Edgar Filing: EAGLE ROCK ENERGY PARTNERS L P

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2007


o		TRANSITION REPORT PURSUANT OT SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

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		(I.R.S. Employer
Incorporation or Organization)		Identification Number)

16701 Greenspoint Park Drive, Suite 200
Houston, Texas 77060
(Address of principal executive offices, including zip code)

(281) 408-1200
(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer o Accelerated Filer o Non-accelerated Filer þ

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ

The issuer had 35,422,108 common units outstanding as of May 14, 2007.

EAGLE ROCK ENERGY PARTNERS, L.P.

TABLE OF CONTENTS


	Page
PART I. FINANCIAL INFORMATION		1

Item 1. Financial Statements		1
Condensed Consolidated Balance Sheets as of March 31, 2007 and December 31, 2006 (unaudited)		1
Condensed Consolidated Statements of Operations for the three months ended March 31, 2007 and 2006 (unaudited)		2
Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2007 and 2006 (unaudited)		3
Condensed Consolidated Statements of Members’ Equity for the three months ended March 31, 2007 (unaudited)		4
Notes to the Condensed Consolidated Financial Statements (unaudited)		5

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		19
Cautionary Note Regarding Forward-Looking Statements		20

Item 3. Quantitative and Qualitative Disclosures About Market Risk		33

Item 4. Controls and Procedures		34

PART II. OTHER INFORMATION		35

Item 1. Legal Proceedings		35

Item 1A. Risk Factors		35

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		36

Item 3. Defaults Upon Senior Securities		37

Item 4. Submission of Matters to a Vote of Security Holders		37

Item 5. Other Information		37

Item 6. Exhibits		37
Certification Pursuant to Section 302
Certification Pursuant to Section 302
Certification Pursuant to Section 906
Certification Pursuant to Section 906

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

EAGLE ROCK ENERGY PARTNERS, L.P.

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)


	March 31,			December 31,
*($ in thousands)*	2007			2006
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	2,059		$	10,581
Accounts receivable		44,567			43,567
Risk management assets		5,629			13,837
Prepayments and other current assets		2,122			2,679

Total current assets		54,377			70,664

PROPERTY, PLANT AND EQUIPMENT — Net		569,147			554,063
INTANGIBLE ASSETS — Net		127,069			130,001
RISK MANAGEMENT ASSETS		14,768			17,373
OTHER ASSETS		7,459			7,800

TOTAL	$	772,820		$	779,901


LIABILITIES AND MEMBERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	60,813		$	49,558
Accrued liabilities		13,640			7,996
Risk management liabilities		2,639			1,005

Total current liabilities		77,092			58,559

LONG-TERM DEBT		405,731			405,731
ASSET RETIREMENT OBLIGATIONS		1,905			1,819
DEFERRED STATE TAX LIABILITY		1,393			1,229
RISK MANAGEMENT LIABILITIES		20,383			20,576
COMMITMENTS AND CONTINGENCIES (Note 11)
MEMBERS’ EQUITY (DEFICIT):
Common Unit Holders(1)		104,402			116,283
Subordinated Unitholders(2)		162,999			176,248
General Partner		(1,085	)		(544	)

Total members’ equity		266,316			291,987

TOTAL	$	772,820		$	779,901


(1)		20,691,495 units were issued and outstanding for March 31, 2007 and December 31, 2006. These numbers do not include 115,150 units and 122,450, respectively, issued to employees as of March 31, 2007 and December 31, 2006, respectively, under the 2006 Long-Term Incentive Plan and which are subject to vesting requirements.

(2)		20,691,495 units were issued and outstanding for March 31, 2007 and December 31, 2006.

See notes to condensed consolidated financial statements.

EAGLE ROCK ENERGY PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(unaudited)


	Three Months
	Ended March 31,
*($ in thousands except per share data)*	2007			2006
REVENUE:
Natural gas liquids sales	$	51,695		$	46,704
Natural gas sales		48,272			53,281
Condensate		10,154			14,202
Gathering, compression and processing fees		4,283			2,201
Loss on risk management instruments		(7,642	)		(20,070	)

Total revenue		106,762			96,318

COSTS AND EXPENSES:
Cost of natural gas and natural gas liquids		90,636			91,991
Operations and maintenance		7,923			5,682
General and administrative		4,923			2,453
Other		1,711			—
Depreciation and amortization		11,630			9,214

Total costs and expenses		116,823			109,340

OPERATING LOSS		(10,061	)		(13,022	)
OTHER (EXPENSE) INCOME:
Interest and other income		124			40
Interest and other expense		(9,567	)		(2,535	)

Total other (expense) income		(9,443	)		(2,495	)

STATE INCOME TAX PROVISION		164			—


NET LOSS	$	(19,668	)	$	(15,517	)


NET LOSS PER COMMON UNIT - BASIC AND DILUTED:
Net loss
Common units	$	(0.28	)	$	(0.63	)
Subordinated units		(0.64	)		(0.63	)
General partner units		(0.64	)		(0.63	)
Basic and Diluted (units in thousands)
Common units		20,691			23,027
Subordinated units		20,691			1,342
General partner units		845			263

See notes to condensed consolidated financial statements.

EAGLE ROCK ENERGY PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)


	Three Months
	Ended March 31,
*($ in thousands)*	2007			2006
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(19,668	)	$	(15,517	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation and amortization		11,630			9,214
Amortization of debt issuance costs		416			229
Reclassifying financing derivative settlements		(100	)		(811	)
Equity-based compensation expense		173			—
Other		120			17
Changes in assets and liabilities — net of acquisitions:
Accounts receivable		(1,000	)		(4,002	)
Prepayments and other current assets		557			306
Risk management activities		12,254			15,905
Accounts payable		4,252			(3,265	)
Accrued liabilities		5,623			2,056
Other assets		(76	)		761

Net cash provided by operating activities		14,181			4,893

CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant and equipment		(16,145	)		(6,218	)
Acquisitions		—			(75,654	)
Escrow cash		—			7,643
Purchase of intangible assets		(513	)		(717	)

Net cash used in investing activities		(16,658	)		(74,946	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from revolver		(9,000	)		—
Repayment of revolver		9,000			—
Repayment of long-term debt		—			(1,320	)
Payment of debt issuance costs		—			(431	)
Proceeds from derivative contracts		100			811
Payment of deferred offering costs		—			(1,452	)
Contribution by members		—			98,390
Distributions to members and affiliates		(6,145	)		—

Net cash (used in) provided by financing activities		(6,045	)		95,998

NET CHANGE IN CASH AND CASH EQUIVALENTS		(8,522	)		25,945
CASH AND CASH EQUIVALENTS — Beginning of period		10,581			19,372

CASH AND CASH EQUIVALENTS — End of period	$	2,059		$	45,317

Interest paid — net of amounts capitalized	$	7,925		$	9,467

Investments in property, plant and equipment not paid	$	6,943		$	—

See notes to condensed consolidated financial statements.

EAGLE ROCK ENERGY PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF MEMBERS’ EQUITY

FOR THE THREE MONTH PERIOD ENDED MARCH 31, 2007

(Unaudited)


				Number of					Number of
	General			Common		Common			Subordinated		Subordinated
	Partner			Units		Units			Units		Units			Total
	($ in thousands, except unit amounts)
BALANCE —December 31, 2006	$	(544	)		20,691,495	$	116,283			20,691,495	$	176,248		$	291,987

Net loss		(544	)		—		(5,790	)		—		(13,334	)		(19,668	)
Distributions		—			—		(6,176	)		—		—			(6,176	)
Restricted unit expense		3			—		85			—		85			173


BALANCE — March 31, 2007	$	(1,085	)		20,691,495	$	104,402			20,691,495	$	162,999		$	266,316

See notes to condensed consolidated financial statements.

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. ORGANIZATION AND DESCRIPTION OF BUSINESS

Organization — Eagle Rock Energy Partners, L.P., a Delaware limited partnership, formed in May 2006, is an indirect majority-owned subsidiary of Eagle Rock Holdings, L.P. (“Holdings”). Holdings is a portfolio company of Irving, Texas based private equity capital firm, Natural Gas Partners. Eagle Rock Pipeline, L.P., a Texas limited partnership which was converted later to a Delaware limited partnership, was formed on November 14, 2005 for the purpose of owning a limited partnership interest in Eagle Rock Midstream Resources, L.P.

Initial Public Offering — Eagle Rock Energy Partners, L.P. was formed for the purpose of completing a public offering of common units. On October 24, 2006, it offered and sold 12,500,000 common units in its initial public offering, or IPO, at a price of $19.00 per unit. Net proceeds from the sale of the units, $222.1 million after underwriting costs, were used for reimbursement of capital expenditures for investors prior to the initial public offering, replenish working capital, and distribution arrearage payment. In connection with the initial public offering, Eagle Rock Pipeline, L.P. was merged with and into a newly formed subsidiary of Eagle Rock Energy Partners, L.P.

Basis of Presentation and Principles of Consolidation — The accompanying financial statements include assets, liabilities and the results of operations of Eagle Rock Pipeline, L.P. from November 15, 2005 and the results of operations of Eagle Rock Midstream Resources, L.P. and its predecessor entities for the periods prior to November 15, 2005. The reorganization of these entities was accounted for as a reorganization of entities under common control. The general partner interests of Eagle Rock Pipeline, L.P. and Eagle Rock Midstream Resources, L.P. are held by Eagle Rock Pipeline GP, L.L.C. a wholly-owned subsidiary of Eagle Rock Energy Partners, L.P. On March 22, 2006, Eagle Rock Pipeline GP, L.L.C. and Eagle Rock Pipeline, L.P. were converted to Delaware entities. Eagle Rock Pipeline, L.P., Eagle Rock Midstream Resources, L.P., Eagle Rock Pipeline GP, L.L.C. and their subsidiaries and, effective October 24, 2006, Eagle Rock Energy Partners, L.P. are collectively referred to as “Eagle Rock Energy” or the “Partnership.”

Description of Business — The Partnership, through wholly-owned subsidiaries and partnerships, provides midstream energy services, including gathering, transportation, treating, processing and conditioning services in Texas and Louisiana. The Partnership’s natural gas pipelines gather natural gas from designated points near producing wells and transports 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, conditioned or processed into marketable natural gas and natural gas liquids (NGLs). The Partnership conducts its operations within Louisiana and two geographic areas of Texas. The Partnership’s Texas panhandle assets consist of assets acquired from ONEOK, Inc. on December 1, 2005 (see Note 4), and include gathering and processing assets (the “Texas Panhandle System”). The Partnership’s southeast Texas and Louisiana assets include a non-operated 25% undivided interest in a processing plant as well as a non-operated 20% undivided interest in a connected gathering system (“Texas and Louisiana System”). On April 7, 2006, the Partnership’s Texas and Louisiana System completed the acquisition of a 100% interest in the Brookeland and Masters Creek processing plants in east Texas from Duke Energy Field Services. On June 2, 2006, the Partnership’s Texas and Louisiana System completed the acquisition of 100% of Midstream Gas Services, L.P. (see Note 4)

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 a gas processing plant and a 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 significant intercompany accounts and transactions are eliminated in the consolidated financial statements. The unaudited consolidated interim financial statements as of and for the three months ended March 31, 2007 and 2006 have been prepared on the same basis as the annual financial statements and should be read in conjunction with the annual

financial statements included in the Partnership’s 2006 Annual Report on Form 10-K filed with the Securities and Exchange Commission.

Use of Estimates — The preparation of the financial statements in conformity with accounting policies generally accepted in the United States of America requires management to make estimates and assumptions which affect the reported amounts of assets, liabilities, revenues and expenses and disclosure of contingent assets and liabilities that exist at the date of the financial statements. Although management believes the estimates are appropriate, actual results can differ from those estimates.

Reclassifications — Certain prior year amounts have been reclassified to conform to the current year presentation. These reclassifications had no effect on the result of operations.

Interim Condensed Disclosures — The information for the three month periods ended March 31, 2007 and 2006 is unaudited but in the opinion of management, reflects all adjustments which are normal, recurring and necessary for a fair presentation of financial position and results of operations for the interim periods. Certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been omitted pursuant to the rules and regulations of the Securities and Exchange Commission.

Cash and Cash Equivalents — Cash and cash equivalents include certificates of deposit or 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. During 2006, the Partnership increased the parties to which it was selling liquids and natural gas from two to seven. These 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 credit 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.

Certain Other Concentrations — The Partnership relies on natural gas producer customers for its natural gas and natural gas liquids supply, with two producers accounting for 27% of its natural gas supply in its Texas Panhandle System and 48% of its natural gas supply in the Texas and Louisiana System for the month ended March 31, 2007. While there are numerous natural gas and natural gas liquids producers and some of these producer customers 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.

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, which are carried at cost less accumulated depreciation. 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 principally over 20-year estimated useful lives of the Partnership’s newly developed or acquired assets. The weighted average useful lives are as follows:


Pipelines and equipment		20 years
Gas processing and equipment		20 years
Office furniture and equipment		5 years

The Partnership capitalizes interest on major projects during extended construction time periods. Such interest is allocated to property, plant and equipment and amortized over the estimated useful lives of the related assets. During

the three month period ended March 31, 2007, the Partnership capitalized interest of approximately $0.4 million. The Partnership did not record capitalized interest in the prior year’s first quarter.

The costs of maintenance and repairs, which are not significant improvements, are expensed when incurred. Expenditures to extend the useful lives of the assets or enhance its productivity or efficiency from its original design are capitalized over the expected benefit or useful period.

Impairment of Long-Lived Assets — Management evaluates whether the carrying value of 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 asset. 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.

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 $4.1 million for the three months ended March 31, 2007, and approximately $3.4 million for the three months ended March 31, 2006. Estimated aggregate amortization expense for each of the five succeeding years is as follows: 2008 — $16.5 million; 2009 — $16.5 million; 2010 — $16.5 million; 2011 — $7.7 million; and 2012 — $6.8 million. Intangible assets consisted of the following:


	March 31,			December 31,
*($ in thousands)*	2007			2006
Rights-of-way and easements — at cost	$	68,000		$	66,801
Less: accumulated amortization		(4,355	)		(3,510	)
Contracts		80,210			80,210
Less: accumulated amortization		(16,786	)		(13,500	)

Net intangible assets	$	127,069		$	130,001

The amortization period for our rights-of-way and easements is 20 years and contracts range from 5 to 15 years, respectively, and overall, approximately 13 years average in total as of March 31, 2007.

Other Assets — Other assets primarily consist of costs associated with debt issuance ($7.4 million at March 31, 2007), net of amortization. Amortization of debt issuance costs is calculated using the straight-line method over the maturity of the associated debt (or the expiration of the contract).

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. As of December 31, 2006, the Partnership had imbalance receivables totaling $0.3 million, and imbalance payables totaling $1.9 million, respectively. As of March 31, 2007, the Partnership had imbalance receivables totaling $0.2 million and imbalance payables totaling $1.8 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 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 we generate revenues from transportation fees.

Revenues associated with sales of natural gas, NGLs and condensate are recognized when title passes to the customer, which is when the risk of ownership passes to the purchaser and physical delivery occurs. Revenues associated with transportation and processing fees are recognized when the service is provided.

For gathering and processing services, Eagle Rock Energy either receives fees or commodities from natural gas producers depending on the type of contract. Commodities received are in turn sold and recognized as revenue in accordance with the criteria outlined above. 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. Under the keep-whole contract type, Eagle Rock Energy purchases wellhead natural gas 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.

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. The Partnership has recorded environmental liabilities of approximately $0.3 million as of December 31, 2006 and March 31, 2007.

Income Taxes — No provision for federal income taxes related to the operation of Eagle Rock Energy is included in the accompanying consolidated financial statements as such income is taxable directly to the partners holding interests in the Partnership. The state of Texas enacted a margin tax in May 2006 which requires the Partnership to report beginning in 2008, based on 2007 results. The method of calculation for this margin tax is similar to an income tax, requiring the Partnership to recognize currently the impact of this new tax using a margin approach based upon revenues less a qualified portion of cost of goods sold, operating costs and depreciation for 2007 activities. In addition, the future tax effects of temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities are also considered. Approximately $1.4 million estimated deferred state tax liability has been recorded at March 31, 2007. (see Note 13)

Derivatives — Statement of Financial Accounting Standards (“SFAS”) No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended (SFAS No. 133), establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. SFAS No. 133 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. SFAS No. 133 provides that normal purchase and normal sale contracts, when appropriately designated, are not subject to the statement. 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 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 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 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 10 for a description of the Partnership’s risk management activities.

NOTE 3. NEW ACCOUNTING PRONOUNCEMENTS

In February 2006, the Financial Accounting Standards Board (the “FASB”) issued SFAS No. 155, Accounting for Certain Hybrid Financial Instruments, an amendment of FASB Statements No. 133 and No. 140 (SFAS No. 155). SFAS No. 155 amends SFAS No. 133, which required a derivative embedded in a host contract which does not meet the definition of a derivative be accounted for separately under certain conditions. SFAS No. 155 amends SFAS No. 133 to narrow the scope of such exception to strips which represent rights to receive only a portion of the contractual interest cash flows or of the contractual principal cash flows of a specific debt instrument. In addition, SFAS No. 155 amends SFAS No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities, which permitted a qualifying special-purpose entity to hold only a passive derivative financial instrument pertaining to beneficial interests issued or sold to parties other than the transferor. SFAS No. 155 amends SFAS No. 140 to allow a qualifying special purpose entity to hold a derivative instrument pertaining to beneficial interests that itself is a derivative financial instrument. SFAS No. 155 is effective for all financial instruments acquired or issued (or subject to a re-measurement event) following the start of an entity’s first fiscal year beginning after September 15, 2006. The Partnership adopted SFAS No. 155 on January 1, 2007, and it had no effect on the results of operations or financial position for the quarter ended March 31, 2007.

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements. This statement defines fair value, establishes a framework for measuring fair value, and expands disclosure about fair value measurements. The statement is effective for financial statements issued for fiscal years beginning after November 15, 2007. The Partnership is currently evaluating the effect the adoption of this statement will have, if any, on its consolidated results of operations and financial position.

In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities (SFAS No. 159), which permits entities to choose to measure many financial instruments and certain other items at fair value. SFAS No. 159 is effective for us as of January 1, 2008 and will have no impact on amounts presented for periods prior to the effective date. We cannot currently estimate the impact of SFAS No. 159 on our consolidated results of operations, cash flows or financial position and have not yet determined whether or not we will choose to measure items subject to SFAS No. 159 at fair value.

A significant portion of the Partnership’s sale and purchase arrangements are accounted for on a gross basis in the 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. In accordance with the provision of Emerging Issues

Task Force Issue No. 04-13, Accounting for Purchases and Sales of Inventory with the Same Counterparty (“EITF 04-13”), the Partnership reflects the amounts of revenues and purchases for these transactions as a net amount in its consolidated statements of operations beginning with April 2006. For the quarter ended March 31, 2007, the Partnership did not enter into any purchase and sale agreements with the same counterparty. As a result, EITF 04-13 had no effect on the results of operations for the quarter ended March 31, 2007.

In July 2006, the FASB issued FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes – an interpretation of FASB Statement No. 109 (FIN 48), which clarifies the accounting and disclosure for uncertainty in tax positions, as defined. FIN 48 seeks to reduce the diversity in practice associated with certain aspects of the recognition and measurement related to accounting for income taxes. This interpretation is effective for fiscal years beginning after December 15, 2006. The adoption of FIN 48 did not have a material impact on our results of operations or financial position.

NOTE 4. ACQUISITIONS

On March 31, 2006, the Partnership’s southeast Texas and Louisiana System completed the acquisition of an 80% interest in the Brookeland gathering and processing facility, a 76.3% interest in the Masters Creek gathering system and 100% of the Jasper NGL line for $75.7 million to solidify the Partnership’s southeast Texas and Louisiana operations and to integrate with the segment’s existing operations. The Partnership commenced recording these results of operations on April 1, 2006. On April 7, 2006, the remaining interests were acquired for $20.2 million and the results of operations have been recorded effective as of April 1, 2006, as the results of operations for the period April 1, 2006 to April 7, 2006, were not material. In connection with the acquisition, the Partnership made a $7.6 million escrow deposit for the acquisition of these assets. This escrow cash was released on March 31, 2006. The purchase price was allocated on a preliminary basis to property, plant and equipment and intangibles in the amounts of $89.0 million and $8.0 million, respectively, based on their respective fair value as determined by management with the assistance of a third-party valuation specialist. In addition to long-term assets, the Partnership assumed certain accrued liabilities. The purchase price has been allocated as presented below.


*($ in thousands)*
Property, plant and equipment	$	89,054
Intangibles		7,992
Other current liabilities		(750	)
Asset retirement obligations		(291	)

	$	96,005

On June 2, 2006, the Partnership purchased Midstream Gas Services, L.P. (“MGS”) for $4.7 million in cash and 809,174 (1,125,416 pre-IPO conversion) common units to integrate with the Texas Panhandle Systems’ existing operations. The Partnership will issue up to 798,113 common units, converted at the time of the initial public offering (1-for-0.719), to the prior equity owner of MGS, as a contingent earn-out payment if MGS achieves certain financial objectives for the year ending December 31, 2007. The Partnership commenced recording the results of operations on June 2, 2006.

The following unaudited pro forma information for the quarter ended March 31, 2006, assumes the Brookeland gathering and processing facility, the Masters Creek gathering system, the Jasper NGL line and the MGS interests (only for 2006) had been acquired on January 1, 2006:


	Quarter Ended
($ in thousands)	March 31, 2006
Pro forma earnings data:
Revenues	$	106,998
Costs and expenses		(119,645	)

Operating income		12,647
Other income (expense), net		(2,495	)

Loss from continuing operations	$	(15,142	)

NOTE 5. FIXED ASSETS AND ASSET RETIREMENT OBLIGATIONS

Fixed assets consisted of the following:


	March 31,			December 31,
*($ in thousands)*	2007			2006
Land	$	853		$	853
Plant		82,082			81,485
Gathering and pipeline		458,577			433,779
Equipment and machinery		38,023			37,185
Vehicles and transportation equipment		2,799			2,740
Office equipment, furniture, and fixtures		511			511
Computer equipment		4,618			4,623
Corporate		126			126
Linefill		3,970			3,923
Construction in progress		15,924			19,677

		607,483			584,902
Less: accumulated depreciation and amortization		(38,336	)		(30,839	)

Net fixed assets	$	569,147		$	554,063

Depreciation expense for the three months ended March 31, 2007 and 2006 was approximately $7.5 million and $5.6 million, respectively.

Asset Retirement Obligations — On December 31, 2005, we adopted FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143 (“FIN 47”). FIN 47 clarified that the term “conditional asset retirement obligation”, as used in SFAS No. 143, Accounting for Asset Retirement Obligations, 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 our 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, we are required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. The adoption of FIN 47 had no impact on the Partnership’s financial statements.

A reconciliation of our liability for asset retirement obligations is as follows:


*($ in thousands)*
Asset retirement obligations — December 31, 2006	$	1,819
Additional liability on newly built assets		49
Accretion expense		37

Asset retirement obligations — March 31, 2007	$	1,905

NOTE 6. LONG-TERM DEBT

Long-term debt consisted of:


	March 31,		December 31,
*($ in thousands)*	2007		2006
Revolver	$	106,481	$	106,481
Term loan		299,250		299,250

Total debt		405,731		405,731
Less: current portion		—		—

Total long-term debt	$	405,731	$	405,731

On August 31, 2006, the Partnership amended and restated its existing credit agreement (the “Amended and Restated Credit Agreement”). The Amended and Restated Credit Agreement is a $500.0 million credit agreement with

a syndicate of commercial and investment banks and institutional lenders, with Goldman Sachs Credit Partners L.P., as the administrative agent. The Amended and Restated Credit Agreement provides for $300.0 million aggregate principal amount of Series B Term Loans (the “Term Loan”) and up to $200.0 million aggregate principal amount of Revolving Commitments (the “Revolver”). The Amended and Restated Credit Agreement includes a sub limit for the issuance of standby letters of credit for the aggregate unused amount of the Revolver. At March 31, 2007, the Partnership had $2.5 million of outstanding letters of credit. In addition, the loan agreement allows the Partnership to expand its credit facility by an additional $100.0 million if the Partnership meets certain financial conditions.

During the quarter ended March 31, 2007 and 2006, the Partnership recorded approximately $0.4 million and $0.2 million of debt issuance amortization expense, respectively. As of March 31, 2007, the unamortized amount of debt issuance costs was $7.4 million.

With the consummation of the Partnership’s initial public offering on October 27, 2006, quarterly installments under the Term Loan ceased with the balance due on the Term Loan maturity date, August 31, 2011. The Revolver matures on the revolving commitment termination date, August 31, 2011.

In certain instances defined in the Amended and Restated Credit Agreement, the Term Loan is subject to mandatory repayments and the Revolver is subject to a commitment reduction for cumulative asset sales exceeding $15.0 million; insurance/condemnation proceeds; the issuance of equity securities; and the issuance of debt.

The Amended and Restated Credit Agreement contains various covenants which limit the Partnership’s ability to grant certain 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 Amended and Restated Credit Agreement 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 $7.5 million.

The Amended and Restated Credit Agreement also contains covenants, which, among other things, require the Partnership, on a consolidated basis, to maintain specified ratios or conditions as follows:

	•		Adjusted EBITDA (as defined) to interest expense of not less than 2.5 to 1.0; and

	•		Total consolidated funded debt to Adjusted EBITDA (as defined) of not more than 5.0 to 1.0 and 5.25 to 1.0 for the three quarters following a material acquisition.

Based upon the senior debt to Adjusted EBITDA ratio calculated as of March 31, 2007 (utilizing the September 2006, December 2006 and March 2007 quarters Consolidated Adjusted EBITDA as defined under the Credit Agreement annualized for an annual Adjusted EBITDA amount for the ratio), the Partnership has approximately $1.5 million of unused capacity under the Amended and Restated Credit Agreement Revolver at March 31, 2007.

At the Partnership’s election, the Term Loan and the Revolver bear interest on the unpaid principal amount either at a base rate plus the applicable margin (defined as 1.25% per annum, reducing to 1.00% when consolidated funded debt to Adjusted EBITDA (as defined) is less than 3.5 to 1); or at the Adjusted Eurodollar Rate plus the applicable margin (currently 2.75% per annum, reducing to 2.25% when consolidated funded debt to Adjusted EBITDA (as defined) is less than 3.5 to 1). At March 31, 2007, the weighted average interest rate on our outstanding debt balance was 8.13%. The applicable margin increased by 0.50% per annum on January 31, 2007, under the Amended and Restated Credit Agreement as the Partnership elected not to obtain a rating by S&P and Moody’s.

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- or six-, nine- or twelve-months, as selected by the Partnership. Interest on the Term Loan is paid approximately each March 31, June 30, September 30 and December 31 of each year. The Partnership pays a commitment fee equal to (1) the average of the daily difference between (a) the revolver commitments and (b) the sum of the aggregate principal amount of all outstanding revolver loans plus the aggregate principal amount of all outstanding swing loans times (2) 0.50% per annum; provided, the commitment fee percentage increased by 0.25% per annum on January 31, 2007, as the Partnership elected not to obtain a rating by S&P and Moody’s. 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 whether 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 obligations under the Amended and Restated Credit Agreement are secured by first priority liens on substantially all of the Partnership’s assets, including a pledge of all of the capital stock of each of its subsidiaries.

Prior to entering into the Amended and Restated Credit Agreement, the Partnership operated under a $475.0 million credit agreement (the “Credit Agreement”) with a syndicate of commercial banks, including Goldman Sachs Credit Partners L.P., as the administrative agent. The Credit Agreement was entered into on December 1, 2005. The Credit Agreement provided for $400.0 million aggregate principal amount of Series A Term Loans (the “Original Term Loan”) and up to $75.0 million ($100.0 million effective June 2, 2006) aggregate principal amount of Revolving Commitments (the “Original Revolver”). The Credit Agreement included a sub limit for the issuance of standby letters of credit for the lesser of $55.0 million or the aggregate unused amount of the Original Revolver.

Scheduled maturities of long-term debt as of March 31, 2007, were as follows:


	Principal
*($ in thousands)*	Amount
2007	$	0
2008		0
2009		0
2010		0
2011		405,731

	$	405,731

The Partnership was in compliance with the financial covenants under the Amended and Restated Credit Agreement as of March 31, 2007. If an event of default existed under the Amended and Restated Credit Agreement, the lenders would be able to accelerate the maturity of the Amended and Restated Credit Agreement and exercise other rights and remedies.

NOTE 7. MEMBERS’ EQUITY

At March 31, 2007, there were 20,691,496 common units and 20,691,496 subordinated units (all subordinated units owned by Holdings) outstanding. In addition, there were 115,150 restricted unvested common units outstanding.

Subordinated units represent limited liability interests in the Partnership, and holders of subordinated units exercise the rights and privileges available to unitholders under the limited liability company agreement. Subordinated units, during the subordination period, will generally receive quarterly cash distributions only when the common units have received a minimum quarterly distribution of $0.3625 per unit. Subordinated units will convert into common units on a one-for-one basis when the subordination period ends. Pursuant to the Partnership’s agreement of limited partnership, the subordination period will extend to the earliest date following March 31, 2009 for which there does not exist any cumulative common unit arrearage.

On January 26, 2007, the Partnership declared its 2006 fourth quarter cash distribution to its common unitholders of record as of February 7, 2007. The distribution amount per common unit was $0.3625 which was adjusted to $0.2679 per unit for the partial quarter the units were outstanding due to the initial public offering date. The distribution was made on February 15, 2007. A distribution was also made to the pre-IPO common unitholders for the period before the effective date of the initial public offering. No distributions were declared on the general partner or subordinated units.

NOTE 8. RELATED PARTY TRANSACTIONS

Holdings previously had a management advisory arrangement with Natural Gas Partners requiring a quarterly fee payment. The fee paid under the advisory arrangement has been expensed by the Partnership. For the quarter ended March 31, 2006, the Partnership expensed $0.1 million for the management advisory arrangement. At the time of the initial public offering, Holdings terminated the agreement with a $6.0 million payment to Natural Gas Partners. The termination fee was recorded as an expense of the Partnership during the fourth quarter of 2006, with the offset as a capital contribution. Holdings owns and controls the general partner of the partnership while Holdings is controlled by Natural Gas Partners with minority ownership by certain management personnel and board members of the Partnership’s general partner.

On July 1, 2006, the Partnership entered into a month to month contract for the sale of natural gas with an affiliate of Natural Gas Partners, under which the Partnership’s Texas Panhandle Systems has the option to sell a portion of its gas supply. The Partnership has received a Letter of Credit related to this agreement. The Partnership recorded revenues of $5.7 million for the three month period ended March 31, 2007 from the agreement, of which there was a receivable of $2.9 million outstanding at March 31, 2007.

The Partnership entered into an Omnibus Agreement with Eagle Rock Energy G&P, LLC, Holdings and the Partnership’s general partner which requires the Partnership to reimburse Eagle Rock Energy G&P, LLC for the payment of certain expenses incurred on the Partnership’s behalf, including payroll, benefits, insurance and other operating expenses, and provides certain indemnification obligations.

The Partnership does not directly employ any persons to manage or operate our business. Those functions are provided by our general partner. We reimburse the general partner for all direct and indirect costs of these services.

On March 31, 2007, the Partnership entered into a Partnership Interest Contribution Agreement with Montierra Minerals & Production, L.P. and NGP-VII Income Co-Investment Opportunities, L.P., to acquire certain fee minerals, royalties and working interests. This transaction closed on April 30, 2007. Both contributors are affiliates of Natural Gas Partners. See Note 15 for a further discussion.

NOTE 9. FAIR VALUE OF FINANCIAL 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 carrying amount of cash equivalents is believed to approximate their fair values because of the short maturities of these instruments. As of March 31, 2007, the debt associated with the Amended and Restated Credit Agreement bore interest at floating rates. As such, carrying amounts of these debt instruments approximates fair value.

NOTE 10. RISK MANAGEMENT ACTIVITIES

The Credit Agreement required the Partnership to enter into interest rate risk management activities. In December 2005, 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 this swap is to eliminate interest rate variability by converting LIBOR-based variable-rate payments to fixed-rate payments for a period of five years from January 1, 2006 to January 1, 2011. Amounts received or paid under these swaps were recorded as reductions or increases in interest expense. The table below summarizes the terms, amounts received or paid and the fair values of the various interest rate swaps:


								($ in thousands)
								Fair Value
Roll Forward	Expiration		Notional		Fixed			March 31,
Effective Date	Date		Amount		Rate			2007
01/03/2006		01/03/2011	$	100,000,000		4.9500	%	$	(264	)
01/03/2006		01/03/2011		100,000,000		4.9625			(213	)
01/03/2006		01/03/2011		50,000,000		4.8800			21
01/03/2006		01/03/2011		50,000,000		4.8800			21

For the three month period ended March 31, 2007 and 2006, the Partnership recorded a fair value loss within interest expense of $1.6 million and $0.1 million, respectively. As of March 31, 2007 and 2006, the fair value liability of these contracts totaled approximately $0.4 million and approximately $3.2 million, respectively.

The prices of natural gas and NGLs are subject to fluctuations in response to changes in supply, market uncertainty and a variety of additional factors which are beyond the Partnership’s control. In order to manage the risks associated with natural gas and NGLs, the Partnership engages in risk management activities that take the form of commodity derivative instruments. Currently these activities are governed by the general partner, which today typically prohibits speculative transactions and limits the type, maturity and notional amounts of derivative transactions. We will be implementing a Risk Management Policy which will allow management to execute crude oil, natural gas liquids and natural gas hedging instruments in order to reduce exposure to substantial adverse changes in the prices of these commodities. We intend to monitor and ensure compliance with this Risk Management Policy through senior level executives in our operations, finance and legal departments.

During 2005 and 2006, the Partnership entered into the following risk management activities:

	•		Over-the-counter NGL puts, costless collar and swap transactions for the sale of Mont Belvieu gas liquids with a combined notional amount of 530,000 Bbls per month for a term from January 2006 through December 2010;

	•		Condensate puts and costless collar transactions for the sale of West Texas Intermediate crude oil with a combined notional amount of 250,000 Bbls per month for a term from January 2006 through December 2010;

	•		Natural gas calls for the sale of Henry Hub natural gas with a notional amount of 200,000 MMBtu per month for a term from January 2006 through December 2007;

	•		Costless collar transactions for West Texas Intermediate crude oil with a combined notional amount of 50,000 Bbls per month for a term of October through December 2006; and, 60,000 Bbls per month for a term of January 2007 through December 2007;

	•		Fixed swap agreements to hedge WTS-WTI basis differential in amount of 20,000 Bbls per month for a term of October-December 2006; and, 20,000 Bbls per month for a term of January through December 2007; and

	•		Natural gas fixed swap agreements to hedge short natural gas positions with a combined notional amount of 100,000 MMBtu per month for the term of August 2006 through September 2006.

The counterparties used for these transactions have investment grade ratings. The NGL and condensate derivatives are intended to hedge the risk of weakening NGL and condensate prices with offsetting increases in the value of the puts based on the correlation between NGL prices and crude oil prices. The natural gas derivatives are included to hedge the risk of increasing natural gas prices with the offsetting value of the natural gas calls.

The Partnership has not designated these derivative instruments as hedges and as a result is marking these derivative contracts to market with changes in fair values recorded as an adjustment to the mark-to-market gains / losses on risk management transactions within revenue. For the three month period ended March 31, 2007, the Partnership recorded a loss on risk management instruments of $7.6 million, representing a fair value (unrealized) loss of $8.5 million, amortization of put premiums of $2.1 million and net (realized) settlements loss from the Partnership of $3.1 million. As of March 31, 2007, the fair value liability of these contracts, including the put premiums, totaled approximately $2.2 million.

For the three month period ended March 31, 2006, the Partnership recorded a loss on risk management instruments of $20.2 million, representing a fair value (unrealized) loss of $15.9 million, amortization of put premiums of $5.1 million and net (realized) settlements gain from the Partnership of $0.8 million. As of March 31, 2006, the fair value gain of these contracts, including premiums, totaled $13.7 million.

NOTE 11. COMMITMENTS AND CONTINGENT LIABILITIES

Litigation — The Partnership is subject to several lawsuits, primarily related to the payments of liquids and gas proceeds in accordance with contractual terms. The Partnership has accruals of approximately $2.8 million and $1.5 million as of March 31, 2007 and December 31, 2006, respectively, related to these matters. In April 2007, the Partnership received notice of an arbitration award against the Partnership in the approximate amount of $1.4 million. The award relates to a fee dispute regarding our Panhandle Segment and such dispute occurred prior to our acquisition of those assets. The Partnership recorded the liability for such arbitration award in the first quarter 2007 in Other expense in the income statement. In addition, the Partnership is also subject to other lawsuits related to the payment of liquid and gas proceeds in accordance with contractual terms for which the Partnership has been indemnified up to a certain dollar amount. 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, 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.

Insurance — The Partnership carries insurance coverage which includes the assets and operations, which management believes is consistent with companies engaged in similar commercial operations with similar type properties. These insurance coverages include (1) commercial general public liability insurance for liabilities arising to third parties for bodily injury and property damage resulting from Eagle Rock Energy field operations; (2) workers’ compensation liability coverage to required statutory limits; (3) automobile liability insurance for all owned, non-owned and hired vehicles covering liabilities to third parties for bodily injury and property damage, (4) property insurance covering the replacement value of all real and personal property damage, including damages arising from boiler and machinery breakdowns, earthquake, flood damage and business interruption/extra expense, and (5) corporate liability policies including Directors and Officers coverage and Employment Practice liability coverage. All coverages are subject to certain deductibles, terms and conditions common for companies with similar types of operation.

The Partnership also maintains excess liability insurance coverage above the established primary limits for commercial general liability and automobile liability insurance. Limits, terms, conditions and deductibles are comparable to those carried by other energy companies of similar size. The cost of general insurance coverages continued to fluctuate over the past year reflecting the changing conditions of 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, compliance with existing laws and regulations will not materially affect the financial position of the Partnership.

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 March 31, 2007 and December 31, 2006, the Partnership had accrued approximately $0.3 million for environmental matters.

Other Commitments and Contingencies — 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 $0.2 million and $0.1 million for the quarters ended March 31, 2007 and 2006, respectively. Rental expense for leases with escalation clauses is recognized on a straight-line basis over the initial lease term.

NOTE 12. SEGMENTS

Based on the Partnership’s approach to managing its assets, the Partnership believes its operations consist of two geographic segments and one functional (corporate) segment: (i) gathering, processing, transportation and marketing of natural gas in the Texas Panhandle System, (ii) gathering, natural gas processing and related NGL transportation in the Texas and Louisiana System, and (iii) risk management and other corporate activities. The Partnership’s chief operating decision-maker currently reviews its operations using these segments. The Partnership evaluates segment performance based on segment margin before depreciation and amortization. Transactions between reportable segments are conducted on a basis believed to be at market values.

Summarized financial information concerning the Partnership’s reportable segments is shown in the following table:


*($ in millions)*			Texas and
Three months ended March 31, 2007	Panhandle		Louisiana		Corporate			Total
Sales to external customers	$	94.9	$	19.5	$	(7.6	)^(a)	$	106.8
Interest expense-net and other financing costs		—		—		9.4			9.4
Depreciation and amortization		9.8		1.6		0.2			11.6
Segment profit (loss)(b)		19.2		4.5		(7.6	)		16.1
Capital expenditures		8.8		13.6		1.1			23.5
Segment assets		574.0		160.4		38.4			772.8


*($ in millions)*			Texas and
Three months ended March 31, 2006	Panhandle		Louisiana		Corporate			Total
Sales to external customers	$	106.5	$	9.9	$	(20.1	)	$	96.3
Interest expense-net and other financing costs		—		—		2.5			2.5
Depreciation and amortization		8.1		0.8		0.3			9.2
Segment profit (loss)(b)		22.0		1.7		(19.3	)		4.4
Capital expenditures		2.1		2.7		1.4			6.2
Segment assets		570.7		105.7		101.1			777.5


(a)		Represents results of our derivatives activity.

(b)		Segment profit (loss) is defined as sales to external customers minus cost of natural gas and natural gas liquids and other cost of sales. Sales to external customers for the corporate column include the impact of the risk management activities.

The following table reconciles segment profit (loss) to income from continuing operations:


	Three Months			Three Months
	Ended			Ended
	March 31,			March 31,
*($ in millions)*	2007			2006
Segment profit	$	16.1		$	4.4
Operations and maintenance		(7.9	)		(5.7	)
General and administrative		(4.9	)		(2.4	)
Depreciation and amortization		(11.6	)		(9.2	)
Other expense		(1.7	)		—
Interest expense, net		(9.5	)		(2.6	)
State income tax provision		(0.2	)		—

Net loss	$	(19.7	)	$	(15.5	)

NOTE 13. INCOME TAXES

No provision for federal income taxes related to the operation of the Partnership is included in the consolidated financial statements as such income is taxable directly to the partners holding interests in the Partnership. In May

2006, the State of Texas enacted a margin tax which will become effective in 2008. This margin tax will require the Partnership to determine a tax of 1.0% on our “margin,” as defined in the law, beginning in 2008 based on our 2007 results. The margin to which the tax rate will be applied generally will be calculated as our revenues for federal income tax purposes less a qualified portion of the cost of the products sold, operating expenses and depreciation expense for federal income tax purposes, in the state of Texas. Under the provisions of Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes”, the Partnership is required to record the effects on deferred taxes for a change in tax rates or tax law in the period which includes the enactment date. For the March 2007 quarter, the Partnership recorded approximately $0.2 million deferred state tax expense.

Under FAS 109, taxes based on income like the Texas margin tax are accounted for using the liability method under which deferred income taxes are recognized for the future tax effects of temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities using the enacted statutory tax rates in effect at the end of the period. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized.

Temporary differences related to the Partnership’s property, including depreciation expense, will affect the Texas margin tax. As of March 31, 2007, the Partnership has a deferred state tax liability in the approximate amount of $1.4 million.

NOTE 14. EQUITY-BASED COMPENSATION

On October 24, 2006, the general partner of the general partner for Eagle Rock Energy Partners, L.P., approved a long-term incentive plan (LTIP) for its employees, directors and consultants who provide services to the Partnership covering an aggregate of 1,000,000 common unit options, restricted units and phantom units. With the consummation of the initial public offering on October 24, 2006, 124,450 restricted common units were issued to the employees and directors of the General Partner who provide services to the Partnership. 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 held by the Partnership and will be distributed to the awardees upon the restriction lapsing. No options or phantom units have been issued to date.

A summary of the restricted common units activity for the quarter ended March 31, 2007, is provided below:


	Number of			Weighted Average
	Restricted			Grant - Date Fair
	Units			Value
Outstanding at December 31, 2006		122,450		$	18.75
Granted		—
Vested		—
Forfeitures		(7,300	)	$	18.75

Outstanding at March 31, 2007		115,150		$	18.75

For the first quarter of 2007, non-cash compensation expense of approximately $0.2 million was recorded related to the granted restricted units.

As of March 31, 2007, unrecognized compensation costs related to the outstanding restricted units under our LTIP totaled approximately $1.9 million. The granted restricted units were valued at the market price of the initial public offering less a discount for the delay in their cash distributions during the unvested period. The remaining expense is to be recognized over a weighted average of 2.5 years.

NOTE 15. SUBSEQUENT EVENTS

On April 30, 2007, Eagle Rock Energy Partners, L.P., a Delaware limited partnership (“Eagle Rock,” or “Contributee”) completed the acquisition of certain fee minerals, royalties and working interest properties from Montierra Minerals & Production, L.P., a Delaware limited partnership (“Montierra”), and NGP-VII Income Co-Investment Opportunities, L.P., a Texas limited partnership (“Co-Invest”) for an aggregate purchase price of $127.4

million (the “Montierra Acquisition”). Moniterra and NGP received as consideration a total of 6,390,400 Eagle Rock common units and $6.0 million in cash.

One or more Natural Gas Partners private equity funds (“NGP”) directly or indirectly owns a majority of the equity interests in Eagle Rock, Montierra and Co-Invest. Because of the potential conflict of interest between the interests of Eagle Rock Energy G&P, LLC (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 Montierra Acquisition. The Conflicts Committee, consisting of independent Directors of the Company, determined that the Montierra 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 Montierra 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 Montierra, including cash receipts and royalty interests.

On May 3, 2007, Eagle Rock completed the acquisition of all of the non-corporate interests of Laser Midstream Energy, LP, including its subsidiaries Laser Quitman Gathering Company, LP, Laser Gathering Company, LP, Hesco Gathering Company, LLC, and Hesco Pipeline Company, LLC (the “Laser Acquisition”) for a total purchase price of $136.8 million, consisting of $110.0 million in cash and 1,407,895 of Eagle Rock common units, subject to customary post-closing adjustments.

On May 3, 2007, Eagle Rock completed the sale of 7,005,495 common units (the “Offering”) to several institutional purchasers in a private offering exempt from registration pursuant to Section 4(2) and Regulation D (Rule 506) under the Securities Act of 1933, as amended (the “Securities Act”). The units were purchased at a price of $18.20 per unit resulting in gross proceeds of $127.5 million. The proceeds from the Offering were used to fully fund the cash portion of the purchase price of the Laser Acquisition and other general company purposes.

On May 4, 2007, the Partnership expanded its revolver commitment level under its Amended and Restated Credit Agreement by $100.0 million to $300.0 million in total. No incremental funding under the Amended and Restated Credit Agreement was needed for the related acquisitions.

On May 4, 2007, the Partnership declared a cash distribution of $0.3625 per unit for the first quarter ending March 31, 2007. The distribution will be paid May 15, 2007, for common unitholders of record as of May 7, 2007, not including unitholders who acquired units in either the Montierra Acquisition or the Laser Acquisition.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Overview

We are a Delaware limited partnership formed in March 2006 to own and operate the assets that have historically been owned and operated by Eagle Rock Pipeline, L.P. and its subsidiaries. In 2002, certain members of our management team formed Eagle Rock Energy, Inc. to provide midstream services to natural gas producers. In 2003, members of our management team and Natural Gas Partners formed Eagle Rock Holdings, L.P., the successor to Eagle Rock Energy, Inc., to own, operate, acquire and develop complementary natural gas midstream assets. Our growth is organic as well as through acquisitions. We have grown significantly through acquisitions, including the acquisitions of:

	•		our Texas Panhandle Systems from ONEOK Texas Field Services, L.P.;

	•		our Brookeland processing plant and system and Masters Creek system from Duke Energy Field Services, L.P. and Swift Energy Corporation;

	•		our pro-rata undivided interests in the Indian Springs processing plant and Camp Ruby gathering system, both of which are operated by an affiliate of Enterprise Products Partners, L.P.; and

	•		Midstream Gas Services, L.P.

Our organic growth projects include the expansion and extension of our gathering systems in the Texas Panhandle

(East-West gathering pipeline) and our Tyler County pipeline and extension allowing for flexibility between our southeast Texas and Louisiana System (Brookeland, Masters Creek and Indian Springs), as well as increasing gas well connects and processing plants modifications. In addition, we put into service the extension of our Tyler County pipeline in late March 2007 and will be starting up our idled Red Deer processing plant in the Texas Panhandle Systems during the second quarter of 2007.

One or more Natural Gas Partners private equity funds (“NGP”) directly or indirectly owns a majority of the equity interests in Eagle Rock, Montierra and Co-Invest. Because of the potential conflict of interest between the interests of Eagle Rock Energy G&P, LLC (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 Montierra Acquisition. The Conflicts Committee, consisting of independent Directors of the Company, determined that the Montierra 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 Montierra Acquisition, the Board of Directors 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 Montierra, including cash receipts and royalty interests.

We believe we have significant opportunities for continued expansion of our existing gathering and processing systems in order to increase the capacity, efficiency and profitability of these systems through the implementation of commercial and operational development projects. Additionally, we have significant opportunities to expand our newly acquired exploration and production assets.

Cautionary Note Regarding Forward-Looking Statements

Certain matters discussed in this report, excluding historical information, as well as some statements by Eagle Rock Energy Partners, L.P. (the Partnership) in periodic press releases and some oral statements of Partnership officials during presentations about the Partnership, include certain “forward-looking” statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Statements using words such as “anticipate,” “believe,” “intend,” “project,” “plan,” “continue,” “estimate,” “forecast,” “may,” “will,” or similar expressions help identify forward-looking statements. Although the Partnership believes such forward-looking statements are based on reasonable assumptions and current expectations and projections about future events, no assurance can be given that these objectives will be reached. Actual results may differ materially from any results projected, forecasted, estimated or expressed in forward-looking statements since many of the factors which determine these results are subject to uncertainties and risks, difficult to predict, and beyond management’s control.

For additional discussion of risks, uncertainties and assumptions, see our Annual Report on Form 10-K for the year ended December 31, 2006, filed with the Securities and Exchange Commission on April 2, 2007.

Our Operations

Our results of operations for our Texas Panhandle Systems and our southeast Texas and Louisiana System are determined primarily by the volumes of natural gas gathered, compressed, treated, processed and transported through our gathering, processing and pipeline systems and the associated commodity prices for natural gas, NGLs and condensate. We gather and process natural gas pursuant to a variety of arrangements generally categorized as “fee-based” arrangements, “percent-of-proceeds” arrangements and “keep-whole” arrangements. Under fee-based arrangements, we earn cash fees for the services we render. Under the latter two types of arrangements, we generally purchase raw natural gas and sell processed natural gas and NGLs.

Percent-of-proceeds and keep-whole arrangements involve commodity price risk to us because our margin is based in part on natural gas and NGL prices. We seek to minimize our exposure to fluctuations in commodity prices in several ways, including managing our contract portfolio. In managing our contract portfolio, we classify our gathering and processing contracts according to the nature of commodity risk implicit in the settlement structure of those contracts.

	•		Fee-Based Arrangements. Under these arrangements, we generally are paid a fixed cash fee 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 our fee revenues. These arrangements provide stable cash flows, but minimal, if any, upside in higher commodity price environments. As of March 31, 2007, these arrangements accounted for approximately 11% of our natural gas volumes.

	•		Percent-of-Proceeds Arrangements. Under these arrangements, we generally gather raw natural gas from producers at the wellhead, transport the gas through our gathering system, process the gas and sell the processed gas and/or NGLs at prices based on published index prices. These arrangements provide upside in high commodity price environments, but result in lower margins in low commodity price environments. We regard the margin from this type of arrangement, that is, the sale proceeds less amounts remitted to the producers, as an important analytical measure of these arrangements. The price paid to producers is based on an agreed percentage of one of the following: (1) the actual sale proceeds; (2) the proceeds based on an index price; or (3) the proceeds from the sale of processed gas or NGLs or both. We refer to contracts in which we share 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, as “percent-of-liquids” arrangements. Under percent-of-proceeds arrangements, our margin correlates directly with the prices of natural gas and NGLs and under percent-of-liquids arrangements, our margin correlates directly with the prices of NGLs (although there is often a fee-based component to both of these forms of contracts in addition to the commodity sensitive component). As of March 31, 2007, these arrangements accounted for about 77% of our natural gas volumes. Approximately 76% of the percent-of-proceeds volumes as of March 31, 2007 also have fee components.

	•		Keep-Whole Arrangements. Under these arrangements, we process raw natural gas 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 gas or its cash equivalent. We are generally entitled to retain the processed NGLs and to sell them for our account. Accordingly, our margin is a function of 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. 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 large 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 of our keep-whole contracts include provisions that reduce our commodity price exposure, including (1) conditioning floors that require the keep-whole contract to convert to a fee-based arrangement if the NGLs have a lower value than their thermal equivalent in natural gas, (2) embedded discounts to the applicable natural gas index price under which we may reimburse the producer an amount in cash for the thermal equivalent volume of raw natural gas acquired from the producer, or (3) fixed cash fees for ancillary services, such as gathering, treating and compressing. As of March 31, 2007, these arrangements accounted for about 12% of our natural gas volumes. Approximately 80% of these keep-whole

arrangements have fee components.

In addition, we are a seller of NGLs and are exposed to commodity price risk associated with downward movements in NGL prices. NGL prices have experienced volatility in recent years in response to changes in the supply and demand for NGLs and market uncertainty. In response to this volatility, we have instituted a hedging program to reduce our exposure to commodity price risk. Under this program, we have hedged substantially all of our share of NGL volumes under percent-of-proceed and keep-whole contracts in 2006 and 2007 through the purchase of NGL put contracts, costless collar contracts and swap contracts. We have also hedged substantially all of our share of NGL volumes under percent-of-proceed contracts from 2008 through 2010 through a combination of direct NGL hedging as well as indirect hedging through crude oil costless collars. Additionally, to mitigate the exposure to natural gas prices from keep-whole volumes, we have purchased natural gas calls from 2006 to 2007 to cover substantially all of our short natural gas position associated with our keep-whole volumes. We anticipate after 2007, our short natural gas position will become a long natural gas position because of our increased volumes in the Texas Panhandle and the volumes contributed from our Brookeland/Masters Creek acquisition. In addition, we intend to pursue fee-based arrangements, where market conditions permit, and to increase retained percentages of natural gas and NGLs under percent-of-proceed arrangements. We continually monitor our hedging and contract portfolio and expect to continue to adjust our hedge position as conditions warrant.

The following is a summary of the contracts that are significant to our operations, which contracts consist of a natural gas liquids exchange agreement, a gathering and processing agreement and four gas purchase agreements.

ONEOK Hydrocarbon. We are a party to a natural gas liquids exchange agreement with ONEOK Hydrocarbon, L.P., dated December 1, 2005. We deliver all of our natural gas liquids extracted at six of our natural gas processing plants in the Texas Panhandle to ONEOK for transportation and fractionation services. We take title to all of these volumes and they are physically delivered to Conway, Kansas where mid-continent type natural gas liquids pricing is available, with an option to exchange certain volumes at Mont Belvieu, Texas where gulf coast type natural gas liquids pricing is available. The primary contract term expires on June 30, 2010, of which an extension to June 30, 2015, may be mutually agreed to by the parties.

Chesapeake Energy Marketing. We are a party to a natural gas purchase agreement with Chesapeake Energy Marketing Inc., dated July 1, 1997, whereby we purchase raw natural gas from a number of wells on acreage dedicated to us located in Moore and Carson Counties, Texas. The natural gas from these wells is delivered into our Stinnett and Cargray gathering and processing systems. The acreage dedication under this contract is for the life of the leases from which the natural gas is produced. We pay Chesapeake an index posted gas price, less a fixed charge and fixed commodity fee and a fixed fuel percentage. Under this contract, there is an annual option to renegotiate the fuel and fees components. The original agreement was between MC Panhandle, Inc. and MidCon Gas Services Corp. and, as a result of ownership changes, the contract is now between Chesapeake and us.

Anadarko E&P. We are a party to a gas gathering and processing agreement with Anadarko E & P Company LP, dated September 1, 1993, whereby we gather and process raw natural gas from a number of wells on acreage dedicated to us located in Jasper and Newton Counties, Texas. The natural gas from these wells is delivered into our Brookeland gathering system and plant. The acreage dedication under this contract is for the life of the leases from which the natural gas is produced. We receive a percentage of the natural gas liquid value and a percentage of the natural gas residue value for gathering and processing services. The original agreement was between Union Pacific Resources Company and Sonat Exploration Company and, as a result of ownership changes, the contract is now between Anadarko and us.

Ergon Energy Partners, L.P. We are a party to a gas purchase agreement with Ergon Energy Partners, L.P., dated September 1, 2005, whereby we gather and process raw natural gas from a number of wells on acreage dedicated to us located in Tyler County, Texas. The natural gas from these wells is delivered to our Tyler County pipeline system. The term of this contract runs through September 30, 2011. We receive a percentage of the natural gas liquid value and fees for gathering and processing services.

Cimarex Energy Marketing. We are a party to a gas purchase agreement with Cimarex Energy Co., dated March 28, 1994, whereby we gather and process raw natural gas from a number of wells on acreage dedicated to us located in Roberts and Hemphill Counties, Texas, delivered to our Canadian processing plant. This is a life of lease contract. We receive a percentage of the natural gas liquid value and a percentage of the natural gas residue value for

gathering and processing services. The original agreement was between Warren Petroleum Company and Wallace Oil & Gas, Inc. and, as a result of ownership changes, the contract is now between Cimarex and us.

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 on a company-wide basis.

Volumes. We must continually obtain new supplies of natural gas to maintain or increase throughput volumes on our gathering and processing systems. 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.

Margins. As of March 31, 2007, our overall portfolio of processing contracts reflected a net short position in natural gas of approximately 3,252 MMBtu/d (meaning we were a net buyer of natural gas) and a net long position in NGLs (including condensate) of approximately 6,822 Bbls/d (meaning we were a net seller of NGLs). As a result, during this period, our margins were positively impacted to the extent the price of NGLs increased in relation to the price of natural gas and were adversely impacted to the extent the price of NGLs declined 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. This portfolio performed well in response to favorable fractionation spreads during these periods. Because of the hedging program of our commodity risk, we have been able to develop overall favorable fractionation spreads within a range and we anticipate our unit margins will not be subject to significant downward fluctuations if commodity prices were to change in an unfavorable relationship.

Risk Management. For the quarter ended March 31, 2007, our risk management portfolio value changes reflected a $7.6 million unrealized non-cash loss recorded to Total Revenues for our natural gas, natural gas liquids and condensate associated derivatives. In addition, we recorded $1.6 million unrealized non-cash loss within Interest and Other Expense related to the interest rate swaps associated with our credit agreement. As both of the unrealized positions reflect underlying commodity prices and interest rates both in the short and long-term, the unrealized value position will be subject to variability from period to period.

Operating Expenses. Operating expenses are a separate measure we use to evaluate operating performance of field operations. Direct labor, insurance, 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. We do not deduct operating expenses from total revenues in calculating segment margin because we separately evaluate commodity volume and price changes in segment margin.

Adjusted EBITDA. We define Adjusted EBITDA as net income (loss) plus income tax, interest-net, depreciation and amortization expense, other non-cash operating expenses less non realized revenues risk management loss (gain) activities and less net income from discontinued operations. We have included as an addback to net income (loss) for 2007 the approximate $1.4 million arbitration award (see Note 11) due to the award relating to a period before the Partnership owned or operated the related assets. Adjusted EBITDA is useful in determining our ability to sustain or increase distributions. By excluding unrealized derivative gains (losses), a non-cash 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.

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.

General Trends and Outlook

We expect our business to continue to be affected by the following key trends. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about or interpretations of available information prove to be incorrect, our actual results may vary materially from our expected results.

Natural Gas Supply, Demand and Outlook. Natural gas continues to be a critical component of energy consumption in the United States. According to the Energy Information Administration, or EIA, total annual domestic consumption of natural gas is expected to increase from approximately 22.2 trillion cubic feet, or Tcf, in 2005 to approximately 22.35 Tcf in 2010. During the last three years, the United States has on average consumed approximately 22.3 Tcf per year, while total marketed domestic production averaged approximately 18.5 Tcf per year during the same period. The industrial and electricity generation sectors currently account for the largest usage of natural gas in the United States.

We believe current natural gas prices and the existing strong demand for natural gas will continue to result in relatively high levels of natural gas-related drilling in the United States as producers seek to increase their level of natural gas production. Although the natural gas reserves in the United States have increased overall in recent years, a corresponding increase in production has not been realized. We believe this lack of increased production is attributable to insufficient pipeline infrastructure, the continued depletion of existing wells and a tight labor and equipment market. We believe an increase in United States natural gas production, additional sources of supply such as liquid natural gas, and imports of natural gas will be required for the natural gas industry to meet the expected increased demand for natural gas in the United States.

Most of the areas in which we operate are experiencing significant drilling activity. Although we anticipate continued high levels of exploration and production activities in substantially all of the areas in which we operate, fluctuations in energy prices can affect production rates over time and levels of investment by third parties in exploration for and development of new natural gas reserves. We have no control over the level of natural gas exploration and development activity in the areas of our operations.

Impact of Interest Rates and Inflation. The credit markets have experienced historically lows in interest rates over the past several years. If the overall United States economy continues to strengthen, we believe it is likely that monetary policy will tighten further, resulting in higher interest rates to counter possible inflation. Interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. Although this could limit our ability to raise funds in the capital markets, we expect in this regard to remain competitive with respect to acquisitions and capital projects, as our competitors would face similar circumstances.

Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations in 2006 or 2007. It may in the future, however, increase the cost to acquire or replace property, plant and equipment and may increase the costs of labor and supplies. Our operating revenues and costs are influenced to a greater extent by price changes in natural gas and NGLs. To the extent permitted by competition, regulation and our existing agreements, we have and will continue to pass along increased costs to our customers in the form of higher fees.

Formation and Acquisitions

We are a Delaware limited partnership formed in March 2006, to own and operate the assets that have historically been owned and operated by Eagle Rock Holdings, L.P. and its subsidiaries. In 2002, certain members of our management team formed Eagle Rock Energy, Inc. to provide midstream services to natural gas producers. In 2003, members of our management team and Natural Gas Partners formed Eagle Rock Holdings, L.P., the successor to Eagle Rock Energy, Inc., to own, operate, acquire and develop complementary midstream energy assets. Natural Gas Partners is one of the largest private equity fund sponsors of companies in the energy sector and, since 2003, has provided us with significant support in pursuing acquisitions.

Acquisition of Camp Ruby Gathering System and Indian Spring Processing Plant and Expansion of System

On July 28, 2004, we acquired certain minority-owned, non-operated undivided interests in natural gas gathering and processing assets from Black Stone Minerals for approximately $20.0 million. The assets consisted of a 20% undivided interest in the Camp Ruby gathering system and a 25% undivided interest in its related Indian Springs processing facility, both located in Southeast Texas. An affiliate of Enterprise Products Partners, L.P. currently owns the remaining interests in the facilities and is the operator of each of the facilities, having taken over the ownership of the majority interest and operation of the assets from El Paso in January 2005.

We began the construction of the Tyler County pipeline in September 2005. During the construction phase, we were able to secure large dedication areas from three additional producers in the vicinity of the Tyler County pipeline increasing our expected volumes from 15 MMcf/d to approximately an average of 30 MMcf/d. The Tyler County pipeline reached the first producer and began flowing natural gas on December 30, 2005. Construction of the pipeline was finished on February 28, 2006, at a cost of approximately $8.6 million. We completed construction of an extension to the Tyler County pipeline and began flowing gas in late March 2007. This line provides additional supply capacity and flexibility in addition to providing us the opportunity to take advantage of processing plant efficiencies for our customers, as well as a reduction in third-party processing fees.

Acquisition of Panhandle Assets

On December 1, 2005, we completed the purchase of ONEOK Texas Field Services, L.P., or ONEOK or predecessor, for approximately $528.0 million of cash. The assets acquired in the transaction consist of gathering and processing assets located in a ten county area in the Texas Panhandle and represent the majority of our assets in the Texas Panhandle.

In the first few months after the acquisition, we attracted 20 MMcf/d of new volumes at attractive processing margins. We are in the process of expanding our processing capacity in this area by beginning to refurbish and will restart an idle 20 MMcf/d processing plant, and by connecting the East Panhandle System with the West Panhandle System, where excess capacity currently exists. We also intend to expand our processing capacity by relocating and restarting a 24.5 MMcf/d facility in the latter part of 2007. In July, 2006, we began flowing gas across the 10-mile pipeline constructed to connect the gas in the east to the surplus plant capacity in the west.

Acquisition of Brookeland Assets

On March 31, 2006, we purchased an 80% interest in the Brookeland gathering and processing facility, a 76.3% interest in the Masters Creek gathering system and 100% of the Jasper NGL line from Duke Energy Field Services, L.P. and on April 7, 2006, we purchased the remaining interest owned by Swift Energy Corporation in those same assets for an approximate total purchase price of $95.9 million. The acquired assets are located in southeast Texas and complement our existing southeast Texas assets. To motivate Swift Energy Corporation to enhance their drilling program, we have negotiated an incentive on all new well production. As such, they have resumed their drilling program.

At the end of the March 2007 quarter, we completed the construction of a 16-mile extension to our Tyler County pipeline to reach the Brookeland processing plant, which operated with excess capacity. This extension allows us to deliver the Tyler County pipeline volumes to our wholly-owned Brookeland processing facility which enable us to avoid the processing fee we currently pay at the Indian Springs processing facility on these volumes. We also expect by delivering these volumes to our Brookeland processing facility we will achieve higher NGL recoveries as the Brookeland processing facility is more efficient than the Indian Springs processing facility.

Acquisition of MGS

In June 2006, we purchased all of the partnership interests in Midstream Gas Services, L.P., which we refer to as MGS, for approximately $4.7 million in cash and 1,125,416 common units in Eagle Rock Pipeline from a group of private investors, including Natural Gas Partners VII, L.P. We issued 798,155 of our common units (pre-IPO common units), which we refer to as the Deferred Common Units, to Natural Gas Partners VII, L.P., the primary equity owner of MGS, as a contingent earn-out payment if MGS achieves certain financial objectives for the year ending December 31, 2007. Prior to the acquisition, Natural Gas Partners VII, L.P. owned a 95% limited partnership interest in MGS

and a 95% interest in its general partner, which owned a 1% general partner interest in MGS. We refer to the private investors who received common units in Eagle Rock Pipeline as partial consideration for the MGS acquisition as the June 2006 Private Investors. The March 2006 Private Investors and the June 2006 Private Investors are collectively referred to in the Annual Report as the “Private Investors.” Each of the Private Investors’ common units in Eagle Rock Pipeline was converted into common units in the Partnership upon consummation of our initial public offering on approximately a 1-for-0.719 common unit basis.

Critical Accounting Policies and Estimates

There have been no changes during the first quarter of 2007 to our critical accounting policies as we described in our Annual Report on Form 10-K for the year ended December 31, 2006.

EAGLE ROCK ENERGY PARTNERS, L.P.

RESULTS OF OPERATIONS

The following table is a summary of the results of operations for the three month period ended March 31, 2007 and 2006:


	Three Months
	Ended March 31,
*($ in thousands)*	2007			2006
Sales of natural gas, NGLS and condensate	$	110,121		$	114,187
Compression, gathering and processing		4,283			2,201
Gain/(loss) on realized risk management instrument		2,999			811
Gain/(loss) on unrealized risk management instrument		(10,641	)		(20,881	)

Total operating revenue		106,762			96,318

Purchase of natural gas and NGLs		90,636			91,991


Segment profit(a)		16,126			4,327

Operating and maintenance expense		7,923			5,682
General and administrative expense		4,923			2,453
Other expense		1,711			—
Depreciation and amortization		11,630			9,214
Interest-net including realized risk management instrument		7,832			7,470
Unrealized risk management interest related instrument		1,611			(4,975	)
State income tax provision		164			—


Net loss	$	(19,668	)	$	(15,517	)


Adjusted EBITDA(b)	$	14,093		$	17,112


(a)		Defined as operating revenues minus the cost of natural gas and NGLs and other cost of sales. Operating revenues include both realized and unrealized risk management activities.

(b)		Defined as net income (loss) plus income tax, interest-net, depreciation and amortization expense, separation costs, other non-cash operating expenses less non realized revenues risk management loss (gain) activities and less net income from discontinued operations. The prior year legal arbitration settlement recorded in Other expense for March 31, 2007 quarter has also been added back to net income (loss).

The following table reconciles segment profit to net loss:


	Three Months
	Ended March 31,
*($ in thousands)*	2007			2006
Segment profit:	$	16,126		$	4,327
*Less:*
Operations and maintenance		7,923			5,682
General and administrative		4,923			2,453
Depreciation and amortization		11,630			9,214
Interest-net including realized risk management instrument		7,832			7,470
Unrealized risk management interest related instrument		1,611			(4,975	)
Other expense		1,711			—
State income tax provision		164			—

Net loss	$	(19,668	)	$	(15,517	)

The following table reconciles Adjusted EBITDA to net loss:


	Three Months
	Ended March 31,
*($ in thousands)*	2007			2006
Adjusted EBITDA:	$	14,093		$	17,112
*Less:*
State income tax provision		164			—
Interest-net including realized risk management instrument		7,832			7,470
Unrealized risk management interest related instrument		1,611			(4,975	)
Depreciation and amortization		11,630			9,214
Equity-based compensation expense		172			—
Other expense		1,711			39
*Plus:*
Risk management instruments-unrealized		(10,641	)		(20,881	)


Net loss	$	(19,668	)	$	(15,517	)

Three Months Ended March 31, 2007 Compared with Three Months Ended March 31, 2006

Financial results for the three months ended March 31, 2007 included activities of the Brookeland (acquired March 31, 2006) and MGS (June 1, 2006) business combinations. The timing of these acquisitions affects the comparison between quarters.

Operating revenues for sales of natural gas, NGLs and condensate for the current year quarter decreased by $6.8 million, 6% decrease, from the first quarter of 2006 due to primarily a decline in oil and gas commodity prices during the periods (Oil and Natural Gas indices averaged $58.33 and $6.77 for the March 2007 quarter as compared to $63.39 and $8.98 for the March 2006 quarter). Marketing basis differentials for natural gas liquids (difference primarily between Conway, Kansas and Mont Belvieu, Texas marketing points) also compared negatively for the current period. These unfavorable variances were partially offset by higher average daily gathering volumes of 229,596 MMcf/d for March 2007 compared to 189,838 daily averages for March 2006 quarter, or a 21% increase. The increase in gathering volumes contributed to increased condensate and NGLs volumes in the current quarter.

Compression, gathering and processing for the current quarter is $4.3 million as compared to $1.8 million for the March 2006 quarter, or an increase of 144%. This increase reflects primarily the increase in fee contracts for gas compression and conditioning as well as the inclusion of the Brookeland acquisition in the current year quarter.

Realized risk management net gain for the March 2007 quarter is $3.0 million compared to $0.8 million for the March 2006 quarter. The increase is primarily the reduction of the commodity index prices indicated above and additional hedge volumes in the March 2007 quarter.

Unrealized risk management net loss for the March 2007 quarter is a $10.6 million loss versus a $20.9 million loss in the March 2006 quarter. The activities for both quarters reflect the movement in future period prices during the quarters on the open hedge positions as well as amortization in both quarters for put premiums as the underlying options have expired. As the forward price curves for our hedged commodities shift in relations to caps, floors, swap and strike prices at which we have executed the derivative instrument, the fair value of such instruments changes through time. The mark to market net unrealized loss reflects overall unfavorable forward curve price movement during the underlying commodities for the derivative instruments. The unrealized mark to market activities recorded do not impact cash activities during the quarter.

Purchase of natural gas and NGLs decreased by $3.8 million, 4% decrease, reflecting primarily the decrease in natural gas prices in the current period as compared to last year offset by the reduced net gas short position between years (the gas short stems from the conversion of natural gas to NGLs during the processing period with a portion of the natural gas being made up to the producers).

Segment profit increased to $16.1 million for the March 2007 quarter compared to $4.4 million for the March 2006 quarter. The increase is primarily from the reduced net unrealized losses on risk management derivatives between periods as well as the increase in net realized gains on risk management derivatives.

Operations and maintenance expense increased in the current quarter by $2.1 million compared to March 2006 quarter primarily from the operations of the Brookeland and MGS acquisitions ($1.4 million), the operating costs on the first part of the Tyler County Pipeline project, installed during the first quarter of 2006, as well as higher costs in the current quarter in our Panhandle segment primarily related to the impact from the colder than normal weather.

General and administrative expenses also increased $2.4 million primarily from the higher costs of being a publicly-traded partnership, including increases in its corporate infrastructure as well as higher third party costs for accounting and auditing, legal fees, Sarbanes Oxley compliance activities and increased related insurance expense. Also, the current quarter activities included $0.3 million of expense related to partnership units registration rights filings.

Other expense reflects the arbitration award recorded during the quarter of approximately $1.4 million (see Contingencies, Note 11) related to a marketing fee dispute on the Panhandle operations for periods before the Partnership ownership. In addition, approximately $0.3 million relates to a separation expense accrual recorded during the current quarter.

Increase of $2.4 million in depreciation and amortization for current year’s quarter is primarily from the Brookeland and MGS acquisitions as well as associated depreciation on construction projects completed and placed in service since March 2006.

Interest-net including realized risk management instrument reflects primarily interest expense associated with our Amended and Restated Credit Agreement and the realized interest rate hedges for the period. The increase in interest expense between periods, approximately $0.4 million, is from increased base interest rate and a higher adds on rate, as the ending debt outstanding balance did not vary significantly between periods.

Unrealized risk management interest related instrument for the March 2007 quarter is $1.6 million net loss relates to future period’s interest rate swaps and from changes during the quarter in the underlying interest rate associated with the derivatives. The unrealized mark to market loss does not impact cash activities during the quarter.

State income taxes recorded during the March 2007 quarter of approximately $0.2 million reflects the Texas Margin Tax (see Note 13) and was recorded as a deferred tax liability.

Other Matters

Wildfires in Texas Panhandle. Wildfires in the Texas Panhandle during the week of March 11, 2006, temporarily affected our operations in the region. While the fires did not cause material direct damage to our facilities, some experienced down-time caused by power outages by the local electric co-ops. We had two processing and gathering facilities in the area impacted with reduced flow rates as producers had shut-in their production during the fires. There was minimal and temporary damage sustained in the field to a very small number of metering facilities and one flow line. Less than $0.1 million was spent on repairs caused by the fires. The overall economic impact was between $0.5 million and $1.0 million.

Environmental. A Phase I environmental study was performed on our Texas Panhandle assets by an independent environmental consultant engaged by us in connection with our pre-acquisition due diligence process in 2005. As a result of performing the Phase I environmental study, we are planning to conduct environmental investigations at 11 properties, the costs of which are estimated to collectively range between $160,000 and $398,000 and for which we have accrued reserves in the amount of $300,000 as of March 31, 2007. Depending on the findings made during those investigations, and in anticipation of implementing amended SPCC (Spill Prevention Control and Counter-measure) plans at multiple locations as well as performing selected cavern closures, we estimate an additional $1.2 million to $2.5 million in costs could be incurred by us in resolving environmental issues at those properties. We believe the likelihood we will be liable for any significant potential remediation liabilities identified in the study is remote. Separately, (1) we are entitled to indemnification with respect to certain environmental liabilities retained by prior owners of these properties, and (2) we purchased an environmental pollution liability insurance policy. The policy pays for on-site clean-up as well as costs and damages to third parties and currently has a one-year term with a $5.0 million limit subject to a $0.5 million deductible. We expect to renew this policy on an annual basis.

Liquidity and Capital Resources

Prior to our initial public offering in October 2006, our sources of liquidity included cash generated from operations, equity investments by our owners and borrowings under our credit facilities.

As a publicly traded partnership, we expect our sources of liquidity to include:

	•		cash generated from operations;

	•		borrowings under our credit facilities;

	•		debt offerings; and

	•		issuance of additional partnership units.

We believe the cash generated from these sources will be sufficient to meet our minimum quarterly cash distributions and our requirements for short-term working capital and long-term capital expenditures through December 31, 2007.

Cash Flows

Since the formation of Eagle Rock Pipeline, L.P. in 2005, several key events having major impacts on our cash flows are:

	•		the acquisition of the midstream assets in the Texas Panhandle on December 1, 2005 for approximately $531.0 million, which was financed through an additional equity contribution of $133.0 million and debt of $400.0 million, not including $27.5 million in risk management costs related to option premiums financed entirely with equity contributions from NGP;

	•		the acquisition of the Brookeland gathering and processing facility and related assets on March 31, 2006 and April 7, 2006 for approximately $95.8 million, which we financed entirely with equity; and

•

the acquisition of all of the partnership interests in Midstream Gas Services, L.P. on June 2, 2006 for approximately $25.0 million which we paid with $4.7 million in cash and $21.3 million in Eagle Rock Pipeline, L.P. units.

Working Capital (Deficit). 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 March 31, 2007, the working capital was a negative (current liabilities exceeded current assets) $22.7 million as compared to a $12.1 million (positive) balance as of December 31, 2006. However, the Partnership has the ability to draw on its credit facility, if needed, to satisfy its current liabilities.

The net decreases in working capital of $34.8 million from December 31, 2006 to March 31, 2007, resulted primarily from the following factors:

	•		cash balances decreased overall by $8.5 million and was impacted from the results of operations, timing of capital expenditures payments, financing activities including our debt activities as well as members’ equity distributions;

	•		trade accounts receivable increased by $1.0 million primarily as a result of timing of collections;

	•		risk management net working capital balance decreased by a net $9.8 million as a result of the changes in the mark-to-market unrealized positions and fair value changing of the option premiums;

	•		prepayments and other current assets decreased by $0.5 million primarily from the property and liability prepaid insurance balances;

	•		accounts payable increased by $11.2 million from December 31, 2006 primarily as a result of activities and timing of payments, including capital expenditures activities; and

	•		accrued liabilities increase of $5.8 million primarily reflects an accrual for an unanticipated legal award and unbilled expenditures related primarily to capital expenditures.

Cash Flows Three Months 2007 Compared to Three Months 2006

Cash Flows from Operating Activities. Increase of $6.4 million during the three months current period is the result of increased working capital sources of $9.9 million and non-cash income charges of $0.5 million, offset partially by higher net loss of $4.1 million.

Cash Flows Used in Investing Activities. Cash flows used in investing activities for the three months ended March 31, 2007 as compared to the three months ended March 31, 2006, decreased by $58.3 million. The investing activities for the prior year’s period reflect the partial Brookeland acquisition transaction, $75.7 million, and an escrow payment cash source related to an acquisition of $7.6 million. Capital expenditures between the two periods is an increase in cash used in current period of $9.9 million reflecting higher capital expenditure activities primarily associated with the Tyler County Pipeline and Red Deer projects for the current year’s activities.

Cash Flows Provided by (Used in) Financing Activities. Cash flows used in financing activities for the three months ended March 31, 2007 was $3.1 million as compared to a source of cash of $96.0 million for the March 2006 three month period. The decrease in cash provided of $99.1 million is primarily from the issuance of members’ equity in March 2006 associated with the Brookeland asset, $98.4 million. In the current quarter, there was a distribution to common unit holders of $6.1 million, with no distributions made in the March 2006 quarter.

Capital Requirements

The midstream 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 additional assets to increase our business, to expand and upgrade existing systems and facilities or to construct or acquire similar systems or facilities; 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 well attachments costs to maintain existing system volumes and related cash flows.

We have budgeted approximately $49.0 million for capital expenditures for the December 31, 2007 year. Growth capital budgeted is approximately $37.8 million which includes the Tyler County pipeline and Red Deer projects. In addition, we have budgeted a significant gathering line extension in our Brookeland area and an idle processing plant to be started up in mid 2007 in the Texas Panhandle System. We have budgeted approximately $11.2 million in maintenance capital expenditures for the year ended December 31, 2007. We include routine well attachments in maintenance capital. For the December 31, 2006 year, we spent $38.4 million for capital expenditures, $27.1 million for growth and $11.3 million for maintenance.

Since our inception in 2002, we have made substantial growth capital expenditures, including those relating to the acquisition of the Dry Trail plant, the Camp Ruby gathering system, the Indian Springs processing plant, the Panhandle Assets and the Brookeland and Masters Creek gathering and processing assets. We anticipate we will continue to make significant growth capital expenditures and acquisitions. Consequently, our ability to develop and maintain sources of funds to meet our capital requirements is critical to our ability to meet our growth objectives.

We continually review opportunities for both organic growth projects and acquisitions which will enhance our financial performance. Because we will distribute most of our available cash to our unitholders, we will depend on borrowings under our Amended and Restated Credit Agreement and the incurrence of debt and equity securities to finance any future growth capital expenditures or acquisitions. The upward trend in interest rates experienced recently will increase our borrowing costs on additional debt financing incurred to finance future acquisitions, as compared to our borrowing costs under our currently hedged credit facility.

Amended and Restated Credit Agreement

On August 31, 2006, we entered into an Amended and Restated Credit Agreement which provides for $300.0 million aggregate principal amount of Series B Term Loans and up to $200.0 million aggregate principal amount of revolving commitments. The Amended and Restated Credit Agreement includes a sub limit for the issuance of standby letters of credit for the aggregate unused amount of the revolver. In addition, the credit facility allows us to expand the Term and Revolving Commitment up to an additional $100.0 million if certain financial conditions are met. At March 31, 2007, we had $299.3 million outstanding under the term loan, $105.4 million outstanding under the revolver and $2.5 million of outstanding letters of credit.

At our election, the term loan and the revolver bear interest on the unpaid principal amount either at a base rate plus the applicable margin (defined as 1.25% per annum, reducing to 1.00% when consolidated funded debt to Adjusted EBITDA (as defined) is less than 3.5 to 1); or at the adjusted Eurodollar rate plus the applicable margin (defined as 2.25% per annum, reducing to 2.00% when consolidated funded debt to Adjusted EBITDA (as defined) is less than 3.5 to 1). At August 31, 2006, we elected the Eurodollar rate plus the applicable margin (defined as 2.25%) for a cumulative rate of 7.65%. The applicable margin increased by 0.50% per annum on January 31, 2007, a result of the Partnership not pursuing a rating by both S&P and Moody’s, per the agreement.

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- or six-, nine- or twelve-months, as selected by us. Interest on the term loans is paid each March 31, June 30, September 30 and December 31 of each year, commencing on September 30, 2006. We pay a commitment fee equal to (1) the average of the daily difference between (a) the revolver commitments and (b) the sum of the aggregate principal amount of all outstanding revolver loans plus the aggregate principal amount of all outstanding swing loans times (2) 0.50% per annum; provided, the commitment fee percentage shall increase by 0.25% per annum on January 31, 2007. We also pay a letter of credit fee equal to (1) the applicable margin for revolving loans that are Eurodollar rate loans times (2) the average aggregate daily maximum amount available to be drawn under all such letters of credit (regardless of whether any conditions for drawing could then be met and determined as of the close of business on any date of determination). Additionally, we pay 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 obligations under the Amended and Restated Credit Agreement are secured by first priority liens on substantially all of our assets, including a pledge of all of the capital stock of each of our subsidiaries. In addition, the credit facility contains various covenants limiting our ability to incur indebtedness, grant liens and make distributions and certain financial covenants requiring us to maintain:

•

an interest coverage ratio (the ratio of our consolidated Adjusted EBITDA to our consolidated interest expense, in each case as defined in the credit agreement) of not less than 2.5 to 1.0, determined as of the last day of each quarter for the four quarter period ending on the date of determination; and a leverage ratio (the ratio of our consolidated indebtedness to our consolidated Adjusted EBITDA, in each case as defined in the credit agreement) of not more than 5.0 to 1.0 (or, on a temporary basis for not more than three consecutive quarters following the consummation of certain acquisitions, not more than 5.25 to 1.0).

We will use the available borrowing capacity under our Amended and Restated Credit Agreement for working capital purposes, maintenance and growth capital expenditures and future acquisitions. The Partnership has approximately $91.0 million of unused capacity under the agreement as of March 31, 2007.

On May 4, 2007, we expanded the revolver commitment under our Amended and Restated Credit Agreement by $100.0 million to $300.0 million, in total. No incremental funding under the Amended and Restated Credit Agreement was needed for the related acquisitions.

Off-Balance Sheet Obligations. We have no off-balance sheet transactions or obligations.

Debt Covenants. At March 31, 2007 and December 31, 2006, we were in compliance with the covenants of the credit facilities.

Total Contractual Cash Obligations. The following table summarizes our total contractual cash obligations as of December 31, 2006 and March 31, 2007. All of the $405.7 million of term loans outstanding on December 31, 2006 are scheduled for interest rate resets on three-month intervals. Interest rates were last reset for all amounts outstanding on March 31, 2007.


($ in millions)	Payments Due by Period
Contractual Obligations	Total		2007		2008		2009		2010-2011		Thereafter
Long-term debt (including interest)(1)	$	554.8	$	31.1	$	31.1	$	31.1	$	461.5	$	0.0
Operating leases		4.4		0.7		0.7		0.7		0.3		2.0
Purchase obligations(2)		—		—		—		—		—		—

Total contractual obligations	$	559.2	$	31.8	$	31.8	$	31.8	$	461.8	$	2.0


(1)		Assumes our fixed swapped average interest rate of 4.92% plus the applicable margin under our Amended and Restated Credit Agreement, which remains constant in all periods.

(2)		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

In February 2006, the Financial Accounting Standards Board, or the FASB issued SFAS No. 155, Accounting for Certain Hybrid Financial Instruments, an amendment of FASB Statements No. 133 and No. 140 (SFAS No. 155). SFAS No. 155 amends SFAS No. 133, which required a derivative embedded in a host contract which does not meet the definition of a derivative be accounted for separately under certain conditions. SFAS No. 155 amends SFAS No. 133 to narrow the scope of such exception to strips which represent rights to receive only a portion of the contractual interest cash flows or of the contractual principal cash flows of a specific debt instrument. In addition, SFAS No. 155 amends SFAS No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilities, which permitted a qualifying special-purpose entity to hold only a passive derivative financial instrument pertaining to beneficial interests issued or sold to parties other than the transferor. SFAS No. 155 amends SFAS No. 140 to allow a qualifying special purpose entity to hold a derivative instrument pertaining to

beneficial interests that itself is a derivative financial instrument. SFAS No. 155 is effective for all financial instruments acquired or issued (or subject to a re-measurement event) following the start of an entity’s first fiscal year beginning after September 15, 2006. The Partnership adopted SFAS No. 155 on January 1, 2007, and it had no effect on the results of operations or financial position for the quarter ended March 31, 2007.

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements. This statement defines fair value, establishes a framework for measuring fair value, and expands disclosure about fair value measurements. The statement is effective for financial statements issued for fiscal years beginning after November 15, 2007. The Company is currently evaluating the effect the adoption of this statement will have, if any, on its consolidated results of operations and financial position.

In July 2006, the FASB, issued FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes – an interpretation of FASB Statement No. 109” (FIN 48), which clarifies the accounting and disclosure for uncertainty in tax positions, as defined. FIN 48 seeks to reduce the diversity in practice associated with certain aspects of the recognition and measurement related to accounting for income taxes. This interpretation is effective for fiscal years beginning after December 15, 2006. The adoption of FIN 48 did not have a material impact on our results of operations or financial position.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Risk and Accounting Policies

We are exposed to market risks associated with commodity prices, counterparty credit and interest rates. Our management has established a comprehensive review of our market risks and is developing risk management policies and procedures to monitor and manage these market risks. Our general partner is responsible for delegation of transaction authority levels, and with the planned establishment of a Risk Management Committee, our general partner will be responsible for the overall approval of market risk management policies. The Risk Management Committee will be composed of directors (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 Risk Management Committee will be responsible for the overall management of credit risk and commodity price risk, including monitoring exposure limits.

Commodity Price Risk

We are exposed to the impact of market fluctuations in the prices of natural gas, NGLs and other commodities as a result of our gathering, processing and marketing activities, which produce a naturally long position in NGLs and a natural short position in natural gas. We attempt to mitigate commodity price risk exposure by matching pricing terms between our purchases and sales of commodities. To the extent that we market commodities in which pricing terms cannot be matched and there is a substantial risk of price exposure, we attempt to use financial hedges to mitigate the risk. It is our policy not to take any speculative marketing positions.

Both our profitability and our cash flow are affected by volatility in prevailing natural gas and NGL prices. Natural gas and NGL prices are impacted by changes in the supply and demand for NGLs and natural gas, as well as market uncertainty. Historically, changes in the prices of heavy NGLs, such as natural gasoline, have generally correlated with changes in the price of crude oil. For a discussion of the volatility of natural gas and NGL prices, please read “Risk Factors.” Adverse effects on our cash flow from increases in natural gas prices and decreases in NGL product prices could adversely affect our ability to make distributions to unitholders. 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. Our overall direct exposure to movements in natural gas prices is managed to minimize the risk of our natural short position for 2006 and 2007, the periods for which we have hedged our natural gas exposure to this point, as well as a result of natural hedges inherent in our contract portfolio. Natural gas prices, however, can also affect our profitability indirectly by influencing the level of drilling activity and related opportunities for our service. We are a seller of NGLs and are exposed to commodity price risk associated with downward movements in NGL prices. NGL prices have experienced volatility in recent years in response to changes in the supply and demand for NGLs and market uncertainty. In response to this volatility, we have instituted a hedging program to reduce our exposure to commodity price risk. Under this program, we have hedged substantially all of our share of expected NGL volumes under percent-of-proceed and keep-whole contracts in 2006 and for 2007 through the purchase of NGL put contracts, costless collar contracts and swap contracts. We have also hedged substantially all of our share of expected NGL volumes under percent-of-proceed contracts from 2008 through 2010 through a combination of direct NGL hedging as well as indirect hedging through crude oil costless collars. Additionally, to mitigate the exposure to natural gas prices from keep-whole volumes, we have purchased natural gas calls from 2006 to 2007 and entered into swaps for the months of August and September 2006 to cover substantially all of our short natural gas position associated with our keep-whole volumes. We anticipate that after 2007, our short natural gas position will become a long natural gas position because of our increased volumes in the Texas Panhandle and the volumes contributed from our Brookeland/Masters Creek acquisition. In addition, we intend to pursue fee-based arrangements, where market conditions permit, and to increase retained percentages of natural gas and NGLs under percent-of-proceed arrangements. We continually monitor our hedging and contract portfolio and expect to continue to adjust our hedge position as conditions warrant.

We have not designated our contracts as accounting hedges under Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities. As a result, we mark our derivatives to market with the resulting change in fair value included in our statement of operations.

Item 4. Controls and Procedures.

Disclosure Controls

At the end of the period covered by this report, an evaluation was performed under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer of the general partner of our general partner, of the effectiveness of the design and operation of our disclosure controls and procedures (as such terms are defined in Rule 13a–15(e) and 15d–15(e) of the Exchange Act of 1934, as amended). Based on that evaluation, management, including the Chief Executive Officer and Chief Financial Officer of the general partner of our general partner, concluded our disclosure controls and procedures were effective as of March 31, 2007, to provide reasonable assurance the information required to be disclosed by us in the reports we file or submit under the Exchange Act of 1934, as amended, are properly recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms.

Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Exchange Act is accumulated and communicated to the issuer’s management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

Internal Control over Financial Reporting

In anticipation of becoming subject to the provisions of Section 404 of the Sarbanes-Oxley Act of 2002, we initiated in late 2006 and continue in 2007, an evaluation and program of documentation, implementation and testing of internal control over financial reporting. This program will continue through 2007, culminating with our initial Section 404 certification and attestation in early 2008. As of March 31, 2007, we have evaluated the effectiveness of our system of internal control over financial reporting, as well as changes therein, in compliance with Rule 13a-15 of the SEC’s rules under the Securities Exchange Act and have filed the certifications with this report required by Rule 13a-14.

In the course of that evaluation, we found no fraud, whether or not material, that involved management or other employees who have a significant role in our internal control over financial reporting and no material weaknesses.

There have been no changes in our internal controls over financial reporting that occurred during the three months ended March 31, 2007, that have materially affected, or are reasonably likely to affect materially, our internal controls over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings.

We and our subsidiaries may become party to legal proceedings which arise from time to time in the ordinary course of business. While the outcome of these proceedings cannot be predicted with certainty, we do not expect these matters to have a material adverse effect on the financial statements.

We carry insurance with coverage and coverage limits consistent with our assessment of risks in our business and of an acceptable level of financial exposure. Although there can be no assurance such insurance will be sufficient to mitigate all damages, claims or contingencies, we believe our insurance provides reasonable coverage for known asserted or unasserted claims. In the event we sustain a loss from a claim and the insurance carrier disputed coverage or coverage limits, we may record a charge in a different period than the recovery, if any, from the insurance carrier.

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 the minimum quarterly distribution on our common units and the trading price of our common units could decline.

The following risks should be read in conjunction with other risk factors disclosed under Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2006. The following risks are included in this report because of our recently completed Montierra Acquisition, described in Note 15 to our Unaudited Consolidated Financial Statements included with this report, pursuant to which transaction we acquired interests in oil and natural gas properties.

Risks Related to Our Business

The Partnership’s acquisition of Montierra has added additional risks. Please refer to the Partnership’s 2006 Annual Report on Form 10-K for additional risks.

Eagle Rock may experience difficulties in integrating Montierra’s business and could fail to realize potential benefits of the acquisition.

Achieving the anticipated benefits of the acquisition of the assets from Montierra depends in part upon whether Eagle Rock is able to integrate Montierra’s business, which is a line of business different from Eagle Rock’s traditional midstream energy gathering and processing business, in an efficient and effective manner. Eagle Rock may not be able to accomplish this integration process smoothly or successfully. The difficulties combining the two companies’ businesses 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 the ability of Eagle Rock to make timely and accurate public disclosure;

•

The demands of managing new lines of business acquired from Montierra in the acquisition.

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 combined company, which may affect the value of Eagle Rock common units after the acquisition.

The returns on Montierra’s oil and gas investments are subject to fluctuation as a result of changes in oil and natural gas prices.

The reserves attributable to the underlying properties and the revenue generated therefrom are highly dependent upon the prices realized from the sale of oil and natural gas. Prices of oil and natural gas can fluctuate widely on a quarter-to-quarter basis in response to a variety of factors that are beyond the control of Eagle Rock. These factors include, among other things:

	•		Political conditions or hostilities in oil and natural gas producing regions;

	•		Weather conditions or force majeure events;

	•		Delays or cancellations of crude oil and natural gas drilling and production activities;

	•		Levels of supply of and demand for oil and natural gas;

	•		U.S. and worldwide economic conditions;

	•		The price and availability of alternative fuels; and

	•		Energy conservation and environmental measures.

Moreover, government regulations can affect commodity prices in the long term. Lower prices of oil and natural gas will reduce the amount of the net proceeds from the Montierra assets to which Eagle Rock is entitled and may ultimately reduce the amount of oil and natural gas that is economic to produce from the underlying properties. As a result, the operator of any of the underlying properties could determine during periods of low commodity prices to shut in or curtail production from wells on the underlying properties. In addition, the operator of the underlying properties could determine during periods of low commodity prices to plug and abandon marginal wells that otherwise may have been allowed to continue to produce for a longer period under conditions of higher prices. The volatility of commodity prices may cause the amount of returns to unitholders to fluctuate, and a substantial decline in the price of oil and natural gas will reduce the amount of cash available for distribution to the unitholders.

Risks associated with the production, gathering, transportation and sale of oil and natural gas could adversely affect returns.

The revenues from the Montierra assets and the value of the Eagle Rock units, which is derived from the Montierra assets, will depend upon, among other things, oil and natural gas production and prices and the costs incurred by the operators to develop and exploit oil and natural gas reserves attributable to the underlying properties. Drilling, production or transportation accidents that temporarily or permanently halt the production and sale of oil and natural gas at any of the underlying properties will reduce the amount of net proceeds generated from the Montierra assets. For example, accidents may occur that result in personal injuries, property damage, damage to productive formations or equipment and environmental damages. Any costs incurred by the operators in connection with any such accidents that are not insured against will have the effect of reducing the net proceeds available for distribution to Eagle Rock unitholders. In addition, curtailments or damage to pipelines used by the operators to transport oil and natural gas production to markets for sale could reduce the amount of net proceeds available for distribution. Any such curtailment or damage to the gathering systems used by the operators could also require such operators to find alternative means to transport the oil and natural gas production from the underlying properties, which alternative means could require such operators to incur additional costs that will have the effect of reducing returns to the unitholders.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.

The information required for this item is provided in Note 15, Subsequent Events, included in the Notes to the Unaudited Consolidated Financial Statements included under Part I, Item 1, which information is incorporated by reference into this item.

We did not repurchase any of our common units during the period covered by this report. However, 9,100 common units were forfeited by departing employees whose common units had not vested at the time of the termination of employment.

Item 3. Defaults Upon Senior Securities.

None.

Item 4. Submission of Matters to a Vote of Security Holders.

None.

Item 5. Other Information.

We have reported on Form 8-K during the quarter covered by this report all information required to be reported on such form.

Item 6. Exhibits.

31.1		Certification by Joseph A. Mills pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.2		Certification by Richard W. FitzGerald pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

32.1		Certification by Joseph A. Mills pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and 18 U.S.C. Section 1350

32.2		Certification by Richard W. FitzGerald pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and 18 U.S.C. Section 1350

SIGNATURES

Pursuant to the requirements 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.

May 15, 2007


		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

		/s/ Richard W. FitzGerald

		Richard W. FitzGerald
		Senior Vice President, Chief Financial Officer and Treasurer
		(Duly Authorized and Principal Financial Officer)

EAGLE ROCK ENERGY PARTNERS, L.P.
EXHIBIT INDEX

31.1		Certification by Joseph A. Mills pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.2		Certification by Richard W. FitzGerald pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

32.1		Certification by Joseph A. Mills pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and 18 U.S.C. Section 1350

32.2		Certification by Richard W. FitzGerald pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and 18 U.S.C. Section 1350

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