be as creditworthy as the current counterparty. The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks that we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material, adverse effect on us, our financial condition, and our results of operations.
A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase.
Our natural gas gathering and intrastate transportation operations are generally exempt from direct Federal Energy Regulatory Commission (FERC) regulation under the Natural Gas Act of 1938 (NGA); however, FERC has jurisdiction over natural gas markets and intrastate pipelines engaged in interstate transportation services (such as Eagle Rock DeSoto Pipeline, L.P.). FERC’s policies and practices across the range of its oil and natural gas regulatory activities, such as its policies on open access transportation, ratemaking, price transparency, market manipulation, capacity release and market center promotion, indirectly affect intrastate markets. In recent years, FERC has pursued policies to increase competition, which could increase FERC's regulation over Eagle Rock Desoto Pipeline. In addition, the distinction between FERC-regulated transmission services and federally unregulated gathering services has been the subject of regular litigation, so the classification and regulation of some of our gathering facilities and intrastate transportation pipelines may change in the future. Further, as a result of recent pipeline incidents nationwide, there is a risk that more stringent pipeline safety requirements may be imposed by Congress and the U.S. Department of Transportation, which could increase our costs.
Other state and local regulations also affect our business. Common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. Ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. These statutes
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restrict our right as an owner of gathering facilities to decide with whom we contract to purchase or gather oil or natural gas. Federal law leaves any economic regulation of natural gas gathering to the states. The states in which we operate have adopted complaint-based regulation of oil and natural gas gathering activities, which allows oil and natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to oil and natural gas gathering access and rate discrimination. Other state regulations may not directly regulate our business, but may nonetheless affect the availability of natural gas for purchase, processing and sale; for example, state regulation of production rates and maximum daily production allowable from gas wells. Although our proprietary gathering lines are currently subject to limited state regulation, there is a risk that state laws will be changed, and this may give producers a stronger basis to challenge the proprietary status of a line, or the rates, terms and conditions of a gathering line providing gathering service. Please see Part I, Item 1. Business—Regulation of Our Operations.
A change in the regulations related to a state's use of eminent domain could inhibit our ability to secure rights-of-way for future pipeline construction projects.
Certain states where we operate are considering the adoption of laws and regulations that would limit or eliminate a state's ability to exercise eminent domain over private property. This, in turn, could make it more difficult or costly for us to secure rights-of-way for future pipeline construction and other projects.
We are subject to compliance with stringent environmental laws and regulations that may expose us to significant costs and liabilities.
Our operations are subject to stringent and complex federal, state and local environmental laws and regulations. These laws and regulations may impose numerous obligations on our operations including the acquisition of permits to conduct regulated activities, the incurrence of capital expenditures to limit or prevent releases of materials from our pipelines and facilities, and the imposition of substantial liabilities for pollution resulting from our operations. Failure or delay in obtaining regulatory approvals or drilling permits by us or our operators could have a material adverse effect on our ability to develop our properties, and receipt of drilling permits with onerous conditions could increase our compliance costs. In addition, regulations regarding conservation practices and the spacing, and density of wellbores may limit the quantity of oil and natural gas that may be produced and sold.
Numerous governmental authorities, such as the U.S. Environmental Protection Agency, also known as the "EPA" and analogous state agencies, have the power to enforce compliance with these laws and regulations, oftentimes requiring difficult and costly actions. Failure to comply may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, assessment of monetary penalties and the issuance of injunctions limiting or preventing some or all of our operations. Certain environmental statutes and analogous state laws impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances have been disposed of or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other waste products into the environment.
There is risk of incurring significant environmental costs and liabilities in connection with our operations as a result of our handling of petroleum hydrocarbons and wastes; operation of our wells, gathering systems and other facilities; air emissions and water discharges related to our operations and historical industry operations and waste disposal practices. Most of our midstream assets have been used for midstream activities for a number of years, oftentimes by third parties, whose treatment and disposal or release of petroleum hydrocarbons or wastes was not under our control. Private parties, including the owners of properties through which our gathering systems pass and facilities where our petroleum hydrocarbons or wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. In addition, changes in environmental laws and regulations occur frequently, and any such changes that result in more stringent and costly waste handling, storage, transport, disposal, or remediation requirements could have a material adverse effect on our operations or financial position. We may not be able to recover some or any of these costs from insurance. See Part I, Item 1. Business—Regulation of Our Operations.
For example, in response to the April 2010 fire and explosion aboard the Deepwater Horizon drilling platform operated by British Petroleum PLC and subsequent release of oil from the Macondo well in ultra-deep water in the Gulf of Mexico, the federal Bureau of Ocean Energy Management, Regulation and Enforcement (“BOEMRE”) has adopted a series of regulatory initiatives that impose a variety of new safety and operating measures on oil and natural gas exploration and production operators in federal waters in the U.S. Gulf of Mexico that are intended to help prevent a similar incident in the future. BOEMRE's adoption of these regulatory requirements have resulted in delays in the resumption of drilling-related activities, including the issuance of drilling permits in federal outer continental shelf waters of the U.S. Gulf of Mexico, and we anticipate that there will continue to
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be such delays as these various regulatory requirements are fully implemented. Such delays have and may continue to have an adverse effect on our midstream business, which relies in part on the transport of natural gas from exploration and production operators situated in outer continental shelf waters. In addition to regulatory restrictions already issued by the BOEMRE, there has been discussion of additional proposed changes in laws, regulations, guidance and policy that could affect exploration and production operators in federal waters of the U.S. Gulf of Mexico and, in turn, adversely affect our midstream business that relies, in part, on the receipt of natural gas from such operators. For instance, at least one bill proposed in the last session of Congress and approved by the House of Representatives would have, among other things, amended the federal Oil Pollution Act of 1990 (“OPA”) by increasing the minimum level of financial responsibility for companies operating on the outer continental shelf from $35 million to $300 million. We currently do not know if similar OPA legislation will be introduced in the current session of Congress or whether such legislation, if introduced, would be adopted as law, but the adoption of any laws that increase the minimum level of financial responsibility may cause oil and natural gas exploration and production operators to experience a significant increase in costs to provide financial insurance under OPA, which effect could result in a decrease in production from the outer continental shelf of the U.S. Gulf of Mexico and a corresponding decrease in our midstream business that relies, in part, on such production.
Climate change laws or regulations restricting emissions of "greenhouse gases" could result in increased operating costs and a decreased demand for oil and natural gas that we produce or process.
In response to findings that emissions of carbon dioxide, methane, and other greenhouse gases, or “GHGs,” present an endangerment to public heath and the environment because emissions of such gases are contributing to the warming of the earth's atmosphere and other climate changes, the U.S. Environmental Protection Agency, or “EPA,” has adopted regulations under existing provisions of the federal Clean Air Act that would require a reduction in emissions of GHGs from motor vehicles and also may trigger construction and operating permit review for GHG emissions from certain stationary sources. The EPA has asserted that the final motor vehicle GHG emission standards triggered Prevention of Significant Deterioration (“PSD”) and Title V permit requirements for stationary sources, commencing when the motor vehicle standards took effect on January 2, 2011. The EPA has published its final rule to address the permitting of GHG emissions from stationary sources under the PSD and Title V permitting programs, pursuant to which these permitting programs have been “tailored” to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources first subject to permitting. It is widely expected that facilities required to obtain PSD permits for their GHG emissions also will be required to reduce those emissions according to “best available control technology” standards for GHG that have yet to be developed. These EPA rulemakings could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified facilities. With regards to the monitoring and reporting of GHGs, on November 30, 2010, the EPA published a final rule expanding its existing GHG emissions reporting rule published in October 2009 to include onshore and offshore oil and natural gas production and onshore oil and natural gas processing, transmission, storage, and distribution activities, which may include certain of our operations, beginning in 2012 for emissions occurring in 2011.
In addition, both houses of Congress have actively considered legislation to reduce emissions of GHGs, and almost one-half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring either major sources of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available for purchase reduced each year until the overall GHG emission reduction goal is achieved. These allowances would be expected to escalate significantly in cost over time. The adoption of any legislation or regulations that requires reporting of GHGs or otherwise limits emissions of GHGs from our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for the oil and natural gas we produce or the oil, natural gas and NGLs we gather and process or fractionate. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth's atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our upstream and midstream operations.
Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.
Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations. We routinely utilize hydraulic fracturing techniques in many of our natural gas well drilling and completion programs. The process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and gas commissions. However, the U.S. Environmental Protection Agency (the “EPA”) recently asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the Safe Drinking Water Act's Underground Injection Control
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Program. While the EPA has yet to take any action to enforce or implement this newly asserted regulatory authority, industry groups have filed suit challenging the EPA's recent decision. At the same time, the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities, and a committee of the U.S. House of Representatives is also conducting an investigation of hydraulic fracturing practices. Legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. In addition, some states have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing operations. For example, Pennsylvania, Colorado, and Wyoming have each adopted a variety of well construction, set back, and disclosure regulations limiting how fracturing can be performed and requiring various degrees of chemical disclosure. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA, our fracturing activities could become subject to additional permitting requirements, and also to attendant permitting delays and potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves.
We may incur significant costs and liabilities as a result of pipeline integrity management program testing and any related pipeline repair, or preventative or remedial measures.
The DOT has adopted regulations requiring pipeline operators to develop integrity management programs for transportation pipelines located where a leak or rupture could do the most harm in "high consequence areas." The regulations require operators to:
• | perform ongoing assessments of pipeline integrity; |
• | identify and characterize applicable threats to pipeline segments |
that could impact a high consequence area;
• | improve data collection, integration and analysis; |
• | repair and remediate the pipeline as necessary; and |
• | implement preventive and mitigating actions. |
We currently estimate that we incur costs of $950,000 between 2011 and 2012 to implement pipeline integrity management program testing along certain segments of our pipeline, as required by existing DOT regulations. This estimate does not include the costs, if any, for repair, remediation, preventative or mitigating actions that may be determined to be necessary as a result of the testing program, which could be substantial.
Tax Risks to Common Unitholders
The tax efficiency of our partnership structure depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service were to treat us as a corporation or if we become subject to a material amount of entity-level taxation for state tax purposes, it would reduce the amount of cash available for distribution.
The anticipated after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the Internal Revenue Service, which we refer to as the IRS, on this or any other tax matter affecting us.
A publicly traded partnership such as us may be treated as a corporation for federal income tax purposes unless it satisfies a “qualifying income” requirement. Based on our current operations we believe that we are treated as a partnership rather than a corporation for such purposes; however, a change in our business or a change in current law could cause us to be treated as a corporation for federal income tax purposes. In addition, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. We are, for example, subject to an entity level tax on the portion of our income that is generated in Texas. Imposition of such a tax on us by any state, will reduce the cash available for distribution.
If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35% and would likely pay state income tax at varying rates.
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Distributions would generally be taxed again as corporate dividends, and no income, gains, losses or deductions would flow through to the limited partners. Because a tax would be imposed upon us as a corporation, our cash available for distributions would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units.
If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS challenge will reduce our cash available for distribution.
We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders because the costs will reduce our cash available for distribution.
The tax consequences relating to the warrants issued in connection with the Recapitalization and Related Transactions are unclear, and the IRS may adopt positions that differ from the positions we intend to take.
The tax consequences relating to the issuance and exercise of the warrants issued in connection with the Recapitalization and Related Transactions are unclear. There is no direct legal authority as to the proper federal income tax treatment of the warrants. However, we intend for our methods of maintaining capital accounts and allocating income, gain, loss and deduction with respect to the warrants to comply with proposed Treasury regulations issued on January 22, 2003, relating to the tax treatment of noncompensatory options issued by partnerships (the “Noncompensatory Option Regulations”). Under these rules, it is not anticipated that we or our existing common unitholders will recognize income or gain as a result of the issuance or exercise of the warrants. However, it is important to note that the Noncompensatory Option Regulations are proposed Treasury regulations that are subject to change and are not legally binding until they are finalized. There can be no assurance that the proposed Treasury Regulations will ever be finalized, or that they will not be finalized in a substantially different form. Consequently, no assurance can be provided that the issuance and exercise of the warrants will be tax free or that our methods to be adopted for allocating income and loss among our unitholders to take into account the outstanding warrants will be given effect for federal income tax purposes. If our allocations are not respected, a unitholder could be allocated more taxable income (or less taxable loss).
The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period would result in the technical termination of our partnership for federal income tax purposes.
We will be considered to have terminated our partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. A technical termination would not affect our consolidated financial statements nor does it affect our classification as a partnership or otherwise affect the nature of our “qualifying income” for U.S. federal income tax purposes. A technical termination would, among other things, result in the closing of our taxable year for all unitholders and would result in a deferral of depreciation deductions allowable in computing our taxable income. A deferral of depreciation deductions would result in increased taxable income or reduced taxable loss to certain unitholders, although the exact increase or reduction for each unitholder cannot be estimated at this time. The IRS has recently announced a relief procedure whereby if a publicly traded partnership that has technically terminated requests and the IRS grants special relief, among other things, the partnership will be required to provide only a single Schedule K-1 to unitholders for the tax years in which the technical termination occurs.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations, and, accordingly, our counsel is unable to opine as to the validity of this method. Recently, the U.S. Treasury Department issued proposed Treasury Regulations that provide a safe harbor pursuant to which publicly traded partnerships may use a similar monthly simplifying convention to allocate tax items. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge our proration method or new Treasury Regulations were issued, we
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may be required to change the allocation of items of income, gain, loss and deduction among our unitholders. If the IRS were to challenge this method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.
A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, he would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.
Because a unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of the loaned units, he may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.
Limited partners may be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.
Because our unitholders will be treated as partners to whom we will allocate taxable income which could be different in amount than the cash we distribute, limited partners will be required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable income even if no cash distributions were received from us. Although not anticipated, our taxable income for a taxable year may include income without a corresponding receipt of cash by us, such as accrual of future income, original issue discount or cancellation of indebtedness income. Limited partners may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that result from that income.
Tax gain or loss on disposition of our common units could be more or less than expected.
If a limited partner sells common units, the limited partner will recognize a gain or loss equal to the difference between the amount realized and the tax basis in those common units. Prior distributions to a limited partner in excess of the total net taxable income allocated for a common unit, which decreased the limited partner's tax basis in that common unit, will, in effect, become taxable income to the limited partner if the common unit is sold at a price greater than their tax basis in that common unit, even if the price received is less than the original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income. In addition, if a limited partner sells units, the limited partner may incur a tax liability in excess of the amount of cash received from the sale.
Tax-exempt entities and non-U.S. persons face unique tax issues from owning common units that may result in adverse tax consequences to them.
Investment in common units by tax-exempt entities, such as individual retirement accounts (known as IRAs), other retirement plans and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable tax rate, and non-U.S. persons will be required to file U.S. federal tax returns and pay tax on their share of our taxable income. If a limited partner is a tax-exempt entity or a non-U.S. person, the limited partner should consult a tax advisor before investing in our common units.
We will treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.
To maintain the uniformity of the economic and tax characteristics of our common units, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to the limited partners. It also could affect the timing of these tax benefits or the amount of gain from sales of common units and could have a negative impact on the value of our common units or result in audit adjustments to tax returns of our limited partners.
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Limited partners will likely be subject to state and local taxes and return filing requirements in states where they do not live as a result of investing in our common units.
In addition to federal income taxes, a limited partner will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property, even if the limited partner does not live in any of those jurisdictions. A limited partner will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, a limited partner may be subject to penalties for failure to comply with those requirements. We own assets and conduct business in several states. Many of these states currently impose a personal income tax. As we make acquisitions or expand our business, we may own assets or conduct business in additional states that impose a personal income tax. It is a limited partner's responsibility to file all United States federal, state and local tax returns.
Certain U.S. federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated as a result of future legislation.
The Fiscal Year 2012 Budget proposed by the President recommends elimination of certain key U.S. tax incentives
currently available to oil and natural gas exploration and production companies. Among others, the provisions include: elimination of the ability to fully deduct intangible drilling costs in the year incurred; repeal of the percentage depletion deduction for oil and gas properties; repeal of the manufacturing tax deduction for oil and gas companies; and an increase in the geological and geophysical amortization period for independent producers. It is unclear whether any such changes will be enacted or how soon any such changes would become effective. The passage of this legislation or any other similar changes in U.S. federal income tax laws could eliminate certain tax deductions that are currently available with respect to oil and gas exploration and development, and any such change could negatively affect the taxable income allocable to the unitholders.
Item 1B. Unresolved Staff Comments.
Not Applicable.
Item 2. Properties.
For a complete description of our significant properties, see Item 1. Business, which descriptions are incorporated into this item by this reference. Substantially all of our pipelines are constructed on rights-of-way granted by the apparent record owners of the property. Lands over which pipeline rights-of-way have been obtained may be subject to prior liens that may have been subordinated to the right-of-way grants. We have obtained, where deemed necessary, license or permit agreements from public authorities and railroad companies to cross over or under, or to lay facilities in or along, waterways, county or parish roads, municipal streets, railroad properties and state highways, as applicable. In some cases, property on which our pipeline was built was purchased in fee.
We believe that we have satisfactory title to our assets. Title to property may be subject to encumbrances and liens on substantially all of our assets as collateral support of our credit facility. We believe that none of these encumbrances will materially detract from the value of our properties or from our interest in these properties or will they materially interfere with their use in the operation of our business.
While we own our facilities, plants and gathering systems, in many cases we do not always own the land upon which the facilities, plants and gathering systems reside. In cases where the land is leased (and not owned), we are ordinarily in long-term leases. From time to time, these long-term leases expire, and we are forced to negotiate new terms at market rates or exit the premises. For more information, see our table of assets within Part I, Item 1 Business – Our Two Lines of Business and Our Six Reporting Segments – Midstream Business.
Item 3. Legal Proceedings.
Our operations are subject to a variety of risks and disputes normally incident to our business. As a result, we are and
may, at any given time, be a defendant in various legal proceedings and litigation arising in the ordinary course of business.
However, we are not currently a party to any material litigation. We maintain insurance policies with insurers in amounts and
with coverage and deductibles that we, with the advice of our insurance advisors and brokers, believe are reasonable and
prudent. We cannot, however, assure you that this insurance will be adequate to protect us from all material expenses related to
potential future claims for personal and property damage or that these levels of insurance will be available in the future at
economical prices.
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On February 9, 2010 a lawsuit, alleging certain claims related to the Recapitalization and Related Transactions (see
Note 9), was filed on behalf of one of our public unitholders in the Court of Chancery of the State of Delaware naming the
Partnership, its general partner, certain affiliates of its general partner, including the general partner of its general partner, and
each member of our Board of Directors as defendants. The complaint alleged a breach by the defendants of their fiduciary
duties to the Partnership and the public unitholders and sought to enjoin the Recapitalization and Related Transactions. We
believed the allegations in the complaint were without merit. On March 11, 2010, in an effort to minimize the further cost,
expense, burden and distraction of any litigation relating to the lawsuit, the parties to the lawsuit entered into a Memorandum
of Understanding regarding the terms of a potential settlement of the lawsuit. On August 16, 2010, the parties to the lawsuit
filed a Stipulation and Agreement of Compromise, Settlement and Release with the Court of Chancery of the State of
Delaware. The settlement proposed to, among other things and subject to the approval of the Court, resolve the allegations by
the plaintiff against the defendants in connection with the Recapitalization and Related Transactions and provide a release and
settlement by a proposed class of our common unitholders during the period from September 17, 2009 through and including
the date of the closing of the transactions, of all claims against the defendants as they relate to the Recapitalization and Related
Transactions. At a hearing on October 28, 2010, the Court of Chancery of the State of Delaware approved the settlement and
entered a Final Order and Judgment. The order approving the settlement became final on November 29, 2010.
During 2009, we completed voluntary self-audits of our compliance with air quality standards, which included
permitting in the Texas Panhandle Segment as well as a majority of our other Midstream Business locations and some of our
Upstream Business locations in Texas. These audits were performed pursuant to the Texas Environmental, Health and Safety
Audit Privilege Act, as amended. We completed the disclosures to the Texas Commission on Environmental Quality (“TCEQ”),
and we have substantially addressed the deficiencies that we disclosed therein. We do not foresee at this time any impediment
in timely addressing the remaining deficiencies identified as a result of these audits.
Since January 1, 2010, we have received additional Notices of Enforcement (“NOEs”) and Notices of Violation
(“NOVs”) from the TCEQ related to air compliance matters and expect to receive additional NOEs or NOVs from the TCEQ
from time to time throughout 2011. Though the TCEQ has the discretion to adjust penalties and settlements upwards based on
a compliance history containing multiple, successive NOEs, we do not expect that the resolution of any existing NOE or any
future similar NOE will vary significantly from the administrative penalties and agreed settlements experienced by us to date.
Item 4. [Removed and Reserved]
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PART II
Item 5. Market for Registrant's Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities.
Our common units are listed on the NASDAQ Global Select Market under the symbol “EROC.” The following table sets forth, for the periods indicated, the high and low sales prices of our common units as reported by the NASDAQ Global Select Market, as well as the amount of cash distributions declared per quarter.
Quarter Ended | High | Low | Distribution per Unit | Record Date | Payment Date | |||||||||||
March 31, 2009 | $ | 7.99 | $ | 3.90 | $ | 0.0250 | May 11, 2009 | May 15, 2009 | ||||||||
June 30, 2009 | $ | 6.57 | $ | 2.94 | $ | 0.0250 | August 10, 2009 | August 14, 2009 | ||||||||
September 30, 2009 | $ | 5.14 | $ | 2.65 | $ | 0.0250 | November 9, 2009 | November 13, 2009 | ||||||||
December 31, 2009 | $ | 5.91 | $ | 4.00 | $ | 0.0250 | February 8, 2010 | February 12, 2010 | ||||||||
March 31, 2010 | $ | 6.76 | $ | 5.35 | $ | 0.0250 | May 7, 2010 | May 14, 2010 | ||||||||
June 30, 2010 | $ | 7.42 | $ | 4.62 | $ | 0.0250 | August 9, 2010 | August 13, 2010 | ||||||||
September 30, 2010 | $ | 6.44 | $ | 4.99 | $ | 0.0250 | November 8, 2010 | November 12, 2010 | ||||||||
December 31, 2010 | $ | 9.00 | $ | 6.09 | $ | 0.1500 | February 7, 2011 | February 14, 2011 | ||||||||
The last reported sale price of our common units on the NASDAQ Global Select Market on February 22, 2011 was $9.40. As of that date, there were 125 holders of record and approximately 15,504 beneficial owners of our common units.
Cash Distribution Policy
We intend to distribute to our unitholders, on a quarterly basis, all of our available cash in the manner described below and as further described in our partnership agreement. Available cash generally means, for any quarter ending prior to liquidation, all cash on hand at the end of that quarter less the amount of cash reserves that are necessary or appropriate in the reasonable discretion of the general partner to:
• | provide for the proper conduct of our business; |
• | comply with applicable law or any partnership debt instrument or other agreement; or |
• | provide funds for distributions to unitholders and the general partner in respect of any one or more of the next four quarters. |
During 2009, we reduced our distributions and used the cash to pay down debt. On January 27, 2011, our Board of Directors approved a distribution of $0.15 per common unit, or $0.60 per common unit on an annualized basis, with respect to the fourth quarter of 2010. Management has announced its intention to recommend increases in the distribution per unit in 2011 to a level of $0.75 per unit on an annualized basis with respect to the fourth quarter of 2011. Actual distributions, if any, will be determined by our Board of Directors and will take into account numerous factors.
Under the terms of the agreements governing our debt, we are prohibited from declaring or paying any distribution to unitholders if a default or event of default (as defined in such agreements) exists. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Capital Requirements—Revolving Credit Facility.
Our Board of Directors will evaluate our distribution policy from time to time as conditions warrant in the future.
Common Unitholder Return Performance Presentation
The performance graph below compares the cumulative total unitholder return on our common units with the cumulative total returns on the Standard & Poor’s 500 Index (the “S&P 500 Index”) and the Alerian MLP Total Return Index (the “Alerian MLP”). The Alerian MLP is a composite of the 50 most prominent energy master limited partnerships and limited liability companies, as determined by Standard & Poor’s using a float-adjusted market capitalization methodology. The graph assumes an investment of $100 in our common units, and in each of the S&P 500 Index and the Alerian MLP on October 26,
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2006 (the day our units began trading on NASDAQ), and reinvestment of all dividends and distributions. The results shown in the graph are based on historical data and should not be considered indicative of future performance.
__________________________
(1) | In addition, the graph compares the cumulative total unitholders return on our common units assuming rights associated with Eagle Rock's Rights Offering were distributed effective May 27, 2010, the record date for the Rights Offering, and then immediately sold. The proceeds of such for the sale of the rights were assumed to be re-invested in Eagle Rock common units on the same day. |
The information contained in the Performance Graph will not be deemed to be "soliciting material" or the be "filed" with the SEC, nor will such information be incorporated by reference into any future filings of the Securities Act of 1933, as amended (the "Securities Act"), or the Securities Exchange Act of 1934, as amended (the "exchange Act"), except to the extent that we specifically incorporate it by reference into any such filing.
Sales of Unregistered Securities
We did not sell our equity securities in unregistered transactions during the three months ended December 31, 2010.
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Repurchases of Common Units
The following table sets forth certain information with respect to repurchases of common units during the three months ended December 31, 2010:
Period | Total Number of Units Purchased | Average Price Paid Per Unit | Total Number of Units Purchased as Part of Publicly Announced Plans or Programs | Maximum Number (or Approximate Dollar Value) of Units that May Yet Be Purchased Under the Plan or Programs | |||||||||
October 1, 2010 to October 31, 2010 | — | — | — | — | |||||||||
November 1, 2010 to November 30, 2010 | 61,364 | $ | 7.38 | — | — | ||||||||
December 1, 2010 to December 31, 2010 | — | — | — | — | |||||||||
Total | 61,364 | $ | 7.38 | — | — | ||||||||
All of the units were surrendered by employees to pay tax withholding in connection with the vesting of restricted common units. As a result, we are deeming the surrenders to be “repurchases.” These repurchases were not part of a publicly announced program to repurchase our common units, nor do we have a publicly announced program to repurchase our common units.
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Item 6. Selected Financial Data.
The following table shows selected historical financial data from our audited consolidated financial statements for the five fiscal years from January 1, 2006 to December 31, 2010. The following financial data should be read in conjunction with our consolidated financial statements and the accompanying notes and "Management's Discussion and Analysis of Financial Condition and Results of Operations" included elsewhere in this report.
Our historical results of operations for the periods presented below may not be comparable either from period to period or going forward, for the following reasons:
• | On March 27, 2006, Eagle Rock Pipeline completed a private placement of 5,455,050 common units for $98.3 million. |
• | On March 31, 2006 and April 7, 2006, a wholly-owned subsidiary of Eagle Rock Energy Partners, L.P. acquired certain natural gas gathering and processing assets from Duke Energy Field Services, L.P. and Swift Energy Corporation, consisting of the Brookeland gathering system and processing plant, the Masters Creek gathering system and the Jasper NGL pipeline. We refer to this acquisition as the Brookeland Acquisition. As a result, our historical financial results for the periods prior to March 31, 2006 do not include the financial results from the operation of these assets. |
• | On June 2, 2006, we purchased all of the partnership interests in Midstream Gas Services, L.P., which we refer to as the MGS Acquisition, an NGP affiliate, for approximately $4.7 million in cash and 809,174 (recorded value of $20.3 million) common units in Eagle Rock Pipeline. As a result, financial results for the periods prior to June 2006 do not include the financial results from the operation of these assets. |
• | On April 30, 2007, we acquired certain fee minerals, royalties and working interest properties through purchases directly from Montierra Minerals & Production, L.P. and through purchases directly from NGP-VII Income Co-Investment Opportunities, L.P., which we refer to as the Montierra Acquisition, for 6,458,946 (recorded value of $133.8 million) of our common units and $5.4 million in cash. |
• | On May 3, 2007, we acquired Laser Midstream Energy, L.P. and certain of its subsidiaries, which we refer to as the Laser Acquisition, for $113.4 million in cash and 1,407,895 (recorded value of $29.2 million) of our common units. As a result, financial results for the periods prior to May 2007 do not include the financial results from these assets. |
• | On May 3, 2007, we completed the private placement of 7,005,495 common units for $127.5 million. |
• | On June 18, 2007, we acquired certain fee minerals and royalties from MacLondon Energy, L.P., which we refer to as the MacLondon Acquisition, for $18.2 million, financed with 757,065 (recorded value of $18.1 million) of our common units and cash of $0.1 million. |
• | On July 31, 2007, we completed the acquisition of Escambia Asset Co. LLC and Escambia Operating Co. LLC, which we refer to as the EAC Acquisition, for approximately $224.6 million in cash and 689,857 (recorded value of $17.2 million) of our common units, subject to post-closing adjustment. As a result, financial results for the periods prior to July 31, 2007 do not include the financial results from these assets. |
• | On July 31, 2007, we completed the acquisition of Redman Energy Holdings, L.P. and Redman Energy Holdings II, L.P. and certain assets owned by NGP Income Co-Investment Opportunities Fund II, L.P. (a Natural Gas Partners affiliate) which we refer to as the Redman Acquisition, for 4,428,334 (recorded value of $108.2 million) common units and $84.6 million. As a result, financial results for the periods prior to July 2007 do not include the financial results from these assets. |
• | On July 31, 2007, we completed the private placement of 9,230,770 common units for approximately $204.0 million. |
• | On April 30, 2008, we completed the acquisition of Stanolind Oil and Gas Corp., which we refer to as the Stanolind Acquisition, for an aggregate purchase price of $81.9 million in cash. As a result, financial results for the periods prior to May 2008 do not include the financial results from these assets. |
• | On October 1, 2008 we completed the acquisition of Millennium Midstream Partners, L.P. (“MMP”), which we refer to as the Millennium Acquisition, for approximately $183.6 million in cash and 3,362,280 (recorded value of $29.3 million) of our common units. As a result, financial results for the periods prior to October 2008 do not include the financial results from these assets. |
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• | On May 24, 2010, we completed the sale of our Minerals Business (assets acquired from Montierra and MacLondon Acquisitions) to Black Stone for approximately $171.6 million, and resulted in a pre-tax gain in the disposition of approximately $37.7 million. We used these proceeds to pay down amounts outstanding under our senior secured credit facility. Operations related to these assets for 2010 have been recorded as part of discontinued operations. Financial information for these assets for 2007, 2008 and 2009 have been retrospectively adjusted to reflect as assets and liabilities held-for-sale and discontinued operations. |
• | On June 30, 2010, we closed our Rights Offering, for which we received gross proceeds of $53.9 million. We used these proceeds to pay down amounts outstanding under our senior secured credit facility. |
• | On September 30, 2010, we acquired certain additional interest in the Big Escambia Creek Field (and the nearby Flomaton and Fanny Church fields) from Indigo Minerals, LLC for approximately $3.9 million in cash on hand. As a result, financial results for the periods prior to October 2010 do not include the financial results from the assets. |
• | On October 19, 2010, we completed the acquisition of certain natural gas gathering systems and related facilities from Centerpoint Energy Field Services, Inc. for $27.0 million of cash. As a result, financial results for the periods prior to October 19, 2010 do not include the financial results from these assets. |
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Year Ended December 31, 2006 | Year Ended December 31, 2007 | Year Ended December 31, 2008 | Year Ended December 31, 2009 | Year Ended December 31, 2010 | ||||||||||||||||
Statement of Operations Data: | ||||||||||||||||||||
Sales to external customers | $ | 502,394 | $ | 760,853 | $ | 1,273,506 | $ | 701,046 | $ | 767,181 | ||||||||||
Unrealized derivative gains/(losses) | (26,306 | ) | (130,773 | ) | 207,824 | (189,590 | ) | 8,224 | ||||||||||||
Realized derivative gains/(losses) | 2,302 | (3,061 | ) | (46,059 | ) | 83,300 | (17,010 | ) | ||||||||||||
Total revenues | 478,390 | 627,019 | 1,435,271 | 594,756 | 758,395 | |||||||||||||||
Cost of natural gas and NGLs | 377,580 | 553,248 | 891,433 | 488,230 | 490,206 | |||||||||||||||
Operating and maintenance expense | 32,905 | 52,793 | 73,620 | 73,196 | 77,898 | |||||||||||||||
Taxes other than income | 2,301 | 7,569 | 18,228 | 10,766 | 12,240 | |||||||||||||||
General and administrative expense | 10,860 | 27,740 | 45,618 | 45,819 | 45,775 | |||||||||||||||
Other operating expense (income) | 6,000 | 2,847 | 10,699 | (3,552 | ) | — | ||||||||||||||
Impairment expense | — | — | 142,116 | 21,788 | 32,875 | |||||||||||||||
Goodwill impairment | — | — | 30,994 | — | — | |||||||||||||||
Depreciation, depletion and amortization | 43,220 | 72,531 | 108,980 | 110,255 | 108,781 | |||||||||||||||
Operating income (loss) | 5,524 | (89,709 | ) | 113,583 | (151,746 | ) | (9,380 | ) | ||||||||||||
Interest (income) expense, net | 28,604 | 49,764 | 65,044 | 27,751 | 42,171 | |||||||||||||||
Other (income) expense | (996 | ) | 8,244 | (363 | ) | 136 | (450 | ) | ||||||||||||
Income (loss) from continuing operations before income taxes | (22,084 | ) | (147,717 | ) | 48,902 | (179,633 | ) | (51,101 | ) | |||||||||||
Income tax provision (benefit) | 1,230 | 13 | (1,449 | ) | 1,022 | (2,545 | ) | |||||||||||||
Income (loss) from continuing operations | (23,314 | ) | (147,730 | ) | 50,351 | (180,655 | ) | (48,556 | ) | |||||||||||
Discontinued operations, net of tax | — | 2,096 | 37,169 | 9,397 | 43,207 | |||||||||||||||
Net income (loss) | $ | (23,314 | ) | $ | (145,634 | ) | $ | 87,520 | $ | (171,258 | ) | $ | (5,349 | ) | ||||||
Loss (income) from continuing operations per common unit - diluted | $ | (0.98 | ) | $ | (2.16 | ) | $ | 0.67 | $ | (2.38 | ) | $ | (0.59 | ) | ||||||
Balance Sheet Data (at period end): | ||||||||||||||||||||
Property, plant and equipment, net | $ | 554,063 | $ | 1,070,120 | $ | 1,229,802 | $ | 1,155,733 | $ | 1,143,459 | ||||||||||
Total assets | 779,901 | 1,609,927 | 1,773,061 | 1,534,818 | 1,349,397 | |||||||||||||||
Long-term debt | 405,731 | 567,069 | 799,383 | 754,383 | 530,000 | |||||||||||||||
Net equity | 291,987 | 726,768 | 727,715 | 530,398 | 579,113 | |||||||||||||||
Cash Flow Data: | ||||||||||||||||||||
Net cash flows provided by (used in): | ||||||||||||||||||||
Operating activities | $ | 54,992 | $ | 91,832 | $ | 138,770 | $ | 79,409 | $ | 96,760 | ||||||||||
Investing activities | (134,873 | ) | (475,790 | ) | (330,667 | ) | (37,284 | ) | 73,545 | |||||||||||
Financing activities | 71,088 | 426,816 | 102,816 | (73,260 | ) | (175,446 | ) | |||||||||||||
Discontinued operations | — | 15,113 | 38,445 | 15,951 | 6,458 | |||||||||||||||
Other Financial Data: | ||||||||||||||||||||
Cash distributions per common unit (declared) | $ | 0.2679 | $ | 1.485 | $ | 1.63 | $ | 0.10 | $ | 0.23 | ||||||||||
Adjusted EBITDA(a) | $ | 81,192 | $ | 118,042 | $ | 206,965 | $ | 174,525 | $ | 128,713 | ||||||||||
________________________
(a) See Part II Item 6. Selection Financial Data – Non-GAAP Financial Measures for reconciliation of “Adjusted EBITDA” to net cash flows from operating activities and net income (loss).
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Non-GAAP Financial Measures
We include in this filing the following non-GAAP financial measure: Adjusted EBITDA (as defined on page 80). We provide reconciliations of this non-GAAP financial measure to its most directly comparable financial measures as calculated and presented in accordance with GAAP.
Adjusted EBITDA should not be considered an alternative to net income, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP.
We define Adjusted EBITDA as net income (loss) plus or (minus) income tax provision (benefit); interest-net, including realized interest rate risk management instruments and other expense; depreciation, depletion and amortization expense; impairment expense; other operating expense, non-recurring; other non-cash operating and general and administrative expenses, including non-cash compensation related to our equity-based compensation program; unrealized (gains) losses on commodity and interest rate risk management related instruments; gains (losses) on discontinued operations and other (income) expense. We use Adjusted EBITDA as a measure of our core profitability to assess the financial performance of our assets. Adjusted EBITDA is also used as a supplemental financial measure by external users of Eagle Rock's financial statements such as investors, commercial banks and research analysts. For example, Eagle Rock's lenders under its revolving credit facility use a variant of Eagle Rock's Adjusted EBITDA in a compliance covenant designed to measure the viability of Eagle Rock and its ability to perform under the terms of its revolving credit facility; Eagle Rock, therefore, uses Adjusted EBITDA to measure its compliance with its revolving credit facility. We believe that investors benefit from having access to the same financial measures that our management team uses in evaluating performance. Adjusted EBITDA is useful in determining our ability to sustain or increase distributions. By excluding unrealized derivative gains (losses), a non-cash, mark-to-market benefit (charge) which represents the change in fair market value of our executed derivative instruments and is independent of our assets’ performance or cash flow generating ability, we believe Adjusted EBITDA reflects more accurately our ability to generate cash sufficient to pay interest costs, support our level of indebtedness, make cash distributions to our unitholders and general partner and finance our maintenance capital expenditures. We further believe that Adjusted EBITDA also describes more accurately the underlying performance of our operating assets by isolating the performance of our operating assets from the impact of an unrealized, non-cash measure designed to describe the fluctuating inherent value of a financial asset. Similarly, by excluding the impact of non-recurring discontinued operations, Adjusted EBITDA provides users of our financial statements a more accurate picture of our current assets’ cash generation ability, independently from that of assets which are no longer a part of our operations. Eagle Rock's Adjusted EBITDA definition may not be comparable to Adjusted EBITDA or similarly titled measures of other entities, as other entities may not calculate Adjusted EBITDA in the same manner as Eagle Rock. For example, we include in Adjusted EBITDA the actual settlement revenue created from our commodity hedges by virtue of transactions undertaken by us to reset commodity hedges to higher prices or purchase puts or other similar floors despite the fact that we exclude from Adjusted EBITDA any charge for amortization of the cost of such commodity hedge reset transactions or puts. For a reconciliation of Adjusted EBITDA to its most directly comparable financial measures calculated and presented in accordance with GAAP (accounting principles generally accepted in the United States), please read “Summary—Non-GAAP Financial Measures.”
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Year Ended December 31, 2006 | Year Ended December 31, 2007 | Year Ended December 31, 2008 | Year Ended December 31, 2009 | Year Ended December 31, 2010 | ||||||||||||||||
Reconciliation of “Adjusted EBITDA” to net cash flows provided by (used in) operating activities and net income (loss): | ||||||||||||||||||||
Net cash flows provided by (used in) operating activities | $ | 54,992 | $ | 91,832 | $ | 138,770 | $ | 79,409 | $ | 96,760 | ||||||||||
Add (deduct): | ||||||||||||||||||||
Discontinued operations, net of tax | — | 2,096 | 37,169 | 9,397 | 43,207 | |||||||||||||||
Depreciation, depletion, amortization and impairment | (43,220 | ) | (72,531 | ) | (282,090 | ) | (132,043 | ) | (141,656 | ) | ||||||||||
Amortization of debt issue cost | (1,114 | ) | (1,777 | ) | (958 | ) | (1,068 | ) | (1,305 | ) | ||||||||||
Risk management portfolio value changes | (23,531 | ) | (136,132 | ) | 199,339 | (147,751 | ) | 9,195 | ||||||||||||
Reclassing financing derivative settlements | 978 | (1,667 | ) | (11,063 | ) | 8,939 | 1,131 | |||||||||||||
Other | (7,566 | ) | (8,541 | ) | (4,811 | ) | (2,878 | ) | (5,319 | ) | ||||||||||
Accounts receivable and other current assets | 1,432 | 13,215 | (41,981 | ) | (20,179 | ) | (10,723 | ) | ||||||||||||
Accounts payable, due to affiliates and accrued liabilities | (8,777 | ) | (31,464 | ) | 54,004 | 35,996 | 3,656 | |||||||||||||
Other assets and liabilities | 3,492 | (665 | ) | (859 | ) | (1,080 | ) | (295 | ) | |||||||||||
Net income (loss) | (23,314 | ) | (145,634 | ) | 87,520 | (171,258 | ) | (5,349 | ) | |||||||||||
Add: | ||||||||||||||||||||
Interest (income) expense, net | 30,383 | 44,587 | 38,282 | 41,350 | 35,058 | |||||||||||||||
Depreciation, depletion, amortization and impairment | 43,220 | 72,531 | 282,090 | 132,043 | 141,656 | |||||||||||||||
Income tax provision (benefit) | 1,230 | 13 | (1,567 | ) | 1,022 | (2,545 | ) | |||||||||||||
EBITDA | 51,519 | (28,503 | ) | 406,325 | 3,157 | 168,820 | ||||||||||||||
Add: | ||||||||||||||||||||
Risk management portfolio value changes | 23,531 | 144,176 | (180,107 | ) | 177,061 | (1,060 | ) | |||||||||||||
Restricted unit compensation expense | 142 | 2,395 | 7,694 | 6,685 | 5,407 | |||||||||||||||
Non-cash mark-to-market Upstream imbalances | — | — | 841 | 1,505 | (746 | ) | ||||||||||||||
Discontinued operations, net of tax | — | (2,096 | ) | (37,169 | ) | (9,397 | ) | (43,207 | ) | |||||||||||
Other income | — | 18 | (1,318 | ) | (934 | ) | (501 | ) | ||||||||||||
Other operating expense (income) (a) | 6,000 | 2,052 | 10,699 | (3,552 | ) | — | ||||||||||||||
ADJUSTED EBITDA(b) | $ | 81,192 | $ | 118,042 | $ | 206,965 | $ | 174,525 | $ | 128,713 | ||||||||||
________________________
(a) Includes $6.0 million to terminate an advisory fee for the year ended December 31, 2006, a settlement of arbitration for $1.4 million, severance to a former executive for $0.3 million and $1.1 million for liquidated damage related to the late registration of our common units during the year ended December 31, 2007; $10.7 million related to bad debt expense taken against our outstanding accounts receivable from SemGroup during the year ended December 31, 2008 and $3.6 million due to the recovery of $2.2 million of assets previously written off and the release of $1.4 million of liabilities assumed as part of our purchase price allocation for our acquisitions of Escambia Asset Co. LLC and Redman Energy Holdings, L.P. during the year ended December 31, 2009.
(b) Adjusted EBITDA excludes amortization of commodity hedge costs (including costs of hedge reset transactions) for the years ended December 31, 2010, 2009, 2008, 2007 and 2006 of $4.0 million, $48.4 million, $13.3 million, $8.2 million and $19.2 million, respectively. Including these amortization costs, our Adjusted EBITDA for the years ended December 31, 2010, 2009, 2008, 2007 and 2006, would have been $124.8 million, $126.2 million, $193.7 million, $109.8 million and $62.0 million, respectively.
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The following table summarizes our quarterly financial data for 2010:
For the Quarters Ended | |||||||||||||||
March 31, 2010 | June 30, 2010 | September 30, 2010 | December 31, 2010 | ||||||||||||
($ in thousands, except earnings per unit) | |||||||||||||||
Sales of natural gas, NGLs and condensate | $ | 199,296 | $ | 170,998 | $ | 165,131 | $ | 177,370 | |||||||
Gathering and treating services | 12,833 | 16,541 | 12,358 | 10,219 | |||||||||||
Realized commodity derivative losses | (2,683 | ) | (5,813 | ) | (1,535 | ) | (6,979 | ) | |||||||
Unrealized commodity derivative gains (losses) | 13,478 | 41,405 | (17,044 | ) | (29,615 | ) | |||||||||
Other revenues | 36 | (251 | ) | 100 | 2,550 | ||||||||||
Total operating revenues | 222,960 | 222,880 | 159,010 | 153,545 | |||||||||||
Cost of natural gas and NGLs | 144,278 | 113,926 | 111,916 | 120,086 | |||||||||||
Operating and maintenance expense | 22,772 | 23,175 | 21,650 | 22,541 | |||||||||||
General and administrative expense | 13,011 | 12,806 | 10,674 | 9,284 | |||||||||||
Depreciation, depletion, amortization and impairment expense | 28,026 | 31,180 | 29,906 | 52,544 | |||||||||||
Interest—net including realized risk management instrument | 9,302 | 9,163 | 8,419 | 8,123 | |||||||||||
Unrealized interest rate derivative losses (gains) | 4,822 | 4,354 | 3,112 | (5,124 | ) | ||||||||||
Income tax (benefit) provision | 711 | (415 | ) | (1,236 | ) | (1,605 | ) | ||||||||
Other expense (income) | (99 | ) | 21 | 30 | (402 | ) | |||||||||
Discontinued operations, net of tax | (3,844 | ) | (39,473 | ) | (224 | ) | 334 | ||||||||
Net income (loss) | $ | 3,981 | $ | 68,143 | $ | (25,237 | ) | $ | (52,236 | ) | |||||
Earnings per unit—diluted | |||||||||||||||
Common units | $ | 0.06 | $ | 0.96 | $ | (0.31 | ) | $ | (0.62 | ) | |||||
Subordinated units | $ | 0.03 | $ | 0.94 | $ | — | $ | — | |||||||
General partner | $ | 0.06 | $ | 0.96 | $ | (0.33 | ) | $ | — | ||||||
During our fiscal year ended December 31, 2010, we recorded the following unusual or infrequently occurring items:
• | During our quarter ended June 30, 2010, we completed the sale of our Minerals Business for approximately $171.6 million, which resulted in a pre-tax gain in the disposition of approximately $37.7 million. We used these proceeds to pay down amounts outstanding under our senior secured credit facility. Operations related to these assets for 2010 have been recorded as part of discontinued operations. |
• | On September 30, 2010, we acquired certain additional interest in the Big Escambia Creek Field (and the nearby Flomaton and Fanny Church fields) from Indigo Minerals, LLC for $3.9 million. During our fourth quarter ended December 31, 2010, we completed the acquisition of certain natural gas gathering systems and related facilities from Centerpoint Energy Field Services, Inc. for $27.0 million. We commenced recording results of operations relating to these acquisitions during our fourth quarter ended December 31, 2010. |
• | During our fourth quarter ended December 31, 2010, we incurred impairment charges of $26.2 million in our South Texas Segment and $0.1 million in our Upstream Segment. During our quarter ended September 30, 2010, we incurred impairment charges of $3.4 million related to our Upstream Segment. During our quarter ended June 30, 2010, we incurred impairment charges of $3.1 million related to our South Texas Segment. See Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Overview - Impairment for further discussion of our impairment charges during the year ended December 31, 2010. |
• | We experienced significant fluctuations in our unrealized commodity derivative gains and losses from quarter to quarter as a result of the volatility that was experience by commodity prices during 2010. For example, we recorded unrealized gains of $13.5 million and $41.4 million during our quarters ended March 31, 2010 and June 30, 2010, respectively, while we recorded unrealized losses of $17.0 and $29.6 million during our quarters ended September 30, 2010 and December 31, 2010, respectively. See Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Overview – General Trends and Outlook – Natural Gas Supply and Demand and Petroleum Supply, Demand and Outlook for further discussion regarding the volatility of commodity prices. |
The following table summarizes our quarterly financial data for 2009:
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For the Quarters Ended | |||||||||||||||
March 31, 2009 | June 30, 2009 | September 30, 2009 | December 31, 2009 | ||||||||||||
($ in thousands, except earnings per unit) | |||||||||||||||
Sales of natural gas, NGLs, condensate and sulfur | $ | 158,490 | $ | 153,320 | $ | 156,779 | $ | 185,123 | |||||||
Gathering and treating services | 11,667 | 11,562 | 11,814 | 10,433 | |||||||||||
Realized commodity derivative gains (losses) | 30,778 | 22,483 | 17,170 | 12,869 | |||||||||||
Unrealized commodity derivative gains (losses) | (4,522 | ) | (97,044 | ) | (26,002 | ) | (62,022 | ) | |||||||
Other revenues | 42 | 1,678 | 50 | 88 | |||||||||||
Total operating revenues | 196,455 | 91,999 | 159,811 | 146,491 | |||||||||||
Cost of natural gas and NGLs | 133,217 | 115,640 | 109,945 | 129,428 | |||||||||||
Operating and maintenance expense | 21,148 | 21,629 | 19,665 | 21,520 | |||||||||||
General and administrative expense | 12,513 | 11,866 | 10,420 | 11,020 | |||||||||||
Other operating income | — | (3,552 | ) | — | — | ||||||||||
Depreciation, depletion, amortization and impairment expense | 28,630 | 26,136 | 26,932 | 50,345 | |||||||||||
Interest—net including realized risk management instrument | 10,990 | 10,434 | 9,345 | 9,511 | |||||||||||
Unrealized interest rate derivative (gains) losses | (3,099 | ) | (11,954 | ) | 5,308 | (2,784 | ) | ||||||||
Income tax (benefit) provision | (2,764 | ) | (1,512 | ) | 5,802 | (596 | ) | ||||||||
Other expense (income) | 183 | 68 | (273 | ) | 158 | ||||||||||
Discontinued operations | (1,818 | ) | (1,969 | ) | (2,062 | ) | (3,456 | ) | |||||||
Net loss | $ | (2,545 | ) | $ | (74,787 | ) | $ | (25,271 | ) | $ | (68,655 | ) | |||
Earnings per unit—diluted | |||||||||||||||
Common units | $ | (0.03 | ) | $ | (0.99 | ) | $ | (0.33 | ) | $ | (0.90 | ) | |||
Subordinated units | $ | (0.06 | ) | $ | (1.02 | ) | $ | (0.35 | ) | $ | (0.93 | ) | |||
General partner | $ | (0.03 | ) | $ | (0.99 | ) | $ | (0.33 | ) | $ | (0.90 | ) | |||
During our fiscal year ended December 31, 2009, we recorded the following unusual or infrequently occurring items:
• | During our quarter ended December 31, 2009, we incurred impairment charges of $13.7 million in our Midstream Business and $7.9 million in our Upstream Segment. During our quarter ended March 31, 2009, we recorded an impairment charge of $0.2 million in our Upstream Segment and in our quarter ended September 30, 2009, we recorded an impairment charge of $0.3 million in our Minerals Segment as a result of the continued decline in natural gas prices. See Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Overview – Impairment for further discussion of our impairment charges during the year ended December 31, 2009. |
• | We experienced significant fluctuations in our unrealized commodity derivative gains and losses from quarter to quarter as a result of the volatility that was experience by commodity prices during 2009. For example, we recorded unrealized losses of $62.0 million, $26.0 million and $97.0 million during our quarters ended December 31, 2009, September 30, 2009 and June 30, 2009, respectively, while in our quarter ended March 31, 2009, we only recorded an unrealized loss of $4.5 million. See Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Overview – General Trends and Outlook – Natural Gas Supply and Demand and Petroleum Supply, Demand and Outlook for further discussion regarding the volatility of commodity prices. |
• | During our quarter ended June 30, 2009, we recorded other operating income of $3.6 million due to the recovery of $2.2 million of assets previously written off and the release of $1.4 million of liabilities assumed as part of our purchase price allocation for our acquisitions of Escambia Asset Co. LLC and Redman Energy Holdings, L.P. |
• | Quarterly amounts generated during 2009 by our Minerals Business have been retrospectively adjusted to be included within discontinued operations as a result of the sale of our Minerals Business during our second quarter ended June 30, 2010. |
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Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.
The following discussion analyzes our financial condition and results of operations and should be read in conjunction with our historical consolidated financial statements and notes included elsewhere in this Annual Report.
OVERVIEW
We are a domestically-focused, growth-oriented, publicly-traded Delaware limited partnership engaged in the following two businesses:
• | Midstream Business—gathering, compressing, treating, processing and transporting of natural gas; fractionating and transporting of natural gas liquids (“NGLs”); and the marketing of natural gas, condensate and NGLs; and |
• | Upstream Business—acquiring, developing and producing oil and natural gas property interests. |
We report on our businesses in six accounting segments.
We conduct, evaluate and report on our Midstream Business within four distinct segments—the Texas Panhandle Segment, the East Texas/Louisiana Segment, the South Texas Segment and the Gulf of Mexico Segment. Our Texas Panhandle Segment consists of gathering and processing assets in the Texas Panhandle. Our East Texas/Louisiana Segment consists of gathering and processing assets in East Texas/Northern Louisiana. Our South Texas Segment consists of gathering systems and related compression and processing facilities in South Texas, Central Texas, and West Texas. Our Gulf of Mexico Segment consists of gathering and processing assets in Southern Louisiana, the Gulf of Mexico and Galveston Bay. During the year ended December 31, 2010, our Midstream Business generated operating income from continuing operations of $19.2 million, compared to operating income from continuing operations of $4.9 million generated during the year ended December 31, 2009, an increase of $14.3 million. In addition, during the year ended December 31, 2010, our Midstream Business incurred impairment charges of $29.3 million, compared to $13.7 million during the year ended December 31, 2009.
We conduct, evaluate and report on our Upstream Business as one segment. Our Upstream Segment includes operated wells in Escambia County, Alabama as well as two treating facilities, one natural gas processing plant and related gathering systems. The Upstream Segment also includes operated and non-operated wells that are primarily located in West, East and South Texas in Ward, Crane, Pecos, Henderson, Rains, Van Zandt, Limestone, Freestone and Atascosa Counties. During the year ended December 31, 2010, our Upstream Business generated operating income of $28.0 million compared to an operating loss of $3.5 million generated during the year ended December 31, 2009. Of important note, our Upstream Business generated net revenue of $6.1 million from the sale of sulfur during the year ended December 31, 2010, compared to expense of $2.2 million during the year ended December 31, 2009. In addition, during the year ended December 31, 2010, our Upstream Business incurred impairment charges related to its unproved properties of $3.4 million, compared to $8.1 million for its proved properties during the year ended December 31, 2009.
The final segment that we report on is our Corporate Segment, which is where we account for our commodity derivative/hedging activity, intercompany eliminations and our general and administrative expenses. During the year ended December 31, 2010, our Corporate Segment generated an operating loss of $56.1 million compared to an operating loss of $153.2 million generated during the year ended December 31, 2009. Within these numbers were net losses, realized and unrealized, on commodity derivatives of $8.8 million during the year ended December 31, 2010 compared to losses, realized and unrealized, on commodity derivatives of $106.3 million during the year ended December 31, 2009.
On May 24, 2010, as part of the Recapitalization and Related Transactions (discussed below), we sold our Minerals Business, which had been broken out as a separate segment in prior filings. As a result of the sale, financial information related to the Minerals Business for 2010 has been classified as discontinued operations and financial information for previous years has been retrospectively adjusted to classify assets and liabilities as held-for-sale and operations as discontinued. For a further discussion of the sale of our Minerals Business, see Note 19, to our consolidated financial statements included in Part II, Item 8. Financial Statement and Supplementary Data starting on page F-1 of this Annual Report.
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Impairment
For the years ended December 31, 2010, 2009 and 2008, we determined that we needed to record an impairment charge for certain plants and pipelines within our Midstream Business and certain proved and unproved properties within our Upstream Business. As a result, we incurred impairment charges during the year ended December 31, 2010 of (i) $3.1 million in our South Texas Segment due to the termination of a significant gathering contract on our Raymondville system, (ii) $26.2 million due to an anticipated decline in volumes on our Wildhorse gathering system within our South Texas Segment, (iii) $3.4 million in our Upstream Segment related to certain fields in its unproved properties which we determined are not technologically feasible to develop and (iv) $0.1 million of proved properties in our Upstream segment due to adjustments to reserves. During the year ended December 31, 2009, we determined that we needed to record an impairment charge for certain plants and pipelines within our Midstream Business and certain fields within our proved properties within our Upstream Segment. As a result, we incurred impairment charges of (i) $13.7 million in our Midstream segment due to reduced throughput volumes as our producer customers curtailed their drilling activity in response to lower natural gas prices, and (ii) $8.1 million in our Upstream Segment, of which, $7.9 million was a result of a decline in natural gas prices, production declines and lower natural gas liquids yields at our Flomaton field and $0.2 million in other fields due to lower natural gas prices. During the year ended December 31, 2008, we recorded impairment charges related to certain processing plants, pipelines and contracts in its Midstream business of $35.1 million due to the substantial decline in commodity prices in the fourth quarter as well as declining drilling activity by its producer customers and $107.0 million in our Upstream Segment. Due to the impairment charge recorded in our Upstream Segment, we assessed our goodwill balance for impairment and recorded an impairment charge of $31.0 million for the year ended December 31, 2008.
Pursuant to generally accepted accounting principles in the United States, our impairment analysis does not take into account the value of our commodity derivative instruments, which generally increase as the estimates of future prices decline. Further declines in commodity prices and other factors could result in additional impairment charges and changes to the fair value of our derivative instruments.
Acquisitions
Historically, we have grown through acquisitions. On September 30, 2010, we acquired certain additional interests in
the Big Escambia Creek, Flomaton and Fanny Church fields in South Alabama from Indigo Minerals, LLC for $3.9 million. These interests are in wells in which we currently own a significant interest and are nearly 100% operated by us. On October 19, 2010, we acquired certain natural gas gathering systems and related facilities located primarily in Wheeler and Hemphill Counties in the Texas Panhandle (the "East Hemphill System") from Centerpoint Energy Field Services, Inc ("CEFS"). The purchase price for the assets was $27.0 million, subject to customary adjustments. We did not make any acquisitions during the year ended December 31, 2009. Refer to Part I, Item 1. Business – Table of Acquisitions/Dispositions in the past five years for a history of acquisitions.
Going forward, we will continue to assess acquisition opportunities for their potential accretive value. Our ability to complete acquisitions will depend on our ability to finance the acquisitions, either through the issuance of additional debt or equity securities or the incurrence of additional debt under our credit facilities, on terms acceptable to us.
Other Matters
Unscheduled Shut-Down of Third-Party Owned and Operated Eustace Processing Facility - On August 11, 2010, the Eustace processing facility, which processes substantially all of our East Texas oil and gas production, was shut down due to events stemming from an electrical failure. As a result, we were unable to produce from our East Texas upstream properties from that date through the end of the year. We estimate the shut-down of the Eustace facility impacted our Upstream Segment's net revenues by approximately $7.1 million in 2010. We recouped $3.0 million of this loss in 2010 under our business interruption insurance, which was recognized as other revenue, and expect to recoup an additional $2.0 million (to reach the total maximum recovery of $5.0 million under our business interruption insurance policy) in the first quarter of 2011. On March 10, 2011, the third-party operator of the Eustace Processing Facility was in the process of returning the facility to service.
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Recent Transactions
Recapitalization and Related Transactions
On December 21, 2009, we announced that we, through certain of our affiliates, had entered into definitive agreements
with affiliates of Natural Gas Partners ("NGP" and collectively with such affiliates, the “NGP Parties”) and Black Stone
Minerals Company, L.P. to improve our liquidity and simplify our capital structure. The definitive agreements included: (i) a
Securities Purchase and Global Transaction Agreement, entered into between us and the NGP Parties, including our general
partner entities controlled by NGP, and (ii) a Purchase and Sale Agreement (the “Minerals Business Sale Agreement”), entered
into between us and Black Stone for the sale of our Minerals Business. The Securities Purchase and Global Transaction
Agreement was amended and restated on January 12, 2010 to allow for greater flexibility in the payment of the contemplated
transaction fee to Eagle Rock Holdings, L.P. ("Holdings"), which is controlled by NGP (we refer to the amended Securities
Purchase and Global Transaction Agreement throughout this document as the “Global Transaction Agreement”).
On May 21, 2010, a majority of our unitholders who are not affiliated with our general partner approved, among other
things, the Global Transaction Agreement, which contemplated a series of transactions that sought to simplify and recapitalize the Partnership, including:
• | the simplification of our capital structure through the contribution, and resulting cancellation, of our incentive distribution rights and all 20,691,495 subordinated units held by Holdings, which occurred on May 24, 2010; |
• | the sale of all of our fee mineral and royalty interests, as well as our equity investment in Ivory Working Interests, L.P. (collectively, the “Minerals Business”) to Black Stone Minerals Company, L.P., which was completed on May 24, 2010 and for which we received net proceeds of $171.6 million. We retained approximately $2.9 million of cash received from net revenues received from the Minerals Business after the effective date of the sale, making our total proceeds from the sale of the Minerals Business $174.5 since January 1, 2010; |
• | a rights offering, which was launched on June 1, 2010 and expired on June 30, 2010, and for which we received gross proceeds of $53.9 million and issued 21,557,164 common units and warrants; |
• | the GP Acquisition Option, exercisable by the issuance of 1,000,000 newly-issued common units to Holdings, to capture the value of the controlling interest in us through (a) acquiring our general partner entities from Holdings and immediately thereafter eliminating our 844,551 outstanding general partner units and (b) reconstituting our Board to allow our common unitholders not affiliated with NGP to elect the majority of our directors. On July 27, 2010, notice was given to Holdings of our intention to exercise the GP Acquisition Option, and we closed the transaction on July 30, 2010. In connection with the completion of the GP Acquisition Option, our board of directors was expanded to include two additional independent directors who were appointed by the conflicts committee on July 30, 2010; and |
• | the obligation of NGP, at the sole discretion of our conflicts committee, to purchase up to $41.6 million, at a price of $3.10 per unit, of an Eagle Rock Energy equity offering. Our conflicts committee determined that it was not in our best interests to require NGP to purchase equity at the $3.10 per unit price, and the obligation expired on September 21, 2010. |
Credit Facility Amendment
On March 8, 2010, we entered into the Second Amendment (the “Credit Facility Amendment”) to our credit
agreement, dated as of December 13, 2007, with Wachovia Bank, N.A., Bank of America, N.A., HSH NordBank AG, New
York Branch, The Royal Bank of Scotland, PLC, BNP Paribas and the other lenders party thereto. In connection with our
unitholders' approval of the Global Transaction Agreement and related matters, the Credit Facility Amendment became
effective.
The Credit Facility Amendment modified the definition of “Change in Control” in such a way that our exercise of the
GP Acquisition Option did not trigger a “Change in Control” event and potential default; see “General Partner Acquisition
Option.” In addition to modifying the definition of “Change in Control,” the Credit Facility Amendment also:
• | reduced the maximum permitted Senior Secured Leverage Ratio (as such term is defined in our credit agreement) from 4.25 to 1.0 under the current credit agreement to 3.75 to 1.0 (and from 4.75 to 1.0 to 4.25 to 1.0 for specified periods following certain permitted acquisitions). The Senior Secured Leverage Ratio covenant is only relevant if we have unsecured senior or subordinated notes outstanding; |
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• | obligated us to use $100 million of the proceeds from the sale of our Minerals Business (described above) to make a mandatory prepayment towards our outstanding borrowings under the revolving credit facility, which mandatory prepayment was made on May 25, 2010; and |
• | reduced, upon such mandatory prepayment, our borrowing capacity under the revolving credit facility by the $100 million amount of such mandatory prepayment; however, this did not impact our availability under our revolving credit facility because it is limited by compliance with financial covenants. |
• | The Credit Facility Amendment further clarified that the proceeds from the sale of our Minerals Business in excess of$100 million may be used to immediately reduce debt, but did not result in a mandatory prepayment unless such proceeds were not reinvested in Property (as defined in our credit agreement) within the 270-day post-closing period (i.e. by February 18, 2011) provided in our credit agreement. On May 28, 2010, we repaid an additional $72 million towards our outstanding borrowings under the revolving credit facility from proceeds from the sale of our Minerals Business. We do not anticipate any further reductions in commitments under the Credit Facility resulting from the sale of the Minerals Business. |
Borrowing Base Redetermination
On October 19, 2010, we announced that the borrowing base under our revolving credit facility, which relates to our
Upstream Business, was set at $140 million as part of our regularly scheduled semi-annual borrowing base redetermination. This was an increase from the $130 million our borrowing base was set at during the April 2010 redetermination. The redetermined borrowing base was effective October 1, 2010, with no additional fees or increase in interest rate spread incurred.
How We Evaluate Our Operations
Our management uses a variety of financial and operational measurements to analyze our performance. We view these measurements as important factors affecting our profitability and review these measurements on a monthly basis for consistency and trend analysis. These measures include volumes, margin, operating expenses and Adjusted EBITDA (defined on page 78) on a company-wide basis.
Volumes (by Business)
Midstream Volumes. In our Midstream Business, due to the natural production decline of the wells connected to our systems we must continually obtain new supplies of natural gas to maintain or increase throughput volumes on our gathering and processing systems in order to achieve our distribution objectives. Our ability to maintain existing supplies of natural gas and obtain new supplies is impacted by (1) the level of workovers or recompletions of existing connected wells and successful drilling activity in areas currently dedicated to our pipelines, (2) our ability to compete for volumes from successful new wells in other areas and (3) our ability to obtain natural gas that has been released from other commitments. We routinely monitor producer activity in the areas served by our gathering and processing systems to pursue new supply opportunities.
We rely on producer drilling activity to maintain and grow our midstream volumes. Generally, producer drilling activity is correlated to the current and expected price of natural gas, and to the current and expected price of crude oil in producing basins that have liquids-rich gas reservoirs. As such, throughput volume in our existing midstream assets will typically increase in times of rising gas prices and will typically decrease in times of falling gas prices, except that in liquids-rich basins we may continue to experience a high level of drilling activity during periods when oil prices are high, even if gas prices are relatively low.
Upstream Volumes. In the Upstream Segment, we continually monitor the production rates of the wells we operate. This information is a critical indicator of the performance of our wells, and we evaluate and respond to any significant adverse changes. We employ an experienced team of engineering and operations professionals to monitor these rates on a well-by-well basis and to design and implement remediation activities when necessary. We also design and implement workover and drilling operations to increase production in order to offset the natural decline of our currently producing wells.
Margin
Commodity Pricing. The margins in our Midstream Business generally are positively correlated to NGL and condensate prices, and may be adversely impacted to the extent the price of NGLs decline in relation to the price of natural gas. We refer to the price of NGLs in relation to the price of natural gas as the "fractionation spread." In our Upstream Segment,
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increases in crude oil, natural gas and NGL prices will generally have a favorable impact on our revenues, conversely, decreases in crude oil, natural gas and NGL prices will generally unfavorably impact our revenue.
Risk Management. We conduct risk management activities to mitigate the effect of commodity price and interest rate fluctuations on our cash flows. Our primary method of risk management in this respect is entering into derivative contracts. The impact of our risk management activities are captured in our Corporate Segment. For a further discussion of our risk management activities, see Part II, Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
Operating Expenses
Midstream Operating Expenses. We monitor midstream operating expenses as a measure of the operating efficiency of our field operations. Direct labor, repair and maintenance, utilities and contract services comprise the most significant portion of our operating expenses. These expenses are largely independent of the volumes through our systems, but fluctuate depending on the activities performed during a specific period.
Upstream Operating Expenses. We monitor and evaluate our Upstream Segment operating costs routinely, both on a total cost and unit cost basis. Many of the operating costs we incur are not directly related to the quantity of hydrocarbons that we produce, so we strive to maximize our production rates in order to improve our unit operating costs. The most significant portion of our Upstream Segment operating costs is associated with the operation of the Big Escambia Creek treating and processing facilities. These facilities are overseen by members of our midstream engineering and operations staff. The majority of the cost of operating these facilities is independent of their throughput. This includes items such as labor, chemicals, utilities and materials.
Adjusted EBITDA
See discussion of Adjusted EBITDA in Part II, Item 6. Selected Financial Data.
General Trends and Outlook
We expect our business to be affected by the following key trends. This expectation is based on assumptions made by us and information currently available to us; however, our actual results may vary materially from our expectations.
Although the global economic weakness that began in late 2008 and continued through 2009 has improved, we expect to continue to feel its effects for several years. Specifically, we expect relatively low economic growth in the United States and other developed economies and relatively high levels of unemployment. We expect the current low interest rate environment to persist throughout 2011 and that credit will remain widely available. However, we expect international sovereign credit concerns and domestic local and state credit concerns to continue to be a source of uncertainty in global credit markets. We further believe that persistent unemployment and housing concerns of U.S. consumers will result in sluggish domestic demand, and that business investment in capacity expansion will remain depressed until demand increases. The issues of low demand and excess productive capacity may be worsened by fiscal austerity measures taken to address national budget deficits.
Within the developing economies, we expect levels of growth to continue at pre-recession levels. In the case of China, many economists believe that its economy is growing at an annual rate of 10% and showing signs of significant inflation. We believe that the Chinese government will take steps to attempt to reduce inflation, but that the factors that are influencing the high level of growth in the Chinese economy will generally continue. The increased demand for commodities that this growth is expected to cause has significant implications for commodity prices in general and for oil prices, in particular.
Natural Gas Supply and Demand
Natural gas prices are more dependent than crude oil prices on regional supply and demand due to the relative difficulty in transporting natural gas from producing to consuming regions of the world. In the United States, where we produce natural gas, the outlook for natural gas demand has improved since the depths of the recession, but we do not expect significant increases in the demand for natural gas during 2011. Over the longer term, however, we believe that the environmental advantages that natural gas has over coal will result in the construction of additional natural gas-fired electricity generation capacity, both for new capacity and to replace aging coal-fired facilities.
During 2010, natural gas prices remained relatively low compared to the prices experienced prior to the recession. Our expectation was that these low prices would lead to reduced gas well drilling and lower natural gas supply, and that the resumption of growth in the United States economy would provide support to natural gas prices. This has not yet occurred,
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however, as operators continue to drill gas wells in emerging shale gas plays such as the Haynesville, Marcellus and Eagle Ford in order to place their leases into production before they expire. In addition, producers have increased their drilling in liquids-rich gas plays such as the Granite Wash and the Eagle Ford in order to extract the more valuable NGLs from the raw gas stream. We now expect that these plays will continue to provide a source of future natural gas supply for the next several years and expect prices to remain near their current level for some time.
In addition to North American drilling activity, imported liquefied natural gas ("LNG") has the potential to increase the supply of natural gas in the United States. At the end of 2010, LNG imports were approximately 1.0 Bcf/d which some forecasters previously predicted might increase to as much as 4.0 Bcf/d in the next few years. However, some of the large LNG projects that are under construction to provide this supply are reported to have been delayed due to the global economic weakness, and the relatively low price of natural gas in the United States compared to other countries that import natural gas make a significant increase in LNG imports in the U.S. unlikely. Recently, there has been some speculation in the industry that the United States may begin to export LNG.
Crude Oil Supply, Demand and Outlook
The majority of the world's crude oil production and reserves is controlled by foreign governments and state-owned oil companies. Many of these countries rely on crude oil exports to fund the majority of their governmental expenditures, and in some of these the export of crude oil represents the bulk of their economic output. Certain exporting countries have seen declines in their production rates due to low levels of capital re-investment in their oil industry. We believe that, while some oil exporting countries will be able to increase their production to meet future increases in demand, that others will have a difficult time maintaining their production levels and that this may result in an undersupplied market for crude oil within a few years.
There are several factors which influence the demand for crude oil, but ultimately the continued growth of the developing economies will result in much greater demand for crude oil. It is uncertain how quickly demand will exceed supply, but we believe that crude oil prices may remain high relative to historical averages or further strengthen over the next one to two years.
Natural gas liquids prices tend to have a high correlation to crude oil prices, especially for propane and heavier NGLs, and we expect this trend to continue. Ethane prices historically have been less correlated to crude oil than have the heavier NGLs. Ethane demand is primarily driven by global petrochemical production and specifically by its use as a feedstock for ethylene. Ethane's low price relative to heavier ethylene feedstocks such as naptha has resulted in strong worldwide demand, and chemical manufacturers have recently announced projects to increase their ethylene production capacity using ethane. We believe this trend will provide support to ethane prices throughout 2011. The increase in drilling activity focused on liquids-rich areas, however, is projected to substantially increase the supply of ethane, which could result in downward pressure on ethane prices over the longer-term.
Sulfur Supply, Demand and Outlook
Much of the natural gas that we produce in our Upstream Segment contains high, naturally-occurring concentrations of hydrogen sulfide. This is a corrosive, poisonous gas that must be removed from the natural gas stream before it can be processed for NGL extraction or sale. The process of removing the hydrogen sulfide yields a large amount of elemental sulfur, which we sell or otherwise dispose of. The process of removing hydrogen sulfide from natural gas, and similar processes for the removal of hydrogen sulfide from sour crude oils (prior to refining), is the primary source of sulfur production in the United States and the world.
The primary use of sulfur is the production of sulfuric acid, and one of the major uses of sulfuric acid is the production of phosphoric acid. Phosphoric acid is a key raw material in the manufacture of phosphate fertilizers. Therefore, one of the major factors influencing the demand for sulfur is the demand for fertilizer. The region around Tampa, Florida contains a large amount of fertilizer manufacturing facilities, and Tampa also serves as an export port for sulfur. For many years, the supply of sulfur was greater than the available demand, such that Tampa prices fluctuated within a narrow band of $20 to $40 per long ton. Depending on a seller's proximity to Tampa, transportation charges may have equaled or exceeded the selling price of the sulfur under this pricing environment.
Beginning in the second half of 2007, global demand for fertilizer increased significantly, and as a result, Tampa prices also rose to record levels. In late 2008, sulfur prices at Tampa peaked at over $600 per long ton. The global economic recession greatly reduced fertilizer demand; however, much of this demand has returned. As with many commodities, the developing economies are responsible for much of this demand growth. By the end of 2008, Tampa sulfur prices had fallen to $0 (zero dollars) per long ton, and they remained low throughout 2009. By the first quarter of 2010, prices had risen to $90 per
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long ton and ended the year at over $150 per long ton. We expect demand to remain relatively strong in 2011, but not as great as that in 2007. Nevertheless, over the next few years, continued rapid growth in emerging economies could result in supply/demand imbalances that could lead to the types of prices spikes we experienced in 2007.
Outlook for Interest Rates and Inflation
In response to the global recession which began in 2008, the governments and central banks of the world's large economies adopted fiscal and monetary policies that introduced unprecedented amounts of liquidity into their financial systems. Most of these efforts have been substantially completed and, other than certain monetary efforts in the United States, we believe it is unlikely that significant amounts of additional liquidity will be injected. Because these economies have excess productive capacity due to the reduction in demand caused by the recession, this liquidity has not led to inflationary pressures. In addition, some of these economies have already begun, or are contemplating, tightening their fiscal policies. This reduction in spending is also likely to reduce inflationary pressures. Eventually, however, as the economies recover and demand increases, policymakers will need to remove excess liquidity from their economies to avoid significant levels of inflation. This will be a delicate task and will require a high degree of coordination among central banks.
It is impossible to predict when these policy changes will occur or how successful they will be. In the near term, however, we expect that unemployment and underemployment will remain high, and this will act as a brake on inflation. As inflationary pressures arise, however, we expect that one of the responses will be higher interest rates, and this could increase our interest expenses.
Impact of Regulation of Greenhouse Gas Emissions
The operations of and use of the products produced by the natural gas and oil industry are sources of emissions of certain greenhouse gases ("GHGs"), namely carbon dioxide and methane. Regulation of GHG emissions has not had an impact on our operations in the past, and the regulation of our GHG emissions as such has not occurred. However, there is a trend towards government-imposed limitation of GHG emissions at the state, regional, and federal level.
The United States Environmental Protection Agency ("EPA"), by virtue of a 2007 Supreme Court decision, was deemed to have authority to regulate carbon dioxide and other GHG emissions under the Clean Air Act, and they are drafting and preparing to implement regulations. It is possible that legislation will be proposed to amend the Clean Air Act to exclude GHGs, although the probability of the enactment of such legislation is uncertain.
In addition, in 2009 there was a significant effort in the United States Congress to enact legislation to establish a cap-and-trade system as a means to regulate GHG emissions. A cap-and-trade bill was approved by the House of Representatives, but was not approved in the Senate. Given the House of Representatives is now under control of the Republican Party which has historically opposed GHG regulation, the probability of of enactment of a cap-and-trade bill during the next two years at least is extremely low. Because of the uncertainty of the nature of any potential future federal GHG regulations at this time, we are unable to forecast how future regulation of GHG emissions would negatively impact our operations. We will continue to monitor regulatory developments and to assess our ability to reasonably predict the economic impact of these developments on our business.
The commercial risk associated with the exploration and production of fossil fuels lies in the uncertainty of regulations that may affect our customers, which could affect the demand for crude oil and natural gas. Such an impact on demand could have an adverse impact on the demand for our services, and could have an impact on our financial condition, results of operations and cash flows.
On the other hand, when burned, natural gas produces less greenhouse gas emissions than other fossil fuels, such as refined petroleum products or coal. As a result, climate change legislation or GHG emissions regulations could create an increased demand for natural gas.
Critical Accounting Policies
Conformity with accounting principles generally accepted in the United States ("GAAP") requires management to make estimates and judgments that affect the amounts reported in the financial statements and notes. On an ongoing basis, we make and evaluate estimates and judgments based on management's best available knowledge of previous, current, and expected future events. We base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ from these estimates, and estimates are subject to change due to modifications in the underlying conditions or assumptions. Currently, we do not foresee any reasonably likely changes to our
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current estimates and assumptions which would materially affect amounts reported in the financial statements and notes. We have selected the following critical accounting policies that currently affect our financial condition and results of operations for discussion.
Successful Efforts. We utilize the successful efforts method of accounting for our oil and natural gas properties. Leasehold costs are capitalized when incurred. Costs incurred to drill and complete development wells are capitalized. Unproved properties are assessed periodically within specific geographic areas and, if necessary, impairments are charged to expense. Geological and geophysical expenses and delay rentals are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to expense if the well is determined to be unsuccessful. We carry the costs of an exploratory well as an asset if the well finds a sufficient quantity of reserves to justify its capitalization as a producing well as long as we are making sufficient progress towards assessing the reserves and the economic and operating viability of the project.
Depletion of producing oil and natural gas properties is recorded based on units of production. Unit rates are computed for unamortized drilling and development costs using proved developed reserves and for acquisition costs using all proved reserves. U.S. GAAP authoritative guidance requires that acquisition costs of proved properties be amortized on the basis of all proved reserves (developed and undeveloped) and that capitalized development costs (wells and related equipment and facilities) be amortized on the basis of proved developed reserves. Since our units of production depletion and amortization rate are a function of our proved reserves, we experience a higher depletion and amortization rate than we would if we claimed undeveloped or non-producing reserves.
Upon sale or retirement of complete fields of depreciable or depleted property, the book value thereof, less proceeds or salvage value, is charged or credited to income.
We assess proved oil and natural gas properties in our Upstream Segment for possible impairment when events or circumstances indicate that the recorded carrying value of the properties may not be pre-tax recoverable. We recognize an impairment loss as a result of a triggering event and when the estimated undiscounted pre-tax future cash flows from a property are less than the carrying value. If impairment is indicated, the fair value is compared to the carrying value for determining the amount of the impairment loss to record. Estimated future cash flows are based on management's expectations for the future and include estimates of oil and natural gas reserves and future commodity prices and operating costs. Downward revisions in estimates of reserve quantities or expectations of falling commodity prices or rising operating costs could result in a reduction in undiscounted future cash flows and could indicate property impairment. During the year ended December 31, 2010, we incurred $0.1 million of impairment charges in our Upstream segment as a result of adjustments to our reserves. During the year ended December 31, 2009, we incurred impairment charges of $8.1 million in our Upstream segment as a result of a decline in natural gas prices, production declines and lower natural gas liquids yields. During the year ended December 31, 2008, we incurred impairment charges related to certain fields of $107.0 million in our Upstream Segment due to the substantial decline in commodity prices during the fourth quarter of 2008.
Unproved properties that are individually insignificant are amortized. Unproved properties that are individually significant are assessed for impairment on a property-by-property basis. If considered impaired, costs are charged to expense when such impairment is deemed to have occurred. During the year ended December 31, 2010, we recorded $3.4 million in impairment charges for certain undrilled wells within our Upstream Segment's unproved properties because we determined it would not be economical to develop these unproved locations.
Our estimates of proved reserves are based on the quantities of oil and natural gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic conditions. Annually, and on other occasions, Cawley, Gillespie & Associates, Inc. prepares an estimate of the proved reserves on all our properties, based on information provided by us.
Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. We prepare our reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with SEC guidelines. The independent engineering firm described above adheres to the same guidelines when preparing their reserve reports. The accuracy of our reserve estimates is a function of many factors including the following: the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions and the judgments of the individuals preparing the estimates. The data for a given reservoir may change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Changes in oil and natural gas prices, operating costs and expected performance from a given reservoir also will result in revisions to the amount of our estimated proved reserves.
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Our proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of natural gas, natural gas liquids and oil eventually recovered.
Revenue and Cost of Goods Sold Recognition. Within our Midstream and Upstream businesses, sales of oil, natural gas, NGLs and sulfur are recognized when their is persuasive evidence of an arrangement, the product has been delivered, the sales price is fixed and determinable and collection of revenue from the sale is reasonably assured. In our Midstream Business, we record revenue and cost of goods sold on the gross basis for those transactions where we act as the principal and take title to natural gas, NGLs or condensates that is purchased for resale. Our service-related revenue is recognized in the period when the service is provided and includes our fee-based service revenue for services such as transportation, compression, treating and processing.
Risk Management Activities. We have structured our hedging activities in order to minimize our commodity pricing and interest rate risks and to help maintain compliance with certain financial covenants in our revolving credit facility. These hedging activities rely upon forecasts of our expected operations and financial structure over the next few years. If our operations or financial structure are significantly different from these forecasts, we could be subject to adverse financial results as a result of these hedging activities. We mitigate this potential exposure by retaining an operational cushion between our forecasted transactions and the level of hedging activity executed. Based on our current production estimates, we have hedged approximately 91% of our 2011 expected hedgeable crude, condensate and natural gas liquids (heavier than propane) volumes and 63% of our natural gas and ethane production. Similarly based on the production estimates in our current forecast, we have hedged approximately 78% of our 2012 expected hedgeable crude, condensate and natural gas liquids (heavier than propane) volumes and 50% of our natural gas and ethane production.
From the inception of our hedging program, we used mark-to-market accounting for our commodity hedges and interest rate swaps. We record monthly realized gains and losses on hedge instruments based upon cash settlement information. The settlement amounts vary due to the volatility in the commodity market prices throughout each month. We also record unrealized gains and losses monthly based upon the future value on mark-to-market hedges through their expiration dates. The expiration dates vary but are currently no later than December 2012 for our interest rate hedges and December 2013 for our commodity hedges. Option premiums and costs incurred to reset contract prices or purchase swaps are amortized during the contract period through the unrealized risk management instruments in total revenue. We monitor and review hedging positions regularly.
Depreciation Expense and Cost Capitalization Policies. Our midstream assets consist primarily of natural gas gathering pipelines and processing plants. We capitalize all construction-related direct labor and material costs, as well as indirect construction costs. Indirect construction costs include general engineering and the cost of funds used in construction. The cost of funds used in construction represent capitalized interest. These costs are then expensed over the life of the constructed asset through the recording of depreciation expense.
As discussed in Note 2 to our consolidated financial statements included in Part II, Item 8. Financial Statements and Supplementary Data starting on page F-1 of this Annual Report, depreciation of our midstream assets is generally computed using the straight-line method over the estimated useful life of the assets. The costs of renewals and betterments which extend the useful life of property, plant and equipment are also capitalized. The costs of repairs, replacements and maintenance projects are expensed as incurred.
The computation of depreciation expense requires judgment regarding the estimated useful lives and salvage value of assets. As circumstances warrant, depreciation estimates are reviewed to determine if any changes are needed. Such changes could involve an increase or decrease in estimated useful lives or salvage values which would impact future depreciation expense.
Impairment of Long-Lived Assets. We assess our long-lived assets for impairment whenever events or changes in circumstances indicate its carrying amount may not be recoverable.
Examples of events or changes in circumstances include:
• | a significant decrease in the market price of a long-lived asset or asset group; |
• | a significant adverse change in the extent or manner in which a long-lived asset or asset group is being used or in its physical condition; |
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• | a significant adverse change in legal factors or in the business climate could affect the value of a long-lived asset or asset group, including an adverse action or assessment by a regulator which would exclude allowable costs from the rate-making process; |
• | an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of a long-lived asset or asset group; |
• | a current-period operating cash flow loss combined with a history of operating cash flow losses or a projection or forecast that demonstrates continuing losses associated with the use of a long-lived asset or asset group; and |
• | a current expectation that, more likely than not, a long-lived asset or asset group will be sold or otherwise disposed of significantly before the end of its previously estimated useful life. |
The carrying value of a long-lived asset is determined to not be recoverable when the carrying value of a long-lived asset exceeds our estimate of the undiscounted cash flows expected to result from the use and eventual disposition of the long-lived asset. If the carrying value of a long-lived asset is determined not to be recoverable, the impairment loss is measured as the excess of the carrying value over its fair value. For our the long-lived assets in our Midstream Business, our estimate of cash flows is based on assumptions regarding the long-lived asset, including future commodity prices and estimate future natural gas production in the region (which is dependent in part on commodity prices). Our estimate of natural gas volumes and future commodity prices are inherently subjective and contingent upon a number of variable factors, including but not limited to: (i) changes in the general economic conditions in which the long-lived asset is located, (ii) the availability and prices of the natural gas supply, (iii) our dependence on certain significant customers and producers of natural gas and (iv)improvements in exploration and production technologies.
During the year ended December 31, 2010, we recorded $29.3 million in impairment charges within our Midstream Segment due to (i) $3.1 million related to the loss of a significant gathering contract in our South Texas Segment and (ii) $26.2 million related to an anticipated decline in volumes on our Wildhorse gathering system in our South Texas Segment. During the year ended December 31, 2009, we incurred impairment charges of $13.7 million in our Midstream segment as a result of reduced throughput volumes as our producer customers curtailed their drilling activity in response to lower natural gas prices. During the year ended December 31, 2008, the Partnership recorded an impairment charge related to certain processing plants, pipelines and contracts in its Midstream business of $35.1 million due to the substantial decline in commodity prices in the fourth quarter as well as declining drilling activity by its producer customers.
Goodwill Impairment. We assess our goodwill for impairment annually or whenever events indicate impairment may have occurred based on authoritative guidance. We performed our annual assessment in May 2008 and no impairment was evident at that point in time. As a result of the impairment charge recorded in our Upstream Segment, we performed an assessment of our goodwill during the fourth quarter and recorded an impairment charge of $31.0 million, or our entire goodwill balance, during the fourth quarter of 2008.
Environmental Remediation. Current accounting guidelines require us to recognize a liability and expense associated with environmental remediation if (i) government agencies mandate such activities or one of our properties were added to the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) database, (ii) the existence of a liability is probable and (iii) the amount can be reasonably estimated. As of December 31, 2010, we have recorded a $4.0 million liability for remediation expenditures. If governmental regulations change, we could be required to incur additional remediation costs which may have a material impact on our profitability. Accrued environmental costs represent our best estimate as to the total costs of remediation and the time period over which these costs will be incurred.
Asset Retirement Obligations. We have recorded liabilities of $24.7 million for future asset retirement obligations in our midstream and upstream operations as of December 31, 2010. Related accretion expense has been recorded in operating expenses, as discussed in Note 5 to our consolidated financial statements included in Part II, Item 8. Financial Statements and Supplementary Data starting on page F-1 of this Annual Report. The recognition of an asset retirement obligation requires that management make numerous estimates, assumptions and judgments regarding such factors as costs of remediation, timing of settlements, the credit-adjusted risk-free rate to be used and inflation rates. In periods subsequent to initial measurement of the asset retirement obligation, we must recognize period-to-period changes in the liability resulting from changes in the timing of settlement to changes in the estimate of the costs of remediation. Any such changes that result in upward or downward revisions in the estimated obligation will result in an adjustment to the related capitalized asset and corresponding liability on a prospective basis and an adjustment in our DD&A expense in future periods. During the year ended December 31, 2010, we recorded revisions to our estimated obligations that resulted in a increase to our capitalized assets and corresponding liabilities of $2.6 million
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Presentation of Financial Information
For a description of the presentation of our financial information in this report, please see Part II, Item 6. Selected Financial Data.
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Year Ended December 31, 2010 Compared with Year Ended December 31, 2009
Summary of Consolidated Operating Results
Below is a table of a summary of our consolidated operating results for the years ended December 31, 2010 and 2009. Operating results for our individual operating segments are presented in tables in this Item 7.
Year Ended December 31, | |||||||
2010 | 2009 | ||||||
($ in thousands) | |||||||
Revenues: | |||||||
Sales of natural gas, NGLs, oil, condensate and sulfur | $ | 712,795 | $ | 653,712 | |||
Gathering, compression, processing and treating fees | 51,951 | 45,476 | |||||
Realized commodity derivative (losses) gains | (17,010 | ) | 83,300 | ||||
Unrealized commodity derivative gains (losses) | 8,224 | (189,590 | ) | ||||
Other | 2,435 | 1,858 | |||||
Total revenues | 758,395 | 594,756 | |||||
Cost of natural gas and natural gas liquids | 490,206 | 488,230 | |||||
Costs and expenses: | |||||||
Operating and maintenance | 77,898 | 73,196 | |||||
Taxes and other income | 12,240 | 10,766 | |||||
General and administrative | 45,775 | 45,819 | |||||
Other operating income | — | (3,552 | ) | ||||
Impairment expense | 32,875 | 21,788 | |||||
Depreciation, depletion and amortization | 108,781 | 110,255 | |||||
Total costs and expenses | 277,569 | 258,272 | |||||
Total operating loss | (9,380 | ) | (151,746 | ) | |||
Other income (expense): | |||||||
Interest income | 111 | 187 | |||||
Other income | 501 | 934 | |||||
Interest expense | (15,147 | ) | (21,591 | ) | |||
Unrealized interest rate derivatives (losses) gains | (7,164 | ) | 12,529 | ||||
Realized interest rate derivative losses | (19,971 | ) | (18,876 | ) | |||
Other expense | (51 | ) | (1,070 | ) | |||
Total other income (expense) | (41,721 | ) | (27,887 | ) | |||
Loss from continuing operations before income taxes | (51,101 | ) | (179,633 | ) | |||
Income tax (benefit) provision | (2,545 | ) | 1,022 | ||||
Loss from continuing operations | (48,556 | ) | (180,655 | ) | |||
Discontinued operations, net of tax | 43,207 | 9,397 | |||||
Net loss | $ | (5,349 | ) | $ | (171,258 | ) | |
Adjusted EBITDA(a) | $ | 128,713 | $ | 174,525 | |||
________________________
(a) | See Part II, Item 6. Selected Financial Data – Non-GAAP Financial Measures for a definition and reconciliation to GAAP. |
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Midstream Business (Four Segments)
Texas Panhandle Segment
Twelve Months Ending December 31, | |||||||
2010 | 2009 | ||||||
(Amounts in thousands, except volumes and realized prices) | |||||||
Revenues: | |||||||
Sales of natural gas, NGLs, oil and condensate | $ | 346,278 | $ | 282,916 | |||
Gathering and treating services | 11,957 | 11,036 | |||||
Total revenues | 358,235 | 293,952 | |||||
Cost of natural gas, natural gas liquids, oil & condensate (a) | 243,054 | 206,985 | |||||
Operating costs and expenses: | |||||||
Operations and maintenance | 35,032 | 31,873 | |||||
Depreciation and amortization | 45,876 | 46,085 | |||||
Total operating costs and expenses | 80,908 | 77,958 | |||||
Operating income | $ | 34,273 | $ | 9,009 | |||
Capital expenditures | $ | 29,282 | $ | 7,293 | |||
Realized prices: | |||||||
Oil and condensate (per Bbl) | $ | 66.68 | $ | 60.14 | |||
Natural gas (per Mcf) | $ | 3.92 | $ | 3.23 | |||
NGLs (per Bbl) | $ | 45.85 | $ | 33.45 | |||
Production volumes: | |||||||
Gathering volumes (Mcf/d)(b) | 131,925 | 138,450 | |||||
NGLs (net equity gallons) (c) | 38,025,937 | 46,376,433 | |||||
Condensate (net equity gallons) (c) | 43,439,551 | 35,292,388 | |||||
Natural gas short position (MMbtu/d)(b) | (4,811 | ) | (6,010 | ) | |||
________________________
(a) | Includes purchase of oil and condensate of $5,587 from the Upstream Segment for the year ended December 31, 2010. |
(b) | Gathering volumes (Mcf/d) and natural gas short position (MMbtu/d) are calculated by taking the total volume and then dividing by the number of days in the respective period. |
(c) | Installation of additional measurement facilities in January 2010 has improved the measurement of NGLs and condensate volumes, resulting in increased equity condensate volumes and a corresponding decrease in equity NGL volumes. |
Revenue and Cost of Natural Gas and Natural Gas Liquids. For the year ended December 31, 2010, revenues minus cost of natural gas and natural gas liquids for our Texas Panhandle Segment operations totaled $115.2 million compared to $87.0 million for the year ended December 31, 2009. The increase is primarily driven by the higher NGL, natural gas and condensate pricing offset by lower gathering and equity volumes. As footnoted above, additional measurement facilities installed in January 2010 have resulted in improved measurement of NGLs and condensate volumes, which in turn resulted in increased equity condensate volumes and a corresponding decrease in equity NGL volumes versus the prior year ending December 31, 2009.
Our Texas Panhandle Segment lies within ten counties in Texas and consists of our East Panhandle System and our
West Panhandle System. The limited drilling activity in the West Panhandle System is not sufficient to offset the natural declines experienced on this system. While our contract mix in the West Panhandle System provides us with a higher equity share of the production, the overall decline will continue. In the East Panhandle, volumes were lower in the first half of 2010 due to falling natural gas prices which constrained drilling activity by our producer customers as they evaluated the economics of the Granite Wash play. We saw a resurgence of drilling activity by our producer customers beginning in the third quarter of 2010 as NGL prices increased dramatically due to improved demand in the United States for NGLs by the petrochemical industry. Given the improvements in horizontal drilling technology and fracturing practices, our producer customers are active in the development of the Granite Wash play. We began to see the benefit of this increase in drilling activity during the fourth
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quarter of 2010, as we saw volumes increasing through our gathering and processing facilities. These increases through our gathering and processing facilities were somewhat slowed during the fourth quarter of 2010 as some of our producer customers experienced delays in contracting well completion services. We expect this to improving drilling environment to carry into 2011.
We have extensive gathering and processing facilities in the Granite Wash play, especially in Wheeler, Roberts and Hemphill Counties, Texas and have long-term acreage dedications from several large producers, so we are focused on improving our processing capabilities in the Texas Panhandle. The processing plants in our East Panhandle System, given the current drilling activity, have sufficient processing capacity to accommodate our customers' current needs until drilling levels increase. In order to provide additional processing capacity to our East Panhandle System, we initiated a project to refurbish the Stinnett cryogenic processing plant, located in the West Panhandle System, and relocate it to the East Panhandle System to replace the existing Arrington lean oil processing plant (the "Phoenix Plant"), resulting in additional processing capacity and improved processing economics. This project was temporarily postponed in early 2009, but in February 2010, we announced our intention to deploy the Phoenix Plant to increase efficiency and accommodate volume growth from the Granite Wash play. The Phoenix Plant began operations in October 2010 with an initial capacity of 50 MMcf/d and the ability to expand to 80 MMcf/d. In support of this project we installed a three mile pipeline to interconnect our System 97 gathering system and the new East Hemphill gathering system, as discussed below, to the new Phoenix Plant providing access to drilling activity in Wheeler and Hemphill counties in Texas and adjoining counties in Oklahoma.
On October 19, 2010, we acquired our East Hemphill system from CEFS. This acquisition provided (i) an immediate increase in gathered volumes of approximately 18.2 MMBtu/d; (ii) a significant extension of our gathering infrastructure in the area; (iii) high and low pressure gathering services to accommodate growing volumes in the Wheeler County area; and (iv) a stronger platform from which we will be able to provide our customers the flexibility to direct liquids-rich gas to one or more of our processing facilities.
In the West Panhandle, the Super Drip and Cargray condensate collection stabilization facilities receive condensate collected from various gathering systems where it is then separated from the collected water and treated. We currently stabilize approximately 2,000 barrels per day combined at our Superdrip and Cargray Stabilizers. The Cargray Stabilizer became operational in October 2010 and has increased our stabilization capacity by 2,400 barrels per day. The additional condensate stabilization capacity at Cargray also allows us to increase operating efficiencies at the Superdrip Stabilizer. Condensate stabilization lowers the product's vapor pressure, resulting in a higher value product for sale. We continue to review additional condensate stabilization projects that may provide an opportunity to handle third party condensate for a fee. We continue to review additional plant consolidation projects in order to rationalize plant processing capacity and operating costs in an area where the gas decline continues in the range of 6% to 8% per year.
During the fourth quarter of 2010, we launched our own marketing company, Eagle Rock Marketing, LLC ("Eagle Rock Marketing") which initiated a condensate marketing operation that involves developing, implementing, and launching marketing uplift strategies surrounding (i) our Upstream Segment's equity production in Alabama and (ii) our equity production in the Texas Panhandle. These plans involve several phases: marketing, operations, transportation, and venturing into third party condensate/liquids purchasing to insure the greatest possible opportunity for repeatable earnings growth. Each area has unique challenges which offer opportunities to enhance product net-back prices for our own equity production as well as third-party production.
Alabama: Our Upstream Segment owns and controls certain condensate produced in the Big Escambia Creek, Fanny Church and Flomaton fields in Escambia County, Alabama. We formed a new subsidiary in late 2010, i.e. Eagle Rock Marketing, that now operates as part of our Midstream Business. In part, this new subsidiary was formed to create alternative market outlets for the condensate produced from these Alabama fields (both by our Upstream Segment and by other working interest owners) and to take advantage of these alternative market outlets to benefit our Upstream Segment, the other working interest owners in the fields and our Midstream Business. To do this, Eagle Rock Marketing purchases product from our Upstream Segment and the other working interest owners in the fields, at an uplift to the highest price that could have been received from existing markets for the product as it exists prior to the purchase by Eagle Rock Marketing. Eagle Rock Marketing is able to pay more for the product on account of Eagle Rock Marketing's business strategy, which includes (i) blending the purchased condensate to lower the concentration of contaminants and create a new and improved condensate that is more marketable when relocated to an appropriate market and (ii) transporting the new and improved condensate to a better market location for further resale. In this regard, neither our Upstream Segment nor the other working interest owners in the fields bear any of the increased risk in blending and relocating, including the heightened risk of loss in transporting the product for blending and further resale or the market risk with respect to resale of the improved product, all of which is born by Eagle Rock Marketing within our Midstream Business. Eagle Rock Marketing launched this project in November 2010, and Eagle
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Rock Marketing has been successful, so far, in blending and relocating the product to create market optionality. As a result, Eagle Rock Marketing has enhanced the price received by our Upstream Segment and the other working interest owners in the Alabama fields, while realizing a good return for its own investment and efforts. Eagle Rock Marketing currently takes delivery of the unimproved condensate at a newly-constructed truck loading facility at our Big Escambia Creek processing plant and delivers it to a leased storage facility at Mobile, Alabama where the condensate is blended to lower the concentration of contaminants and create an improved condensate product. Thereafter, the improved product is relocated to a suitable market for resale at an improved price.
Texas Panhandle: In the Texas Panhandle many dynamics are impacting natural gas liquids and condensate prices, especially product quality and location. Eagle Rock has seen an increased price erosion given the gravity, vapor pressure and over-supply of condensate in the Granite Wash and other shale plays in Texas. Consequently, the regional markets are saturated. Eagle Rock Marketing's strategy for Texas Panhandle condensate is again an organic growth initiative. In October 2010, we installed a new stabilizer at our Cargray Plant to lower the vapor pressure of our equity and third-party condensate, thereby increasing our received price for the condensate. In addition, we are currently evaluating various storage and transportation opportunities to aggregate our product along with other third party condensate and move it to more attractive markets outside the Panhandle.
Operating Expenses. Operating expenses, including taxes other than income, for the year ended December 31, 2010 increased $3.2 million as compared to the year ended December 31, 2009. The increase was due to increased compressor rental expenses as we expanded the compressor station at our Roberts County Plant with leased units and replaced aging compressors at our Stinnett facility with more efficient leased units. In addition, the increase was also due to increased maintenance costs as we worked to improve our existing infrastructure to support our new Phoenix Plant and extraordinary mechanical breakdowns of our Goad Treater. The installation of a new 26 MMcf/d treating facility, the Goad Treater, was completed in November 2010 and replaces an older original facility. This facility removes hydrogen sulfide and carbon dioxide from the natural gas prior to delivery to interstate pipelines.
Depreciation and Amortization. Depreciation and amortization expenses for the year ended December 31, 2010 decreased $0.2 million from the year ended December 31, 2009. The major item impacting the decrease was a reduction in amortization expense due to the completion of the amortization of certain intangible assets. This decrease was offset by depreciation expense associated with the capital expenditures placed into service during the period.
Capital Expenditures. Capital expenditures for the year ended December 31, 2010 increased $22.0 million compared to the year ended December 31, 2009. The increase was primarily driven by spending related to the Phoenix Plant in 2010, including an interconnect between our System 97 gathering system and the Phoenix Plant and spending related to improvements to the Cargray Stabilizer and Goad Treater.
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East Texas/Louisiana Segment
Twelve Months Ending December 31, | |||||||
2010 | 2009 | ||||||
(Amounts in thousands, except volumes and realized prices) | |||||||
Revenues: | |||||||
Sales of natural gas, NGLs, oil and condensate | $ | 168,922 | $ | 181,550 | |||
Gathering and treating services | 35,427 | 27,968 | |||||
Total revenues | 204,349 | 209,518 | |||||
Cost of natural gas and natural gas liquids | 151,236 | 162,957 | |||||
Operating costs and expenses: | |||||||
Operations and maintenance | 17,275 | 17,985 | |||||
Depreciation and amortization | 18,452 | 17,188 | |||||
Impairment | — | 5,941 | |||||
Total operating costs and expenses | 35,727 | 41,114 | |||||
Operating income | $ | 17,386 | $ | 5,447 | |||
Capital expenditures | $ | 15,756 | $ | 18,188 | |||
Realized prices: | |||||||
Oil and condensate (per Bbl) | $ | 79.89 | $ | 63.34 | |||
Natural gas (per Mcf) | $ | 4.87 | $ | 3.83 | |||
NGLs (per Bbl) | $ | 34.68 | $ | 35.87 | |||
Production volumes: | |||||||
Gathering volumes (Mcf/d)(a) | 205,868 | 248,597 | |||||
NGLs (net equity gallons) | 18,217,505 | 19,924,820 | |||||
Condensate (net equity gallons) | 1,617,996 | 2,381,123 | |||||
Natural gas short position (MMbtu/d)(a) | 833 | 2,851 | |||||
________________________
(a) | Gathering volumes (Mcf/d) and natural gas short position (MMbtu/d) are calculated by taking the total volume and then dividing by the number of days in the respective period. |
Revenue and Cost of Natural Gas and Natural Gas Liquids. For the year ended December 31, 2010, revenues minus cost of natural gas and natural gas liquids for our East Texas/Louisiana Segment totaled $53.1 million compared to $46.6 million for the year ended December 31, 2009. During the year ended December 31, 2010 and 2009, we recorded revenues associated with deficiency payments of $10.4 million and $1.1 million, respectively, from certain of our producers. We receive deficiency payments under certain of our gathering contracts when delivered volumes fail to meet certain thresholds. These amounts are included within gathering and treating services revenue. Excluding these deficiency payments, revenues minus cost of natural gas and NGLs for the year ended December 31, 2010 and 2009 would have been $42.7 million and $45.5 million, respectively. The decrease for the year ended December 31, 2010 compared to the year ended December 31, 2009, excluding the impact of the deficiency payments, is primarily due to a decrease in gathering and equity volumes and lower NGL prices, partially offset by higher condensate and natural gas prices. In addition, during the first two months of 2009, we elected to not recover the ethane component in the natural gas stream in our plants and instead chose to leave the ethane component in the residue gas stream sold at the tailgate of our plants. We operate in this manner when the value of ethane is worth more in the gas stream than as a liquid.
Our gathering volumes on our ETML system and certain other East Texas/Louisiana systems for the year ended December 31, 2010 decreased as compared to the year ended December 31, 2009, due to natural declines in the production of the existing wells and to reduced drilling activity in lean gas formations as a result of the continued depressed natural gas price environment. Our Brookeland and associated systems have seen a modest rebound in gathered volumes beginning in the fourth quarter of 2010. During the second half of 2010, we saw an increase in drilling activity by our producer customers as NGL
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prices increased dramatically as a result of the improved demand in the United States for NGL' by the petrochemical industry. Given the improvements in horizontal drilling technology and fracturing practices, our producer customers are active in the development of the Austin Chalk play. We have an extensive gathering footprint in the Austin Chalk play and we believe we have sufficient processing capacity today to accommodate increasing liquids rich natural gas volumes. We began to see the benefit of this increased drilling activity during the fourth quarter of 2010, as we saw volumes increasing through our gathering and processing facilities. These increases were somewhat slowed as some of our producer customers encountered delays due to permitting or water production issues. We expect this improving drilling environment to carry into 2011.
Operating Expenses. Operating expenses for the year ended December 31, 2010 decreased $0.7 million compared to the year ended December 31, 2009 as a result of reduced volumes.
Depreciation and Amortization. Depreciation and amortization expenses for the year ended December 31, 2010 increased $1.3 million compared to the year ended December 31, 2009. The major items impacting the increase were (i) depreciation expense associated with the capital expenditures placed into service and (ii) an acceleration of the amortization related to certain intangibles (e.g., rights-of-ways) due to the cancellation of the ETML expansion project. These increases were offset by an adjustment of $0.9 million recorded during the three months ended June 30, 2009 to correct an overstatement of depreciation expense in a prior period.
Impairment. During the year ended December 31, 2009, we incurred impairment charges of $5.9 million of pipeline assets in our East Texas/Louisiana Segment as a result of reduced throughput volumes as our producer customers curtailed their drilling activity in response to lower natural gas prices. No impairment charges were incurred during the year ended December 31, 2010.
Capital Expenditures. Capital expenditures for the year ended December 31, 2010 decreased $2.4 million compared to the year ended December 31, 2009 due primarily to our overall lower capital spending on account of the reduced drilling activity of our producer customers.
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South Texas Segment
Twelve Months Ending December 31, | |||||||
2010 | 2009 | ||||||
(Amounts in thousands, except volumes and realized prices) | |||||||
Revenues: | |||||||
Sales of natural gas, NGLs, oil and condensate (a) | $ | 79,480 | $ | 94,691 | |||
Gathering and treating services | 3,538 | 5,608 | |||||
Other | — | 3 | |||||
Total revenues | 83,018 | 100,302 | |||||
Cost of natural gas and natural gas liquids | 73,475 | 91,916 | |||||
Operating costs and expenses: | |||||||
Operations and maintenance | 3,336 | 3,661 | |||||
Depreciation and amortization | 5,641 | 5,324 | |||||
Impairment | 29,339 | 7,733 | |||||
Total operating costs and expenses | 38,316 | 16,718 | |||||
Operating loss from continuing operations | (28,773 | ) | (8,332 | ) | |||
Discontinued operations | 77 | 290 | |||||
Operating loss | $ | (28,696 | ) | $ | (8,042 | ) | |
Capital expenditures | $ | 90 | $ | 69 | |||
Realized prices: | |||||||
Oil and condensate (per Bbl) | $ | 75.41 | $ | 50.83 | |||
Natural gas (per Mcf) | $ | 4.38 | $ | 3.76 | |||
NGLs (per Bbl) | $ | 45.91 | $ | 32.26 | |||
Production volumes: | |||||||
Gathering volumes (Mcf/d)(b) | 57,571 | 83,307 | |||||
NGLs (net equity gallons) | 1,175,767 | 1,248,783 | |||||
Condensate (net equity gallons) | 1,259,346 | 1,443,060 | |||||
Natural gas short position (MMbtu/d)(a) | 865 | 902 | |||||
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(a) | Includes sales of natural gas of $47 to the Upstream Segment for the year ended December 31, 2010. |
(b) | Gathering volumes (Mcf/d) and natural gas short position (MMbtu/d) are calculated by taking the total volume and then dividing by the number of days in the respective period. |
Revenue and Cost of Natural Gas and Natural Gas Liquids. During the year ended December 31, 2010 the South Texas Segment contributed revenues minus cost of natural gas and natural gas liquids of $9.5 million, as compared to $8.4 million for the year ended December 31, 2009. The variance of $1.1 million was positively impacted by adjustments relating to prior periods. Our South Texas Segment was negatively impacted by declining gathering volumes, offset by increased commodity prices during the year ended December 31, 2010, as compared to 2009. Our gathered volumes for the year ended December 31, 2010 decreased by 31% as compared to the year ended December 31, 2009. This decrease is due to natural declines from existing wells and to the loss of a significant producer during the third quarter of 2010. The reduction in natural gas prices throughout 2010, the low liquid content of the natural gas from the existing reservoirs that we gather and our lack of processing capabilities have negatively impacted the drilling activity around our assets in South Texas. As natural gas prices level or recover from the current levels, we expect to see improving natural gas volumes in the future. At this point we are unable to predict when we will see increasing natural gas volumes through our gathering systems in South Texas.
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Operating Expenses. Operating expenses for the year ended December 31, 2010 decreased $0.3 million as compared to the year ended December 31, 2009. The decrease was primarily as a result of operating the gathering systems at lower volumes.
Depreciation and Amortization. Depreciation and amortization expenses for the year ended December 31, 2010 as compared to the year ended December 31, 2009 increased $0.3 million.
Impairment. During the year ended December 31, 2010, we incurred impairment charges of $29.3 million in the South Texas Segment for (i) $3.1 million due to the termination of a significant gathering contract in the third quarter and (ii) $26.2 million due to an anticipated decline in volumes on our Wildhorse gathering system. During the year ended December 31, 2009, we incurred impairment charges of $7.7 million in our South Texas segment as a result of reduced throughput volumes as our producer customers curtailed their drilling activity in response to lower natural gas prices.
Capital Expenditures. Capital expenditures remained consistent for the year ended December 31, 2010 and 2009.
Discontinued Operations. On April 1, 2009, we sold our producer services line of business, and thus have retrospectively classified the revenues minus the cost of natural gas and natural gas liquids as discontinued operations. During the year ended December 31, 2010, this business generated revenues of $0.1 million, as compared to revenues of $19.2 million and cost of natural gas and natural gas liquids of $18.9 million during the year ended December 31, 2009.
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Gulf of Mexico Segment
Twelve Months Ending December 31, | |||||||
2010 | 2009 | ||||||
(Amounts in thousands, except volumes and realized prices) | |||||||
Revenues: | |||||||
Sales of natural gas, NGLs, oil and condensate | $ | 31,925 | $ | 31,161 | |||
Gathering and treating services | 1,029 | 864 | |||||
Other | — | 1,616 | |||||
Total revenues | 32,954 | 33,641 | |||||
Cost of natural gas and natural gas liquids | 28,028 | 26,372 | |||||
Operating costs and expenses: | |||||||
Operations and maintenance | 1,771 | 1,907 | |||||
Depreciation and amortization | 6,838 | 6,576 | |||||
Total operating costs and expenses | 8,609 | 8,483 | |||||
Operating loss | $ | (3,683 | ) | $ | (1,214 | ) | |
Capital Expenditures | $ | 180 | $ | 358 | |||
Realized average prices: | |||||||
NGLs (per Bbl) | $ | 46.00 | $ | 35.52 | |||
Production volumes: | |||||||
Gathering volumes (Mcf/d)(a) | 103,846 | 116,492 | |||||
NGLs and condensate (net equity gallons) | 4,398,467 | 5,768,018 | |||||
________________________
(a) | Gathering volumes (Mcf/d) are calculated by taking the total volume and then dividing by the number of days in the respective period. |
Revenues and Cost of Natural Gas and Natural Gas Liquids. During the year ended December 31, 2010, the Gulf of Mexico Segment contributed $4.9 million in revenues minus cost of natural gas and natural gas liquids compared to $7.3 million in the year ended December 31, 2009. During the year ended December 31, 2009, we recorded other revenue of approximately $1.6 million from business interruption insurance related to damages caused by Hurricanes Gustav and Ike. Excluding this other revenue, revenues minus cost of natural gas and NGLs would have been $5.7 million for the year ended December 31, 2009. The decrease, exclusive of the business interruption insurance recovery, can be attributed to a reduction in gathering volumes offset by higher NGL prices during the year ended December 31, 2010, as compared to the year ended December 31, 2009. The reduction in volumes is due to natural declines in the underlying existing wells, reduced drilling activity during 2010 and 2009, on account of workovers and new shallow water drilling being generally reduced due to permitting delays by the federal government, and an adjustment downward in our ownership percentage at the North Terrebonne Plant. Our ownership percentage in North Terrebonne and Yscloskey adjusts up or down annually based upon our volume of gas from committed leases as compared to the total volumes of gas from all plant owners committed leases. Our ownership in Yscloskey decreased from 13.78% to 11.45% in 2010. Our ownership in North Terrebonne Plant decreased to 1.67% in 2010 from 5.16% for 2009 but increased in January 2011 to 2.63%.
Operating Expenses. Operating expenses for the year ended December 31, 2010 compared to the year ended December 31, 2009 decreased $0.1 million.
Depreciation and Amortization. Depreciation and amortization expenses for in the year ended December 31, 2010 compared to the year ended December 31, 2009 increased $0.3 million.
Capital Expenditures. Capital expenditures for the year ended December 31, 2010 for the Gulf of Mexico Segment compared to the year ended December 31, 2009 decreased $0.2 million.
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Upstream Segment
Twelve Months Ending December 31, | |||||||
2010 | 2009 | ||||||
(Amounts in thousands, except volumes and realized prices) | |||||||
Revenues: | |||||||
Oil and condensate (a) (b) | $ | 50,507 | $ | 35,316 | |||
Natural gas (c) | 15,027 | 12,021 | |||||
NGLs (d) | 19,973 | 16,057 | |||||
Sulfur (e) | 6,793 | — | |||||
Other | 2,435 | 239 | |||||
Total revenues | 94,735 | 63,633 | |||||
Operating Costs and expenses: | |||||||
Operations and maintenance (f) | 32,042 | 26,336 | |||||
Sulfur disposal costs | 729 | 2,200 | |||||
Other operating income | — | (3,552 | ) | ||||
Depletion, depreciation and amortization | 30,424 | 34,009 | |||||
Impairment | 3,536 | 8,114 | |||||
Total operating costs and expenses | 66,731 | 67,107 | |||||
Operating income (loss) | $ | 28,004 | $ | (3,474 | ) | ||
Capital expenditures | $ | 26,772 | $ | 8,437 | |||
Realized average prices (h): | |||||||
Oil and condensate (per Bbl) | $ | 62.35 | $ | 45.30 | |||
Natural gas (per Mcf) | $ | 4.43 | $ | 3.69 | |||
NGLs (per Bbl) | $ | 47.00 | $ | 31.90 | |||
Sulfur (per Long ton) (g) | $ | 88.36 | — | ||||
Production volumes: | |||||||
Oil and condensate (Bbl) | 808,077 | 811,075 | |||||
Natural gas (Mcf) | 3,514,078 | 3,659,431 | |||||
NGLs (Bbl) | 437,375 | 504,669 | |||||
Total (Mcfe) | 10,986,790 | 11,553,895 | |||||
Sulfur (Long ton) (g) | 84,065 | 119,812 | |||||
________________________
(a) | Includes sales of oil and condensate to the Texas Panhandle Segment of $6,063 for the year ended December 31, 2010. |
(b) | Revenues include a change in the value of product imbalances by $(102) and $(260) for the year ended December 31, 2010 and 2009, respectively. |
(c) | Revenues include a change in the value of product imbalances by $430 and $(1,273) for the year ended December 31, 2010 and 2009, respectively. |
(d) | Revenues include a change in the value of product imbalances by $370 and $28 for the year ended December 31, 2010 and 2009, respectively. |
(e) | Revenues include a change in the value of product imbalances by $48 for year ended December 31, 2010. |
(f) | Includes purchases of natural gas of $47 from the South Texas Segment for the year ended December 31, 2010. |
(g) | During year ended December 31, 2010, an adjustment was made to decrease sulfur volumes by 5,230 long tons related to a prior period. This adjustment is excluded from the calculation of realized prices. |
(h) | Calculation does not include impact of product imbalances. In addition, volumes and realized price for the year ended December 31, 2009 and the three months ended March 31, 2010 have been revised from prior period reported amounts due to a reallocation of historical production results based on more accurate well tests of our Alabama properties. |
Revenue. For the year ended December 31, 2010, Upstream Segment revenues increased by $31.1 million, as compared to the year ended December 31, 2009. The increase in revenue was due to higher realized prices for oil, natural gas, NGLs and sulfur during year ended December 31, 2010 compared to the year ended December 31, 2009. This increase was partially offset by the shut-in of our East Texas production beginning August 11, 2010 (see further discussion of the shut-in
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below) and the turnarounds at our Big Escambia Creek and Flomaton facilities during the year ended December 31, 2010, as discussed below.
During late April and early May 2010, we completed a scheduled turnaround (i.e., a complete shutdown of the facility to perform certain standard plant repairs and routine inspections of equipment) of our Big Escambia Creek facility in Southern Alabama. During the plant turnaround, all wells in the Big Escambia Creek field were shut-in. The duration of both the plant turnaround and the well shut-in was approximately 12 days. The negative impact to our production during this period was a loss of approximately 48 MMcf of residue gas, 14 MBbls of oil, 8.7 MBbls of plant liquids and 2,000 long tons of sulfur. The
revenue impact of the loss in production was approximately $1.8 million during the year ended December 31, 2010. In addition, during the year ended December 31, 2010, we completed a reallocation of historical production results based on more accurate tests and product analyses for our Big Escambia Creek wells for the period from August 2007 through March 2010. As a result of this reallocation of historical production, our revenues for the year ended December 31, 2010 were negatively impacted by $1.3 million.
In August 2010, we announced that our East Texas oil and natural gas production was temporarily shut-in due to an unscheduled shutdown of the Eustace processing facility owned and operated by a third-party. The shutdown involved replacing all of the tubes in the reaction furnace's waste heat recovery unit, replacing the catalyst in the sulfur recovery unit and other equipment repairs. The operator originally estimated that the shutdown would take 30 to 45 days to complete. Subsequently, we were informed by the operator that more extensive repairs would be required and that the shutdown would last through mid-November of 2010. This estimate was later revised to late December 2010 and again to late-February 2011. As of March 10, 2011, the third-party operator was in the process of returning the facility to service. We estimate that the shut-in negatively impacted our 2010 net revenues by approximately $7.1 million (excluding recoveries) and assuming the latest estimate holds, we expect that our 2011 net revenues will be negatively impacted by approximately $3.4 million (excluding potential recoveries). We maintain business interruption insurance and are pursuing recovery of the lost net revenue above our 30-day deductible. As of December 31, 2010, we have recognized $3.0 million related to our business interruption insurance claim in other revenue. The maximum recovery under our business interruption insurance policy for this named facility is $5.0 million for each claimed event.
During the year ended December 31, 2010, sulfur revenue was $6.8 million. During the year ended December 31, 2009, however, sulfur prices were sufficiently low that we experienced costs to dispose of sulfur which exceeded their sales revenues by $2.2 million. In addition, during the year ended December 31, 2010, we recorded sulfur disposal costs of $0.7 million to adjust for a shortfall in a prior period accrual of sulfur disposal costs. Historically, sulfur was viewed as a low value byproduct in the production of oil and natural gas. During the year ended December 31, 2010, we saw a recovery in sulfur prices, with prices ranging from $90 per long ton on February 10, 2010 to $185 per long ton on February 12, 2011 at the Tampa, Florida market. Our net realized price will always be lower than the price set at the Tampa, Florida hub due to transportation and marketing deductions and charges. These charges vary depending on the distance our product is produced from the Tampa, Florida market.
Operating Expenses. Operating expenses, including severance and ad valorem taxes, increased by $5.7 million for the year ended December 31, 2010, as compared to the year ended December 31, 2009. The increase in operating expense for the year ended December 31, 2010, as compared to the same period in the prior year can be attributed increased well workovers in our Alabama operations and to $2.3 million of expenses related to the turnarounds at our facilities at Big Escambia Creek and Flomaton, as discussed above. In addition, during the year ended December 31, 2010, we recorded a reversal of $0.6 million of operating costs due to the reallocation of historical production for our Big Escambia Creek wells, as discussed above. During the year ended December 31, 2009, operating expenses were reduced due to the reversal of $1.6 million of environmental reserves determined to no longer be necessary and receipt of a $0.7 million credit for overbillings related to a non-operated asset. Also, during the year ended December 31, 2010, our severance taxes increased due to (i) the increase in revenue from the same periods in the prior year and (ii) additional severance taxes as a result of the reallocation of historical production discussed above. This increase for the year ended December 31, 2010 was offset by a refund of severance taxes from the state of Alabama for overpayment in prior periods.
Depletion, Depreciation and Amortization. Depletion, depreciation and amortization expense decreased by $3.6 million for the year ended December 31, 2010, as compared to the same period in the prior year. The decrease for the year ended December 31, 2010, as compared to the comparable period in 2009 is due to decreases in production as a result of our East Texas wells being shut-in, as discussed above.
Other Operating Income. Other operating income for the year ended December 31, 2009, includes the recovery of $2.2 million of assets previously written off and the release of $1.4 million of liabilities assumed as part of our purchase price allocation for our acquisitions of Escambia Asset Co. LLC and Redman Energy Holdings, L.P. During the period, we received
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additional information about collectability of the referenced assets which enabled us to recover on them and we determined that we no longer had any obligation under the referenced liabilities which enabled us to release them.
Impairment. Impairment charges of $3.5 million incurred during the year ended December 31, 2010 of which (i) $3.4 million related to certain fields in our unproved properties we determined it would not be technologically feasible to develop these unproved locations and (ii) $0.1 million related to proved properties due to adjustments to our reserves. During the year ended December 31, 2009, we incurred impairment charges of $8.1 million of which (i) $7.9 million was a result of a decline in natural gas prices, production declines and lower natural gas liquids yields at our Flomaton field and (ii) $0.2 million in other fields due to lower natural gas prices.
Capital Expenditures. Capital expenditures increased by $18.3 million for the year ended December 31, 2010, as compared to the year ended December 31, 2009. The increase in capital expenditures is due to drilling activity in our Permian and Alabama operations, recompletions in our Jourdanton and Edgewood fields, leasing in our Edgewood and Flomaton fields, and the acquisition of compression equipment for the turnaround at our Big Escambia Creek facility, as discussed above. The two new compressors will provide improved reliability and backup for the existing residue gas and plant inlet compression. The new backup compression was placed in service in November 2010. During the year ended December 31, 2010, we drilled and completed five wells in our Permian operations. During the three months ended September 30, 2010 we drilled and plugged a dry hole in our Permian operations. As of December 31, 2010, we were in the process of drilling one additional well in our Big Escambia Creek field.
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Corporate and Other Segment
Twelve Months Ending December 31, | |||||||
2010 | 2009 | ||||||
($ in thousands) | |||||||
Revenues: | |||||||
Realized commodity derivatives (losses) gains | $ | (17,010 | ) | $ | 83,300 | ||
Unrealized commodity derivatives gains (losses) | 8,224 | (189,590 | ) | ||||
Intersegment elimination - Sales of natural gas, oil and condensate | (6,110 | ) | — | ||||
Total revenues | (14,896 | ) | (106,290 | ) | |||
Intersegment elimination - Cost of oil and condensate | (5,587 | ) | — | ||||
General and administrative | 45,775 | 45,819 | |||||
Intersegment elimination - Operations and maintenance | (47 | ) | — | ||||
Depreciation and amortization | 1,550 | 1,073 | |||||
Operating loss | (56,587 | ) | (153,182 | ) | |||
Other income (expense): | |||||||
Interest income | 111 | 187 | |||||
Other income | 501 | 934 | |||||
Interest expense | (15,147 | ) | (21,591 | ) | |||
Unrealized interest rate derivative (losses) gains | (7,164 | ) | 12,529 | ||||
Realized interest rate derivative losses | (19,971 | ) | (18,876 | ) | |||
Other expense | (51 | ) | (1,070 | ) | |||
Total other income (expense) | (41,721 | ) | (27,887 | ) | |||
Loss from continuing operations before taxes | (98,308 | ) | (181,069 | ) | |||
Income tax (benefit) provision | (2,545 | ) | 1,022 | ||||
Loss from continuing operations | (95,763 | ) | (182,091 | ) | |||
Discontinued operations, net of tax | 43,130 | 9,107 | |||||
Segment loss | $ | (52,633 | ) | $ | (172,984 | ) | |
Revenue. Our Corporate and Other Segment's revenue consists of our intersegment eliminations, see further discussion below, and our commodity derivatives activity. Our commodity hedging activities impact our Corporate segment revenues through (i) the unrealized, non-cash, mark-to-market of our commodity derivatives scheduled to settle in future periods; and (ii) the realized gains or losses on our commodity derivatives settled in the indicated period. Our unrealized commodity gains and losses reflect (i) the change in the mark-to-market value of our derivative position from the beginning of a period to the end and (ii) the amortization of put premiums and other derivative costs. In general, the change in the mark-to-market value of our derivative position may be due to several factors including the settlement of derivative instruments during the period, the addition of new derivative positions during the period, changes in the forward curves of the underlying commodities from the beginning to the end of the period, changes in interest rates used in the mark to market calculations from the beginning to the end of the period, and the passage of time during the period.
During the year ended December 31, 2010, we experienced an unrealized gain on our commodity derivative portfolio due the difference in value between the contracts that settled and the new contracts added to our portfolio and decreases in the natural gas forward curve, offset by increases in the crude oil and natural gas liquids forward curves. This compares to the year ended December 31, 2009 during which we experienced an unrealized loss on our commodity derivative portfolio due to increases in the crude oil and natural gas liquids forward curves, partially offset by a decline in the natural gas forward curve. Included with our unrealized commodity derivative gains (losses) are the amortization of put premiums and other derivative costs, including the costs of hedge resets, of $4.0 million and $48.4 million for the years ended December 31, 2010 and 2009, respectively. The unrealized commodity derivative gains (losses), including the amortization of put premiums and other derivative costs, for the years ended December 31, 2010 and 2009, had no impact on cash activities for those periods and are excluded from our calculation of Adjusted EBITDA.
We recognized realized commodity derivative losses during the year ended December 31, 2010, as compared to realized commodity gains for the year ended December 31, 2009, primarily due to lower strike prices on our derivatives that
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settled during the year ended December 31, 2010 as a result of our hedging strategy in which we entered into hedges with strike prices above market during the year ended December 31, 2009, in addition to higher index prices for crude and NGLs in the year ended December 31, 2010 as compared to the year ended December 31, 2009.
Given the uncertainty surrounding future commodity prices, and the general inability to predict future commodity prices as they relate to the strike prices at which we have hedged our exposure, it is difficult to predict the magnitude and impact that marking our hedges to market will have on our income from operations in future periods.
Intersegment Eliminations. During the year ended December 31, 2010, our South Texas Segment within our Midstream Business began selling natural gas to our Upstream Segment to be used as fuel, and our Upstream Segment began selling oil and condensate to the marketing group within our Midstream Business for resale. We have included the eliminations of these transactions within our Corporate Segment.
General and Administrative Expenses. General and administrative expenses decreased by less than $0.1 million for the year ended December 31, 2010 as compared to the same period in 2009. During the year ended December 31, 2010, our salary and benefit expense, excluding equity based compensation, increased by $3.5 million. This increase was primarily the result of increased headcount in accounting, back-office, engineering, land and operations-related corporate personnel and due to increased health insurance costs. This increase was offset by a decrease in equity-based compensation expense of approximately $1.3 million during the year ended December 31, 2010, as compared to the year ended December 31 2009. This decrease was primarily the result of natural run-off (through vesting) of restricted common units granted in prior periods at higher prices. In addition, equity based compensation during the years ended December 31, 2010 and 2009 included an allocation of expense of $0.1 million and $0.4 million, respectively, from Holdings on account of Holdings' issuance of incentive interests to certain of our executives. The increase in overall compensation and benefit was partially offset by a reduction of our allowance for bad debts. Also, due to the increase in headcount, we were able to reduce our contract labor and other professional services expenses by approximately $1.3 million during the year ended December 31, 2010, as compared to the year ended December 31, 2009. In addition, included within our general and administrative expenses for the year ended December 31, 2010 and 2009 are non-capitalizable legal and other professional advisory fees of $2.1 million and $0.7 million, respectively, related to the Recapitalization and Related Transactions and the related lawsuit.
At the present time, we do not allocate our general and administrative expenses cost to our operational segments. The Corporate Segment bears the entire amount.
Total Other Expense. Total other expense primarily consists of both realized and unrealized gains and losses from our interest rate swaps and interest expense related to our senior secured credit facility. During 2010, our realized settlements decreased by about $1.1 million, as compared to 2009, as a result of lower LIBOR rates in 2010. For the year ended December 31, 2010, we recognized an unrealized loss of $7.2 million, as compared to an unrealized gain of $12.5 million during the same period in 2009, as a result of a decrease to the forward interest rate curves. These unrealized mark-to-market losses did not have any impact on cash activities for the period, and are excluded by definition from our calculation of Adjusted EBITDA.
Interest expense decreased by $6.4 million during the year ended December 31, 2010, as compared to the same period in the prior year. Interest expense is shown before the impact of our interest rate derivatives, which convert a portion of our outstanding debt from variable-rate interest obligations to fixed-rate interest obligations. All of our outstanding debt consists of borrowings under our revolving credit facility, which bears interest primarily based on a LIBOR rate plus the applicable margin. The decrease in interest expense is due to lower LIBOR rates during 2010, as compared to the same period in 2009, and lower outstanding debt balances as a result of our efforts to pay down debt over the past 21 months.
Income Tax (Benefit) Provision. Income tax provision for the 2010 and 2009 relates to (i) state taxes due by us and (ii) federal taxes due by Eagle Rock Energy Acquisition Co., Inc. (acquiring entity of certain entities acquired in the acquisition of Redman Energy Corporation “Redman Acquisition” in 2008) and Eagle Rock Energy Acquisition Co. II, Inc. (acquiring entity of certain entities acquired in the Stanolind Acquisition) and their wholly-owned corporations, Eagle Rock Upstream Development Company, Inc. (successor entity to certain entities acquired in the Redman acquisition) and Eagle Rock Upstream Development Company II, Inc. (successor entity to certain entities acquired in the Stanolind acquisition), which are subject to federal income taxes (the “C Corporations”). During 2010, our tax provision decreased by $3.6 million as compared to the same periods in the prior year, primarily due to the reduction of the deferred tax liabilities created by the book/tax differences as a result of the federal income taxes associated with the Redman and Stanolind Acquisitions, receipt of state tax refunds and true-ups related to our prior year provision. For further discussion of our income tax (benefit) provision, see Note 15 to our consolidated financial statements included in Part II, Item 8. Financial Statements and Supplementary Data staring on page F-1 of this Annual Report.
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Discontinued Operations. On May 24, 2010, we completed the sale of our Minerals Business. We recorded a gain of $37.7 million on the sale, which is recorded as part of discontinued operations for the year ended December 31, 2010. Further upward or downward adjustments to the purchase price may occur post-closing to reflect customary true-ups. Subsequent to the sale, we received payments of $0.3 million related to pre-effective date operations and have recorded this amount as part of discontinued operations for the period. For the year ended December 31, 2010, we generated revenues of $8.9 million and income from operations of $5.5 million. For the year ended December 31, 2009, we generated revenues of $15.7 million and income from operations of $7.8 million. During the years ended December 31, 2010 and 2009, the Partnership incurred state tax expense on discontinued operations of $0.4 million and $0.2 million, respectively. During the years ended December 31, 2010 and 2009, we recorded income to discontinued operations, excluding the gain recognized by us on the sale of the Minerals Business, of $5.5 million and $9.1 million, respectively.
Adjusted EBITDA
Adjusted EBITDA, as defined under Part II, Item 6. Selected Financial Data - Non-GAAP Financial Measures, decreased by $45.8 million from $174.5 million for the year ended December 31, 2009 to $128.7 million for the year ended December 31, 2010.
As described above, revenues minus cost of natural gas and natural gas liquids for the Midstream Business (including the Texas Panhandle, East Texas/Louisiana, South Texas and Gulf of Mexico Segments) increased by $33.6 million during the year ended December 31, 2010, as compared to the comparable period in 2009. The Upstream Segment revenues increased $28.9 million during the year ended December 31, 2010, as compared to the comparable period in 2009. Intersegment eliminations revenues minus cost of natural gas and natural gas liquids resulted in a $0.5 million decrease. Our Corporate Segment's realized commodity derivatives gain decreased by $100.3 million during the year ended December 31, 2010 as compared to the comparable period in 2009. This resulted in total incremental revenues minus cost of natural gas and natural gas liquids decreasing by $38.4 million during the year ended December 31, 2010 as compared to the comparable period in 2009. The incremental revenue amounts are adjusted to exclude the impact of unrealized commodity derivatives, which includes the amortization of put premiums and other derivative costs, and the non-cash mark-to-market Upstream Segment imbalances, none of which are included in the calculation of Adjusted EBITDA.
Operating expenses (including taxes other than income) for our Midstream Business increased by $2.0 million for the year ended December 31, 2010, as compared to the same period in 2009, while Operating Expenses (including taxes other than income) for the Upstream Segment increased $4.2 million for the year ended December 31, 2010, as compared to the comparable period in 2009.
General and administrative expense, excluding the impact of non-cash compensation charges related to our long-term incentive program, Holding's Tier I incentive units and other non-recurring items and captured within our Corporate Segment, increased during the year ended December 31, 2010 by $1.2 million, as compared to the respective period in 2009.
As a result, revenues (excluding the impact of unrealized commodity derivative activity) minus cost of natural gas and natural gas liquids for the year ended December 31, 2010, as compared to the same period in 2009 decreased by $38.4 million, operating expenses increased by $6.2 million and general and administrative expenses increased by $1.2 million. The decreases in revenues minus the cost of natural gas and natural gas liquids, the decreases in operating costs offset by the increase in general and administrative expenses resulted in a decrease to Adjusted EBITDA during the year ended December 31, 2010, as compared to the year ended December 31, 2009. Adjusted EBITDA excludes amortization of commodity hedge costs (including costs of hedge reset transactions) for the years ended December 31, 2010 and 2009 of $4.0 million and $48.4 million, respectively. Including these amortization costs, our Adjusted EBITDA for the years ended December 31, 2010 and 2009 would have been $124.8 million and $126.2 million, respectively.
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Year Ended December 31, 2009 Compared with Year Ended December 31, 2008
Summary of Consolidated Operating Results
Below is a table of a summary of our consolidated operating results for the years ended December 31, 2009 and December 31, 2008. Operating results for our individual operating segments are presented in tables in this Item 7.
Year Ended December 31, | |||||||
2009 | 2008 | ||||||
($ in thousands) | |||||||
Revenues: | |||||||
Sales of natural gas, NGLs, oil, condensate and sulfur | $ | 653,712 | $ | 1,233,919 | |||
Gathering, compression, processing and treating fees | 45,476 | 38,871 | |||||
Realized commodity derivative gains (losses) | 83,300 | (46,059 | ) | ||||
Unrealized commodity derivative gains (losses) | (189,590 | ) | 207,824 | ||||
Other | 1,858 | 716 | |||||
Total revenues | 594,756 | 1,435,271 | |||||
Cost of natural gas and natural gas liquids | 488,230 | 891,433 | |||||
Costs and expenses: | |||||||
Operating and maintenance | 73,196 | 73,620 | |||||
Taxes and other income | 10,766 | 18,228 | |||||
General and administrative | 45,819 | 45,618 | |||||
Other operating (income) expense | (3,552 | ) | 10,699 | ||||
Depreciation, depletion and amortization | 110,255 | 108,980 | |||||
Impairment expense | 21,788 | 142,116 | |||||
Goodwill impairment expense | — | 30,994 | |||||
Total costs and expenses | 258,272 | 430,255 | |||||
Total operating income (loss) | (151,746 | ) | 113,583 | ||||
Other income (expense): | |||||||
Interest income | 187 | 771 | |||||
Other income | 934 | 1,318 | |||||
Interest expense | (21,591 | ) | (32,884 | ) | |||
Unrealized interest rate derivatives (gains) losses | 12,529 | (27,717 | ) | ||||
Realized interest rate derivative losses | (18,876 | ) | (5,214 | ) | |||
Other expense | (1,070 | ) | (955 | ) | |||
Total other income (expense) | (27,887 | ) | (64,681 | ) | |||
Income (loss) from continuing operations before income taxes | (179,633 | ) | 48,902 | ||||
Income tax (benefit) provision | 1,022 | (1,449 | ) | ||||
Income (loss) from continuing operations | (180,655 | ) | 50,351 | ||||
Discontinued operations, net of tax | 9,397 | 37,169 | |||||
Net income (loss) | $ | (171,258 | ) | $ | 87,520 | ||
Adjusted EBITDA(a) | $ | 174,525 | $ | 206,965 | |||
__________________________
(a) | See Part II, Item 6. Selected Financial Data – Non-GAAP Financial Measures for a definition and reconciliation to GAAP. |
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Midstream Business (Four Segments)
Texas Panhandle Segment
Twelve Months Ending December 31, | |||||||
2009 | 2008 | ||||||
(Amounts in thousands, except volumes and realized prices) | |||||||
Revenues: | |||||||
Sales of natural gas, NGLs, oil and condensate | $ | 282,916 | $ | 592,997 | |||
Gathering and treating services | 11,036 | 10,069 | |||||
Total revenues | 293,952 | 603,066 | |||||
Cost of natural gas and natural gas liquids | 206,985 | 459,064 | |||||
Operating costs and expenses: | |||||||
Operations and maintenance | 31,873 | 34,269 | |||||
Depreciation and amortization | 46,085 | 43,688 | |||||
Total operating costs and expenses | 77,958 | 77,957 | |||||
Operating income | $ | 9,009 | $ | 66,045 | |||
Capital expenditures | $ | 7,293 | $ | 30,738 | |||
Realized prices: | |||||||
Oil and condensate (per Bbl) | $ | 60.14 | $ | 94.27 | |||
Natural gas (per Mcf) | $ | 3.23 | $ | 7.44 | |||
NGLs (per Bbl) | $ | 33.45 | $ | 58.34 | |||
Production volumes: | |||||||
Gathering volumes (Mcf/d)(a) | 138,450 | 151,964 | |||||
NGLs and condensate (net equity gallons) | 46,376,433 | 51,351,966 | |||||
Condensate (net equity gallons) | 35,292,388 | 35,162,578 | |||||
Natural gas short position (MMbtu/d)(a) | (6,010 | ) | (5,607 | ) | |||
________________________
(a) | Gathering volumes (Mcf/d) and natural gas short position (MMbtu/d) are calculated by taking the total volume and then dividing by the number of days in the respective period. |
Revenue and Cost of Natural Gas and Natural Gas Liquids. For the year ended December 31, 2009, the revenues minus cost of natural gas and natural gas liquids for our Texas Panhandle Segment operations totaled $87.0 million compared to $144.0 million for the year ended December 31, 2008. There were two primary contributors to this decrease: (i) lower NGL and condensate pricing, as compared to pricing in 2008, and (ii) lower NGL equity production as compared to production in 2008. The lower NGL equity production was primarily due to approximately 9% lower gathered volumes in 2009 as compared to 2008 and due to operating certain plants in ethane rejection mode for much of the first two months of 2009. Ethane rejection operations occur when we elect to not recover the ethane component in the natural gas stream in our plants and instead choose to leave the ethane component in the residue gas stream sold at the tailgates of our plants. Ethane rejection operations result in a lower volume of equity NGLs with a correspondingly smaller natural gas short position. We operate in this manner when the value of ethane is worth more in the gas stream than as a separate product.
The lower gathering volumes during the twelve months ended December 31, 2009 compared to the same period in the prior year were due to natural declines in the underlying existing wells in addition to reduced drilling activity during 2009. The dramatic fall in commodity prices experienced in the latter part of 2008 and continuing throughout into 2009 has resulted in many of our producer customers significantly reducing drilling activity in the Texas Panhandle, presumably not to be resumed
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until commodity prices rise to levels which justify drilling. While oil prices have recovered from the lows seen in the three months ended March 31, 2009, natural gas prices have improved during the fourth quarter of 2009; however, not to levels that have caused our producers to increase drilling activity back to the 2008 levels.
Our Texas Panhandle Segment primarily covers ten counties in Texas and consists of our East Panhandle System and our West Panhandle System. The drilling activity in the West Panhandle System is not sufficient to offset the natural declines experienced on this system. While our contract mix in the West Panhandle System provides us with a higher equity share of the production, the overall decline will continue and we expect to recover smaller equity production in the future on the West Panhandle System.
The East Panhandle System experienced growth in volumes and equity production due to the active Granite Wash drilling play located in Roberts, Hemphill and Wheeler Counties, Texas through much of 2008; however, due to lower commodity values during the fourth quarter of 2008 continuing through the twelve months of 2009, we experienced a significant decline in drilling activity in this area.
Recent drilling by the largest operators in the Granite Wash play, utilizing horizontal drilling technologies, has resulted in initial natural gas production rates of 6 MMcf/d. These operators believe the economics of the Granite Wash play will be significantly enhanced due to the fewer number of wells and lower capital required to develop the same amount of acreage versus conventional vertical drilling results. We have extensive gathering and processing facilities in Roberts and Hemphill Counties, Texas and long term acreage dedications from several of the larger producers. We believe the Partnership will benefit in the future due to the application of this technology in the Granite Wash play with increased natural gas and condensate production in the East Panhandle System.
The liquids content of the natural gas is lower in the East Texas Panhandle System and our contract mix provides us with a smaller share of equity production as compared to the West Panhandle System. At the current lower drilling activity in the East Panhandle System we would be unable to offset the continued decline on the West Panhandle System of NGL and condensate equity gallons. Our current goal is to aggressively contract for new volumes in the East Panhandle System to offset the decline in volumes and our share of equity production in the West Panhandle System.
Operating Expenses. Operating expenses, including taxes other than income, for the year ended December 31, 2009 were $31.9 million compared to $34.3 million for the year ended December 31, 2008. The major items impacting the $2.4 million decrease in operating expenses for the year ended December 31, 2009 were primarily due to overall cost reduction initiatives implemented by the Partnership across the segment.
Depreciation and Amortization. Depreciation and amortization expenses for the year ended December 31, 2009 were $46.1 million compared to $43.7 million for the year ended December 31, 2008. The major item impacting the $2.4 million increase was depreciation expense associated with the capital expenditures placed into service during the period.
Capital Expenditures. Capital expenditures for the year ended December 31, 2009 were $7.3 million as compared to $30.7 million for the year ended December 31, 2008. We classify capital expenditures as either maintenance capital (which represents routine well connects and capitalized maintenance activities) or as growth capital (which represents organic growth projects). In the year ended December 31, 2009, growth capital represented 39% of our capital expenditures as compared to 70%, respectively, in the year ended December 31, 2008. The decrease in capital expenditures of $23.4 million was driven by reduced maintenance capital associated with fewer new well connects due to the lower drilling activity and by less growth capital due to expenditures related to our Stinnett - Cargray plant consolidation project having occurred in the year ended December 31, 2008.
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East Texas/Louisiana Segment
Twelve Months Ending December 31, | |||||||
2009 | 2008(b) | ||||||
(Amounts in thousands, except volumes and realized prices) | |||||||
Revenues: | |||||||
Sales of natural gas, NGLs, oil and condensate | $ | 181,550 | $ | 298,720 | |||
Gathering and treating services | 27,968 | 23,320 | |||||
Total revenues | 209,518 | 322,040 | |||||
Cost of natural gas and natural gas liquids | 162,957 | 269,030 | |||||
Operating costs and expenses: | |||||||
Operations and maintenance | 17,985 | 16,569 | |||||
Depreciation and amortization | 17,188 | 13,559 | |||||
Impairment | 5,941 | 26,994 | |||||
Total operating costs and expenses | 41,114 | 57,122 | |||||
Operating (loss) income | $ | 5,447 | $ | (4,112 | ) | ||
Capital expenditures | $ | 18,188 | $ | 17,391 | |||
Realized prices: | |||||||
Oil and condensate (per Bbl) | $ | 63.34 | $ | 101.62 | |||
Natural gas (per Mcf) | $ | 3.83 | $ | 8.75 | |||
NGLs (per Bbl) | $ | 35.87 | $ | 54.66 | |||
Production volumes: | |||||||
Gathering volumes (Mcf/d)(a) | 248,597 | 198,365 | |||||
NGLs and condensate (net equity gallons) | 19,924,820 | 27,038,450 | |||||
Condensate (net equity gallons) | 2,381,123 | 1,580,928 | |||||
Natural gas short position (MMbtu/d)(a) | 2,851 | 1,427 | |||||
________________________
(a) | Gathering volumes (Mcf/d) and natural gas short position (MMbtu/d) are calculated by taking the total volume and then dividing by the number of days in the respective period. |
(b) | Includes operations related to the Millennium Acquisition starting on October 1, 2008. |
Revenue and Cost of Natural Gas and Natural Gas Liquids. For the year ended December 31, 2009, revenues minus cost of natural gas and natural gas liquids for our East Texas/Louisiana Segment totaled $46.6 million compared to $53.0 million for the year ended December 31, 2008.
In October 1, 2008, we acquired Millennium Midstream Partners, L.P. (the "Millennium Acquisition"). With this acquisition, we acquired a natural gas gathering and processing business, with assets located in East, Central and West Texas and South Louisiana. The Millennium Acquisition positively impacted the East Texas/Louisiana Segment's revenue minus cost of natural gas and natural gas liquids by $15.3 million during the year ended December 31, 2009. Our lower NGL equity gallons for 2009 were primarily due to operating the facilities in ethane rejection mode during much of the first two months of 2009. Ethane rejection mode is when we elect to not recover the ethane component in the natural gas stream in our plants and instead choose to leave the ethane component in the residue gas stream sold at the tailgates of our plants. We operate in this manner when the value of ethane is worth more in the gas stream than as a separate product.
We were negatively impacted by lower NGL and condensate pricing during 2009 as compared to 2008. We were positively impacted by 38% growth in gathering volume during 2009 compared to 2008 due to the Millennium Acquisition. Other East Texas/Louisiana Segment gathering systems realized a reduction in volumes. Excluding the Millennium Acquisition, our gathering volumes decreased by 11%. The offsetting reduction in higher margin gas volumes is being replaced with lower
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margin, fixed fee volumes from the Millennium Acquisition. The gas volumes from the Millennium Acquisition are comprised primarily of dry gas that does not require processing to remove NGLs prior to delivery to the interstate pipelines in order to meet the pipelines' gas quality tariff requirements. The lower margin gas, though contributing to a significant increase in overall gathered volumes, has not offset the lower revenues and margins due to the lower NGL, condensate and natural gas prices during 2009 as compared to the same time period in 2008. During the last three months of 2008 and continuing into 2009, we saw a significant reduction in our customer's drilling activity due to lower commodity values.
During the month of September 2009, two producers curtailed their gas production due to low natural gas prices by a total of approximately 17,500 Mcf/d for the month delivered to the Brookeland Plant and Tyler County gathering system. As of December 31, 2009, no production remains curtailed due to natural gas prices.
Operating Expenses. Operating expenses for the year ended December 31, 2009 were $18.0 million compared to $16.6 million for the year ended December 31, 2008. The major item impacting the $1.4 million increase in operating expense for 2009 was due to expenses associated with operating the assets acquired as part of the Millennium Acquisition. The year ended December 31, 2009 includes twelve months of activity for the assets acquired as part of the Millennium Acquisition compared to three months in the year ended December 31, 2008. Excluding operating expenses related to the assets acquired as part of the Millennium Acquisition, operating expenses were relatively flat for 2009 as compared to the same period in 2008.
Depreciation and Amortization. Depreciation and amortization expenses for the year ended December 31, 2009 were $17.2 million compared to $13.6 million for the year ended December 31, 2008. The major items impacting the $3.6 million increase were (i) twelve months of depreciation and amortization of the assets acquired as part of Millennium Acquisition and (ii) depreciation expense associated with the capital expenditures placed into service. These increases were offset by an adjustment of $0.9 million recorded during the three months ended June 30, 2009 to correct an overstatement of depreciation expense in a prior period.
Impairment. During the year ended December 31, 2009, we incurred impairment charges of $5.9 million in our Midstream segment as a result of reduced throughput volumes as our producer customers curtailed their drilling activity in response to lower natural gas prices. During the year ended December 31, 2008, the Partnership recorded an impairment charge related to certain processing plants, pipelines and contracts in its Midstream business of $27.0 million due to the substantial decline in commodity prices in the fourth quarter as well as declining drilling activity by its producer customers.
Capital Expenditures. Capital expenditures for the year ended December 31, 2009 were $18.2 million compared to $17.4 million for the year ended December 31, 2008. During 2009, of our capital spending in this segment, we spent $10.8 million on growth capital and $7.4 million on maintenance capital. We classify capital expenditures as either maintenance capital, which represents routine well connects and capitalized maintenance activities, or as growth capital, which represents organic growth projects. Our increase in capital spending for 2009 is due primarily to the construction of gathering lines to producers in the Brookeland and Tyler County gathering systems.
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South Texas Segment
Twelve Months Ending December 31, | |||||||
2009 | 2008(b) | ||||||
(Amounts in thousands, except volumes and realized prices) | |||||||
Revenues: | |||||||
Sales of natural gas, NGLs, oil and condensate | $ | 94,691 | $ | 168,922 | |||
Gathering and treating services | 5,608 | 4,779 | |||||
Other | 3 | 15 | |||||
Total revenues | 100,302 | 173,716 | |||||
Cost of natural gas and natural gas liquids | 91,916 | 161,963 | |||||
Operating costs and expenses: | |||||||
Operations and maintenance | 3,661 | 2,924 | |||||
Depreciation and amortization | 5,324 | 4,428 | |||||
Impairment | 7,733 | 8,105 | |||||
Total operating costs and expenses | 16,718 | 15,457 | |||||
Operating income (loss) from continuing operations | (8,332 | ) | (3,704 | ) | |||
Discontinued operations | 290 | 1,782 | |||||
Operating income (loss) | $ | (8,042 | ) | $ | (1,922 | ) | |
Capital expenditures | $ | 69 | $ | 1,145 | |||
Realized volumes: | |||||||
Oil and condensate (per Bbl) | $ | 50.83 | $ | 92.10 | |||
Natural gas (per Mcf) | $ | 3.76 | $ | 8.99 | |||
NGLs (per Bbl) | $ | 32.26 | $ | 52.66 | |||
Production volumes: | |||||||
Gathering volumes (Mcf/d)(a) | 83,307 | 88,488 | |||||
NGLs and condensate (net equity gallons) | 1,248,783 | 591,683 | |||||
Condensate (net equity gallons) | 1,443,060 | 1,821,800 | |||||
Natural gas short position (MMbtu/d)(a) | 902 | 500 | |||||
________________________
(a) | Gathering volumes (Mcf/d) and natural gas short position (MMbtu/d) are calculated by taking the total volume and then dividing by the number of days in the respective period. |
(b) | Includes operations related to the Millennium Acquisition starting on October 1, 2008. |
Revenue and Cost of Natural Gas and Natural Gas Liquids. During the year ended December 31, 2009 the South Texas Segment contributed revenues minus cost of natural gas and natural gas liquids of $8.4 million, as compared to $11.8 million for the year ended December 31, 2008. We were negatively impacted by lower NGL, natural gas and condensate pricing during 2009 as compared to the same period in 2008. This decline was partially offset by the impact of the assets acquired as part of the Millennium Acquisition which contributed revenue minus cost of natural gas and natural gas liquids of $3.7 million during 2009.
Operating Expenses. Operating expenses for the year ended December 31, 2009 were $3.7 million, as compared to $2.9 million for the year ended December 31, 2008. The major item impacting the $0.7 million increase in operating expense was the additional expenses associated with operating the assets acquired as part of the Millennium Acquisition.
Depreciation and Amortization. Depreciation and amortization expenses for the year ended December 31, 2009 were $5.3 million, as compared to $4.4 million for the year ended December 31, 2008. Depreciation and amortization increased due to depreciation and amortization associated with the assets acquired as part of the Millennium Acquisition.
Impairment. During the year ended December 31, 2009, we incurred impairment charges of $7.7 million in our
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Midstream segment as a result of reduced throughput volumes as our producer customers curtailed their drilling activity in response to lower natural gas prices. During the year ended December 31, 2008, the Partnership recorded an impairment charge related to certain processing plants, pipelines and contracts in its Midstream business of $8.1 million due to the substantial decline in commodity prices in the fourth quarter as well as declining drilling activity by its producer customers.
Capital Expenditures. Capital expenditures for the year ended December 31, 2009 were $0.1 million as compared to $1.1 million for the year ended December 31, 2008. During the year ended December 31, 2009, we spent $0.1 million on maintenance capital. The decrease in capital expenditures in 2009 compared to 2008 was the result of a reduction in drilling activity during 2009.
Discontinued Operations. On April 1, 2009, we sold our producer services line of business, and thus have retrospectively classified the revenues minus the cost of natural gas and natural gas liquids as discontinued operations. During the year ended December 31, 2009, this business generated revenues of $19.2 million and cost of natural gas and natural gas liquids of $18.9 million, as compared to revenues of $265.1 million and cost of natural gas and natural gas liquids of $263.3 million during the year ended December 31, 2008.
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Gulf of Mexico Segment
Three Months Ending December 31, | |||||||
2009 | 2008 (b) | ||||||
(Amounts in thousands, except volumes and realized prices) | |||||||
Revenues: | |||||||
Sales of natural gas, NGLs, oil and condensate | $ | 31,161 | $ | 952 | |||
Gathering and treating services | 864 | 703 | |||||
Other | 1,616 | — | |||||
Total revenues | 33,641 | 1,655 | |||||
Cost of natural gas and natural gas liquids | 26,372 | 1,376 | |||||
Operating costs and expenses: | |||||||
Operations and maintenance | 1,907 | 605 | |||||
Depreciation and amortization | 6,576 | 1,521 | |||||
Total operating costs and expenses | 8,483 | 2,126 | |||||
Operating loss | $ | (1,214 | ) | $ | (1,847 | ) | |
Capital Expenditures | 358 | — | |||||
Realized average prices: | |||||||
Oil and condensate (per Bbl) | $ | 59.11 | $ | — | |||
Natural gas (per Mcf) | $ | 4.64 | $ | 6.64 | |||
NGLs (per Bbl) | $ | 35.52 | $ | 20.58 | |||
Production volumes: | |||||||
Gathering volumes (Mfc/d)(a) | 116,492 | 12,014 | |||||
NGLs and condensate (net equity gallons) | 5,768,018 | 176,962 | |||||
________________________
(a) | Gathering volumes (Mcf/d) are calculated by taking the total volume and then dividing by the number of days in the respective period. |
(b) | Includes operations related to the Millennium Acquisition starting on October 1, 2008. |
Revenues and Cost of Natural Gas and Natural Gas Liquids. The Gulf of Mexico Segment was a new segment and new area of operations for us in 2008. We entered into this segment as a result of the Millennium Acquisition, effective October 1, 2008. During the year ended December 31, 2009, the Gulf of Mexico Segment contributed $7.3 million in revenues minus cost of natural gas and natural gas liquids compared to $0.3 million in the year ended December 31, 2008. As a result of damage inflicted by Hurricanes Gustav and Ike in August 2008 and September 2008, respectively, the Yscloskey plant did not come back online until mid-January 2009 and the North Terrebonne plant did not come back online until mid-November 2008. We received a partial payment of approximately $1.6 million for business interruption caused by Hurricanes Gustav and Ike which we recognized as other revenue during the three months ended June 30, 2009.
Operating Expenses. Operating expenses for the year ended December 31, 2009 were $1.9 million compared to $0.6 million in the year ended December 31, 2008. We continued to incur operating expenses associated with the Yscloskey and North Terrebonne plants while the plants were undergoing repair for the hurricane damage. We also incurred costs for the repair of the two plants. Such costs were recovered from the escrow account established pursuant to the Millennium Acquisition purchase and sale agreement. As a result and pursuant to the agreement, any insurance proceeds received for repair costs will be deposited into the escrow account. During 2009, we received payment from the Millennium Acquisition escrow of the remaining $0.3 million in cash and continued canceling common units held in escrow to satisfy additional claims.
Depreciation and Amortization. Depreciation and amortization expenses for the year ended December 31, 2009 were $6.6 million compared to $1.5 million for the three months in 2008 that we owned the assets acquired in the Millennium Acquisition.
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Capital Expenditures. Capital expenditures for 2009 for the Gulf of Mexico Segment were $0.4 million. We did not incur any capital expenditures related to the Gulf of Mexico Segment in 2008.
Upstream Segment
Twelve Months Ending December 31, | |||||||
2009 | 2008 (a) | ||||||
(Amounts in thousands, except volumes and realized prices) | |||||||
Revenues: | |||||||
Oil and condensate | $ | 35,316 | $ | 72,526 | |||
Sulfur | — | 37,759 | |||||
Natural gas (b) | 12,021 | 32,513 | |||||
NGLs | 16,057 | 29,530 | |||||
Other | 239 | 701 | |||||
Total revenues | 63,633 | 173,029 | |||||
Operating Costs and expenses: | |||||||
Operations and maintenance (c) | 28,536 | 37,481 | |||||
Other operating expense | (3,552 | ) | — | ||||
Depletion, depreciation and amortization | 34,009 | 44,997 | |||||
Impairment | 8,114 | 107,017 | |||||
Goodwill impairment | — | 30,994 | |||||
Total operating costs and expenses | 67,107 | 220,489 | |||||
Operating (loss) income | $ | (3,474 | ) | $ | (47,460 | ) | |
Capital expenditures | $ | 8,437 | $ | 20,655 | |||
Realized average prices (d): | |||||||
Oil and condensate (per Bbl) | $ | 45.30 | $ | 87.04 | |||
Natural gas (per Mcf) | $ | 3.69 | $ | 8.09 | |||
NGLs (per Bbl) | $ | 31.90 | $ | 61.39 | |||
Sulfur (per Long ton) | $ | — | 359,96 | ||||
Production volumes (e): | |||||||
Oil and condensate (Bbl) | 811,075 | 823,316 | |||||
Natural gas (Mcf) | 3,659,431 | 4,117,247 | |||||
NGLs (Bbl) | 504,669 | 480,450 | |||||
Total (Mcfe) | 11,553,895 | 11,939,843 | |||||
Sulfur (Long ton) | 119,812 | 104,613 | |||||
________________________
(a) | Includes operations from the Stanolind Acquisition effective May 1, 2008. |
(b) | Revenues include a change in the value of product imbalances of $1,505 and $841 for the years ended December 31, 2009 and 2008, respectively. |
(c) | Includes costs to dispose of sulfur in our Upstream segment of $2.2 million for the year ended December 31, 2009. |
(d) | Calculation does not include impact of product imbalances. |
(e) | Volumes and realized prices for the year ended December 31, 2008 have been adjusted from prior reported amounts for a reallocation which was recorded in December 2009. |
Revenue. For the year ended December 31, 2009, the Upstream Segment contributed $63.6 million of revenue as compared to $173.0 million for the year ended December 31, 2008. On April 30, 2008, we acquired all of Stanolind Oil and Gas Corp. (the "Stanolind Acquisition"). With this acquisition, we acquired crude oil and natural gas producing properties in the Permian Basin of West Texas, primarily in Ward, Crane and Pecos Counties. The decrease in revenue was due to substantially lower realized prices for oil, natural gas, NGLs and sulfur and the non-cash mark-to-market of product imbalances, partially offset by
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an additional four months of operations related to the assets acquired in the Stanolind Acquisition. During 2009, production averaged 10.3 MMcf/d of natural gas, 2.2 MBO/d of oil and condensate, 1.4 MB/d of NGL's and 328 LT/d of sulfur. The period included twelve months of production from the assets acquired in the Stanolind Acquisition which averaged 812 Boe/d. During 2009, the Big Escambia Creek (BEC) plant experienced reduced oil, residue gas and NGL sales due to unanticipated repairs and overhauls to the plant's residue gas compressors. Sales of oil, residue gas and NGLs from BEC, Flomaton and Fanny Church fields were curtailed for 60 days, during 2009 associated with the compressors' downtime. The reduced production during these periods negatively impacted Upstream revenues by approximately $2.6 million.
During 2009, the cost to dispose sulfur exceeded the sales price by $2.2 million compared to revenue of $37.8 million during 2008. Historically, sulfur was viewed as a low value by-product in the production of oil and natural gas. Due to an increase in demand in the global fertilizer market during the first nine months of 2008, the price per long ton (before effects of net-backs) peaked at over $600 at the Tampa, Florida market in September 2008. Deterioration in the sulfur market during 2009 has caused the price at the Tampa, Florida market to decline to a range of $0 to $30 per long ton. Currently in the first quarter 2010, the Tampa, Florida sulfur market has improved to $90 per long ton.
Operating Expenses. Operating expenses, including severance and ad valorem taxes, totaled $28.5 million for the Upstream Segment during the year ended December 31, 2009, as compared to $37.5 million for the year ended December 31, 2008. The operating expenses include twelve months of expenses related to the assets acquired in the Stanolind Acquisition during 2009 compared to only eight months for the same period in 2008. The decrease in operating expense can be attributed to lower well workover expense incurred during 2009 as compared to the same period in the prior year and additional expenses being incurred during 2008 due to the turnaround at the BEC treating facility in April 2008. The decrease during 2009 is also due to a reversal of $1.6 million in environmental reserves determined to no longer be necessary as well as a credit of $0.7 million for overbilling related to a non-operated asset.
Depletion, Depreciation and Amortization. Depletion, depreciation and amortization expense for the year ended December 31, 2009 was $34.0 million, as compared to $45.0 million for the year ended December 31, 2008. The decrease for 2009 compared to the comparable period in 2008 is due to the decrease in our depletable base as a result of the impairment charges we incurred during the last three months of fiscal year 2008. This decrease was partially offset by the depletion expense related to the assets added through the Stanolind Acquisition for 2009 compared to only eight months during the same period in 2008 and the curtailed production during 2008 due to the turnaround at the BEC treating facility in April 2008.
Other Operating Income. Other operating income for the year ended December 31, 2009, includes income of $3.6 million due to the recovery of $2.2 million of assets previously written off and the release of $1.4 million of liabilities assumed as part of our purchase price allocation for our acquisitions of Escambia Asset Co. LLC and Redman Energy Holdings, L.P. During the period, we received additional information about collectability of these assets and determined that we no longer had any obligation under these liabilities.
Impairment. During the year ended December 31, 2009, we incurred impairment charges of $8.1 million in our Upstream Segment, of which, $7.9 million was a result of a decline in natural gas prices, production declines and lower natural gas liquids yields at our Flomaton field and $0.2 million in other fields due to lower natural gas prices. During the year ended December 31, 2008, we incurred impairment charges related to certain fields of $107.0 million due to the substantial decline in commodity prices during the fourth quarter of 2008. As a result of the impairment charge in the year ended December 31, 2008, we assessed our goodwill balance for impairment and recorded an impairment charge to goodwill of $31.0 million.
Capital Expenditures. The Upstream Segment's maintenance capital expenditures for the year ended December 31, 2009 totaled $8.4 million compared $20.7 million for the year ended December 31, 2008. We did not incur any growth capital expenditures during 2009 or 2008. The maintenance capital expenditures during 2009 were associated with compressor overhauls at the BEC and Flomaton treating facilities and well completions, recompletions, workovers, equipping and leasing activities. The higher maintenance capital expenditures in 2009 were related primarily to a planned turnaround at our Big Escambia Creek (“BEC”) facility.
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Corporate Segment
Twelve Months Ending December 31, | |||||||
2009 | 2008 | ||||||
($ in thousands) | |||||||
Revenues: | |||||||
Realized commodity derivatives gains (losses) | $ | 83,300 | $ | (46,059 | ) | ||
Unrealized commodity derivatives gains (losses) | (189,590 | ) | 207,824 | ||||
Total revenues | (106,290 | ) | 161,765 | ||||
General and administrative | 45,819 | 45,618 | |||||
Depreciation and amortization | 1,073 | 787 | |||||
Other expense | — | 10,699 | |||||
Operating income (loss) | (153,182 | ) | 104,661 | ||||
Other income (expense): | |||||||
Interest income | 187 | 771 | |||||
Other income | 934 | 1,318 | |||||
Interest expense | (21,591 | ) | (32,884 | ) | |||
Unrealized interest rate derivative losses | 12,529 | (27,717 | ) | ||||
Realized interest rate derivative gains (losses) | (18,876 | ) | (5,214 | ) | |||
Other expense | (1,070 | ) | (955 | ) | |||
Total other income (expense) | (27,887 | ) | (64,681 | ) | |||
Gain (loss) from continuing operations before taxes | (181,069 | ) | 39,980 | ||||
Income tax (benefit) provision | 1,022 | (1,449 | ) | ||||
Gain (loss) from continuing operations | (182,091 | ) | 41,429 | ||||
Discontinued operations, net of tax | 9,107 | 35,387 | |||||
Segment gain (loss) | $ | (172,984 | ) | $ | 76,816 | ||
Revenue. As a master limited partnership, we distribute available cash (as defined in our partnership agreement) every quarter to our unitholders subject to reserves established by our Board of Directors. Our distribution policy, including a description of the right to make reserves against available cash, is discussed in greater detail in Part II, Item 5. Market for Registrant's Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities - Cash Distribution Policy.
The volatility inherent in commodity prices generates uncertainty in future levels of available cash. We enter into derivative transactions to reduce our exposure to commodity price risk and reduce the uncertainty of future cash flows.
Our Corporate Segment's revenue, which solely includes our commodity derivatives activity, decreased to a loss of $106.3 million for the year ended December 31, 2009, from a gain of $161.8 million for the year ended December 31, 2008. As a result of our commodity hedging activities, revenues include total realized gains of $83.3 million on risk management activity settled during the year ended December 31, 2009 and unrealized mark-to-market losses of $189.6 million for the year ended December 31, 2009, as compared to realized losses of $46.1 million and unrealized mark-to-market gains of $207.8 million for the year ended December 31, 2008. Included in unrealized commodity derivative (losses) gains is amortization related to put premiums and costs associated with the resetting of derivative contract prices of $48.4 million during the year ended December 31, 2009 as compared to $13.3 million for the year ended December 31, 2008.
As the forward price curves for our hedged commodities shift in relation to the caps, floors, and swap strike prices, the fair value of such instruments changes. We capture this change as unrealized, non-cash, mark-to-market changes during the period of the change. The unrealized mark-to-market changes for the year ended December 31, 2009 and 2008 had no impact on cash activities for those periods and, as such, are excluded from our calculation of Adjusted EBITDA. The realized commodity derivatives results during the year ended December 31, 2009 reflect the difference between the strike prices and settlement prices for derivative volumes settled during the year. As such, the realized amounts impact our cash flows and are included in our calculation of Adjusted EBITDA.
Given the uncertainty surrounding future commodity prices, and the general inability to predict future commodity prices as they relate to the strike prices at which we have hedged our exposure, it is difficult to predict the magnitude and impact that
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marking our hedges to market will have on our income from operations in future periods. Conversely, negative commodity price movements affecting our revenues and costs are expected to be partially offset by our executed derivative instruments.
General and Administrative Expenses. General and administrative expenses increased by $0.2 million to $45.8 million for 2009 as compared to $45.6 million for 2008. This growth in general and administrative expenses was primarily driven by increased headcount in our corporate office as a result of our 2008 acquisitions but was also impacted by our recruiting efforts in accounting, back-office, engineering, land and operations-related corporate personnel associated with being a public partnership. Corporate-office payroll expenses increased by $2.8 million in 2009 as a result of the increased headcount. Included within the increased corporate-office payroll expenses was an decrease of $1.0 million related to equity-based compensation, of which 2009 includes $0.4 million related to the allocation of expense from Eagle Rock Holdings, L.P. due to its issuance of Tier I units to one of our executives, as compared to $1.6 million in 2008. Also included in 2009 was a one time charge of $0.1 million for severance payments due to a reduction in workforce. As a result of the increase in our expenses for corporate-office headcount, contract labor and other outside professional services decreased by $2.6 million in 2009 as compared to the same period in 2008. In addition, 2009 included legal and other professional advisory fees of $0.9 million incurred related to strategic discussions regarding our capital structure and proposals received regarding the sale of the Minerals Business.
At the present time, we do not allocate our general and administrative expenses cost to our operational segments. The Corporate Segment bears the entire amount.
Other Operating Expenses. In July 2008, SemGroup, L.P. and certain of its subsidiaries (“SemGroup”) filed petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code. We historically sold portions of our condensate production from our Texas Panhandle and East Texas midstream systems to SemGroup. During July 2008, we sold pre-bankruptcy, and continued to sell post-bankruptcy, condensate to SemGroup. As of August 1, 2008, we ceased all deliveries/sales of condensate to SemGroup. As a result of the bankruptcy we recorded a $10.7 million bad debt charge during the year ended December 31, 2008 which is included in “Other Operating Expense” in the consolidated statement of operations. Although we sought payment of our $10.7 million receivable for condensate sales as a critical supplier to SemGroup under its Supplier Protection Program (“SPP”), we were not successful in being recognized as a critical provider by SemGroup and thus were not admitted to the SPP.
Total Other Expense. Total other expense, which includes both realized and unrealized gains and losses from our interest rate swaps, decreased to $27.9 million for the year ended December 31, 2009 as compared to $64.7 million for the year ended December 31, 2008. During 2009, we incurred realized losses from our interest rate swaps of $18.9 million as compared to realized losses of $5.2 million during the year ended December 31, 2008. We also incurred unrealized mark-to-market gains from our interest rate swaps of $12.5 million during the year ended December 31, 2009 as compared to unrealized mark-to-market losses of $27.7 million for the same period in 2008. These unrealized mark-to-market losses did not have any impact on cash activities for the period, and are excluded by definition from our calculation of Adjusted EBITDA.
Interest expense decreased to $21.6 million for the year ended December 31, 2009 as compared to $32.9 million during the same period in the prior year. Interest expense is shown before the impact of our interest rate derivatives, which convert a portion of our outstanding debt from variable-rate interest obligations to fixed-rate interest obligations. All of our outstanding debt consists of borrowings under our revolving credit facility, which bears interest primarily based on a LIBOR rate plus the applicable margin. The decrease in interest expense is due to lower LIBOR rates during 2009, as compared to the same period in 2008, partially offset by higher debt balances in the 2009 period as a result of our acquisitions made in 2008.
Income Tax (Benefit) Provision. Income tax provision for the 2009 and 2008 relates to (i) state taxes due by us and (ii) federal taxes due by Eagle Rock Energy Acquisition Co., Inc. (acquiring entity of certain entities acquired in the acquisition of Redman Energy Corporation “Redman Acquisition” in 2007) and Eagle Rock Energy Acquisition Co. II, Inc. (acquiring entity of certain entities acquired in the Stanolind Acquisition) and their wholly-owned corporations, Eagle Rock Upstream Development Company, Inc. (successor entity to certain entities acquired in the Redman acquisition) and Eagle Rock Upstream Development Company II, Inc. (successor entity to certain entities acquired in the Stanolind acquisition), which are subject to federal income taxes (the “C Corporations”). During 2009, our tax provision increased by $2.5 million as compared to the same periods in the prior year. These increases were the result of 2009 income projected for the C Corporations resulting from utilization of our remaining net operating loss carryforwards, adjustments to true-up of the results of 2008 tax return and our 2008 tax provision, as well as changes in estimates used in our tax provision calculation in prior periods. For further discussion of our income tax (benefit) provision, see Note 15 to our consolidated financial statements included in Part II, Item 8. Financial Statements and Supplementary Data staring on page F-1 of this Annual Report.
Discontinued Operations. On May 24, 2010, we completed the sale of our Minerals Business. For the year ended December 31, 2009, we generated revenues of $15.7 million and income from operations of $7.8 million. For the year ended
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December 31, 2008, we generated revenues of $43.0 million and income loss from operations of $31.7 million. During the years ended December 31, 2009 and 2008, the Partnership incurred state tax expense on discontinued operations of $0.2 million and $0.4 million, respectively. During the years ended December 31, 2009 and 2008, we recorded a gain (loss) to discontinued operations, excluding the gain recognized by us on the sale of the Minerals Business, of $9.1 million and $35.4 million, respectively.
Adjusted EBITDA.
Adjusted EBITDA, as defined under Part II, Item 6. Selected Financial Data - Non-GAAP Financial Measures, decreased by $32.4 million from $207.0 million for the year ended December 31, 2008 to $174.5 million for the year ended December 31, 2009.
As described above, revenues minus cost of natural gas and natural gas liquids for the Midstream Business (including the Texas Panhandle, East Texas/Louisiana, South Texas and Gulf of Mexico Segments) decreased by $59.9 million during the year ended December 31, 2009, as compared to the comparable period in 2008. The Upstream Segment decreased an additional $108.7 million to revenues during the year ended December 31, 2009, as compared to the comparable period in 2008. Our Corporate Segment's realized commodity derivatives gain increased by $129.4 million during the year ended December 31, 2009 as compared to the comparable period in 2008. This resulted in a negative $39.2 million of total incremental revenues minus cost of natural gas and natural gas liquids during the year ended December 31, 2009 as compared to the comparable period in 2008. The incremental revenue amounts are adjusted to exclude the impact of unrealized commodity derivatives not included in the calculation of Adjusted EBITDA.
Operating expenses (including taxes other than income) for our Midstream Business increased by $1.1 million for the year ended December 31, 2009, as compared to the same period in 2008, while Operating Expenses (including taxes other than income) for the Upstream Segment decreased $8.9 million for the year ended December 31, 2009, as compared to the comparable period in 2008.
General and administrative expense, excluding the impact of non-cash compensation charges related to our long-term incentive program, Holding's Tier I incentive units and other non-recurring items and captured within our Corporate Segment, increased during the year ended December 31, 2009 by $1.2 million, as compared to the respective period in 2008.
As a result, revenues (excluding the impact of unrealized commodity derivative activity) minus cost of natural gas and natural gas liquids for the year ended December 31, 2009, as compared to the same period in 2008 decreased by $39.2 million, operating expenses decreased by $7.9 million and general and administrative expenses increased by $1.2 million. The decreases in revenues minus the cost of natural gas and natural gas liquids, the decreases in operating costs offset by the increase in general and administrative expenses resulted in a decrease to Adjusted EBITDA during the year ended December 31, 2009, as compared to the year ended December 31, 2008. Adjusted EBITDA excludes amortization of commodity hedge costs (including costs of hedge reset transactions) for the years ended December 31, 2009 and 2008 of $48.4 million and $13.3 million, respectively. Including these amortization costs, our Adjusted EBITDA for the years ended December 31, 2009 and 2008 would have been $126.2 million and $193.7 million, respectively.
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LIQUIDITY AND CAPITAL RESOURCES
Historically, our sources of liquidity have included cash generated from operations, equity investments by our existing owners, equity investments by other institutional investors and borrowings under our revolving credit facility. We believe that the cash generated from these sources will continue to be sufficient to meet all of our expected liquidity needs, which include our requirements for short-term working capital, long-term capital expenditures for maintenance and organic growth and our expected quarterly cash distributions. In the event we acquire additional midstream assets or natural gas or oil properties at purchase prices that exceed our existing capital resources, we expect that we will finance those acquisitions with a combination of expanded or new debt facilities, and new equity and debt issuances through the capital markets.
Our distribution policy is to distribute to our unitholders, on a quarterly basis, all of our available cash in the manner described below and as further described in our partnership agreement. Available cash generally means, for any quarter ending prior to liquidation, all cash on hand at the end of that quarter less the amount of cash reserves that the general partner determines to establish to:
• | provide for the proper conduct of our business, including for future capital expenditures and credit and other needs; |
• | comply with applicable law or any partnership debt instrument or other agreement; or |
• | provide funds for distributions to unitholders and the general partner in respect of any one or more of the next four quarters. |
The actual distributions we will declare will be subject to our operating performance, prevailing market conditions (including forward oil, natural gas and sulfur prices), the impact of unforeseen events and the approval of our Board of Directors and will be done pursuant to our distribution policy.
In response to, in part, a lack of liquidity due to our high leverage levels and restricted access to the capital markets during 2009, our Board of Directors determined to reduce the quarterly distribution with respect to the first quarter of 2009 (and sustain such reduced quarterly distribution through the distributions for the third quarter of 2010). This decision was made to establish cash reserves (as against available cash) for the proper conduct of our business and to enhance our ability to remain in compliance with financial covenants under our revolving credit facility in future periods. The cash not distributed was used to reduce our outstanding debt under our revolving credit facility, to continue to execute our hedge strategy to maintain future cash flows and/or to fund growth capital expenditures.
Our goal is to reduce our ratio of outstanding debt to Adjusted EBITDA, or “leverage ratio,” both on a total Partnership basis and with respect to the definition of Total Leverage Ratio under our revolving credit facility (which is based on the outstanding borrowings allocated to, and the Adjusted EBITDA generated by, our Midstream Business), to approximately 3.0 to 3.5 on a sustained basis. We believe this leverage ratio range to be appropriate for our business and more in-line with historical midstream industry standards. We plan to achieve this goal by, without limitation, reducing outstanding indebtedness and investing in attractive organic growth and acquisition opportunities. As of December 31, 2010, our Total Leverage Ratio was 4.3. During the year ended December 31, 2010, we reduced our outstanding debt under the revolving credit facility by $224.4 million to $530.0 million, and since March 31, 2009, we have reduced our outstanding indebtedness under the revolving credit facility by $307.4 million. We do not expect to be able to maintain this level of debt reduction during 2011. We expect our efforts to reduce our leverage ratio to our desired range during 2011 will be primarily through investing in attractive growth opportunities which will increase our Adjusted EBITDA. We also expect our leverage ratio to benefit from any exercise of our approximately 20.7 million warrants outstanding as of December 31, 2010, which carry an exercise price of $6.00 per common unit and expire on May 15, 2012. Total proceeds to the Partnership from the warrants, if exercised in full, would total approximately $124 million. It is our intention to use future proceeds from warrants being exercised, if any, to pay for general partnership purposes, including to pay down borrowings outstanding under our revolving credit facility, absent any organic growth or acquisition opportunities.
Given the improvement in our liquidity during 2010, we announced an increase in the quarterly distribution to an annualized rate of $0.60 per unit with respect to the fourth quarter of 2010 (paid on February 14, 2011). Given our current outlook, we intend to recommend to the Board further quarterly increases in the distribution throughout 2011, with the expectation and objective of reaching an annualized distribution rate of $0.75 per unit beginning with respect to the fourth quarter of 2011 (payable in February 2012). Actual future increases in the distribution level, if any, will be driven by market conditions, future commodity prices, our leverage levels, the performance of our underlying assets and our ability to consummate accretive growth projects or acquisitions. Management's distribution recommendation is subject to change should factors affecting the general business climate or our specific operations differ from current expectations. All actual distributions
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paid will be determined and declared at the discretion of the Board, regardless of our recommendation.
For a detailed description of our revolving credit facility, see Note 7 to our consolidated financial statements included in Part II, Item 8. Financial Statements and Supplementary Data and below under “Revolving Credit Facility and Debt Covenants.”
Cash Flows
From January 1, 2009 through December 31, 2010, the key events that have had major impacts on our cash flows are:
• | the sale of our Minerals Business to Black Stone Minerals Company for approximately $171.6 million; |
• | a rights offering for which we received gross proceeds of $53.9 million and issued 21,557,164 common units and 21,557,164 warrants to purchase common units; |
• | the completion of the refurbishment of our Phoenix Plant and its installation in our Texas Panhandle region for a cost of $24.3 million; |
• | the acquisition of certain additional interest in the Big Escambia Creek Field (and the nearby Flomaton and Fanny Church fields) from Indigo Minerals, LLC for approximately $3.9 million in cash on hand; and |
• | the acquisition of certain natural gas gathering systems and related facilities from Centerpoint Energy Field Services, Inc. for $27.0 million in cash drawn from our revolver and cash on hand. |
Cash Distributions.
On February 4, 2009, we declared a $0.41 per unit distribution on all outstanding units (including common units, general partner units, and subordinated units) for the fourth quarter of 2008, payable on February 13, 2009 to the unitholders of record on February 10, 2009. The distribution to the common units, general partner units and subordinated units was paid on February 13, 2009.
With respect to the first quarter 2009 through the third quarter 2010, we declared a quarterly cash distribution of $0.025 to our general partner (as to its general partner units through our first quarter 2010) and our common unitholders (except for the restricted units granted on October 27, 2010) as of each record date. The total combined distribution amount was $9.3 million.
On January 27, 2011, we declared our fourth quarter 2010 cash distribution of $0.15 per unit to our common unitholders of record as of February 7, 2011. The distribution was paid on February 14, 2011.
Working Capital.
Working capital is the amount by which current assets exceed current liabilities and is a measure of our ability to pay our liabilities as they become due. As of December 31, 2010, working capital was a negative $60.7 million as compared to negative $59.9 million as of December 31, 2009, excluding assets and liabilities held for sale.
The net decrease in working capital of $0.8 million from December 31, 2009 to December 31, 2010, resulted primarily from the following factors:
• | cash balances and marketable securities, net of due to/from affiliates, increased overall by $1.3 million; |
• | trade accounts receivable decreased by $10.3 million primarily from the impact of slightly lower revenues, increased collection efforts and realized settlement losses on our commodity derivatives; |
• | risk management net working capital balance increased by a net $9.8 million as a result of changes in current portion of mark-to-market unrealized positions, the adjustment of the strike price of certain derivative instrument (see Hedging Strategy) and the amortization of put premiums and other derivative costs; |
• | accounts payable increased by $2.3 million from December 31, 2009 primarily as a result of activities and timing of payments, including capital expenditures activities; and |
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• | accrued liabilities increased by $0.2 million primarily reflecting payment of employee benefit accruals, lower interest payments and the timing of payment of unbilled expenditures related primarily to capital expenditures. |
Cash Flows Year Ended 2010 Compared to Year Ended 2009
Cash Flow from Operating Activities. Cash flows from operating activities increased $17.4 million during 2010 as compared to 2009 as a result of higher commodity prices across our two businesses. These higher commodity prices resulted in higher cash flows from the sale of our equity crude oil, natural gas and NGLs volumes and higher cash flows from the sale of sulfur. Higher commodity prices also resulted in us realizing net settlement losses on our commodity derivatives during 2010, of which $1.1 million of cash received was reclassified to cash from financing activities, compared to $8.9 million of cash received being reclassified during 2009. In addition, our cash flows from operations for the year ended December 31, 2010 includes a payment of $5.9 million to adjust the strike price on an existing derivative contract and net payments of $2.2 million to unwind certain derivative contracts, as discussed within "Hedging Strategy" below, compared to a payment of $19.6 million to reset certain derivative contracts and payments of $5.6 million to unwind certain derivative contracts included within cash flows from operating activities during 2009.
Cash Flows from Investing Activities. Cash flows provided by investing activities for 2010 were $73.5 million, as compared to cash flows used in investing activities of $37.3 million for 2009, primarily due to the sale of our Minerals Business. The cash inflow from the sale of our Minerals Business was offset by our acquisition of the additional working interests from Indigo Minerals, LLC and certain natural gas gathering systems from CEFS, In 2009 we did not make any acquisitions. In addition, we increased our cash outlays for capital expenditures, in particular spending related to our Phoenix Plant, as compared to our spending on capital expenditures in 2009.
Cash Flows from Financing Activities. Cash flows used in financing activities during 2010 as compared to 2009, increased by $102.2 million. Key differences between periods include net repayments to our revolving credit facility of $224.4 million during 2010 as compared to net repayments of $45.0 million from our revolving credit facility during 2009. We used the proceeds received from the sale of our Minerals Business and the proceeds received from our rights offering, in which we raised gross proceeds of $53.9 million, to pay down borrowings outstanding under our revolving credit facility. Cash outflows related to our distributions decreased to $7.2 million during 2010 as compared to $35.7 million during 2009 as a result of reducing our quarterly distribution to $0.025 for the payments made in 2010 (for the fourth quarter of 2009 and first three quarters of 2010) from $0.41 paid in the first quarter of 2009 (for the fourth quarter of 2008), coupled with $0.025 paid in the last three quarters of 2009 (for the first three quarters of 2009).
Cash Flows Year Ended 2009 Compared to Year Ended 2008
Cash Flow from Operating Activities. Cash flows from operating activities decreased $59.4 million during 2009 as compared to 2008 as a result of lower commodity prices across our three businesses and reduced NGL equity volumes in the Midstream Business. These lower commodity prices resulted in lower cash flows from the sale of our equity crude oil, natural gas and natural gas liquids volumes. In addition, during 2009, we incurred expenses of $2.2 million as the cost to dispose sulfur exceeded the sales price, compared to 2008 in which we recorded revenue related to the sale of sulfur of $37.8 million. The lower commodity prices also had a direct result in the decrease in our working capital. Specifically contributing to the decrease in cash flows from operating activities was the $38.0 million decrease in accounts payable, as discussed above. Lower commodity prices also resulted in us realizing settlement gains during the year ended December 31, 2009, of which $8.9 million of cash received was reclassified to cash from financing activities, compared to $11.1 million of payments being reclassified during 2008. In addition, our cash flows from operating activities for 2009 includes payments of $19.6 million to reset certain derivative contracts and $5.6 million to unwind certain derivative contracts.
Cash Flows from Investing Activities. Cash flows used for investing activities for 2009, as compared to 2008, decreased by $368.0 million due to acquisitions completed in 2008. During 2008, we paid $262.2 million, net of cash acquired, for our acquisitions. During the 2009, we did not make any acquisitions. The investing activities for the current period reflect additions to property, plant and equipment expenditures of $36.1 million versus $66.7 million for the prior year period. This decrease is attributable to lower well-connect activity in our Midstream Business resulting from the reduced drilling activity of our producer customers, as well as lower capital spending associated with the maintenance of our Big Escambia Creek (“BEC”) facility, for which we performed a scheduled turnaround during 2008.
Cash Flows from Financing Activities. Cash flows used for financing activities during 2009 were $73.3 million versus cash flows provided by financing activities of $102.8 million during 2008. Key differences between periods include net payments to our revolving credit facility of $45.0 million during 2009, as compared to net proceeds of $232.3 million from our
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revolving credit facility during 2008. The net proceeds received during 2008, were used for our acquisitions of Stanolind and MMP. Distributions to members decreased to $35.7 million during 2009, as compared to $117.6 million during 2008 as a result of reducing our quarterly distribution to $0.025 from $0.41, as discussed above.
Capital Requirements
We anticipate that we will have sufficient liquidity and access to capital to continue to maintain and commercially exploit our Midstream Business (all four segments) and Upstream Segment assets consistent with our current operations. Additionally, as an operator of midstream and upstream assets, our capital requirements have increased to maintain those assets, hold production and throughput constant and to replace reserves. We anticipate that we will meet these requirements through cash generated from operations. We believe, however, that substantial growth would require access to external capital sources.
The energy business can be capital intensive, requiring significant investment for the acquisition or development of new facilities. We categorize our capital expenditures as either:
• | growth capital expenditures, which are made to acquire or construct additional assets to expand or upgrade our business, or to grow our production in our Upstream Business; or |
• | maintenance capital expenditures, which are made to replace partially or fully depreciated assets, to meet regulatory requirements, to maintain the existing operating capacity of our assets and extend their useful lives, or to maintain production in our Upstream Business. |
Our 2010 capital budget anticipated that we would spend approximately $40 million in total in 2010 on maintenance and growth capital, excluding acquisitions. We actually spent approximately $73.7 million in total in 2010 due primarily to the installation of the Phoenix Plant in our Texas Panhandle segment and to additional drilling and workover activity in our Upstream Business, particularly in Southern Alabama. In addition, we spent $31.0 million on the acquisition of certain assets from CEFS and Indigo Minerals, LLC.
Our 2011 capital budget anticipates that we will spend approximately $78 million in total for the year. This budget includes capital expenditures for growth, maintenance and well connect projects in both our Midstream and Upstream Segments. We intend to finance our capital expenditures with internally generated cash flow and draws from our revolving credit facility.
Since our inception in 2002, we have made substantial growth capital expenditures. We historically have financed our maintenance capital expenditures (including well-connect costs) with internally generated cash flow and our growth capital expenditures ultimately with draws from our revolving credit facility (although such expenditures were often funded out of internally generated cash flow as an interim step). We anticipate funding our growth capital expenditures, for the foreseeable future, out of cash flow generated from operations, with draws from our revolving credit facility, and, to the extent necessary, issuances of additional equity and debt securities.
Hedging Strategy
We use a variety of hedging instruments to accomplish our risk management objectives. At times our hedging strategy may involve entering into hedges with strike prices above current futures prices or resetting existing hedges to higher price levels in order to meet our cash flow requirements, stay in compliance with our revolving credit facility covenants and continue to execute on our distribution objectives. In addition, we may also terminate or unwind hedges or portions of hedges when the expected future volumes do not support the level of hedges. Hedge transactions such as these impact our liquidity in that we are required to pay the present value of the difference between the hedged price and the current futures price. These transactions also increase our exposure to the counterparties through which we execute the hedges. As part of this strategy, we executed the following hedging transactions during the year ended December 31, 2010;
• | On July 23, 2010, we enhanced our commodity derivative portfolio by adjusting the strike price of certain hedges to the forward market prices as of the date the hedges were executed. Specifically, we paid $5.9 million to adjust the strike price from $53.55 to $79.80 per barrel on existing NYMEX WTI crude oil swaps of 45,000 barrels per month for the five months ending December 31, 2010. |
• | On November 23, 2010, we entered into a series of hedging transactions to unwind existing contracts. We unwound; (i) 20,000 barrels a month of an "out-of-the-money" WTI crude oil swap with a price of $80.05, (ii) 15,000 barrels a |
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month of a 20,000 barrels a month "out-of-the-money" WTI crude oil swap with a price of $75.00 and (iii)23,000 barrels a month of a "in-the-money" WTI crude oil swap covering 29,000 barrels per month for the first half of the 2011 calendar year and 23,000 barrels a month covering the second half of the 2011 calendar year with a price a $86.20. For these transactions, we paid $2.2 million. We were using these WTI crude oil derivatives to hedge against changes in NGL prices. To continue hedging these NGL volumes, we then entered into the following derivative transactions for the 2011 calendar year on November 23, 2010: a 996,000 gallon per month OPIS normal butane swap at $1.50 per gallon, a 462,000 gallon per month OPIS iso butane swap at $1.5425 per gallon, a 378,000 gallon per month OPIS natural gasoline swap at $1.8525 per gallon, a 1,680,000 gallon per month OPIS propane swap for $1.1165 per gallon and a 252,000 gallon per month OPIS propane swap for $1.11 per gallon.
• | On December 20, 2010, we entered into a 34,000 MMbtu per month Henry Hub natural gas swap at $4.45 per MMbtu. For this swap, we will be paying the fixed price, where normally, for the swaps we enter into, we pay the floating price. We were using a portion of our Henry Hub natural gas swaps to hedge against changes in ethane prices and this transaction effectively unwinds a portions of these swaps. To continue hedging these ethane volumes, we then entered into a 1,428,000 gallon per month OPIS ethane swap at a price of $0.545 per gallon. |
For a further discussion of our hedging strategy, see Note 11 to our consolidated financial statements included in Part II, Item 8. Financial Statements and Supplementary Data starting on page F-1 of this Annual Report. For a detail of our open derivative positions as of December 31, 2010, see Part II, Item 7A. Qualitative and Quantitative Disclosure About Market Risk.
Revolving Credit Facility
As of December 31, 2010, our revolving credit facility was comprised of 19 banks with aggregate commitments of $880 million. unused capacity available to us under our credit agreement, based on outstanding debt and total commitments as of that date, was approximately $341 million (before taking into account covenant-based capacity limitations and the approximately $9.1 million of unfunded commitments from Lehman Brothers that is no longer available after Lehman Brothers' bankruptcy filing), on which we pay a commitment fee of 0.3% annually. Historically, our available capacity has been further limited by compliance with the financial covenants in the credit agreement. The credit agreement is scheduled to mature on December 13, 2012.
Given the current state of the banking industry worldwide, we are pleased with the degree of diversification within our lender group. As of today, all of our banks’ commitments, with the exception of Lehman Brothers’ commitment, remain in place and have funded in response to our borrowing notices. A Lehman Brothers subsidiary has an approximately 2.6% participation in our revolving credit facility.
We announced in October 2010 that our existing borrowing base was increased to $140 million from $130 million as part of our regularly scheduled semi-annual borrowing base redetermination. The reaffirmation was effective as of October 1, 2010, with no additional fees or increases in interest rate spread incurred.
Debt Covenants
Our revolving credit facility accommodates, through the use of a borrowing base for our Upstream Business and traditional cash-flow based covenants for our Midstream Business, the allocation of indebtedness to either our Upstream Business (to be measured against the borrowing base) or to our Midstream Business (to be measured against the cash-flow based covenant). At December 31, 2010, we were in compliance with our covenants under the revolving credit facility. Our interest coverage ratio, as defined in the credit agreement (i.e., Consolidated EBITDA divided by Consolidated Interest Expense), was 3.8 as compared to a minimum interest coverage covenant of 2.5, and our leverage ratio, as defined in the credit agreement (i.e., Total Funded Indebtedness divided by Adjusted Consolidated EBITDA), was 4.3 as compared to a maximum leverage ratio of 5.0. We believe that we will remain in compliance with our financial covenants through 2011.
Off-Balance Sheet Obligations.
We have no off-balance sheet transactions or obligations.
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Total Contractual Cash Obligations.
The following table summarizes our total contractual cash obligations as of December 31, 2010.
Payments Due by Period | ||||||||||||||||||||||||
Contractual Obligations | Total | 2011 | 2012 | 2013 | 2014-2015 | Thereafter | ||||||||||||||||||
($ in millions) | ||||||||||||||||||||||||
Long-term debt (including interest)(a) | $ | 592.4 | $ | 31.5 | $ | 560.9 | $ | — | $ | — | $ | — | ||||||||||||
Operating leases | 18.3 | 4.2 | 4.0 | 2.4 | 3.4 | 4.3 | ||||||||||||||||||
Purchase obligations(b) | — | — | — | — | — | — | ||||||||||||||||||
Total contractual obligations | $ | 610.7 | $ | 35.7 | $ | 564.9 | $ | 2.4 | $ | 3.4 | $ | 4.3 | ||||||||||||
__________________________
(a) Assumes our fixed swapped average interest rate of 3.76% plus the applicable margin under our amended and restated credit agreement, which remains constant in all periods.
(b) Excludes physical and financial purchases of natural gas, NGLs, and other energy commodities due to the nature of both the price and volume components of such purchases, which vary on a daily or monthly basis. Additionally, we do not have contractual commitments for fixed price and/or fixed quantities of any material amount.
Recent Accounting Pronouncements
The Financial Accounting Standards Board (the “FASB”) has codified a single source of U.S. Generally Accepted Accounting Principles (U.S. GAAP), the Accounting Standards Codification. Unless needed to clarify a point to readers, the Partnership will refrain from citing specific section references when discussing application of accounting principles or addressing new or pending accounting rule changes.
In January 2010, the FASB issued updated authoritative guidance which aligns the current oil and natural gas reserve estimation and disclosure requirements of the Extractive Industries - Oil and Gas guidance, as discussed above. This guidance expands the disclosures required for equity method investments, revises the definition of oil- and natural gas-producing activities to include nontraditional resources in reserves unless not intended to be upgraded into synthetic oil or natural gas, amends the definition of proved oil and natural gas reserves to require 12-month average pricing in estimating reserves, amends and adds definitions in the Master Glossary that is used in estimating proved oil and natural gas quantities and provides guidance on geographic areas with respect to disclosure of information about significant reserves. This guidance must be applied prospectively as a change in accounting principle that is inseparable from a change in accounting estimate and is effective for entities with annual reporting periods ending on or after December 31, 2009. We adopted this guidance effective December 31, 2009 (See Note 21).
In June 2009, the FASB issued authoritative guidance which reflects the FASB’s response to issues entities have encountered when applying previous guidance. In addition, this guidance addresses concerns expressed by the SEC, members of the United States Congress, and financial statement users about the accounting and disclosures required in the wake of the subprime mortgage crisis and the deterioration in the global credit markets. In addition, because this guidance eliminates the exemption from consolidation for qualified special-purpose entities (“QSPEs”) a transferor will need to evaluate all existing QSPEs to determine whether they must be consolidated. This guidance was effective for us on January 1, 2010 and did not have a material impact on our consolidated financial statements
In June 2009, the FASB issued authoritative guidance, which amends the consolidation guidance applicable to variable interest entities ("VIEs"). The amendments will significantly affect the overall consolidation analysis. While the FASB’s discussions leading up to the issuance of this guidance focused extensively on structured finance entities, the amendments to the consolidation guidance affect all entities and enterprises, as well as qualifying special-purpose entities (QSPEs) that were excluded from previous guidance. Accordingly, an enterprise will need to carefully reconsider its previous conclusions, including (1) whether an entity is a VIE, (2) whether the enterprise is the VIE’s primary beneficiary, and (3) what type of financial statement disclosures are required. This guidance was effective for us on January 1, 2010 and did not have a material impact on our consolidated financial statements.
In September 2009, the FASB issued a consensus which revises the standards for recognizing revenue on arrangements with multiple deliverables. Before evaluating how to recognize revenue for transactions with multiple revenue generating activities, an entity should identify all the deliverables in the arrangement and, if there are multiple deliverables,
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evaluate each deliverable to determine the unit of accounting and whether it should be treated separately or in combination. The consensus removes certain thresholds for separation, provides criteria for allocation of revenue amongst deliverables and expands disclosure requirements. This standard was effective for us on January 1, 2011 and will not have a material impact on our consolidated financial statements.
In January 2010, the FASB issued additional guidance on fair value disclosures. The new guidance clarifies two existing disclosure requirements and requires new disclosures such as: (1) a “gross” presentation of activities (purchases, sales, and settlements) within the Level 3 rollforward reconciliation, which will replace the “net” presentation format; and (2) detailed disclosures about the transfers in and out of Level 1 and 2 measurements. This guidance is effective for the first interim or annual reporting period beginning after December 15, 2009, except for the gross presentation of the Level 3 rollforward information, which is required for annual reporting periods beginning after December 15, 2010, and for interim reporting periods within those years. We adopted the fair value disclosures guidance on January 1, 2010, except for the gross presentation of the Level 3 rollforward information which was not required to be adopted by us until January 1, 2011.
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Item 7 A. Quantitative and Qualitative Disclosures About Market Risk.
Risk and Accounting Policies
We are exposed to market risks associated with adverse changes in commodity prices, interest rates and counterparty credit. We may use financial instruments such as put and call options, swaps and other derivatives to mitigate the effects of the identified risks. Adverse effects on our cash flow from changes in crude oil, natural gas, NGL product prices or interest rates could adversely impact our ability to make distributions to our unitholders, meet debt service obligations, fund required capital expenditures, and other similar requirements. Our management has established a comprehensive review of our market risks and has developed risk management policies and procedures to monitor and manage these market risks. Our general partner is responsible for the overall approval of market risk management policies, delegation of transaction authority levels, and for the establishment of a Risk Management Committee ("RMC"). The RMC is composed of officers (including, on an ex officio basis, our chief executive officer) who receive regular briefings on positions and exposures, credit exposures and overall risk management in the context of market activities. The RMC is responsible for the overall management of commodity price risk, interest rate risk and credit risk, including monitoring exposure limits.
Our Board of Directors also plays an important role in our risk oversight function. The Audit Committee is primarily responsible for the oversight of: (i) the integrity of our financial statements and internal controls, (ii) our compliance with legal and regulatory requirements, (iii) our independent auditor's qualifications, independence and performance of our internal audit function, and (iv) matters related to our hedging activities, litigation/disputes and environmental issues.
See Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations —Critical Accounting Policies — Risk Management Activities and Note 11 to our consolidated financial statements included in Part II, Item 8. Financial Statements and Supplementary Data starting on page F-1 for further discussion of the accounting for our derivative contracts.
Commodity Price Risk
We are exposed to the impact of market fluctuations in the prices of crude oil, natural gas, NGLs and other commodities as a result of our gathering, processing, producing and marketing activities, which produce a naturally long position in these commodities. Our profitability and cash flow are affected by changes in prices of these commodities. These prices are impacted by changes in the supply and demand for these commodities, as well as market uncertainty and other factors beyond our control. Historically, changes in the prices of NGLs have generally correlated with changes in the price of crude oil. For a discussion of the volatility of crude oil, natural gas and NGL prices, please read “Risk Factors.”
We manage this commodity price exposure through an integrated strategy that includes management of our contract portfolio, matching sales prices of commodities with purchases, optimization of our portfolio by monitoring basis and other price differentials in our areas of operations, and the use of derivative contracts. Crude oil, natural gas and NGL prices can also indirectly affect our profitability by influencing the level of drilling activity and related opportunities for our service.
The RMC is the entity responsible for creating and implementing a sound approach to managing our commodity price risk with respect to our budgetary exposure and stated risk tolerance. As such, the RMC’s responsibilities and authorities are to:
• | Identify sources of financial risk; |
• | Establish risk management policies (or ensure they are developed by appropriate departments within the partnership); |
• | Develop, oversee, review, assess and implement the risk management processes and infrastructure; |
• | Establish controls for risk management activities, including hedging transactions and financial reporting; |
• | Developing and enforcing policies related to setting and following acceptable risk parameters and risk limits; |
Measure and analyze our overall commodity price risk exposure, at least quarterly;
• | Recommend and approve hedging transactions to reduce our commodity price risk; and |
• | Report quarterly to the Board of Directors on the performance of the hedge program. These reports disclose, but may not necessarily be limited to, the following: open hedge position volumes; percentage of volumes and debt outstanding |
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hedged; mark-to-market valuations of open positions; cash-flow-at-risk reports; and settlement reports.
• | Establishing clearly-defined segregation of duties and delegations of authority; |
• | Identifying permitted transaction and product types; and |
• | Establishing and enforcing counterparty credit limitations. |
The Audit Committee of our Board of Directors monitors the implementation of our policy, and we have engaged an independent firm to provide additional oversight.
We frequently use financial derivatives (“hedges”) to reduce our exposure to commodity price risk. We have implemented a Risk Management Policy which allows management to execute crude oil, natural gas liquids and natural gas hedging instruments, which may include swaps, collars, options and other derivatives, in order to reduce exposure to substantial adverse changes in the prices of these commodities. These hedges are only intended to mitigate the risk associated with our natural physical position. We monitor and ensure compliance with this Risk Management Policy through senior level executives in our operations, finance and legal departments. Our Risk Management Policy includes the following provisions:
1. Anti-speculation
Speculative buying and selling of commodity or interest rate products is prohibited. “Speculation” includes, but is not limited to, buying or selling commodity or financial instruments that are not necessary for meeting forecasted production, consumption, or outstanding debt service.
2. Maximum Transaction Term
The maximum term of any hedging transaction should be five (5) years, unless specifically approved by our Board of Directors.
3. Maximum Transaction Volumes
Hedged commodity volumes are not to exceed 80% of the expected production or consumption in any settlement period, and hedged interest rates shall not exceed 80% of total outstanding indebtedness. Neither of these limitations shall be exceeded without the prior approval of the Board of Directors, which (with respect to commodity volumes) we did obtain for 2009 and 2010.
In any quarter, newly-hedged volumes (i.e., added during that quarter) shall not exceed 20% of the expected production, consumption, or indebtedness for any settlement period without the prior approval of the Board of Directors.
4. Portfolio Performance and Value Reporting
Our staff shall prepare performance reports containing an analysis of physical and financial positions of all energy price and interest rate hedge contracts for review by the Risk Management Committee and presentation to the Board of Directors. The frequency and content of performance reports shall be determined by the Risk Management Committee, but in no case will be done less frequently than quarterly.
Payment obligations in connection with our hedging transactions are secured by a first priority lien in the collateral securing our senior secured indebtedness that ranks equal in right of payment with liens granted in favor of our senior secured lenders. As long as this first priority lien is in effect, we will have no obligation to post cash, letters of credit, or other additional collateral to secure these hedges at any time even if our counterparty’s exposure to our credit increases over the term of the hedge as a result of higher commodity prices or because there has been a change in our creditworthiness.
See Note 11 to our consolidated financial statements included in Part II, Item 8 Financial Statements and Supplementary Data starting on page F-1 of this Annual Report for additional discussion of our commodity hedging activities.
We have not designated our contracts as accounting hedges based on authoritative guidance. As a result, we mark our
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derivatives to market with the resulting change in fair value included in our statement of operations.
We continually monitor our hedging and contract portfolio and expect to continue to adjust our hedge position as conditions warrant.
The following table, as of December 31, 2010, sets forth certain information regarding our commodity derivatives that will mature during the year ended December 31, 2011:
Underlying | Period | Notional Volumes (units) | Type | Floor Strike Price ($/unit) | Cap Strike Price ($/unit) | Fair Value | ||||||||||||
($ in thousands except volumes and $/unit) | ||||||||||||||||||
Natural Gas: | ||||||||||||||||||
NYMEX Henry Hub | Jan-Dec 2011 | 1,200,000 mmbtu | Costless Collar | $ | 7.50 | $ | 8.85 | $ | 3,171 | |||||||||
NYMEX Henry Hub | Jan-Dec 2011 | 720,000 mmbtu | Swap | 7.085 | 1,633 | |||||||||||||
NYMEX Henry Hub | Jan-Dec 2011 | 2,280,000 mmbtu | Swap | 6.57 | 4,128 | |||||||||||||
NYMEX Henry Hub | Jan-Dec 2011 | (408,000) mmbtu | Swap | 4.45 | 50 | |||||||||||||
Crude Oil: | ||||||||||||||||||
NYMEX WTI | Jan-Dec 2011 | 139,152 bbls | Costless Collar | 75.00 | 85.70 | (1,419 | ) | |||||||||||
NYMEX WTI | Jan-Dec 2011 | 360,000 bbls | Costless Collar | 80.00 | 92.40 | (1,837 | ) | |||||||||||
NYMEX WTI | Jan-Dec 2011 | 144,000 bbls | Costless Collar | 75.00 | 89.85 | (1,058 | ) | |||||||||||
NYMEX WTI | Jan-Dec 2011 | 125,256 bbls | Swap | 80.00 | (1,714 | ) | ||||||||||||
NYMEX WTI | Jan-Dec 2011 | 120,000 bbls | Swap | 65.10 | (3,371 | ) | ||||||||||||
NYMEX WTI | Jan-Dec 2011 | 60,000 bbls | Swap | 75.00 | (1,103 | ) | ||||||||||||
NYMEX WTI | Jan-Dec 2011 | 360,000 bbls | Swap | 65.60 | (9,938 | ) | ||||||||||||
NYMEX WTI | Jan-Dec 2011 | 204,000 bbls | Swap | 83.30 | (2,091 | ) | ||||||||||||
NYMEX WTI | Jan-Jun 2011 | 36,000 bbls | Swap | 86.20 | (246 | ) | ||||||||||||
Natural Gas Liquids: | ||||||||||||||||||
OPIS NButane Mt. Belv non TET | Jan-Dec 2011 | 11,592,000 gallons | Swap | 1.50 | (1,293 | ) | ||||||||||||
OPIS IsoButane Mt. Belv non TET | Jan-Dec 2011 | 5,544,000 gallons | Swap | 1.5425 | (650 | ) | ||||||||||||
OPIS Natural Gasoline Mt. Belv non TET | Jan-Dec 2011 | 4,536,000 gallons | Swap | 1.8525 | (1,121 | ) | ||||||||||||
OPIS Propane Mt. Belv non TET | Jan-Dec 2011 | 20,160,000 gallons | Swap | 1.1165 | (2,450 | ) | ||||||||||||
OPIS Propane Mt. Belv non TET | Jan-Dec 2011 | 3,024,000 gallons | Swap | 1.11 | (387 | ) | ||||||||||||
OPIS Ethane Mt. Belv non TET | Jan-Dec 2011 | 17,136,000 gallons | Swap | 0.545 | 168 | |||||||||||||
Total | $ | (19,528 | ) | |||||||||||||||
The following table, as of December 31, 2010, sets forth certain information regarding our commodity derivatives that will mature during the year ended December 31, 2012:
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Underlying | Period | Notional Volumes (units) | Type | Floor Strike Price ($/unit) | Cap Strike Price ($/unit) | Fair Value | ||||||||||||
($ in thousands except volumes and $/unit) | ||||||||||||||||||
Natural Gas: | ||||||||||||||||||
NYMEX Henry Hub | Jan-Dec 2012 | 1,080,000 mmbtu | Costless Collar | $ | 7.35 | $ | 8.65 | $ | 2,402 | |||||||||
NYMEX Henry Hub | Jan-Dec 2012 | 3,120,000 mmbtu | Swap | 6.77 | 5,179 | |||||||||||||
Crude Oil: | ||||||||||||||||||
NYMEX WTI | Jan-Dec 2012 | 135,576 bbls | Costless Collar | 75.30 | 86.30 | (1,515 | ) | |||||||||||
NYMEX WTI | Jan-Dec 2012 | 360,000 bbls | Costless Collar | 80.00 | 98.50 | (1,200 | ) | |||||||||||
NYMEX WTI | Jan-Dec 2012 | 192,000 bbls | Costless Collar | 75.00 | 94.75 | (1,197 | ) | |||||||||||
NYMEX WTI | Jan-Dec 2012 | 108,468 bbls | Swap | 80.30 | (1,447 | ) | ||||||||||||
NYMEX WTI | Jan-Dec 2012 | 240,000 bbls | Swap | 68.30 | (5,792 | ) | ||||||||||||
NYMEX WTI | Jan-Dec 2012 | 240,000 bbls | Swap | 76.50 | (3,938 | ) | ||||||||||||
NYMEX WTI | Jan-Dec 2012 | 240,000 bbls | Swap | 82.02 | (2,689 | ) | ||||||||||||
NYMEX WTI | Jan-Dec 2012 | 420,000 bbls | Swap | 90.65 | (1,292 | ) | ||||||||||||
Total | $ | (11,489 | ) | |||||||||||||||
The following table, as of December 31, 2010, sets forth certain information regarding our commodity derivatives that will mature during the year ended December 31, 2013:
Underlying | Period | Notional Volumes (units) | Type | Floor Strike Price ($/unit) | Cap Strike Price ($/unit) | Fair Value | ||||||||||
($ in thousands except volumes and $/unit) | ||||||||||||||||
Natural Gas: | ||||||||||||||||
NYMEX Henry Hub | Jan-Dec 2013 | 600,000 mmbtu | Swap | $ | 5.645 | $ | 169 | |||||||||
NYMEX Henry Hub | Jan-Dec 2013 | 600,000 mmbtu | Swap | 5.295 | (20 | ) | ||||||||||
NYMEX Henry Hub | Jan-Dec 2013 | 600,000 mmbtu | Swap | 5.305 | (15 | ) | ||||||||||
Crude Oil: | ||||||||||||||||
NYMEX WTI | Jan-Dec 2013 | 240,000 bbls | Swap | 90.20 | (585 | ) | ||||||||||
NYMEX WTI | Jan-Dec 2013 | 720,000 bbls | Swap | 89.85 | (1,980 | ) | ||||||||||
NYMEX WTI | Jan-Dec 2013 | 384,000 bbls | Swap | 90.75 | (746 | ) | ||||||||||
NYMEX WTI | Jan-Dec 2013 | 120,000 bbls | Swap | 88.20 | (507 | ) | ||||||||||
Total | $ | (3,684 | ) | |||||||||||||
Effectiveness of Commodity Risk Management Activities
The goal of our commodity risk management activities is to reduce the impact of changing commodity prices on our ability to make future distributions to our unitholders. One way we evaluate the effectiveness of these activities is to analyze the theoretical change in our internal estimates of future Adjusted EBITDA given an assumed change in future commodity prices. Using this method, we estimate that a $10 per barrel increase in NYMEX crude oil prices, a $10 per barrel decrease in NYMEX crude oil prices and a $1 per MMbtu change in NYMEX natural gas prices would result in changes to 2011 Adjusted EBITDA of $9.7 million, $5.3 million and $1.3 million, respectively, based on $80 per barrel and $4 per MMbtu commodity prices.
Users of this information should be aware that these estimates rely on a large number of assumptions that may ultimately prove to be false. These assumptions include, but are not limited to, future production rates, future volumes delivered to our plants and systems, future costs and other economic conditions, and future relationships between crude oil prices and natural gas liquids prices.
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Interest Rate Risk
We are exposed to variable interest rate risk as a result of borrowings under our existing credit agreement. To mitigate its interest rate risk, the Partnership has entered into various interest rate swaps. These swaps convert the variable-rate term loan into a fixed-rate obligation. The purpose of entering into these swaps is to eliminate interest rate variability by converting LIBOR-based variable-rate payments to fixed-rate payments. Amounts received or paid under these swaps were recorded as reductions or increases in interest expense.
On March 30, 2009, the Partnership amended all of its existing interest rate swaps to change the interest rate the Partnership received from three month LIBOR to one month LIBOR through January 9, 2011. During this time period, the fixed rate to be paid by the Partnership was reduced, on average, by 20 basis points. After January 9, 2011, the interest rate received by the Partnership changed back to three month LIBOR and the fixed rate the Partnership pays reverted back to the original rate and will remain at that rate through the end of swap maturities in 2012.
Based upon the transactions discussed in the paragraph above, we estimate that for 2011, a 10% increase or decrease in the current LIBOR rates would impact our interest expense by less than $0.1 million.
See Note 11 of our consolidated financial statements included in Part II, Item 8. Financial Statements and Supplementary Data starting on page F-1 of this Annual Report for additional discussion of our interest rate hedging activities.
The table below summarizes the terms, amounts received or paid and the fair values of the various interest swaps:
Roll Forward Effective Date | Expiration Date | Notional Amount | Fixed Rate(a) | Fair Market Value December 31, 2010 | ||||||||
($ in thousands except notional amount) | ||||||||||||
12/31/2008 | 12/31/2012 | $ | 150,000,000 | 2.36% / 2.56% | $ | (5,158 | ) | |||||
9/30/2008 | 12/31/2012 | 150,000,000 | 4.105% / 4.295% | (10,194 | ) | |||||||
10/3/2008 | 12/31/2012 | 300,000,000 | 3.895% / 4.095% | (19,227 | ) | |||||||
$ | (34,579 | ) | ||||||||||
(a) First amount is the interest rate we pay through January 9, 2011 and the second amount is the interest rate we pay from January 10, 2011 through December 31, 2012.
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The table below summarizes the changes in commodity and interest rate risk management assets for the applicable periods:
Year Ended 12/31/2010 | Year Ended 12/31/2009 | ||||||
($ in thousands) | |||||||
Net risk management assets at beginning of period | $ | (78,476 | ) | $ | 69,275 | ||
Investment premium payments (amortization), net | (3,957 | ) | (27,901 | ) | |||
Cash paid (received) to terminate contracts, net | 8,136 | 8,850 | |||||
Cash received (paid) from settled contracts | (36,981 | ) | 64,425 | ||||
Settlements of positions | 36,981 | (64,425 | ) | ||||
Unrealized mark-to-market valuations of positions | 5,017 | (128,700 | ) | ||||
Balance of risk management assets at end of period | $ | (69,280 | ) | $ | (78,476 | ) | |
Credit Risk
Our principal natural gas sales customers are large gas marketing companies that, in turn, typically sell to large end users such as local distribution companies and electrical utilities. With respect to the sale of our NGLs and condensates, our principle customers are large natural gas liquids purchasers, fractionators and marketers, and large condensate aggregators that then typically sell to large multi-national petrochemical and refining companies. We also sell a small amount of propane to medium sized, local distributors.
For the year ended December 31, 2010, ONEOK Hydrocarbon, our largest customer, represented 29% of our total sales revenue (including realized and unrealized gains on commodity derivatives). All of our natural gas sales are under 30 day term deals, with credit based upon 60 days of deliveries and almost all other product sales contracts are under 30 day term arrangements.
This concentration of credit risk may affect our overall credit risk in that these customers may be similarly affected by changes in the natural gas, natural gas liquids, petrochemical and other segments of the energy industry, the economy in general, the regulatory environment and other factors.
In evaluating credit risk exposure we analyze the financial condition of each counterparty before entering into an agreement. Our corporate credit policy lists the resource materials and information required to assess the financial condition of each prospective customer. The credit threshold for each customer is also based upon a time horizon for exposure, which is typically 60 days or less. We establish these credit limits and monitor and adjust them on an ongoing basis. We also require counterparties to provide letters of credit or other collateral financial agreements for exposure in excess of the established threshold. All of our sales agreements contain adequate assurance provisions to permit us to mitigate or eliminate future credit risk, at our sole discretion, by suspending deliveries until obligations and payments are satisfied or by canceling the agreement.
In July 2008, SemGroup, L.P. and certain of its subsidiaries (“SemGroup”) filed petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code. We historically sold portions of our condensate production from our Texas Panhandle and East Texas midstream systems to SemGroup. The abrupt bankruptcy of SemGroup caught us, the energy business and the financial community by surprise. We are not aware of any other measures that we could have taken to identify this risk at an earlier time. During the year ended December 31, 2008, we recorded a bad debt provision of $10.7 million related to our outstanding receivables from SemGroup. We discontinued all sales to SemGroup as of August 1, 2008, and as a result, we do not anticipate recording any additional bad debt charges in future periods.
Our derivative counterparties include BNP Paribas, Wells Fargo Bank, N.A., Comerica Bank, Barclays Bank PLC, The Royal Bank of Scotland plc, Bank of America N.A., J Aron & Company (an affiliate of Goldman Sachs), BBVA Compass Bank and Credit Suisse Energy LLC (an affiliate of Credit Suisse Group AG).
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Item 8. Financial Statements and Supplementary Data.
Our consolidated financial statements, together with the independent registered public accounting firm's report of Deloitte & Touche LLP (“Deloitte & Touche”), begin on page F-1 of this Annual Report.
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure.
None.
Item 9A. Controls and Procedures.
Disclosure Controls and Procedures
The Partnership maintains disclosure controls and procedures that are designed to ensure that information required to be disclosed in the Partnership's reports under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, and our Audit Committee of the Board of Directors, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and management is required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures. In addition, a control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the internal control system are met. Because of the inherent limitations of any internal control system, no evaluation of controls can provide absolute assurance that all control issues, if any, within a company have been detected.
Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures as of December 31, 2010. Based on the evaluation of our disclosure controls and procedures (as defined in the Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) required by Exchange Act Rules 13a-15(b) or 15d-15(b), our principal executive officer and principal financial officer have concluded that as of the end of the period covered by this report, our disclosure controls and procedures were effective at the reasonable assurance level to ensure that information we are required to disclose in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms, and include controls and procedures designed to ensure that information required to be disclosed by us in such reports is accumulated and communicated to our management, including the principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.
Management's Annual Report On Internal Control Over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting. Management has conducted (i) an evaluation of the design of our internal control over financial reporting, and (ii) a testing of the effectiveness of our internal control over financial reporting, as it pertains to the calendar year 2010. The evaluation and testing was conducted by our internal auditor, under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer. Our evaluation and testing followed the “Internal Control—Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Our evaluation and testing was conducted as of the year ended December 31, 2010, which is the period covered by this Annual Report on Form 10-K. Based on our assessment, we believe our internal controls over financial reporting are effective to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles based on the criteria of the COSO Framework.
There have been no changes in our internal control over financial reporting that occurred during the last quarter that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.
The Partnership's independent registered public accounting firm has issued an attestation report based on their assessment of the Partnership's internal control over financial reporting, which appears below.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors of Eagle Rock Energy G&P, LLC and Unitholders of Eagle Rock Energy Partners, L.P. Houston, Texas
We have audited the internal control over financial reporting of Eagle Rock Energy Partners, L.P. and subsidiaries (the Partnership) as of December 31, 2010, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Partnership's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Partnership's internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Partnership maintained in all material respects effective internal control over financial reporting as of December 31, 2010, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2010, of the Partnership and our report dated March 11, 2011 expressed an unqualified opinion on those financial statements and included an explanatory paragraph regarding the Partnership's change in its method of accounting for oil and gas reserves.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
March 11, 2011
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Item 9B. Other Information.
None.
PART III
Item 10. Directors, Executive Officers and Corporate Governance.
Information required to be set forth in Item 10. Directors, Executive Officers and Corporate Governance, has been omitted and will be incorporated herein by reference, when filed, to our proxy statement for our 2011 Annual Meeting of Unitholders to be filed no later than April 30, 2011.
Item 11. Executive Compensation.
Information required to be set forth in Item 11. Executive Compensation, has been omitted and will be incorporated herein by reference, when filed, to our proxy statement for our 2011 Annual Meeting of Unitholders to be filed no later than April 30, 2011.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters.
Information required to be set forth in Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters, has been omitted and will be incorporated herein by reference, when filed, to our proxy statement for our 2011 Annual Meeting of Unitholders to be filed no later than April 30, 2011.
Item 13. Certain Relationships and Related Transactions, and Director Independence.
Information required to be set forth in Item 13. Certain Relationships and Related Transactions, and Director Independence, has been omitted and will be incorporated herein by reference, when filed, to our proxy statement for our 2011 Annual Meeting of Unitholders to be filed no later than April 30, 2011.
Item 14. Principal Accounting Fees and Services.
Information required to be set forth in Item 14. Principal Accountant Fees and Services, has been omitted and will be incorporated herein by reference, when filed, to our proxy statement for our 2011 Annual Meeting of Unitholders to be filed no later than April 30, 2011.
136
PART IV
Item 15. Exhibits and Financial Statement Schedules.
(a)(1) Financial Statements:
The following financial statements and the Report of Independent Registered Public Accounting Firm are filed as a part of this report on the pages indicated:
(a)(2) Financial Statement Schedules:
All other schedules have been omitted since the required information is not significant or is included in the Consolidated Financial Statements or Notes thereto or is not applicable.
137
(a)(3) Exhibits:
The following documents are included as exhibits to this report:
Exhibit Number | Description |
2.1 | Purchase and Sale Agreement dated December 21, 2009 among Eagle Rock Pipeline GP,LLC, EROC Production, LLC and BSAP II GP, L.L.C. (incorporated by reference to Exhibit 2.1 of the registrant’s current report on Form 8-K filed with the Commission on December 21, 2009) |
3.1 | Certificate of Limited Partnership of Eagle Rock Energy Partners, L.P. (incorporated by reference to Exhibit 3.1 of the registrant’s registration statement on Form S-1 (File No. 333-134750)) |
3.2 | Second Amended and Restated Agreement of Limited Partnership of Eagle Rock Energy Partners, L.P. (incorporated by reference to Exhibit 3.1 of the registrant’s current report on Form 8-K filed with the Commission on May 25, 2010) |
3.3 | Certificate of Limited Partnership of Eagle Rock Energy GP, L.P. (incorporated by reference to Exhibit 3.3 of the registrant’s registration statement on Form S-1 (File No. 333-134750)) |
3.4 | Limited Partnership Agreement of Eagle Rock Energy GP, L.P. (incorporated by reference to Exhibit 3.4 of the registrant’s registration statement on Form S-1 (File No. 333-134750)) |
3.5 | Certificate of Formation of Eagle Rock Energy G&P, LLC (incorporated by reference to Exhibit 3.5 of the registrant’s registration statement on Form S-1 (File No. 333-134750)) |
3.6 | Third Amended and Restated Limited Liability Company Agreement of Eagle Rock Energy G&P, LLC (incorporated by reference to Exhibit 42 of the registrant’s current report on Form 8-K filed with the Commission on July 30, 2010) |
3.7 | Amendment No. 1 to the Second Amended and Restated Agreement of Limited Partnership of Eagle Rock Energy Partners, L.P. (incorporated by reference to Exhibit 4.1 of the registrant's current report on Form 8-K filed with the Commission on July 30, 2010) |
4.1 | Form of Common Unit Certificate (included as Exhibit A to the Second Amended and Restated Partnership Agreement of Eagle Rock Energy Partners, L.P.) (incorporated by reference to Exhibit 3.1 of the registrant’s current report on Form 8-K filed on May 25, 2010) |
4.2 | Form of Warrant Agent Agreement between Eagle Rock Energy Partners, L.P. and American Stock Transfer & Trust Company, LLC, as warrant agent (incorporated by reference to Exhibit 4.3 to the registrant's current report on Form 8-K filed on May 27, 2010) |
4.3 | Form of Warrant (included as Exhibit A to Exhibit 4.3 to the registrant's current report on Form 8-K filed on May 27, 2010) |
10.1** | Amended and Restated Eagle Rock Energy Partners, L.P. Long-Term Incentive Plan dated September 17, 2010 (incorporated by reference to Exhibit 10.1 of the registrant’s current report on Form 8-K filed on September 17, 2010) |
10.2† | Natural Gas Liquids Exchange Agreement by and between ONEOK Hydrocarbon, L.P. and ONEOK Texas Field Services, L.P. (Eagle Rock Field Services, L.P.) (incorporated by reference to Exhibit 10.5 of the registrant’s registration statement on Form S-1 (File No. 333-134750)) |
10.3 | Gas Sales and Purchase Agreement between MC Panhandle, Inc. (Chesapeake Energy Marketing Inc.) and MidCon Gas Services Corp. (Eagle Rock Field Services, L.P.) (incorporated by reference to Exhibit 10.6 of the registrant’s registration statement on Form S-1 (File No. 333-134750)) |
10.4 | Brookeland Gas Facilities Gas Gathering and Processing Agreement between Union Pacific Resources Company (Anadarko E&P Company LP) and Sonat Exploration Company (Eagle Rock Field Services, L.P.) (incorporated by reference to Exhibit 10.7 of the registrant’s registration statement on Form S-1 (File No. 333-134750)) |
10.5 | Gas Purchase Contract between Warren Petroleum Company (Eagle Rock Field Services, L.P.) and Wallace Oil & Gas, Inc. (Cimarex Energy Co.) (incorporated by reference to Exhibit 10.10 of the registrant’s registration statement on Form S-1 (File No. 333-134750)) |
10.6 | Base Contract for Sale and Purchase of Natural Gas between Eagle Rock Field Services, L.P. and Odyssey Energy Services, LLC (incorporated by reference to Exhibit 10.13 of the registrant’s registration statement on Form S-1 (File No. 333-134750)) |
10.7** | Form of Supplemental Indemnification Agreement among Eagle Rock Energy G&P, LLC, Eagle Rock Energy GP, L.P., Eagle Rock Energy Partners, L.P. and officers and directors of Eagle Rock Energy G&P, LLC (incorporated by reference to Exhibit 10.1 of the registrant’s current report on Form 8-K filed with the Commission on December 30, 2009) |
10.8**† | Eagle Rock Energy G&P, LLC 2010 Short Term Incentive Bonus Plan approved and adopted on December 30, 2009 (incorporated by reference to Exhibit 10.3 of the registrant’s current report on Form 8-K filed with the Commission on December 30, 2009) |
138
Exhibit Number | Description |
10.9 | Amended and Restated Securities Purchase and Global Transaction Agreement dated January 12, 2010 among Natural Gas Partners VII, L.P., Natural Gas Partners VIII, L.P., Montierra Minerals & Production, L.P., Montierra Management LLC, Eagle Rock Holdings, L.P., Eagle Rock Energy G&P, LLC, Eagle Rock Energy GP, L.P. and Eagle Rock Energy Partners, L.P. (incorporated by reference to Exhibit 10.1 of the registrant’s current report on Form 8-K filed with the Commission on January 12, 2010) |
10.10 | Credit Agreement dated December 13, 2007 among Eagle Rock Energy Partners, L.P. and Wachovia Bank, National Association, as administrative agent and swingline lender, Bank of America, N.A., as syndication agent, HSH Nordbank AG, New York Branch, the Royal Bank of Scotland, plc, and BNP Paribas, as co-documentation agents, and the other lenders who are parties thereto (incorporated by reference to Exhibit 10.17 of the Form 8-K filed with the Commission on December 13, 2007) |
10.11 | Credit Facility Amendment, dated as of March 8, 2010, by and among Eagle Rock Energy Partners, L.P., as borrower, Wachovia Back, N/A., Bank of America, N.A., HSH Nordbank AG, New York Branch, The Royal Bank of Scotland, PLC, BNP Paribas and the other lenders party threeto, and the Guarantors thereto (incorporated by reference to Exhibit 10.1 of the Registrant's Current Report on Form 8-K file with the Commisision on March 9, 2010) |
10.12 | Contribution Agreement, dated May 24, 2010, by and among the Partnership, Eagle Rock Holdings, L.P. and Eagle Rock Energy GP, L.P. (incorporated by reference to Exhibit 10.1 to the registrant's current report on Form 8-K filed on May 25, 2010) |
10.13** | Executive Change of Control Agreement Policy (incorporated by reference to Exhibit 10.1 to the registrant's current report on Form 8-K filed on July 28, 2010) |
10.14** | Form of Executive Change of Control Agreement (incorporated by reference to Exhibit 10.2 to the registrant's current report on Form 8-K filed on July 28, 2010) |
10.15 | Administrative Services Agreement, dated as of July 30, 2010, between Eagle Rock Energy Partners, L.P. and Eagle Rock Energy G&P, LLC (incorporated by reference to Exhibit 10.1 to the registrant's current report on Form 8-K filed on July 30, 2010) |
10.16** | Form of Restricted Unit Agreement for Non-Employee Directors Under the Eagle Rock Energy Partners Long-Term Incentive Plan (incorporated by reference to Exhibit 10.3 to the registrant's current report on Form 8-K filed on July 30, 2010) |
10.17** | Form of Restricted Unit Agreement for Officers under the Eagle Rock Energy Partners Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the registrant's current report on Form 8-K filed on July 30, 2010) |
10.18† | Amendment to Natural Gas Liquids Exchange Agreement by and between ONEOK Hydrocarbon, L.P. and Eagle Rock Field Services L.P. (successor to ONEOK Texas Field Services, L.P. dated December 3, 2010 (incorporated by reference to Exhibit 10.1 to the registrant's current report on Form 8-K filed on December 9, 2010) |
10.19**† | Eagle Rock Energy G&P, LLC 2011 Short Term Incentive Bonus Plan (incorporated by reference to Exhibit 10.1 to the registrant's current report on Form 8-K filed on February 14, 2011) |
14.1 | Code of Ethics for Chief Executive Officer and Senior Financial Officers posted on the Company’s website at www.eaglerockenergy.com. |
21.1* | List of Subsidiaries of Eagle Rock Energy Partners, L.P. |
23.1* | Consent of Deloitte & Touche LLP |
23.2* | Consent of Cawley, Gillespie & Associates, Inc. |
23.3* | Consent of K.E. Andrews & Company |
31.1* | Certification of Periodic Financial Reports by Joseph A. Mills in satisfaction of Section 302 of the Sarbanes-Oxley Act of 2002 |
31.2* | Certification of Periodic Financial Reports by Jeffrey P. Wood in satisfaction of Section 302 of the Sarbanes-Oxley Act of 2002 |
32.1* | Certification of Periodic Financial Reports by Joseph A. Mills in satisfaction of Section 906 of the Sarbanes-Oxley Act of 2002 |
32.2* | Certification of Periodic Financial Reports by Jeffrey P. Wood in satisfaction of Section 906 of the Sarbanes-Oxley Act of 2002 |
99.1* | Report of Cawley, Gillespie & Associates, Inc. |
* Filed herewith
** Management contract or compensatory plan or arrangement required to be filed as an exhibit hereto.
† Portions of this exhibit have been omitted pursuant to a request for confidential treatment.
139
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on March 11, 2011.
EAGLE ROCK ENERGY PARTNERS, L.P. | ||||
By: | Eagle Rock Energy GP, L.P., its general partner | |||
By: | Eagle Rock Energy G&P, LLC, its general partner | |||
By: | /s/ JOSEPH A. MILLS | |||
Name: | Joseph A. Mills | |||
Title: | Chief Executive Officer | |||
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacity and on the dates indicated:
Signature | Title | Date |
/s/ JOSEPH A. MILLS Joseph A. Mills | Chief Executive Officer (Principal Executive Officer) | March 11, 2011 |
/s/ JEFFREY P. WOOD Jeffrey P. Wood | Senior Vice President and Chief Financial Officer (Principal Financial and Accounting Officer) | March 11, 2011 |
/s/ PEGGY A. HEEG Peggy A. Heeg | Director | March 11, 2011 |
/s/ KENNETH A. HERSH Kenneth A. Hersh | Director | March 11, 2011 |
/s/ WILLIAM J. QUINN William J. Quinn | Director | March 11, 2011 |
/s/ PHILIP B. SMITH Philip B. Smith | Director | March 11, 2011 |
/s/ WILLIAM A. SMITH William A. Smith | Director | March 11, 2011 |
/s/ JOHN A. WEINZIERL John A. Weinzierl | Director | March 11, 2011 |
/s/ WILLIAM K. WHITE William K. White | Director | March 11, 2011 |
/s/ HERBERT C. WILLIAMSON III Herbert C. Williamson III | Director | March 11, 2011 |
140
INDEX TO FINANCIAL STATEMENTS
Eagle Rock Energy Partners, L.P. Consolidated Financial Statements: | |
F- 1
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors of Eagle Rock Energy G&P, LLC and Unitholders of Eagle Rock Energy Partners, L.P.
Houston, Texas
We have audited the accompanying consolidated balance sheets of Eagle Rock Energy Partners, L.P. and subsidiaries (the Partnership) as of December 31, 2010 and 2009, and the related consolidated statements of operations, members' equity, and cash flows for each of the three years in the period ended December 31, 2010. These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on the financial statements based on our audits.
We conducted our audits in accordance with standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Partnership as of December 31, 2010 and 2009, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 3 to the consolidated financial statements, on December 31, 2009, the Partnership changed its method of accounting for oil and gas reserves.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Partnership's internal control over financial reporting as of December 31, 2010, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 11, 2011 expressed an unqualified opinion on the Partnership's internal control over financial reporting.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
March 11, 2011
F- 2
CONSOLIDATED BALANCE SHEETS
AS OF DECEMBER 31, 2010 AND 2009
($ in thousands)
December 31, 2010 | December 31, 2009 | ||||||
ASSETS | |||||||
CURRENT ASSETS: | |||||||
Cash and cash equivalents | $ | 4,049 | $ | 2,732 | |||
Accounts receivable(a) | 77,810 | 88,122 | |||||
Risk management assets | — | 2,479 | |||||
Due from affiliates | — | 490 | |||||
Prepayments and other current assets | 2,498 | 2,790 | |||||
Assets held for sale | — | 135,224 | |||||
Total current assets | 84,357 | 231,837 | |||||
PROPERTY, PLANT AND EQUIPMENT — Net | 1,143,459 | 1,155,733 | |||||
INTANGIBLE ASSETS — Net | 113,914 | 132,343 | |||||
DEFERRED TAX ASSET | 1,969 | 1,562 | |||||
RISK MANAGEMENT ASSETS | 1,075 | 3,410 | |||||
OTHER ASSETS | 4,623 | 9,933 | |||||
TOTAL | $ | 1,349,397 | $ | 1,534,818 | |||
LIABILITIES AND MEMBERS' EQUITY | |||||||
CURRENT LIABILITIES: | |||||||
Accounts payable | $ | 93,591 | $ | 91,286 | |||
Due to affiliate | 56 | 60 | |||||
Accrued liabilities | 10,940 | 11,110 | |||||
Taxes payable | 1,102 | 2,416 | |||||
Risk management liabilities | 39,350 | 51,650 | |||||
Liabilities held for sale | — | 150 | |||||
Total current liabilities | 145,039 | 156,672 | |||||
LONG-TERM DEBT | 530,000 | 754,383 | |||||
ASSET RETIREMENT OBLIGATIONS | 24,711 | 19,829 | |||||
DEFERRED TAX LIABILITY | 38,662 | 40,246 | |||||
RISK MANAGEMENT LIABILITIES | 31,005 | 32,715 | |||||
OTHER LONG TERM LIABILITIES | 867 | 575 | |||||
COMMITMENTS AND CONTINGENCIES (Note 12) | |||||||
MEMBERS' EQUITY: | |||||||
Common Unitholders(b) | 579,113 | 484,282 | |||||
Subordinated Unitholders(c) | — | 52,058 | |||||
General Partner(c) | — | (5,942 | ) | ||||
Total members' equity | 579,113 | 530,398 | |||||
TOTAL | $ | 1,349,397 | $ | 1,534,818 | |||
________________________
(a) | Net of allowance for bad debt of $4,496 as of December 31, 2010 and $4,818 as of December 31, 2009. |
(b) | 83,425,378 and 54,203,471 units were issued and outstanding as of December 31, 2010 and 2009, respectively. These amounts do not include unvested restricted common units granted under the Partnership's long-term incentive plan of 1,744,454 and 1,371,019 as of December 31, 2010 and 2009, respectively. |
(c) | 20,691,495 subordinated units and 844,551 general partner units were issued and outstanding as of December 31, 2009. On May 24, 2010 and July 30, 2010, all of the subordinated and general partner units, respectively, were contributed to the Partnership and subsequently cancelled. |
See notes to consolidated financial statements.
F-3
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008
($ in thousands)
Years Ended December 31, | |||||||||||
2010 | 2009 | 2008 | |||||||||
REVENUE: | |||||||||||
Natural gas, natural gas liquids, oil, condensate and sulfur sales | $ | 712,795 | $ | 653,712 | $ | 1,233,919 | |||||
Gathering, compression, processing and treating fees | 51,951 | 45,476 | 38,871 | ||||||||
Commodity risk management (losses) gains | (8,786 | ) | (106,290 | ) | 161,765 | ||||||
Other revenue | 2,435 | 1,858 | 716 | ||||||||
Total revenue | 758,395 | 594,756 | 1,435,271 | ||||||||
COSTS AND EXPENSES: | |||||||||||
Cost of natural gas and natural gas liquids | 490,206 | 488,230 | 891,433 | ||||||||
Operations and maintenance | 77,898 | 73,196 | 73,620 | ||||||||
Taxes other than income | 12,240 | 10,766 | 18,228 | ||||||||
General and administrative | 45,775 | 45,819 | 45,618 | ||||||||
Other operating (income) expense | — | (3,552 | ) | 10,699 | |||||||
Impairment expense | 32,875 | 21,788 | 142,116 | ||||||||
Goodwill impairment | — | — | 30,994 | ||||||||
Depreciation, depletion and amortization | 108,781 | 110,255 | 108,980 | ||||||||
Total costs and expenses | 767,775 | 746,502 | 1,321,688 | ||||||||
OPERATING (LOSS) INCOME | (9,380 | ) | (151,746 | ) | 113,583 | ||||||
OTHER INCOME (EXPENSE): | |||||||||||
Interest income | 111 | 187 | 771 | ||||||||
Other income | 501 | 934 | 1,318 | ||||||||
Interest expense | (15,147 | ) | (21,591 | ) | (32,884 | ) | |||||
Interest rate risk management losses | (27,135 | ) | (6,347 | ) | (32,931 | ) | |||||
Other expense | (51 | ) | (1,070 | ) | (955 | ) | |||||
Total other (expense) income | (41,721 | ) | (27,887 | ) | (64,681 | ) | |||||
(LOSS) INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES | (51,101 | ) | (179,633 | ) | 48,902 | ||||||
INCOME TAX PROVISION (BENEFIT) | (2,545 | ) | 1,022 | (1,449 | ) | ||||||
(LOSS) INCOME FROM CONTINUING OPERATIONS | (48,556 | ) | (180,655 | ) | 50,351 | ||||||
DISCONTINUED OPERATIONS, NET OF TAX | 43,207 | 9,397 | 37,169 | ||||||||
NET (LOSS) INCOME | $ | (5,349 | ) | $ | (171,258 | ) | $ | 87,520 | |||
See notes to consolidated financial statements.
F-4
CONSOLIDATED STATEMENTS OF OPERATIONS (continued)
FOR THE YEARS ENDED December 31, 2010, 2009 AND 2008
(in thousands, except per unit amounts)
Years Ended December 31, | |||||||||||
2010 | 2009 | 2008 | |||||||||
NET (LOSS) INCOME PER COMMON UNIT—BASIC AND DILUTED: | |||||||||||
Basic: | |||||||||||
(Loss) Income from Continuing Operations | |||||||||||
Common units | $ | (0.59 | ) | $ | (2.38 | ) | $ | 0.67 | |||
Subordinated units | $ | (0.81 | ) | $ | (2.48 | ) | $ | 0.67 | |||
General partner units | $ | (0.72 | ) | $ | (2.38 | ) | $ | 0.67 | |||
Discontinued Operations | |||||||||||
Common units | $ | 0.55 | $ | 0.13 | $ | 0.51 | |||||
Subordinated units | $ | 0.55 | $ | 0.13 | $ | 0.51 | |||||
General partner units | $ | 0.55 | $ | 0.13 | $ | 0.51 | |||||
Net Income (Loss) | |||||||||||
Common units | $ | (0.04 | ) | $ | (2.26 | ) | $ | 1.18 | |||
Subordinated units | $ | (0.26 | ) | $ | (2.36 | ) | $ | 1.18 | |||
General partner units | $ | (0.17 | ) | $ | (2.26 | ) | $ | 1.18 | |||
Weighted Average Units Outstanding (in thousands) | |||||||||||
Common units | 68,625 | 53,496 | 51,534 | ||||||||
Subordinated units | 8,163 | 20,691 | 20,691 | ||||||||
General partner units | 488 | 845 | 845 | ||||||||
Diluted: | |||||||||||
(Loss) Income from Continuing Operations | |||||||||||
Common units | $ | (0.59 | ) | $ | (2.38 | ) | $ | 0.67 | |||
Subordinated units | $ | (0.81 | ) | $ | (2.48 | ) | $ | 0.67 | |||
General partner units | $ | (0.72 | ) | $ | (2.38 | ) | $ | 0.67 | |||
Discontinued Operations | |||||||||||
Common units | $ | 0.55 | $ | 0.13 | $ | 0.51 | |||||
Subordinated units | $ | 0.55 | $ | 0.13 | $ | 0.51 | |||||
General partner units | $ | 0.55 | $ | 0.13 | $ | 0.51 | |||||
Net (Loss) Income | |||||||||||
Common units | $ | (0.04 | ) | $ | (2.26 | ) | $ | 1.18 | |||
Subordinated units | $ | (0.26 | ) | $ | (2.36 | ) | $ | 1.18 | |||
General partner units | $ | (0.17 | ) | $ | (2.26 | ) | $ | 1.18 | |||
Weighted Average Units Outstanding (in thousands) | |||||||||||
Common units | 68,625 | 53,496 | 51,699 | ||||||||
Subordinated units | 8,163 | 20,691 | 20,691 | ||||||||
General partner units | 488 | 845 | 845 | ||||||||
See notes to consolidated financial statements.
F-5
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008
($ in thousands)
Years Ended December 31, | |||||||||||
2010 | 2009 | 2008 | |||||||||
CASH FLOWS FROM OPERATING ACTIVITIES: | |||||||||||
Net (loss) income | $ | (5,349 | ) | $ | (171,258 | ) | $ | 87,520 | |||
Adjustments to reconcile net (loss) income to net cash provided by operating activities: | |||||||||||
Discontinued Operations | (43,207 | ) | (9,397 | ) | (37,169 | ) | |||||
Depreciation, depletion and amortization | 108,781 | 110,255 | 108,980 | ||||||||
Impairment | 32,875 | 21,788 | 173,110 | ||||||||
Amortization of debt issuance costs | 1,305 | 1,068 | 958 | ||||||||
Equity in earnings of unconsolidated affiliates | 20 | (153 | ) | — | |||||||
Distribution from unconsolidated affiliates—return on investment | 67 | 164 | — | ||||||||
Reclassing financing derivative settlements | (1,131 | ) | (8,939 | ) | 11,063 | ||||||
Equity-based compensation | 5,407 | 6,685 | 7,694 | ||||||||
Gain of sale of assets | (371 | ) | (476 | ) | (1,265 | ) | |||||
Other operating income | — | (3,552 | ) | — | |||||||
Other | 196 | 210 | (1,618 | ) | |||||||
Changes in assets and liabilities—net of acquisitions: | |||||||||||
Accounts receivable | 10,431 | 20,351 | 41,040 | ||||||||
Prepayments and other current assets | 292 | (172 | ) | 941 | |||||||
Risk management activities | (9,195 | ) | 147,751 | (199,339 | ) | ||||||
Accounts payable | (4,025 | ) | (38,022 | ) | (40,255 | ) | |||||
Due to affiliates | 328 | 8,437 | (12,491 | ) | |||||||
Accrued liabilities | 41 | (6,411 | ) | (1,258 | ) | ||||||
Other assets | 1,058 | 1,487 | 23 | ||||||||
Other current liabilities | (763 | ) | (407 | ) | 836 | ||||||
Net cash provided by operating activities | 96,760 | 79,409 | 138,770 | ||||||||
CASH FLOWS FROM INVESTING ACTIVITIES: | |||||||||||
Additions to property, plant and equipment | (64,497 | ) | (36,134 | ) | (66,741 | ) | |||||
Acquisitions, net of cash acquired | (30,984 | ) | — | (262,245 | ) | ||||||
Proceeds from sale of asset | 171,686 | 476 | 1,294 | ||||||||
Purchase of intangible assets | (2,660 | ) | (1,626 | ) | (2,975 | ) | |||||
Net cash provided by (used in) investing activities | 73,545 | (37,284 | ) | (330,667 | ) | ||||||
CASH FLOWS FROM FINANCING ACTIVITIES: | |||||||||||
Proceeds from long-term debt | 90,617 | 131,000 | 432,128 | ||||||||
Repayment of long-term debt | (315,000 | ) | (176,000 | ) | (199,814 | ) | |||||
Payment of debt issuance costs | — | — | (789 | ) | |||||||
Proceeds from derivative contracts | 1,131 | 8,939 | (11,063 | ) | |||||||
Proceeds from Rights Offering | 53,893 | — | — | ||||||||
Transaction fees | (3,066 | ) | (1,480 | ) | — | ||||||
Exercise of warrants | 5,351 | — | — | ||||||||
Repurchase of common units | (1,177 | ) | (64 | ) | — | ||||||
Distributions to members and affiliates | (7,195 | ) | (35,655 | ) | (117,646 | ) | |||||
Net cash (used in) provided by financing activities | (175,446 | ) | (73,260 | ) | 102,816 | ||||||
CASH FLOWS FROM DISCONTINUED OPERATIONS: | |||||||||||
Operating activities | 6,562 | 17,532 | 42,381 | ||||||||
Investing activities | (104 | ) | (1,581 | ) | (3,936 | ) | |||||
Net cash provided by discontinued operations | 6,458 | 15,951 | 38,445 | ||||||||
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS | 1,317 | (15,184 | ) | (50,636 | ) | ||||||
CASH AND CASH EQUIVALENTS—Beginning of period | 2,732 | 17,916 | 68,552 | ||||||||
CASH AND CASH EQUIVALENTS—End of period | $ | 4,049 | $ | 2,732 | $ | 17,916 | |||||
Interest paid—net of amounts capitalized | $ | 14,272 | $ | 26,311 | $ | 29,822 | |||||
Units issued in acquisitions and from escrow for acquisitions | $ | 2,089 | $ | 3,000 | $ | 24,236 | |||||
Cash paid for taxes | $ | 1,923 | $ | 1,517 | $ | 705 | |||||
Issuance of common units for transaction fee | $ | 29,000 | $ | — | $ | — | |||||
Investments in property, plant and equipment, not paid | $ | 10,922 | $ | 3,761 | $ | 5,534 | |||||
Deferred tranasaction fees, not paid | $ | — | $ | 1,155 | $ | — | |||||
See notes to consolidated financial statements.
F-6
CONSOLIDATED STATEMENTS OF MEMBERS’ EQUITY
FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008
($ in thousands)
General Partner | Number of Common Units | Common Units | Number of Subordinated Units | Subordinated Units | Total | ||||||||||||||||
BALANCE — January 1, 2008 | $ | (3,155 | ) | 50,699,647 | $ | 617,563 | 20,691,495 | $ | 112,360 | $ | 726,768 | ||||||||||
Net income | 1,009 | — | 61,794 | — | 24,717 | 87,520 | |||||||||||||||
Equity issued in acquisitions | — | 2,181,818 | 24,236 | — | — | 24,236 | |||||||||||||||
Distribution to affiliates | — | — | (857 | ) | — | — | (857 | ) | |||||||||||||
Distributions | (1,643 | ) | — | (82,588 | ) | — | (33,415 | ) | (117,646 | ) | |||||||||||
Vesting of restricted units | — | 162,302 | — | — | — | — | |||||||||||||||
Equity-based compensation | 75 | — | 5,442 | — | 2,177 | 7,694 | |||||||||||||||
BALANCE — December 31, 2008 | (3,714 | ) | 53,043,767 | 625,590 | 20,691,495 | 105,839 | 727,715 | ||||||||||||||
Net loss | (1,921 | ) | — | (122,270 | ) | — | (47,067 | ) | (171,258 | ) | |||||||||||
Distributions | (379 | ) | — | (26,738 | ) | — | (8,538 | ) | (35,655 | ) | |||||||||||
Vesting of restricted units | — | 334,403 | — | — | — | — | |||||||||||||||
Repurchase of common units | — | (17,492 | ) | (64 | ) | — | — | (64 | ) | ||||||||||||
Equity-based compensation | 72 | — | 4,789 | — | 1,824 | 6,685 | |||||||||||||||
Units returned from escrow | — | (7,065 | ) | (25 | ) | — | — | (25 | ) | ||||||||||||
Units issued from escrow | — | 849,858 | 3,000 | — | — | 3,000 | |||||||||||||||
BALANCE — December 31, 2009 | (5,942 | ) | 54,203,471 | 484,282 | 20,691,495 | 52,058 | 530,398 | ||||||||||||||
Net income (loss) | 734 | — | (24,225 | ) | — | 18,142 | (5,349 | ) | |||||||||||||
Distributions | (483 | ) | — | (35,869 | ) | — | — | (36,352 | ) | ||||||||||||
Vesting of restricted units | — | 798,301 | — | — | — | — | |||||||||||||||
Rights offering | — | 21,557,164 | 53,893 | — | — | 53,893 | |||||||||||||||
Transaction costs for rights offering | — | — | (4,147 | ) | — | — | (4,147 | ) | |||||||||||||
Exercise of warrants | — | 891,919 | 5,351 | — | — | 5,351 | |||||||||||||||
Units released from escrow | — | 330,604 | 2,089 | — | — | 2,089 | |||||||||||||||
Repurchase of common units | — | (181,292 | ) | (1,177 | ) | — | — | (1,177 | ) | ||||||||||||
Equity based compensation | 43 | — | 4,570 | — | 794 | 5,407 | |||||||||||||||
Payment of tranaction fee to Eagle Rock Holdings, L.P. | — | 4,825,211 | 29,000 | — | — | 29,000 | |||||||||||||||
Cancellation of subordinated units | — | — | 70,994 | (20,691,495 | ) | (70,994 | ) | — | |||||||||||||
Acquisition of General Partner | 5,648 | 1,000,000 | (5,648 | ) | — | — | — | ||||||||||||||
BALANCE — December 31, 2010 | $ | — | 83,425,378 | $ | 579,113 | — | $ | — | $ | 579,113 | |||||||||||
See notes to consolidated financial statements.
F-7
EAGLE ROCK ENERGY PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008
NOTE 1. ORGANIZATION AND DESCRIPTION OF BUSINESS
Basis of Presentation and Principles of Consolidation—The accompanying financial statements include consolidated
assets, liabilities and the results of operations of Eagle Rock Energy Partners, L.P. (“Eagle Rock Energy” or the “Partnership”).
The general partner of Eagle Rock Energy is Eagle Rock Energy GP, L.P, and the general partner of Eagle Rock Energy GP,
L.P. is Eagle Rock Energy G&P, LLC, both of which became wholly-owned subsidiaries of the Partnership on July 30, 2010, as
further discussed in Notes 8 and 9. The transaction with Eagle Rock Energy GP, L.P. was accounted for by the Partnership as
a recapitalization. The acquisition of Eagle Rock Energy G&P, LLC was accounted for as an acquisition of entities under
common control, which requires the Partnership to present its financial statements as if the two entities had always been
combined, similar to the pooling of interests method. The balance sheet as of December 31, 2009 and the cash flow statements
for the year ended December 31, 2009 have been retrospectively adjusted to reflect the amounts due to Eagle Rock Energy G&P, LLC as accounts payable rather than due to affiliates. No retrospective adjustments were made to the statements of operations for the twelve months ended December 30, 2010, 2009 and 2008, as Eagle Rock Energy G&P, LLC did not have any operations outside of the services provided to and reimbursed by the Partnership through an omnibus agreement.
Recent Developments— On May 21, 2010, a majority of the Partnership's unaffiliated unitholders approved the Recapitalization and Related Transactions, as defined and further discussed in Note 9. As a result of this approval, the Partnership's subordinated units and incentive distribution rights were contributed and subsequently cancelled (see Note 8), and the Partnership consummated the sale of all of its fee mineral and royalty interests as well as its equity investment in Ivory Working Interests, L.P. (collectively, the "Minerals Business"). Operations related to the Minerals Business for the year ended December 31, 2010, have been recorded as part of discontinued operations. Financial information related to the Minerals Business for the years ended December 31, 2009 and 2008 have been retrospectively adjusted to be reflected as assets and liabilities held-for-sale and discontinued operations (see Notes 13 and 19). In addition, the Partnership launched a rights offering to the holders of its common units and general partner units on June 1, 2010, in which it distributed transferable subscription rights (“Rights”) to subscribe for common units and warrants to purchase additional common units. This rights offering expired on June 30, 2010, and the Partnership issued 21,557,164 common units and 21,557,164 warrants on or about July 8, 2010. See Note 8 for a further discussion of the rights offering.
Description of Business—Eagle Rock Energy is a growth-oriented limited partnership engaged in the business of gathering, compressing, treating, processing, transporting and selling natural gas, fractionating and transporting natural gas liquids, or NGLs (the “Midstream Business”) and the business of acquiring, developing and producing interests in oil and natural gas properties (the “Upstream Business”). The Partnership's natural gas pipelines gather natural gas from designated points near producing wells and transport these volumes to third-party pipelines, the Partnership's gas processing plants, utilities and industrial consumers. Natural gas transported to the Partnership's gas processing plants, either on the Partnership's pipelines or third party pipelines, is treated to remove contaminants and conditioned or processed into marketable natural gas and natural gas liquids. The Partnership conducts its midstream operations within Louisiana and three geographic areas of Texas and accordingly reports its Midstream Business results through four segments: the Texas Panhandle Segment, the South Texas Segment, the East Texas/Louisiana Segment and the Gulf of Mexico Segment. On October 1, 2008, the Partnership completed the acquisition of 100% of the outstanding units of Millennium Midstream Partners, L.P. (“MMP”) (see Note 4). The MMP assets include natural gas gathering and related compression and processing facilities in West Texas, Central Texas, East Texas, Southern Louisiana and the Gulf of Mexico that are now a part of the Partnership's East Texas/Louisiana Segment, South Texas Segment and which created the Partnership's Gulf of Mexico Segment.
On April 30, 2008, the Partnership completed the acquisition of all of the outstanding capital stock of Stanolind Oil and Gas Corp. (“Stanolind”). The Stanolind assets include operated oil and natural gas producing properties in the Permian Basin, primarily in Ward, Crane and Pecos Counties, Texas.
NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America. Eagle Rock Energy is the owner of a non-operating undivided interest in the Indian Springs gas processing plant and the Camp Ruby gas gathering system. Eagle Rock Energy owns these interests as tenants-in-common with the majority owner-operator of the facilities. Accordingly, Eagle Rock Energy includes its pro-rata share of assets, liabilities, revenues and expenses related to these assets in its financial statements. All intercompany accounts and transactions are eliminated in the consolidated financial statements.
F-8
Oil and Natural Gas Accounting Policies
The Partnership utilizes the successful efforts method of accounting for its oil and natural gas properties. Leasehold costs are capitalized when incurred. Costs incurred to drill and complete development wells are capitalized. Unproved properties are assessed periodically within specific geographic areas and, if necessary, impairments are charged to expense. Geological and geophysical expenses and delay rentals are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to expense if the well is determined to be unsuccessful. The Partnership carries the costs of an exploratory well as an asset if the well finds a sufficient quantity of reserves to justify its capitalization as a producing well as long as the Partnership is making sufficient progress towards assessing the reserves and the economic and operating viability of the project.
Depletion of producing oil and natural gas properties is recorded based on units of production. Unit rates are computed for unamortized drilling and development costs using proved developed reserves and for acquisition costs using all proved reserves. Authoritative guidance requires that acquisition costs of proved properties be amortized on the basis of all proved reserves, (developed and undeveloped) and that capitalized development costs (wells and related equipment and facilities) be amortized on the basis of proved developed reserves.
Upon sale or retirement of complete fields of depreciable or depleted property, the book value thereof, less proceeds or salvage value, is charged or credited to income.
Impairment of Oil and Natural Gas Properties
The Partnership reviews its proved properties at the field level when management determines that events or circumstances indicate that the recorded carrying value of the properties may not be recoverable. Such events include a projection of future oil and natural gas reserves that will be produced from a field, the timing of this future production, future costs to produce the oil and natural gas, and future inflation levels. If the carrying amount of an asset exceeds the sum of the undiscounted estimated future net cash flows, the Partnership recognizes impairment expense equal to the difference between the carrying value and the fair value of the asset, which is estimated to be the expected present value of discounted future net cash flows from proved reserves utilizing the Partnership's weighted average cost of capital. During the year ended December 31, 2010, the Partnership incurred impairment charges of $0.1 million in its Upstream Segment due to adjustments to reserves. During the year ended December 31, 2009, the Partnership incurred impairment charges of $8.1 million in its Upstream Segment, of which $7.9 million was a result of a decline in natural gas prices, production declines and lower natural gas liquids yields at its Flomaton field and $0.2 million in other fields due to lower natural gas prices. During the year ended December 31, 2008, the Partnership recorded impairment charges of $107.0 million in its Upstream Business as a result of substantial declines in commodity prices in the fourth quarter. The Partnership cannot predict the amount of additional impairment charges that may be recorded in the future.
Unproved leasehold costs are reviewed periodically and a loss is recognized to the extent, if any, that the cost of the property has been impaired. Unproved properties that are individually insignificant are amortized. Unproved properties that are individually significant are assessed for impairment on a property-by-property basis. If considered impaired, costs are charged to expense when such impairment is deemed to have occurred. During the year ended December 31, 2010, the Partnership recorded impairment charges of $3.4 million to certain fields in its unproved properties as the Partnership determined it would not be technologically feasible to develop these unproved locations.
Asset Retirement Obligations
The Partnership is required to make estimates of the future costs of the retirement obligations of its producing oil and natural gas properties. This requirement necessitates that the Partnership make estimates of property abandonment costs that, in some cases, will not be incurred until a substantial number of years in the future. Such cost estimates could be subject to significant revisions in subsequent years due to changes in regulatory requirements, technological advances and other factors that may be difficult to predict.
F-9
Other Significant Accounting Policies
Use of Estimates—The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reported period. Significant estimates are required for proved oil and natural gas reserves, which can affect the carrying value of oil and natural gas properties. The Partnership evaluates its estimates and assumptions on a regular basis. The Partnership bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results could differ from those estimates and such differences could be material.
Cash and Cash Equivalents—Cash and cash equivalents include certificates of deposit and other highly liquid investments with maturities of three months or less at the time of purchase.
Concentration and Credit Risk—Concentration and credit risk for the Partnership principally consists of cash and cash equivalents and accounts receivable.
The Partnership places its cash and cash equivalents with high-quality institutions and in money market funds. The Partnership derives its revenue from customers primarily in the natural gas industry. Industry concentrations have the potential to impact the Partnership's overall exposure to credit risk, either positively or negatively, in that the Partnership's customers could be affected by similar changes in economic, industry or other conditions. However, the Partnership believes the risk posed by this industry concentration is offset by the creditworthiness of the Partnership's customer base. The Partnership's portfolio of accounts receivable is comprised primarily of mid-size to large domestic corporate entities. The following is the activity within the Partnership's allowance for doubtful accounts during the years ended December 31, 2010, 2009 and 2008.
2010 | 2009 | 2008 | |||||||||
($ in thousands) | |||||||||||
Balance at beginning of period | $ | 4,818 | $ | 12,080 | $ | 1,046 | |||||
Charged to bad debt expense | (122 | ) | 535 | 11,136 | |||||||
Write-offs/adjustments charged to allowance | (200 | ) | (7,797 | ) | (102 | ) | |||||
Balance at end of period | $ | 4,496 | $ | 4,818 | $ | 12,080 | |||||
Of the $11.1 million charged to bad debt expense during the year ended December 31, 2008, $10.7 relates to outstanding receivables from SemGroup, L.P., which filed for bankruptcy in July 2008. During the year ended December 31, 2009, the Partnership wrote off $7.3 million related to SemGroup, L.P. This amount relates to the non-503(b)(9) claims and the portion of the receivables sold in August 2009 (see Note 18 for further discussion).
Certain Other Concentrations—The Partnership relies on natural gas producers for its Midstream Business's natural gas and natural gas liquid supply, with the top two producers (by segment) accounting for 24% of its natural gas supply in the Texas Panhandle Segment, 20% of its natural gas supply in the East Texas/Louisiana Segment and 62% of its natural gas supply in the South Texas Segment, and in the Gulf of Mexico Segment, three customers accounted for 84% of its natural gas supply for the year ended December 31, 2010. While there are numerous natural gas and natural gas liquid producers, and some of these producers are subject to long-term contracts, the Partnership may be unable to negotiate extensions or replacements of these contracts on favorable terms, if at all. If the Partnership were to lose all or even a portion of the natural gas volumes supplied by these producers and was unable to acquire comparable volumes, the Partnership's results of operations and financial position could be materially adversely affected. These percentages are calculated based on MMBtus gathered during the year ended December 31, 2010. For the year ended December 31, 2010, ONEOK Hydrocarbon, the Partnership's largest customer, represented 29% of its total sales revenue (including realized and unrealized gains on commodity derivatives).
Inventory—Inventory is stated at the lower of cost or market, with cost being determined using the standard cost method, which approximates actual costs on a first-in-first-out or average basis. At December 31, 2010, the Partnership had $0.5 million of crude oil finished goods inventory which is recorded as part of Other Current Assets within the Consolidated Balance Sheet.
F-10
Property, Plant, and Equipment—Property, plant, and equipment consists primarily of gas gathering systems, gas processing plants, NGL pipelines, conditioning and treating facilities and other related facilities, and oil and gas properties, which are carried at cost less accumulated depreciation, depletion and amortization. The Partnership charges repairs and maintenance against income when incurred and capitalizes renewals and betterments, which extend the useful life or expand the capacity of the assets. The Partnership calculates depreciation on the straight-line method over estimated useful lives of the Partnership's newly developed or acquired assets. The weighted average useful lives are as follows:
Plant Assets | 20 years |
Pipelines and equipment | 20 years |
Gas processing and equipment | 20 years |
Office furniture and equipment | 5 years |
The Partnership capitalizes interest costs on major projects during extended construction time periods. Such interest costs are allocated to property, plant and equipment and amortized over the estimated useful lives of the related assets. During the years ended December 31, 2010, 2009 and 2008, the Partnership capitalized interest costs of approximately $0.4 million, $0.1 million, and $0.4 million, respectively.
Impairment of Long-Lived Assets—Management evaluates whether the carrying value of non-oil and natural gas long-lived assets has been impaired when circumstances indicate the carrying value of those assets may not be recoverable. This evaluation is based on undiscounted cash flow projections. The carrying amount is not recoverable if it exceeds the undiscounted sum of cash flows expected to result from the use and eventual disposition of the assets. Management considers various factors when determining if these assets should be evaluated for impairment, including, but not limited to:
• | significant adverse change in legal factors or in the business climate; |
• | a current-period operating or cash flow loss combined with a history of operating or cash flow losses or a projection or forecast which demonstrates continuing losses associated with the use of a long-lived asset; |
• | an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of a long-lived asset; |
• | significant adverse changes in the extent or manner in which an asset is used or in its physical condition; |
• | a significant change in the market value of an asset; or |
• | a current expectation that, more likely than not, an asset will be sold or otherwise disposed of before the end of its estimated useful life. |
If the carrying value is not recoverable on an undiscounted basis, the impairment loss is measured as the excess of the asset's carrying value over its fair value. Management assesses the fair value of long-lived assets using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales, internally developed discounted cash flow analysis and analysis from outside advisors. Significant changes in market conditions resulting from events such as the condition of an asset or a change in management's intent to utilize the asset would generally require management to reassess the cash flows related to the long-lived assets. During the year ended December 31, 2010, the Partnership recorded impairment charges of $29.3 million related to its Midstream Business due to (i) $3.1 million due to the notification during the second quarter 2010 that a significant gathering contract on its Raymondville system in its South Texas Segment would be terminated during the third quarter of 2010 and (ii) $26.2 million due to an anticipated decline in volumes on its Wildhorse gathering system in the South Texas Segment. During the year ended December 31, 2009, the Partnership recorded impairment charges related to certain processing plants, pipelines and contracts in its Midstream business of $13.7 million due to reduced throughput volumes. During the year ended December 31, 2008, the Partnership recorded an impairment charge related to certain processing plants, pipelines and contracts in its Midstream business of $35.1 million due to the substantial decline in commodity prices in the fourth quarter as well as declining drilling activity by its producer customers. Due to the percent-of-proceeds, fixed recovery and keep-whole contract arrangements the Partnership operates under with some of its producer customers, cash flows are dependent up the selling price of the natural gas and natural gas liquids processed by its plants. Under these arrangements, lower commodity prices result in lower margins. In addition, lower commodity prices influence the drilling activity of the Partnership's producer customers. Lower drilling activity reduces the future volumes of natural gas projected to flow through the Partnership's gathering systems, thus reducing both the equity
F-11
volumes attributable to the Partnership and the fees generated under the fee-based arrangements the Partnership operates under as part of its Midstream Business.
Goodwill—Goodwill acquired in connection with business combinations represent the excess of consideration over the fair value of tangible net assets and identifiable intangible assets acquired. Certain assumptions and estimates are employed in determining the fair value of assets acquired and liabilities assumed, as well as in determining the allocation of goodwill to the appropriate reporting unit.
During the year ended December 31, 2008, the Partnership performed its annual impairment test in May 2008 and determined that no impairment appeared evident. The Partnership's goodwill impairment test involves a comparison of the fair value of each of its reporting units with their carrying value. The fair value is determined using discounted cash flows and other market-related valuation models. Certain estimates and judgments are required in the application of the fair value models. As a result of the impairment charge incurred within the Partnership's Upstream Segment during the fourth quarter of 2008 which resulted from the substantial decline in commodity prices during the fourth quarter of 2008, the Partnership performed an assessment of its goodwill and recorded an impairment charge of $31.0 million, which reduced its goodwill amount to zero. No such impairment was recorded in the years ended December 31, 2010 or 2009. At December 31, 2010, 2009 and 2008, the Partnership had gross goodwill of $31.0 million, $31.0 million and $31.0 million, respectively, and accumulated impairment losses of $31.0 million, $31.0 million and $31.0 million, respectively.
Other Assets— As of December 31, 2010, other assets primarily consist of costs associated with: debt issuance costs, net of amortization ($1.9 million); business deposits to various providers and state or regulatory agencies ($1.6 million); and investment in unconsolidated affiliates ($1.1 million). As of December 31, 2009, other assets primarily consist of costs associated with: debt issuance costs, net of amortization ($3.2 million); business deposits to various providers and state or regulatory agencies ($1.1 million); and investment in unconsolidated affiliates ($13.3 million).
Within the Partnership's investments of unconsolidated affiliates, the Partnership owns 5.0% of the common units of each of Buckeye Pipeline, L.P. and Trinity River, LLC. The Partnership also owns a 50% joint venture in Valley Pipeline, LLC. and Sweeny Gathering, L.P. These investments are accounted for under the equity method and as of December 31, 2010 are not considered material to the Partnership's financial position or results of operations.
Transportation and Exchange Imbalances—In the course of transporting natural gas and natural gas liquids for others, the Partnership may receive for redelivery different quantities of natural gas or natural gas liquids than the quantities actually delivered. These transactions result in transportation and exchange imbalance receivables or payables which are recovered or repaid through the receipt or delivery of natural gas or natural gas liquids in future periods, if not subject to cash out provisions. Imbalance receivables are included in accounts receivable and imbalance payables are included in accounts payable on the consolidated balance sheets and marked-to-market using current market prices in effect for the reporting period of the outstanding imbalances. For the Midstream Business, as of December 31, 2010, the Partnership had imbalance receivables totaling $0.8 million and imbalance payables totaling $1.2 million, respectively. For the Midstream business, as of December 31, 2009, the Partnership had imbalance receivables totaling $0.3 million and imbalance payables totaling $2.9 million, respectively. Changes in market value and the settlement of any such imbalance at a price greater than or less than the recorded imbalance results in either an upward or downward adjustment, as appropriate, to the cost of natural gas sold.
Revenue Recognition—Eagle Rock Energy's primary types of sales and service activities reported as operating revenue include:
• | sales of natural gas, NGLs, crude oil and condensate; |
• | natural gas gathering, processing and transportation, from which Eagle Rock Energy generates revenues primarily through the compression, gathering, treating, processing and transportation of natural gas; and |
• | NGL transportation from which the Partnership generates revenues from transportation fees. |
Revenues associated with sales of natural gas, NGLs, crude oil and condensate are recognized when title passes to the customer, which is when the risk of ownership passes to the customer and physical delivery occurs. Revenues associated with transportation and processing fees are recognized when the service is provided.
F-12
For gathering and processing services, Eagle Rock Energy either receives fees or commodities from natural gas producers depending on the type of contract. Under the percentage-of-proceeds contract type, Eagle Rock Energy is paid for its services by keeping a percentage of the NGLs produced and a percentage of the residue gas resulting from processing the natural gas. Commodities received are in turn sold and recognized as revenue in accordance with the criteria outlined above. Under the keep-whole contract type, Eagle Rock Energy purchases wellhead natural gas to return to the producer and sells processed natural gas and NGLs to third parties.
Transportation, compression and processing-related revenues are recognized in the period when the service is provided and include the Partnership's fee-based service revenue for services such as transportation, compression and processing.
The Partnership's Upstream Segment has elected the entitlements method to account for production imbalances. Imbalances occur when the Partnership sells more or less than its entitled ownership percentage of total production. In accordance with the entitlements method, any amount received in excess of the partnership's share is treated as a liability. If the Partnership receives less than its entitled share, the underproduction is recorded as a receivable. As of December 31, 2010, the Partnership's Upstream Segment had an imbalance receivable balance of $0.5 million. As of December 31, 2009, the Partnership's Upstream Segment had an imbalance receivable balance of $1.9 million and an imbalance payable balance of $0.5 million.
A significant portion of the Partnership's sale and purchase arrangements are accounted for on a gross basis in the consolidated statements of operations as natural gas sales and costs of natural gas, respectively. These transactions are contractual arrangements which establish the terms of the purchase of natural gas at a specified location and the sale of natural gas at a different location at the same or at another specified date. These arrangements are detailed either jointly, in a single contract, or separately in individual contracts which are entered into concurrently or in contemplation of one another with a single or multiple counterparties. Both transactions require physical delivery of the natural gas and the risk and reward of ownership are evidenced by title transfer, assumption of environmental risk, transportation scheduling, credit risk and counterparty nonperformance risk. Under authoritative guidance, purchase and sale agreements with the same counterparty are required to be recorded on a net basis. For the years ended December 31, 2010, 2009 and 2008, the Partnership did not enter into any purchase and sale agreements with the same counterparty.
Environmental Expenditures—Environmental expenditures are expensed or capitalized as appropriate, depending upon the future economic benefit. Expenditures which relate to an existing condition caused by past operations and do not generate current or future revenue are expensed. Liabilities for these expenditures are recorded on an undiscounted basis when environmental assessments and/or clean-ups are probable and the costs can be reasonably estimated.
Income Taxes—Provision for income taxes is primarily applicable to the Partnership's state tax obligations under the Revised Texas Franchise Tax (the “Revised Texas Franchise Tax”) and certain federal and state tax obligations of Eagle Rock Energy Acquisition Co., Inc. and Eagle Rock Upstream Development Company, Inc., both of which are consolidated subsidiaries. Deferred income tax assets and liabilities are recognized for temporary differences between the assets and liabilities of the tax paying entities for financial reporting and tax purposes.
In general, legal entities that conduct business in Texas are subject to the Revised Texas Franchise Tax. In May 2006, the State of Texas expanded its pre-existing franchise tax to include limited partnerships, limited liability companies, corporations and limited liability partnerships. As a result of the change in tax law, the Partnership's tax status in the State of Texas changed from non-taxable to taxable effective with the 2007 tax year.
Since the Partnership is structured as a pass-through entity, it is not subject to federal income taxes. As a result, its partners are individually responsible for paying federal and certain income taxes on their share of the Partnership's taxable income. Since the Partnership does not have access to information regarding each partner's tax basis, it cannot readily determine the total difference in the basis of the Partnership's net assets for financial and tax reporting purposes.
In accordance with authoritative guidance, the Partnership must recognize the tax effects of any uncertain tax positions it may adopt, if the position taken by it is more likely than not sustainable. If a tax position meets such criteria, the tax effect to be recognized by the Partnership would be the largest amount of benefit with more than a 50% chance of being realized upon settlement. This guidance was effective January 1, 2007, and the Partnership's adoption of this guidance had no material impact on its financial position, results of operations or cash flows. See Note 15 for additional information regarding the Partnership's income taxes.
F-13
Derivatives—Authoritative guidance establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. It requires an entity to recognize all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. The guidance provides that normal purchase and normal sale contracts, when appropriately designated, are not subject to the guidance. Normal purchases and normal sales are contracts which provide for the purchase or sale of something, other than a financial instrument or derivative instrument that will be delivered in quantities expected to be used or sold by the reporting entity over a reasonable period in the normal course of business. The Partnership's forward natural gas and crude oil purchase and sales contracts are designated as normal purchases and sales. Substantially all forward contracts fall within a one-month to four-year term; however, the Partnership does have certain contracts which extend through the life of the dedicated production. The terms of these contracts generally preclude unplanned netting. The Partnership uses financial instruments such as puts, swaps and other derivatives to mitigate the risks to cash flows resulting from changes in commodity prices and interest rates. The Partnership recognizes these financial instruments on its consolidated balance sheet at the instrument's fair value with changes in fair value reflected in the consolidated statement of operations, as the Partnership has not designated any of these derivative instruments as hedges. The cash flows from derivatives are reported as cash flows from operating activities unless the derivative contract is deemed to contain a financing element. Derivatives deemed to contain a financing element are reported as a financing activity in the statement of cash flows. See Note 11 for a description of the Partnership's risk management activities.
Fair Value Measurement—Authoritative guidance establishes accounting and reporting standards for assets and liabilities carried at fair value. The guidance provides definitions of fair value and expands the disclosure requirements with respect to fair value a specifies a hierarchy of valuation techniques based on the inputs used to measure fair value. See Note 10 for additional information regarding the Partnership's assets and liabilities carried at fair value.
NOTE 3. NEW ACCOUNTING PRONOUNCEMENTS
The Financial Accounting Standards Board (the “FASB”) has codified a single source of U.S. Generally Accepted Accounting Principles (U.S. GAAP), the Accounting Standards Codification. Unless needed to clarify a point to readers, the Partnership will refrain from citing specific section references when discussing application of accounting principles or addressing new or pending accounting rule changes.
In January 2010, the FASB issued updated authoritative guidance which aligns the current oil and natural gas reserve estimation and disclosure requirements of the Extractive Industries - Oil and Gas guidance, as discussed above. This guidance expands the disclosures required for equity method investments, revises the definition of oil- and natural gas-producing activities to include nontraditional resources in reserves unless not intended to be upgraded into synthetic oil or natural gas, amends the definition of proved oil and natural gas reserves to require 12-month average pricing in estimating reserves, amends and adds definitions in the Master Glossary that is used in estimating proved oil and natural gas quantities and provides guidance on geographic areas with respect to disclosure of information about significant reserves. This guidance must be applied prospectively as a change in accounting principle that is inseparable from a change in accounting estimate and is effective for entities with annual reporting periods ending on or after December 31, 2009. The Partnership adopted this guidance effective December 31, 2009. (See Note 21).
In June 2009, the FASB issued authoritative guidance which reflects the FASB’s response to issues entities have encountered when applying previous guidance. In addition, this guidance addresses concerns expressed by the SEC, members of the United States Congress, and financial statement users about the accounting and disclosures required in the wake of the subprime mortgage crisis and the deterioration in the global credit markets. In addition, because this guidance eliminates the exemption from consolidation for qualified special-purpose entities (“QSPEs”) a transferor will need to evaluate all existing QSPEs to determine whether they must be consolidated. This guidance was effective for the Partnership on January 1, 2010 and did not have a material impact on its consolidated financial statements
In June 2009, the FASB issued authoritative guidance, which amends the consolidation guidance applicable to variable interest entities ("VIEs"). The amendments will significantly affect the overall consolidation analysis. While the FASB’s discussions leading up to the issuance of this guidance focused extensively on structured finance entities, the amendments to the consolidation guidance affect all entities and enterprises, as well as qualifying special-purpose entities (QSPEs) that were excluded from previous guidance. Accordingly, an enterprise will need to carefully reconsider its previous conclusions, including (1) whether an entity is a VIE, (2) whether the enterprise is the VIE’s primary beneficiary, and (3) what type of financial statement disclosures are required. This guidance was effective for the Partnership on January 1, 2010 and did not have a material impact on its consolidated financial statements.
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In September 2009, the FASB issued a consensus which revises the standards for recognizing revenue on arrangements with multiple deliverables. Before evaluating how to recognize revenue for transactions with multiple revenue generating activities, an entity should identify all the deliverables in the arrangement and, if there are multiple deliverables, evaluate each deliverable to determine the unit of accounting and whether it should be treated separately or in combination. The consensus removes certain thresholds for separation, provides criteria for allocation of revenue amongst deliverables and expands disclosure requirements. This standard was effective for the Partnership on January 1, 2011 and will not have a material impact on the Partnership's consolidated financial statements.
In January 2010, the FASB issued additional guidance on fair value disclosures. The new guidance clarifies two existing disclosure requirements and requires new disclosures such as: (1) a “gross” presentation of activities (purchases, sales, and settlements) within the Level 3 rollforward reconciliation, which will replace the “net” presentation format; and (2) detailed disclosures about the transfers in and out of Level 1 and 2 measurements. This guidance is effective for the first interim or annual reporting period beginning after December 15, 2009, except for the gross presentation of the Level 3 rollforward information, which is required for annual reporting periods beginning after December 15, 2010, and for interim reporting periods within those years. The Partnership adopted the fair value disclosures guidance on January 1, 2010, except for the gross presentation of the Level 3 rollforward information which was not required to be adopted by the Partnership until January 1, 2011. The presentation of the table disclosing the assets and liabilities by hierarchy level as of December 31, 2009 has been changed to conform to the presentation as of December 31, 2010 (see Note 10).
NOTE 4. ACQUISITIONS
2010 Acquisitions
On September 30, 2010, the Partnership acquired certain additional interests in the Big Escambia Creek Field (and the
nearby Flomaton and Fanny Church Fields) from Indigo Minerals, LLC for $3.9 million in cash on hand. These interests are in wells in which the Partnership currently owns significant interests and are nearly 100% operated by the Partnership. The entire purchase price was allocated to proved properties.
On October 19, 2010, the Partnership acquired certain natural gas gathering systems and related facilities located primarily in Wheeler and Hemphill Counties in the Texas Panhandle from Centerpoint Energy Field Services, Inc. ("CEFS"). The closing purchase price for the assets was $27.0 million, subject to customary post-closing adjustments. The assets acquired include over 200 miles of gathering pipeline and related compression and dehydration facilities, together with gas gathering contracts, rights of way and other intangible assets. The assets are located in the core of the highly active and prolific Granite Wash play and are highly complementary to the Partnership's existing East Panhandle system.
The preliminary purchase price was allocated based on their respective fair value as determined by management with the assistance of K.E. Andrews & Company, a third-party valuation specialist. The purchase price allocation is set forth below (in thousands):
Property, plant and equipment | $ | 22,917 | |
Intangibles, rights-of-way | 4,583 | ||
Other current assets | 147 | ||
Other current liabilities | (344 | ) | |
Asset retirement obligations | (260 | ) | |
$ | 27,043 | ||
The Partnership commenced recording results of operations related to these assets acquired from CEFS on October 19, 2010.
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2008 Acquisitions
Update on Millennium Acquisition. On October 1, 2008, the Partnership completed the acquisition of 100% of the outstanding units of Millennium Midstream Partners, L.P. (“MMP”). MMP is in the natural gas gathering and processing business, with assets located in East, Central and West Texas and South Louisiana. With respect to the South Louisiana assets acquired in the acquisition, the Yscloskey and North Terrebonne facilities were flooded with three to four feet of water as a result of the storm surges caused by Hurricanes Ike and/or Gustav. The North Terrebonne facility came back on-line in November 2008 and the Yscloskey facility came back on-line in January 2009. The former owners of MMP provided the Partnership indemnity coverage for Hurricanes Gustav and Ike to the extent losses are not covered by insurance and established an escrow account of 1,818,182 common units and $0.6 million in cash available for the Partnership to recover against for this purpose. As of December 31, 2009, the escrow account held 391,304 common units. During the year ended December 31, 2010, the Partnership released 330,604 units out of escrow to the former owners of MMP and recovered the remaining 60,700 units held in escrow. As of December 31, 2010, the Partnership had an additional claim for $0.2 million cash out of escrow.
As a result of releasing the 330,604 units out of escrow to the former owners of MMP, the Partnership adjusted its purchase price allocation with respect to the Millennium Acquisition. As of December 31, 2010, the total purchase price was $212.9 million. With respect to the Millennium Acquisition, the Partnership increased the amount allocated to pipelines, plants
and intangibles by $1.2 million, $0.8 million and $0.3 million, respectively.
NOTE 5. PROPERTY PLANT AND EQUIPMENT AND ASSET RETIREMENT OBLIGATIONS
Fixed assets consisted of the following:
December 31, 2010 | December 31, 2009 | ||||||
($ in thousands) | |||||||
Land | $ | 2,629 | $ | 1,559 | |||
Plant | 251,499 | 242,223 | |||||
Gathering and pipeline | 676,047 | 675,474 | |||||
Equipment and machinery | 26,548 | 22,527 | |||||
Vehicles and transportation equipment | 4,251 | 4,232 | |||||
Office equipment, furniture, and fixtures | 1,120 | 1,248 | |||||
Computer equipment | 8,486 | 6,912 | |||||
Corporate | 126 | 126 | |||||
Linefill | 4,269 | 4,269 | |||||
Proved properties | 471,781 | 435,789 | |||||
Unproved properties | 1,304 | 7,264 | |||||
Construction in progress | 42,416 | 15,513 | |||||
1,490,476 | 1,417,136 | ||||||
Less: accumulated depreciation, depletion and amortization | (347,017 | ) | (261,403 | ) | |||
Net property plant and equipment | $ | 1,143,459 | $ | 1,155,733 | |||
Depreciation expense for the years ended December 31, 2010, 2009 and 2008 was approximately $55.9 million, $53.1 million and $44.1 million, respectively. Depletion expense for the year ended December 31, 2010, 2009 and 2008 was approximately $30.0 million, $33.7 million and $45.0 million, respectively. During the year ended December 31, 2010, the Partnership recorded impairment charges of $2.6 million related to its pipeline and plant assets due to the notification during the second quarter 2010 that a significant gathering contract in its South Texas Segment would be terminated during the third quarter of 2010, $23.6 million due to an anticipated decline in volumes on its Wildhorse gathering system in its South Texas Segment, $0.1 million of proved properties in its Upstream segment due to adjustments to reserves and $3.4 million of impairment charges related to unproved properties in the Upstream Segment due to the fact that the Partnership determined it would not be technologically feasible to develop these unproved locations. During the year ended December 31, 2009, the Partnership recorded impairment charges related to its pipeline assets and proved properties of $12.6 million and $8.1 million, respectively. During the year ended December 31, 2008, the Partnership recorded impairment charges related to its plants, gathering and pipeline assets and proved properties of $4.3 million, $19.5 million and $107.0 million, respectively.
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Asset Retirement Obligations—The Partnership recognizes asset retirement obligations for its oil and gas working interests associated with the retirement of tangible long-lived assets that result from the acquisition, construction and development of the assets. The Partnership records the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. The Partnership recognizes asset retirement obligations for its midstream assets in accordance with the term “conditional asset retirement obligation,” which refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional upon a future event that may or may not be within the Partnership's control. Although uncertainty about the timing and/or method of settlement may exist and may be conditional upon a future event, the obligation to perform the asset retirement activity is unconditional. Accordingly, the Partnership is required to recognize a liability for the fair value of a conditional asset retirement obligation upon initial recognition if the fair value of the liability can be reasonably estimated. As of December 31, 2009, the Partnership had $1.0 million restricted in an escrow account for purposes of settling associated asset retirement obligations in the State of Alabama, which was released out of escrow during the year ended December 31, 2010.
A reconciliation of the Partnership's liability for asset retirement obligations is as follows:
2010 | 2009 | 2008 | |||||||||
($ in thousands) | |||||||||||
Asset retirement obligations—January 1 | $ | 19,829 | $ | 19,872 | $ | 11,337 | |||||
Additional liability | 1,019 | — | 204 | ||||||||
Liabilities settled | (1,175 | ) | (1,324 | ) | — | ||||||
Revision to liabilities | 2,582 | — | — | ||||||||
Additional liability related to acquisitions | 663 | — | 7,260 | ||||||||
Accretion expense | 1,793 | 1,281 | 1,071 | ||||||||
Asset retirement obligations—December 31 | $ | 24,711 | $ | 19,829 | $ | 19,872 | |||||
During the year ended December 31, 2010, the Partnership made revisions of $2.6 million to increase certain asset retirement obligations due to changes in the estimate of the costs to remediate, as well as changes in the estimates of the timing of settlement.
NOTE 6. INTANGIBLE ASSETS
Intangible assets consist of right-of-ways and easements and acquired customer contracts, which the Partnership amortizes over the term of the agreement or estimated useful life. Amortization expense was approximately $22.8 million, $23.4 million and $19.9 million for the years ended December 31, 2010, 2009 and 2008, respectively. Estimated aggregate amortization expense for each of the five succeeding years is as follows: 2011—$12.1 million; 2012—$11.7 million; 2013—$10.5 million; 2014—$7.0 million; and 2015 —$7.0 million. Intangible assets consisted of the following (as of December 31, 2010 and 2009):
December 31, 2010 | December 31, 2009 | ||||||
($ in thousands) | |||||||
Rights-of-way and easements—at cost | $ | 91,942 | $ | 86,243 | |||
Less: accumulated amortization | (20,724 | ) | (15,600 | ) | |||
Contracts | 122,601 | 123,959 | |||||
Less: accumulated amortization | (79,905 | ) | (62,259 | ) | |||
Net intangible assets | $ | 113,914 | $ | 132,343 | |||
The amortization period for the Partnership's rights-of-way and easements is 20 years. The amortization period for contracts range from 5 to 20 years, and are approximately 8 years on average as of December 31, 2010. During the year ended December 31, 2010, the Partnership recorded impairment charges of $1.1 million related to rights-of-way and $1.6 million for contracts. During the year ended December 31, 2009, the Partnership recorded impairment charges related to its Rights-of-way and easements of $1.1 million. During the year ended December 31, 2008, the Partnership recorded impairment charges related to its rights-of-way and easements and contracts of $3.7 million and $7.6 million, respectively.
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NOTE 7. LONG-TERM DEBT
Long-term debt consisted of:
December 31, 2010 | December 31, 2009 | ||||||
($ in thousands) | |||||||
Revolving credit facility | $ | 530,000 | $ | 754,383 | |||
Total debt | 530,000 | 754,383 | |||||
Less: current portion | — | — | |||||
Total long-term debt | $ | 530,000 | $ | 754,383 | |||
On December 13, 2007, the Partnership entered into a senior secured revolving credit facility (the “Revolving Credit Facility”) with aggregate commitments of $800 million. During the year ended December 31, 2008, the Partnership exercised $180 million of its $200 million accordion feature of the Revolving Credit Facility, which increased the total commitment to $980 million. The Revolving Credit Facility was entered into with a syndicate of commercial and investment banks, led by Wachovia Capital Markets, LLC and Bank of America Securities LLC as joint lead arrangement agents and joint book runners. The Revolving Credit Facility provided for $980 million aggregate principal amount of revolving commitments and had a maturity date of December 13, 2012. The Revolving Credit Facility provided the Partnership with the ability to potentially increase the total amount of revolving commitments by an additional $20 million to a total of $1 billion. Subsequently, as a result of Lehman Brothers’ bankruptcy filing, the amount of available commitments was reduced by the unfunded portion of Lehman Brother's commitment in an amount of approximately $9.1 million to a total of $970.9 million and the potential increase in commitments was reduced by approximately $0.5 million to a total of approximately $19.5 million.
On March 8, 2010, the Partnership entered into the Second Amendment (the “Credit Facility Amendment”) to its Revolving Credit Facility. In connection with its unitholders' approval of the Global Transaction Agreement and related matters (see Note 9), the Credit Facility Amendment became effective.
The Credit Facility Amendment modified the definition of “Change in Control” in such a way that the exercising of the GP Acquisition Option, as defined in Note 9, did not trigger a “Change in Control” event and potential default. In addition to modifying the definition of “Change in Control,” the Credit Facility Amendment also:
• | reduced the maximum permitted Senior Secured Leverage Ratio (as such term is defined in the credit agreement) from 4.25 to 1.0 under the current credit agreement to 3.75 to 1.0 (and from 4.75 to 1.0 to 4.25 to 1.0 for specified periods following certain permitted acquisitions). The Senior Secured Leverage Ratio covenant is only relevant if the Partnership has unsecured senior or subordinated notes outstanding; |
• | obligated the Partnership to use $100 million of the proceeds from the sale of the Minerals Business (described in Note 19) to make a mandatory prepayment towards its outstanding borrowings under the revolving credit facility, which mandatory prepayment was made on May 25, 2010; and |
• | reduced, upon such mandatory prepayment, its borrowing capacity under the revolving credit facility by the $100 million amount of such mandatory prepayment to $880 million; however, this did not impact its availability under the Partnership's revolving credit facility because it is limited by compliance with financial covenants. |
The Credit Facility Amendment further clarifies that the proceeds from the sale of the Minerals Business in excess of$100 million may be used to immediately reduce debt, but will not result in a mandatory prepayment unless such proceeds are not reinvested in Property (as defined in the credit agreement) within the 270-day post-closing period (i.e. by February 18, 2011) provided in the credit agreement. On May 28, 2010, the Partnership repaid an additional $72 million towards its outstanding borrowings under the revolving credit facility from proceeds from the sale of the Minerals Business. The Partnership does not anticipate any further reductions in commitments under the Credit Facility resulting from the sale of the Minerals Business.
At the Partnership's election, its outstanding indebtedness bears interest on the unpaid principal amount either at a base rate plus the applicable margin (currently 0.75% per annum based on the Partnership's total leverage ratio and utilization of its borrowing base as part of its total indebtedness); or at the Adjusted Eurodollar Rate plus the applicable margin (currently
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1.875% per annum based on the Partnership's total leverage ratio and utilization of its borrowing base as part of its total indebtedness). At December 31, 2010, the weighted average interest rate on the Partnership's outstanding debt balance was 5.94%.
Base rate interest loans are paid the last day of each March, June, September and December. Eurodollar Rate Loans are paid the last day of each interest period, representing one-, two-, three-, six-, nine- or twelve months, as selected by the Partnership. The Partnership pays a commitment fee equal to (1) the average of the daily differences between (a) the revolver commitments and (b) the sum of the aggregate principal amount of all outstanding loans times (2) 0.30% per annum, based on its current leverage ratio and borrowing base utilization. The Partnership also pays a letter of credit fee equal to (1) the applicable margin for revolving loans which are Eurodollar Rate loans times (2) the average aggregate daily maximum amount available to be drawn under all such Letters of Credit (regardless of where any conditions for drawing could then be met and determined as of the close of business on any date of determination). Additionally, the Partnership pays a fronting fee equal to 0.125% per annum times the average aggregate daily maximum amount available to be drawn under all letters of credit.
The obligation under the Revolving Credit Facility are secured by first priority liens on substantially all for the Partnership's assets, including a pledge of all of the capital stock of each of its subsidiaries.
The Revolving Credit Facility contains various covenants which limit the Partnership's ability to grant liens, make certain loans and investments; make certain capital expenditures outside the Partnership's current lines of business or certain related lines of business; make distributions other than from available cash; merge or consolidate with or into a third party; or engage in certain asset dispositions, including a sale of all or substantially all of the Partnership's assets. Additionally, the Revolving Credit Facility limits the Partnership's ability to incur additional indebtedness with certain exceptions and purchase money indebtedness and indebtedness related to capital or synthetic leases not to exceed 2.5% of tangible net worth.
The Revolving Credit Facility also contains covenants, which, amount other things, require the Partnership, on a consolidated basis, to maintain specified ratios or conditions as follows:
• | Consolidated EBITDA (as defined) to Consolidated Interest Expense (as defined) of not less than 2.5 to 1.0; |
• | Total Funded Indebtedness (as defined) to Adjusted Consolidated EBITDA (as defined) of not more than 5.0 to 1.0 (5.25 to 1.0 for the three quarters following a material acquisition); and |
• | Borrowing Base Indebtedness (as defined) not to exceed the Borrowing Base (as defined) as re-determined from time to time. |
As of December 31, 2010, the Partnership was in compliance with the financial covenants under its revolving credit facility and has not been subject to mandatory repayments and/or a commitment reduction for asset and property sales, reductions in borrowing base and for insurance/condemnation proceeds.
The Partnership's credit facility accommodates, through the use of a borrowing base for its Upstream Business and traditional cash-flow based covenants for its Midstream Business, the allocation of indebtedness to either its Upstream Business (to be measured against the borrowing base) or to its Midstream Business (to be measured against the cash-flow based covenant.
On October 19, 2010, the Partnership announced that the borrowing base under its revolving credit facility, which relates to our Upstream Business, was set at $140 million by its commercial lenders as part of its regularly scheduled semi-annual borrowing base redetermination. This was an increase from the $130 million our borrowing base was set at during the April 2010 redetermination. The redetermined borrowing base was effective October 1, 2010, with no additional fees or increase in interest rate spread incurred.
Based upon total commitments as of December 31, 2010, the Partnership had approximately $341 million of unused capacity under the Revolving Credit Facility at December 31, 2010 on which the Partnership pays a 0.35% commitment fee per year.
The Revolving Credit Facility includes a sub-limit for the issuance of standby letters of credit for a total of $200 million. At December 31, 2010, the Partnership had $0.8 million of outstanding letters of credit.
In certain instances defined in the Revolving Credit Facility, the Partnership's outstanding debt is subject to mandatory repayments and/or is subject to a commitment reduction for asset and property sales, reductions in borrowing base and for insurance/
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condemnation proceeds.
During the year ended December 31, 2008, the Partnership incurred an additional $0.8 million of debt issuance costs in connection with exercising the accordion feature of the Revolving Credit Facility. During the years ended December 31, 2010, 2009 and 2008, the Partnership recorded approximately $1.3 million, $1.1 million and $1.0 million of debt issuance amortization expense, respectively. As of December 31, 2010 the unamortized amount of debt issuance cost was $1.9 million.
Scheduled maturities of long-term debt as of December 31, 2010, were as follows:
Principal Amount | |||
($ in thousands) | |||
2011 | — | ||
2012 | 530,000 | ||
$ | 530,000 | ||
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NOTE 8. MEMBERS’ EQUITY
At December 31, 2010, there were 83,425,378 common units outstanding. In addition, there were 1,744,454 restricted unvested common units outstanding.
As a result of the approval of certain of the Recapitalization and Related Transactions, as further discussed in Note 9, on May 24, 2010, the Partnership's general partner and Eagle Rock Holdings, L.P. ("Holdings") contributed to the Partnership all 20,691,495 of the outstanding subordinated units and all of the outstanding incentive distribution rights in the Partnership. In connection with the contribution of the subordinated units and incentive distribution rights, the Partnership (i) issued 4,825,211 common units to Holdings as payment of the transaction fee contemplated by the Global Transaction Agreement (as defined in Note 9) and (ii) adopted and entered into a Second Amended and Restated Agreement of Limited Partnership.
Pursuant to the Partnership's Second Amended and Restated Agreement of Limited Partnership, among other things: (i) the subordinated units and incentive distribution rights were cancelled; (ii) the concepts of a subordination period and a minimum quarterly distribution (and, as a result, the concept of arrearages on the common units) were eliminated; and (iii) provisions were included that provide the Partnership an option to acquire its general partner and its general partner entities, which were acquired on July 30, 2010, as further discussed below.
On June 1, 2010, the Partnership launched its rights offering and distributed 21,557,164 Rights to the holders of its common and general partner units as of close of business on May 27, 2010, the record date. Each common and general partner unitholder received 0.35 Rights for each unit held as of the record date. Each Right entitled the holder (including holders of Rights acquired during the subscription period) to purchase for $2.50 in cash (i) one common unit and (ii) one warrant to purchase one additional common unit at $6.00 on certain specified days beginning on August 15, 2010 and ending on May 15,
2012. The warrants are exercisable only on each March 15, May 15, August 15 and November 15 during the period in which
the warrants remain outstanding. The rights offering expired on June 30, 2010, and the Partnership issued 21,557,164 common
units and 21,557,164 warrants on or about July 8, 2010 for gross proceeds of $53.9 million. During the three months ended
September 30, 2010, the Partnership used the proceeds received from the rights offering to repay $50.0 million of outstanding
borrowings under the revolving credit facility. On August 15, 2010, 284,722 warrants were exercised for 284,722 newly issued
common units, for which the Partnership received proceeds of $1.7 million. On November 15, 2010, 607,197 warrants were exercised for 607,197 newly issued common units, for which the Partnership received proceeds of $3.6 million. As of December 31, 2010, 20,665,245 warrants were still outstanding.
On July 27, 2010, the Partnership gave notice to Holdings of its intention to exercise the GP Acquisition Option (as
defined in Note 9). The transaction closed on July 30, 2010, and the Partnership issued 1,000,000 common units to Holdings to
acquire the Partnership's general partner entities. As a result, the Partnership's 844,551 outstanding general partner units were
cancelled. In connection with the completion of the GP Acquisition Option, the Partnership's board of directors (the "Board")
was expanded to include two additional independent directors who were appointed by the Conflicts Committee on July 30,
2010.
During the year ended December 31, 2010, the Partnership released 330,604 common units that were previously held in an escrow account related to its acquisition of MMP to the former owners of MMP.
During the year ended December 31, 2009, the Partnership recovered and cancelled 7,065 common units that were being held in an escrow account related to its acquisition of MacLondon Energy, L.P. and released 849,858 common units that were previously held in an escrow account related to its Millennium Acquisition to the former owners of MMP.
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The Partnership has declared a cash distribution for each quarter since its initial public offering. The table below summarizes these distributions for the last three years.
Quarter Ended | Distribution per Unit | Record Date | Payment Date | |||||
March 31, 2008 | $ | 0.4000 | May 9, 2008 | May 15, 2008 | ||||
June 30, 2008 | $ | 0.4100 | August 8, 2008 | August 14, 2008 | ||||
September 30, 2008 | $ | 0.4100 | November 7, 2008 | November 14, 2008 | ||||
December 31, 2008 | $ | 0.4100 | February 10, 2009 | February 13, 2009 | ||||
March 31, 2009* | $ | 0.0250 | May 11, 2009 | May 15, 2009 | ||||
June 30, 2009* | $ | 0.0250 | August 10, 2009 | August 14, 2009 | ||||
September 30, 2009* | $ | 0.0250 | November 9, 2009 | November 13, 2009 | ||||
December 31, 2009* | $ | 0.0250 | February 8, 2010 | February 12, 2010 | ||||
March 31, 2010* | $ | 0.0250 | May 7, 2010 | May 14, 2010 | ||||
June 30, 2010* | $ | 0.0250 | August 9, 2010 | August 13, 2010 | ||||
September 30, 2010+ | $ | 0.0250 | November 8, 2010 | November 12, 2010 | ||||
December 31, 2010+ | $ | 0.1500 | February 7, 2011 | February 14, 2011 | ||||
______________________________
+ The distribution per unit represents distributions made only on common units.
* The distribution per unit represents distributions made only on common units and general partner units.
NOTE 9. RELATED PARTY TRANSACTIONS
During the year ended December 31, 2010, 2009 and 2008 the Partnership incurred $6.8 million, $8.8 million and $0.6 million, respectively, in expenses with related parties, of which there was an outstanding accounts payable balance of $0.5 million and $0.7 million as of December 31, 2010 and 2009, respectively.
Related to its investments in unconsolidated subsidiaries, during the year ended December 31, 2010 and 2009, the Partnership recorded income of less than $0.1 million for each of the periods. There were no outstanding accounts receivable balances as of December 31, 2010 and 2009.
The Partnership receives services from Stanolind Field Services ("SFS"), which was an entity controlled by Natural Gas Partners ("NGP"). On August 2, 2010, SFS ceased being a related party of the Partnership as NGP sold all of its interests in SFS. During the periods from January 1, 2010 through August 2, 2010 and during the years ended December 31, 2009 and 2008, the Partnership incurred approximately $0.6 million, $2.2 million and 2.1 million, respectively, for services performed by SFS. As of December 31, 2010 and 2009, there were no outstanding accounts payable balances.
As of December 31, 2010 and 2009, the Partnership had zero and $0.5 million, respectively, due from Holdings relating to payments made by the Partnership on Holdings' behalf.
As of December 31, 2010 and 2009, the Partnership had $0.1 million due to Sweeny Gathering, L.P. (the Partnership owns a 50% joint venture in this entity), for money the Partnership has collected on their behalf.
During 2009 and 2008, the Partnership leased office space from Montierra Minerals & Production, L.P. (“Montierra”), which is owned by NGP and certain members of the Partnership's senior management, including the Chief Executive Officer. During the years ended December 31, 2009 and 2008, the Partnership made rental payments of $0.1 million for each year. In addition, the Partnership was reimbursed by Montierra for services performed by its employees on behalf of Montierra of less than $0.1 million, $0.1 million and $0.2 million for the years ended December 31, 2010, 2009 and 2008, respectively. As of December 31, 2010 and 2009, no amounts were due to or from Montierra.
As of December 31, 2010 and 2009, the Partnership had an outstanding receivable balance of zero and $0.7 million, respectively, due from an affiliate of NGP.
In connection with the closing of the Partnership's initial public offering, on October 24, 2006, it entered into a registration rights agreement with Eagle Rock Holdings, L.P. in connection with its contribution to the Partnership of all of Eagle Rock Holdings, L.P.'s limited and general partner interests in Eagle Rock's predecessor. In the registration rights agreement, the Partnership agreed, for the benefit of Eagle Rock Holdings, L.P., to register the common units it holds, the
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common units issuable upon conversion of the subordinated units that it holds and any common units or other equity securities issuable in exchange for the common units and subordinated units it holds. The registration rights agreement is still in effect and the Partnership is in compliance with all obligations of the agreement.
In connection with the closing of the acquisition of certain fee minerals, royalties, overriding royalties and non-operated working interest properties from Montierra and NGP-VII Co-Investment Opportunities, L.P. ("Co-Invest"), the Partnership entered into a registration rights agreements with Montierra and Co-Invest. In the registration rights agreements, the Partnership agreed, for the benefit of Montierra and Co-Invest, to register the common units it holds, the common units issuable upon conversion of the subordinated units that it holds and any common units or other equity securities issuable in exchange for the common units and subordinated units it holds. The registration rights agreement is still in effect and the Partnership is in compliance with all obligations of the agreement.
On April 30, 2008, the Partnership completed the acquisition of all of the outstanding capital stock of Stanolind, for an aggregate purchase price of $81.8 million. Because of the potential conflict of interest between the interests of the Company and the public unitholders of Eagle Rock, the Board of Directors authorized the Company's Conflicts Committee to review, evaluate, and, if determined appropriate, approve the Stanolind Acquisition. The Conflicts Committee, consisting of independent Directors of the Company, determined that the Stanolind Acquisition was fair and reasonable to Eagle Rock and its public unitholders and recommended to the Board of Directors of the Company that the transaction be approved and authorized. In determining the purchase consideration for the Stanolind Acquisition, the Conflicts Committee considered the valuation of the properties involved in the transaction, the valuation of the units to be offered as consideration in the transaction, and the cash flow of Stanolind. Based on the recommendation of the Conflicts Committee, the Board of Directors approved the transaction.
Recapitalization and Related Transactions
On December 21, 2009, the Partnership announced that it, through certain of its affiliates, had entered into definitive agreements with affiliates of NGP and Black Stone Minerals Company, L.P. (“Black Stone”) to improve its liquidity and simplify its capital structure. The definitive agreements included: (i) a Securities Purchase and Global Transaction Agreement, entered into between Eagle Rock Energy and NGP, including Eagle Rock Energy's general partner entities controlled by NGP, and (ii) a Purchase and Sale Agreement (the “Minerals Business Sale Agreement”), entered into between Eagle Rock Energy and Black Stone for the sale of Eagle Rock Energy's Minerals Business. The Securities Purchase and Global Transaction Agreement was amended on January 12, 2010 to allow for greater flexibility in the payment of the contemplated transaction fee to Holdings, which is controlled by NGP (the Partnership refers to the amended Securities Purchase and Global Transaction Agreement as the “Global Transaction Agreement”). The Partnership refers to the transactions contemplated by the Global Transaction Agreement and Minerals Business Sale Agreement collectively as the “Recapitalization and Related Transactions.”
On May 21, 2010, at a reconvened special meeting of the Partnership's common unitholders, a majority of the Partnership's unaffiliated unitholders approved, among other things, the Recapitalization and Related Transactions.
The Recapitalization and Related Transactions included the following key provisions,
• | An option in favor of the Partnership, to issue 1,000,000 common units to capture the value of its controlling interest through (i) acquiring the Partnership's general partner, and such general partner's general partner, and thereafter canceling the 844,551 general partner units outstanding, and (ii) reconstituting its board of directors to allow its common unitholders to elect the majority of its directors (the “GP Acquisition Option”); |
• | The sale of the Partnership's Minerals Business to Black Stone for which we received net proceeds of $171.6 million. The Partnership retained approximately $2.9 million of cash received from net revenues received from the Minerals Business after the effective date of the sale, making its total proceeds from the sale of the Minerals Business $174.5 since January 1, 2010; |
• | The simplification of the Partnership's capital structure through the contribution, and resulting cancellation, of the incentive distribution rights and the approximate 20.7 million subordinated units held by Holdings; |
• | A rights offering for which Holdings and NGP agreed to fully participate with respect to 9.5 million common and general partner units owned or controlled by NGP as well as with respect to common units it received (see below) as payment of the transaction fee; and |
• | For a period of up to four months following unitholder approval of the amended Global Transaction |
F-23
Agreement, NGP's commitment to back-stop (primarily through Holdings) up to $41.6 million, at a price of $3.10 per unit, an Eagle Rock Energy equity offering to be undertaken at the sole option of the Partnership's Conflicts Committee.
In exchange for NGP's and Holdings' contributions and commitments under the Global Transaction Agreement, Eagle Rock paid Holdings a transaction fee of $29 million in newly-issued common units. The units were valued at $6.0101 per unit, based on 90% of the volume-adjusted trailing 10-day average of the trading price of Eagle Rock's common units as of April 24, 2010, resulting in a total of approximately 4.8 million common units paid to Holdings upon completion of the Minerals Business sale on May 24, 2010.
The sale of the Minerals Business closed on May 24, 2010, and the Partnership received $171.6 million in net proceeds (after consideration of approximately $2.9 million of net revenues received from the Minerals Business after the effective date) (see Note 17).
The subordinated units and incentive distribution rights were contributed and subsequently cancelled on May 24, 2010
(see Note 8).
The rights offering was launched on June 1, 2010 and expired on June 30, 2010 (see Note 8).
On July 27, 2010, the Partnership gave notice to Holding of its intention to exercise the GP Acquisition Option. On July 30, 2010, the Partnership closed the acquisition and cancelled the general partner units (see Note 8).
NGP's commitment to back-stop an Eagle Rock Energy equity offering expired on September 21, 2010.
See Note 7 for a discussion of an amendment to the Partnership's revolving credit facility related to the Recapitalization and Related Transactions.
See Note 12 for a discussion of a settled lawsuit that alleged certain claims related to the Recapitalization and Related
Transactions.
In connection with the Recapitalization and Related Transactions, the Partnership incurred legal (not including related litigation costs), accounting, advisory and similar costs, beginning in May 2009 through December 31, 2010, totaling
$6.6 million. Of these costs, the Partnership expensed $2.5 million, of which $0.4 million was recorded as part of discontinued operations, and capitalized $4.1 million as transactions costs within Members' Equity.
F-24
NOTE 10. FAIR VALUE OF FINANCIAL MEASUREMENTS
Effective January 1, 2008, the Partnership adopted authoritative guidance which, among other things, requires enhanced disclosures about assets and liabilities carried at fair value.
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Partnership utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk inherent in the inputs to the valuation technique. The authoritative guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements).
The three levels of the fair value hierarchy are as follows:
Level 1 – Quoted prices are available in active markets for identical assets and liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide information on an ongoing basis.
Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the market place throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.
Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management's best estimate of fair value.
As of December 31, 2010, the Partnership has recorded its interest rate swaps and commodity derivative instruments (see Note 11), which includes crude oil, natural gas and natural gas liquids (“NGLs”), at fair value. The Partnership has classified the inputs to measure the fair value of its interest rate swap, crude oil derivatives and natural gas derivatives as Level 2. Because the NGL market is thinly traded and considered to be less liquid, the Partnership has classified the inputs related to its NGL derivatives as Level 3. The following table discloses the fair value of the Partnership's derivative instruments as of December 31, 2010 and 2009:
As of December 31, 2010 | |||||||||||||||||||
Level 1 | Level 2 | Level 3 | Netting(a) | Total | |||||||||||||||
($ in thousands) | |||||||||||||||||||
Assets: | |||||||||||||||||||
Crude oil derivatives | $ | — | $ | — | $ | — | $ | (1,292 | ) | $ | (1,292 | ) | |||||||
Natural gas derivatives | — | 16,731 | — | (14,364 | ) | 2,367 | |||||||||||||
NGL derivatives | — | — | 168 | (168 | ) | — | |||||||||||||
Total | $ | — | $ | 16,731 | $ | 168 | $ | (15,824 | ) | $ | 1,075 | ||||||||
Liabilities: | |||||||||||||||||||
Crude oil derivatives | $ | — | $ | (45,664 | ) | $ | — | $ | 1,292 | $ | (44,372 | ) | |||||||
Natural gas derivatives | — | (35 | ) | — | 14,364 | 14,329 | |||||||||||||
NGL derivatives | — | — | (5,901 | ) | 168 | (5,733 | ) | ||||||||||||
Interest rate swaps | — | (34,579 | ) | — | — | (34,579 | ) | ||||||||||||
Total | $ | — | $ | (80,278 | ) | $ | (5,901 | ) | $ | 15,824 | $ | (70,355 | ) | ||||||
__________________________
(a) | Represents counterparty netting under agreements governing such derivative contracts. |
F-25
As of December 31, 2009 | |||||||||||||||||||
Level 1 | Level 2 | Level 3 | Netting(a) | Total | |||||||||||||||
($ in thousands) | |||||||||||||||||||
Assets: | |||||||||||||||||||
Crude oil derivatives | $ | — | $ | 9,089 | $ | — | (9,086 | ) | $ | 3 | |||||||||
Natural gas derivatives | — | 8,761 | — | (3,475 | ) | 5,286 | |||||||||||||
Interest rate swaps | — | 600 | — | — | 600 | ||||||||||||||
Total | $ | — | $ | 18,450 | $ | — | $ | (12,561 | ) | $ | 5,889 | ||||||||
Liabilities: | |||||||||||||||||||
Crude oil derivatives | $ | — | $ | (54,125 | ) | $ | — | 9,086 | $ | (45,039 | ) | ||||||||
Natural gas derivatives | — | — | — | 3,475 | 3,475 | ||||||||||||||
NGL derivatives | — | — | (14,784 | ) | — | (14,784 | ) | ||||||||||||
Interest rate swaps | — | (28,017 | ) | — | — | (28,017 | ) | ||||||||||||
Total | $ | — | $ | (82,142 | ) | $ | (14,784 | ) | $ | 12,561 | $ | (84,365 | ) | ||||||
__________________________
(a) | Represents counterparty netting under agreements governing such derivative contracts. |
The fair value hierarchy of derivative assets and liabilities presented as of December 31, 2009 has been changed from the previously presented 2009 disclosures to reflect gross assets and liabilities reconciled to the net presentation in the consolidated balance sheet due to counterparty netting under agreements governing such derivative contracts.
As of December 31, 2010 and 2009, risk management current assets in the Consolidated Balance Sheet include put premiums and other derivative costs, net of amortization, of zero and $4.0 million, respectively.
The following table sets forth a reconciliation of changes in the fair value of the Level 3 NGL derivatives during the years ended December 31, 2010, 2009 and 2008 (in thousands):
Year Ended December 31, | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
Net asset (liability) balance as of January 1 | $ | (14,784 | ) | $ | 14,016 | $ | (52,793 | ) | ||||
Settlements | 12,358 | 66 | 16,098 | |||||||||
Total gains or losses (realized and unrealized) | (3,307 | ) | (28,866 | ) | 50,711 | |||||||
Net (liability) asset balance as of December 31 | $ | (5,733 | ) | $ | (14,784 | ) | $ | 14,016 | ||||
The Partnership values its Level 3 NGL derivatives using forward curves, volatility curves, volatility skew parameters, interest rate curves and model parameters. In addition, the impact of counterparty credit risk is factored into the value of derivative assets and the Partnership's credit risk is factored into the value of derivative liabilities.
The Partnership recognized (losses) gains of $(5.7) million, $(15.2) million, and $50.0 million in the years ended December 31, 2010, 2009 and 2008, respectively, that are attributable to the change in unrealized gains or losses related to those assets and liabilities still held at December 31, 2010, 2009 and 2008, which are included in the commodity risk management (losses) gains.
Realized and unrealized losses related to the interest rate derivatives are recorded as part of interest rate risk management gains and losses in the Consolidated Statements of Operations. Realized and unrealized gains and losses and premium amortization related to the Partnership's commodity derivatives are recorded as a component of revenue in the Consolidated Statements of Operations.
F-26
The following table discloses the fair value of the Partnership's assets measured at fair value on a nonrecurring basis for the year ended December 31, 2010 (in thousands):
December 31, 2010 | Level 1 | Level 2 | Level 3 | Total Losses | |||||||||||||||
Plant assets | $ | 131 | $ | — | $ | — | $ | 131 | $ | 725 | |||||||||
Pipeline assets | $ | 6,498 | $ | — | $ | — | $ | 6,498 | $ | 25,410 | |||||||||
Rights-of-way | $ | 85 | $ | — | $ | — | $ | 85 | $ | 1,609 | |||||||||
Contracts | $ | — | $ | — | $ | — | $ | — | $ | 1,595 | |||||||||
Unproved properties | $ | — | $ | — | $ | — | $ | — | $ | 3,432 | |||||||||
Proved properties | $ | 132 | $ | — | $ | — | $ | 132 | $ | 104 | |||||||||
In connection with the preparation of these financial statements for the year ended December 31, 2010, the Partnership wrote down plant assets with a carrying value of $0.9 million to their fair value of $0.1 million, pipeline assets with a carrying value of $31.9 million to their fair value of $6.5 million, rights-of-way with a carrying value of $1.7 million to their fair value of $0.1 million, contracts with a carrying value of $1.6 million to their fair value of zero, proved properties with a carrying value of $0.2 million to their fair value of $0.1 million and unproved properties with a carrying value of $3.4 million to their fair value of zero, resulting in an impairment charge of $32.9 million being included in earnings for the year ended December 31, 2010. The impairment charges related to plant assets, pipeline assets, rights-of-way and contracts related specifically to the Midstream Business due to the loss during the second quarter 2010 of a significant contract on the Partnership's Raymondville system within its South Texas Segment and due to an anticipated decline in volumes on the Partnership's Wildhorse gathering system within its South Texas Segment, while the impairment of the Upstream Segment's unproved properties was due to the Partnership determining that it was not technologically feasible to develop these unproved locations and the Upstream Segment's proved properties was due to adjustments to its reserves. The Partnership calculated the fair value of the impaired assets on its Raymondville system and its proved properties using discounted cash flow analysis to determine the excess of the asset's carrying value over its fair value. The Partnership calculated the fair value of the impaired assets on its Wildhorse gathering system based on an unsolicited value of the system provided by a market participant.
The carrying amount of cash equivalents is believed to approximate their fair values because of the short maturities of these instruments. The fair value of accounts receivable and accounts payable are not materially different from their carrying amounts because of the short-term nature of these instruments.
The Partnership believes that the fair value of its Revolving Credit Facility does not approximate its carrying value as of December 31, 2010 because the applicable floating rate margin on the Revolving Credit Facility was a below-market rate. The fair value of the Revolving Credit Facility has been estimated based on similar transactions that occurred during the twelve months ended December 31, 2010 and the first two months of 2011. The Partnership's estimate of the fair value of the borrowings under its Revolving Credit Facility as of December 31, 2010 was $518.0 million versus a carrying value of $530.0 million. The Partnership's estimate of the fair value of the borrowings under its Revolving Credit Facility as of December 31, 2009 was $713.2 million versus a carrying value of $754.4 million.
NOTE 11. RISK MANAGEMENT ACTIVITIES
To mitigate its interest rate risk, the Partnership entered into various interest rate swaps. These swaps convert the variable-rate term loan into a fixed-rate obligation. The purpose of entering into these swaps is to eliminate interest rate variability by converting LIBOR-based variable-rate payments to fixed-rate payments. Amounts received or paid under these swaps were recorded as reductions or increases in interest expense.
On March 30, 2009, the Partnership amended all of its existing interest rate swaps to change the interest rate the Partnership received from three month LIBOR to one month LIBOR through January 9, 2011. During this time period, the fixed rate to be paid by the Partnership was reduced, on average, by 20 basis points. After January 9, 2011, the interest rate to be received by the Partnership changed back to three month LIBOR, and the fixed rate the Partnership pays reverted back to the original rate through the end of swap maturities in 2012.
F-27
The table below summarizes the terms, amounts received or paid and the fair values of the various interest rate swaps:
Effective Date | Expiration Date | Notional Amount | Fixed Rate (a) | |||||
12/31/2008 | 12/31/2012 | $ | 150,000,000 | 2.360% / 2.560% | ||||
9/30/2008 | 12/31/2012 | 150,000,000 | 4.105% / 4.295% | |||||
10/3/2008 | 12/31/2012 | 300,000,000 | 3.895% / 4.095% | |||||
_________________________________
(a) | First amount is the rate the Partnership pays through January 9, 2011 and the second amount is the interest rate the Partnership pays from January 10, 2011 through December 31, 2012. |
The Partnership's interest rate derivative counterparties include Wells Fargo Bank N.A. and The Royal Bank of Scotland plc.
Commodity Derivative Instruments
The prices of crude oil, natural gas and NGLs are subject to fluctuations in response to changes in supply, demand, market uncertainty and a variety of additional factors which are beyond the Partnership's control. These risks can cause significant changes in the Partnership's cash flows and affect its ability to achieve its distribution objective and comply with the covenants of its revolving credit facility. In order to manage the risks associated with the future prices of crude oil, natural gas and NGLs, the Partnership engages in non-speculative risk management activities that take the form of commodity derivative instruments. The Partnership has determined that it is necessary to hedge a substantial portion of its expected production in order to meaningfully reduce its future cash flow volatility. The Partnership generally limits its hedging levels to 80% of expected future production. While hedging at this level of production does not eliminate all of the volatility in the Partnership's cash flows, it allows the Partnership to mitigate the risk of situations where a modest loss of production would put it in an over-hedged position. The Partnership may hedge for periods of time above the 80% of expected future production levels where it deems it prudent to reduce extreme future price volatility. However, hedging to that level requires approval of the Board of Directors, which the Partnership obtained for its 2009 and 2010 hedging activity. At times, the Partnership's strategy may involve entering into hedges with strike prices above current future prices or resetting existing hedges to higher price levels in order to meet its cash flow objectives or to stay in compliance with its revolving credit facility. In addition, the Partnership may also terminate or unwind hedges or portions of hedges when the expected future volumes do not support the level of hedges. Expected future production for its Upstream Business is derived from the proved reserves, adjusted for price-dependent expenses and revenue deductions. For the Midstream Business, expected future production is based on the expected production from wells currently flowing to the Partnership's processing plants, plus additional volumes the Partnership expects to receive from future drilling activity by its producer customer base. The Partnership's expectations for its Midstream Business volumes associated with future drilling are based on information it receives from its producer customer base and historical observations. The Partnership applies the appropriate contract terms to these projections to determine its expected future equity share of the commodities.
The Partnership uses put options, costless collars and fixed-price swaps to achieve its hedging objectives, and often hedges its expected future volumes of one commodity with derivatives of the same commodity. In some cases, however, the Partnership believes it is better to hedge future changes in the price of one commodity with a derivative of another commodity, which it refers to as “cross-commodity” hedging. The Partnership will often hedge the changes in future NGL prices (propane and heavier) using crude oil hedges because NGL prices have been highly correlated to crude oil prices and hedging NGLs directly is usually less attractive due to the relative illiquidity in the NGL forward market. The Partnership will also use natural gas hedges to hedge a portion of its expected future ethane production because forward prices for ethane are often heavily discounted from its current prices. Also, natural gas prices provide support for ethane prices because in many processing plants ethane can be recombined with the residue gas stream and sold as natural gas. When the Partnership uses cross-commodity hedging, it will convert the expected volumes of the underlying commodity to equivalent volumes of the hedged commodity. In the case of NGLs hedged with crude oil derivatives, these conversions are based on the linear regression of the prices of the two commodities observed during the previous 36 months and management's judgment regarding future price relationships of the commodities. In the case where ethane is hedged with natural gas derivatives, the conversion is based on the thermal content of ethane.
The Partnership has a risk management policy which allows management to execute crude oil, natural gas and NGL hedging instruments in order to reduce exposure to substantial adverse changes in the prices of these commodities. The Partnership continually monitors and ensures compliance with this risk management policy through senior level executives in its operations, finance and legal departments.
F-28
The Partnership has not designated any of its commodity derivative instruments as hedges and therefore is marking these derivative contracts to fair value. Changes in fair values of the commodity derivative instruments are recorded as an adjustment to the mark-to-market gains (losses) on risk management transactions within revenue.
By using derivative instruments to economically hedge exposure to changes in commodity prices, the Partnership exposes itself to credit risk, which is the failure of the counterparty to perform under the terms of the derivative contract. The Partnership's counterparties are all participants or affiliates of participants within its Revolving Credit Facility (see Note 7), which is secured by substantially all of the assets of the Partnership. Therefore, the Partnership is not required to post any collateral, nor does it require collateral from its counterparties. The Partnership minimizes the credit risk in derivative instruments by limiting its exposure to any single counterparty and monitoring the creditworthiness of its counterparties on an ongoing basis. In addition, the Partnership's derivative contracts, for certain counterparties, are subject to counterparty netting agreements governing such derivatives and therefore the risk of loss is somewhat mitigated.
The Partnership's commodity derivative counterparties include BNP Paribas, Wells Fargo Bank, N.A, Comerica Bank, Barclays Bank PLC, Bank of Nova Scotia, The Royal Bank of Scotland plc, Bank of America N.A., J Aron and Company (an affiliate of Goldman Sachs), BBVA Compass Bank and Credit Suisse Energy LLC (an affiliate of Credit Suisse Group AG).
On November 23, 2010, the Partnership entered into a series of hedging transactions to unwind existing contracts. The Partnership unwound; (i) 20,000 barrels a month of an "out-of-the-money" WTI crude oil swap with a price of $80.05, (ii) 15,000 barrels a month of a 20,000 barrels a month "out-of-the-money" WTI crude oil swap with a price of $75.00 and (iii)23,000 barrels a month of a "in-the-money" WTI crude oil swap covering 29,000 barrels per month for the first half of the 2011 calendar year and 23,000 barrels a month covering the second half of the 2011 calendar year with a price a $86.20. For these transactions, the Partnership paid $2.2 million. The Partnership was using these WTI crude oil derivatives to hedge against changes in NGL prices. To continue hedging these NGL volumes, the Partnership then entered into the following derivative transactions for the 2011 calendar year on November 23, 2010: a 996,000 gallon per month OPIS normal butane swap at $1.50 per gallon, a 462,000 gallon per month OPIS iso butane swap at $1.5425 per gallon, a 378,000 gallon per month OPIS natural gasoline swap at $1.8525 per gallon, a 1,680,000 gallon per month OPIS propane swap for $1.1165 per gallon and a 252,000 gallon per month OPIS propane swap for $1.11 per gallon.
On December 20, 2010, the Partnership entered into a 34,000 MMbtu per month Henry Hub natural gas swap at $4.45 per MMbtu. For this swap, the Partnership will be paying the fixed price, where normally, for the swaps it enters into, it pays the floating price. The Partnership was using a portion of its Henry Hub natural gas swaps to hedge against changes in ethane prices and this transaction effectively unwinds a portions of these swaps. To continue hedging these ethane volumes, the Partnership then entered into a 1,428,000 gallon per month OPIS ethane swap at a price of $0.545 per gallon.
In addition, during the year ended December 31, 2010, the Partnership entered into the following derivative transactions for its 2011 calendar year: a 12,000 barrel per month NYMEX WTI costless collar with a floor strike price at $75.00 per barrel and a cap strike price of $89.85 per barrel on February 16, 2010, a 17,000 barrel per month NYMEX WTI swap at $83.30 on June 18, 2010 and a NYMEX WTI swap covering 29,000 barrels per month for the first half of the calendar year and 23,000 barrels per month for the second half of the calendar year with a strike price of $86.20 per barrel on August 23, 2010.
F-29
The following table, as of December 31, 2010, sets forth certain information regarding the Partnership's commodity derivatives that will mature during the year ended December 31, 2011:
Underlying | Period | Notional Volumes (units) | Type | Floor Strike Price ($/unit) | Cap Strike Price ($/unit) | |||||||||
Natural Gas: | ||||||||||||||
NYMEX Henry Hub | Jan-Dec 2011 | 1,200,000 mmbtu | Costless Collar | $ | 7.50 | $ | 8.85 | |||||||
NYMEX Henry Hub | Jan-Dec 2011 | 720,000 mmbtu | Swap | 7.085 | ||||||||||
NYMEX Henry Hub | Jan-Dec 2011 | 2,280,000 mmbtu | Swap | 6.57 | ||||||||||
NYMEX Henry Hub | Jan-Dec 2011 | (408,000) mmbtu | Swap | 4.45 | ||||||||||
Crude Oil: | ||||||||||||||
NYMEX WTI | Jan-Dec 2011 | 139,152 bbls | Costless Collar | 75.00 | 85.70 | |||||||||
NYMEX WTI | Jan-Dec 2011 | 360,000 bbls | Costless Collar | 80.00 | 92.40 | |||||||||
NYMEX WTI | Jan-Dec 2011 | 144,000 bbls | Costless Collar | 75.00 | 89.85 | |||||||||
NYMEX WTI | Jan-Dec 2011 | 125,256 bbls | Swap | 80.00 | ||||||||||
NYMEX WTI | Jan-Dec 2011 | 120,000 bbls | Swap | 65.10 | ||||||||||
NYMEX WTI | Jan-Dec 2011 | 60,000 bbls | Swap | 75.00 | ||||||||||
NYMEX WTI | Jan-Dec 2011 | 360,000 bbls | Swap | 65.60 | ||||||||||
NYMEX WTI | Jan-Dec 2011 | 204,000 bbls | Swap | 83.30 | ||||||||||
NYMEX WTI | Jan-Jun 2011 | 36,000 bbls | Swap | 86.20 | ||||||||||
Natural Gas Liquids: | ||||||||||||||
OPIS NButane Mt. Belv non TET | Jan-Dec 2011 | 11,592,000 gallons | Swap | 1.50 | ||||||||||
OPIS IsoButane Mt. Belv non TET | Jan-Dec 2011 | 5,544,000 gallons | Swap | 1.5425 | ||||||||||
OPIS Natural Gasoline Mt. Belv non TET | Jan-Dec 2011 | 4,536,000 gallons | Swap | 1.8525 | ||||||||||
OPIS Propane Mt. Belv non TET | Jan-Dec 2011 | 20,160,000 gallons | Swap | 1.1165 | ||||||||||
OPIS Propane Mt. Belv non TET | Jan-Dec 2011 | 3,024,000 gallons | Swap | 1.11 | ||||||||||
OPIS Ethane Mt. Belv non TET | Jan-Dec 2011 | 17,136,000 gallons | Swap | 0.545 | ||||||||||
F-30
The following table, as of December 31, 2010, sets forth certain information regarding the Partnership's commodity derivatives that will mature during the year ended December 31, 2012:
Underlying | Period | Notional Volumes (units) | Type | Floor Strike Price ($/unit) | Cap Strike Price ($/unit) | |||||||||
Natural Gas: | ||||||||||||||
NYMEX Henry Hub | Jan-Dec 2012 | 1,080,000 mmbtu | Costless Collar | $ | 7.35 | $ | 8.65 | |||||||
NYMEX Henry Hub | Jan-Dec 2012 | 3,120,000 mmbtu | Swap | 6.77 | ||||||||||
Crude Oil: | ||||||||||||||
NYMEX WTI | Jan-Dec 2012 | 135,576 bbls | Costless Collar | 75.30 | 86.30 | |||||||||
NYMEX WTI | Jan-Dec 2012 | 360,000 bbls | Costless Collar | 80.00 | 98.50 | |||||||||
NYMEX WTI | Jan-Dec 2012 | 192,000 bbls | Costless Collar | 75.00 | 94.75 | |||||||||
NYMEX WTI | Jan-Dec 2012 | 108,468 bbls | Swap | 80.30 | ||||||||||
NYMEX WTI | Jan-Dec 2012 | 240,000 bbls | Swap | 68.30 | ||||||||||
NYMEX WTI | Jan-Dec 2012 | 240,000 bbls | Swap | 76.50 | ||||||||||
NYMEX WTI | Jan-Dec 2012 | 240,000 bbls | Swap | 82.02 | ||||||||||
NYMEX WTI | Jan-Dec 2012 | 420,000 bbls | Swap | 90.65 | ||||||||||
On February 16, 2010, the Partnership entered into a 12,000 barrels per month WTI costless collar with a floor strike price at $75.00 per barrel and a cap strike price of $89.85 per barrel for its 2011 calendar year. On February 17, 2010, the Partnership entered into a 16,000 barrels per month NYMEX WTI costless collar with a floor strike price at $75.00 per barrel and a cap strike price of $94.75 per barrel for its 2012 calendar year.
The following table, as of December 31, 2010, sets forth certain information regarding the Partnership's commodity derivatives that will mature during the year ended December 31, 2013:
Underlying | Period | Notional Volumes (units) | Type | Floor Strike Price ($/unit) | Cap Strike Price ($/unit) | |||||||
Natural Gas: | ||||||||||||
NYMEX Henry Hub | Jan-Dec 2013 | 600,000 mmbtu | Swap | $ | 5.65 | |||||||
NYMEX Henry Hub | Jan-Dec 2013 | 600,000 mmbtu | Swap | 5.30 | ||||||||
NYMEX Henry Hub | Jan-Dec 2013 | 600,000 mmbtu | Swap | 5.305 | ||||||||
Crude Oil: | ||||||||||||
NYMEX WTI | Jan-Dec 2013 | 240,000 bbls | Swap | 90.20 | ||||||||
NYMEX WTI | Jan-Dec 2013 | 720,000 bbls | Swap | 89.85 | ||||||||
NYMEX WTI | Jan-Dec 2013 | 384,000 bbls | Swap | 90.75 | ||||||||
NYMEX WTI | Jan-Dec 2013 | 120,000 bbls | Swap | 88.20 | ||||||||
F-31
Fair Value of Interest Rate and Commodity Derivatives
Fair values of interest rate and commodity derivative instruments not designated as hedging instruments in the consolidated balance sheet as of December 31, 2010 and 2009:
As of December 31, 2010 | |||||||||||
Derivative Assets | Derivative Liabilities | ||||||||||
Balance Sheet Classification | Fair Value | Balance Sheet Classification | Fair Value | ||||||||
($ in thousands) | |||||||||||
Interest rate derivatives - liabilities | $ | — | Current liabilities | $ | (19,822 | ) | |||||
Interest rate derivatives - liabilities | — | Long-term liabilities | (14,757 | ) | |||||||
Commodity derivatives - assets | Current assets | — | Current liabilities | 9,150 | |||||||
Commodity derivatives - assets | Long-term assets | 2,402 | Long-term liabilites | 5,347 | |||||||
Commodity derivatives - liabilities | Current assets | — | Current liabilities | (28,678 | ) | ||||||
Commodity derivatives - liabilities | Long-term assets | (1,327 | ) | Long-term liabilities | (21,595 | ) | |||||
Total derivatives | $ | 1,075 | $ | (70,355 | ) | ||||||
As of December 31, 2009 | |||||||||||
Derivative Assets | Derivative Liabilities | ||||||||||
Balance Sheet Classification | Fair Value | Balance Sheet Classification | Fair Value | ||||||||
($ in thousands) | |||||||||||
Interest rate derivatives - assets | Long-term assets | $ | 600 | $ | — | ||||||
Interest rate derivatives - liabilities | — | Current liabilities | (16,988 | ) | |||||||
Interest rate derivatives - liabilities | — | Long-term liabilities | (11,029 | ) | |||||||
Commodity derivatives - assets | Current assets | 3,494 | Current liabilities | 9,842 | |||||||
Commodity derivatives - assets | Long-term assets | 2,830 | Long-term liabilities | 1,684 | |||||||
Commodity derivatives - liabilities | Current assets | (1,015 | ) | Current liabilities | (44,504 | ) | |||||
Commodity derivatives - liabilities | Long-term assets | (20 | ) | Long-term liabilities | (23,370 | ) | |||||
Total derivatives | $ | 5,889 | $ | (84,365 | ) | ||||||
The following table sets forth the location of gains and losses for derivatives not designated as hedging instruments within the Partnership's Consolidated Statement of Operations (in thousands):
Amount of Gain (Loss) recognized in Income on Derivatives | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
Interest rate derivatives | Interest rate risk management losses | $ | (27,135 | ) | $ | (6,347 | ) | $ | (32,931 | ) | ||
Commodity derivatives | Commodity risk management (losses) gains | (8,786 | ) | (106,290 | ) | 161,765 | ||||||
Total | $ | (35,921 | ) | $ | (112,637 | ) | $ | 128,834 | ||||
The Partnership's hedge counterparties are participants in its credit agreement, and the collateral for the outstanding borrowings under its credit agreement is used as collateral for the Partnership's hedges. The Partnership does not have rights to collateral from its counterparties, nor does it have rights of offset against borrowings under its credit agreement.
NOTE 12. COMMITMENTS AND CONTINGENT LIABILITIES
Litigation—The Partnership is subject to several lawsuits which arise from time to time in the ordinary course of business, such as the interpretation and application of contractual terms related to the calculation of payment for liquids and natural gas proceeds. The Partnership has accruals of approximately zero and $0.1 million as of December 31, 2010 and 2009, respectively, related to these matters. The Partnership has been indemnified up to a certain dollar amount for two of these lawsuits. For the indemnified lawsuits, the Partnership has not established any accruals as the likelihood of these suits being successful against them is considered remote. If there ultimately is a finding against the Partnership in the indemnified cases,
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the Partnership would expect to make a claim against the indemnification up to limits of the indemnification. These matters are not expected to have a material adverse effect on our financial position, results of operations or cash flows.
On February 9, 2010, a lawsuit, alleging certain claims related to the Recapitalization and Related Transactions (see
Note 9), was filed on behalf of one of the Partnership's public unitholders in the Court of Chancery of the State of Delaware
naming the Partnership, its general partner, certain affiliates of its general partner, including the general partner of its general
partner, and each member of the Partnership's Board of Directors as defendants. The complaint alleged a breach by the defendants of their fiduciary duties to the Partnership and the public unitholders and sought to enjoin the Recapitalization and
Related Transactions. The Partnership believed the allegations made in the complaint were without merit. On March 11, 2010, in an effort to minimize the further cost, expense, burden and distraction of any litigation relating to the lawsuit, the parties to the lawsuit entered into a Memorandum of Understanding regarding the terms of a potential settlement of the lawsuit. On August 16, 2010, the parties to the lawsuit filed a Stipulation and Agreement of Compromise, Settlement and Release with the Court of Chancery of the State of Delaware. The settlement resolved the allegations by the plaintiff against the defendants in connection with the Recapitalization and Related Transactions and provides a release and settlement by a proposed class of the Partnership common unitholders during the period from September 17, 2009 through and including the date of the closing of the transactions of all claims against the defendants as they relate to the Recapitalization and Related Transactions. At a hearing on October 28, 2010, the Court of Chancery of the State of Delaware approved the settlement and entered a final Order and Judgment. The order approving the settlement became final on November 29, 2010. During the year ended December 31, 2010, the Partnership incurred $1.2 million of costs, and as of December 31, 2010, the Partnership no longer had an accrual relating to this matter. In addition, the Partnership had recorded a receivable related to this matter of approximately $0.6 million for amounts it expects to recover under its Directors and Officers insurance, of which approximately $0.3 million remains outstanding as of December 31, 2010.
Insurance—The Partnership covers its operations and assets with insurance which management believes is consistent with that in force for other companies engaged in similar commercial operations with similar type properties. This insurance includes: (1) commercial general liability insurance covering liabilities to third parties for bodily injury, property damage and pollution arising out of Eagle Rock Energy operations; (2) workers’ compensation liability coverage for employees to required statutory limits; (3) automobile liability insurance covering liability to third parties for bodily injury and property damage arising out of the operation of all owned, hired and non-owned vehicles by its employees on company business; (4) property insurance covering the replacement cost of all owned real and personal property, including coverage for losses due to boiler and machinery breakdown, earthquake, flood and consequent business interruption/extra expense; (5) control of well/operator's extra expense insurance for operated and non operated wells in the Upstream Segment; and (6) corporate liability insurance including coverage for Directors and Officers and Employment Practices liabilities. In addition, the Partnership maintains excess liability insurance providing limits in excess of the established primary limits for commercial general liability and automobile liability insurance.
All coverages are subject to industry accepted policy terms, conditions, limits and deductibles comparable to that obtained by other energy companies with similar operations. The cost of insurance for the energy industry continued to fluctuate over the past year, reflecting the changing conditions in the insurance markets.
Regulatory Compliance—In the ordinary course of business, the Partnership is subject to various laws and regulations. In the opinion of management, the Partnership is in material compliance with existing laws and regulations.
Environmental—The operation of pipelines, plants and other facilities for gathering, transporting, processing, treating, or storing natural gas, NGLs and other products is subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of these facilities, the Partnership must comply with United States laws and regulations at the federal, state and local levels that relate to air and water quality, hazardous and solid waste management and disposal and other environmental matters. The cost of planning, designing, constructing and operating pipelines, plants, and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures, including citizen suits, which can include the assessment of monetary penalties, the imposition of remedial requirements and the issuance of injunctions or restrictions on operation. Management believes that, based on currently known information, compliance with these laws and regulations will not have a material adverse effect on the Partnership's combined results of operations, financial position or cash flows. At December 31, 2010 and 2009, the Partnership had accrued approximately $4.0 million and $4.4 million, respectively, for environmental matters.
During 2009, the Partnership completed voluntary self-audits of its compliance with air quality standards, which included permitting in the Texas Panhandle Segment as well as a majority of its other Midstream Business locations and some of its Upstream Business locations in Texas. These audits were performed pursuant to the Texas Environmental, Health and
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Safety Audit Privilege Act, as amended. The Partnership completed the disclosures to the Texas Commission on Environmental Quality (“TCEQ”), and the Partnership has substantially addressed the deficiencies that it disclosed therein. The Partnership does not foresee at this time any impediment in timely addressing the remaining deficiencies identified as a result of these audits.
Since January 1, 2010, the Partnership has received additional Notices of Enforcement (“NOEs”) and Notices of Violation (“NOVs”) from the TCEQ related to air compliance matters and expects to receive additional NOEs or NOVs from the TCEQ from time to time throughout 2011. Though the TCEQ has the discretion to adjust penalties and settlements upwards based on a compliance history containing multiple, successive NOEs, the Partnership does not expect that the resolution of any existing NOE or any future similar NOE will vary significantly from the administrative penalties and agreed settlements experienced by it to date.
Retained Revenue Interest—Certain assets of the Partnership's Upstream Segment are subject to retained revenue interests. These interests were established under purchase and sale agreements that were executed by the Partnership's predecessors in title. The terms of these agreements entitle the owners of the retained revenue interests to a portion of the revenues received from the sale of the hydrocarbons above specified base oil and natural gas prices. These retained revenue interests do not represent a real property interest in the hydrocarbons. The Partnership's reported revenues are reduced to account for the retained revenue interests on a monthly basis.
The retained revenue interests affect the Partnership's interest at the Big Escambia Creek, Flomaton and Fanny Church fields in Escambia County, Alabama. With respect to the Partnership's Flomaton and Fanny Church fields, these retained revenue interests are in effect for any calendar year in which the Partnership surpasses certain average net production rates, while for the Partnership's Big Escambia field, the retained revenue interest commenced in 2010 and is expected to continue through the end of 2019.
Other Commitments—The Partnership utilizes assets under operating leases for its corporate office, certain rights-of way and facilities locations, vehicles and in several areas of its operation. Rental expense, including leases with no continuing commitment, amounted to approximately $7.8 million, $8.9 million, and $5.8 million for the years ended December 31, 2010, 2009 and 2008, respectively. Rental expense for leases with escalation clauses is recognized on a straight-line basis over the initial lease term. At December 31, 2010, commitments under long-term non-cancelable operating leases for the next five years are as follows: 2011—$4.2 million; 2012—$4.0 million; 2013—$2.4 million; 2014—$1.7 million and 2015—$1.7 million.
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NOTE 13. SEGMENTS
On May 24, 2010, the Partnership completed the sale of its fee mineral and royalty interests as well as its equity investment in Ivory Working Interests, L.P. (collectively, the “Minerals Business”). As authoritative guidance requires the operations for components of entities disposed of be recorded as part of discontinued operations, operating results for the Minerals Business for the years ended December 31, 2010 and 2009 have been excluded from the Partnership’s segment presentation below. See Note 19 for a further discussion of the sale of the Partnership’s Minerals Business.
Based on the Partnership’s approach to managing its assets, the Partnership believes its operations consist of four geographic segments in its Midstream Business, one upstream segment that is its Upstream Business and one functional (Corporate and Other) segment:
(i) | Midstream—Texas Panhandle Segment: |
gathering, compressing, processing and treating natural gas and marketing of natural gas, NGLs and condensate in the Texas Panhandle;
(ii) | Midstream—South Texas Segment: |
gathering, compressing, processing and treating natural gas and marketing of natural gas, NGLs and condensate in South Texas and West Texas;
(iii) | Midstream—East Texas/Louisiana Segment: |
gathering, compressing, processing, treating and transporting natural gas and marketing of natural gas, NGLs and condensate and related NGL transportation in East Texas and Louisiana;
(iv) | Midstream—Gulf of Mexico Segment: |
gathering and processing of natural gas and fractionating, transporting and marketing of NGLs in South Louisiana, Gulf of Mexico and inland waters of Texas;
(v) | Upstream Segment: |
crude oil, natural gas and sulfur production from operated and non-operated wells; and
(vi) | Corporate and Other Segment: |
risk management, intersegment eliminations and other corporate activities such as general and administrative expenses.
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The Partnership's chief operating decision-maker (“CODM”) currently reviews its operations using these segments. The CODM evaluates segment performance based on segment operating income or loss from continuing operations. Summarized financial information concerning the Partnership's reportable segments is shown in the following table:
Midstream Business Year Ended December 31, 2010 | Texas Panhandle Segment | South Texas Segment | East Texas / Louisiana Segment | Gulf of Mexico Segment | Total Midstream Business | |||||||||||||||
($ in thousands) | ||||||||||||||||||||
Sales to external customers | $ | 358,235 | $ | 82,971 | $ | 204,349 | $ | 32,954 | $ | 678,509 | ||||||||||
Intersegment sales | — | 47 | — | — | 47 | |||||||||||||||
Cost of natural gas, natural gas liquids and condensate | 237,467 | 73,475 | 151,236 | 28,028 | 490,206 | |||||||||||||||
Intersegment cost of oil and condensate | 5,587 | — | — | — | 5,587 | |||||||||||||||
Operating costs and other expenses | 35,032 | 3,336 | 17,275 | 1,771 | 57,414 | |||||||||||||||
Depreciation, depletion, amortization and impairment | 45,876 | 34,980 | 18,452 | 6,838 | 106,146 | |||||||||||||||
Operating income (loss) from continuing operations | $ | 34,273 | $ | (28,773 | ) | $ | 17,386 | $ | (3,683 | ) | $ | 19,203 | ||||||||
Capital Expenditures | $ | 29,282 | $ | 90 | $ | 15,756 | $ | 180 | $ | 45,308 | ||||||||||
Segment Assets | $ | 566,641 | $ | 56,961 | $ | 269,640 | $ | 82,475 | $ | 975,717 | ||||||||||
Total Segments Year Ended December 31, 2010 | Total Midstream Business | Upstream Segment | Corporate and Other Segment | Total Segments | ||||||||||||||
($ in thousands) | ||||||||||||||||||
Sales to external customers | $ | 678,509 | $ | 88,672 | (c) | $ | (8,786 | ) | (a) | $ | 758,395 | |||||||
Intersegment sales | 47 | 6,063 | (6,110 | ) | — | |||||||||||||
Cost of natural gas, natural gas liquids and condensate | 490,206 | — | — | 490,206 | ||||||||||||||
Intersegment cost of oil and condensate | 5,587 | — | (5,587 | ) | — | |||||||||||||
Operating costs and other (income) expenses | 57,414 | 32,724 | (b) | 45,775 | 135,913 | |||||||||||||
Intersegment operations and maintenance | — | 47 | (47 | ) | — | |||||||||||||
Depreciation, depletion, amortization and impairment | 106,146 | 33,960 | 1,550 | 141,656 | ||||||||||||||
Operating income (loss) from continuing operations | $ | 19,203 | $ | 28,004 | $ | (56,587 | ) | $ | (9,380 | ) | ||||||||
Capital Expenditures | $ | 45,308 | $ | 26,772 | $ | 1,609 | $ | 73,689 | ||||||||||
Segment Assets | $ | 975,717 | $ | 359,474 | $ | 14,206 | (d) | $ | 1,349,397 | |||||||||
_________________________________
(a) | Represents results of the Partnership's derivatives activity. |
(b) | Includes costs to dispose of sulfur in the Upstream segment of $0.7 million for the year ended December 31, 2010. |
(c) | Sales to external customers for the year ended December 31, 2010 includes $3.0 million of business interruption insurance recovery related to the shutdown of the Eustace plant in 2010 in the Upstream Segment, which is recognized in Other revenue on the Consolidated Statement of Operations. |
(d) | Includes elimination of intersegment transactions. |
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Midstream Business Year Ended December 31, 2009 | Texas Panhandle Segment | South Texas Segment | East Texas / Louisiana Segment | Gulf of Mexico Segment | Total Midstream Business | |||||||||||||||
($ in thousands) | ||||||||||||||||||||
Sales to external customers | $ | 293,952 | $ | 100,302 | $ | 209,518 | $ | 33,641 | (c) | $ | 637,413 | |||||||||
Cost of natural gas, natural gas liquids and condensate | 206,985 | 91,916 | 162,957 | 26,372 | 488,230 | |||||||||||||||
Operating costs and other expenses | 31,873 | 3,661 | 17,985 | 1,907 | 55,426 | |||||||||||||||
Depreciation, depletion, amortization and impairment | 46,085 | 13,057 | 23,129 | 6,576 | 88,847 | |||||||||||||||
Operating income (loss) from continuing operations | $ | 9,009 | $ | (8,332 | ) | $ | 5,447 | $ | (1,214 | ) | $ | 4,910 | ||||||||
Capital Expenditures | $ | 7,293 | $ | 69 | $ | 18,188 | $ | 358 | $ | 25,908 | ||||||||||
Segment Assets | $ | 539,899 | $ | 93,837 | $ | 285,327 | $ | 87,780 | $ | 1,006,843 | ||||||||||
Total Segments Year Ended December 31, 2009 | Total Midstream Business | Upstream Segment | Corporate and Other Segment | Total Segments | |||||||||||||
($ in thousands) | |||||||||||||||||
Sales to external customers | $ | 637,413 | $ | 63,633 | $ | (106,290 | ) | (a) | $ | 594,756 | |||||||
Cost of natural gas, natural gas liquids and condensate | 488,230 | — | — | 488,230 | |||||||||||||
Operating costs and other expenses | 55,426 | 24,984 | (b) | 45,819 | 126,229 | ||||||||||||
Depreciation, depletion, amortization and impairment | 88,847 | 42,123 | 1,073 | 132,043 | |||||||||||||
Operating income (loss) from continuing operations operations | $ | 4,910 | $ | (3,474 | ) | $ | (153,182 | ) | $ | (151,746 | ) | ||||||
Capital Expenditures | $ | 25,908 | $ | 8,437 | $ | 2,022 | $ | 36,367 | |||||||||
Segment Assets | $ | 1,006,843 | $ | 363,667 | $ | 164,308 | $ | 1,534,818 | |||||||||
Midstream Business Year Ended December 31, 2008 | Texas Panhandle Segment | South Texas Segment | East Texas / Louisiana Segment | Gulf of Mexico Segment | Total Midstream Business | |||||||||||||||
($ in thousands) | ||||||||||||||||||||
Sales to external customers | $ | 603,066 | $ | 173,716 | $ | 322,040 | $ | 1,655 | $ | 1,100,477 | ||||||||||
Cost of natural gas, natural gas liquids and condensate | 459,064 | 161,963 | 269,030 | 1,376 | 891,433 | |||||||||||||||
Operating costs and other expenses | 34,269 | 2,924 | 16,569 | 605 | 54,367 | |||||||||||||||
Depreciation, depletion, amortization and impairment | 43,688 | 12,533 | 40,553 | 1,521 | 98,295 | |||||||||||||||
Operating income (loss) from continuing operations | 66,045 | $ | (3,704 | ) | $ | (4,112 | ) | $ | (1,847 | ) | $ | 56,382 | ||||||||
Capital Expenditures | $ | 30,738 | $ | 1,145 | $ | 17,391 | $ | — | $ | 49,274 | ||||||||||
Segment Assets | $ | 563,556 | $ | 107,655 | $ | 313,383 | $ | 80,106 | $ | 1,064,700 | ||||||||||
Total Segments Year Ended December 31, 2008 | Total Midstream Business | Upstream Segment | Corporate and Other Segment | Total Segments | |||||||||||||
($ in thousands) | |||||||||||||||||
Sales to external customers | $ | 1,100,477 | $ | 173,029 | $ | 161,765 | (a) | $ | 1,435,271 | ||||||||
Cost of natural gas, natural gas liquids and condensate | 891,433 | — | — | 891,433 | |||||||||||||
Operating costs and other expenses | 54,367 | 37,481 | 56,317 | 148,165 | |||||||||||||
Depreciation, depletion, amortization and impairment | 98,295 | 183,008 | 787 | 282,090 | |||||||||||||
Operating income (loss) from continuing operations operations | $ | 56,382 | $ | (47,460 | ) | $ | 104,661 | $ | 113,583 | ||||||||
Capital Expenditures | $ | 49,274 | $ | 20,655 | $ | 751 | $ | 70,680 | |||||||||
Segment Assets | $ | 1,064,700 | $ | 397,785 | $ | 310,576 | $ | 1,773,061 | |||||||||
(a) | Represents results of the Partnership's derivatives activity. |
(b) | Includes costs to dispose of sulfur in the Upstream segment of $2.2 million for the year ended December 31, 2009. |
(c) | Sales to external customers for the year ended December 31, 2009 includes $1.6 million of business interruption insurance recovery related to the damage incurred from Hurricane Ike and Gustav in the Gulf of Mexico Segment, which is recognized in Other revenue on the Consolidated Statement of Operations. |
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NOTE 14. EMPLOYEE BENEFIT PLAN
The Partnership offers a defined contribution benefit plan to its employees. The plan, which was amended in December 2007 to eliminate, in part, a requirement that an employee have been with the Partnership longer than six months, provides for a dollar for dollar matching contribution by the Partnership of up to 3% of an employee's contribution and 50% of additional contributions up to an additional 2%. Additionally, the Partnership may, at its sole discretion and election, contribute up to 6% of a participating employee's base salary annually, subject to vesting requirements. Expenses under the plan for the years ended December 31, 2010, 2009 and 2008 were approximately $1.0 million, $0.7 million and $1.4 million, respectively.
NOTE 15. INCOME TAXES
The Partnership's provision for income taxes relates to (i) state taxes for the Partnership and (ii) federal taxes for Eagle Rock Energy Acquisition Co., Inc, (acquiring entity of Redman Energy Holdings, L.P. and Redman Energy Holdings II, L.P. and certain assets owned by NGP Income Co-Investment Opportunities Fund II, L.P. (collectively the "Redman Acquisition") in 2007) and Eagle Rock Energy Acquisition Co. II, Inc. (acquiring entity of certain entities acquired in the Stanolind Acquisition in 2008) and their wholly owned corporations, Eagle Rock Upstream Development Company, Inc., (successor entity of certain entities acquired in the Redman acquisition) and Eagle Rock Upstream Development Company II, Inc. (successor entity of certain entities acquired in the Stanolind acquisition), which are subject to federal income taxes (the “C Corporations”). In addition, with the amendment of the Texas Franchise Tax in 2006, the Partnership has become a taxable entity in the state of Texas. The Partnership's federal and state income tax provision is summarized below (in thousands):
For the Year Ended December 31, | |||||||||||
2010 | 2009 | 2008 | |||||||||
Current: | |||||||||||
Federal | $ | 236 | $ | 680 | $ | 140 | |||||
State | (240 | ) | 1,464 | 831 | |||||||
Total current provision | (4 | ) | 2,144 | 971 | |||||||
Deferred: | |||||||||||
Federal | (2,204 | ) | 1,862 | (6,766 | ) | ||||||
State | 513 | 235 | 2,217 | ||||||||
Total deferred | (1,691 | ) | 2,097 | (4,549 | ) | ||||||
Total (benefit) provision for income taxes | (1,695 | ) | 4,241 | (3,578 | ) | ||||||
Add Back: Valuation allowance for Federal tax attributes | — | (3,154 | ) | 2,444 | |||||||
Total (benefit) provision for income taxes less valuation allowance | (1,695 | ) | 1,087 | (1,134 | ) | ||||||
Income taxes from discontinued operations | (850 | ) | (65 | ) | (315 | ) | |||||
Total (benefit) provision for income taxes on continuing operations | $ | (2,545 | ) | $ | 1,022 | $ | (1,449 | ) | |||
The effective rate for the years ended December 31, 2010, 2009 and 2008 are shown in the table below. For 2010 and 2008, the effective tax rates are attributable to the state and federal taxes being applied to their respective book incomes. In 2009, the federal and state based income taxes were applied against book losses which resulted in a 100% effective tax rate. A reconciliation of the provision for income taxes with amounts determined by applying the statutory U.S. federal income tax rate to income before income taxes is as follows (in thousands):
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For the Year Ended December 31, | |||||||||||
2010 | 2009 | 2008 | |||||||||
Pre-tax net book income (loss) from continuing operations | $ | (51,101 | ) | $ | (179,633 | ) | $ | 48,902 | |||
Texas Margin Tax current and deferred | (577 | ) | 1,634 | 2,733 | |||||||
Federal income taxes computed by applying the federal statutory rate to NBI of corporate entities | (1,498 | ) | (963 | ) | (4,182 | ) | |||||
Tax attributes used | (470 | ) | (2,803 | ) | (2,444 | ) | |||||
Valuation allowance | — | 3,154 | 2,444 | ||||||||
(Benefit) provision for income taxes from continuing operations | $ | (2,545 | ) | $ | 1,022 | $ | (1,449 | ) | |||
Effective income tax rate on continuing operations | 5.0 | % | 100.0 | % | (3.0 | )% | |||||
Significant components of deferred tax liabilities and deferred tax assets as of December 31, 2010 and 2009 are as follows (in thousands):
December 31, 2010 | December 31, 2009 | ||||||
Deferred Tax Assets: | |||||||
Statutory depletion carryover | $ | 1,765 | $ | 1,562 | |||
AMT credit carryforward | 204 | — | |||||
Total deferred tax | 1,969 | 1,562 | |||||
Less: valuation allowance | — | — | |||||
Net Deferred Tax Assets | 1,969 | 1,562 | |||||
Deferred Tax Liabilities: | |||||||
Property, plant, equipment & amortizable assets | (3,295 | ) | (3,012 | ) | |||
Unrealized hedging transactions | (540 | ) | (609 | ) | |||
Book/tax differences from partnership investment | (34,827 | ) | (36,625 | ) | |||
Total Deferred Tax Liabilities | (38,662 | ) | (40,246 | ) | |||
Total Net Deferred Tax Liabilities | (36,693 | ) | (38,684 | ) | |||
Current potion of total net deferred tax liabilities | — | — | |||||
Long-term portion of total net deferred tax liabilities | $ | (36,693 | ) | $ | (38,684 | ) | |
The Partnership had depletion deduction carryforwards and AMT credit carryforwards of $2.0 million and $1.6 million at December 31, 2010 and 2009, respectively.
The largest single component of Partnership's deferred tax liabilities is related to federal income taxes of the C Corporations described above. Book/tax differences were created by the Redman and Stanolind Acquisitions. These book/tax temporary differences result in a net deferred tax liability of $32.9 million at December 31, 2010, which will be reduced as allocation of built-in gain in proportion to the assets contributed brings the book and tax basis closer together over time. This deferred tax liability was recognized in conjunction with the purchase accounting adjustments for long term assets. The additional $3.8 million in deferred tax liabilities are related to book/tax differences in property, plant, and equipment and unrealized hedging transactions.
On May 18, 2006, the State of Texas enacted House Bill 3 which revised the pre-existing state franchise tax. In general, legal entities that conduct business in Texas are subject to the Revised Texas Franchise Tax, including previously non-taxable entities such as limited partnerships and limited liability partnerships. The tax is assessed on Texas sourced taxable margin which is defined as the lesser of (i) 70% of total revenue or (ii) total revenue less (a) cost of goods sold or (b) compensation and benefits.
Although the bill states that the Revised Texas Franchise Tax is not an income tax, it has the characteristics of an income tax since it is determined by applying a tax rate to a base that considers both revenues and expenses. Due to the enactment of the Revised Texas Franchise Tax, the Partnership recorded a net deferred tax liability of $3.8 million, $3.6 million
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and $3.4 million as of December 31, 2010, 2009 and 2008, respectively. The offsetting net changes of $0.2 million, $0.2 million and $1.5 million are shown in the Consolidated Statements of Operations for the years ended December 31, 2010, 2009 and 2008, respectively, as a component of provision for income taxes.
The Partnership adopted authoritative guidance related to accounting for uncertainty in income taxes on January 1, 2007. The Partnership has taken a position which is deemed to be “more likely than not” to be upheld upon review, if any, with respect to the deductibility of certain costs for the purpose of its franchise tax liability on a state franchise return. The Partnership has recorded a provision for the portion of this tax liability equal to the probability of recognition. In addition, the Partnership has accrued interest and penalties associated with these liabilities and has recorded these amounts within its state deferred income tax expense. The amount stated below relates to the tax returns filed for 2010 and 2009, which are still open under current statute. A reconciliation of the beginning and ending amount of the unrecognized tax benefits (liabilities) is as follows (in thousands):
Balance as of December 31, 2009 | $ | (267 | ) |
Increases related to prior year tax positions | — | ||
Increases related to current year tax positions | (302 | ) | |
Balance as of December 31, 2010 | $ | (569 | ) |
NOTE 16. EQUITY-BASED COMPENSATION
Eagle Rock Energy G&P, LLC, the general partner of the general partner for the Partnership, has a long-term incentive plan as amended (“LTIP”) for its employees, directors and consultants who provide services to the Partnership and its subsidiaries and affiliates. On September 17, 2010, at a special meeting of the unitholders of the Partnership, the Partnership's unitholders approved an amendment and restatement of the Partnership's Long Term Incentive Plan (the "Amended Plan") to (i) increase the number of Partnership common units reserved for issuance under the Amended Plan by 5,000,000 units, (ii) provide for the grant of unit appreciation rights and other unit based awards, and (iii) make certain other non-material changes to the Amended Plan. The Amended Plan became effective following its approval by the Partnership's unitholders. Subsequent to approval, the LTIP provides for the issuance of an aggregate of 7,000,000 common units, to be granted either as options, restricted units or phantom units. Distributions declared and paid on outstanding restricted units are paid directly to the holders of the restricted units. The Partnership has historically only issued restricted units under the LTIP. No options or phantom units have been issued to date.
The weighted average fair value of the units granted during the years ended December 31, 2010, 2009 and 2008 were $6.60, $5.58 and $14.89, respectively. The awards generally vest on the basis of one third of the award each year. During the restriction period, distributions associated with the granted awards will be distributed to the awardees. No options or phantom units have been issued to date.
A summary of the restricted common units’ activity for the year ended December 31, 2010, is provided below:
Number of Restricted Units | Weighted Average Fair Value | |||||
Outstanding at December 31, 2009 | 1,371,019 | $ | 9.35 | |||
Granted | 1,293,845 | $ | 6.60 | |||
Vested | (798,301 | ) | $ | 11.80 | ||
Forfeitures | (122,109 | ) | $ | 8.19 | ||
Outstanding at December 31, 2010 | 1,744,454 | $ | 6.27 | |||
For the years ended December 31, 2010, 2009, and 2008, non-cash compensation expense of approximately $5.4 million, $6.3 million, and $6.0 million, respectively, was recorded related to the granted restricted units. The GP Acquisition, as discussed in Note 8, triggered a change of control under certain award agreements for outstanding restricted common units awarded under the Partnership's LTIP and the accelerated vesting of the 315,607 affected outstanding restricted units, of which 84,086 were cancelled by the Partnership in satisfaction of $0.5 million in related employee tax liability paid by the Partnership, which are included in amounts discussed below. As a result of the accelerated vesting, the Partnership recognized an additional $2.8 million in equity-based compensation in the third quarter of 2010. In addition, during the three months ended September 30, 2010, the Partnership recorded a reduction to compensation expense of $2.2 million as a result of adjusting its forfeiture rate.
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As of December 31, 2010, unrecognized compensation costs related to the outstanding restricted units under the Partnership's LTIP totaled approximately $8.9 million. The remaining expense is to be recognized over a weighted average of 2.56 years.
Due to the vesting of certain restricted units during the years ended December 31, 2010 and 2009, 181,292 and 17,492, respectively, were repurchased by the Partnership for $1.2 million and $0.1 million, respectively, as consideration for the related employee tax liability paid by the Partnership. No units were repurchased in during the year ended December 31, 2008. Pursuant to the terms of the LTIP, these repurchased units are available for future grants under the LTIP.
In addition to equity awards under the LTIP, Eagle Rock Holdings, L.P. (“Holdings”), which is controlled by NGP, has
from time to time granted equity in Holdings to certain employees working on behalf of the Partnership, some of which are
named executive officers. During years ended December 31, 2010, 2009 and 2008, Holdings granted 40,000, 160,000 and 417,000, respectively, “Tier I” incentive interests to certain Eagle Rock Energy employee. The Partnership recorded a portion of the value of the incentive units as compensation expense in the Partnership's Consolidated Statements of Operations. This allocation is based on management's estimation of the total value of the incentive unit grant and of the grantees' portion of time dedicated to the Partnership. The Partnership recorded non-cash compensation expense of $0.1 million, $0.4 million and $1.7 million based on management's estimates related to the Tier I incentive unit grants made by Holdings during years ended December 31, 2010, 2009 and 2008, respectively.
NOTE 17. EARNINGS PER UNIT
Basic earnings per unit are computed by dividing the net income (loss) by the weighted average number of units outstanding during a period. To determine net income (loss) allocated to each class of ownership (common, subordinated and general partner), the Partnership first allocates net income (loss) in accordance with the amount of distributions made for the quarter by each class, if any. The remaining net income (loss) is allocated to each class in proportion to the class weighted average number of units outstanding for a period, as compared to the weighted average number of units for all classes for the period.
The Partnership has unvested restricted common units outstanding, which are considered dilutive securities . These units will be considered in the diluted weighted average common unit outstanding number in periods of net income. In periods of net losses, these units are excluded from the diluted weighted average common unit outstanding number.
As part of its rights offering, the Partnership granted warrants, as discussed in Note 8. Any warrants outstanding during the period are consider to be dilutive securities. These outstanding warrants will be considered in the diluted weighted average common unit outstanding number in periods of net income, except if the exercise price of the outstanding warrants is greater than the average market price of the common units for such periods. In periods of net losses, the outstanding warrants are excluded from the diluted weighted average common unit outstanding number.
For the years ended December 31, 2010, 2009 and 2008, the Partnership determined that it is more dilutive to apply the two-class method versus the treasury stock method in calculating dilutive earnings per unit. Thus, the unvested restricted common units are included in the computation of the diluted weighted average common unit outstanding calculation, but the denominator in the computation of diluted earnings per unit only includes the basic weighted average common units outstanding.
Under the Partnership's original partnership agreement, which was amended and restated on May 24, 2010, in connection with approval of the Recapitalization and Related Transactions, for any quarterly period, incentive distribution rights (“IDRs”) participated in net income only to the extent of the amount of cash distributions actually declared, thereby excluding the IDRs from participating in undistributed earnings or losses. Accordingly, undistributed net income is assumed to be allocated to the other ownership interests on a pro-rata basis. During the years ended December 31,2010 and 2009, the Partnership did not declare a quarterly distribution for the IDRs. On May 24, 2010, the Partnership's general partner contributed all of the outstanding IDRs to the Partnership (see Notes 8 and 9), and they were eliminated.
In addition, all of the subordinated units and general partner units, as discussed in Notes 8 and 9, were contributed to the Partnership and cancelled on May 24, 2010 and July, 30, 2010, respectively. As a result, the number of subordinated units and general partner units used in the calculation of earnings per unit for the three and nine months ended September 30, 2010 is based on the weighted average amount of time they were outstanding during those periods.
The restricted common units granted under the LTIP, as discussed in Note 15, contain non-forfeitable rights to the distributions declared by the Partnership and therefore meet the definition of participating securities. Participating securities are
F-41
required to be included in the computation of earnings per unit pursuant to the two-class method.
F-42
The following table presents the Partnership's calculation of basic and diluted units outstanding for the periods indicated:
For the Year Ended December 31, | ||||||||
2010 | 2009 | 2008 | ||||||
(Unit amounts in thousands) | ||||||||
Basic weighted average unit outstanding during period: | ||||||||
Common units | 68,625 | 53,496 | 51,534 | |||||
Subordinated units | 8,163 | 20,691 | 20,691 | |||||
General partner units | 488 | 845 | 845 | |||||
Diluted weighted average unit outstanding during period: | ||||||||
Common units | 68,625 | 53,496 | 51,699 | |||||
Subordinated units | 8,163 | 20,691 | 20,691 | |||||
General partner units | 488 | 845 | 845 | |||||
The following table presents the Partnership's basic and diluted loss per unit for the year ended December 31, 2010:
Total | Common Units | Restricted Common Units | Subordinated Units | General Partner Units | ||||||||||||||||
($ in thousands, except for per unit amounts) | ||||||||||||||||||||
Loss from continuing operations | $ | (48,556 | ) | |||||||||||||||||
Distributions declared | 14,943 | $ | 14,658 | $ | 243 | $ | — | $ | 42 | |||||||||||
Assumed loss from continuing operations after distribution to be allocated | (63,499 | ) | (55,441 | ) | (1,069 | ) | (6,595 | ) | (394 | ) | ||||||||||
Assumed allocation of loss from continuing operations | (48,556 | ) | (40,783 | ) | (826 | ) | (6,595 | ) | (352 | ) | ||||||||||
Discontinued operations | 43,207 | 37,724 | 727 | 4,487 | 269 | |||||||||||||||
Assumed net loss to be allocated | $ | (5,349 | ) | $ | (3,059 | ) | $ | (99 | ) | $ | (2,108 | ) | $ | (83 | ) | |||||
Basic and diluted loss from continuing operations per unit | $ | (0.59 | ) | $ | (0.81 | ) | $ | (0.72 | ) | |||||||||||
Basic and diluted discontinued operations per unit | $ | 0.55 | $ | 0.55 | $ | 0.55 | ||||||||||||||
Basic and diluted loss per unit | $ | (0.04 | ) | $ | (0.26 | ) | $ | (0.17 | ) | |||||||||||
F-43
The following table presents the Partnership's basic and diluted loss per unit for the year ended December 31, 2009:
Total | Common Units | Restricted Common Units | Subordinated Units | General Partner Units | ||||||||||||||||
($ in thousands, except for per unit amounts) | ||||||||||||||||||||
Loss from continuing operations | $ | (180,655 | ) | |||||||||||||||||
Distributions declared | 5,498 | $ | 5,350 | $ | 64 | $ | — | $ | 84 | |||||||||||
Assumed loss from continuing operations after distribution to be allocated | (186,153 | ) | (132,723 | ) | — | (51,335 | ) | (2,095 | ) | |||||||||||
Assumed allocation of loss from continuing operations | (180,655 | ) | (127,373 | ) | 64 | (51,335 | ) | (2,011 | ) | |||||||||||
Discontinued operations | 9,397 | 6,700 | — | 2,591 | 106 | |||||||||||||||
Assumed net loss to be allocated | $ | (171,258 | ) | $ | (120,673 | ) | $ | 64 | $ | (48,744 | ) | $ | (1,905 | ) | ||||||
Basic and diluted loss from continuing operations per unit | $ | (2.38 | ) | $ | (2.48 | ) | $ | (2.38 | ) | |||||||||||
Basic and diluted discontinued operations per unit | $ | 0.13 | $ | 0.13 | $ | 0.13 | ||||||||||||||
Basic and diluted loss per unit | $ | (2.26 | ) | $ | (2.36 | ) | $ | (2.26 | ) | |||||||||||
The following table presents the Partnership's basic and diluted income per unit for the year ended December 31, 2008:
Total | Common Units | Restricted Common Units | Subordinated Units | General Partner Units | ||||||||||||||||
($ in thousands, except for per unit amounts) | ||||||||||||||||||||
Income from continuing operations | $ | 50,351 | ||||||||||||||||||
Distributions declared | 120,256 | $ | 84,000 | $ | 1,152 | $ | 33,727 | $ | 1,377 | |||||||||||
Assumed loss from continuing operations after distribution to be allocated | (69,905 | ) | (49,302 | ) | — | (19,795 | ) | (808 | ) | |||||||||||
Assumed allocation of income from continuing operations | 50,351 | 34,782 | 1,152 | 13,965 | 570 | |||||||||||||||
Discontinued operations | 37,169 | 26,214 | — | 10,525 | 430 | |||||||||||||||
Assumed net income to be allocated | $ | 87,520 | $ | 60,913 | $ | 1,152 | $ | 24,457 | $ | 998 | ||||||||||
Basic and diluted income from continuing operations per unit | $ | 0.67 | $ | 0.67 | $ | 0.67 | ||||||||||||||
Basic and diluted discontinued operations per unit | $ | 0.51 | $ | 0.51 | $ | 0.51 | ||||||||||||||
Basic and diluted income per unit | $ | 1.18 | $ | 1.18 | $ | 1.18 | ||||||||||||||
NOTE 18. OTHER OPERATING EXPENSE
Other operating (income) expense for the year ended December 31, 2009, includes income of $3.6 million due to the recovery of $2.2 million of assets previously written off and the release of $1.4 million of liabilities assumed as part of the Partnership's purchase price allocation for its acquisitions of Escambia Asset Co., LLC and Redman Energy Holdings, L.P. During the period, the Partnership received additional information about collectability of these assets and determined that it no longer had any obligation under these liabilities.
In July 2008, SemGroup, L.P. and certain of its subsidiaries (“SemGroup”) filed petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code. The Partnership historically sold portions of its condensate production from its Texas
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Panhandle and East Texas midstream systems to SemGroup. As a result of the bankruptcy, the Partnership took a $10.7 million bad debt charge during the year ended December 31, 2008, which is included in “Other Operating Expense” in the consolidated statement of operations. In August 2009, the Partnership sold $3.9 million of its outstanding receivables from SemGroup, which represented its 20-day administrative claims under 503(b)(9) of the United States Bankruptcy Code, for which it received a payment of $3.0 million. Due to certain repurchase obligations under the assignment agreement, the Partnership recorded the payment as a current liability within accounts payable as of December 31, 2010 and anticipates maintaining the balance as a liability until it is clear that the repurchase obligations can no longer be triggered.
NOTE 19. DISCONTINUED OPERATIONS
On April 1, 2009, the Partnership sold its producer services business (which was accounted for in its South Texas Segment) by assigning and novating the contracts under this business to a third-party purchaser. The Partnership sold the producer services business to a third-party purchaser as it was a low-margin business that was not core to the Partnership's operations. The Partnership received an initial payment of $0.1 million for the sale of the business. In addition the Partnership received a contingency payment of $0.1 million in October 2009. The Partnership will also continue to receive a monthly payment equivalent to $0.01 per MMbtu on the volume of gas that flows pursuant to the assigned contracts through March 31, 2011. Producer services was a business in which the Partnership would negotiate new well connections on behalf of small producers to pipelines other than its own. During the year ended December 31, 2010, this business generated revenues of $0.1 million and no cost of natural gas and NGLs. During the year ended December 31, 2009, this business generated revenues of $19.2 million and cost of natural gas and NGLs of $18.9 million. During the year ended December 31, 2008, this business generated revenues of $265.1 million and cost of natural gas and NGLs of $263.3 million. For the year ended December 31, 2010, 2009 and 2008, $0.1 million. $0.3 million and $1.8 million, respectively, of revenues minus the cost of natural gas and NGLs have been reported as discontinued operations.
On May 24, 2010, the Partnership completed the sale of its Minerals Business, for which it received net proceeds of approximately $171.6 million in cash after purchase price adjustments made to reflect an effective date of January 1, 2010 for the sale, as established in the agreement governing the sale. The Partnership retained approximately $2.9 million of cash from net revenues received from the Minerals Business after the effective date. The Partnership recorded a gain of $37.7 million on the sale, which is recorded as part of discontinued operations for the year ended December 31, 2010. Further upward or downward adjustments to the purchase price may occur post-closing to reflect customary true-ups. During the six months ended December 31, 2010, the Partnership received payments of $0.3 million related to pre-effective date operations and have recorded this amount as part of discontinued operations for the period. For the year ended December 31, 2010, the Minerals Business generated revenues of $8.9 million and income from operations of $5.5 million. For the year ended December 31, 2009, the Minerals Business generated revenues of $15.7 million and income from operations of $7.8 million. For the year ended December 31, 2008, the Minerals Business generated revenues of $43.0 million and income from operations of $31.7 million. During the years ended December 31, 2010, 2009 and 2008, the Minerals Business incurred state tax expense on discontinued operations of $0.4 million, $0.2 million and $0.4 million, respectively. During the years ended December 31, 2010, 2009 and 2008, the Minerals Business recorded a gain to discontinued operations of $5.5 million, $9.1 million and $35.4 million, respectively, excluding the gain recognized by the Partnership on the sale of the Minerals Business.
Assets and liabilities held for sale represent the assets and liabilities of the Partnership's Minerals Business. As of December 31, 2009, assets held for sale consists of the following: (i) accounts receivable of $3.0 million, (ii) net proved reserves of $55.2 million, (iii) unproved reserves of $64.9 million and (iv) the Partnership's equity investment in Ivory Working Interests, L.P. of $12.0 million. As of December 31, 2009, liabilities held for sale was made up of accounts payable.
NOTE 20. SUBSIDIARY GUARANTORS
In the future, the Partnership may issue registered debt securities guaranteed by its subsidiaries. The Partnership expects that all guarantors would be wholly-owned or available to be pledged and that such guarantees would be joint and several and full and unconditional. In accordance with practices accepted by the SEC, the Partnership has prepared Condensed Consolidating Financial Statements as supplemental information. The following Condensed Consolidating Balance Sheets at December 31, 2010 and 2009, and Condensed Consolidating Statements of Operations and Condensed Consolidating Statements of Cash Flows for the years ended December 31, 2010, 2009 and 2008, present financial information for Eagle Rock Energy Partners, L.P. as the Parent on a stand-alone basis (carrying any investments in subsidiaries under the equity method), financial information for the subsidiary guarantors, which are all 100% owned by the Parent, on a stand-alone basis, and the consolidation and elimination entries necessary to arrive at the information for the Partnership on a consolidated basis. The subsidiary guarantors are not restricted from making distributions to the Partnership.
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Condensed Consolidating Balance Sheet | |||||||||||||||||||
December 31, 2010 | |||||||||||||||||||
(in thousands) | Parent Issuer | Subsidiary Guarantors | Non-guarantor investments | Consolidating Entries | Total | ||||||||||||||
ASSETS: | |||||||||||||||||||
Accounts receivable – related parties | $ | 42,667 | $ | — | $ | — | $ | (42,667 | ) | $ | — | ||||||||
Other current assets | 5,694 | 78,663 | — | — | 84,357 | ||||||||||||||
Total property, plant and equipment, net | 1,200 | 1,142,259 | — | — | 1,143,459 | ||||||||||||||
Investment in subsidiaries | 1,113,603 | — | 1,116 | (1,114,719 | ) | — | |||||||||||||
Total other long-term assets | 3,622 | 117,959 | — | — | 121,581 | ||||||||||||||
Total assets | $ | 1,166,786 | $ | 1,338,881 | $ | 1,116 | $ | (1,157,386 | ) | $ | 1,349,397 | ||||||||
LIABILITIES AND EQUITY: | |||||||||||||||||||
Accounts payable – related parties | $ | — | $ | 42,667 | $ | — | $ | (42,667 | ) | $ | — | ||||||||
Other current liabilities | 31,208 | 113,831 | — | — | 145,039 | ||||||||||||||
Other long-term liabilities | 26,465 | 68,780 | — | — | 95,245 | ||||||||||||||
Long-term debt | 530,000 | — | — | — | 530,000 | ||||||||||||||
Equity | 579,113 | 1,113,603 | 1,116 | (1,114,719 | ) | 579,113 | |||||||||||||
Total liabilities and equity | $ | 1,166,786 | $ | 1,338,881 | $ | 1,116 | $ | (1,157,386 | ) | $ | 1,349,397 | ||||||||
Condensed Consolidating Balance Sheet | |||||||||||||||||||
December 31, 2009 | |||||||||||||||||||
(in thousands) | Parent Issuer | Subsidiary Guarantors | Non-guarantor investments | Consolidating Entries | Total | ||||||||||||||
ASSETS: | |||||||||||||||||||
Accounts receivable – related parties | $ | 87,433 | $ | — | $ | — | $ | (87,433 | ) | $ | — | ||||||||
Assets held for sale | — | 135,224 | — | — | 135,224 | ||||||||||||||
Other current assets | 5,171 | 91,442 | — | — | 96,613 | ||||||||||||||
Total property, plant and equipment, net | 212 | 1,155,521 | — | — | 1,155,733 | ||||||||||||||
Investment in subsidiaries | 1,244,384 | — | 1,205 | (1,245,589 | ) | — | |||||||||||||
Total other long-term assets | 5,620 | 141,628 | — | — | 147,248 | ||||||||||||||
Total assets | $ | 1,342,820 | $ | 1,523,815 | $ | 1,205 | $ | (1,333,022 | ) | $ | 1,534,818 | ||||||||
LIABILITIES AND EQUITY: | |||||||||||||||||||
Accounts payable – related parties | $ | — | $ | 87,433 | $ | — | $ | (87,433 | ) | $ | — | ||||||||
Liabilities held for sale | — | 150 | — | — | 150 | ||||||||||||||
Other current liabilities | 42,099 | 114,423 | — | — | 156,522 | ||||||||||||||
Other long-term liabilities | 15,940 | 77,425 | — | — | 93,365 | ||||||||||||||
Long-term debt | 754,383 | — | — | — | 754,383 | ||||||||||||||
Equity | 530,398 | 1,244,384 | 1,205 | (1,245,589 | ) | 530,398 | |||||||||||||
Total liabilities and equity | $ | 1,342,820 | $ | 1,523,815 | $ | 1,205 | $ | (1,333,022 | ) | $ | 1,534,818 | ||||||||
F-46
Condensed Consolidating Statement of Operations | |||||||||||||||||||
For the year ended December 31, 2010 | |||||||||||||||||||
(in thousands) | Parent Issuer | Subsidiary Guarantors | Non-guarantor investments | Consolidating Entries | Total | ||||||||||||||
Total revenues | $ | (8,296 | ) | $ | 766,691 | $ | — | $ | — | $ | 758,395 | ||||||||
Cost of natural gas and natural gas liquids | — | 490,206 | — | — | 490,206 | ||||||||||||||
Operations and maintenance | — | 77,898 | — | — | 77,898 | ||||||||||||||
Taxes other than income | 2 | 12,238 | — | — | 12,240 | ||||||||||||||
General and administrative | 3,680 | 42,095 | — | — | 45,775 | ||||||||||||||
Depreciation, depletion, amortization and impairment | 165 | 141,491 | — | — | 141,656 | ||||||||||||||
Loss from operations | (12,143 | ) | 2,763 | — | — | (9,380 | ) | ||||||||||||
Interest expense | (15,145 | ) | (2 | ) | — | — | (15,147 | ) | |||||||||||
Other non-operating income | 8,300 | 2,755 | 26 | (10,469 | ) | 612 | |||||||||||||
Other non-operating expense | (14,988 | ) | (22,667 | ) | — | 10,469 | (27,186 | ) | |||||||||||
Loss before income taxes | (33,976 | ) | (17,151 | ) | 26 | — | (51,101 | ) | |||||||||||
Income tax provision (benefit) | 517 | (3,062 | ) | — | — | (2,545 | ) | ||||||||||||
Equity in earnings of subsidiaries | 29,144 | — | — | (29,144 | ) | — | |||||||||||||
Loss from continuing operations | (5,349 | ) | (14,089 | ) | 26 | (29,144 | ) | (48,556 | ) | ||||||||||
Discontinued operations | — | 43,207 | — | — | 43,207 | ||||||||||||||
Net (loss) income | $ | (5,349 | ) | $ | 29,118 | $ | 26 | $ | (29,144 | ) | $ | (5,349 | ) | ||||||
Condensed Consolidating Statement of Operations | |||||||||||||||||||
For the year ended December 31, 2009 | |||||||||||||||||||
(in thousands) | Parent Issuer | Subsidiary Guarantors | Non-guarantor investments | Consolidating Entries | Total | ||||||||||||||
Total revenues | $ | (37,432 | ) | $ | 632,188 | $ | — | $ | — | $ | 594,756 | ||||||||
Cost of natural gas and natural gas liquids | — | 488,230 | — | — | 488,230 | ||||||||||||||
Operations and maintenance | — | 73,196 | — | — | 73,196 | ||||||||||||||
Taxes other than income | — | 10,766 | — | — | 10,766 | ||||||||||||||
General and administrative | 2,803 | 43,016 | — | — | 45,819 | ||||||||||||||
Other operating income | — | (3,552 | ) | — | — | (3,552 | ) | ||||||||||||
Depreciation, depletion, amortization and impairment | — | 132,043 | — | — | 132,043 | ||||||||||||||
Loss from operations | (40,235 | ) | (111,511 | ) | — | — | (151,746 | ) | |||||||||||
Interest expense | (21,568 | ) | (23 | ) | — | — | (21,591 | ) | |||||||||||
Other non-operating income | 6,886 | 2,788 | 153 | (8,706 | ) | 1,121 | |||||||||||||
Other non-operating expense | (5,572 | ) | (10,551 | ) | — | 8,706 | (7,417 | ) | |||||||||||
Income (loss) before income taxes | (60,489 | ) | (119,297 | ) | 153 | — | (179,633 | ) | |||||||||||
Income tax provision (benefit) | 1,547 | (525 | ) | — | — | 1,022 | |||||||||||||
Equity in losses of subsidiaries | (109,222 | ) | — | — | 109,222 | — | |||||||||||||
Loss from continuing operations | (171,258 | ) | (118,772 | ) | 153 | 109,222 | (180,655 | ) | |||||||||||
Discontinued operations | — | 9,397 | — | — | 9,397 | ||||||||||||||
Net loss | $ | (171,258 | ) | $ | (109,375 | ) | $ | 153 | $ | 109,222 | $ | (171,258 | ) | ||||||
F-47
Condensed Consolidating Statement of Operations | |||||||||||||||
For the year ended December 31, 2008 | |||||||||||||||
(in thousands) | Parent Issuer | Subsidiary Guarantors | Consolidating Entries | Total | |||||||||||
Total revenues | $ | 8,809 | $ | 1,426,462 | $ | — | $ | 1,435,271 | |||||||
Cost of natural gas and natural gas liquids | — | 891,433 | — | 891,433 | |||||||||||
Operations and maintenance | — | 73,620 | — | 73,620 | |||||||||||
Taxes other than income | — | 18,228 | — | 18,228 | |||||||||||
General and administrative | 15 | 45,603 | — | 45,618 | |||||||||||
Other operating expense | — | 10,699 | — | 10,699 | |||||||||||
Depreciation, depletion, amortization and impairment | — | 282,090 | — | 282,090 | |||||||||||
Income from operations | 8,794 | 104,789 | — | 113,583 | |||||||||||
Interest expense | (33,842 | ) | — | — | (33,842 | ) | |||||||||
Other non-operating income | 5,617 | 2,318 | (5,846 | ) | 2,089 | ||||||||||
Other non-operating expense | (5,665 | ) | (33,109 | ) | 5,846 | (32,928 | ) | ||||||||
(Loss) income before income taxes | (25,096 | ) | 73,998 | — | 48,902 | ||||||||||
Income tax provision (benefit) | 1,087 | (2,536 | ) | — | (1,449 | ) | |||||||||
Equity in earnings of subsidiaries | 113,703 | — | (113,703 | ) | — | ||||||||||
Income from continuing operations | 87,520 | 76,534 | (113,703 | ) | 50,351 | ||||||||||
Discontinued operations | — | 37,169 | — | 37,169 | |||||||||||
Net income | $ | 87,520 | $ | 113,703 | $ | (113,703 | ) | $ | 87,520 | ||||||
F-48
Condensed Consolidating Statement of Cash Flows | |||||||||||||||||||
For the year ended December 31, 2010 | |||||||||||||||||||
(in thousands) | Parent Issuer | Subsidiary Guarantors | Non-guarantor investments | Consolidating Entries | Total | ||||||||||||||
Net cash flows provided by operating activities | $ | 43,756 | $ | 52,950 | $ | 54 | $ | — | $ | 96,760 | |||||||||
CASH FLOWS FROM INVESTING ACTIVITIES: | |||||||||||||||||||
Additions to property, plant and equipment | (1,152 | ) | (63,345 | ) | — | — | (64,497 | ) | |||||||||||
Purchase of intangible assets | — | (2,660 | ) | — | — | (2,660 | ) | ||||||||||||
Acquisitions,net of cash acquired | — | (30,984 | ) | — | — | (30,984 | ) | ||||||||||||
Proceeds from sale of asset | 171,686 | — | — | — | 171,686 | ||||||||||||||
Contributions to subsidiaries | (27,043 | ) | — | — | 27,043 | — | |||||||||||||
Net cash flows provided by (used in) investing activities | 143,491 | (96,989 | ) | — | 27,043 | 73,545 | |||||||||||||
CASH FLOWS FROM FINANCING ACTIVITIES: | |||||||||||||||||||
Proceeds from long-term debt | 90,617 | — | — | — | 90,617 | ||||||||||||||
Repayment of long-term debt | (315,000 | ) | — | — | — | (315,000 | ) | ||||||||||||
Proceeds from derivative contracts | — | 1,131 | — | — | 1,131 | ||||||||||||||
Deferred transaction fees | (3,066 | ) | — | — | — | (3,066 | ) | ||||||||||||
Repurchase of common units | 53,893 | — | — | — | 53,893 | ||||||||||||||
Proceeds from Rights Offering | 5,351 | — | — | — | 5,351 | ||||||||||||||
Exercise of Warrants | (1,177 | ) | — | — | — | (1,177 | ) | ||||||||||||
Contributions from parent | — | 27,043 | — | (27,043 | ) | — | |||||||||||||
Distributions to members and affiliates | (7,195 | ) | — | — | — | (7,195 | ) | ||||||||||||
Net cash flows provided by (used in) financing activities | (176,577 | ) | 28,174 | — | (27,043 | ) | (175,446 | ) | |||||||||||
Net cash flows provided by discontinued operations | — | 6,458 | — | — | 6,458 | ||||||||||||||
Net (decrease) increase in cash and cash equivalents | 10,670 | (9,407 | ) | 54 | — | 1,317 | |||||||||||||
Cash and cash equivalents at beginning of year | 4,922 | (2,179 | ) | (11 | ) | — | 2,732 | ||||||||||||
Cash and cash equivalents at end of year | $ | 15,592 | $ | (11,586 | ) | $ | 43 | $ | — | $ | 4,049 | ||||||||
F-49
Condensed Consolidating Statement of Cash Flows | |||||||||||||||||||
For the year ended December 31, 2009 | |||||||||||||||||||
(in thousands) | Parent Issuer | Subsidiary Guarantors | Non-guarantor Investments | Consolidating Entries | Total | ||||||||||||||
Net cash flows provided by operating activities | $ | 57,933 | $ | 21,487 | $ | (11 | ) | $ | — | $ | 79,409 | ||||||||
CASH FLOWS FROM INVESTING ACTIVITIES: | |||||||||||||||||||
Additions to property, plant and equipment | (84 | ) | (36,050 | ) | — | — | (36,134 | ) | |||||||||||
Purchase of intangible assets | — | (1,626 | ) | — | — | (1,626 | ) | ||||||||||||
Proceeds from sale of asset | — | 476 | — | — | 476 | ||||||||||||||
Net cash flows used in investing activities | (84 | ) | (37,200 | ) | — | — | (37,284 | ) | |||||||||||
CASH FLOWS FROM FINANCING ACTIVITIES: | |||||||||||||||||||
Proceeds from long-term debt | 131,000 | — | — | — | 131,000 | ||||||||||||||
Repayment of long-term debt | (176,000 | ) | — | — | — | (176,000 | ) | ||||||||||||
Proceeds from derivative contracts | — | 8,939 | — | — | 8,939 | ||||||||||||||
Deferred transactions fees | (1,480 | ) | — | — | — | (1,480 | ) | ||||||||||||
Repurchase of common units | (64 | ) | — | — | — | (64 | ) | ||||||||||||
Distributions to members and affiliates | (35,655 | ) | — | — | — | (35,655 | ) | ||||||||||||
Net cash flows (used in) provided by financing activities | (82,199 | ) | 8,939 | — | — | (73,260 | ) | ||||||||||||
Net cash flows provided by discontinued operations | — | 15,951 | — | — | 15,951 | ||||||||||||||
Net (decrease) increase in cash and cash equivalents | (24,350 | ) | 9,177 | (11 | ) | — | (15,184 | ) | |||||||||||
Cash and cash equivalents at beginning of year | 29,272 | (11,356 | ) | — | — | 17,916 | |||||||||||||
Cash and cash equivalents at end of year | $ | 4,922 | $ | (2,179 | ) | $ | (11 | ) | $ | — | $ | 2,732 | |||||||
Condensed Consolidating Statement of Cash Flows | |||||||||||||||||||
For the year ended December 31, 2008 | |||||||||||||||||||
(in thousands) | Parent Issuer | Subsidiary Guarantors | Non-guarantor Investments | Consolidating Entries | Total | ||||||||||||||
Net cash flows provided by operating activities | $ | 106,073 | $ | 32,697 | $ | — | $ | — | $ | 138,770 | |||||||||
CASH FLOWS FROM INVESTING ACTIVITIES: | |||||||||||||||||||
Additions to property, plant and equipment | (128 | ) | (66,613 | ) | — | — | (66,741 | ) | |||||||||||
Purchase of intangible assets | — | (2,975 | ) | — | — | (2,975 | ) | ||||||||||||
Investment in partnerships | — | — | — | — | — | ||||||||||||||
Acquisitions, net of cash acquired | (857 | ) | (261,388 | ) | — | — | (262,245 | ) | |||||||||||
Proceeds from sale of asset | — | 1,294 | — | — | 1,294 | ||||||||||||||
Contributions to subsidiaries | (261,981 | ) | — | — | 261,981 | — | |||||||||||||
Net cash flows used in investing activities | (262,966 | ) | (329,682 | ) | — | 261,981 | (330,667 | ) | |||||||||||
CASH FLOWS FROM FINANCING ACTIVITIES: | |||||||||||||||||||
Proceeds from long-term debt | 432,128 | — | — | — | 432,128 | ||||||||||||||
Repayment of long-term debt | (199,814 | ) | — | — | — | (199,814 | ) | ||||||||||||
Proceeds from derivative contracts | — | (11,063 | ) | — | — | (11,063 | ) | ||||||||||||
Payment of debt issuance costs | (789 | ) | — | — | — | (789 | ) | ||||||||||||
Contributions from parent | — | 261,981 | — | (261,981 | ) | — | |||||||||||||
Distributions to members and affiliates | (117,646 | ) | — | — | — | (117,646 | ) | ||||||||||||
Net cash flows provided by financing activities | 113,879 | 250,918 | — | (261,981 | ) | 102,816 | |||||||||||||
Net cash flows provided by discontinued operations | — | 38,445 | — | — | 38,445 | ||||||||||||||
Net decrease in cash and cash equivalents | (43,014 | ) | (7,622 | ) | — | — | (50,636 | ) | |||||||||||
Cash and cash equivalents at beginning of year | 72,286 | (3,734 | ) | — | — | 68,552 | |||||||||||||
Cash and cash equivalents at end of year | $ | 29,272 | $ | (11,356 | ) | $ | — | $ | — | $ | 17,916 | ||||||||
F-50
NOTE 21. SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)
Oil and Natural Gas Reserves
Users of this information should be aware that the process of estimating quantities of proved oil and natural gas reserves is very complex, and requires significant subjective decisions in the evaluation of the available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and changing operating and market conditions. As a result, revisions to existing reserve estimates may occur from time to time. Although reasonable effort is made to ensure the reported reserve estimates represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures.
There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production and timing of development expenditures. Reserve data represent estimates only and should not be construed as being exact. Moreover, the Standardized Measure of Oil and Gas (“SMOG”) should not be construed as the current market value of the proved oil and natural gas reserves or the costs that would be incurred to obtain equivalent reserves. A market value determination would include many additional factors including (a) anticipated future changes in natural gas and crude oil prices, production and development costs, (b) an allowance for return on investment, (c) the value of additional reserves, not considered proved at present, which may be recovered as a result of further exploration and development activities, and (d) other business risks.
Recent Developments
On May 24, 2010, the Partnership sold its Minerals Business (see Notes 1, 13 and 19). Financial information, including reserve amounts and changes, related to the Minerals Business have been retrospectively adjusted to be reflected as assets and liabilities held-for-sale and discontinued operations, as discussed further in Note 1.
Proved Reserves Summary
The following table illustrates the Partnership's estimated net proved reserves, including changes, and proved developed reserves for the periods indicated, as estimated by Cawley, Gillespie and Associates. Oil and natural gas liquids prices for 2010 are based on a prior twelve month average West Texas Intermediate spot price of $79.63 per barrel and are adjusted for quality, transportation fees, and regional price differentials. Natural gas prices for 2010 are based on a prior 12 month average Henry Hub spot market price of $4.37 per MMBtu and are adjusted for energy content, transportation fees, and regional price differentials. All prices are held constant in accordance with SEC guidelines. All of the Partnership's reserves are located in the United States.
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Proved Reserves - 2008 | ||||||||
Oil (MBbls) | Gas (MMcf) | Natural Gas Liquids (MBbls) | ||||||
Proved reserves, January 1, 2008 | 10,081 | 44,643 | 5,743 | |||||
Extensions and discoveries | 139 | 2,639 | 45 | |||||
Purchase of minerals in place | 3,513 | 8,157 | 1,432 | |||||
Production | (832 | ) | (4,123 | ) | (482 | ) | ||
Revision of previous estimates | (2,864 | ) | (6,182 | ) | (1,099 | ) | ||
Changes from discontinued operations | (31 | ) | (546 | ) | — | |||
Proved reserves, December 31, 2008 | 10,006 | 44,588 | 5,639 | |||||
Proved developed reserves - continuing operations, December 31, 2008 | 6,425 | 31,286 | 4,883 | |||||
Proved developed reserves - discontiued operations, December 31, 2008 | 2,775 | 4,871 | — | |||||
Proved undeveloped reserves - continuing operations, December 31, 2008 | 806 | 8,431 | 756 | |||||
Proved Reserves - 2009 | ||||||||
Oil (MBbls) | Gas (MMcf) | Natural Gas Liquids (MBbls) | ||||||
Proved reserves, January 1, 2009 | 10,006 | 44,588 | 5,639 | |||||
Extensions and discoveries | 298 | 1,782 | 241 | |||||
Purchase of minerals in place | 18 | — | — | |||||
Production | (829 | ) | (6,647 | ) | (493 | ) | ||
Revision of previous estimates | 797 | (1,030 | ) | 718 | ||||
Changes from discontinued operations | 162 | (53 | ) | — | ||||
Proved reserves, December 31, 2009 | 10,452 | 38,640 | 6,105 | |||||
Proved developed reserves - continuing operations, December 31, 2009 | 7,121 | 26,263 | 5,410 | |||||
Proved developed reserves - discontinued operations, December 31, 2009 | 2,937 | 4,819 | — | |||||
Proved undeveloped reserves - continuing operations, December 31, 2009 | 394 | 7,558 | 695 | |||||
Proved Reserves - 2010 | ||||||||
Oil (MBbls) | Gas (MMcf) | Natural Gas Liquids (MBbls) | ||||||
Proved reserves, January 1, 2010 | 10,452 | 38,640 | 6,105 | |||||
Extensions and discoveries | 7 | 3,930 | — | |||||
Purchase of minerals in place | 216 | 555 | 102 | |||||
Production | (808 | ) | (3,514 | ) | (437 | ) | ||
Revision of previous estimates | 1,766 | 3,590 | 406 | |||||
Change from discontinued operations | (54 | ) | (342 | ) | — | |||
Sale of minerals in place | (2,883 | ) | (4,477 | ) | — | |||
Proved reserves, December 31, 2010 | 8,696 | 38,382 | 6,176 | |||||
Proved developed reserves - continuing operations, December 31, 2010 | 8,299 | 29,686 | 5,758 | |||||
Proved undeveloped reserves - continuing operations, December 31, 2010 | 397 | 8,696 | 418 | |||||
In 2009, the Partnership experienced significant revisions to its proved reserves. The Partnership revised its oil and natural gas liquids reserves upwards due to changes in production forecasts and engineering factors such as condensate and natural gas liquids yields. The Partnership also revised its natural gas reserves downward due to technical factors (such as increased shrinkage related to fuel usage and plant processing) and economic factors. Revisions due to economic factors are due to the relatively low prior twelve
F-52
month average natural gas price that was used to determine the reserves and higher operating cost estimates in its Permian Basin operations. The Partnership also experienced negative oil and natural gas revisions in its Permian Basin operations, particularly in its lease in the Ward Estes and surrounding fields. These revisions were primarily due to poorer than expected performance in recent San Andres drilling and recompletions, changes to decline curves to reflect recent production performance, and the upward adjustment of operating costs which rendered several leases non-commercial. The Partnership is working to improve its cost structure on these leases and is optimistic that some of these negative reserves may be reversed in the future.
Proved Reserves Summary - Equity Method Entities
As part of the sale of the Minerals Business, the Partnership sold it 13.2% limited partner interest in IWI, which it had accounted for under the equity method. IWI is managed by Black Stone and is not required to make public disclosures about its proved reserves and the agreements that governed the Partnership's rights as limited partners in IWI do not require Black Stone to provide us with detailed reserve data of the type that would be sufficient to make all of the disclosures that the SEC now requires with respect to proved reserves of equity method entities. As a result, the Partnership lacks the date needed to prepare the Supplemental Oil and Gas Disclosures for its equity interests.
Capitalized Costs Relating to Oil and Natural Gas Producing Activities
The following table illustrates the total amount of capitalized costs relating to oil and natural gas producing activities and the total amount of related accumulated depreciation, depletion and amortization at December 31, 2010, 2009 and 2008:
As of December 31, 2010 | As of December 31, 2009 | As of December 31, 2008 | |||||||||
($ in thousands) | |||||||||||
Evaluated properties | $ | 471,781 | $ | 435,789 | $ | 437,865 | |||||
Unevaluated properties—excluded from depletion | 1,304 | 7,264 | 7,599 | ||||||||
Gross oil and gas properties | 473,085 | 443,053 | 445,464 | ||||||||
Accumulated depreciation, depletion, amortization | (125,832 | ) | (95,135 | ) | (60,833 | ) | |||||
Net oil and gas properties | 347,253 | 347,918 | 384,631 | ||||||||
Net oil and gas properties held-for-sale | — | 120,149 | 127,807 | ||||||||
Total net oil and gas properties | $ | 347,253 | $ | 468,067 | $ | 512,438 | |||||
Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities
Costs incurred in property acquisition, exploration and development activities were as follows for the years ended December 31, 2010, 2009 and 2008:
Years Ended December 31, | |||||||||||
2010 | 2009 | 2008 | |||||||||
($ in thousands) | |||||||||||
Property acquisition costs, proved | $ | 4,222 | $ | 512 | $ | 110,747 | |||||
Property acquisition costs, unproved | 259 | 20 | 7,597 | ||||||||
Exploration and extension well costs | — | 1 | 1,610 | ||||||||
Development costs | 25,922 | 8,137 | 12,294 | ||||||||
Total costs | $ | 30,403 | $ | 8,670 | $ | 132,248 | |||||
The Partnership's exploration and extension well costs are primarily related to low risk drilling around its existing fields.
No costs were incurred associated with the Minerals Business which is classified as Discontinued Operations on the Consolidated Statements of Operations and Assets Held for Sale on the Consolidated Balances sheet.
F-53
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves
The following information has been developed utilizing authoritative guidance procedures and is based on oil and natural gas reserves estimated by the Partnership's independent reserves engineer. It can be used for some comparisons, but should not be the only method used to evaluate the Partnership or its performance. Further, the information in the following table may not represent realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flow be viewed as representative of the current value of the Partnership.
The Partnership believes that the following factors should be taken into account when reviewing the following information:
• | future costs and selling prices will probably differ from those required to be used in these calculations; |
• | due to future market conditions and governmental regulations, actual rates of production in future years may vary significantly from the rate of production assumed in the calculations; and |
• | a 10% discount rate may not be reasonable as a measure of the relative risk inherent in realizing future net oil and natural gas revenues. |
Under the Standardized Measure, future cash inflows were estimated by applying year-end oil and natural gas prices to the estimated future production of year-end proved reserves. Estimates of future income taxes are computed using current statutory income tax rates including consideration for estimated future statutory depletion and tax credits. The resulting net cash flows are reduced to present value amounts by applying a 10% discount factor.
In the Partnership's 2009 Standardized Measure calculations it included the future revenues that would be associated with the sales of sulfur; however the cash flows only partially offset the costs of transporting and marketing the sulfur. As such, it is a net negative cash flow in the Standardized Measure. Also, the Partnership included the expected impact of the retained revenue interests as a revenue reduction.
The recent changes to the disclosure rules relating to proved reserves require the inclusion of the Partnership's share of the reserves associated with entities that it reports under the equity method. As discussed above, the Partnership sold these interests as part of the sale of its Minerals Business. As the Partnership did not have the right and has been unable to gather the data needed to include these reserves in its Standardized Measure calculations, the tables below reflect only the reserves for the Partnership's consolidate entities.
The Standardized Measure is as follows as of December 31, 2010, 2009 and 2008:
As of December 31, 2010 | As of December 31, 2009 | As of December 31, 2008 | |||||||||
($ in thousands) | |||||||||||
Future cash inflows | $ | 1,027,417 | $ | 650,564 | $ | 654,901 | |||||
Future production costs | (336,080 | ) | (307,605 | ) | (316,920 | ) | |||||
Future development costs | (97,745 | ) | (72,577 | ) | (60,189 | ) | |||||
Future net cash flows before income taxes | 593,592 | 270,382 | 277,792 | ||||||||
Future income tax (expense) benefit | (1,005 | ) | 554 | 1,992 | |||||||
Future net cash flows before 10% discount | 592,587 | 270,936 | 279,784 | ||||||||
10% annual discount for estimated timing of cash flows | (258,594 | ) | (111,321 | ) | (116,773 | ) | |||||
Standardized measure of discounted future net cash flows related to continuing operations | 333,993 | 159,615 | 163,011 | ||||||||
Standardized measure of discounted future net cash flows related to discontinued operations | — | 55,038 | 46,733 | ||||||||
Total standardized measure of discounted future net cash flows | $ | 333,993 | $ | 214,653 | $ | 209,744 | |||||
F-54
Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves
The following is a summary of the changes in the Standardized Measure of discounted future net cash flows for the Partnership's proved oil and natural gas reserves for the years ended December 31, 2010, 2009 and 2008:
Years Ended December 31, | |||||||||||
2010 | 2009 | 2008 | |||||||||
($ in thousands) | |||||||||||
Beginning of year | $ | 214,653 | $ | 209,744 | $ | 556,960 | |||||
Sale of oil and gas produced, net of production costs | (54,353 | ) | (40,824 | ) | (99,968 | ) | |||||
Net changes in prices and production costs | 147,003 | 6,146 | (257,840 | ) | |||||||
Extensions, discoveries and improved recovery, less related costs | 5,492 | 7,859 | 5,603 | ||||||||
Previously estimated development costs incurred during the period | 25,922 | (8,137 | ) | (12,294 | ) | ||||||
Net changes in future development costs | (30,033 | ) | 8,733 | 11,766 | |||||||
Revisions of previous quantity estimates | 74,864 | 9,404 | (50,144 | ) | |||||||
Purchases of property | 7,342 | 347 | 45,239 | ||||||||
Sales of property | (70,845 | ) | — | — | |||||||
Accretion of discount | 14,528 | 14,777 | 42,524 | ||||||||
Net changes in income taxes | (793 | ) | (908 | ) | 1,069 | ||||||
Other | (15,594 | ) | (793 | ) | 7,860 | ||||||
Change from discontinued operations | 15,807 | 8,305 | (41,031 | ) | |||||||
End of year | $ | 333,993 | $ | 214,653 | $ | 209,744 | |||||
Results of Operations
The following are the results of operations for the Partnership's oil and natural gas producing activities for the years ended December 31, 2010, 2009 and 2008:
Year Ended December 31, | 2010 | 2009 | 2008 | |||||||||
($ in thousands) | ||||||||||||
Revenues | $ | 87,211 | $ | 67,159 | $ | 138,082 | ||||||
Costs and expenses: | ||||||||||||
Production costs | 32,858 | 26,335 | 38,114 | |||||||||
General and administrative | 6,349 | 5,151 | 4,282 | |||||||||
Depreciation, depletion, and amortization | 30,424 | 34,009 | 44,997 | |||||||||
Impairment | 3,536 | 8,114 | 107,017 | |||||||||
Total costs and expenses | 73,167 | 73,609 | $ | 194,410 | ||||||||
Results of continuing operations | 14,044 | (6,450 | ) | (56,328 | ) | |||||||
Discontinued operations | 5,262 | 5,686 | 17,642 | |||||||||
Total result of operations | $ | 19,306 | $ | (764 | ) | $ | (38,686 | ) | ||||
* * * *
F-55
Index to Exhibits
Exhibit Number | Description |
2.1 | Purchase and Sale Agreement dated December 21, 2009 among Eagle Rock Pipeline GP,LLC, EROC Production, LLC and BSAP II GP, L.L.C. (incorporated by reference to Exhibit 2.1 of the registrant’s current report on Form 8-K filed with the Commission on December 21, 2009) |
3.1 | Certificate of Limited Partnership of Eagle Rock Energy Partners, L.P. (incorporated by reference to Exhibit 3.1 of the registrant’s registration statement on Form S-1 (File No. 333-134750)) |
3.2 | Second Amended and Restated Agreement of Limited Partnership of Eagle Rock Energy Partners, L.P. (incorporated by reference to Exhibit 3.1 of the registrant’s current report on Form 8-K filed with the Commission on May 25, 2010) |
3.3 | Certificate of Limited Partnership of Eagle Rock Energy GP, L.P. (incorporated by reference to Exhibit 3.3 of the registrant’s registration statement on Form S-1 (File No. 333-134750)) |
3.4 | Limited Partnership Agreement of Eagle Rock Energy GP, L.P. (incorporated by reference to Exhibit 3.4 of the registrant’s registration statement on Form S-1 (File No. 333-134750)) |
3.5 | Certificate of Formation of Eagle Rock Energy G&P, LLC (incorporated by reference to Exhibit 3.5 of the registrant’s registration statement on Form S-1 (File No. 333-134750)) |
3.6 | Third Amended and Restated Limited Liability Company Agreement of Eagle Rock Energy G&P, LLC (incorporated by reference to Exhibit 42 of the registrant’s current report on Form 8-K filed with the Commission on July 30, 2010) |
3.7 | Amendment No. 1 to the Second Amended and Restated Agreement of Limited Partnership of Eagle Rock Energy Partners, L.P. (incorporated by reference to Exhibit 4.1 of the registrant's current report on Form 8-K filed with the Commission on July 30, 2010) |
4.1 | Form of Common Unit Certificate (included as Exhibit A to the Second Amended and Restated Partnership Agreement of Eagle Rock Energy Partners, L.P.) (incorporated by reference to Exhibit 3.1 of the registrant’s current report on Form 8-K filed on May 25, 2010) |
4.2 | Form of Warrant Agent Agreement between Eagle Rock Energy Partners, L.P. and American Stock Transfer & Trust Company, LLC, as warrant agent (incorporated by reference to Exhibit 4.3 to the registrant's current report on Form 8-K filed on May 27, 2010) |
4.3 | Form of Warrant (included as Exhibit A to Exhibit 4.3 to the registrant's current report on Form 8-K filed on May 27, 2010) |
10.1** | Amended and Restated Eagle Rock Energy Partners, L.P. Long-Term Incentive Plan dated September 17, 2010 (incorporated by reference to Exhibit 10.1 of the registrant’s current report on Form 8-K filed on September 17, 2010) |
10.2† | Natural Gas Liquids Exchange Agreement by and between ONEOK Hydrocarbon, L.P. and ONEOK Texas Field Services, L.P. (Eagle Rock Field Services, L.P.) (incorporated by reference to Exhibit 10.5 of the registrant’s registration statement on Form S-1 (File No. 333-134750)) |
10.3 | Gas Sales and Purchase Agreement between MC Panhandle, Inc. (Chesapeake Energy Marketing Inc.) and MidCon Gas Services Corp. (Eagle Rock Field Services, L.P.) (incorporated by reference to Exhibit 10.6 of the registrant’s registration statement on Form S-1 (File No. 333-134750)) |
10.4 | Brookeland Gas Facilities Gas Gathering and Processing Agreement between Union Pacific Resources Company (Anadarko E&P Company LP) and Sonat Exploration Company (Eagle Rock Field Services, L.P.) (incorporated by reference to Exhibit 10.7 of the registrant’s registration statement on Form S-1 (File No. 333-134750)) |
10.5 | Gas Purchase Contract between Warren Petroleum Company (Eagle Rock Field Services, L.P.) and Wallace Oil & Gas, Inc. (Cimarex Energy Co.) (incorporated by reference to Exhibit 10.10 of the registrant’s registration statement on Form S-1 (File No. 333-134750)) |
10.6 | Base Contract for Sale and Purchase of Natural Gas between Eagle Rock Field Services, L.P. and Odyssey Energy Services, LLC (incorporated by reference to Exhibit 10.13 of the registrant’s registration statement on Form S-1 (File No. 333-134750)) |
10.7** | Form of Supplemental Indemnification Agreement among Eagle Rock Energy G&P, LLC, Eagle Rock Energy GP, L.P., Eagle Rock Energy Partners, L.P. and officers and directors of Eagle Rock Energy G&P, LLC (incorporated by reference to Exhibit 10.1 of the registrant’s current report on Form 8-K filed with the Commission on December 30, 2009) |
10.8**† | Eagle Rock Energy G&P, LLC 2010 Short Term Incentive Bonus Plan approved and adopted on December 30, 2009 (incorporated by reference to Exhibit 10.3 of the registrant’s current report on Form 8-K filed with the Commission on December 30, 2009) |
Exhibit Number | Description |
10.9 | Amended and Restated Securities Purchase and Global Transaction Agreement dated January 12, 2010 among Natural Gas Partners VII, L.P., Natural Gas Partners VIII, L.P., Montierra Minerals & Production, L.P., Montierra Management LLC, Eagle Rock Holdings, L.P., Eagle Rock Energy G&P, LLC, Eagle Rock Energy GP, L.P. and Eagle Rock Energy Partners, L.P. (incorporated by reference to Exhibit 10.1 of the registrant’s current report on Form 8-K filed with the Commission on January 12, 2010) |
10.10 | Credit Agreement dated December 13, 2007 among Eagle Rock Energy Partners, L.P. and Wachovia Bank, National Association, as administrative agent and swingline lender, Bank of America, N.A., as syndication agent, HSH Nordbank AG, New York Branch, the Royal Bank of Scotland, plc, and BNP Paribas, as co-documentation agents, and the other lenders who are parties thereto (incorporated by reference to Exhibit 10.17 of the Form 8-K filed with the Commission on December 13, 2007) |
10.11 | Credit Facility Amendment, dated as of March 8, 2010, by and among Eagle Rock Energy Partners, L.P., as borrower, Wachovia Back, N/A., Bank of America, N.A., HSH Nordbank AG, New York Branch, The Royal Bank of Scotland, PLC, BNP Paribas and the other lenders party threeto, and the Guarantors thereto (incorporated by reference to Exhibit 10.1 of the Registrant's Current Report on Form 8-K file with the Commisision on March 9, 2010) |
10.12 | Contribution Agreement, dated May 24, 2010, by and among the Partnership, Eagle Rock Holdings, L.P. and Eagle Rock Energy GP, L.P. (incorporated by reference to Exhibit 10.1 to the registrant's current report on Form 8-K filed on May 25, 2010) |
10.13** | Executive Change of Control Agreement Policy (incorporated by reference to Exhibit 10.1 to the registrant's current report on Form 8-K filed on July 28, 2010) |
10.14** | Form of Executive Change of Control Agreement (incorporated by reference to Exhibit 10.2 to the registrant's current report on Form 8-K filed on July 28, 2010) |
10.15 | Administrative Services Agreement, dated as of July 30, 2010, between Eagle Rock Energy Partners, L.P. and Eagle Rock Energy G&P, LLC (incorporated by reference to Exhibit 10.1 to the registrant's current report on Form 8-K filed on July 30, 2010) |
10.16** | Form of Restricted Unit Agreement for Non-Employee Directors Under the Eagle Rock Energy Partners Long-Term Incentive Plan (incorporated by reference to Exhibit 10.3 to the registrant's current report on Form 8-K filed on July 30, 2010) |
10.17** | Form of Restricted Unit Agreement for Officers under the Eagle Rock Energy Partners Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the registrant's current report on Form 8-K filed on July 30, 2010) |
10.18† | Amendment to Natural Gas Liquids Exchange Agreement by and between ONEOK Hydrocarbon, L.P. and Eagle Rock Field Services L.P. (successor to ONEOK Texas Field Services, L.P. dated December 3, 2010 (incorporated by reference to Exhibit 10.1 to the registrant's current report on Form 8-K filed on December 9, 2010) |
10.19**† | Eagle Rock Energy G&P, LLC 2011 Short Term Incentive Bonus Plan (incorporated by reference to Exhibit 10.1 to the registrant's current report on Form 8-K filed on February 14, 2011) |
14.1 | Code of Ethics for Chief Executive Officer and Senior Financial Officers posted on the Company’s website at www.eaglerockenergy.com. |
21.1* | List of Subsidiaries of Eagle Rock Energy Partners, L.P. |
23.1* | Consent of Deloitte & Touche LLP |
23.2* | Consent of Cawley, Gillespie & Associates, Inc. |
23.3* | Consent of K.E. Andrews & Company |
31.1* | Certification of Periodic Financial Reports by Joseph A. Mills in satisfaction of Section 302 of the Sarbanes-Oxley Act of 2002 |
31.2* | Certification of Periodic Financial Reports by Jeffrey P. Wood in satisfaction of Section 302 of the Sarbanes-Oxley Act of 2002 |
32.1* | Certification of Periodic Financial Reports by Joseph A. Mills in satisfaction of Section 906 of the Sarbanes-Oxley Act of 2002 |
32.2* | Certification of Periodic Financial Reports by Jeffrey P. Wood in satisfaction of Section 906 of the Sarbanes-Oxley Act of 2002 |
99.1* | Report of Cawley, Gillespie & Associates, Inc. |
* Filed herewith
** Management contract or compensatory plan or arrangement required to be filed as an exhibit hereto.
† Portions of this exhibit have been omitted pursuant to a request for confidential treatment.