Exhibit

Depreciation, depletion and amortization

Impairment of oil and natural gas properties

EX-99.4 9 a994-trinityriverenergy201.htm EXHIBIT 99.4 Exhibit

Exhibit 99.4

Trinity River Energy, LLC

Combined and Consolidated Financial Statements

as of and for the Years Ended December 31, 2015 and 2014 and Independent Auditors’ Report

TRINITY RIVER ENERGY, LLC

TABLE OF CONTENTS

Page

INDEPENDENT AUDITORS’ REPORT 1–2

COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS AS OF AND FOR THE YEARS ENDED DECEMBER 31, 2015 AND 2014:

Consolidated Balance Sheets 3

Consolidated Statement of Operations for the year ended December 31, 2015 and Combined and Consolidated Statement of Operations for the year ended December 31, 2014. 4

Consolidated Statement of Members’ Equity for the year ended December 31, 2015 and Combined and Consolidated Statement of Members’ Equity for the year ended December 31, 2014. 5

Consolidated Statement of Cash Flows for the year ended December 31, 2015 and Combined and Consolidated Statement of Cash Flows for the year ended December 31, 2014. 6

Notes to the Combined and Consolidated Financial Statements 7–23

INDEPENDENT AUDITORS’ REPORT

To the Board of Directors of Trinity River Energy, LLC:

We have audited the accompanying combined and consolidated financial statements of Trinity River Energy, LLC and its subsidiaries (the “Company”), which comprise the consolidated balance sheets as of December 31, 2015 and 2014, and the related combined and consolidated statements of operations, members’ equity, and cash flows for the years then ended and the related notes to the combined and consolidated financial statements (collectively, the “financial statements”).

Management’s Responsibility for the Financial Statements

Management is responsible for the preparation and fair presentation of these 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 financial statements that are free from material misstatement, whether due to fraud or error.

Auditors’ Responsibility

Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits 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 financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the 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 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 financial statements.

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

Opinion

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Trinity River Energy, LLC and its subsidiaries as of December 31, 2015 and 2014, and the results of its operations and its cash flows for the years then ended in accordance with accounting principles generally accepted in the United States of America.

Emphasis of Matter Regarding Going Concern

The accompanying financial statements for the year ended December 31, 2015, have been prepared assuming that the Company will continue as a going concern. As discussed in Note 2 to the consolidated financial statements, the Company’s projected debt covenant violation, which could result in an acceleration of the maturity of the Company’s debt under the Revolving Credit Facility leading to a possible lack of liquidity, raises substantial doubt about its ability to continue as a going concern.

Management's plans in regard to these matters are also described in Note 2. The financial statements do not include any adjustments that might result from the outcome of this uncertainty. Our opinion is not modified with respect to this matter.

Emphasis of a Matter

As discussed in Note 1 to the financial statements, the Company was formed on September 30, 2014 through a merger of Legend Production Holdings, LLC and KNR Investors.

March 30, 2016

TRINITY RIVER ENERGY, LLC

CONSOLIDATED BALANCE SHEETS AS OF DECEMBER 31, 2015 AND 2014

(In thousands)

CURRENT ASSETS:

December 31, 2015 December 31, 2014



Cash	$	7,935	$	3,715
Accounts receivable—net	23,041		42,527
Prepaid and other	3,301		1,921
Deferred financing costs—net	3,963		-
Derivative contracts	56,197		85,668

Total current assets 94,437 133,831 PROPERTY AND EQUIPMENT:



Oil and natural gas properties (successful efforts method)	1,342,041		1,478,681
Other fixed assets	5,679		2,657
Less accumulated depreciation, depletion and amortization	(866,327	)	(297,186	)

Net property and equipment 481,393 1,184,152 OTHER NONCURRENT ASSETS:



Deferred financing costs—net	-		4,898
Derivative contracts	10,105		23,802
TOTAL ASSETS	$	585,935	$	1,346,683
CURRENT LIABILITIES:
Accounts payable	$	7,219	$	23,978
Accrued liabilities	22,587		33,733
Royalties and revenue payable	25,118		19,195
Derivative contracts	964		1,742
Other current liabilities	278		-
Current portion of long-term debt	274,000		-
Total current liabilities	330,166		78,648
LONG-TERM DEBT	-		486,000
OTHER NONCURRENT LIABILITIES:
Derivative contracts	7,432		4,985
Asset retirement obligations	38,275		46,748
Other	675		995
TOTAL LIABILITIES	376,548		617,376
COMMITMENTS AND CONTINGENCIES (Note 13)
MEMBERS’ EQUITY	209,123		729,039
NONCONTROLLING INTEREST	264		268
TOTAL EQUITY	209,387		729,307
TOTAL LIABILITIES AND MEMBERS’ EQUITY	$	585,935	$	1,346,683
The accompanying notes are an integral part of these financial statements.

TRINITY RIVER ENERGY, LLC

CONSOLIDATED STATEMENT OF OPERATIONS FOR THE YEAR ENDED DECEMBER 31, 2015 AND, COMBINED AND CONSOLIDATED STATEMENT OF OPERATIONS FOR THE YEAR ENDED DECEMBER 31, 2014

(In thousands)

December 31, 2015 December 31, 2014

REVENUES:



Oil, natural gas and natural gas liquids	$172,746	$209,319
Gathering, transportation and marketing	1,462	795
Total revenues	174,208	210,114
OPERATING EXPENSES: Lease operating	95,138	61,935
Workover	4,775	5,183
Gathering, transportation and marketing	32,409	32,193
Production and ad valorem taxes	11,148	9,852
Exploration costs	1,186	1,184
Depreciation, depletion and amortization	103,007	64,171
Impairment of oil and natural gas properties	535,296	123,261
Impairment of equity method investment	-	6,927
General and administrative	39,979	39,028
Total operating expenses	822,938	343,734
OPERATING LOSS	(648,730)	(133,620)
OTHER INCOME (EXPENSE): Interest expense, net of amounts capitalized	(11,837)	(9,983)
Other income—net	601	252
Gain on sale of assets—net	80,725	76
Gain on derivative contracts—net	57,930	75,881
Total other income	127,419	66,226
EQUITY METHOD INVESTMENT INCOME	-	859
LOSS BEFORE INCOME TAX EXPENSE	(521,311)	(66,535)
INCOME TAX EXPENSE	278	-
NET LOSS	(521,589)	(66,535)
NONCONTROLLING INTEREST	14	20
NET LOSS ATTRIBUTABLE TO TRINITY RIVER ENERGY, LLC	$(521,603)	$(66,555)
The accompanying notes are an integral part of these financial statements.

TRINITY RIVER ENERGY, LLC

CONSOLIDATED STATEMENT OF MEMBERS’ EQUITY FOR THE YEAR ENDED DECEMBER 31, 2015 AND, COMBINED AND CONSOLIDATED STATEMENT OF MEMBERS’ EQUITY FOR THE YEAR ENDED DECEMBER 31, 2014

(In thousands)

December 31, 2015 December 31, 2014

BEGINNING BALANCE

$ 729,307 $

452,592



Net loss	(521,589)		(66,535)
Distributions	(17)		(25,351)
Contributions	-		253,690
Payment of shareholder loans (Note 12)	1,686		839
Equity exchanged for companies (Note 5)	-		114,072
ENDING BALANCE	$	209,387	$	729,307
The accompanying notes are an integral part of these financial statements.

TRINITY RIVER ENERGY, LLC

CONSOLIDATED STATEMENT OF CASH FLOWS FOR THE YEAR ENDED DECEMBER 31, 2015 AND, COMBINED AND CONSOLIDATED STATEMENT OF CASH FLOWS FOR THE YEAR ENDED DECEMBER 31, 2014

(In thousands)

CASH FLOWS FROM OPERATING ACTIVITIES:

December 31, 2015 December 31, 2014



Net loss	$	(521,589	)	$	(66,535	)
Adjustments to reconcile net loss to net cash provided
by operating activities:
Depreciation, depletion and amortization	103,007			64,171
Impairment of oil and natural gas properties	535,296			123,261
Impairment of equity method investment	-			6,927
Gain on sale of assets, net	(80,725)			(76)
Unrealized (gain) loss on derivative contracts	44,837			(73,443)
Amortization of deferred financing costs	1,042			2,690
Other operating	(32)			(627)
Changes in assets and liabilities:
Accounts receivable	19,486			5,883
Prepaid and other	(1,380)			2,428
Accounts payable	(16,759)			(3,443)
Accrued liabilities	(7,939)			2,128
Royalties and revenue payable	5,923			(912		)

Net cash provided by operating activities 81,167 62,452

CASH FLOWS FROM INVESTING ACTIVITIES:



Cash acquired in mergers	-		18,129
Proceeds from the sale of assets	148,306		-
Oil and natural gas properties capital expenditures	(11,725)		(45,206)
Other fixed assets capital expenditures	(3,089	)	(809	)

Net cash provided by (used in) investing activities 133,492 (27,886)

CASH FLOWS FROM FINANCING ACTIVITIES:



Issuance of long-term debt	10,000			535,000
Reduction of long-term debt	(222,000)			(805,800)
Deferred financing costs	(108)			(5,156)
Proceeds from payment of shareholder loans	1,686			839
Contributions	-			253,690
Distributions	(17		)	(25,351	)
Net cash used in financing activities	(210,439		)	(46,778	)
NET INCREASE (DECREASE) IN CASH	4,220			(12,212)
CASH AT BEGINNING OF YEAR	3,715			15,927
CASH AT END OF YEAR	$	7,935		$3,715
SUPPLEMENTAL CASH FLOW DISCLOSURES:
Interest paid, net of amounts capitalized	$	10,490		$6,696

NONCASH INVESTING AND FINANCING ACTIVITIES - AT YEAR END:

Capital expenditures included in accrued liabilities

$ 421 $

3,497

The accompanying notes are an integral part of these financial statements.

TRINITY RIVER ENERGY, LLC

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS AS OF AND FOR THE YEARS ENDED DECEMBER 31, 2015 AND 2014

(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.


1.	ORGANIZATION, DESCRIPTION OF OPERATIONS AND BASIS OF PRESENTATION

Organization—We are a Delaware limited liability company formed on September 30, 2014, through a merger 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”) advised by Kohlberg Kravis Roberts & Co. L.P. (together with its affiliates, “KKR”), (collectively, the “Merger”). The Merger effectively combined subsidiaries of KFN NR Investors L.P. (“KFN”), subsidiaries of KKR NR Investors I L.P. (“KNR I”) and subsidiaries of KKR NR Investors I-A L.P. (“KNR I-A”), with Legend Natural Gas II, L.P., Legend Natural Gas

III, L.P. and Legend Natural Gas IV, L.P.

KKR and Riverstone/Carlyle, are private equity investment firms, which, among other things, are engaged in the acquisition and development of oil and gas properties. We have authorized and issued approximately 831 million Class A units, of which investment entities advised by KKR own approximately 77% and Riverstone/Carlyle owns approximately 23%.

Description of Operations—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 in the Barnett Shale in north central Texas and within various formations in south Texas, Louisiana and Mississippi.

Basis of Presentation—The accompanying combined and 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 periods and, in the opinion of management, reflect all adjustments necessary to present fairly the results of the periods 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 30, 2016, the date our financial statements were available to be issued.As a result of the September 30, 2014 Merger, the combined and consolidated financial statements include the accounts of KNR Investors and Legend. For purposes of the December 31, 2014 financial statement presentation, the financial statements of the KNR Investors (the accounting acquirer) are presented at their historical carryover cost basis and the financial statements of Legend are presented at fair value on the date of the Merger. See Note 5 for further information.

KKR had a controlling financial interest in KNR Investors at September 30, 2014, which is represented by:


•	KKR having a controlling financial interest in KNR I and KNR I-A during the nine months ended September 30, 2014.


•	On April 30, 2014, KKR acquired a controlling financial interest in KFN through an acquisition of KKR Financial Holdings LLC, the parent company of KFN. KKR controlled KFN during the five months ended September 30, 2014.

The accompanying combined and consolidated statements of operations, members’ equity and cash flows represent:


•	Combined results of operations of KNR I and KNR I-A for the period January 1, 2014 to April 30, 2014;


•	Combined results of operations of KNR I, KNR I-A and KFN for the period May 1, 2014 to September 30, 2014;


•	Consolidated results of operations of KNR Investors and Legend for the period September 30, 2014 to December 31, 2014 and the twelve months ended December 31, 2015.

Correction of the December 31, 2014 consolidated balance sheet and the related combined and consolidated statements of operations, members’ equity, and cash flows for the year ended December 31, 2014—Subsequent to the issuance of the 2014 combined and consolidated financial statements, certain well locations were specifically identified without recorded asset retirement obligation (“ARO”) liabilities within the 2014 consolidated balance sheet. The unrecorded ARO liabilities also resulted in misstatements in net property and equipment, depreciation, depletion and amortization and impairment of oil and natural gas properties. The prior period amounts within the 2014 consolidated balance sheet, combined and consolidated statement of operations, members’ equity, and cash flows for the year ended December 31, 2014 as shown in the table below have been revised to reflect the correct amounts (in thousands):

Consolidate d Balance She et

Property and equipment:

As of and for the Year Ended December 31, 2014

As Pre viously As

Reported Adjusted

Oil and natural gas properties $ 1,476,870 $ 1,478,681 Less accumulated depreciation, depletion and amortization (288,289) (297,186) Net property and equipment $ 1,191,238 $ 1,184,152

Other noncurrent liabilities:

Asset retirement obligations $ 44,851 $ 46,748

Combine d and Consolidate d State me nt of Ope rations

Operating expenses:



Depreciation, depletion and amortization	$	63,996	$	64,171
Impairment of oil and natural gas properties	114,453		123,261
Total operating expenses	$	334,751	$	343,734

Combine d and Consolidate d State me nt of Membe rs' Equity

Members' Equity:

Net loss $ (57,552) $ (66,535)

Combine d and Consolidate d State me nt of Cash Flows

Cash flows from operating activities:

Use of Estimates—The preparation of these combined and 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 these combined and consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. The most significant estimates pertain to:


•	Oil, natural gas and NGL proved reserves;


•	Expected future cash flows used in determining possible impairments of oil and natural gas properties and the assumptions used in these calculations;


•	Cut-off of production volumes used to calculate the oil and natural gas sales accrual;


•	Valuation of purchase price allocations resulting from business combinations;


•	Mark-to-market valuation of derivative instruments;


•	Asset retirement obligations (“AROs”).

Actual results may differ from our estimates, judgments and assumptions used in the preparation of our combined and consolidated financial statements. See Note 9 for further information.


2.	GOING CONCERN

In connection with the audit of our financial statements for the year ended December 31, 2015, our independent auditors issued their report dated March 30, 2016, that included an explanatory paragraph describing the existence of conditions that raise substantial doubt about our ability to continue as a going concern due to our inability to demonstrate that we will meet our total debt to EBITDAX (earnings before interest, taxes, depreciation, depletion and amortization, and exploration) financial performance covenant contained in our senior secured revolving credit agreement (the “Credit Agreement”) in the fourth quarter of 2016. This could result in an acceleration of the maturity of our debt under the Revolving Credit Facility leading to a possible lack of liquidity, raising substantial doubt about our ability to continue as a going concern. Should this occur, it may be necessary to obtain the approval of our lenders to modify the terms of our Credit Agreement in order to avoid an Event of Default under the Credit Agreement. As no assurance can be given as to our ability to obtain such approval, we have presented the outstanding balance under the Credit Agreement and related deferred financing costs as current on our consolidated balance sheet as of December 31, 2015.

Our available operating cash flow is dependent on production from producing wells, commodity prices and markets in which we sell and the costs associated with operating wells. The substantial decrease in natural gas, NGL and oil prices has resulted in reduced operating revenues which has been mitigated in part by realized gains on commodity derivative contracts. Given the estimated proceeds resulting from gains on derivative contracts, we expect to generate positive operating cash flows in 2016 to fund our business. However, if commodity prices remain low compared to historical prices, we will continue to experience lower operating cash flows as current derivative contracts maturing in the second half of 2016 and 2017 represent a smaller percentage of expected production volumes.

As discussed in Note 7, our Revolving Credit Facility’s borrowing base is subject to re-determination on a semi-annual basis. It is currently unknown what impact the lower commodity price environment will have on our borrowing base. Under the terms of our Credit Agreement, reduction in borrowing base below the then outstanding balance could require us to paydown the difference in up to six equal monthly installments. However, our derivative contracts are in excess of current commodity prices and provide price protection for a significant portion of our 2016 production while also mitigating to some extent the impact that depressed commodity prices have on the redetermination of our borrowing base.

The accompanying consolidated financial statements do not include any adjustments related to the recoverability and classification of recorded assets or the amounts and classification of liabilities that might result from the uncertainty associated with the ability to meet obligations as they come due.

Our Board of Directors and management team continue to take proactive steps to evaluate various initiatives to maintain liquidity and strengthen our financial position during 2016 and beyond.

Additionally, our plans are to conserve cash through 2016 by focusing on reductions in our general and administrative and field operating costs. However, our ability to be successful will depend on various factors, such as commodity prices, the interest of third parties in acquiring our assets, access to financing options, prevailing market conditions and other factors outside of our control.


3.	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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

Accounts Receivable—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 $14.4 million and

$37.1 million at December 31, 2015 and 2014, respectively. 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 $0.7 million and $0.3 million at December 31, 2015 and 2014, respectively.

Asset Retirement Obligations—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 combined and consolidated statement of operations. See Note 10 for further information.

Contingencies—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 can be reasonably estimated. 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 13 for further information.

Concentration of Credit Risk—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 11% and 46% of our revenues for the years ended December 31, 2015 and 2014, respectively. No other purchaser accounted for 10% or more of our revenues for the years ended December 31, 2015 and 2014.

Derivative Contracts—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 sheets 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 combined and consolidated statement of operations.

We are party to various physical commodity contracts for the sale of oil and natural gas 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, 2015 and 2014, we had no past-due receivables from any counterparty. See Notes 8 and 9 for a discussion of the use of financial instruments, management of credit risk inherent in financial instruments and fair value information.

Oil and Natural Gas Properties—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 is $0.1 million and $45.9 million at December 31, 2015 and 2014, respectively. Unproved leases are reviewed annually, and an impairment loss is recorded for any estimated decline in value. The change in unproved property costs between 2014 and 2015 is due primarily to the sale of our Permian assets. See Note 5 for further information. 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 is 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 other income (expense). 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 were $0.6 million and $0.2 million during the twelve months ended December 31, 2015 and 2014, respectively.

Impairment of Oil and Natural Gas Properties—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 9 for further information.

Oil and Natural Gas Reserves—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.

Income Taxes—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 basis 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.

Revenue Recognition—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.

Defined Contribution Plan—We sponsor a 401(k) tax deferred savings plan, whereby we match a portion of our employees’ contributions in cash. Participation in the plan is voluntary and all full-time employees and part-time employees of the Company are eligible to participate. For the years ended December 31, 2015 and 2014, our matching contributions to the 401(k) plan recognized in the combined and consolidated statements of operations were $1.1 million and $0.5 million, respectively.


4.	RECENT ACCOUNTING PRONOUNCEMENTS

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. The new guidance did not have a material impact 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. ASU 2014-09 will be effective for the Company beginning on January 1, 2019 considering the one year deferral provided by ASU 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date. The standard permits the use of either the retrospective or cumulative effect transition method and early adoption is permitted. The Company has not selected a transition method and is evaluating the impact this standard will have on its consolidated financial statements and related disclosures.

In August, 2014, the FASB issued ASU 2014-15, 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 April 2015, the FASB issued ASU 2015-03, Simplifying the Presentation of Debt Issuance costs. This guidance does not address the presentation of issuance costs associated with revolving debt arrangements. In August 2015, the FASB issued ASU No. 2015-15, Presentation and Subsequent Measurement of Debt Issuance Costs with Line-of-Credit Arrangements. This guidance codifies the SEC’s position not to object to an entity deferring and presenting debt issuance costs as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. ASU 2015-03 and ASU 2015-15 are effective for fiscal years beginning after December 15, 2015. Early adoption is permitted and the guidance should be applied retrospectively to all prior year periods presented. We adopted ASU 2015-15 for the consolidated balance sheets included herein. Debt issuance costs of $4.0 million and $4.9 million on the Revolving Credit Facility are presented as a current asset in "deferred financing costs, net" in the consolidated balance sheet as of December 31, 2015 and as a noncurrent asset in "deferred financing costs, net" in the consolidated balance sheet as of December 31, 2014, respectively, and will continue to be amortized over the term of the arrangement.

On February 25, 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842). The new guidance introduces a lessee model that brings most leases on the balance sheet and eliminates the required use of bright-line tests in current GAAP for determining lease classification. The scope of the new guidance is limited to leases of property, plant and equipment and excludes leases to explore for or use minerals, oil, natural gas, and similar nonregenerative resources. The new standard is effective for calendar periods beginning on January 1, 2019, for public business entities and January 1, 2020, for all other entities. We are currently evaluating the impact of the adoption of this ASU on our consolidated financial statements.


5.	BUSINESS ACQUISITIONS AND DISPOSITIONS

Business Acquisitions—On April 30, 2014, KKR acquired all of the outstanding common shares of KKR Financial Holdings LLC, the parent company of KFN, in an exchange of equity. The transaction was recorded under the acquisition method of accounting by KKR and pushed down to KFN by allocating the total purchase consideration to the cost of the assets purchased and the liabilities assumed based on their estimated fair values at the date of the transaction. No goodwill or bargain purchase resulted for KFN from the application of purchase accounting. The following table summarizes the preliminary fair value assessment of the assets acquired and liabilities assumed as of the acquisition date (in thousands):



Cash	$2,874
Accounts receivable—net	7,470
Derivative assets	2,850
Oil and natural gas properties	174,000
Other assets	536
Accounts payable and accrued liabilities	(8,092)
Derivative liabilities	(3,970)
Long-term debt	(54,489)
Asset retirement obligations	(7,281)
Other liabilities	(105)
Total equity consideration transferred	$113,793

We own an equity interest in Bluebonnet Gathering, LLC (“Bluebonnet”), a regulated pipeline servicing our Barnett Shale wells. Prior to the KFN acquisition, the investment was accounted for under the equity method. In connection with the KFN acquisition, we obtained control of Bluebonnet and changed our accounting method to full consolidation. As a result of the change in accounting method, we recorded a loss of $6.9 million for the year ended December 31, 2014.

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 $617.0 million in exchange for oil and natural gas properties and other assets of approximately that amount. In connection with the Merger, we incurred acquisition and transition-related costs of approximately $7.3 million in 2014 and approximately $14.4 million in 2015, which are included in general and administrative expenses in the accompanying combined and consolidated statements of operations. The following table summarizes the

fair value assessment of the contributed assets and liabilities assumed as of the acquisition date (in thousands):



Assets Acquired
Cash	$13,919
Accounts receivable—net	22,456
Derivative assets	22,189
Oil and natural gas properties, as adjusted	555,687
Other fixed assets	1,617
Other assets	1,109
Total identifiable net assets	$616,977
Liabilitie s Assumed
Long-term debt	$(551,000)
Accounts payable and accrued liabilities	(50,184)
Derivative liabilities	(1,788)
Asset retirement obligations, as adjusted	(13,365)
Other liabilities	(640)
Total identifiable net liabilities	$(616,977)

Dispositions— On September 1, 2015, we completed a sale of our Permian assets to an unaffiliated third party for $148.3 million in cash net of selling expenses of $0.5 million. We recorded a net gain of

$80.6 million, included in gain on sale of assets, net on our combined and consolidated statement of operations. The net book value of the assets sold was $67.7 million. Our Permian assets contributed to

$8.5 million of net income for the eight months ended September 1, 2015.


6.	RELATED-PARTY TRANSACTIONS

Other Transactions—Members of the management team have minority ownership interests in companies which provide oilfield services to us. We have contracts with the oilfield service vendors and have implemented controls surrounding the purchase and approval for such services. For the year ended December 31, 2015, we paid these vendors approximately $1.8 million. Additionally, we owed $0.3 million in outstanding payables to these vendors as of December 31, 2015.


7.	LONG-TERM DEBT

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 $360.0 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,

2015, the amount outstanding under the credit agreement was $274.0 million and the amount available for borrowing was $86.0 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 twelve months ended December 31, 2015, was 2.44%.

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, 2015, we were in compliance with all of our covenants under the credit agreement. As a result of substantially lower commodity prices, there is no assurance that we will be able to comply with all of the required covenants for the remainder of 2016 and as such have classified all of our outstanding debt as current on the consolidated balance sheet for the year ended December 31, 2015.

Deferred Financing Costs—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 were $1.0 million and $2.7 million for the years ended December 31, 2015 and 2014, respectively.


8.	FINANCIAL INSTRUMENTS

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.

Commodity Derivative Contracts—As of December 31, 2015 and 2014, we had natural gas swap contracts based on West Texas hub (WAHA) and Henry Hub (“HH”) index prices and oil swap contracts and natural gas swap contracts based on the New York Mercantile Exchange (“NYMEX”) futures index. The fair values, notional quantities and weighted-average swap prices of these contracts as of December 31, 2015, are summarized in the table below.

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

Natural Gas Swap Contracts (MMBtu):

Total Weighted- Fair


Remaining	Average Value Volumes Swap Price (In thousands)

2016 30,971,000 4.13 $ 51,132



2017 7,259,000			4.17	9,627
Total natural gas 38,230,000				60,759
Oil Swap Contracts (Bbls):	2016	177,000	67.64	4,617
	2017	13,000	82.30	472
Total oil		190,000		5,089
Basis Swap Contracts: Natural gas (MMBtu)	2016	14,160,000	(0.10)	454
Natural gas (MMBtu)	2017	12,751,000	(0.100)	6
Oil (Bbls)	2016	63,000	1.21	(6)
				454
Total oil, natural gas, and basis	contracts			$66,302

Interest Rate Derivative Contracts—The following table summarizes the fair value, notional amount and swap rate of the interest rate swap contracts in place at December 31, 2015:



Type	Effective Date	Maturity Date	LIBOR	Notional Amount (In thousands)		Fair Value (In thousands)
Swap	January 2, 2015	June 1, 2023	3.1107%	$	71,000	$(6,049)
Swap	January 2, 2015	December 1, 2019	2.4487%	13,000		(513)
Swap	January 2, 2015	December 1, 2021	2.8593%	13,000		(856)
Swap	January 2, 2015	June 1, 2023	3.1107%	9,000		(767)
Swap	January 2, 2015	December 1, 2021	2.8593%	2,000		(132)
Swap	January 2, 2015	December 1, 2019	2.4487%	2,000		(79)
						$(8,396)

We have not designated any of our derivative contracts as hedging instruments.

Our derivative contracts are subject to master netting arrangements and are presented on a net basis in our consolidated balance sheets. The following table summarizes the location and fair value of our derivative contracts as of December 31, 2015 and 2014 (in thousands):



	December 31, 2015
		Gross	Less Gross	Net
		Amounts	Amounts of	Amounts
Derivative Contracts	Balance Sheet Classification	Recognized	Offset	Recognized
Derivative assets:
Commodity swaps	Derivative contracts—current	$56,287	$90	$56,197
Commodity swaps	Derivative contracts—non-current	10,105		10,105
		$ 66,392	$ 90	$ 66,302
Derivative liabilities:
Interest rate swaps	Derivative contracts—current	$964	$ -	$964
Interest rate swaps	Derivative contracts—non-current	7,432		7,432

$ 8,396

$ -

$ 8,396

December 31, 2014

Gross Less Gross Net Amounts Amounts of Amounts

Derivative Contracts Balance Sheet Classification Recognized Offset 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 statements of operations for the years ended December 31, 2015 and 2014 (in thousands):

Location of Gain Recognized in

Amound of Gain (Loss) Recognized in Net Loss

Commodity swaps:

Other Income (Expense) 2015 2014

Realized Gain on derivative contracts—net

$ 104,710

$ 3,155

Unrealized Gain on derivative contracts—net (43,168) 81,702 Interest rate swaps:



Realized	Gain on derivative contracts—net	(1,943)	(717)
Unrealized	Gain on derivative contracts—net	(1,669)	(8,259)

Total realized and unrealized gain on derivative contracts

$ 57,930

$ 75,881


9.	FAIR VALUE MEASUREMENTS

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:


•	Level 1: Inputs based on quoted market prices in active markets for identical assets or liabilities at the measurement date.


•	Level 2: Inputs based on quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets and liabilities in markets that are not active or other inputs that are observable and can be corroborated by observable market data.


•	Level 3: Inputs that reflect management’s best estimates and assumptions of what market participants would use in pricing the asset or liability at the measurement date. The inputs are unobservable in the market and significant to the valuation of the instruments.

Changes in economic conditions or model-based valuation techniques may require the transfer of financial instruments from one fair value level to another. In such instances, the transfer would be reported at the beginning of the period in which the change occurs.

Recurring Fair Value Measurements—Our financial assets and liabilities that were accounted for at fair value on a recurring basis at December 31, 2015 and 2014 are as follows (in thousands):

Assets—commodity derivative

December 31, 2015

Level 1 Level 2 Level 3 Total

contracts

Liabilities—interest rate derivative

$ - $

66,302 $ -

$ 66,302

contracts 8,396 8,396

Assets—commodity derivative

December 31, 2014

Level 1 Level 2 Level 3 Total

contracts

Liabilities—interest rate derivative

$ - $ 109,470 $ -

$ 109,470

contracts 6,727 6,727

Our derivative contracts consist of swaps for oil, natural gas, natural gas basis, 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 10.

Nonrecurring Fair Value Measurements—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 years ended December 31, 2015 and 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 $535.3 million and $123.3 million, respectively. 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.

Other Fair Value Measurements—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.


10.	ASSET RETIREMENT OBLIGATIONS

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 years ended December 31, 2015 and 2014 are presented in the table below (in thousands):

2015 2014

Beginning balance—January 1

$ 47,201 $

25,875



Additions	-	211
Acquisitions	-	20,646
Liabilities settled and divested (a)	(2,139)	(584)
Accretion expense	1,790	1,270
Revision of estimates (b)	(8,255)	(217)
Ending balance—December 31	38,597	47,201
Less current portion	(322)	(453)
Long-term asset retirement obligation	$38,275	$46,748


(a)	Includes a decrease in ARO due to the sale of the Permian assets of approximately $1.8 million.


(b)	During 2015, TRE revised its ARO by $8.3 million primarily due to an overall decrease in TRE’s abandonment cost estimates.

The amount of the obligation expected to be incurred in the upcoming year is included in accrued liabilities in our consolidated balance sheets.


11.	INCOME TAXES

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, 2015 and 2014, we recorded a long-term deferred tax asset of $3.4 million and $2.8 million, respectively, and a valuation allowance of the same amount, due to low probability of realization.


12.	MEMBERS’ EQUITY

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. During the years ended December 31, 2015 and 2014, we distributed $17,000 and $25.3 million, respectively, of available cash to our members.

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 were $1.7 million as of December 31, 2014 and presented net within members’ equity. No remaining payments are outstanding on loans from officers at December 31, 2015.


13.	COMMITMENTS AND CONTINGENCIES

Commitments—We lease office space under operating leases in Houston, Texas, and Fort Worth, Texas, and rent expense related to these lease agreements was $2.2 million and $1.1 million for the years ended December 31, 2015 and 2014, respectively.

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.

The future minimum payments related to these contracts as of December 31, 2015, are presented in the table below (in thousands):



Year	Office Lease		Transportation	Total
2016	$	1,857	$1,997	$3,854
2017	1,889		1,007	2,896
2018	1,928		986	2,914
2019	1,969		175	2,144
2020	2,010		-	2,010
Thereafter	7,081		-	7,081
Total	$	16,734	$4,165	$20,899

Contingencies—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.