C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S
Trinity River Energy, LLC
As of and for the Three Months Ended December 31, 2014

We have audited the accompanying consolidated financial statements of Trinity River Energy, LLC (the "Company"), which comprise the Consolidated Balance Sheet as of December 31, 2014, and the related statements of operations, members' equity, and cash flows for the three months then ended, and the related notes to the consolidated financial statements.

Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

Our responsibility is to express an opinion on these consolidated financial statements based on our audit. We conducted our audit in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditor's judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the Company's preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Trinity River Energy, LLC as of December 31, 2014, and the results of its operations and its cash flows for the three months then ended in accordance with accounting principles generally accepted in the United States of America.

	December 31, 2014

CURRENT ASSETS:
Cash	$	3,715
Accounts receivable, net		42,527
Prepaid and other		1,921
Derivative contracts		85,668

Total current assets		133,831
PROPERTY AND EQUIPMENT:
Oil and natural gas properties (successful efforts method)		1,476,870
Other fixed assets		2,657
Less: accumulated depreciation, depletion and amortization		(288,289	)

Net property and equipment		1,191,238
OTHER NONCURRENT ASSETS:
Deferred financing costs, net		4,898
Derivative contracts		23,802

TOTAL ASSETS	$	1,353,769



CURRENT LIABILITIES:
Accounts payable	$	23,978
Accrued liabilities		33,733
Royalties and revenue payable		19,195
Derivative contracts		1,742

Total current liabilities		78,648
LONG-TERM DEBT		486,000
OTHER NONCURRENT LIABILITIES:
Derivative contracts		4,985
Asset retirement obligations		44,851
Other		995

TOTAL LIABILITIES		615,479
COMMITMENTS AND CONTINGENCIES (Note 11)
MEMBERS' EQUITY		738,022
NONCONTROLLING INTEREST		268

TOTAL EQUITY		738,290

TOTAL LIABILITIES AND MEMBERS' EQUITY	$	1,353,769

	Three Months Ended December 31, 2014

REVENUES:
Oil, natural gas and natural gas liquids	$	71,395
Gathering, transportation and marketing		334

Total revenues		71,729
OPERATING EXPENSES:
Lease operating		23,550
Workover		744
Gathering, transportation and marketing		9,306
Production and ad valorem taxes		3,556
Exploration costs		845
Depreciation, depletion and amortization		27,134
Impairment of oil and natural gas properties		114,458
General and administrative		26,656

Total operating expenses		206,249

OPERATING LOSS		(134,520	)
OTHER INCOME (EXPENSE):
Interest expense, net of amounts capitalized		(5,227	)
Other income, net		252
Loss on sale of assets, net		(62	)
Gain on derivative contracts, net		79,231

Total other income		74,194

LOSS BEFORE INCOME TAX EXPENSE (BENEFIT)		(60,326	)
Income tax expense (benefit)		—

NET LOSS	$	(60,326	)
NONCONTROLLING INTEREST		8

NET LOSS ATTRIBUTABLE TO TRINITY RIVER ENERGY, LLC	$	(60,334	)

	Three Months Ended December 31, 2014

CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(60,326	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization		27,134
Impairment of oil and natural gas properties		114,458
Loss on sale of assets, net		62
Unrealized gain on derivative contracts		(70,529	)
Amortization of deferred financing costs		1,814
Other operating		(579	)
Changes in assets and liabilities:
Accounts receivable		6,236
Prepaid and other		(756	)
Accounts payable		(5,012	)
Accrued liabilities		4,250
Royalties and revenue payable		(913	)

Net cash provided by operating activities		15,839

CASH FLOWS FROM INVESTING ACTIVITIES:
Cash acquired in merger		13,919
Oil and natural gas properties capital expenditures		(18,216	)
Other fixed assets capital expenditures		(801	)

Net cash used in investing activities		(5,098	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Issuance of long-term debt		522,000
Reduction of long-term debt		(805,800	)
Proceeds from payment of shareholder loans		839
Deferred financing costs		(5,156	)
Distributions		(8	)
Contributions		253,690

Net cash used in financing activities		(34,435	)
NET DECREASE IN CASH		(23,694	)
CASH AT SEPTEMBER 30, 2014		27,409

CASH AT DECEMBER 31, 2014	$	3,715



Supplemental cash flow disclosures:
Interest paid, net of amounts capitalized	$	2,870
Noncash investing and financing activities:
Capital expenditures included in accrued liabilities	$	3,497

(Except per-unit amounts, or as noted within the context of each footnote disclosure, the dollar amounts presented in the tabular data within these footnote disclosures are stated in thousands of dollars.)

References to "we," "us" and "our" mean Trinity River Energy, LLC ("TRE") and subsidiaries.

We are a Delaware limited liability company formed on September 30, 2014, through a merger of partnerships held by wholly owned subsidiaries of Legend Production Holdings, LLC ("Legend"), a majority owned subsidiary of Riverstone Holdings, LLC and the Carlyle Group (collectively, "Riverstone/Carlyle"), and certain investment entities (together the "KNR Investors") of funds advised by Kohlberg Kravis Roberts & Co. L.P. (together with its affiliates, "KKR"). We have authorized and issued approximately 831 million Class A units, of which KKR and Riverstone/Carlyle each own approximately 77% and 23%, respectively.

We are an independent exploration and production company focused on the acquisition, exploration, development and production of oil, natural gas and natural gas liquids ("NGLs") reserves. We operate and have non-operating interests in producing wells and future drilling locations in the Barnett Shale in north central Texas, the Permian basin region in southeastern New Mexico and within various formations in south Texas, Louisiana and Mississippi.

The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") and include our accounts and those of our majority-owned, controlled subsidiaries for the relevant period and, in the opinion of management, reflect all adjustments necessary to present fairly the results of the period presented. All intercompany transactions have been eliminated in consolidation. We operate in one oil and natural gas exploration and production segment. We evaluated subsequent events through March 31, 2015, the date our financial statements were available to be issued.

The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. The most significant estimates pertain to:

1. Organization, Description of Operations and Basis of Presentation (Continued)

Actual results may differ from our estimates, judgments and assumptions used in the preparation of our consolidated financial statements.

Cash represents unrestricted cash on hand and highly liquid investments with original maturities of three months or less from the date of original issuance.

Our accounts receivable are primarily from purchasers of our oil, natural gas and NGL production and exploration and production companies which own interests in properties we operate. Receivables from purchasers of oil, natural gas and NGL production were $37.1 million at December 31, 2014. We generally do not require collateral or other security as a condition of sale; rather we rely on credit ratings and ongoing monitoring procedures.

We establish provisions for losses on accounts receivable if we determine that it is probable that we will not collect all or part of the outstanding balance. We regularly review collectability and establish or adjust the allowance as necessary using relevant attributes, such as recent loss experience, current economic conditions and other factors. We recorded an allowance for doubtful accounts of $0.3 million at December 31, 2014.

AROs associated with the legal obligation to retire tangible long-lived assets are recognized as liabilities with an increase to the carrying amounts of the related long-lived assets in the period incurred. AROs are recorded at estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligations discounted at our credit-adjusted risk-free interest rate. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value. If estimated future costs of AROs change, an adjustment is recorded to both the asset retirement obligation and the long-lived asset. Revisions to estimated AROs can result from changes in retirement cost estimates, revisions to estimated inflation rates, and changes in the estimated timing of abandonment. Accretion expense is included in depreciation, depletion and amortization expense in the Consolidated Statement of Operations. See Note 8 for further information.

We are subject to legal proceedings, claims, and liabilities that arise in the ordinary course of business. Except for legal contingencies acquired in a business combination, which are recorded at fair value at the time of acquisition, we accrue losses associated with legal claims when such losses are probable and reasonably estimable. If we determine that a loss is probable and cannot estimate a specific amount for that loss, but can estimate a range of loss, the best estimate within the range is accrued. If no amount within the range is a better estimate than any other, the minimum amount of

the range is accrued. Estimates are adjusted as additional information becomes available or circumstances change. Legal defense costs associated with loss contingencies are expensed in the period incurred. See Note 11 for further information.

We sell a significant amount of our oil, natural gas and NGL production to a limited number of purchasers. One of our purchasers accounted for 27% of our revenues for the three months ended December 31, 2014. No other purchaser accounted for 10% or more of our revenues for the three months ended December 31, 2014.

We use derivative contracts to reduce our exposure to commodity price volatility and interest rate changes. We do not use derivative contracts for trading purposes. We record all derivative contracts at fair value on the Consolidated Balance Sheet as either an asset or liability and do not designate any of our derivative contracts as hedging instruments for accounting purposes. Therefore, unrealized gains and losses from valuation changes in our unsettled derivative contracts are reported in gain on derivative contracts, net, in our Consolidated Statement of Operations.

We are party to various physical commodity contracts for the sale of oil, natural gas and NGLs that have varying terms and pricing provisions. While some of these physical commodity contracts meet the definition of a derivative instrument, the contracts qualify for and we elect the normal purchase and normal sale exception at inception and, therefore, are not subject to hedge or mark-to-market accounting. The financial impact of physical commodity contracts is included in oil, natural gas and natural gas liquids revenues at the time of settlement.

We are exposed to the credit risk of our counterparties. Credit risk is the potential failure of the counterparty to perform under the terms of the derivative contract. To minimize the credit risk in derivative contracts, the majority of our derivative contracts are with counterparties that are lenders under our revolving credit facility. As of December 31, 2014, we had no past-due receivables from any counterparty. See Notes 6 and 7 for a discussion of the use of financial instruments, management of credit risk inherent in financial instruments and fair value information.

We follow the successful efforts method of accounting for exploration and development expenditures. Under this method, costs of acquiring unproved and proved oil and natural gas leasehold acreage are capitalized. When proved reserves are found on unproved property, the associated leasehold cost is transferred to proved properties. The value of unproved leases included in oil and natural gas properties at December 31, 2014 is $45.9 million. Unproved leases are reviewed annually, and an impairment loss is recorded for any estimated decline in value. Development costs are capitalized, including the costs of unsuccessful development wells.

Exploration expenditures, including geological and geophysical costs, delay rentals and exploratory dry hole costs, are expensed as incurred. Costs of drilling exploratory wells are initially capitalized pending determination of whether proved reserves have been found and are subsequently expensed if it is determined that commercial quantities of hydrocarbons have not been discovered.

Depreciation, depletion and amortization ("DD&A") of producing oil and natural gas properties are calculated using the units-of-production method. Proved developed reserves are used to compute the DD&A rate for unamortized tangible and intangible drilling and completion costs, and total proved reserves are used to compute the DD&A rate for unamortized leasehold costs.

Gains and losses on disposals are included in operating income. Costs related to maintenance, repairs and minor renewals necessary to maintain properties in operating condition are expensed as incurred and recorded as lease operating expense. Major betterments, replacements and renewals are capitalized to the appropriate oil and natural gas property accounts.

We capitalize interest on capital invested in projects related to unevaluated properties and significant development projects. As proved reserves are established, the related capitalized interest is transferred into costs subject to amortization. Capitalized interest costs for the three months ended December 31, 2014, was $0.2 million.

Our oil and natural gas properties are assessed for impairment on a field-by-field basis annually and when events or changes in circumstances indicate that the carrying value may not be recoverable. The asset impairment review compares the carrying value of an oil and natural gas property to its estimated undiscounted future cash flows. When estimated undiscounted future cash flows are less than its carrying value, an impairment loss is recognized, and the oil and natural gas property is reduced to its estimated fair value. Fair value is calculated by discounting the future cash flows at an appropriate risk-adjusted discount rate consistent with that used by market participants.

The factors used to determine fair value include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows, net of estimated operating and development costs using estimates of reserves, future commodity pricing, future production estimates, anticipated capital expenditures and discount rates commensurate with the risk associated with realizing the projected cash flows. See note 7 for further information.

Proved oil, natural gas and NGL reserves are defined by the Financial Accounting Standards Board ("FASB") and the US Securities and Exchange Commission ("SEC"). This definition includes oil, natural gas, and NGLs that geological and engineering data demonstrate with reasonable certainty to be economically producible in future periods from known reservoirs under existing economic conditions, operating methods and government regulations, using price and cost assumptions as of the date the reserve estimates are made. Reserves are determined using a beginning-of-period 12-month average price with no provision for price and cost escalations in future years except by contractual arrangements. Our reserve estimates were prepared by third-party reservoir engineers.

The reserve estimation process is inherently uncertain for numerous reasons, including many factors beyond our control. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner.

The accuracy of any reserve estimate is a function of the quality of data available and of engineering and geological interpretation and judgment. In addition, estimates of reserves may be revised based on actual production, results of subsequent exploration and development activities,

prevailing commodity prices, operating costs and other factors. These revisions may be material and could materially affect future DD&A expense, plugging and abandonment costs and impairment expense.

We are not a taxpaying entity for federal income tax purposes and, accordingly, do not recognize any expense for such taxes. The federal income tax liability resulting from our activities is the responsibility of the members.

Some of our subsidiaries are subject to Texas margin tax and recognize deferred taxes for the future tax consequences of differences between the tax bases of assets and liabilities and their financial reporting amounts based on enacted tax laws and statutory tax rates applicable to the periods in which the differences are expected to affect taxable income. Such differences arise primarily from the differences in accounting treatment of intangible drilling costs and impairment losses for tax and financial reporting purposes, and basis adjustments for assets recorded at fair value for GAAP versus historical cost for tax.

Oil, natural gas and NGL sales are recognized based on actual volumes sold to customers and the contracted sales prices, and are reported net of royalties. Sales require delivery of the product to the customer, passage of title and probability of collection of customer amounts owed.

We use the sales method of accounting for natural gas imbalances. An imbalance is created when the volumes of natural gas sold by us pertaining to a property do not equate to the volumes produced to which we are entitled based on our interest in the property. An asset or liability is recognized to the extent that we have an imbalance in excess of our share of the remaining reserves on the underlying properties.

In April, 2014, the FASB issued Accounting Standards Update ("ASU") 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. The ASU changes the criteria for reporting discontinued operations and requires additional disclosures, both for discontinued operations and for individually significant dispositions and assets classified as held for sale not qualifying as discontinued operations. This ASU is effective for annual and interim periods beginning in 2015. We are currently evaluating the impact of the adoption of this ASU on our consolidated financial statements.

In May, 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. This ASU supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and industry-specific guidance in Subtopic 932-605, Extractive Activities—Oil and Gas—Revenue Recognition, and requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services. This ASU is effective for annual and interim periods beginning in 2017 and is required to be adopted using one of two retrospective application methods, with no early adoption permitted. We

are currently evaluating the impact of the adoption of this ASU on our consolidated financial statements.

In August, 2014, the FASB issued ASU 2014-15—Presentation of Financial Statements—Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity's Ability to Continue as a Going Concern. This guidance requires management to perform interim and annual assessments of an entity's ability to continue as a going concern within one year of the date the financial statements are issued. The standard also provides guidance on determining when and how to disclose going-concern uncertainties in the financial statements. The new guidance is effective for the annual period ending after December 15, 2016, and interim periods thereafter, with early adoption permitted. We are currently evaluating the impact of the adoption of this ASU on our consolidated financial statements.

In November, 2014, the FASB issued ASU 2014-17, Business Combinations (Topic 805): Pushdown Accounting. The ASU gives an acquired business or not-for-profit organization the option to apply pushdown accounting in their separate financial statements when an acquirer obtains control of them. Pushdown accounting occurs in an acquisition when an acquired organization uses the acquirer's basis of accounting to prepare its financial statements. The new standard also requires disclosures designed to help financial statement users evaluate the effects of pushdown accounting. The SEC rescinded portions of its interpretive guidance for pushdown accounting to bring its guidance into conformity with the new FASB standard. The new guidance did not have a material impact on our financial position or results of operations.

The September 30, 2014 Merger between KNR Investors and Legend represents a business combination that was accounted for using the acquisition method of accounting which requires, among other things, that assets acquired and liabilities assumed be recognized at their fair values as of the acquisition date. KNR Investors was determined to be the accounting acquirer. The merger was motivated by the desire of KNR Investors to generate benefits of scale resulting from operational expense synergies (especially within the Barnett Shale in north central Texas), and obtain the ability to better access the capital markets. We assumed debt and other liabilities of approximately $616.8 million in exchange for oil and natural gas properties and other assets of approximately that amount. In connection with the merger, we incurred acquisition-related costs of approximately $7.3 million, which are included in general and administrative expenses in the accompanying Consolidated Statement of Operations. The following table summarizes the preliminary fair value assessment of the contributed assets and liabilities assumed as of the acquisition date (in thousands):

On September 30, 2014, we entered into a senior secured revolving credit agreement (the "Credit Agreement") with a group of financial institutions (the "Lenders") that provides a facility with a $1.0 billion commitment and a current borrowing base of $650.0 million (the "Revolving Credit Facility"). The borrowing base will be re-determined on a semi-annual basis, or as requested by our Lenders or us. To the extent that the borrowing base is re-determined at an amount that is below the amount currently outstanding, we have options under the Credit Agreement, including repayment over a period of up to six months, provision of additional collateral, or other negotiated alternatives with the Lenders. We used the borrowings from the Revolving Credit Facility to repay existing indebtedness of Legend and KNR Investors and provide additional working capital. The obligations under the Credit Agreement and guarantees of those obligations are secured by substantially all of our oil and natural gas properties. The maturity date of the revolving credit facility is September 30, 2019. As of December 31, 2014, the amount outstanding under the credit agreement was $486.0 million and the amount available for borrowing was $164.0 million.

Pursuant to the credit agreement, interest on borrowings is calculated using the adjusted base rate plus an applicable margin or the London Interbank Offered Rate ("LIBOR") plus an applicable margin. The adjusted base rate is defined as the greater of (a) the prime rate established by the administrative agent, (b) the federal funds rate in effect plus 0.50% and (c) the daily one-month LIBOR plus 1.00%. The applicable margin ranges from 0.50% to 1.50% for the adjusted base rate loans and from 1.50% to 2.50% for LIBOR loans, depending on the percentage of the borrowing base utilization level. In addition to interest, the banks receive various fees, including a commitment fee on the unutilized commitment, which ranges from 0.375% to 0.50% per annum. The weighted-average interest rate on loan amounts outstanding during the three months ended December 31, 2014, was 2.59%.

Our credit agreement contains financial covenants typical for these types of agreements, including a total debt to EBITDAX (earnings before interest, taxes, depreciation, depletion, and amortization, and exploration) ratio and a current assets to current liabilities ratio. At December 31, 2014, we were in compliance with all of our covenants under the credit agreement.

Our liquidity outlook has changed since September 30, 2014 primarily as a result of the substantial decrease in oil and natural gas prices. This has resulted in lower operating revenues than expected and if commodity prices remain low compared to recent historical prices, will result in significantly lower future levels of operating cash flows as current derivative contracts expire.

As discussed above, our Revolving Credit Facility's borrowing base is subject to re-determination on a semi-annual basis. Although it is unknown what impact the lower commodity price environment will have on our borrowing base, we believe we are strategically positioned to sustain a low price environment for the next 12 to 18 months. Our derivative contracts are significantly in excess of current commodity prices and provide price protection for a significant portion of our 2015 and 2016 production. Additionally, our plans are to conserve cash through mid-2016 by focusing on internal cost reductions and limiting drilling activities (we have no firm commitments in place for drilling on our operated properties as of year-end). Assuming limited drilling activities, excess operating cash flow will be used to reduce borrowings under our Revolving Credit Facility.

Our forecasts indicate that current unutilized borrowing capacity under the Revolving Credit Facility of $164.0 million, coupled with repayment efforts and cash flows from existing derivative contracts, are sufficient to ensure ongoing compliance with our financial performance covenants under the Revolving Credit Facility for at least the next 12 to 18 months.

We capitalize costs incurred in connection with obtaining financing and amortize such costs as additional interest expense over the life of the underlying indebtedness. Deferred financing costs charged to interest expense for the three months ended December 31, 2014 was $1.8 million.

In the normal course of business, we are exposed to certain risks, including changes in the prices of oil, natural gas and NGLs and interest rates. We enter into derivative contracts to manage our exposure to these risks. Our risk management activity is generally accomplished through over-the-counter derivative contracts with large financial institutions.

As of December 31, 2014, we had natural gas swap contracts based on West Texas hub (WAHA) and Houston Ship Channel ("HSC") index prices, oil swap contracts and natural gas swap contracts based on the New York Mercantile Exchange ("NYMEX") futures index and NGL swap contracts based on the trading prices at Mont Belvieu. The fair values, notional quantities and weighted-average swap prices of these contracts as of December 31, 2014, are summarized in the table below.

Volumes are presented in million British Thermal Units ("MMBtu") for natural gas and in barrels ("Bbls") for oil and NGLs.

			Weighted- Average Swap Price			Fair Value (in thousands)

Natural Gas Swap Contracts (MMBtu):	2015	44,200,000	$	4.53		$	66,966
	2016	30,971,000		4.13			20,364
	2017	7,259,000		4.17			2,542

Total natural gas		82,430,000					89,872



Oil Swap Contracts (Bbls):	2015	195,300		93.18			7,142
	2016	33,000		84.45			695
	2017	13,000		82.30			201

Total oil		241,300					8,038



NGL Swap Contracts (Bbls):	2015	551,000		44.46	(1)		11,550

Total NGLs		551,000					11,550



Basis Swap Contracts:
Oil (Bbls)	2015	57,400		2.57			10

		57,400					10



Total oil, natural gas, NGL and basis contracts						$	109,470

The following table summarizes the fair value, notional amount and swap rate of the interest rate swap contracts in place at December 31, 2014:

Type	Effective Date	Maturity Date			Notional Amount (in thousands)		Fair Value (in thousands)

Swap	May 26, 2011	March 1, 2015	1.6410	%	$	40,000	$	(225	)
Swap	May 26, 2011	March 1, 2015	1.6400	%		40,000		(225	)
Swap	May 26, 2011	March 1, 2015	1.6400	%		60,000		(338	)
Swap	May 26, 2011	March 1, 2015	1.6410	%		60,000		(338	)
Swap	January 2, 2015	June 1, 2023	2.8532	%		71,000		(4,100	)
Swap	January 2, 2015	December 1, 2019	2.1339	%		13,000		(310	)
Swap	January 2, 2015	December 1, 2021	2.5782	%		13,000		(541	)
Swap	January 2, 2015	June 1, 2023	2.8532	%		9,000		(520	)
Swap	January 2, 2015	December 1, 2021	2.5782	%		2,000		(83	)
Swap	January 2, 2015	December 1, 2019	2.1339	%		2,000		(47	)

							$	(6,727	)

Our derivative contracts are subject to master netting arrangements and are presented on a net basis in our Consolidated Balance Sheet. The following table summarizes the location and fair value of our derivative contracts as of December 31, 2014 (in thousands):

Derivative Contracts	Balance Sheet Classification	Gross amounts recognized			Net amounts recognized

Derivative Assets
Commodity swaps	Derivative contracts—current	$	85,668	—	$	85,668
Commodity swaps	Derivative contracts—non-current		23,802	—		23,802

		$	109,470	—	$	109,470



Derivative Liabilities
Interest rate swaps	Derivative contracts—current	$	1,742	—	$	1,742
Interest rate swaps	Derivative contracts—non-current		4,985	—		4,985

		$	6,727	—	$	6,727

The following table summarizes the effects of our derivative contracts on the Combined and Consolidated Statement of Operations for the three months ended December 31, 2014 (in thousands):

	Location of Gain Recognized in Other Income (Expense)	Amount of Gain (Loss) Recognized in Net Loss

Commodity swaps:
Realized gain	Gain on derivative contracts, net	$	9,419
Unrealized gain	Gain on derivative contracts, net		72,911
Interest rate swaps:
Realized loss	Gain on derivative contracts, net		(717	)
Unrealized loss	Gain on derivative contracts, net		(2,382	)

Total realized and unrealized gain on derivative contracts		$	79,231

We classify financial assets and liabilities that are measured and reported at fair value on a recurring basis using a hierarchy based on the inputs used in measuring fair value. GAAP defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We classify the inputs used to measure fair value into the following hierarchy:

Our financial assets and liabilities that were accounted for at fair value on a recurring basis at December 31, 2014 are as follows (in thousands):

Our derivative contracts consist of swaps for oil, natural gas, NGLs, oil basis, and interest rates and are carried at fair value. Commodity derivative contracts are valued using market inputs such as

indexes, pricing and interest rates in a discounted cash flow model. Interest rate derivative contracts are valued using inputs such as LIBOR futures and interest rates using a discounted cash flow model. As such, these derivative contracts are classified within Level 2.

The initial measurement of ARO at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with property and equipment. Significant Level 3 inputs used in the calculation of ARO include plugging costs and reserve lives. A reconciliation of our ARO is presented in Note 8.

Certain nonfinancial assets and liabilities are measured at fair value on a nonrecurring basis (e.g., oil and natural gas properties) and are subject to fair value adjustments under certain circumstances. The inputs used to determine such fair value are primarily based upon internally developed cash flow models and are classified within Level 3.

During the three months ended December 31, 2014, using a discounted cash flow valuation technique, we adjusted the carrying value of certain oil and natural gas properties and recorded impairment charges of $114.5 million. The impairment charges primarily resulted from a decline in oil and natural gas prices and to a much lesser extent to minor changes in management's assumptions, based on an extensive review of operating results, production history, price realizations and costs.

The estimated fair value of cash, accounts receivable and accounts payable approximates their carrying value due to their short-term nature. The estimated fair value of our long-term debt approximates carrying value because it carries a variable interest rate reflective of market rates. We categorized our long-term debt within Level 2 of the fair value hierarchy.

We record an ARO for our future plugging, abandonment and site restoration costs related to our oil and natural gas properties. The changes in our AROs for the three months ended December 31, 2014 are presented in the table below (in thousands):

	2014

Beginning balance, October 1	$	32,342
Acquisitions		13,182
Liabilities settled and divested		(421	)
Accretion expense		417
Revision of estimates		(216	)

Ending balance, December 31		45,304
Less: current portion		(453	)

Long-term asset retirement obligation	$	44,851

The amount of the obligation expected to be incurred in the upcoming year is included in accrued liabilities in our Consolidated Balance Sheet.

We record deferred income taxes related to Texas margin tax for the net effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for Texas margin tax provisions. At December 31, 2014, we recorded a long-term deferred tax asset of $2.8 million and a valuation allowance of the same amount, due to low probability of realization.

We maintain separate capital accounts for each of our members and capital contributions, distributions and net income (loss) are recorded pro rata to each in accordance with their ownership percentage. On September 30, 2014, in connection with the Merger, we received $253.7 million in cash contributions from our members to fund the Company.

We have an agreement with certain of our officers to purchase 2,525,000 Class A Units at a price of $1 per unit. The agreement provides for officer loans which are to be paid in 2014 and 2015. The outstanding loans as of December 31, 2014 were $1.7 million and are presented net within Members' Equity until cash payment occurs.

We lease office space under operating leases in Houston, Texas, and Fort Worth, Texas, and rent expense related to these lease agreements for the three months ended December 31, 2014 was $0.3 million.

We contract with various companies to transport the natural gas we produce to purchasers and processing plants. The contracts are based on actual amounts transported with minimum amounts committed to be paid.

We have programs in the form of cash retention bonuses and performance bonuses for eligible key employees. The payments are contingent upon the successful completion of the Merger, as well as certain future liquidity events leading to change in control. We expect to pay $8.0 million in 2015. At December 31, 2014, we accrued a liability of $3.2 million for these programs, included in accrued liabilities on the Consolidated Balance Sheet.

We have a compensation program for certain key service providers. We accrued a liability of $2.7 million at December 31, 2014, which we expect to pay in 2015.

The future minimum payments related to these contracts as of December 31, 2014, are presented in the table below (in thousands):

Year	Office Lease		Transportation		Bonus and Severance Programs		Total

2015	$	1,669	$	2,512	$	13,317	$	17,498
2016		1,796		1,175		—		2,971
2017		1,832		1,007		—		2,839
2018		1,872		986		—		2,858
2019		1,913		178		—		2,091
Thereafter		8,517		—		—		8,517

Total	$	17,599	$	5,858	$	13,317	$	36,774

We are party to various legal actions arising in the normal course of business. Management believes the disposition of these outstanding legal actions will not have a material impact on our financial condition, results of operations or cash flows.


Independent Auditors' Report			1
Consolidated Financial Statements
Consolidated Balance Sheet			2
Consolidated Statement of Operations			3
Consolidated Statement of Members' Equity			4
Consolidated Statement of Cash Flows			5
Notes to the Consolidated Financial Statements			6

Assets Acquired

Cash	$	13,919
Accounts receivable, net		22,456
Derivative assets		22,189
Oil and natural gas properties		555,504
Other fixed assets		1,617
Other assets		1,109

Total identifiable net assets	$	616,794

Liabilities Assumed

Long-term debt	$	(551,000	)
Accounts payable and accrued liabilities		(50,184	)
Derivative liabilities		(1,788	)
Asset retirement obligations		(13,182	)
Other liabilities		(640	)

Total identifiable net liabilities	$	(616,794	)

	Three Months Ended December 31, 2014

BEGINNING BALANCE	$	544,095
Net loss		(60,326	)
Contributions		253,690
Distributions		(8	)
Payment of shareholder loans (Note 10)		839

ENDING BALANCE	$	738,290

	December 31, 2014

	Level 1		Level 2		Level 3		Total
Assets:
Commodity derivative contracts	$	—	$	109,470	$	—	$	109,470
Liabilities:
Interest rate derivative contracts		—		6,727		—		6,727