UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
T QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2015
or
£ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from __________ to _________
Commission File Number 001-37419
PDC ENERGY, INC.
(Exact name of registrant as specified in its charter)
Delaware | 95-2636730 |
(State of incorporation) | (I.R.S. Employer Identification No.) |
1775 Sherman Street, Suite 3000
Denver, Colorado 80203
(Address of principal executive offices) (Zip code)
Registrant's telephone number, including area code: (303) 860-5800
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 T No £
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes T No £
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer x | Accelerated filer o |
Non-accelerated filer £ (Do not check if a smaller reporting company) | Smaller reporting company o |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes £ No T
Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date: 40,107,524 shares of the Company's Common Stock ($0.01 par value) were outstanding as of October 16, 2015.
PDC ENERGY, INC.
TABLE OF CONTENTS
PART I – FINANCIAL INFORMATION | Page | ||
Item 1. | Financial Statements | ||
Item 2. | |||
Item 3. | |||
Item 4. | |||
PART II – OTHER INFORMATION | |||
Item 1. | |||
Item 1A. | |||
Item 2. | |||
Item 3. | |||
Item 4. | |||
Item 5. | |||
Item 6. | |||
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
This Quarterly Report on Form 10-Q contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 ("Securities Act") and Section 21E of the Securities Exchange Act of 1934 ("Exchange Act") regarding our business, financial condition, results of operations and prospects. All statements other than statements of historical facts included in and incorporated by reference into this report are "forward-looking statements" within the meaning of the safe harbor provisions of the United States ("U.S.") Private Securities Litigation Reform Act of 1995. Words such as expects, anticipates, intends, plans, believes, seeks, estimates and similar expressions or variations of such words are intended to identify forward-looking statements herein. These statements relate to, among other things: estimated future production (including the components of such production), sales, expenses, cash flows and liquidity; estimated crude oil, natural gas and natural gas liquids (“NGLs”) reserves, including 2015 year-end reserves; expected 2015 capital forecast allocations, including revised capital and production forecasts and that we expect to meet or exceed the high end of our range; anticipated increased 2015 capital projects and expenditures; expected year-end exit rates; the impact of prolonged depressed commodity prices; the Utica Shale impairment and other potential future impairments; availability of sufficient funding for our 2015 capital program and sources of that funding; future exploration, drilling and development activities, including our expected rig count in both the Utica Shale and Wattenberg Field; expectation of cash flows in 2015 and 2016; potential additional revisions to our 2015 capital and production forecast; anticipated reductions in our 2015 cost structure; the expiration of certain leases and our current development plan in the Utica Shale; our evaluation method of our customers' and derivative counterparties' credit risk, including certain of our gas marketing customers; our expected positive net settlements on our derivative positions and effect on cash flow in 2015; effectiveness of our derivative program in providing a degree of price stability; the impact of high line pressures and the timing, availability, cost and effect of additional midstream facilities and services going forward; expected differentials; compliance with debt covenants; expected funding sources for anticipated net settlement of our 3.25% convertible senior notes due 2016; the impact of litigation on our results of operations and financial position; that we do not expect to pay dividends in the foreseeable future; and our future strategies, plans and objectives.
The above statements are not the exclusive means of identifying forward-looking statements herein. Although forward-looking statements contained in this report reflect our good faith judgment, such statements can only be based on facts and factors currently known to us. Forward-looking statements are always subject to risks and uncertainties, and become subject to greater levels of risk and uncertainty as they address matters further into the future. Throughout this report or accompanying quarterly materials, we may use the terms “outlook,” “projection” or similar terms or expressions, or indicate that we have “modeled” certain future scenarios. We typically use these terms to indicate our current thoughts on possible outcomes relating to our business or the industry in periods beyond the current fiscal year. In addition to being subject to additional levels of uncertainty generally, forward-looking statements regarding such prospective matters do not necessarily reflect the outcomes we view as the most likely to occur, but instead are shown to illustrate aspects of our business in the context of a variety of scenarios we believe to be plausible.
Important factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to:
• | changes in worldwide production volumes and demand, including economic conditions that might impact demand; |
• | volatility of commodity prices for crude oil, natural gas and NGLs and the risk of an extended period of depressed prices; |
• | impact of governmental policies and/or regulations, including changes in environmental and other laws, the interpretation and enforcement related to those laws and regulations, liabilities arising thereunder and the costs to comply with those laws and regulations; |
• | potential declines in the value of our crude oil, natural gas and NGLs properties resulting in impairments; |
• | changes in estimates of proved reserves; |
• | inaccuracy of reserve estimates and expected production rates; |
• | potential for production decline rates from our wells being greater than expected; |
• | timing and extent of our success in discovering, acquiring, developing and producing reserves; |
• | our ability to secure leases, drilling rigs, supplies and services at reasonable prices; |
• | availability of sufficient pipeline, gathering and other transportation facilities and related infrastructure to process and transport our production and the impact of these facilities and regional capacity on the prices we receive for our production; |
• | timing and receipt of necessary regulatory permits; |
• | risks incidental to the drilling and operation of crude oil and natural gas wells; |
• | future cash flows, liquidity and financial condition; |
• | competition within the oil and gas industry; |
• | availability and cost of capital; |
• | reductions in the borrowing base under our revolving credit facility; |
• | our success in marketing crude oil, natural gas and NGLs; |
• | effect of crude oil and natural gas derivatives activities; |
• | impact of environmental events, governmental and other third-party responses to such events, and our ability to insure adequately against such events; |
• | cost of pending or future litigation; |
• | effect that acquisitions we may pursue have on our capital expenditures; |
• | our ability to retain or attract senior management and key technical employees; and |
• | success of strategic plans, expectations and objectives for our future operations. |
Further, we urge you to carefully review and consider the cautionary statements and disclosures, specifically those under the heading "Risk Factors," made in this Quarterly Report on Form 10-Q, our Annual Report on Form 10-K for the year ended December 31, 2014 (the
"2014 Form 10-K"), filed with the U.S. Securities and Exchange Commission ("SEC") on February 19, 2015, and our other filings with the SEC for further information on risks and uncertainties that could affect our business, financial condition, results of operations and prospects, which are incorporated by this reference as though fully set forth herein. We caution you not to place undue reliance on the forward-looking statements, which speak only as of the date of this report. We undertake no obligation to update any forward-looking statements in order to reflect any event or circumstance occurring after the date of this report or currently unknown facts or conditions or the occurrence of unanticipated events. All forward-looking statements are qualified in their entirety by this cautionary statement.
REFERENCES
Unless the context otherwise requires, references in this report to "PDC Energy," "PDC," "the Company," "we," "us," "our" or "ours" refer to the registrant, PDC Energy, Inc. and all subsidiaries consolidated for the purposes of its financial statements, including our proportionate share of the financial position, results of operations, cash flows and operating activities of our affiliated partnerships and PDC Mountaineer, LLC ("PDCM"), a joint venture owned, until October 2014, 50% each by PDC and Lime Rock Partners, LP. See Note 1, Nature of Operations and Basis of Presentation, to our condensed consolidated financial statements included elsewhere in this report for a description of our consolidated subsidiaries.
PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
PDC ENERGY, INC.
Condensed Consolidated Balance Sheets
(unaudited; in thousands, except share and per share data)
September 30, 2015 | December 31, 2014 | |||||||
Assets | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 3,690 | $ | 16,066 | ||||
Accounts receivable, net | 106,776 | 131,204 | ||||||
Fair value of derivatives | 208,144 | 187,495 | ||||||
Prepaid expenses and other current assets | 7,683 | 5,954 | ||||||
Total current assets | 326,293 | 340,719 | ||||||
Properties and equipment, net | 1,873,327 | 1,800,186 | ||||||
Assets held for sale | 2,874 | 2,874 | ||||||
Fair value of derivatives | 73,049 | 112,819 | ||||||
Other assets | 68,767 | 83,990 | ||||||
Total Assets | $ | 2,344,310 | $ | 2,340,588 | ||||
Liabilities and Shareholders' Equity | ||||||||
Liabilities | ||||||||
Current liabilities: | ||||||||
Accounts payable | $ | 65,337 | $ | 130,321 | ||||
Production tax liability | 26,159 | 21,314 | ||||||
Fair value of derivatives | 2,245 | 570 | ||||||
Funds held for distribution | 32,780 | 27,186 | ||||||
Current portion of long-term debt | 112,063 | — | ||||||
Accrued interest payable | 19,881 | 9,109 | ||||||
Deferred income taxes | 52,188 | 59,174 | ||||||
Other accrued expenses | 25,146 | 62,717 | ||||||
Total current liabilities | 335,799 | 310,391 | ||||||
Long-term debt | 550,000 | 664,923 | ||||||
Deferred income taxes | 87,907 | 125,693 | ||||||
Asset retirement obligation | 71,616 | 71,992 | ||||||
Fair value of derivatives | 723 | 197 | ||||||
Other liabilities | 18,529 | 30,033 | ||||||
Total liabilities | 1,064,574 | 1,203,229 | ||||||
Commitments and contingent liabilities | ||||||||
Shareholders' equity | ||||||||
Preferred shares - par value $0.01 per share, 50,000,000 shares authorized, none issued | — | — | ||||||
Common shares - par value $0.01 per share, 150,000,000 authorized, 40,121,608 and 35,927,985 issued as of September 30, 2015 and December 31, 2014, respectively | 401 | 359 | ||||||
Additional paid-in capital | 903,038 | 689,209 | ||||||
Retained earnings | 377,400 | 448,702 | ||||||
Treasury shares - at cost, 22,418 and 21,643 as of September 30, 2015 and December 31, 2014, respectively | (1,103 | ) | (911 | ) | ||||
Total shareholders' equity | 1,279,736 | 1,137,359 | ||||||
Total Liabilities and Shareholders' Equity | $ | 2,344,310 | $ | 2,340,588 | ||||
See accompanying Notes to Condensed Consolidated Financial Statements
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PDC ENERGY, INC.
Condensed Consolidated Statements of Operations
(unaudited; in thousands, except per share data)
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
2015 | 2014 | 2015 | 2014 | |||||||||||||
Revenues | ||||||||||||||||
Crude oil, natural gas and NGLs sales | $ | 104,483 | $ | 120,526 | $ | 275,520 | $ | 371,556 | ||||||||
Sales from natural gas marketing | 2,580 | 13,297 | 8,336 | 62,649 | ||||||||||||
Commodity price risk management gain, net | 123,549 | 90,213 | 141,170 | 12,661 | ||||||||||||
Well operations, pipeline income and other | 488 | 520 | 1,666 | 1,650 | ||||||||||||
Total revenues | 231,100 | 224,556 | 426,692 | 448,516 | ||||||||||||
Costs, expenses and other | ||||||||||||||||
Production costs | 25,484 | 22,754 | 71,129 | 64,611 | ||||||||||||
Cost of natural gas marketing | 2,781 | 13,347 | 8,875 | 62,645 | ||||||||||||
Exploration expense | 252 | 190 | 812 | 773 | ||||||||||||
Impairment of crude oil and natural gas properties | 153,535 | 1,863 | 158,792 | 3,621 | ||||||||||||
General and administrative expense | 18,528 | 34,625 | 55,875 | 96,549 | ||||||||||||
Depreciation, depletion and amortization | 80,947 | 49,640 | 206,873 | 142,165 | ||||||||||||
Accretion of asset retirement obligations | 1,594 | 861 | 4,742 | 2,542 | ||||||||||||
(Gain) loss on sale of properties and equipment | (74 | ) | 21 | (302 | ) | 577 | ||||||||||
Total cost, expenses and other | 283,047 | 123,301 | 506,796 | 373,483 | ||||||||||||
Income (loss) from operations | (51,947 | ) | 101,255 | (80,104 | ) | 75,033 | ||||||||||
Interest expense | (12,092 | ) | (11,821 | ) | (35,384 | ) | (36,199 | ) | ||||||||
Interest income | 1,378 | 39 | 3,626 | 309 | ||||||||||||
Income (loss) from continuing operations before income taxes | (62,661 | ) | 89,473 | (111,862 | ) | 39,143 | ||||||||||
Provision for income taxes | 21,167 | (35,396 | ) | 40,560 | (15,852 | ) | ||||||||||
Income (loss) from continuing operations | (41,494 | ) | 54,077 | (71,302 | ) | 23,291 | ||||||||||
Income (loss) from discontinued operations, net of tax | — | (80 | ) | — | 392 | |||||||||||
Net income (loss) | $ | (41,494 | ) | $ | 53,997 | $ | (71,302 | ) | $ | 23,683 | ||||||
Earnings per share: | ||||||||||||||||
Basic | ||||||||||||||||
Income (loss) from continuing operations | $ | (1.04 | ) | $ | 1.51 | $ | (1.84 | ) | $ | 0.65 | ||||||
Income (loss) from discontinued operations, net of tax | — | — | — | 0.01 | ||||||||||||
Net income (loss) | $ | (1.04 | ) | $ | 1.51 | $ | (1.84 | ) | $ | 0.66 | ||||||
Diluted | ||||||||||||||||
Income (loss) from continuing operations | $ | (1.04 | ) | $ | 1.47 | $ | (1.84 | ) | $ | 0.63 | ||||||
Income (loss) from discontinued operations, net of tax | — | — | — | 0.01 | ||||||||||||
Net income (loss) | $ | (1.04 | ) | $ | 1.47 | $ | (1.84 | ) | $ | 0.64 | ||||||
Weighted-average common shares outstanding: | ||||||||||||||||
Basic | 40,085 | 35,834 | 38,837 | 35,763 | ||||||||||||
Diluted | 40,085 | 36,828 | 38,837 | 36,831 | ||||||||||||
See accompanying Notes to Condensed Consolidated Financial Statements
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PDC ENERGY, INC.
Condensed Consolidated Statements of Cash Flows
(unaudited; in thousands)
Nine Months Ended September 30, | ||||||||
2015 | 2014 | |||||||
Cash flows from operating activities: | ||||||||
Net income (loss) | $ | (71,302 | ) | $ | 23,683 | |||
Adjustments to net income (loss) to reconcile to net cash from operating activities: | ||||||||
Net change in fair value of unsettled derivatives | 21,322 | (34,323 | ) | |||||
Depreciation, depletion and amortization | 206,873 | 151,293 | ||||||
Impairment of crude oil and natural gas properties | 158,792 | 4,054 | ||||||
Accretion of asset retirement obligation | 4,742 | 2,582 | ||||||
Stock-based compensation | 14,278 | 13,111 | ||||||
(Gain) loss on sale of properties and equipment | (302 | ) | 384 | |||||
Amortization of debt discount and issuance costs | 5,308 | 5,206 | ||||||
Deferred income taxes | (44,770 | ) | 14,981 | |||||
Non-cash interest income | (3,624 | ) | — | |||||
Other | 2,241 | (759 | ) | |||||
Changes in assets and liabilities | (10,552 | ) | 21,753 | |||||
Net cash from operating activities | 283,006 | 201,965 | ||||||
Cash flows from investing activities: | ||||||||
Capital expenditures | (489,036 | ) | (451,081 | ) | ||||
Proceeds from sale of properties and equipment | 319 | 1,587 | ||||||
Net cash from investing activities | (488,717 | ) | (449,494 | ) | ||||
Cash flows from financing activities: | ||||||||
Proceeds from sale of common stock, net of issuance costs | 202,851 | — | ||||||
Proceeds from revolving credit facility | 325,000 | 136,750 | ||||||
Repayment of revolving credit facility | (331,000 | ) | (61,000 | ) | ||||
Other | (3,516 | ) | (2,726 | ) | ||||
Net cash from financing activities | 193,335 | 73,024 | ||||||
Net change in cash and cash equivalents | (12,376 | ) | (174,505 | ) | ||||
Cash and cash equivalents, beginning of period | 16,066 | 193,243 | ||||||
Cash and cash equivalents, end of period | $ | 3,690 | $ | 18,738 | ||||
Supplemental cash flow information: | ||||||||
Cash payments for: | ||||||||
Interest, net of capitalized interest | $ | 23,467 | $ | 24,933 | ||||
Income taxes | 9,936 | 1,800 | ||||||
Non-cash investing and financing activities: | ||||||||
Change in accounts payable related to purchases of properties and equipment | $ | (68,529 | ) | $ | 19,320 | |||
Change in asset retirement obligation, with a corresponding change to crude oil and natural gas properties, net of disposals | 1,642 | 500 | ||||||
Purchase of properties and equipment under capital leases | 1,479 | — | ||||||
See accompanying Notes to Condensed Consolidated Financial Statements
3
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
September 30, 2015
(Unaudited)
NOTE 1 - NATURE OF OPERATIONS AND BASIS OF PRESENTATION
PDC Energy, Inc. (the "Company," "we," "us," or "our") is a domestic independent exploration and production company that produces, develops, acquires and explores for crude oil, natural gas and NGLs, with primary operations in the Wattenberg Field in Colorado and the Utica Shale in southeastern Ohio. Our operations in the Wattenberg Field are focused in the horizontal Niobrara and Codell plays and our Ohio operations are focused in the Utica Shale play. As of September 30, 2015, we owned an interest in approximately 2,950 gross wells. We are engaged in two business segments: Oil and Gas Exploration and Production and Gas Marketing. In October 2014, we sold our entire 50% ownership interest in our joint venture, PDCM, to an unrelated third-party.
The accompanying unaudited condensed consolidated financial statements include the accounts of PDC, our wholly-owned subsidiary Riley Natural Gas ("RNG"), our proportionate share of our four affiliated partnerships and, for the three and nine months ended September 30, 2014, our proportionate share of PDCM. Pursuant to the proportionate consolidation method, our accompanying condensed consolidated financial statements include our pro rata share of assets, liabilities, revenues and expenses of the entities which we proportionately consolidate. All material intercompany accounts and transactions have been eliminated in consolidation.
In our opinion, the accompanying condensed consolidated financial statements contain all adjustments (consisting of only normal recurring adjustments) necessary for a fair presentation of our financial statements for interim periods in accordance with accounting principles generally accepted in the United States of America ("U.S. GAAP") and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, pursuant to such rules and regulations, certain notes and other financial information included in audited financial statements have been condensed or omitted. The information presented in this Quarterly Report on Form 10-Q should be read in conjunction with our audited consolidated financial statements and notes thereto included in our 2014 Form 10-K. Our results of operations and cash flows for the three and nine months ended September 30, 2015 are not necessarily indicative of the results to be expected for the full year or any other future period.
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Recently Issued Accounting Standards
In May 2014, the Financial Accounting Standards Board ("FASB") and the International Accounting Standards Board issued their converged standard on revenue recognition that provides a single, comprehensive model that entities will apply to determine the measurement of revenue and timing of when it is recognized. The underlying principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. The standard outlines a five-step approach to apply the underlying principle: (1) identify the contract with the customer, (2) identify the separate performance obligations in the contract, (3) determine the transaction price, (4) allocate the transaction price to separate performance obligations and (5) recognize revenue when (or as) each performance obligation is satisfied. In August 2015, the FASB deferred the effective date of the revenue standard to annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The revenue standard can be adopted under the full retrospective method or simplified transition method. Entities are permitted to adopt the revenue standard early, beginning with annual reporting periods after December 15, 2016. We are currently evaluating the impact these changes may have on our condensed consolidated financial statements.
In August 2014, the FASB issued a new standard related to the disclosure of uncertainties about an entity's ability to continue as a going concern. The new standard will explicitly require management to assess an entity's ability to continue as a going concern every reporting period and to provide related footnote disclosures in certain circumstances. The new standard will be effective for all entities in the first annual period ending after December 15, 2016, with early adoption permitted. Adoption of this guidance is not expected to have a significant impact on our condensed consolidated financial statements.
In November 2014, the FASB issued an update to accounting for derivatives and hedging instruments. The update clarifies how current accounting guidance should be interpreted in evaluating the economic characteristics and risks of a host contract in a hybrid financial instrument that is issued in the form of a share. Specifically, the accounting update clarifies that an entity should consider all relevant terms and features, including the embedded derivative feature being evaluated for bifurcation, in evaluating the nature of the host contract. Furthermore, the update clarifies that no single term or feature would necessarily determine the economic characteristics and risks of the host contract. Rather, the nature of the host contract depends upon the economic characteristics and risks of the entire hybrid financial instrument. The assessment of the substance of the relevant terms and features should incorporate a consideration of the characteristics of the terms and features themselves, the circumstances under which the hybrid financial instrument was issued or acquired, and the potential outcomes of the hybrid financial instrument, as well as the likelihood of those potential outcomes. The accounting update is effective for public entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. Early adoption is permitted. We are currently evaluating the impact these changes may have on our condensed consolidated financial statements.
In January 2015, the FASB issued new accounting guidance eliminating from current accounting guidance the concept of extraordinary items, which, among other things, required an entity to segregate extraordinary items considered to be unusual and infrequent from the results of ordinary operations and show the item separately in the income statement, net of tax, after income from continuing operations. This guidance
4
is effective for public entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. Early adoption is permitted. Adoption of this guidance is not expected to have a significant impact on our condensed consolidated financial statements.
In February 2015, the FASB issued an accounting update modifying existing consolidation guidance for reporting organizations that are required to evaluate whether they should consolidate certain legal entities. The amendments in this update are effective for fiscal years and interim periods within those years beginning after December 15, 2015, and require either a retrospective or a modified retrospective approach to adoption. Early adoption is permitted. Adoption of this guidance is not expected to have a significant impact on our condensed consolidated financial statements.
In April 2015, the FASB issued an accounting update simplifying the presentation of debt issuance costs and requiring that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The update did not affect the recognition and measurement guidance for debt issuance costs. This guidance is effective for public entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. Early adoption is permitted. Adoption of this guidance is not expected to have a significant impact on our condensed consolidated financial statements.
In July 2015, the FASB issued an accounting update requiring all entities to measure inventory at the lower of cost and net realizable value. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. This guidance is effective for public entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016. Adoption of this guidance is not expected to have a significant impact on our condensed consolidated financial statements.
In September 2015, the FASB issued an accounting update requiring adjustments to provisional amounts that are identified during the measurement period of a business combination to be recognized in the reporting period in which the adjustment amounts are determined. The accounting update also requires an entity to present separately on the face of the income statement, or disclose in the notes, the portion of the amount recorded in current-period earnings, by line item, that would have been recorded in previous reporting periods if the adjustment to the estimated amounts had been recognized as of the acquisition date. This guidance is effective for public entities for fiscal years beginning after December 15, 2015, including interim periods within those fiscal years. The accounting update should be applied prospectively to adjustments to provisional amounts that occur after the effective date with earlier application permitted for financial statements that have not been issued. Adoption of this guidance is not expected to have a significant impact on our condensed consolidated financial statements.
NOTE 3 - FAIR VALUE OF FINANCIAL INSTRUMENTS
Derivative Financial Instruments
Determination of fair value. Our fair value measurements are estimated pursuant to a fair value hierarchy that requires us to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date, giving the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability, and may affect the valuation of the assets and liabilities and their placement within the fair value hierarchy levels. The three levels of inputs that may be used to measure fair value are defined as:
Level 1 – Quoted prices (unadjusted) for identical assets or liabilities in active markets.
Level 2 – Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived from observable market data by correlation or other means.
Level 3 – Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity.
Derivative Financial Instruments. We measure the fair value of our derivative instruments based on a pricing model that utilizes market-based inputs, including, but not limited to, the contractual price of the underlying position, current market prices, crude oil and natural gas forward curves, discount rates such as the LIBOR curve for a similar duration of each outstanding position, volatility factors and nonperformance risk. Nonperformance risk considers the effect of our credit standing on the fair value of derivative liabilities and the effect of our counterparties' credit standings on the fair value of derivative assets. Both inputs to the model are based on published credit default swap rates and the duration of each outstanding derivative position.
We validate our fair value measurement through the review of counterparty statements and other supporting documentation, the determination that the source of the inputs is valid, the corroboration of the original source of inputs through access to multiple quotes, if available, or other information and monitoring changes in valuation methods and assumptions. While we use common industry practices to develop our valuation techniques and believe our valuation method is appropriate and consistent with those used by other market participants, changes in our pricing methodologies or the underlying assumptions could result in significantly different fair values.
5
Our fixed-price swaps, basis swaps and physical purchases are included in Level 2 and our collars and physical sales are included in Level 3. The following table presents, for each applicable level within the fair value hierarchy, our derivative assets and liabilities, including both current and non-current portions, measured at fair value on a recurring basis:
September 30, 2015 | December 31, 2014 | ||||||||||||||||||||||
Significant Other Observable Inputs (Level 2) | Significant Unobservable Inputs (Level 3) | Total | Significant Other Observable Inputs (Level 2) | Significant Unobservable Inputs (Level 3) | Total | ||||||||||||||||||
(in thousands) | |||||||||||||||||||||||
Assets: | |||||||||||||||||||||||
Commodity-based derivative contracts | $ | 197,331 | $ | 83,862 | $ | 281,193 | $ | 237,939 | $ | 62,356 | $ | 300,295 | |||||||||||
Basis protection derivative contracts | — | — | — | 19 | — | 19 | |||||||||||||||||
Total assets | 197,331 | 83,862 | 281,193 | 237,958 | 62,356 | 300,314 | |||||||||||||||||
Liabilities: | |||||||||||||||||||||||
Commodity-based derivative contracts | 482 | — | 482 | 742 | — | 742 | |||||||||||||||||
Basis protection derivative contracts | 2,486 | — | 2,486 | 25 | — | 25 | |||||||||||||||||
Total liabilities | 2,968 | — | 2,968 | 767 | — | 767 | |||||||||||||||||
Net asset | $ | 194,363 | $ | 83,862 | $ | 278,225 | $ | 237,191 | $ | 62,356 | $ | 299,547 | |||||||||||
The following table presents a reconciliation of our Level 3 assets measured at fair value:
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
2015 | 2014 | 2015 | 2014 | |||||||||||||
(in thousands) | ||||||||||||||||
Fair value, net asset (liability), beginning of period | $ | 58,256 | $ | (6,967 | ) | $ | 62,356 | $ | 1,111 | |||||||
Changes in fair value included in statement of operations line item: | ||||||||||||||||
Commodity price risk management gain, net | 38,085 | 12,758 | 42,525 | 3,961 | ||||||||||||
Sales from natural gas marketing | 51 | 2 | 51 | (24 | ) | |||||||||||
Settlements included in statement of operations line items: | ||||||||||||||||
Commodity price risk management gain (loss), net | (12,530 | ) | 142 | (21,063 | ) | 882 | ||||||||||
Sales from natural gas marketing | — | (3 | ) | (7 | ) | 2 | ||||||||||
Fair value, net asset end of period | $ | 83,862 | $ | 5,932 | $ | 83,862 | $ | 5,932 | ||||||||
Net change in fair value of unsettled derivatives included in statement of operations line item: | ||||||||||||||||
Commodity price risk management gain, net | $ | 34,564 | $ | 11,831 | $ | 31,794 | $ | 673 | ||||||||
Sales from natural gas marketing | — | 1 | — | (2 | ) | |||||||||||
Total | $ | 34,564 | $ | 11,832 | $ | 31,794 | $ | 671 | ||||||||
The significant unobservable input used in the fair value measurement of our derivative contracts is the implied volatility curve, which is provided by a third-party vendor. A significant increase or decrease in the implied volatility, in isolation, would have a directionally similar effect resulting in a significantly higher or lower fair value measurement of our Level 3 derivative contracts. There has been no change in the methodology we apply to measure the fair value of our Level 3 derivative contracts.
Non-Derivative Financial Assets and Liabilities
The carrying value of the financial instruments included in current assets and current liabilities, excluding the current portion of long-term debt, approximate fair value due to the short-term maturities of these instruments.
The liability associated with our non-qualified deferred compensation plan for non-employee directors may be settled in cash or shares of our common stock. The carrying value of this obligation is based on the quoted market price of our common stock, which is a Level 1 input. The liability related to this plan, which was included in other liabilities on the condensed consolidated balance sheets, was immaterial as of September 30, 2015 and December 31, 2014.
6
The portion of our long-term debt related to our revolving credit facility approximates fair value due to the variable nature of related interest rates. We have not elected to account for the portion of our debt related to our senior notes under the fair value option; however, as of September 30, 2015, we estimate the fair value of the portion of our long-term debt related to our 3.25% convertible senior notes due 2016 to be $161.4 million, or 140.3% of par value, and the portion related to our 7.75% senior notes due 2022 to be $496.3 million, or 99.3% of par value. We determined these valuations based upon measurements of trading activity and broker and/or dealer quotes, respectively, which are published market prices, and therefore are Level 2 inputs.
The carrying value of our capital lease obligations approximates fair value as it represents the present value of future lease payments.
Concentration of Risk
Derivative Counterparties. Our derivative arrangements expose us to credit risk of nonperformance by our counterparties. We primarily use financial institutions who are also lenders under our revolving credit facility as counterparties to our derivative contracts. To date, we have had no counterparty default losses relating to our derivative arrangements. We have evaluated the credit risk of our derivative assets from our counterparties using relevant credit market default rates, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on our evaluation, we have determined that the potential impact of nonperformance of our counterparties on the fair value of our derivative instruments was not significant at September 30, 2015, taking into account the estimated likelihood of nonperformance.
The following table presents the counterparties that expose us to credit risk as of September 30, 2015 with regard to our derivative assets:
Counterparty Name | Fair Value of Derivative Assets | |||
(in thousands) | ||||
JP Morgan Chase Bank, N.A (1) | $ | 77,743 | ||
Canadian Imperial Bank of Commerce (1) | 72,977 | |||
Bank of Nova Scotia (1) | 41,354 | |||
Wells Fargo Bank, N.A. (1) | 38,973 | |||
NATIXIS (1) | 32,941 | |||
Key Bank N.A. (1) | 11,163 | |||
Other lenders in our revolving credit facility | 6,042 | |||
Total | $ | 281,193 | ||
__________
(1)Major lender in our revolving credit facility. See Note 7, Long-Term Debt.
Note Receivable. The following table presents information regarding our note receivable outstanding as of September 30, 2015:
Amount | |||
(in thousands) | |||
Note receivable: | |||
Principal outstanding, December 31, 2014 | $ | 39,707 | |
Paid-in-kind interest | 2,430 | ||
Principal outstanding, September 30, 2015 | $ | 42,137 | |
In October 2014, we sold our entire 50% ownership interest in PDCM to an unrelated third-party. See Note 13, Assets Held for Sale, Divestitures and Discontinued Operations, for additional information regarding the sale. As part of the consideration, we received a promissory note (the “Note”) for a principal sum of $39.0 million, bearing interest at varying rates beginning at 8%, and increasing annually. Pursuant to the Note agreement, interest shall be paid quarterly, in arrears, commencing in December 2014 and continuing on the last business day of each fiscal quarter thereafter. At the option of the issuer of the Note, an unrelated third-party, interest can be paid-in-kind (the “PIK Interest”) and any such PIK Interest will be added to the outstanding principal amount of the Note. As of September 30, 2015, the issuer of the Note had elected the PIK Interest option. The principal and any unpaid interest shall be due and payable in full in September 2020 and can be prepaid in whole or in part at any time, and in certain circumstances must be repaid prior to maturity. Any such prepayment will be made without premium or penalty. The Note is secured by a pledge of stock in certain subsidiaries of the unrelated third-party, debt securities and other assets.
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Under the effective interest method, we recognized $1.1 million and $3.4 million of interest income for the three and nine months ended September 30, 2015, respectively, of which $0.8 million and $2.4 million, respectively, was PIK Interest. As of September 30, 2015, the $42.1 million outstanding balance on the Note was included in the condensed consolidated balance sheet line item other assets.
NOTE 4 - DERIVATIVE FINANCIAL INSTRUMENTS
Our results of operations and operating cash flows are affected by changes in market prices for crude oil, natural gas and NGLs. To manage a portion of our exposure to price volatility from producing crude oil and natural gas, we utilize the following economic hedging strategies for each of our business segments.
• | For crude oil and natural gas sales, we enter into derivative contracts to protect against price declines in future periods. While we structure these derivatives to reduce our exposure to changes in price associated with the derivative commodity, they also limit the benefit we might otherwise have received from price increases in the physical market; and |
• | For natural gas marketing, we enter into fixed-price physical purchase and sale agreements that qualify as derivative contracts. In order to offset the fixed-price physical derivatives in our natural gas marketing, we enter into financial derivative instruments that have the effect of locking in the prices we will receive or pay for the same volumes and period, offsetting the physical derivative. |
We believe our derivative instruments continue to be effective in achieving the risk management objectives for which they were intended. As of September 30, 2015, we had derivative instruments, which were comprised of collars, fixed-price swaps, basis protection swaps and physical sales and purchases, in place for a portion of our anticipated production through 2018 for a total of 73,176 BBtu of natural gas and 6,701 MBbls of crude oil. The majority of our derivative contracts are entered into at no cost to us as we hedge our anticipated production at the then-prevailing commodity market prices.
We have elected not to designate any of our derivative instruments as hedges, and therefore do not qualify for use of hedge accounting. Accordingly, changes in the fair value of our derivative instruments are recorded in the statements of operations. Changes in the fair value of derivative instruments related to our Oil and Gas Exploration and Production segment are recorded in commodity price risk management, net. Changes in the fair value of derivative instruments related to our Gas Marketing segment are recorded in sales from and cost of natural gas marketing.
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The following table presents the balance sheet location and fair value amounts of our derivative instruments on the condensed consolidated balance sheets:
Fair Value | |||||||||||
Derivative instruments: | Balance sheet line item | September 30, 2015 | December 31, 2014 | ||||||||
(in thousands) | |||||||||||
Derivative assets: | Current | ||||||||||
Commodity contracts | |||||||||||
Related to crude oil and natural gas sales | Fair value of derivatives | $ | 207,731 | $ | 186,886 | ||||||
Related to natural gas marketing | Fair value of derivatives | 413 | 590 | ||||||||
Basis protection contracts | |||||||||||
Related to crude oil and natural gas sales | Fair value of derivatives | — | 19 | ||||||||
208,144 | 187,495 | ||||||||||
Non-current | |||||||||||
Commodity contracts | |||||||||||
Related to crude oil and natural gas sales | Fair value of derivatives | 72,950 | 112,599 | ||||||||
Related to natural gas marketing | Fair value of derivatives | 99 | 220 | ||||||||
73,049 | 112,819 | ||||||||||
Total derivative assets | $ | 281,193 | $ | 300,314 | |||||||
Derivative liabilities: | Current | ||||||||||
Commodity contracts | |||||||||||
Related to natural gas marketing | Fair value of derivatives | $ | 393 | $ | 545 | ||||||
Basis protection contracts | |||||||||||
Related to crude oil and natural gas sales | Fair value of derivatives | 1,852 | 25 | ||||||||
2,245 | 570 | ||||||||||
Non-current | |||||||||||
Commodity contracts | |||||||||||
Related to natural gas marketing | Fair value of derivatives | 89 | 197 | ||||||||
Basis protection contracts | |||||||||||
Related to crude oil and natural gas sales | Fair value of derivatives | 634 | — | ||||||||
723 | 197 | ||||||||||
Total derivative liabilities | $ | 2,968 | $ | 767 | |||||||
The following table presents the impact of our derivative instruments on our condensed consolidated statements of operations:
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
Condensed consolidated statement of operations line item | 2015 | 2014 | 2015 | 2014 | ||||||||||||
(in thousands) | ||||||||||||||||
Commodity price risk management gain, net | ||||||||||||||||
Net settlements | $ | 67,993 | $ | (4,459 | ) | $ | 162,454 | $ | (21,511 | ) | ||||||
Net change in fair value of unsettled derivatives | 55,556 | 94,672 | (21,284 | ) | 34,172 | |||||||||||
Total commodity price risk management gain, net | $ | 123,549 | $ | 90,213 | $ | 141,170 | $ | 12,661 | ||||||||
Sales from natural gas marketing | ||||||||||||||||
Net settlements | $ | 165 | $ | 210 | $ | 561 | $ | (376 | ) | |||||||
Net change in fair value of unsettled derivatives | (5 | ) | 170 | (298 | ) | 123 | ||||||||||
Total sales from natural gas marketing | $ | 160 | $ | 380 | $ | 263 | $ | (253 | ) | |||||||
Cost of natural gas marketing | ||||||||||||||||
Net settlements | $ | (157 | ) | $ | (182 | ) | $ | (531 | ) | $ | 502 | |||||
Net change in fair value of unsettled derivatives | (5 | ) | (191 | ) | 260 | (199 | ) | |||||||||
Total cost of natural gas marketing | $ | (162 | ) | $ | (373 | ) | $ | (271 | ) | $ | 303 | |||||
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All of our financial derivative agreements contain master netting provisions that provide for the net settlement of all contracts through a single payment in the event of early termination. Our fixed-price physical purchase and sale agreements that qualify as derivative contracts are not subject to master netting provisions and are not significant. We have elected not to offset the fair value positions recorded on our condensed consolidated balance sheets.
The following table reflects the impact of netting agreements on gross derivative assets and liabilities:
As of September 30, 2015 | Derivative instruments, recorded in condensed consolidated balance sheet, gross | Effect of master netting agreements | Derivative instruments, net | |||||||||
(in thousands) | ||||||||||||
Asset derivatives: | ||||||||||||
Derivative instruments, at fair value | $ | 281,193 | $ | (2,548 | ) | $ | 278,645 | |||||
Liability derivatives: | ||||||||||||
Derivative instruments, at fair value | $ | 2,968 | $ | (2,548 | ) | $ | 420 | |||||
As of December 31, 2014 | Derivative instruments, recorded in condensed consolidated balance sheet, gross | Effect of master netting agreements | Derivative instruments, net | |||||||||
(in thousands) | ||||||||||||
Asset derivatives: | ||||||||||||
Derivative instruments, at fair value | $ | 300,314 | $ | (29 | ) | $ | 300,285 | |||||
Liability derivatives: | ||||||||||||
Derivative instruments, at fair value | $ | 767 | $ | (29 | ) | $ | 738 | |||||
NOTE 5 - PROPERTIES AND EQUIPMENT
The following table presents the components of properties and equipment, net of accumulated depreciation, depletion and amortization ("DD&A"):
September 30, 2015 | December 31, 2014 | ||||||
(in thousands) | |||||||
Properties and equipment, net: | |||||||
Crude oil and natural gas properties | |||||||
Proved | $ | 2,712,759 | $ | 2,267,165 | |||
Unproved | 82,280 | 188,206 | |||||
Total crude oil and natural gas properties | 2,795,039 | 2,455,371 | |||||
Equipment and other | 32,119 | 29,562 | |||||
Land and buildings | 9,016 | 9,015 | |||||
Construction in progress | 99,008 | 137,937 | |||||
Properties and equipment, at cost | 2,935,182 | 2,631,885 | |||||
Accumulated DD&A | (1,061,855 | ) | (831,699 | ) | |||
Properties and equipment, net | $ | 1,873,327 | $ | 1,800,186 | |||
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The following table presents impairment charges recorded for crude oil and natural gas properties:
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||
2015 | 2014 | 2015 | 2014 | ||||||||||||
(in thousands) | |||||||||||||||
Continuing operations: | |||||||||||||||
Impairment of proved and unproved properties | $ | 150,344 | $ | — | $ | 150,344 | $ | — | |||||||
Amortization of individually insignificant unproved properties | 3,191 | 1,085 | 8,448 | 2,843 | |||||||||||
Other | — | 778 | — | 778 | |||||||||||
Total continuing operations | 153,535 | 1,863 | 158,792 | 3,621 | |||||||||||
Discontinued operations: | |||||||||||||||
Amortization of individually insignificant unproved properties | — | 274 | — | 433 | |||||||||||
Total impairment of crude oil and natural gas properties | $ | 153,535 | $ | 2,137 | $ | 158,792 | $ | 4,054 | |||||||
Due to a significant decline in commodity prices and a decrease in net-back realizations, we experienced a triggering event that required us to assess our crude oil and natural gas properties for possible impairment during the third quarter of 2015. As a result of our assessment, we recorded an impairment charge of $150.3 million to write-down our Utica Shale proved and unproved properties. Of this impairment charge, $24.7 million was recorded to write-down certain capitalized well costs on our Utica Shale proved producing properties. This impairment charge represented the amount by which the carrying value of these crude oil and natural gas properties exceeded the estimated fair value. The estimated fair value of approximately $27.9 million, excluding estimated salvage value, was determined based on estimated future discounted net cash flows, a Level 3 input, using estimated production and prices at which we reasonably expect the crude oil and natural gas will be sold. Additionally, as a result of the current outlook for future commodity prices, we recorded an impairment charge of $125.6 million to write-down all of our Utica Shale lease acquisition costs and pad development costs for pads not in production. These impairment charges were included in the condensed consolidated statements of operations line item impairment of crude oil and natural gas properties.
NOTE 6 - INCOME TAXES
We evaluate and update our estimated annual effective income tax rate on a quarterly basis based on current and forecasted operating results and tax laws. Consequently, based upon the mix and timing of our actual earnings compared to annual projections, our effective tax rate may vary quarterly and may make quarterly comparisons not meaningful. A tax expense or benefit unrelated to the current year income or loss is recognized in its entirety as a discrete item of tax in the period identified. The quarterly income tax provision is generally comprised of tax expense on income or benefit on loss at the most recent estimated annual effective tax rate, adjusted for the effect of discrete items.
The effective tax rate for continuing operations for the three and nine months ended September 30, 2015 was a 33.8% and 36.3% benefit on loss, respectively, compared to a 39.6% and 40.5% provision on income for the three and nine months ended September 30, 2014, respectively.
The effective tax rates for the three and nine months ended September 30, 2015 include discrete tax expense of $0.3 million. This discrete tax expense arose based upon the final actual 2014 tax return expense differing from the previous year’s estimated tax provision amount and the loss of a state deferred tax asset due to ceasing operations within that state. The effective rate for the three and nine months ended September 30, 2015 would have been 34.2% and 36.5%, respectively, without the inclusion of discrete items. This effective rate is based upon a full year forecasted tax benefit on loss and is greater than the statutory rate, primarily due to state taxes, percentage depletion and domestic production deduction, partially offset by nondeductible expenses that consist primarily of officers' compensation and government lobbying expenses.
The effective tax rates for the three and nine months ended September 30, 2014 include discrete tax expense of $0.6 million. This discrete tax expense arose based upon the final actual 2013 tax return expense differing from the previous year’s estimated tax provision amount. The effective rate for the three and nine months ended September 30, 2014 would have been 38.8% and 38.9%, respectively, without the inclusion of discrete items. This effective tax rate is based upon a full year forecasted tax provision on income and is greater than the statutory rate primarily due to state taxes and nondeductible officers' compensation, partially offset by percentage depletion and domestic production deduction.
As of September 30, 2015, we had no liability for unrecognized tax benefits. As of the date of this report, we are current with our income tax filings in all applicable state jurisdictions and are not currently under any state income tax examinations. We continue voluntary participation in the Internal Revenue Service’s ("IRS") Compliance Assurance Program for the 2014 and 2015 tax years. We have received a partial acceptance “no change” notice from the IRS for our filed 2014 federal tax return and expect to receive a full acceptance notice after the IRS’s post filing review is completed.
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NOTE 7 - LONG-TERM DEBT
Long-term debt consists of the following:
September 30, 2015 | December 31, 2014 | ||||||
(in thousands) | |||||||
Senior notes: | |||||||
3.25% Convertible senior notes due 2016: | |||||||
Principal amount | $ | 115,000 | $ | 115,000 | |||
Unamortized discount | (2,937 | ) | (6,077 | ) | |||
3.25% Convertible senior notes due 2016, net of discount | 112,063 | 108,923 | |||||
7.75% Senior notes due 2022 | 500,000 | 500,000 | |||||
Total senior notes | 612,063 | 608,923 | |||||
Revolving credit facility | 50,000 | 56,000 | |||||
Total debt | 662,063 | 664,923 | |||||
Less current portion of long-term debt | 112,063 | — | |||||
Long-term debt | $ | 550,000 | $ | 664,923 | |||
Senior Notes
3.25% Convertible Senior Notes Due 2016. In November 2010, we issued $115 million aggregate principal amount 3.25% convertible senior notes due May 15, 2016 (the "Convertible Notes") in a private placement to qualified institutional buyers. Interest is payable semi-annually in arrears on each May 15 and November 15. The indenture governing the Convertible Notes contains certain non-financial covenants. We allocated the gross proceeds of the Convertible Notes between the liability and equity components of the debt. The initial $94.3 million liability component was determined based upon the fair value of similar debt instruments with similar terms, excluding the conversion feature, and priced on the same day we issued the Convertible Notes. The original issue discount and capitalized debt issuance costs are being amortized to interest expense over the life of the Convertible Notes using an effective interest rate of 7.4%. As the stated maturity for payment of principal is May 2016, we have included the carrying value of the Convertible Notes, net of discount, in the current portion of long-term debt on our condensed consolidated balance sheet as of September 30, 2015.
Upon conversion, the Convertible Notes may be settled, at our election, in shares of our common stock, cash or a combination of cash and shares of our common stock. Per the terms of the Convertible Notes, we have currently elected the net-settlement method to satisfy our conversion obligation, which allows us to settle the principal amount of the Convertible Notes in cash and to settle the excess conversion value in shares, as well as cash in lieu of fractional shares. The Convertible Notes were not convertible at the option of holders as of September 30, 2015. Notwithstanding the inability to convert, the “if-converted” value of the Convertible Notes as of September 30, 2015 exceeded the aggregate principal amount by approximately $28.8 million.
7.75% Senior Notes Due 2022. In October 2012, we issued $500 million aggregate principal amount 7.75% senior notes due October 15, 2022 (the “2022 Senior Notes”) in a private placement to qualified institutional buyers. Interest on the 2022 Senior Notes is payable semi-annually in arrears on each April 15 and October 15. The indenture governing the 2022 Senior Notes contains customary restrictive incurrence covenants. Capitalized debt issuance costs are being amortized as interest expense over the life of the 2022 Senior Notes using the effective interest method.
As of September 30, 2015, we were in compliance with all covenants related to the Convertible Notes and the 2022 Senior Notes and expect to remain in compliance throughout the next 12-month period.
Credit Facility
Revolving Credit Facility. In September 2015, we entered into a Second Amendment to Third Amended and Restated Credit Agreement with JPMorgan Chase Bank, N.A. as administrative agent, and other lenders party thereto. This agreement amends and restates the credit agreement dated November 2010 and extends the maturity of the revolving credit facility to May 2020. The revolving credit facility is available for working capital requirements, capital expenditures, acquisitions, general corporate purposes and to support letters of credit. The revolving credit facility provides for a maximum of $1 billion in allowable borrowing capacity, subject to the borrowing base. As of September 30, 2015, the fall 2015 semi-annual redetermination resulted in the reaffirmation of our borrowing base at $700 million; however, we have elected to maintain the aggregate commitment at $450 million. The borrowing base is based on, among other things, the loan value assigned to the proved reserves attributable to our crude oil and natural gas interests, excluding proved reserves attributable to our affiliated partnerships. The borrowing base is subject to a semi-annual size redetermination based upon quantification of our reserves at June 30 and December 31, and is also subject to a redetermination upon the occurrence of certain events. The revolving credit facility is secured by a pledge of the stock of certain of our subsidiaries, mortgages of certain producing crude oil and natural gas properties and substantially all of our and such subsidiaries' other assets. Our affiliated partnerships are not guarantors of our obligations under the revolving credit facility.
12
We had $50.0 million outstanding on our revolving credit facility as of September 30, 2015, compared to $56.0 million outstanding as of December 31, 2014. The weighted-average interest rate on the outstanding balance on our revolving credit facility, exclusive of fees on the unused commitment and the letter of credit noted below, was 2.7% and 4.1% per annum as of September 30, 2015 and December 31, 2014, respectively.
As of September 30, 2015, RNG had an irrevocable standby letter of credit of approximately $11.7 million in favor of a third-party transportation service provider to secure firm transportation of the natural gas produced by third-party producers for whom we market production in the Appalachian Basin. The letter of credit currently expires in September 2016 and is automatically extended annually in accordance with the letter of credit's terms and conditions. The letter of credit reduces the amount of available funds under our revolving credit facility by an amount equal to the letter of credit. As of September 30, 2015, the available funds under our revolving credit facility, including the reduction for the $11.7 million letter of credit, was $388.3 million.
The revolving credit facility contains covenants customary for agreements of this type, with the most restrictive being certain financial tests on a quarterly basis. The financial tests, as defined per the revolving credit facility, include requirements to: (a) maintain a minimum current ratio of 1.00 to 1.00 and (b) not exceed a maximum leverage ratio of 4.25 to 1.00. As of September 30, 2015, we were in compliance with all the revolving credit facility covenants and expect to remain in compliance throughout the next 12-month period.
NOTE 8 - CAPITAL LEASES
Beginning in the first quarter of 2015, we entered into non-cancelable lease agreements for vehicles utilized by our operations and field personnel. Each lease agreement has a term of three years and is being accounted for as a capital lease, as the present value of minimum monthly lease payments, including the residual value guarantee, exceeds 90% of the fair value of the leased vehicles at inception of the lease.
The following table presents leased vehicles under capital leases as of September 30, 2015:
Amount | ||||
(in thousands) | ||||
Vehicles | $ | 1,479 | ||
Accumulated depreciation | (121 | ) | ||
$ | 1,358 | |||
Future minimum lease payments by year and in the aggregate, under non-cancelable capital leases with terms of one year or more, consist of the following:
For the Twelve Months Ending September 30, | Amount | |||
(in thousands) | ||||
2016 | $ | 447 | ||
2017 | 454 | |||
2018 | 743 | |||
1,644 | ||||
Less executory cost | (72 | ) | ||
Less amount representing interest | (215 | ) | ||
Present value of minimum lease payments | $ | 1,357 | ||
Short-term capital lease obligations | $ | 315 | ||
Long-term capital lease obligations | 1,042 | |||
$ | 1,357 | |||
Short-term capital lease obligations are included in other accrued expenses on the condensed consolidated balance sheets. Long-term capital lease obligations are included in other liabilities on the condensed consolidated balance sheets.
13
NOTE 9 - ASSET RETIREMENT OBLIGATIONS
The following table presents the changes in carrying amounts of the asset retirement obligations associated with our working interests in crude oil and natural gas properties:
Amount | |||
(in thousands) | |||
Balance at beginning of period, January 1, 2015 | $ | 73,855 | |
Obligations incurred with development activities | 1,642 | ||
Accretion expense | 4,742 | ||
Obligations discharged with asset retirements | (3,163 | ) | |
Balance end of period, September 30, 2015 | 77,076 | ||
Less current portion | (5,460 | ) | |
Long-term portion | $ | 71,616 | |
Short-term asset retirement obligations are included in other accrued expenses on the condensed consolidated balance sheets.
NOTE 10 - COMMITMENTS AND CONTINGENCIES
Firm Transportation, Processing and Sales Agreements. We enter into contracts that provide firm transportation, sales and processing agreements on pipeline systems through which we transport or sell crude oil and natural gas. Satisfaction of the volume requirements includes volumes produced by us, purchased from third parties and produced by our affiliated partnerships and other third-party working interest owners. We record in our financial statements only our share of costs based upon our working interest in the wells. These contracts require us to pay these transportation and processing charges, whether or not the required volumes are delivered. As commodity prices continue to remain depressed, certain customers under our Gas Marketing segment have begun and will continue to experience financial distress, which has led to certain contractual defaults. To date, we have had no material counterparty default losses.
The following table presents gross volume information related to our long-term firm transportation, sales and processing agreements for pipeline capacity:
For the Twelve Months Ending September 30, | ||||||||||||||||||||||||||
Area | 2016 | 2017 | 2018 | 2019 | 2020 and Through Expiration | Total | Expiration Date | |||||||||||||||||||
Natural gas (MMcf) | ||||||||||||||||||||||||||
Appalachian Basin | 7,136 | 7,117 | 7,117 | 7,117 | 20,480 | 48,967 | August 31, 2022 | |||||||||||||||||||
Utica Shale | 2,745 | 2,738 | 2,737 | 2,738 | 10,500 | 21,458 | July 22, 2023 | |||||||||||||||||||
Total | 9,881 | 9,855 | 9,854 | 9,855 | 30,980 | 70,425 | ||||||||||||||||||||
Crude oil (MBbls) | ||||||||||||||||||||||||||
Wattenberg Field | 2,420 | 2,413 | 2,413 | 2,413 | 1,813 | 11,472 | June 30, 2020 | |||||||||||||||||||
Dollar commitment (in thousands) | $ | 17,623 | $ | 17,473 | $ | 16,326 | $ | 16,326 | $ | 21,312 | $ | 89,060 | ||||||||||||||
Litigation. The Company is involved in various legal proceedings that it considers normal to its business. The Company reviews the status of these proceedings on an ongoing basis and, from time to time, may settle or otherwise resolve these matters on terms and conditions that management believes are in the best interests of the Company. There is no assurance that settlements can be reached on acceptable terms or that adverse judgments, if any, in the remaining litigation will not exceed the amounts reserved. Although the results cannot be known with certainty, we currently believe that the ultimate results of such proceedings will not have a material adverse effect on our financial position, results of operations or liquidity.
Class Action Regarding 2010 and 2011 Partnership Purchases
In December 2011, the Company and its wholly-owned merger subsidiary were served with an alleged class action on behalf of unit holders of 12 former limited partnerships, related to its repurchase of the 12 partnerships, which were formed beginning in late 2002 through 2005. The mergers were completed in 2010 and 2011. The action was filed in U.S. District Court for the Central District of California and was titled Schulein v. Petroleum Development Corp. The complaint primarily alleged that the disclosures in the proxy statements issued in connection with the mergers were inadequate, and a state law breach of fiduciary duty. In January 2014, the plaintiffs were certified as a class by the court.
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In October 2014, the Company and plaintiffs’ counsel reached a settlement agreement. That settlement agreement was signed in December 2014 and was given final court approval in March 2015. Under this settlement agreement, the plaintiffs received a cash payment of $37.5 million in January 2015, of which the Company paid $31.5 million and insurers paid $6 million. In March 2015, the class action was dismissed with prejudice and all class claims were released. As of December 31, 2014, the Company accrued a liability of $37.5 million related to this litigation, which was included in other accrued expenses in the condensed consolidated balance sheet.
Environmental. Due to the nature of the natural gas and oil industry, we are exposed to environmental risks. We have various policies and procedures to minimize and mitigate the risks from environmental contamination. We conduct periodic reviews to identify changes in our environmental risk profile. Liabilities are recorded when environmental damages resulting from past events are probable and the costs can be reasonably estimated. As of September 30, 2015 and December 31, 2014, we had accrued environmental liabilities in the amount of $4.4 million and $0.8 million, respectively, included in other accrued expenses on the condensed consolidated balance sheets. We are not aware of any environmental claims existing as of September 30, 2015 which have not been provided for or would otherwise have a material impact on our financial statements; however, there can be no assurance that current regulatory requirements will not change or that unknown past non-compliance with environmental laws will not be discovered on our properties.
In August 2015, we received a Clean Air Act Section 114 Information Request (the "Information Request") from the United States Environmental Protection Agency ("EPA"). The Information Request seeks, among other things, information related to the design, operation, and maintenance of our production facilities in the DJ Basin of Colorado. The Information Request focuses primarily on 46 of our production facilities and asks that we conduct certain sampling and analyses at the identified 46 facilities. We are currently scheduled to respond to the Information Request in January 2016. We cannot predict the outcome of this matter at this time.
In 2014, we experienced a loss of well control while drilling an oil and gas well in Morgan County, Ohio. The event resulted in a release of well fluids, including oil based drilling mud. We have completed the appropriate remediation to address the release. In August 2015, the EPA issued us a Notice of Intent seeking civil penalties. We and the EPA recently agreed in principle to settle this matter for a civil fine of approximately $152,000, although settlement is subject to the parties entering into a definitive settlement agreement.
Employment Agreements with Executive Officers. Each of our senior executive officers may be entitled to a severance payment and certain other benefits upon the termination of the officer's employment pursuant to the officer's employment agreement and/or the Company's executive severance compensation plan. The nature and amount of such benefits would vary based upon, among other things, whether the termination followed a change of control of the Company.
NOTE 11 - COMMON STOCK
Sale of Equity Securities
In March 2015, we completed a public offering of 4,002,000 shares of our common stock, par value $0.01 per share, at a price to us of $50.73 per share. Net proceeds of the offering were $202.9 million, after deducting offering expenses and underwriting discounts, of which $40,020 is included in common shares-par value and $202.8 million is included in additional paid-in capital on the September 30, 2015 condensed consolidated balance sheet. The shares were issued pursuant to an effective shelf registration statement on Form S-3 filed with the SEC in March 2015.
Stock-Based Compensation Plans
The following table provides a summary of the impact of our outstanding stock-based compensation plans on the results of operations for the periods presented:
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
2015 | 2014 | 2015 | 2014 | |||||||||||||
(in thousands) | ||||||||||||||||
Stock-based compensation expense | $ | 4,813 | $ | 4,232 | $ | 14,278 | $ | 13,111 | ||||||||
Income tax benefit | (1,828 | ) | (1,482 | ) | (5,423 | ) | (4,856 | ) | ||||||||
Net stock-based compensation expense | $ | 2,985 | $ | 2,750 | $ | 8,855 | $ | 8,255 | ||||||||
Stock Appreciation Rights ("SARs")
The SARs vest ratably over a three-year period and may be exercised at any point after vesting through ten years from the date of issuance. Pursuant to the terms of the awards, upon exercise, the executive officers will receive, in shares of common stock, the excess of the market price of the award on the date of exercise over the market price of the award on the date of issuance.
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In January 2015, the Compensation Committee awarded 68,274 SARs to our executive officers. The fair value of each SAR award was estimated on the date of grant using a Black-Scholes pricing model using the following assumptions:
Nine Months Ended September 30, | |||||||
2015 | 2014 | ||||||
Expected term of award | 6 years | 6 years | |||||
Risk-free interest rate | 1.6 | % | 2.1 | % | |||
Expected volatility | 59.4 | % | 65.6 | % | |||
Weighted-average grant date fair value per share | $ | 21.99 | $ | 29.96 | |||
The expected term of the award was estimated using historical stock option exercise behavior data. The risk-free interest rate was based on the U.S. Treasury yields approximating the expected life of the award in effect at the time of grant. Expected volatilities were based on our historical volatility. We do not expect to pay or declare dividends in the foreseeable future.
The following table presents the changes in our SARs for the periods presented:
Nine Months Ended September 30, | |||||||||||||||||||||||||
2015 | 2014 | ||||||||||||||||||||||||
Number of SARs | Weighted-Average Exercise Price | Average Remaining Contractual Term (in years) | Aggregate Intrinsic Value (in thousands) | Number of SARs | Weighted-Average Exercise Price | Average Remaining Contractual Term (in years) | Aggregate Intrinsic Value (in thousands) | ||||||||||||||||||
Outstanding beginning of year, January 1, | 279,011 | $ | 38.77 | 190,763 | $ | 33.77 | |||||||||||||||||||
Awarded | 68,274 | 39.63 | 88,248 | 49.57 | |||||||||||||||||||||
Outstanding at September 30, | 347,285 | 38.94 | 7.5 | $ | 4,888 | 279,011 | 38.77 | 8.0 | $ | 3,215 | |||||||||||||||
Vested and expected to vest at September 30, | 341,423 | 38.89 | 7.5 | 4,821 | 270,589 | 38.56 | 8.0 | 3,173 | |||||||||||||||||
Exercisable at September 30, | 191,149 | 35.68 | 6.6 | 3,312 | 109,920 | 32.71 | 7.1 | 1,933 | |||||||||||||||||
Total compensation cost related to SARs granted, net of estimated forfeitures, and not yet recognized in our condensed consolidated statement of operations as of September 30, 2015 was $2.4 million. The cost is expected to be recognized over a weighted-average period of 1.7 years.
Restricted Stock Awards
Time-Based Awards. The fair value of the time-based restricted shares is amortized ratably over the requisite service period, primarily three years. The time-based shares vest ratably on each anniversary following the grant date that a participant is continuously employed.
In January 2015, the Compensation Committee awarded to our executive officers a total of 80,707 time-based restricted shares that vest ratably over a three-year period ending in January 2018.
The following table presents the changes in non-vested time-based awards to all employees, including executive officers, for the nine months ended September 30, 2015:
Shares | Weighted-Average Grant-Date Fair Value | |||||
Non-vested at December 31, 2014 | 564,332 | $ | 46.02 | |||
Granted | 295,694 | 48.58 | ||||
Vested | (258,555 | ) | 40.36 | |||
Forfeited | (17,457 | ) | 54.51 | |||
Non-vested at September 30, 2015 | 584,014 | 49.56 | ||||
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The following table presents the weighted-average grant date fair value per share and related information as of/for the periods presented:
As of/for the Nine Months Ended September 30, | |||||||
2015 | 2014 | ||||||
(in thousands, except per share data) | |||||||
Total intrinsic value of time-based awards vested | $ | 13,061 | $ | 15,840 | |||
Total intrinsic value of time-based awards non-vested | 30,959 | 31,996 | |||||
Market price per common share as of September 30, | 53.01 | 50.29 | |||||
Weighted-average grant date fair value per share | 48.58 | 56.64 | |||||
Total compensation cost related to non-vested time-based awards, net of estimated forfeitures, and not yet recognized in our condensed consolidated statements of operations as of September 30, 2015 was $19.2 million. This cost is expected to be recognized over a weighted-average period of 1.9 years.
Market-Based Awards. The fair value of the market-based restricted shares is amortized ratably over the requisite service period, primarily three years. The market-based shares vest if the participant is continuously employed throughout the performance period and the market-based performance measure is achieved, with a maximum vesting period of three years. All compensation cost related to the market-based awards will be recognized if the requisite service period is fulfilled, even if the market condition is not achieved.
In January 2015, the Compensation Committee awarded a total of 29,398 market-based restricted shares to our executive officers. In addition to continuous employment, the vesting of these shares is contingent on the Company's total shareholder return ("TSR"), which is essentially the Company’s stock price change including any dividends, as compared to the TSR of a group of peer companies. The shares are measured over a three-year period ending on December 31, 2017 and can result in a payout between 0% and 200% of the total shares awarded. The weighted-average grant date fair value per market-based share for these awards granted was computed using the Monte Carlo pricing model using the following assumptions:
Nine Months Ended September 30, | |||||||
2015 | 2014 | ||||||
Expected term of award | 3 years | 3 years | |||||
Risk-free interest rate | 0.9 | % | 0.8 | % | |||
Expected volatility | 53.0 | % | 55.2 | % | |||
Weighted-average grant date fair value per share | $ | 57.35 | $ | 56.87 | |||
The expected term of the awards was based on the requisite service period. The risk-free interest rate was based on the U.S. Treasury yields in effect at the time of grant and extrapolated to approximate the life of the award. The expected volatility was based on our historical volatility.
The following table presents the change in non-vested market-based awards during the nine months ended September 30, 2015:
Shares | Weighted-Average Grant-Date Fair Value per Share | ||||||
Non-vested at December 31, 2014 | 83,721 | $ | 52.98 | ||||
Granted | 29,398 | 57.35 | |||||
Non-vested at September 30, 2015 | 113,119 | 54.12 | |||||
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The following table presents the weighted-average grant date fair value per share and related information as of/for the periods presented:
As of/for the Nine Months Ended September 30, | |||||||
2015 | 2014 | ||||||
(in thousands, except per share data) | |||||||
Total intrinsic value of market-based awards non-vested | $ | 5,996 | $ | 5,746 | |||
Market price per common share as of September 30, | 53.01 | 50.29 | |||||
Weighted-average grant date fair value per share | 57.35 | 56.87 | |||||
Total compensation cost related to non-vested market-based awards, net of estimated forfeitures, and not yet recognized in our condensed consolidated statements of operations as of September 30, 2015 was $2.4 million. This cost is expected to be recognized over a weighted-average period of 1.7 years.
NOTE 12 - EARNINGS PER SHARE
Basic earnings per share is computed by dividing net earnings by the weighted-average number of common shares outstanding for the period. Diluted earnings per share is similarly computed, except that the denominator includes the effect, using the treasury stock method, of unvested restricted stock, outstanding SARs, stock options, Convertible Notes and shares held pursuant to our non-employee director deferred compensation plan, if including such potential shares of common stock is dilutive.
The following table presents a reconciliation of the weighted-average diluted shares outstanding:
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||
2015 | 2014 | 2015 | 2014 | ||||||||
(in thousands) | |||||||||||
Weighted-average common shares outstanding - basic | 40,085 | 35,834 | 38,837 | 35,763 | |||||||
Dilutive effect of: | |||||||||||
Restricted stock | — | 259 | — | 287 | |||||||
SARs | — | 56 | — | 45 | |||||||
Stock options | — | 1 | — | 1 | |||||||
Non-employee director deferred compensation | — | 6 | — | 5 | |||||||
Convertible notes | — | 672 | — | 730 | |||||||
Weighted-average common shares and equivalents outstanding - diluted | 40,085 | 36,828 | 38,837 | 36,831 | |||||||
We reported a net loss for the three and nine months ended September 30, 2015. As a result, our basic and diluted weighted-average common shares outstanding were the same because the effect of the common share equivalents was anti-dilutive.
The following table presents the weighted-average common share equivalents excluded from the calculation of diluted earnings per share due to their anti-dilutive effect:
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||
2015 | 2014 | 2015 | 2014 | ||||||||
(in thousands) | |||||||||||
Weighted-average common share equivalents excluded from diluted earnings | |||||||||||
per share due to their anti-dilutive effect: | |||||||||||
Restricted stock | 816 | 4 | 836 | — | |||||||
SARs | 83 | 11 | 87 | 30 | |||||||
Stock options | 4 | — | 4 | — | |||||||
Non-employee director deferred compensation | 8 | — | 6 | — | |||||||
Convertible notes | 468 | — | 505 | — | |||||||
Total anti-dilutive common share equivalents | 1,379 | 15 | 1,438 | 30 | |||||||
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In November 2010, we issued our Convertible Notes, which give the holders the right to convert the aggregate principal amount into 2.7 million shares of our common stock at a conversion price of $42.40 per share. The Convertible Notes could be included in the diluted earnings per share calculation using the treasury stock method if the average market share price exceeds the $42.40 conversion price during the period presented. Shares issuable upon conversion of the Convertible Notes were excluded from the diluted earnings per share calculation for the three and nine months ended September 30, 2015 as the effect would be anti-dilutive to our earnings per share. Shares issuable upon conversion of the Convertible Notes were included in the diluted earnings per share calculation for the three and nine months ended September 30, 2014, as the average market price during the period exceeded the conversion price.
NOTE 13 - ASSETS HELD FOR SALE, DIVESTITURES AND DISCONTINUED OPERATIONS
In October 2014, we completed the sale of our entire 50% ownership interest in PDCM to an unrelated third-party for aggregate consideration, after our share of PDCM's debt repayment and other working capital adjustments, of approximately $192 million, comprised of approximately $153 million in net cash proceeds and a promissory note due in 2020 of approximately $39 million. The transaction included the buyer's assumption of our share of the firm transportation commitment related to the assets owned by PDCM, as well as our share of PDCM's natural gas hedging positions for the years 2014 through 2017. The divestiture resulted in a pre-tax gain of $76.3 million. Proceeds from the divestiture were used to reduce outstanding borrowings on our revolving credit facility and to fund a portion of our 2014 capital budget. The divestiture represented a strategic shift that will have a major effect on our operations, in that our organizational structure no longer has joint venture partners or dry gas assets. Therefore, our proportionate share of PDCM's Marcellus Shale results of operations have been separately reported as discontinued operations in the condensed consolidated statements of operations for the three and nine months ended September 30, 2014.
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The following table presents condensed consolidated statement of operations data related to discontinued operations:
Condensed consolidated statements of operations - discontinued operations | Three Months Ended September 30, 2014 | Nine Months Ended September 30, 2014 | ||||||
(in thousands) | ||||||||
Revenues | ||||||||
Crude oil, natural gas and NGLs sales | $ | 5,411 | $ | 24,149 | ||||
Commodity price risk management income (loss), net | 1,929 | (1,085 | ) | |||||
Well operations, pipeline income and other | — | 48 | ||||||
Total revenues | 7,340 | 23,112 | ||||||
Costs, expenses and other | ||||||||
Production costs | 1,020 | 7,120 | ||||||
Impairment of crude oil and natural gas properties | 273 | 433 | ||||||
Depreciation, depletion and amortization | 1,272 | 9,128 | ||||||
Other | 1,061 | 3,445 | ||||||
Gain on sale of properties and equipment | (1 | ) | (193 | ) | ||||
Total costs, expenses and other | 3,625 | 19,933 | ||||||
Interest expense | (709 | ) | (2,222 | ) | ||||
Interest income | 62 | 194 | ||||||
Income from discontinued operations | 3,068 | 1,151 | ||||||
Provision for income taxes | (3,148 | ) | (759 | ) | ||||
Income (loss) from discontinued operations, net of tax | $ | (80 | ) | $ | 392 | |||
The following table presents supplemental cash flows information related to our 50% ownership interest in PDCM, which is classified as discontinued operations:
Supplemental cash flows information - discontinued operations | Nine Months Ended September 30, 2014 | |||
(in thousands) | ||||
Cash flows from investing activities: | ||||
Capital expenditures | $ | (17,253 | ) | |
Significant non-cash investing items: | ||||
Change in accounts payable related to purchases of properties and equipment | (5,727 | ) | ||
Assets held for sale of $2.9 million as of September 30, 2015 and December 31, 2014 represents the carrying value of approximately 12 acres of land located adjacent to our Bridgeport, West Virginia, regional headquarters.
NOTE 14 - BUSINESS SEGMENTS
We separate our operating activities into two segments: Oil and Gas Exploration and Production and Gas Marketing. All material inter-company accounts and transactions between segments have been eliminated.
Oil and Gas Exploration and Production. Our Oil and Gas Exploration and Production segment includes all of our crude oil and natural gas properties. The segment represents revenues and expenses from the production and sale of crude oil, natural gas and NGLs. Segment revenue includes crude oil, natural gas and NGLs sales, commodity price risk management, net and well operation and pipeline income. Segment income (loss) consists of segment revenue less production cost, exploration expense, impairment of crude oil and natural gas properties, direct general and administrative expense and depreciation, depletion and amortization expense.
Gas Marketing. Our Gas Marketing segment purchases, aggregates and resells natural gas produced by us and others. Segment income (loss) primarily represents sales from natural gas marketing and direct interest income, less costs of natural gas marketing and direct general and administrative expense.
Unallocated Amounts. Unallocated income includes unallocated other revenue, less corporate general and administrative expense, corporate DD&A expense, interest income and interest expense. Unallocated assets include assets utilized for corporate general and administrative purposes, as well as assets not specifically included in our two business segments.
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The following tables present our segment information:
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||
2015 | 2014 | ||||||||||||||