10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

________________________________________________________

FORM 10-Q

________________________________________________________

(Mark One)

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

For the quarterly period ended September 30, 2016 

or

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

For the transition period from to

Commission file number: 1-13283

PENN VIRGINIA CORPORATION

(Exact name of registrant as specified in its charter)

__________________________________________________________

Virginia	23-1184320
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification Number)

14701 ST. MARY'S LANE, SUITE 275

HOUSTON, TX 77079

(Address of principal executive offices) (Zip Code)

(713) 722-6500

(Registrant’s telephone number, including area code)

FOUR RADNOR CORPORATE CENTER, SUITE 200

100 MATSONFORD RD

RADNOR, PA 19087

(Former name, former address and former fiscal year, if changed since last report)

__________________________________________________________

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ý  No  ¨

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

Large accelerated filer	o	Accelerated filer	ý
Non-accelerated filer	o	Smaller reporting company	ý

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

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court.    Yes  ý No  ¨

 As of November 14, 2016, 14,992,018 shares of common stock of the registrant were outstanding.

PENN VIRGINIA CORPORATION

QUARTERLY REPORT ON FORM 10-Q

 For the Quarterly Period Ended September 30, 2016

Table of Contents

Part I - Financial Information
Item		Page
1.	Financial Statements:
	Condensed Consolidated Statements of Operations	3
	Condensed Consolidated Statements of Comprehensive Income	5
	Condensed Consolidated Balance Sheets	6
	Condensed Consolidated Statements of Cash Flows	7
	Notes to Condensed Consolidated Financial Statements:
	1. Nature of Operations	8
	2. Basis of Presentation	8
	3. Chapter 11 Proceedings and Emergence	9
	4. Fresh Start Accounting	11
	5. Accounts Receivable and Major Customers	16
	6. Derivative Instruments	16
	7. Property and Equipment	18
	8. Debt Obligations	19
	9. Income Taxes	20
	10. Exit Activities	20
	11. Additional Balance Sheet Detail	21
	12. Fair Value Measurements	22
	13. Commitments and Contingencies	23
	14. Shareholders’ Equity	24
	15. Share-Based Compensation and Other Benefit Plans	25
	16. Interest Expense	26
	17. Earnings per Share	27
Forward-Looking Statements		28
2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations:
	Overview and Executive Summary	30
	Key Developments	31
	Financial Condition	34
	Results of Operations	38
	Critical Accounting Estimates	46
4.	Controls and Procedures	47
Part II - Other Information
1.	Legal Proceedings	48
1A.	Risk Factors
2.	Unregistered Sales of Equity Securities	50
3.	Defaults Upon Senior Securities	50
6.	Exhibits	51
Signatures		52

Part I. FINANCIAL INFORMATION

Item 1. Financial Statements

PENN VIRGINIA CORPORATION

(DEBTOR-IN-POSSESSION MAY 12, 2016 THROUGH SEPTEMBER 12, 2016)

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS – unaudited

(in thousands, except per share data)

	Successor			Predecessor
	Period From			Period From
	September 13, 2016 Through			July 1, 2016 Through			Three Months Ended
	September 30, 2016			September 12, 2016			September 30, 2015
Revenues
Crude oil	$	5,508		$	23,392		$	51,124
Natural gas liquids	333			1,680			3,254
Natural gas	475			1,889			6,312
Gain on sales of property and equipment, net	—			504			50,828
Other, net	33			(804		)	466
Total revenues	6,349			26,661			111,984
Operating expenses
Lease operating	756			4,209			11,304
Gathering, processing and transportation	576			4,767			5,654
Production and ad valorem taxes	375			574			3,483
General and administrative	1,476			12,181			9,416
Exploration	—			4,641			1,673
Depreciation, depletion and amortization	2,029			8,024			76,850
Total operating expenses	5,212			34,396			108,380
Operating income (loss)	1,137			(7,735		)	3,604
Other income (expense)
Interest expense	(218		)	(1,363		)	(22,985		)
Derivatives	(4,369		)	8,934			44,701
Other	9			(2,154		)	(44		)
Reorganization items, net	—			1,152,373			—
Income (loss) before income taxes	(3,441		)	1,150,055			25,276
Income tax benefit	—			—			624
Net income (loss)	(3,441		)	1,150,055			25,900
Preferred stock dividends	—			—			(5,935		)
Net income (loss) attributable to common shareholders	$	(3,441	)	$	1,150,055		$	19,965
Net income (loss) per share:
Basic	$	(0.23	)	$	12.88		$	0.27
Diluted	$	(0.23	)	$	10.32		$	0.25
Weighted average shares outstanding – basic	14,992			89,292			72,651
Weighted average shares outstanding – diluted	14,992			111,458			103,452

See accompanying notes to condensed consolidated financial statements.

3

PENN VIRGINIA CORPORATION

(DEBTOR-IN-POSSESSION MAY 12, 2016 THROUGH SEPTEMBER 12, 2016)

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS – unaudited

(in thousands, except per share data)

	Successor			Predecessor
	Period From			Period From
	September 13, 2016 Through			January 1, 2016 Through			Nine Months Ended
	September 30, 2016			September 12, 2016			September 30, 2015
Revenues
Crude oil	$	5,508		$	81,377		$	180,964
Natural gas liquids	333			6,064			13,841
Natural gas	475			6,208			22,143
Gain on sales of property and equipment, net	—			1,261			50,803
Other, net	33			(600		)	2,376
Total revenues	6,349			94,310			270,127
Operating expenses
Lease operating	756			15,626			33,780
Gathering, processing and transportation	576			13,235			19,535
Production and ad valorem taxes	375			3,490			13,139
General and administrative	1,476			38,945			32,865
Exploration	—			10,288			11,922
Depreciation, depletion and amortization	2,029			33,582			253,056
Impairments	—			—			1,084
Total operating expenses	5,212			115,166			365,381
Operating income (loss)	1,137			(20,856		)	(95,254		)
Other income (expense)
Interest expense	(218		)	(58,018		)	(68,021		)
Derivatives	(4,369		)	(8,333		)	52,073
Other	9			(3,184		)	(586		)
Reorganization items, net	—			1,144,993			—
Income (loss) before income taxes	(3,441		)	1,054,602			(111,788		)
Income tax benefit	—			—			394
Net income (loss)	(3,441		)	1,054,602			(111,394		)
Preferred stock dividends	—			(5,972		)	(18,069		)
Net income (loss) attributable to common shareholders	$	(3,441	)	$	1,048,630		$	(129,463	)
Net income (loss) per share:
Basic	$	(0.23	)	$	11.91		$	(1.79	)
Diluted	$	(0.23	)	$	8.50		$	(1.79	)
Weighted average shares outstanding – basic	14,992			88,013			72,438
Weighted average shares outstanding – diluted	14,992			124,087			72,438

See accompanying notes to condensed consolidated financial statements.

4

PENN VIRGINIA CORPORATION

(DEBTOR-IN-POSSESSION MAY 12, 2016 THROUGH SEPTEMBER 12, 2016)

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME – unaudited

(in thousands) 

	Successor			Predecessor
	Period From			Period From
	September 13, 2016 Through			July 1, 2016 Through			Three Months Ended
	September 30, 2016			September 12, 2016			September 30, 2015
Net income (loss)	$	(3,441	)	$	1,150,055		$	25,900
Other comprehensive loss:
Change in pension and postretirement obligations, net of tax of $(6) in 2015	—			(383		)	(11		)
	—			(383		)	(11		)
Comprehensive income (loss)	$	(3,441	)	$	1,149,672		$	25,889

	Successor			Predecessor
	Period From			Period From
	September 13, 2016 Through			January 1, 2016 Through			Nine Months Ended
	September 30, 2016			September 12, 2016			September 30, 2015
Net income (loss)	$	(3,441	)	$	1,054,602		$	(111,394	)
Other comprehensive loss:
Change in pension and postretirement obligations, net of tax of $(17) in 2015	—			(421		)	(32		)
	—			(421		)	(32		)
Comprehensive income (loss)	$	(3,441	)	$	1,054,181		$	(111,426	)

See accompanying notes to condensed consolidated financial statements.

5

PENN VIRGINIA CORPORATION

(DEBTOR-IN-POSSESSION MAY 12, 2016 THROUGH SEPTEMBER 12, 2016)

CONDENSED CONSOLIDATED BALANCE SHEETS – unaudited

(in thousands, except share data)

	Successor			Predecessor
	As of			As of
	September 30,			December 31,
	2016			2015
Assets
Current assets
Cash and cash equivalents	$	13,994		$	11,955
Accounts receivable, net of allowance for doubtful accounts	32,137			47,965
Derivative assets	446			97,956
Other current assets	3,518			7,104
Total current assets	50,095			164,980
Property and equipment, net	251,200			344,395
Other assets	5,571			8,350
Total assets	$	306,866		$	517,725
Liabilities and Shareholders’ Equity (Deficit)
Current liabilities
Accounts payable and accrued liabilities	$	45,432		$	103,525
Derivative liabilities	3,888			—
Current portion of long-term debt, net of unamortized issuance costs	—			1,224,383
Total current liabilities	49,320			1,327,908
Other liabilities	4,451			104,938
Derivative liabilities	11,291			—
Long-term debt	54,350			—
Commitments and contingencies (Note 13)
Shareholders’ equity (deficit):
Predecessor preferred stock of $100 par value – 100,000 shares authorized; Series A – 3,915 shares issued as of December 31, 2015 and Series B – 27,551 issued as of December 31, 2015, each with a redemption value of $10,000 per share	—			3,146
Predecessor common stock of $0.01 par value – 228,000,000 shares authorized; 81,252,676 shares issued as of December 31, 2015	—			628
Predecessor paid-in capital	—			1,211,088
Predecessor deferred compensation obligation	—			3,440
Predecessor accumulated other comprehensive income	—			422
Predecessor treasury stock – 455,689 shares of common stock, at cost, as of December 31, 2015,	—			(3,574		)
Successor preferred stock of $0.01 par value – 5,000,000 shares authorized; none issued	—			—
Successor common stock of $0.01 par value – 45,000,000 shares authorized; 14,992,018 shares issued as of September 30, 2016	150			—
Successor paid-in capital	190,745			—
Accumulated deficit	(3,441		)	(2,130,271		)
Total shareholders’ equity (deficit)	187,454			(915,121		)
Total liabilities and shareholders’ equity (deficit)	$	306,866		$	517,725

See accompanying notes to condensed consolidated financial statements.

6

PENN VIRGINIA CORPORATION

(DEBTOR-IN-POSSESSION MAY 12, 2016 THROUGH SEPTEMBER 12, 2016)

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS – unaudited

(in thousands)

	Successor			Predecessor
	Period From			Period From
	September 13, 2016 Through			January 1, 2016 Through			Nine Months Ended
	September 30, 2016			September 12, 2016			September 30, 2015
Cash flows from operating activities
Net income (loss)	$	(3,441	)	$	1,054,602		$	(111,394	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Non-cash reorganization items	—			(1,178,302		)	—
Depreciation, depletion and amortization	2,029			33,582			253,056
Impairments	—			—			1,084
Accretion of firm transportation obligation	—			317			705
Derivative contracts:
Net losses (gains)	4,369			8,333			(52,073		)
Cash settlements, net	—			48,008			104,590
Deferred income tax expense	—			—			266
Gain on sales of assets, net	—			(1,261		)	(50,803		)
Non-cash exploration expense	—			6,038			4,903
Non-cash interest expense	38			22,189			3,504
Share-based compensation (equity-classified)	—			1,511			3,369
Other, net	—			(13		)	(17		)
Changes in operating assets and liabilities, net	585			35,243			5,051
Net cash provided by operating activities	3,580			30,247			162,241
Cash flows from investing activities
Capital expenditures	—			(15,359		)	(324,876		)
Proceeds from sales of assets, net	—			224			73,670
Other, net	—			1,186			—
Net cash used in investing activities	—			(13,949		)	(251,206		)
Cash flows from financing activities
Proceeds from revolving credit facility borrowings	—			75,350			203,000
Repayment of revolving credit facility borrowings	(21,000		)	(119,121		)	(98,000		)
Debt issuance costs paid	—			(3,011		)	(744		)
Proceeds received from rights offering, net	—			49,943			—
Dividends paid on preferred stock	—			—			(18,201		)
Net cash (used in) provided by financing activities	(21,000		)	3,161			86,055
Net (decrease) increase in cash and cash equivalents	(17,420		)	19,459			(2,910		)
Cash and cash equivalents – beginning of period	31,414			11,955			6,252
Cash and cash equivalents – end of period	$	13,994		$	31,414		$	3,342
Supplemental disclosures:
Cash paid for:
Interest	$	—		$	4,331		$	47,489
Income taxes paid (refunds received)	$	—		$	(35	)	$	7
Reorganization items, net	$	—		$	30,990		$	—
Non-cash investing and financing activities:
Common stock issued in exchange for liabilities	$	—		$	140,952		$	—
Changes in accrued liabilities related to capital expenditures	$	—		$	(11,301	)	$	(41,800	)
Derivatives settled to reduce outstanding debt	$	—		$	51,979		$	—

See accompanying notes to condensed consolidated financial statements.

7

PENN VIRGINIA CORPORATION

(DEBTOR-IN-POSSESSION MAY 12, 2016 THROUGH SEPTEMBER 12, 2016)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – unaudited

For the Quarterly Period Ended September 30, 2016

(in thousands, except per share amounts or where otherwise indicated)

1.  Nature of Operations

Penn Virginia Corporation (together with its consolidated subsidiaries, unless the context otherwise requires, “Penn Virginia,” the “Company,” “we,” “us” or “our”) is an independent oil and gas company engaged in the onshore exploration, development and production of oil, natural gas liquids (“NGLs”) and natural gas. Our current operations consist primarily of drilling unconventional horizontal development wells and operating our producing wells in the Eagle Ford Shale (the “Eagle Ford”) in South Texas. Our operations are substantially concentrated with over 90 percent of our production, revenues and capital expenditures being attributable to this region. We also have less significant operations in Oklahoma, primarily non-operated properties in the Granite Wash. In August 2016, we terminated our remaining operations in the Marcellus Shale in Pennsylvania and are currently in the process of remediating the sites of our former wells in that region.

2. Basis of Presentation

Our unaudited Condensed Consolidated Financial Statements include the accounts of Penn Virginia and all of our subsidiaries. Intercompany balances and transactions have been eliminated. Our Condensed Consolidated Financial Statements have been prepared in conformity with accounting principles generally accepted in the United States of America (“U.S. GAAP”). Preparation of these statements involves the use of estimates and judgments where appropriate. In the opinion of management, all adjustments, consisting of normal recurring accruals, considered necessary for a fair presentation of our Condensed Consolidated Financial Statements have been included. Our Condensed Consolidated Financial Statements should be read in conjunction with the Consolidated Financial Statements and Notes included in our Annual Report on Form 10-K for the year ended December 31, 2015. Operating results for the nine months ended September 30, 2016, are not necessarily indicative of the results that may be expected for the year ending December 31, 2016. Certain amounts for the corresponding 2015 periods have been reclassified to conform to the current year presentation. These reclassifications have no impact on our previously reported results of operations, balance sheets or cash flows.

Management has evaluated all of our activities through the issuance date of our Condensed Consolidated Financial Statements and has concluded that no subsequent events have occurred that would require recognition in our Condensed Consolidated Financial Statements or disclosure in the Notes thereto.

Comparability of Financial Statements to Prior Periods

As discussed in further detail in Note 4 below, we have adopted and applied the relevant guidance provided in U.S. GAAP with respect to the accounting and financial statement disclosures for entities that have emerged from bankruptcy proceedings (“Fresh Start Accounting”). Accordingly, our Condensed Consolidated Financial Statements and Notes after September 12, 2016, are not comparable to the Condensed Consolidated Financial Statements and Notes prior to that date. To facilitate our financial statement presentations, we refer to the reorganized company in these Condensed Consolidated Financial Statements and Notes as the “Successor” for periods subsequent to September 12, 2016, and “Predecessor” for periods prior to September 13, 2016. Furthermore, our Condensed Consolidated Financial Statements and Notes have been presented with a “black line” division to delineate the lack of comparability between the Predecessor and Successor. In addition, and as referenced in Note 7 below, we have adopted the full cost method of accounting for our oil and gas properties effective with our adoption of Fresh Start Accounting. Accordingly, our results of operations and financial position for the Successor periods will be substantially different from our historic trends.

We have applied the relevant guidance provided in U.S. GAAP with respect to the accounting and financial statement disclosures for entities that have filed petitions with the bankruptcy court and expect to reorganize as going concerns in preparing our Condensed Consolidated Financial Statements and Notes through the period ended September 12, 2016, or Predecessor periods. That guidance requires that, for periods subsequent to our bankruptcy filing on May 12, 2016, or post-petition periods, certain transactions and events that were directly related to our reorganization be distinguished from our normal business operations. Accordingly, certain revenues, expenses, realized gains and losses and provisions that were realized or incurred in the bankruptcy proceedings have been included in “Reorganization items, net” on our Condensed Consolidated Statement of Operations for the period ended September 12, 2016. In addition, certain liabilities and other obligations incurred prior to May 12, 2016, or pre-petition periods, have been classified in “Liabilities subject to compromise” on our Predecessor Condensed Consolidated Balance Sheet through September 12, 2016. Further detail for our “Reorganization items, net” and “Liabilities subject to compromise” are provided in Note 4 below.

8

Going Concern Presumption

Our unaudited Condensed Consolidated Financial Statements for the Successor periods have been prepared on a going concern basis, which contemplates the realization of assets and the satisfaction of liabilities and other commitments in the normal course of business. As referenced in Note 3 below, we operated as a “debtor-in-possession” through September 12, 2016, during which time there was inherent doubt as to our ability to continue as a going concern.

Recently Adopted Accounting Pronouncements

In March 2016, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”)2016–09, Improvements to Employee Share-based Payment Accounting (“ASU 2016–09”), which simplifies the accounting for share-based compensation. The areas for simplification that are applicable to publicly-held companies are as follows: (i) Accounting for Income Taxes, (ii) Classification of Excess Tax Benefits on the Statement of Cash Flows, (iii) Forfeitures, (iv) Minimum Statutory Tax Withholding Requirements and (v) Classification of Employee Taxes Paid on the Statement of Cash Flows when an employer withholds shares for tax-withholding purposes. The effective date of ASU 2016–09 is January 1, 2017, with early adoption permitted. We adopted ASU 2016–09 on September 12, 2016 effective upon our emergence from bankruptcy. As of September 30, 2016, we did not have any awards issued in the form of share-based compensation. Accordingly, the adoption of ASU 2016–09 had no impact on our Condensed Consolidated Financial Statements and Notes.

Recently Issued Accounting Pronouncements

In June 2016, the FASB issued ASU 2016–13, Measurement of Credit Losses on Financial Instruments (“ASU 2016–13”), which changes the recognition model for the impairment of financial instruments, including accounts receivable, loans and held-to-maturity debt securities, among others. ASU 2016–13 is required to be adopted using the modified retrospective method by January 1, 2020, with early adoption permitted. ASU 2016–13 will have applicability to our accounts receivable portfolio, particularly those receivables attributable to our joint interest partners. At this time, we do not anticipate that the adoption of ASU 2016–13 will have a significant impact on our Consolidated Financial Statements and related disclosures; however, we are currently in the early stages of evaluating the requirements and the period for which we will adopt the standard.

In February 2016, the FASB issued ASU 2016–02, Leases (“ASU 2016–02”), which will require organizations that lease assets to recognize on the balance sheet the assets and liabilities for the rights and obligations created by those leases with terms of more than twelve months. Consistent with current U.S. GAAP, the recognition, measurement, and presentation of expenses and cash flows arising from a lease by a lessee primarily will depend on its classification as a finance or operating lease. ASU 2016–02 also will require disclosures regarding the amount, timing, and uncertainty of cash flows arising from leases. The effective date of ASU 2016–02 is January 1, 2019, with early adoption permitted. We are continuing to evaluate the effect that ASU 2016–02 will have on our Consolidated Financial Statements and related disclosures as well as the period for which we will adopt the standard. We believe that ASU 2016–02 will likely be applicable to our oil and natural gas gathering commitment arrangements as described in Note 13, our existing leases for office facilities and certain office equipment and potentially to certain drilling rig contracts with terms in excess of twelve months.

In May 2014, the FASB issued ASU 2014–09, Revenues from Contracts with Customers (“ASU 2014–09”), which requires an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. ASU 2014–09 will replace most existing revenue recognition guidance in U.S. GAAP when it becomes effective on January 1, 2018. The standard permits the use of either the retrospective or cumulative effect transition method upon adoption. While traditional commodity sales transactions, property conveyances and joint interest arrangements in the oil and gas industry are not expected to be significantly impacted by ASU 2014–09, natural gas imbalances and other non-product revenues, including our ancillary marketing, gathering and transportation and water service revenues could be affected. Accordingly, we are continuing to evaluate the effect that ASU 2014–09 will have on our Consolidated Financial Statements and related disclosures, with a more focused analysis on these other revenue sources. We have not yet selected a transition method nor have we determined the period for which we will adopt the new standard.

3. Chapter 11 Proceedings and Emergence

On May 12, 2016 (the “Petition Date”), we and eight of our subsidiaries (the “Chapter 11 Subsidiaries”) filed voluntary petitions (In re Penn Virginia Corporation, et al, Case No. 16-32395) seeking relief under Chapter 11 of Title 11 of the United States Bankruptcy Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Eastern District of Virginia (the “Bankruptcy Court”).

On August 11, 2016 (the “Confirmation Date”), the Bankruptcy Court confirmed our Second Amended Joint Chapter 11 Plan of Reorganization of Penn Virginia Corporation and its Debtor Affiliates (the “Plan”), and we subsequently emerged from bankruptcy on September 12, 2016 (the “Effective Date”).

9

Debtors-In-Possession. From the Petition Date through the Effective Date, we and the Chapter 11 Subsidiaries operated our business as debtors-in-possession in accordance with the applicable provisions of the Bankruptcy Code. The Bankruptcy Court granted all “first day” motions filed by us and the Chapter 11 Subsidiaries, which were designed primarily to minimize the impact of the Chapter 11 proceedings on our normal day-to-day operations, our customers, regulatory agencies, including taxing authorities, and employees. As a result, we were able to conduct normal business activities and pay all associated obligations for the post-petition period and we were also authorized to pay and have paid (subject to limitations applicable to payments of certain pre-petition obligations) pre-petition employee wages and benefits, pre-petition amounts owed to certain lienholders, amounts due to taxing authorities for production and other related taxes and funds belonging to third parties, including royalty and working interest holders.

Pre-Petition Agreements. Immediately prior to the Petition Date, the holders (the “Ad Hoc Committee”) of approximately 86 percent of the $1,075 million principal amount of our 7.25% Senior Notes due 2019 (the “2019 Senior Notes”) and 8.50% Senior Notes due 2020 (the “2020 Senior Notes” and, together with the 2019 Senior Notes, the “Senior Notes”) agreed to a restructuring support agreement (the “RSA”) that set forth the general framework of the Plan and the timeline for the Chapter 11 proceedings. In addition, we entered into a backstop commitment agreement (the “Backstop Commitment Agreement”) with the parties thereto (collectively, the “Backstop Parties”), pursuant to which the Backstop Parties committed to provide a $50.0 million commitment to backstop a rights offering (the “Rights Offering”) that was conducted in connection with the Plan.

Plan of Reorganization. Pursuant to the terms of the Plan, which was supported by us, the holders (the “RBL Lenders”) of 100 percent of the claims attributable to our pre-petition revolving credit agreement (as amended, the “RBL”), the Ad Hoc Committee and the Official Committee of Unsecured Claimholders (the “UCC”), the following transactions were completed subsequent to the Confirmation Date and prior to or at the Effective Date:

• the approximately $1,122 million of indebtedness, including accrued interest, attributable to our Senior Notes and certain other unsecured claims were exchanged for 6,069,074 shares representing 41 percent of the Successor’s common stock (“New Common Stock”);

• a total of $50 million of proceeds were received on the Effective Date from the Rights Offering resulting in the issuance of 7,633,588 shares representing 51 percent of New Common Stock to holders of claims arising under the Senior Notes, certain holders of general unsecured claims and to the Backstop Parties;

• the Backstop Parties received a backstop fee comprised of 472,902 shares representing three percent of New Common Stock;

• an additional 816,454 shares representing five percent of New Common Stock were authorized for disputed general unsecured claims and non-accredited investor holders of the Senior Notes and 749,600 shares representing five percent of the New Common Stock outstanding were reserved for issuance under a new management incentive plan;

• on the Effective Date, we entered into a shareholders agreement and a registration rights agreement and amended our articles of incorporation and bylaws for the authorization of the New Common Stock and to provide customary registration rights thereunder, among other corporate governance actions;

• holders of claims arising under the RBL were paid in full from cash on hand, $75.4 million from borrowings under our new revolving credit agreement (the “Revolver”) (see Note 8 below) and proceeds from the Rights Offering;

• the debtor-in-possession credit facility (the “DIP Facility”), under which there were no outstanding borrowings at any time from the Petition Date through the Effective Date, was canceled and less than $0.1 million in fees were paid in full in cash;

• certain other priority claims were paid in full in cash, reinstated or otherwise treated in a manner acceptable to the creditor claim-holders;

• a cash reserve of $2.7 million was established for certain other secured, priority or convenience claims pending resolution as of the Effective Date;

• an escrow account for professional service fees attributable to our advisers and those of the UCC was funded by us with cash of $14.6 million, and we paid $7.2 million for professional fees and expenses on behalf of the RBL Lenders, the Ad Hoc Committee and the indenture trustee for the Senior Notes;

• on the Effective Date, our previous interim Chief Executive Officer, Edward B. Cloues, and each member of our board of directors resigned and was replaced by three new board members: Darin G. Holderness, CPA, Marc McCarthy and Harry Quarls;

• our Predecessor preferred stock and common stock was canceled, extinguished and discharged; and

• all of our Predecessor share-based compensation plans and supplemental employee retirement plan (the “SERP”) entitlements were canceled.

While our emergence from bankruptcy is effectively complete, certain administrative activities will continue under the authority of the Bankruptcy Court for the next several months.

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4. Fresh Start Accounting

We adopted Fresh Start Accounting on the Effective Date in connection with our emergence from bankruptcy. As referenced below, our reorganization value of $334.0 million, immediately prior to emergence was substantially less than our post-petition liabilities and allowed claims. Furthermore and in connection with our reorganization, we experienced a change in control as the outstanding common and preferred shares of the Predecessor were canceled and substantially all of the New Common Stock was issued to the Predecessor’s creditors, primarily former holders of our Senior Notes. Accordingly, the holders of the Predecessor’s common and preferred shares effectively received no shares of the Successor. The adoption of Fresh Start Accounting results in a new reporting entity, the Successor, for financial reporting purposes. The presentation is analogous to that of a new business entity such that the Successor is presented with no beginning retained earnings or deficit on the Effective Date.

Reorganization Value

Reorganization value represents the fair value of the Successor’s total assets prior to the consideration of liabilities and is intended to approximate the amount a willing buyer would pay for the assets immediately after a restructuring. The reorganization value, which was derived from the Successor’s enterprise value, was allocated to our individual assets based on their estimated fair values.

Enterprise value represents the estimated fair value of an entity’s long term debt and shareholders’ equity. The Successor’s enterprise value, as approved by the Bankruptcy Court in support of the Plan, was estimated to be within a range of $218 million to $382 million with a mid-point value of $300 million. Based on the estimates and assumptions utilized in our Fresh Start Accounting process, we estimated the Successor’s enterprise value to be approximately $266.2 million after the consideration of cash and cash equivalents on hand at the Effective Date.

The following table reconciles the enterprise value, net of cash and cash equivalents, to the estimated fair value of our Successor common stock as of the Effective Date:

Enterprise value	$	234,831
Plus: Cash and cash equivalents	31,414
Less: Fair value of debt	(75,350		)
Fair value of Successor common stock	$	190,895
Shares outstanding as of September 12, 2016	14,992,018
Per share value	$	12.73

The following table reconciles the enterprise value to the reorganization value of our Successor assets as of the Effective Date:

Enterprise value	$	234,831
Plus: Cash and cash equivalents	31,414
Plus: Current liabilities	54,171
Plus: Noncurrent liabilities excluding long-term debt	13,558
Reorganization value	$	333,974

Valuation Process

Our valuation analysis was prepared with the assistance of an independent third-party consultant utilizing reserve information prepared by our independent reserve engineers, internal development plans and schedules, other internal financial information and projections and the application of standard valuation techniques including risked net asset value analysis and comparable public company metrics.

Our principal assets include the Successor’s oil and gas properties. We determined the fair value of our oil and gas properties based on the discounted cash flows expected to be generated from these assets. Our analyses were based on market conditions and reserves in place as confirmed by our independent petroleum engineers. The proved reserves were segregated into various geographic regions, including sub-regions within the Eagle Ford where a substantial portion of our assets are located, for which separate risk factors were determined based on geological characteristics. Due to the limited drilling plans that we have in place, proved undeveloped locations were risked accordingly. Future cash flows were estimated by using NYMEX forward prices for West Texas Intermediate crude oil and Henry Hub natural gas with inflation adjustments applied to periods beyond a five-year horizon. These prices were adjusted for differentials realized by us for location and product quality. Gathering and transportation costs were estimated based on agreements that we have in place and development and operating costs were based on our most recent experience and adjusted for inflation in future years. The risk-adjusted after-tax cash flows

11

were discounted at a rate of 13.5%. This rate was determined from a weighted-average cost of capital computation which utilized a blended expected cost of debt and expected returns on equity for similar industry participants. Plugging and abandonment costs were also identified and measured in this process in order to determine the fair value of the Successor’s asset retirement obligations (“AROs”) attributable to our proved developed reserves on the Effective Date. Based on this valuation process, we determined fair values of $121.9 million for our proved reserves and $2.7 million for the related AROs.

With respect to the valuation of our undeveloped acreage, we segregated our current lease holdings in the Eagle Ford into prospect regions in which we have significant developed acreage and those in which we have not yet initiated any significant drilling activity. For those prospects within previously developed regions, we applied a multiple based on recent transactions involving acreage deemed comparable to our acreage for each targeted formation. Based on this valuation process, we determined a fair value of $92.5 million for our undeveloped acreage within previously developed regions of the Eagle Ford. For those lease holdings in other areas of the Eagle Ford, we disregarded those prospects for which lease expirations will occur during the remainder of 2016 as well as those for which future drilling is considered uneconomical at current commodity prices. A reduced multiple was then applied to this adjusted undeveloped acreage consistent with recent transactions for acreage deemed comparable to our acreage resulting in a fair value of $8.3 million. We attributed no value to our limited undeveloped lease holdings in all areas other than the Eagle Ford.

Our remaining equipment and other fixed assets were valued at $26.7 million primarily using a cost approach that incorporated depreciation and obsolescence to the extent applicable on an asset-by-asset basis. The most significant of these assets is our water facility in South Texas which is integral to our regional operations. Accordingly, this asset, for which we determined a fair value of $23.4 million, is included in our full cost pool for purposes of determining our depletion, depreciation and amortization (“DD&A”) attributable to our oil and gas production. Certain assets, particularly personal property including office equipment and vehicles, among others, were valued based on market data for comparable assets to the extent such information was available.

The remaining reorganization value is attributable to certain natural gas imbalance receivables, cash and cash equivalents, working capital assets including accounts receivable, prepaid items, current derivative assets and debt issuance costs. Our natural gas imbalance receivables, which are fully attributable to our Mid-Continent operations in the Granite Wash, were valued using NYMEX spot prices for Henry Hub natural gas adjusted for basis differentials for transportation. Our accounts receivable, including amounts receivable from our joint venture partners, were subjected to analysis on an individual basis and reserved to the extent we believe was appropriate. Collectively, these remaining assets, including our current derivative assets which are marked-to-market on a monthly basis, are stated at their fair values on the Effective Date. The reorganization value also includes $3.0 million of issuance costs attributable to the Revolver under which we initially borrowed $75.4 million. This amount has been capitalized in accordance with GAAP as it represents costs attributable to the access to credit over the term of the Revolver.

Our liabilities on the Effective Date include the aforementioned borrowings under the Revolver, working capital liabilities including accounts payable and accrued liabilities, a reserve for certain litigation matters, pension and health care obligations attributable to certain retirees, AROs, and derivative liabilities. As the Revolver is current and is a variable-rate financial instrument, it is stated at its fair value. Our working capital liabilities and litigation reserve are ordinary course obligations and their carrying amounts approximate their fair values. We revalued our retiree obligations based on data from our independent actuaries and have been stated at their fair values. The AROs were valued in connection with the valuation process attributable to our oil and gas reserves as discussed above. Finally, our derivative liabilities have also been stated at their fair value as they are marked-to-market on a monthly basis.

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Successor Balance Sheet

The following table reflects the reorganization and application of Fresh Start Accounting adjustments on our Condensed Consolidated Balance Sheet as of September 12, 2016:

						Reorganization					Fresh Start
			Predecessor			Adjustments					Adjustments					Successor
Assets
Current assets
	Cash and cash equivalents		$	48,718		$	(17,304	)	(1	)	$	—				$	31,414
	Accounts receivable, net of allowance for doubtful accounts		35,606			4,292			(2	)	—					39,898
	Derivative assets		397			—					—					397
	Other current assets		3,966			(832		)	(3	)	—					3,134
		Total current assets	88,687			(13,844		)			—					74,843
Property and equipment, net			309,261			—					(55,751		)	(12	)	253,510
Other assets			6,902			(1,281		)	(4	)	—					5,621
		Total assets	$	404,850		$	(15,125	)			$	(55,751	)			$	333,974
Liabilities and Shareholders’ Deficit
Current liabilities
	Accounts payable and accrued liabilities		$	77,151		$	(21,166	)	(5	)	$	(3,455	)	(13	)	$	52,530
	Derivative liabilities		1,641			—					—					1,641
	Current maturities of long-term debt		113,653			(113,653		)	(6	)	—					—
		Total current liabilities	192,445			(134,819		)			(3,455		)			54,171
Other liabilities			84,953			100			(5	)	(80,615		)	(14	)	4,438
Derivative liabilities			9,120			—					—					9,120
Long-term debt			—			75,350			(7	)	—					75,350
Liabilities subject to compromise			1,154,163			(1,154,163		)	(8	)	—					—
Shareholders’ equity (deficit)
	Preferred stock (Predecessor)		1,880			(1,880		)	(9	)	—					—
	Common stock (Predecessor)		697			(697		)	(9	)	—					—
	Paid-in capital (Predecessor)		1,213,797			(1,213,797		)	(9	)	—					—
	Deferred compensation obligation (Predecessor)		3,440			(3,440		)	(9	)	—					—
	Accumulated other comprehensive income (Predecessor)		383			(383		)	(9	)	—					—
	Treasury stock (Predecessor)		(3,574		)	3,574			(9	)	—					—
	Common stock (Successor)		—			150			(10	)	—					150
	Paid-in capital (Successor)		—			190,745			(10	)	—					190,745
	Accumulated deficit		(2,252,454		)	2,224,135			(11	)	28,319			(15	)	—
		Total shareholders’ equity (deficit)	(1,035,831		)	1,198,407					28,319					190,895
		Total liabilities and shareholders’ equity (deficit)	$	404,850		$	(15,125	)			$	(55,751	)			$	333,974

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Reorganization Adjustments

1. Represents the net cash payments that occurred on the Effective Date:

Sources:
Proceeds from the Revolver	$	75,350
Proceeds from the Rights Offering, net of issuance costs	49,943
Total sources			$	125,293
Uses:
Repayment of RBL	$	113,653
Accrued interest payable on RBL	1,374
DIP Facility fees	12
Debt issue costs of the Revolver	3,011
Funding of professional fee escrow account	14,575
RBL lender professional fees and expenses	455
Ad Hoc Committee and indenture trustee professional fees and expenses	6,782
Payment of certain allowed claims and settlements	2,735
Total uses			142,597
			$	(17,304	)

2. Represents the reclassification of SERP assets to a current receivable from other noncurrent assets upon the cancellation of the underlying plan and the reversion of the assets to the Successor.

3. Represents the write-off of certain prepaid directors and officers tail insurance.

4. Represents the capitalization of debt issuance costs attributable to the Revolver, net of the reclassification of SERP assets as discussed in item (2) above.

5. Represents the payment of professional fees on behalf of the RBL Lenders, the Ad Hoc Committee and the UCC, indenture trustee fees and expenses, interest payable on the RBL as well as certain allowed claims and settlements net of the establishment of reserves and the reinstatement of certain other obligations.

6. Represents the repayment of the RBL in cash in full.

7. Represents the initial borrowings under the Revolver.

8. Liabilities subject to compromise were settled as follows in accordance with the Plan:

Liabilities subject to compromise prior to the Effective Date:
Senior Notes	$	1,075,000
Interest on Senior Notes	47,213
Firm transportation obligation	11,077
Compensation – related	9,733
Deferred compensation	4,676
Trade accounts payable	1,487
Litigation claims	1,092
Other accrued liabilities	3,885
			$	1,154,163
Amounts settled in cash, reinstated or otherwise reserved at emergence			(3,915		)
Gain on settlement of liabilities subject to compromise			$	1,150,248

9. Represents the cancellation of our Predecessor preferred and common stock and related components of our Predecessor shareholders’ deficit.

10. Represents the issuance of 14,992,018 shares of New Common Stock with a fair value of $12.73 per share.

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11. Represents the cumulative impact of the reorganization adjustments described above:

Gain on settlement of of liabilities subject to compromise		$	1,150,248
Fair value of equity allocated to:
Unsecured creditors on the Effective Date	174,477
Unsecured creditors pending resolution on the Effective Date	10,396
Backstop Parties in the form of a Commitment Premium	6,022
		190,895
Cancellation of Predecessor shareholders’ deficit		882,992
Net impact to Predecessor accumulated deficit		$	2,224,135

Fresh Start Adjustments

12. Represents the Fresh Start Accounting valuation adjustments applied to our oil and gas properties and other equipment.

13. Represents the accelerated recognition of the current portion of previously deferred gains on sales of assets attributable to the accounting presentation required by GAAP under the Predecessor.

14. Represents the recognition of Fresh Start Accounting adjustments to: (i) our AROs attributable to the revalued oil and gas properties and (ii) our retiree obligations based on actuarial measurements, as well as the accelerated recognition of the noncurrent portion of previously deferred gains on sales of assets attributable to the accounting presentation required by GAAP under the Predecessor.

15. Represents the cumulative impact of the Fresh Start Accounting adjustments discussed above.

Reorganization Items. As described above in Note 2, our Condensed Consolidated Statements of Operations for the periods ended September 12, 2016 include “Reorganization items, net,” which reflects gains recognized on the settlement of liabilities subject to compromise and costs and other expenses associated with the Chapter 11 proceedings, principally professional fees, and the costs associated with the DIP Facility. These post-petition costs for professional fees, as well as administrative fees charged by the U.S. Trustee, have been reported in “Reorganization items, net” in our Condensed Consolidated Statement of Operations as described above. Similar costs that were incurred during the pre-petition periods have been reported in “General and administrative” expenses.

The following table summarizes the components included in “Reorganization items, net” in our Condensed Consolidated Statements of Operations for the periods presented:

	July 1 through			January 1 through
	September 12,			September 12,
	2016			2016
Gains on the settlement of liabilities subject to compromise	$	1,150,248		$	1,150,248
Fresh start accounting adjustments	28,319			28,319
Legal and professional fees and expenses	(22,739		)	(29,976		)
Settlements attributable to contract amendments	(2,550		)	(2,550		)
DIP Facility costs and commitment fees	(27		)	(170		)
Write-off of prepaid directors and officers insurance	(832		)	(832		)
Other reorganization items	(46		)	(46		)
	$	1,152,373		$	1,144,993

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5.       Accounts Receivable and Major Customers

The following table summarizes our accounts receivable by type as of the dates presented:

	Successor			Predecessor
	September 30,			December 31,
	2016			2015
Customers	$	19,221		$	23,481
Joint interest partners	8,201			18,381
Other 1	7,158			7,658
	34,580			49,520
Less: Allowance for doubtful accounts	(2,443		)	(1,555		)
	$	32,137		$	47,965

_______________________

¹ Includes amounts owed to us from joint venture partners for acquisitions in prior periods, severance tax refunds approved by state taxing authorities to be returned to us and other miscellaneous non-operating items. The balance as of September 30, 2016 also includes a $4.3 million receivable from the trustee of the SERP for the reversion of plan assets to the Successor.

For the nine months ended September 30, 2016, or combined Predecessor and Successor periods, three customers accounted for $93.5 million, or approximately 94%, of our consolidated product revenues. The revenues generated from these customers during the nine months ended September 30, 2016 were $64.1 million, $15.8 million and $13.6 million or 64%, 16% and 14% of the consolidated total, respectively. As of September 30, 2016, $16.2 million, or approximately 88%, of our consolidated accounts receivable from customers was related to these customers. For the nine months ended September 30, 2015, two customers accounted for $108.4 million, or approximately 50%, of our consolidated product revenues. The revenues generated from these customers during the nine months ended September 30, 2015 were $62.3 million and $46.1 million, or approximately 29%, and 21% of the consolidated total, respectively. As of December 31, 2015, $21.1 million, or approximately 90%, of our consolidated accounts receivable from customers was related to these customers. No significant uncertainties exist related to the collectability of amounts owed to us by any of these customers.

6. Derivative Instruments

We utilize derivative instruments to mitigate our financial exposure to crude oil and natural gas price volatility. Our derivative instruments are not formally designated as hedges in the context of U.S. GAAP.

Commodity Derivatives

We typically utilize collars and swaps, which are placed with financial institutions that we believe are acceptable credit risks, to hedge against the variability in cash flows associated with anticipated sales of our future oil and gas production. While the use of derivative instruments limits the risk of adverse price movements, such use may also limit future revenues from favorable price movements.

The counterparty to a collar or swap contract is required to make a payment to us if the settlement price for any settlement period is below the floor or swap price for such contract. We are required to make a payment to the counterparty if the settlement price for any settlement period is above the ceiling or swap price for such contract. Neither party is required to make a payment to the other party if the settlement price for any settlement period is equal to or greater than the floor price and equal to or less than the ceiling price for such contract.

We determine the fair values of our commodity derivative instruments based on discounted cash flows derived from third-party quoted forward prices for NYMEX Henry Hub gas and West Texas Intermediate crude oil closing prices as of the end of the reporting period. The discounted cash flows utilize discount rates adjusted for the credit risk of our counterparties if the derivative is in an asset position and our own credit risk if the derivative is in a liability position.

We terminated all of our pre-petition derivative contracts for $22.9 million, $22.6 million and $17.5 million and reduced our amounts outstanding under the RBL by $22.9 million, $16.6 million and $12.5 million in March 2016, April 2016 and May 2016, respectively. In connection with these transactions, the counterparties to the derivative contracts, which are also affiliates of lenders under the RBL, transferred the cash proceeds that were used for RBL repayments directly to the administrative agent under the RBL. Accordingly, all of these RBL repayments have been presented as non-cash financing activities on our Condensed Consolidated Statement of Cash Flows for the period January 1, 2016 through September 12, 2016.

On May 13, 2016, the Bankruptcy Court approved our motion to enter into new commodity derivative contracts. Accordingly, we hedged a substantial portion of our future crude oil production through the end of 2019, as required in the RSA, at a weighted-average price of approximately $48.62 per barrel. We are currently unhedged with respect to natural gas production.

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The following table sets forth our commodity derivative positions as of September 30, 2016:

		Average
		Volume Per	Weighted Average Price			Fair Value
	Instrument	Day	Floor/Swap		Ceiling	Asset		Liability
Crude Oil:		(barrels)	($/barrel)
Fourth quarter 2016	Swaps	5,940	$	47.69		$	—	$	709
First quarter 2017	Swaps	4,408	$	48.62		—		737
Second quarter 2017	Swaps	4,408	$	48.62		—		1,106
Third quarter 2017	Swaps	4,408	$	48.62		—		1,335
Fourth quarter 2017	Swaps	4,408	$	48.62		—		1,518
First quarter 2018	Swaps	3,476	$	49.12		—		1,131
Second quarter 2018	Swaps	3,476	$	49.12		—		1,244
Third quarter 2018	Swaps	3,476	$	49.12		—		1,353
Fourth quarter 2018	Swaps	3,476	$	49.12		—		1,451
First quarter 2019	Swaps	2,916	$	49.90		—		1,051
Second quarter 2019	Swaps	2,916	$	49.90		—		1,117
Third quarter 2019	Swaps	2,916	$	49.90		—		1,179
Fourth quarter 2019	Swaps	2,916	$	49.90		—		1,247

Financial Statement Impact of Derivatives

The impact of our derivative activities on income is included in “Derivatives” in our Condensed Consolidated Statements of Operations. The following tables summarize the effects of our derivative activities for the periods presented:

	Successor			Predecessor
	Period From September 13, 2016			Period from July 1, 2016		Three Months Ended
	Through September 30, 2016			through September 12, 2016		September 30, 2015
Derivative gains (losses)	$	(4,369	)	$	8,934	$	44,701

	Successor			Predecessor
	Period From September 13, 2016			Period From January 1, 2016			Nine Months Ended
	Through September 30, 2016			Through September 12, 2016			September 30, 2015
Derivative gains (losses)	$	(4,369	)	$	(8,333	)	$	52,073

The effects of derivative gains and (losses) and cash settlements (except for those cash settlements attributable to the aforementioned termination transactions) are reported as adjustments to reconcile net income (loss) to net cash provided by operating activities. These items are recorded in “Derivative contracts” on our Condensed Consolidated Statements of Cash Flows under “Net losses (gains)” and “Cash settlements, net.”

The following table summarizes the fair values of our derivative instruments, as well as the locations of these instruments on our Condensed Consolidated Balance Sheets as of the dates presented:

		Successor				Predecessor
		Fair Values as of
		September 30, 2016				December 31, 2015
		Derivative		Derivative		Derivative		Derivative
Type	Balance Sheet Location	Assets		Liabilities		Assets		Liabilities
Commodity contracts	Derivative assets/liabilities – current	$	446	$	3,888	$	97,956	$	—
Commodity contracts	Derivative assets/liabilities - noncurrent	—		11,291		—		—
		$	446	$	15,179	$	97,956	$	—

17

As of September 30, 2016, we reported a net commodity derivative liability of $14.7 million. The contracts associated with this position are with three counterparties, all of which are investment grade financial institutions. This concentration may impact our overall credit risk, either positively or negatively, in that these counterparties may be similarly affected by changes in economic or other conditions. We have neither paid to, nor received from, our counterparties any cash collateral in connection with our derivative positions. Furthermore, our derivative contracts are not subject to margin calls or similar accelerations. No significant uncertainties exist related to the collectability of amounts that may be owed to us by these counterparties.

7. Property and Equipment

The following table summarizes our property and equipment as of the dates presented: 

	Successor			Predecessor
	September 30,			December 31,
	2016			2015
Oil and gas properties:
Proved	$	241,308		$	2,678,415
Unproved	8,338			6,881
Total oil and gas properties	249,646			2,685,296
Other property and equipment	3,574			31,365
Total properties and equipment	253,220			2,716,661
Accumulated depreciation, depletion and amortization	(2,020		)	(2,372,266		)
	$	251,200		$	344,395

We account for our oil and gas properties by applying the full cost method in the Successor period whereas we utilized the successful efforts method during the Predecessor periods.

The following describes our accounting policies with respect to our oil and gas properties and equipment:

Under the full cost method of accounting for oil and gas properties, all costs incurred in the exploration, development and acquisition of oil and gas reserves are capitalized. Such costs may be incurred both prior to and after the acquisition of a property and include lease acquisitions, geological and geophysical, or seismic, drilling, completion and equipment costs. Internal costs incurred that are directly attributable to exploration, development and acquisition activities undertaken by us for our own account, and which are not attributable to production, general corporate overhead or similar activities are also capitalized.

Depreciation, depletion and amortization (“DD&A”) of our oil and gas properties is computed using the units-of-production method. We apply this method by multiplying the unamortized cost of our proved oil and gas properties, net of estimated salvage plus future development costs, by a rate determined by dividing the physical units of oil and gas produced during the period by the total estimated units of proved oil and gas reserves at the beginning of the period.

At the end of each quarterly reporting period, the unamortized cost of our oil and gas properties, net of deferred income taxes, is limited to the sum of the estimated discounted future net revenues from proved properties adjusted for costs excluded from amortization and related income taxes (“Ceiling Test”). The estimated discounted future net revenues are determined using the prior 12-month’s average price based on closing prices on the first day of each month, adjusted for differentials, discounted at 10%. The calculation of the Ceiling Test and provision for DD&A are based on estimates of proved reserves. There are significant uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production, timing and plan of development.

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8. Debt Obligations

The following table summarizes our debt obligations as of the dates presented:

	Successor				Predecessor
	September 30, 2016				December 31, 2015
	Principal		Unamortized Issuance Costs 1		Principal			Unamortized Issuance Costs 1
Revolving credit facility 2	$	54,350			$	—
Pre-petition revolving credit facility 3	—				170,000
Senior notes due 2019	—		$	—	300,000			$	3,295
Senior notes due 2020	—		—		775,000			17,322
Totals	54,350		$	—	1,245,000			$	20,617
Less: Unamortized issuance costs	—				(20,617		)
Less: Amounts classified as current	—				(1,224,383		)
Long-term debt, net of unamortized issuance costs	$	54,350			$	—

____________________

¹ Issuance costs attributable to the Senior Notes were subject to an accelerated write-off in advance of our bankruptcy filing during the three months ended June 30, 2016.

² Issuance costs attributable to the Revolver, which represent costs attributable to the access to credit over the Revolver’s contractual term, have been presented as a component of Other assets (see Note 11).

³ Issuance costs attributable to the RBL were presented as a component of Other assets (see Note 11) prior to the accelerated write-off in advance of our bankruptcy filing during the three months ended June 30, 2016.

Revolving Credit Facility

Upon the Effective Date, we entered into the Revolver. The Revolver provides for a $200 million revolving commitment and has an initial borrowing base of $128 million. The Revolver also includes a $5.0 million sublimit for the issuance of letters of credit, of which $0.8 million was outstanding as of September 30, 2016. The Revolver is governed by a borrowing base calculation, which is redetermined semi-annually, and the availability under the Revolver may not exceed the lesser of the aggregate commitments and the borrowing base. The Revolver is scheduled for its initial redetermination in April 2017. The Revolver is available to us to pay expenses associated with Chapter 11 and for general corporate purposes including working capital. The Revolver matures in September 2020.

The outstanding borrowings under the Revolver bear interest at a rate equal to, at our option, either (a) a customary reference rate plus an applicable margin ranging from 2.00% to 3.00%, determined based on the average availability under the Revolver or (b) a customary London interbank offered rate (“LIBOR”) plus an applicable margin ranging from 3.00% to 4.00%, determined based on the average availability under the Revolver. Interest on reference rate borrowings is payable quarterly in arrears and is computed on the basis of a year of 365/366 days, and interest on eurocurrency borrowings is payable every one, three or six months, at the election of the Borrower, and is computed on the basis of a 360-day year. As of September 30, 2016, the actual interest rate on the outstanding borrowings under the Revolver was 3.770% which is derived from the LIBOR rate of 0.520% plus an applicable margin of 3.250%. Unused commitment fees are charged at a rate of 0.50%.

The Revolver is guaranteed by us and all of our subsidiaries (the “Guarantor Subsidiaries”). The guarantees under the Revolver are full and unconditional and joint and several. Substantially all of our consolidated assets are held by the Guarantor Subsidiaries. The parent company has no material independent assets or operations. The obligations under the Revolver are secured by a first priority lien on substantially all of our assets.

The Revolver requires us to maintain (1) a minimum interest coverage ratio (adjusted earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses as defined in the Revolver (“EBITDAX”) to adjusted interest expense), measured as of the last day of each fiscal quarter, of 3.00 to 1.00, (2) a minimum current ratio (as defined in the Revolver), measured as of the last day of each fiscal quarter of 1.00 to 1.00, and (3) a maximum leverage ratio (consolidated indebtedness to adjusted EBITDAX), measured as of the last day of each fiscal quarter, initially of 4.00 to 1.00, decreasing on December 31, 2017 to 3.75 to 1.00 and on March 31, 2018 and thereafter to 3.50 to 1.00. In accordance with the terms of the Revolver, the quarter ending December 31, 2016 will be the first period for which we are required to comply with these covenants.

The Revolver also contains customary affirmative and negative covenants, including as to compliance with laws (including environmental laws, ERISA and anti-corruption laws), maintenance of required insurance, delivery of quarterly and annual financial statements, oil and gas engineering reports and budgets, maintenance and operation of property (including oil and gas properties), restrictions on the incurrence of liens and indebtedness, merger, consolidation or sale of assets, payment of dividends, and transactions with affiliates and other customary covenants.

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The Revolver contains customary events of default and remedies for credit facilities of this nature. If we do not comply with the financial and other covenants in the Revolver, the lenders may, subject to customary cure rights, require immediate payment of all amounts outstanding under the Revolver.

Pre-Petition Revolving Credit Agreement

As described in Notes 3 and 4, our principal and interest obligations outstanding under the RBL as well as certain associated fees and expenses were satisfied in cash in full on the Effective Date. These obligations were funded from a combination of cash on hand, proceeds from the Rights Offering and proceeds from initial borrowings under the Revolver.

2019 Senior Notes and 2020 Senior Notes

The Senior Notes have been included in “Liabilities subject to compromise” on the Condensed Consolidated Balance Sheet of the Predecessor as of September 12, 2016 (see Note 4) and have been included in “Current liabilities” as of December 31, 2015. As described in Notes 3 and 4, the Senior Notes were canceled upon our emergence from bankruptcy.

9. Income Taxes

We recognized a federal income tax benefit for each of the periods ended September 12, 2016 (Predecessor) and September 30, 2016 (Successor) at the statutory rate of 35%; however, the federal tax benefit was fully offset by a valuation allowance against our net deferred tax assets. We considered both the positive and negative evidence in determining that it was more likely than not that some portion or all of our deferred tax assets will not be realized, primarily as a result of cumulative losses. We recognized income tax benefits for the three and nine months ended September 30, 2015 due primarily to a federal return to provision adjustment partially offset by a minimal deferred state income tax expense. We received a state income tax refund of less than $0.1 million during the period ended September 12, 2016.

We have evaluated the impact of the reorganization, including the change in control, resulting from our emergence from bankruptcy. From an income tax perspective, the most significant impact is attributable to our carryover tax attributes associated with our net operating losses (“NOLs”). We believe that the Successor will be able to fully absorb the cancellation of debt income realized by the Predecessor in connection with the reorganization with its adjusted NOL carryovers. The amount of the remaining NOL carryovers and the tax basis of our properties will be limited under Section 382 of the Internal Revenue Code due to the change in control as referenced in Notes 3 and 4. As the tax basis of our assets, primarily our oil and gas properties, is in excess of the carrying value, as adjusted in the Fresh Start Accounting process, the Successor is in a net deferred tax asset position. We have determined that it is more likely than not that we will not realize future income tax benefits from the additional tax basis and our remaining NOL carryovers. Accordingly, we have provided for a full valuation allowance of the underlying deferred tax assets.

10. Exit Activities

We have committed to a number of actions, or exit activities, consistent with our current business plans for which we have continuing financial commitments. The most significant of these activities are attributable to an overall reduction in the scope and scale of our organization and require payments to satisfy obligations associated with the underlying commitments. The following summarizes our most significant exit activities.

Reductions in Force

In connection with efforts to reduce our administrative costs, we took certain actions to reduce our total employee headcount. In February, June and September, we reduced our total employee headcount by 45 employees. We paid a total of $1.9 million, including $1.2 million in severance and termination benefits and $0.7 million in retention bonuses during the nine months ended September 2016, and $0.1 million in severance and termination benefits during October 2016. The employment of nine employees scheduled for termination was extended with a payout of $0.2 million in retention bonuses, included in the above retention. Estimated severance and termination benefits for these employees is expected to be $0.3 million. The affected employees must continue to provide services through each of their extension dates in order to receive these benefits. Accordingly, we incurred a charge and established an accrual representing the period for which these benefits have been earned.

The costs associated with these reduction-in-force and retention actions are included as a component of our “General and administrative” expenses on our Condensed Consolidated Statements of Operations. The related obligations are included in “Accounts payable and accrued liabilities” on our Condensed Consolidated Balance Sheet.

Drilling Rig Termination

In connection with the suspension of our 2016 drilling program in the Eagle Ford, we terminated our one remaining drilling rig contract and incurred $1.3 million in early termination charges. As this obligation represented a pre-petition liability of the Predecessor, it was discharged and included in “Reorganization items, net” on our Condensed Consolidated Statements of Operations. The vendor recovered a portion of the amount in the form of New Common Stock.

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Firm Transportation Obligation

We had a contractual obligation for certain firm transportation capacity in the Appalachian region that was scheduled to expire in 2022 and, as a result of the sale of our natural gas assets in this region in 2012, we no longer had production available to satisfy this commitment. We originally recognized a liability in 2012 representing this obligation for the estimated discounted future net cash outflows over the remaining term of the contract. The accretion of the obligation through the Petition Date, net of any recoveries from periodic sales of our contractual capacity, was charged as an offset to Other revenue. In connection with our emergence from bankruptcy, we rejected the underlying contract and the obligation was discharged and included in “Reorganization items, net” on our Condensed Consolidated Statements of Operations. The vendor recovered a portion of the amount in the form of New Common Stock.

11. Additional Balance Sheet Detail

The following table summarizes components of selected balance sheet accounts as of the dates presented:

	Successor		Predecessor
	September 30,		December 31,
	2016		2015
Other current assets:
Tubular inventory and well materials	$	2,154	$	2,878
Prepaid expenses	1,357		4,184
Other	7		42
	$	3,518	$	7,104
Other assets:
Assets of SERP 1	$	—	$	4,123
Deferred issuance costs of the revolving credit facilities 2	2,973		1,572
Other	2,598		2,655
	$	5,571	$	8,350
Accounts payable and accrued liabilities:
Trade accounts payable	$	7,926	$	11,603
Drilling costs	1,475		12,074
Royalties and revenue – related	28,203		39,119
Compensation – related	2,164		9,904
Interest	125		15,531
Other	5,539		15,294
	$	45,432	$	103,525
Other liabilities:
Deferred gains on sales of assets	$	—	$	82,943
Firm transportation obligation	—		10,705
Asset retirement obligations	2,696		2,621
Defined benefit pension obligations	1,132		1,129
Postretirement health care benefit obligations	523		731
Compensation – related	—		1,447
Deferred compensation – SERP obligations and other	—		4,434
Other	100		928
	$	4,451	$	104,938

_______________________

¹ In connection with our emergence from bankruptcy, the assets of the SERP reverted to us upon the release of claims by our employees attributable to certain deferred compensation arrangements in September 2016. The SERP assets were liquidated by the plan trustee in November 2016 and the cash value was transferred to us (see Notes 3, 4 and 5).

² The balance as of September 30, 2016 includes those costs, net of amortization, attributable to the Revolver. Deferred issuance costs attributable to the RBL, which represents the amounts outstanding as of December 31, 2015, were charged in full to interest expense during the three months ended June 30, 2016 in advance of our Chapter 11 filing.

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12. Fair Value Measurements

We apply the authoritative accounting provisions for measuring fair value of both our financial and nonfinancial assets and liabilities. Fair value is an exit price representing the expected amount we would receive upon the sale of an asset or that we would expect to pay to transfer a liability in an orderly transaction with market participants at the measurement date.

Our financial instruments that are subject to fair value disclosure consist of cash and cash equivalents, accounts receivable, accounts payable, derivatives and long-term debt. As of September 30, 2016, the carrying values of all of these financial instruments approximated fair value.

The following table summarizes the fair value of our debt obligations with fixed interest rates, which is estimated based on the published market prices for these financial liabilities, as of the dates presented:

	Successor				Predecessor
	September 30, 2016				December 31, 2015
	Fair Value		Carrying Value		Fair Value		Carrying Value
Senior Notes due 2019 1	$	—	$	—	$	40,830	$	300,000
Senior Notes due 2020 1	—		—		125,473		775,000
	$	—	$	—	$	166,303	$	1,075,000

______________________

¹ The Senior Notes were canceled upon our emergence from bankruptcy.

Recurring Fair Value Measurements

Certain financial assets and liabilities are measured at fair value on a recurring basis in our Condensed Consolidated Balance Sheets. The following tables summarize the valuation of those assets and liabilities as of the dates presented:

	Successor As of September 30, 2016
	Fair Value			Fair Value Measurement Classification
Description	Measurement			Level 1		Level 2			Level 3
Assets:
Commodity derivative assets – current	$	446		$	—	$	446		$	—
Assets of SERP 1	4,292			4,292		—			—
Liabilities:
Commodity derivative liabilities – current	(3,888		)	—		(3,888		)	—
Commodity derivative liabilities – noncurrent	(11,291		)	—		(11,291		)	—

______________________

¹ In connection with our emergence from bankruptcy, the assets of the SERP reverted to us upon the release of claims by our employees attributable to certain deferred compensation arrangements in September 2016. The SERP assets were liquidated by the plan trustee in October 2016 and the cash value, which was included in accounts receivable as of September 30, 2016, was transferred to us for general corporate purposes.

	Predecessor As of December 31, 2015
	Fair Value			Fair Value Measurement Classification
Description	Measurement			Level 1			Level 2		Level 3
Assets:
Commodity derivative assets – current	$	97,956		$	—		$	97,956	$	—
Assets of SERP	4,123			4,123			—		—
Liabilities:
Deferred compensation – SERP obligations	(4,125		)	(4,125		)	—		—

Changes in economic conditions or model-based valuation techniques may require the transfer of financial instruments from one level of the fair value hierarchy to another level. In such instances, the transfer is deemed to have occurred at the beginning of the quarterly period in which the event or change in circumstances that caused the transfer occurred. There were no transfers during the nine months ended September 30, 2016 and 2015.

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We used the following methods and assumptions to estimate fair values for the financial assets and liabilities described below:

• Commodity derivatives: We determine the fair values of our commodity derivative instruments based on discounted cash flows derived from third-party quoted forward prices for West Texas Intermediate crude oil and NYMEX Henry Hub gas closing prices as of the end of the reporting periods. We generally use the income approach, using valuation techniques that convert future cash flows to a single discounted value. Each of these is a level 2 input.

• Assets of SERP: We held various publicly traded equity securities in a Rabbi Trust as assets for funding certain deferred compensation obligations. The fair values were based on quoted market prices, which are level 1 inputs.

• Deferred compensation – SERP obligations: Certain of our deferred compensation obligations were ultimately to be settled in cash based on the underlying fair value of certain assets, including those held in the Rabbi Trust. The fair values were based on quoted market prices, which are level 1 inputs.

Non-Recurring Fair Value Measurements

The most significant non-recurring fair value measurements utilized in the preparation of our Condensed Consolidated Financial Statements are those attributable to the recognition and measurement of the Successor's net assets with respect to the application of Fresh Start Accounting. Those measurements are more fully described in Note 4. In addition, we utilize non-recurring fair value measurements with respect to the recognition and measurement of asset impairments, particularly during our Predecessor periods during which time we applied the successful efforts method to our oil and gas properties, as well as the initial determination of AROs associated with the ongoing development of new oil and gas properties.

The factors used to determine fair value for purposes of recognizing and measuring asset impairments while we applied the successful efforts method to our oil and gas properties during our Predecessor periods included, but were not limited to, estimates of proved and risk-adjusted probable reserves, future commodity prices, indicative sales prices for properties, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties. Under the full cost method, we apply a ceiling test determination utilizing prescribed procedures as described in Note 7. The full cost method is substantially different from the successful efforts method which relies upon fair value measurements. Because these significant fair value inputs were typically not observable, we have categorized the amounts as level 3 inputs.

The determination of the fair value of AROs is based upon regional market and facility specific information. The amount

of an ARO and the costs capitalized represent the estimated future cost to satisfy the abandonment obligation using current

prices that are escalated by an assumed inflation factor after discounting the future cost back to the date that the abandonment

obligation was incurred using a rate commensurate with the risk, which approximates our cost of funds. Because these

significant fair value inputs are typically not observable, we have categorized the initial estimates as level 3 inputs.

13. Commitments and Contingencies

Gathering and Intermediate Transportation Commitments

We have long-term agreements with Republic Midstream, LLC (“Republic Midstream”) and Republic Midstream Marketing, LLC (“Republic Marketing” and, together with Republic Midstream, collectively, “Republic”) to provide for gathering and intermediate pipeline transportation services for a substantial portion of our crude oil and condensate production in the South Texas region as well as volume capacity support for certain downstream interstate pipeline transportation.

In August 2016, the Bankruptcy Court approved a settlement with Republic and authorized the assumption of certain amended agreements with Republic (the “Amended Agreements”). We paid Republic $0.3 million in connection with the settlement which is included in “Reorganization items, net” in our Condensed Consolidated Statements of Operations.

Under the terms of the Amended Agreements, Republic is obligated to gather and transport our crude oil and condensate from within a dedicated area in the Eagle Ford (the “Dedication Area”) via a gathering system and intermediate takeaway pipeline connecting to a downstream interstate pipeline operated by a third party. The amended gathering agreement reduced our minimum volume commitment from 15,000 to 8,000 barrels of oil per day. The term of the amended gathering agreement runs through 2041, with the term of the minimum volume commitment extended from 10 to 15 years.

Under the amended marketing agreement, we have a 10-year commitment to sell 8,000 barrels per day of crude oil to Republic, or any third party, utilizing Republic Marketing’s capacity on a certain downstream interstate pipeline.

Excluding the potential impact of the effects of price escalation from commodity price changes, the minimum fee requirements under the Amended Agreements are as follows: $3.9 million for the remainder of 2016, $9.6 million for 2017, $10.4 million for 2018, $11.7 million for 2019, $13.0 million for 2020 through 2025, $7.4 million for 2026, $3.8 million for 2027 through 2030 and $2.2 million for 2031.

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Legal and Regulatory

We are involved, from time to time, in various legal proceedings arising in the ordinary course of business. While the ultimate results of these proceedings cannot be predicted with certainty, our management believes that these claims will not have a material effect on our financial position, results of operations or cash flows. During the quarter ended September 30, 2016, we reduced our reserve for a litigation matter to $0.1 million from $0.9 million due to our expected dismissal from the subject litigation. As of September 30, 2016, we also had AROs of approximately $2.7 million attributable to the plugging of abandoned wells. 

14. Shareholders’ Equity

The following tables summarize the components of our shareholders’ equity (deficit) and the changes therein as of and for the Predecessor period from December 31, 2015, through September 12, 2016 and the Successor period from September 13, 2016 through September 30, 2016:

																Accumulated
													Deferred			Other
	Preferred			Common			Paid-in			Accumulated			Compensation			Comprehensive			Treasury
	Stock 2			Stock 2			Capital 2			Deficit			Obligation			Income 3			Stock			Total
Balance, December 31, 2015 (Predecessor)	$	3,146		$	628		$	1,211,088		$	(2,130,271	)	$	3,440		$	422		$	(3,574	)	$	(915,121	)
Net Loss	—			—			—			1,054,602			—			—			—			1,054,602
All Other Changes 1	(1,266		)	69			2,709			—			—			(39		)	—			1,473
Balance, September 12, 2016 (Predecessor)	$	1,880		$	697		$	1,213,797		$	(1,075,669	)	$	3,440		$	383		$	(3,574	)	$	140,954
Cancellation of Predecessor equity	(1,880		)	(697		)	(1,213,797		)	1,075,669			(3,440		)	(383		)	3,574			(140,954		)
Balance, September 12, 2016 (Predecessor)	$	—		$	—		$	—		$	—		$	—		$	—		$	—		$	—
Issuance of Successor common stock - Rights Offering	$	—		$	76		$	49,867		$	—		$	—		$	—		$	—		$	49,943
Issuance of Successor common stock - Backstop Fee	—			5			9,054			—			—			—			—			9,059
Issuance of Successor common stock - exchange of claims	—			69			131,824			—			—			—			—			131,893
Balance, September 12, 2016 (Successor)	—			150			190,745			—			—			—			—			190,895
Net Loss	—			—			—			(3,441		)	—			—			—			(3,441		)
Balance, September 30, 2016 (Successor)	$	—		$	150		$	190,745		$	(3,441	)	$	—		$	—		$	—		$	187,454

_______________________

¹ Includes equity-classified share-based compensation of $(3,918) for the period January 1, 2016 through September 12, 2016. Share-based compensation awards that were outstanding on the Effective Date were canceled in connection with our emergence from bankruptcy.

² A total of 52 shares, or 5,159 depositary shares, of our Series A 6% Convertible Perpetual Preferred Stock (the “Series A Preferred Stock”) were converted into 85,982 shares of our common stock during the period January 1, 2016 through September 12, 2016. A total of 12,619 shares, or 1,261,850 depositary shares, of our Series B 6% Convertible Perpetual Preferred Stock (the “Series B Preferred Stock”) were converted into 6,879,222 shares of our common stock during the period January 1, 2016 through September 12, 2016. Preferred Stock was canceled in connection with our emergence from bankruptcy.

³ Accumulated other comprehensive income (“AOCI”) is entirely attributable to our defined benefit pension and postretirement health care plans. The changes in the balance of AOCI for the period January 1, 2016 through September 12, 2016, represent reclassifications from AOCI to net periodic benefit expense, a component of “General and administrative expenses,” of $(38).

In September 2015, we announced a suspension of quarterly dividends on the Series A Preferred Stock and Series B Preferred Stock for the quarter ended September 30, 2015, which was extended through the bankruptcy period. The accumulated dividends were discharged as a result of our emergence from bankruptcy.

We do not anticipate that cash dividends or other distributions will be paid with respect to our common stock in the foreseeable future. In addition, our Revolver has restrictive covenants that limit our ability to pay dividends.

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15. Share-Based Compensation and Other Benefit Plans

Share-Based Compensation

We recognize share-based compensation expense related to our share-based compensation plans as a component of “General and administrative” expense in our Condensed Consolidated Statements of Operations.

In the Predecessor periods in 2016 and 2015 we had outstanding equity-classified awards in the form of stock options, restricted stock units and deferred stock unit. As discussed in Notes 3 and 4, all remaining equity-classified share-based compensation awards were canceled in connection with our emergence from bankruptcy. On the Effective Date, we authorized 749,600 shares of New Common Stock for future share-based compensation awards, none of which were outstanding as of September 30, 2016.

With the exception of performance-based restricted stock units (“PBRSUs”), all of our Predecessor’s share-based compensation awards were classified as equity instruments because they would result in the issuance of common stock on the date of grant, upon exercise or were otherwise payable in common stock upon vesting, as applicable. The compensation cost attributable to these awards was measured at the grant date and recognized over the applicable vesting period as a non-cash item of expense. Because the PBRSUs were payable in cash, they were typically considered liability-classified awards and were included in “Accounts payable and accrued liabilities” (current portion) and “Other liabilities” (noncurrent portion) on our Condensed Consolidated Balance Sheets of the Predecessor. Compensation cost associated with the PBRSUs was measured at the end of each reporting period and recognized based on the period of time that had elapsed during each of the individual performance periods. Similar to the equity-classified awards referenced above, all outstanding PBRSUs were canceled as well upon our emergence from bankruptcy.

The following tables summarize our share-based compensation expense (benefit) recognized for the periods presented:

	Successor		Predecessor
	Period from September 13,		Period from July 1,
	2016 through September		2016 through September		Three Months Ended
	30, 2016		12, 2016		September 30, 2015
Equity-classified awards	$	—	$	5,433	$	1,263
Liability-classified awards	—		—		(851		)
	$	—	$	5,433	$	412

	Successor		Predecessor
	Period from September 13,		Period from January 1,
	2016 through September		2016 through September			Nine Months Ended
	30, 2016		12, 2016			September 30, 2015
Equity-classified awards	$	—	$	1,511		$	3,369
Liability-classified awards	—		(19		)	(686		)
	$	—	$	1,492		$	2,683

The equity-classified share-based compensation expense for the Predecessor periods from July 1, 2016 and January 1, 2016, each through September 12, 2016, include an adjustment of $5.3 million to correct for an error that occurred in the reporting of equity-classified share-based compensation expense for the three months ended June 30, 2016. We have assessed the quantitative and qualitative factors with respect to this error as well as the effect of the correcting adjustment being recorded in the Predecessor period from July 1, 2016 through September 12, 2016 and determined that the amount and timing of the adjustment is not material to the Condensed Consolidated Financial Statements taken as a whole for any of the subject periods.

The substance of the error was attributable to the accounting for the voluntary cancellation of certain restricted stock unit awards that were scheduled to vest immediately prior to the Petition Date. While we believe the dollar amount of the error is not insignificant, the non-cash nature of the underlying compensation expense and the overall variability of all of our share-based compensation awards as a component of general and administrative expenses are factors to which we gave strong consideration in our assessment. In general and specifically in the industry in which we operate, non-cash share-based compensation expense is generally viewed independently of traditional cash-based general and administrative expenses. Accordingly, significant variability of such expense in any discrete period is not indicative of a trend in general and administrative expenses that would influence a user of our financial statements. Furthermore, the Condensed Consolidated Financial Statements that included the original error were issued approximately two and one-half months after we entered

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bankruptcy. Accordingly, we do not believe that the error which occurred within and was subsequently corrected in a sequential Predecessor period would influence any current users of our financial statements as the subject compensations plans were ultimately canceled and we are a substantially different company, particularly with respect to total employee headcount, as the Successor from an overall general and administrative cost perspective.

Other Benefit Plans

We maintain the Penn Virginia Corporation and Affiliated Companies Employees 401(k) Plan (the “401(k) Plan”), a defined contribution plan, which covers substantially all of our employees. We recognized $0.4 million for the period January 1, 2016 through September 12, 2016, less then $0.1 million for the period September 13, 2016 through September 30, 2016 and $0.6 million of expense attributable the 401(k) Plan for the nine months ended September 30, 2015.

We maintain unqualified legacy defined benefit pension and defined benefit postretirement plans that cover a limited number of former employees, all of whom retired prior to 2000. The combined expense recognized with respect to these plans was less than $0.1 million for the period January 1, 2016 through September 12, 2016, less than $0.1 million for the period September 13, 2016 through September 30, 2016 and $0.1 million for the nine months ended September 30, 2015.

16. Interest Expense

The following tables summarize the components of interest expense for the periods presented:

	Successor		Predecessor
	Period from September 13, 2016		Period from July 1, 2016		Three Months Ended
	through September 30, 2016		through September 12, 2016		September 30, 2015
Interest on borrowings and related fees 1	$	180	$	1,363	$	23,239
Amortization of debt issuance costs	38		—		1,224
Capitalized interest	—		—		(1,478		)
	$	218	$	1,363	$	22,985

_______________________

¹ Absent the bankruptcy proceedings and the corresponding suspension of the accrual of interest on unsecured debt, we would have recorded total contractual interest expense of $19.3 million for the period July 1, 2016 through September 12, 2016, including $4.4 million attributable to the 2019 Senior Notes and $13.4 million attributable to the 2020 Senior Notes.

	Successor		Predecessor
	Period from September 13, 2016		Period from January 1, 2016			Nine Months Ended
	through September 30, 2016		through September 12, 2016			September 30, 2015
Interest on borrowings and related fees 2	$	180	$	36,013		$	69,371
Amortization of debt issuance costs 3	38		22,188			3,504
Capitalized interest	—		(183		)	(4,854		)
	$	218	$	58,018		$	68,021

_______________________

² Absent the bankruptcy proceedings and the corresponding suspension of the accrual of interest on unsecured debt, we would have recorded total contractual interest expense of $66.1 million for the period from January 1, 2016 through September 12, 2016, including $15.3 million attributable to the 2019 Senior Notes and $46.3 million attributable to the 2020 Senior Notes.

³ Includes$20.5 million related to the accelerated write-off of unamortized debt issuance costs associated with the RBL and Senior Notes (see Note 8).

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17. Earnings (Loss) per Share

The following tables provide a reconciliation of the components used in the calculation of basic and diluted earnings per share for the periods presented:

	Successor			Predecessor
	Period from September 13,			Period from July 1,
	2016 through September			2016 through September		Three Months Ended
	30, 2016			12, 2016		9/30/2015
Net (loss) income	$	(3,441	)	$	1,150,055	$	25,900
Less: Preferred stock dividends	—			—		$	(5,935	)
Net (loss) income attributable to common shareholders – basic	$	(3,441	)	$	1,150,055	$	19,965
Add: Preferred stock dividends	—			—		5,935
Net (loss) income attributable to common shareholders – diluted	$	(3,441	)	$	1,150,055	$	25,900
Weighted-average shares – basic	14,992			89,292		72,651
Effect of dilutive securities	—			22,166		30,801
Weighted-average shares – diluted	14,992			111,458		103,452

	Successor			Predecessor
	Period from September 13,			Period from January 1,
	2016 through September			2016 through September			Nine Months Ended
	30, 2016			12, 2016			2015
Net (loss) income	$	(3,441	)	$	1,054,602		$	(111,394	)
Less: Preferred stock dividends 1	—			(5,972		)	(18,069		)
Net (loss) income attributable to common shareholders – basic and diluted	$	(3,441	)	$	1,048,630		$	(129,463	)
Weighted-average shares – basic	14,992			88,013			72,438
Effect of dilutive securities 2	—			36,074			—
Weighted-average shares – diluted	14,992			124,087			72,438

_______________________

¹ Preferred stock dividends were excluded from the computation of diluted earnings (loss) per share for the period January 1, 2016 through September 12, 2016 and the nine months ended September 30, 2015, as the assumed conversion of the outstanding preferred stock would have been anti-dilutive.

² For the nine months ended September 30, 2015, approximately 31.1 million of potentially dilutive securities, including the Series A Preferred Stock and Series B Preferred Stock, stock options and restricted stock units, had the effect of being anti-dilutive and were excluded from the calculation of diluted earnings (loss) per common share.

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Forward-Looking Statements

Certain statements contained herein that are not descriptions of historical facts are “forward-looking” statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. Because such statements include risks, uncertainties and contingencies, actual results may differ materially from those expressed or implied by such forward-looking statements. These risks, uncertainties and contingencies include, but are not limited to, the following:

• potential adverse effects of the completed Chapter 11 proceedings on our liquidity, results of operations, brand, business prospects, ability to retain financing and other risks and uncertainties related to our emergence from Chapter 11;

• the ability to operate our business following emergence from Chapter 11;

• our ability to satisfy our short-term and long-term liquidity needs, including our inability to generate sufficient cash flows from operations or to obtain adequate financing to fund our capital expenditures and meet working capital needs;

• negative events or publicity adversely affecting our ability to maintain our relationships with our suppliers, service providers, customers, employees, and other third parties;

• our new capital structure and the adoption of fresh start accounting, including the risk that assumptions and factors used in estimating enterprise value vary significantly from the current estimates in connection with the application of fresh start accounting;

• plans, objectives, expectations and intentions contained in this report that are not historical;

• our ability to become listed on the OTCQX or a national securities exchange;

• our ability to execute our business plan in the current depressed commodity price environment;

• the decline in and volatility of commodity prices for oil, natural gas liquids, or NGLs, and natural gas;

• our ability to develop, explore for, acquire and replace oil and natural gas reserves and sustain production;

• our ability to generate profits or achieve targeted reserves in our development and exploratory drilling and well operations;

• any impairments, write-downs or write-offs of our reserves or assets;

• the resumption of our drilling program;

• the projected demand for and supply of oil, NGLs and natural gas;

• our ability to contract for drilling rigs, supplies and services at reasonable costs;

• our ability to obtain adequate pipeline transportation capacity for our oil and gas production at reasonable cost and to sell our production at, or at reasonable discounts to, market prices;

• the uncertainties inherent in projecting future rates of production for our wells and the extent to which actual production differs from estimated proved oil and natural gas reserves;

• drilling and operating risks;

• our ability to compete effectively against other oil and gas companies;

• leasehold terms expiring before production can be established and our ability to replace expired leases;

• environmental obligations, costs and liabilities that are not covered by an effective indemnity or insurance;

• the timing of receipt of necessary regulatory permits;

• the effect of commodity and financial derivative arrangements;

• the occurrence of unusual weather or operating conditions, including force majeure events;

• our ability to retain or attract senior management and key employees;

• counterparty risk related to the ability of these parties to meet their future obligations;

• compliance with and changes in governmental regulations or enforcement practices, especially with respect to environmental, health and safety matters;

• physical, electronic and cybersecurity breaches;

• uncertainties relating to general domestic and international economic and political conditions; and

• other factors set forth in our periodic filings with the Securities and Exchange Commission, including the risks set forth in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2015 and Item 1A of Part II of this Quarterly Report on Form 10-Q.

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Additional information concerning these and other factors can be found in our press releases and public periodic filings with the Securities and Exchange Commission. Many of the factors that will determine our future results are beyond the ability of management to control or predict. Readers should not place undue reliance on forward-looking statements, which reflect management’s views only as of the date hereof. All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these cautionary statements. We undertake no obligation to revise or update any forward-looking statements, or to make any other forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by applicable law.

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

The following discussion and analysis of the financial condition and results of operations of Penn Virginia Corporation and its subsidiaries (“Penn Virginia,” the “Company,” “we,” “us” or “our”) should be read in conjunction with our Condensed Consolidated Financial Statements and Notes thereto included in Part I, Item 1, “Financial Statements.” All dollar amounts presented in the tables that follow are in thousands unless otherwise indicated. Also, due to the combination of different units of volumetric measure, the number of decimal places presented and rounding, certain results may not calculate explicitly from the values presented in the tables.

Overview and Executive Summary

We are an independent oil and gas company engaged in the exploration, development and production of oil, NGLs and natural gas. Our current operations consist primarily of drilling unconventional horizontal development wells and operating our producing wells in the Eagle Ford Shale, or the Eagle Ford, in South Texas. Our operations are substantially concentrated with over 90 percent of our production, revenues and capital expenditures being attributable to this region. We also have less significant operations in Oklahoma, primarily non-operated properties in the Granite Wash. In August 2016, we terminated our remaining operations in the Marcellus Shale in Pennsylvania and are currently in the process of remediating the sites of our former wells in that region.

As discussed in further detail in Note 4 to our Condensed Consolidated Financial Statements, we have adopted and applied the relevant guidance with respect to the accounting and financial reporting for entities that have emerged from bankruptcy proceedings, or Fresh Start Accounting. Accordingly, our Condensed Consolidated Financial Statements and Notes after September 12, 2016, are not comparable to the Condensed Consolidated Financial Statements and Notes prior to that date. To facilitate our discussion and analysis of our financial condition and results of operations herein, we refer to the reorganized company as the “Successor” for periods subsequent to September 12, 2016, and “Predecessor” for periods prior to September 13, 2016. Furthermore, our presentations herein include a “black line” division to delineate the lack of comparability between the Predecessor and Successor. In order to facilitate our discussion herein, we have addressed the Successor and Predecessor periods discretely and have provided comparative analysis, to the extent that it is practical, where appropriate. In addition, and as referenced in Note 7 to the Condensed Consolidated Financial Statements, we have adopted the full cost method of accounting for our oil and gas properties effective with our adoption of Fresh Start Accounting. Accordingly, our results of operations and financial position for the Successor periods will be substantially different from our historic trends.

The following table sets forth certain summary operating and financial statistics for the periods presented: 

	Successor			Predecessor						Successor			Predecessor
							Three Months									Nine Months
	September 13 to			July 1 to			Ended			September 13 to			January 1 to			Ended
	September 30,			September 12,			September 30,			September 30,			September 12,			September 30,
	2016			2016			2015			2016			2016			2015
Total production (MBOE)	183			796			1,930			183			3,346			6,295
Average daily production (BOEPD)	10,145			10,752			20,976			10,145			13,071			23,058
Crude oil and NGL production (MBbl)	154			680			1,537			154			2,844			4,934
Crude oil and NGL production as a percent of total	84		%	85		%	80		%	84		%	85		%	78		%
Product revenues	$	6,316		$	26,961		$	60,690		6,316			$	93,649		$	216,948
Realized prices:
Crude oil ($ per Bbl)	$	43.35		$	42.75		$	42.42		$	43.35		$	35.21		$	47.35
NGLs ($ per Bbl)	$	12.56		$	12.66		$	9.81		$	12.56		$	11.37		$	12.45
Natural gas ($ per Mcf)	$	2.73		$	2.72		$	2.68		$	2.73		$	2.06		$	2.71
Aggregate ($ per BOE)	$	34.59		$	33.89		$	31.45		$	34.59		$	27.99		$	34.46
Lease operating ($ per BOE)	$	4.13		$	5.29		$	5.86		$	4.13		$	4.67		$	5.37
Gathering, processing and transportation ($ per BOE)	$	3.15		$	5.99		$	2.93		$	3.15		$	3.96		$	3.10
Production and ad valorem taxes ($ per BOE)	$	2.05		$	0.72		$	1.80		$	2.05		$	1.04		$	2.09
General and administrative ($ per BOE) 1	$	8.07		$	15.30		$	4.88		$	8.07		$	11.64		$	5.22
Depreciation, depletion and amortization ($ per BOE)	$	11.09		$	10.08		$	39.82		$	11.09		$	10.04		$	40.20

¹ Includes the effects of share-based compensation and other significant charges. See discussion of our Results of Operations that follow for additional detail.

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Key Developments

The following corporate actions and general business developments had or may have a significant impact on the financial reporting and disclosure of our results of operations, financial position and cash flows:

Chapter 11 Proceedings

On May 12, 2016, or the Petition Date, we and eight of our subsidiaries, or the Chapter 11 Subsidiaries, filed voluntary petitions (In re Penn Virginia Corporation, et al, Case No. 16-32395) seeking relief under Chapter 11 of Title 11 of the United States Bankruptcy Code, or the Bankruptcy Code in the United States Bankruptcy Court for the Eastern District of Virginia, or the Bankruptcy Court.

On August 11, 2016, or the Confirmation Date, the Bankruptcy Court confirmed our Second Amended Joint Chapter 11 Plan of Reorganization of Penn Virginia Corporation and its Debtor Affiliates, or the Plan, and we subsequently emerged from bankruptcy on September 12, 2016, or the Effective Date.

Debtors-In-Possession. From the Petition Date through the Effective Date, we and the Chapter 11 Subsidiaries operated our business as debtors-in-possession in accordance with the applicable provisions of the Bankruptcy Code. The Bankruptcy Court granted all “first day” motions filed by us and the Chapter 11 Subsidiaries, which were designed primarily to minimize the impact of the Chapter 11 proceedings on our normal day-to-day operations, our customers, regulatory agencies, including taxing authorities, and employees. As a result, we were able to conduct normal business activities and pay all associated obligations for the post-petition period and we were also authorized to pay and have paid (subject to limitations applicable to payments of certain pre-petition obligations) pre-petition employee wages and benefits, pre-petition amounts owed to certain lienholders, amounts due to taxing authorities for production and other related taxes and funds belonging to third parties, including royalty and working interest holders.

Pre-Petition Agreements. Immediately prior to the Petition Date, the holders, or the Ad Hoc Committee, of approximately 86 percent of the $1,075 million principal amount of our 7.25% Senior Notes due 2019, or the 2019 Senior Notes, and 8.50% Senior Notes due 2020, or the 2020 Senior Notes, and, together with the 2019 Senior Notes, or the Senior Notes agreed to a restructuring support agreement, or the RSA, that set forth the general framework of the Plan and the timeline for the Chapter 11 proceedings. In addition, we entered into a backstop commitment agreement, or the Backstop Commitment Agreement, with the parties thereto, or collectively, the Backstop Parties, pursuant to which the Backstop Parties committed to provide a $50.0 million commitment to backstop a rights offering, or the Rights Offering, that was conducted in connection with the Plan.

Plan of Reorganization. Pursuant to the terms of the Plan, which was supported by us, the holders, or the RBL Lenders, of 100 percent of the claims attributable to our pre-petition revolving credit agreement, as amended, or the RBL, the Ad Hoc Committee and the Official Committee of Unsecured Claimholders, or the UCC, the following transactions were completed subsequent to the Confirmation Date and prior to or at the Effective Date:

• the approximately $1,122 million of indebtedness, including accrued interest, attributable to our Senior Notes and certain other unsecured claims were exchanged for 6,069,074 shares representing 41 percent of the Successor’s common stock, or New Common Stock;

• a total of $50 million of proceeds were received on the Effective Date from the Rights Offering resulting in the issuance of 7,633,588 shares representing 51 percent of New Common Stock to holders of claims arising under the Senior Notes, certain holders of general unsecured claims and to the Backstop Parties;

• the Backstop Parties received a backstop fee comprised of 472,902 shares representing three percent of New Common Stock;

• an additional 816,454 shares representing five percent of New Common Stock were authorized for disputed general unsecured claims and non-accredited investor holders of the Senior Notes and 749,600 shares representing five percent of the New Common Stock outstanding were reserved for issuance under a new management incentive plan;

• on the Effective Date, we entered into a shareholders agreement and a registration rights agreement and amended our articles of incorporation and bylaws for the authorization of the New Common Stock and to provide customary registration rights thereunder, among other corporate governance actions;

• holders of claims arising under the RBL were paid in full from cash on hand, $75.4 million from borrowings under our new revolving credit agreement, or the Revolver, (see Note 8 to the Condensed Consolidated Financial Statements) and proceeds from the Rights Offering;

• the debtor-in-possession credit facility, or DIP Facility, under which there were no outstanding borrowings at any time from the Petition Date through the Effective Date, was canceled and less than $0.1 million in fees were paid in full in cash;

• certain other priority claims were paid in full in cash, reinstated or otherwise treated in a manner acceptable to the creditor claim-holders;

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• a cash reserve of $2.7 million was established for certain other secured, priority or convenience claims pending resolution as of the Effective Date;

• an escrow account for professional service fees attributable to our advisers and those of the UCC was funded by us with cash of $14.6 million, and we paid $7.2 million for professional fees and expenses on behalf of the RBL Lenders, the Ad Hoc Committee and the indenture trustee for the Senior Notes;

• on the Effective Date, our previous interim Chief Executive Officer, Edward B. Cloues, and each member of our board of directors resigned and was replaced by three new board members: Darin G. Holderness, CPA, Marc McCarthy and Harry Quarls;

• our Predecessor preferred stock and common stock was canceled, extinguished and discharged; and

• all of our Predecessor share-based compensation plans and supplemental employee retirement plan, or the SERP, entitlements were canceled.

While our emergence from bankruptcy is effectively complete, certain administrative activities will continue under the authority of the Bankruptcy Court for the next several months.

Production and Development Plans

Total production for the quarter ended September 30, 2016 was 979 thousand barrels of oil equivalent, or MBOE, or 10,629 barrels of oil equivalent per day, or BOEPD, with 85 percent of production comprised of oil and NGLs, 183 MBOE of which was attributable to the Successor and 796 MBOE of which was attributable to the Predecessor. Production from our Eagle Ford operations during this period was 889 MBOE or 9,659 BOEPD, 165 MBOE of which was attributable to the Successor and 724 MBOE of which was attributable to the Predecessor. Approximately 75 percent of our Eagle Ford production for this combined period was from crude oil, 15 percent was from NGLs and 10 percent was from natural gas. Production from Eagle Ford operations was approximately 91 percent of total Company production during this combined period and was derived from 301 operated and 36 outside-operated legacy wells. We did not drill or complete a well during this period and the last completed well was brought to sales in February 2016.

We intend to restart Eagle Ford shale drilling by the end of November with a one-rig development program. We plan to initially focus on the Sable 6-H, the third well of a three-well pad located two-and-a-half miles southwest of, and on-strike with, our successful three-well Hawg Hunter pad, and completing all three Sable wells before year-end 2016. Following the Sable, we anticipate drilling the three-well Axis pad in the fourth quarter of 2016 with production commencing in the first quarter of 2017.

Our initial 2017 plan, which is subject to commodity prices, anticipates drilling 16 to 19 net lower Eagle Ford wells with 13 to 16 net wells turned to sales during the year. This is based on 2017 capital expenditures of up to $115 million of which 85 percent will be directed to development drilling and completion expenditures. We expect to fund capital spending primarily from cash from operating activities.

As of November 1, 2016, we had 81,593 gross (53,045 net) Eagle Ford acres largely held by production. An additional 33,623 gross (28,491 net) Eagle Ford acres may be deemed non-core and are subject to expire by year-end 2017. We also had 15,014 gross (7,141 net) acres in the Granite Wash as of November 1, 2016.

Amended Gathering and Transportation Agreements

In August 2016, the Bankruptcy Court approved a settlement with Republic Midstream, LLC, or Republic Midstream, and Republic Midstream Marketing, LLC, or Republic Marketing, and, together with Republic Midstream, collectively, Republic, and authorized the assumption of certain amended agreements with Republic, or Amended Agreements. We paid Republic $0.3 million in connection with the settlement which is included in “Reorganization items, net” in our Condensed Consolidated Statements of Operations.

Under the terms of the Amended Agreements, Republic is obligated to gather and transport our crude oil and condensate from within a dedicated area in the Eagle Ford, or Dedication Area, via a gathering system and intermediate takeaway pipeline connecting to a downstream interstate pipeline operated by a third party. The amended gathering agreement reduced our minimum volume commitment from 15,000 to 8,000 barrels of oil per day. The term of the amended gathering agreement runs through 2041, with the term of the minimum volume commitment extended from 10 to 15 years.

Under the amended marketing agreement, we have a 10-year commitment to sell 8,000 barrels per day of crude oil to Republic, or any third party, utilizing Republic Marketing’s capacity on a certain downstream interstate pipeline.

Excluding the potential impact of the effects of price escalation from commodity price changes, the minimum fee requirements under the Amended Agreements are as follows: $3.9 million for the remainder of 2016, $9.6 million for 2017, $10.4 million for 2018, $11.7 million for 2019, $13.0 million for 2020 through 2025, $7.4 million for 2026, $3.8 million for 2027 through 2030 and $2.2 million for 2031.

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Cost Reduction Initiatives

We have taken significant measures in 2016 to significantly reduce our drilling, operating and support costs. In conjunction with our reorganization through Chapter 11 bankruptcy, we have renegotiated a number of contracts with vendors and service providers to bring costs in line with current market conditions. Other initiatives include reductions in force and, at the corporate level, we have also undertaken significant staff reductions.

In connection with efforts to reduce our administrative costs, we took certain actions to reduce our total employee headcount. In February, June and September, we reduced our total employee headcount by 45 employees. We paid a total of $1.9 million, including $1.2 million in severance and termination benefits and $0.7 million in retention bonuses during the nine months ended September 2016, and $0.1 million in severance and termination benefits during October 2016. The employment of nine employees scheduled for termination was extended with a payout of $0.2 million in retention bonuses, included in the above retention. Estimated severance and termination benefits for these employees is expected to be $0.3 million. The affected employees must continue to provide services through each of their extension dates in order to receive these benefits. Accordingly, we incurred a charge and established an accrual representing the period for which these benefits have been earned.

Commodity Hedging Program

We hedged a substantial portion of our future crude oil production through the end of 2019. Our weighted-average hedge prices is approximately $47.69 per barrel for the remainder of 2016, $48.62 per barrel for 2017, $49.12 per barrel for 2018 and $49.90 per barrel for 2019. We are currently unhedged with respect to natural gas production.

Stock Listing

Trading in our common stock on the NYSE was suspended and subsequently delisted in January 2016. Our common stock was traded on the OTC Pink marketplace under the symbol “PVAH” until the common stock was canceled on September 12, 2016, in connection with our emergence from bankruptcy. Our New Common Stock is currently trading on the OTC Pink marketplace under the symbol “PVAC.” We anticipate that New Common Stock will commence trading on the OTCQX by the end of November in anticipation of subsequently listed on a national securities exchange. We can provide no assurance that the New Common Stock will trade on a nationally recognized market, whether the trading volume on an over-the-counter market of the New Common Stock will be sufficient to provide for an efficient trading market or whether quotes for the New Common Stock may be blocked by OTC Markets Group in the future.

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Financial Condition

Liquidity

Our primary sources of liquidity include our cash on hand, cash provided by operating activities and borrowings under the Revolver. The Revolver provides us with up to $200 million in borrowing commitments. The initial borrowing base under the Revolver is $128 million. As of November 14, 2016, we had $88.2 million of availability under the Revolver.

Our cash flows from operating activities are subject to significant volatility due to changes in commodity prices for our crude oil, NGL and natural gas products, as well as variations in our production. The prices for these commodities are driven by a number of factors beyond our control, including global and regional product supply and demand, weather, product distribution, refining and processing capacity and other supply chain dynamics, among other factors. The level of our hedging activity and duration of the instruments employed depend on our desired cash flow protection, available hedge prices, the magnitude of our capital program and our operating strategy.

In order to mitigate this volatility, we entered into a series of new derivatives contracts in May 2016 and hedged a substantial portion of our future crude oil production through the end of 2019. Our weighted-average hedge prices are $47.69 per barrel for the remainder of 2016, $48.62 per barrel for 2017, $49.12 per barrel for 2018 and $49.90 per barrel for 2019. Our natural gas hedges expired in 2015 and we are currently unhedged with respect to natural gas production.

Capital Resources

Our business plan for the remainder of 2016 is attributable exclusively to the re-start of our drilling program in the Eagle Ford. For 2017, we currently anticipate capital expenditures of up to $115 million of which 85 percent will be directed to development drilling and completion expenditures. We expect to fund capital spending primarily with cash from operating activities. We do not anticipate any additional borrowing under the Revolver for the reminder of the year for purposes other than temporary liquidity needs. For a detailed analysis of our historical capital expenditures, see the “Cash Flows” discussion that follows.

Cash on Hand and Cash From Operating Activities. As of November 11, 2016, we had $7.6 million of cash on hand. As discussed further above, we have actively managed our exposure to commodity price fluctuations by hedging the commodity price risk for a portion of our expected production.

Revolver Borrowings. We initially borrowed $75.4 million under the Revolver on the Effective Date. Since that time we have paid down $36.4 million. For additional information regarding the terms and covenants under the Revolver, see the “Capitalization” discussion that follows.

The following table summarizes our borrowing activity under the RBL through September 12, 2016 and the Revolver from the Effective Date through September 30, 2016 during the periods presented:

	Borrowings Outstanding
	Weighted- Average		Maximum		Weighted- Average Rate
Predecessor
Period from July 1, 2016 to September 12, 2016	$	112,749	$	113,653	5.9860	%
Period from January 1, 2016 to September 12, 2016	$	134,263	$	170,000	4.4180	%
Successor
Period from September 12, 2016 to September 30, 2016	$	70,187	$	75,350	4.3040	%

Proceeds from Sales of Assets. We continually evaluate potential sales of non-core assets, including certain oil and gas properties and non-strategic undeveloped acreage, among others.

Capital Market Transactions. Form time-to-time and under market conditions that we believe are favorable to us, we may consider capital market transactions, including the offering of debt and equity securities.

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Cash Flows

The following table, summarizes our cash flows for the periods presented:

	Successor			Predecessor
							Nine Months
	September 13 to			January 1 to			Ended
	September 30,			September 12,			September 30,
	2016			2016			2015
Cash flows from operating activities
Operating cash flows, net of of working capital changes	$	4,782		$	34,731		$	110,451
Commodity derivative settlements received, net:
Crude oil	—			48,008			103,909
Natural gas	—			—			681
Interest payments, net of amounts capitalized	—			(4,148		)	(42,635		)
Income taxes received (paid)	—			35			(7		)
Drilling rig termination charges paid	—			—			(6,416		)
Strategic, financial and bankruptcy-related advisory fees and costs paid	—			(46,606		)	(1,195		)
Restructuring and exit costs paid	(1,202		)	(1,773		)	(2,547		)
Net cash provided by operating activities	3,580			30,247			162,241
Cash flows from investing activities
Capital expenditures	—			(15,359		)	(324,876		)
Proceeds from sales of assets, net	—			224			73,670
Other, net	—			1,186			—
Net cash used in investing activities	—			(13,949		)	(251,206		)
Cash flows from financing activities
(Repayments) proceeds from revolving credit facility borrowings, net	(21,000		)	(43,771		)	105,000
Debt issuance costs paid	—			(3,011		)	(744		)
Proceeds from rights offering, net	—			49,943			—
Dividends paid on preferred stock	—			—			(18,201		)
Net cash (used in) provided by financing activities	(21,000		)	3,161			86,055
Net (decrease) increase in cash and cash equivalents	$	(17,420	)	$	19,459		$	(2,910	)

Cash Flows From Operating Activities. The Successor period, which represents the last 18 days in September 2016, included cash receipts and disbursements attributable to our normal monthly operating cycle for product revenues and joint venture billing collections net of payments for royalties, lease operating expenses, gathering, processing and transportation expenses, severance taxes and general and administrative expenses. This period also included $1.2 million paid for severance and termination benefits as well as retention bonuses. There were no derivative transactions that settled during this period nor were there any interest or income tax payments.

Aggregate average commodity prices declined approximately 18 percent during the Predecessor period in 2016 compared to the corresponding Predecessor period in 2015 and production declined due primarily to the suspension of our Eagle Ford drilling program in February 2016, natural production declines and the sale of our East Texas assets in August 2015 and certain other properties in the Eagle Ford and Mid-Continent region in October 2015. The combined effect of these factors in the Predecessor period ended September 12, 2016, excluding the minimal net cash impact of the additional 18 days during the 2015 Predecessor period, contributed to the substantial reduction in the realized cash receipts from our production revenues when compared to the 2015 Predecessor period. During the 2016 Predecessor period, we incurred and paid substantially higher professional fees and other costs associated with our consideration of strategic financing alternatives and our bankruptcy proceedings. In addition, we received lower settlements from derivatives during the 2016 period due primarily to: (i) lower spreads between hedge and realized prices on our post-petition derivatives, (ii) lower overall crude oil volumes hedged, (iii) the early termination of our entire pre-petition portfolio of 2016 derivative contracts, most of the proceeds from which were directly provided to the RBL lenders to pay down borrowings under the RBL, prior to the Petition Date, and (iv) the expiration of our natural gas hedges in the 2015 Predecessor period. The overall decline in operating cash flows was partially offset by the suspension of interest payments on the Senior Notes in connection with the bankruptcy proceedings. Also partially offsetting the decline in operating cash flows was the reduction in amounts paid to release operated drilling rigs.

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Cash Flows From Investing Activities. As illustrated in the tables below, our cash payments for capital expenditures were substantially lower during the 2016 Predecessor period compared to the nine months ended September 30, 2015 due primarily to the suspension of our capital program in February 2016. Furthermore, the 2016 Predecessor period includes substantially lower settlements of accrued capital charges from the prior year-end period. The 2016 Predecessor period also includes insurance recoveries from a casualty loss incurred in 2015. The 2015 Predecessor period includes $73.7 million of net proceeds received from the sale of assets which were primarily attributable to the sale of our East Texas assets.

The following table sets forth costs related to our capital program for the periods presented:

	Successor		Predecessor
						Nine Months
	September 13 to		January 1 to			Ended
	September 30,		September 30,			September 30,
	2016		2016			2015
Oil and gas:
Drilling and completion	$	—	$	3,696		$	262,130
Lease acquisitions and other land-related costs 1	—		58			13,587
Pipeline, gathering facilities and other equipment	—		375			3,634
Geological, geophysical (seismic) and delay rental costs	—		(16		)	836
	—		4,113			280,187
Other – Corporate	—		—			526
Total capital program costs	$	—	$	4,113		$	280,713

______________________

¹ Includes site preparation and other pre-drilling costs.

The following table reconciles the total costs of our capital program with the net cash paid for capital expenditures for additions to property and equipment as reported in our Condensed Consolidated Statements of Cash Flows for the periods presented:

	Successor		Predecessor
						Nine Months
	September 13 to		January 1 to			Ended
	September 30,		September 30,			September 30,
	2016		2016			2015
Total capital program costs	$	—	$	4,113		$	280,713
Decrease in accrued capitalized costs	—		11,301			41,800
Less:
Exploration costs charged to operations:
Geological, geophysical (seismic) and delay rental costs	—		16			(836		)
Transfers from tubular inventory and well materials	—		(465		)	(4,154		)
Add:
Tubular inventory and well materials purchased in advance of drilling	—		211			2,499
Capitalized interest	—		183			4,854
Total cash paid for capital expenditures	$	—	$	15,359		$	324,876

Cash Flows From Financing Activities. Cash flows from financing activities for the nine months ended September 30, 2016 included repayments of $119.1 million under the RBL and borrowings, net of repayments, of $54.4 million under the Revolver while the 2015 period included net borrowings of $105 million under the RBL. We also realized net proceeds of $49.9 million from the Rights Offering that were used to pay down the RBL. We did not pay dividends on the Series A Preferred Stock and Series B Preferred Stock during the nine months ended September 30, 2016 while the 2015 period includes dividend payments of $18.2 million.

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Capitalization

The following table summarizes our total capitalization as of the date presented:

	Successor
	September 30,
	2016
Revolving credit facility	$	54,350
Total debt	54,350
Shareholders’ equity	187,454
	$	241,804
Debt as a % of total capitalization	22		%

Revolving Credit Facility. The outstanding borrowings under the Revolver bear interest at a rate equal to, at our option, either (a) a customary reference rate plus an applicable margin ranging from 2.00% to 3.00%, determined based on the average availability under the Revolver or (b) a customary London interbank offered rate, or LIBOR, plus an applicable margin ranging from 3.00% to 4.00%, determined based on the average availability under the Revolver. Interest on reference rate borrowings is payable quarterly in arrears and is computed on the basis of a year of 365/366 days, and interest on eurocurrency borrowings is payable every one, three or six months, at the election of the Borrower, and is computed on the basis of a 360-day year. As of September 30, 2016, the actual interest rate applicable to the Revolver was 3.770%, which is derived from an Adjusted LIBOR rate of 0.520% plus an applicable margin of 3.250%. Unused commitment fees are charged at a rate of 0.5%.

The Revolver is guaranteed by us and all of our subsidiaries, or the Guarantor Subsidiaries. The guarantees under the Revolver are full and unconditional and joint and several. Substantially all of our consolidated assets are held by the Guarantor Subsidiaries. The parent company has no material independent assets or operations. The obligations under the Revolver are secured by a first priority lien on substantially all of our assets.

Covenant Compliance. The Revolver requires us to maintain (1) a minimum interest coverage ratio (adjusted earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses as defined in the Revolver, or adjusted EBITDAX, to adjusted interest expense), measured as of the last day of each fiscal quarter, of 3.00 to 1.00, (2) a minimum current ratio (as defined in the Revolver), measured as of the last day of each fiscal quarter of 1.00 to 1.00, and (3) a maximum leverage ratio (consolidated indebtedness to adjusted EBITDAX), measured as of the last day of each fiscal quarter, initially of 4.00 to 1.00, decreasing on December 31, 2017 to 3.75 to 1.00 and on March 31, 2018 and thereafter to 3.50 to 1.00. In accordance with the terms of the Revolver, the quarter ending December 31, 2016 will be the first period for which we are required to comply with these covenants.

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Results of Operations

Production

The following tables set forth a summary of our total and daily production volumes by product and geographic region for the periods presented: 

	Total Production			Average Daily Production
	Successor	Predecessor		Successor	Predecessor
			Three Months			Three Months
	September 13 to	July 1 to	Ended	September 13 to	July 1 to	Ended
	September 30,	September 12,	September 30,	September 30,	September 12,	September 30,
	2016	2016	2015	2016	2016	2015
	(Total volume)			(Volume per day)
Crude oil (MBbl & BOPD)	127	547	1,205	7,060	7,394	13,098
NGLs (MBbl and BOPD)	27	133	332	1,473	1,793	3,605
Natural gas (MMcf and MMcfpd)	174	695	2,358	10	9	26
Total (MBOE and BOEPD)	183	796	1,930	10,145	10,752	20,976
			Three Months			Three Months
	September 13 to	July 1 to	Ended	September 13 to	July 1 to	Ended
	September 30,	September 12,	September 30,	September 30,	September 12,	September 30,
	2016	2016	2015	2016	2016	2015
	(MBOE)			(BOE per day)
South Texas 1	164	724	1,705	9,131	9,788	18,528
Mid-Continent and other 2	18	71	122	1,014	964	1,328
Divested properties 3	—	—	103	—	—	1,119
	183	796	1,930	10,145	10,752	20,976
			Nine Months			Nine Months
	September 13 to	January 1 to	Ended	September 13 to	January 1 to	Ended
	September 30,	September 12,	September 30,	September 30,	September 12,	September 30,
	2016	2016	2015	2016	2016	2015
	(Total volume)			(Volume per day)
Crude oil (MBbl & BOPD)	127	2,311	3,822	7,060	9,028	14,000
NGLs (MBbl and BOPD)	27	533	1,112	1,473	2,082	4,074
Natural gas (MMcf and MMcfpd)	174	3,012	8,165	10	12	30
Total (MBOE and BOEPD)	183	3,346	6,295	10,145	13,071	23,058
			Nine Months			Nine Months
	September 13 to	January 1 to	Ended	September 13 to	January 1 to	Ended
	September 30,	September 12,	September 30,	September 30,	September 12,	September 30,
	2016	2016	2015	2016	2016	2015
	(MBOE)			(BOE per day)
South Texas 1	164	3,071	5,473	9,131	11,995	20,049
Mid-Continent and other 2	18	276	373	1,014	1,077	1,365
Divested properties 3	—	—	449	—	—	1,644
	183	3,346	6,295	10,145	13,071	23,058

_______________________

¹ The three and nine months ended September 30, 2015 include total production and average daily production of approximately 24 MBOE (256 BOEPD) and 89 MBOE (326 BOEPD) attributable to non-core Eagle Ford properties that we sold in October 2015.

²  The three and nine months ended September 30, 2015 include total production and average daily production of approximately 5 MBOE (58 BOEPD) and 20 MBOE (72 BOEPD) attributable to certain Mid-Continent properties that we sold in October 2015. Also includes total production and average daily production of approximately 0.9 MBOE (29 BOEPD) and 10 MBOE (43 BOEPD) and 5 MBOE (58 BOEPD) and 16 MBOE (60 BOEPD) for each of the Predecessor periods presented, respectively, attributable to our three Marcellus Shale wells.

³  The three and nine months ended September 30, 2015 include total production and average daily production attributable to our former East Texas assets that were sold in August 2015.

Total production decreased during the Successor and Predecessor periods in 2016 when compared to the three and nine months ended September, 2015 due primarily to the suspension of our drilling program in February 2016, natural production declines in all of our operating regions and the sale of our East Texas assets in August 2015 and other non-core Eagle Ford and certain Mid-Continent properties in October 2015. Approximately 70 percent of total production during the Successor and Predecessor periods in 2016 was attributable to oil when compared to approximately 62 percent and 61 percent during the three

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and nine month periods in 2015. Our Eagle Ford production represented over 90 percent of our total production during the Successor and Predecessor periods in 2016 when compared to approximately 88 percent from this region during the three and nine month periods in 2015.

Product Revenues and Prices

The following tables set forth a summary of our revenues and prices per unit of volume by product and geographic region for the periods presented:

	Successor		Predecessor				Successor		Predecessor
					Three Months						Three Months
	September 13 to		July 1 to		Ended		September 13 to		July 1 to		Ended
	September 30,		September 12,		September 30,		September 30,		September 12,		September 30,
	2016		2016		2015		2016		2016		2015
							($ per Unit of volume)
Crude oil (Total and $ per Bbl)	$	5,508	$	23,392	$	51,124	$	43.35	$	42.75	$	42.42
NGLs (Total and $ per Bbl)	333		1,680		3,254		$	12.56	$	12.66	$	9.81
Natural gas (Total and $ per Mcf)	475		1,889		6,312		$	2.73	$	2.72	$	2.68
Total (Total and $ per BOE)	$	6,316	$	26,961	$	60,690	$	34.59	$	33.89	$	31.45
					Three Months						Three Months
	September 13 to		July 1 to		Ended		September 13 to		July 1 to		Ended
	September 30,		September 12,		September 30,		September 30,		September 12,		September 30,
	2016		2016		2015		2016		2016		2015
							($ per BOE)
South Texas 1	$	5,955	$	25,448	$	56,412	$	36.31	$	35.15	$	33.09
Mid-Continent and other 2	361		1,513		2,459		$	20.06	$	21.31	$	20.12
Divested properties 3	—		—		1,819		$	—	$	—	$	17.67
	$	6,316	$	26,961	$	60,690	$	34.51	$	33.87	$	31.45
					Nine Months						Nine Months
	September 13 to		January 1 to		Ended		September 13 to		January 1 to		Ended
	September 30,		September 12,		September 30,		September 30,		September 12,		September 30,
	2016		2016		2015		2016		2016		2015
							($ per Unit of volume)
Crude oil (Total and $ per Bbl)	$	5,508	$	81,377	$	180,964	$	43.35	$	35.21	$	47.35
NGLs (Total and $ per Bbl)	333		6,064		13,841		$	12.56	$	11.37	$	12.45
Natural gas (Total and $ per Mcf)	475		6,208		22,143		$	2.73	$	2.06	$	2.71
Total (Total and $ per BOE)	$	6,316	$	93,649	$	216,948	$	34.59	$	27.99	$	34.46
					Nine Months						Nine Months
	September 13 to		January 1 to		Ended		September 13 to		January 1 to		Ended
	September 30,		September 12,		September 30,		September 30,		September 12,		September 30,
	2016		2016		2015		2016		2016		2015
							($ per BOE)
South Texas 1	$	5,955	$	88,849	$	200,740	$	36.31	$	28.93	$	36.68
Mid-Continent and other 2	361		4,800		8,048		$	20.06	$	17.39	$	21.60
Divested properties 3	—		—		8,160		$	—	$	—	$	18.18
	$	6,316	$	93,649	$	216,948	$	34.51	$	27.99	$	34.46

_______________________

¹ The three and nine months ended September 30, 2015 include revenues of $1.0 million and $4.1 million attributable to non-core Eagle Ford properties that we sold in October 2015.

²  The three and nine months ended September 30, 2015 include revenues of $0.1 million and $0.4 million attributable to certain Mid-Continent properties that we sold in October 2015 as well as revenues of less than $0.1 million attributable to the Marcellus Shale for each of the Predecessor periods presented.

³  The three and nine months ended September 30, 2015 include revenues attributable to our former East Texas assets that were sold in August 2015.

Our product revenues declined substantially during the Successor and Predecessor periods in 2016 as compared to the three and nine month periods ended September 30, 2015 due primarily to the significant decline in production volume as discussed above. While we experienced nominal pricing improvement during the Successor period as well as the Predecessor period from July 1, 2016 to September 12, 2016 when compared to the three months ended September 30, 2015, the effect of an aggregate pricing decline during the Predecessor period from January 1, 2016 through September 12, 2016 was unfavorable when compared to the nine months ended September 30, 2015.

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Effects of Derivatives

The following table reconciles crude oil and natural gas revenues to realized prices, as adjusted for derivative activities, for the periods presented: 

	Successor		Predecessor				Successor		Predecessor
					Three Months						Nine Months
	September 13 to		July 1 to		Ended		September 13 to		January 1 to		Ended
	September 30,		September 12,		September 30,		September 30,		September 12,		September 30,
	2016		2016		2015		2016		2016		2015
Crude oil revenues as reported	$	5,508	$	23,392	$	51,124	$	5,508	$	81,377	$	180,964
Derivative settlements, net	—		1,056		32,258		—		48,008		103,909
	$	5,508	$	24,448	$	83,382	$	5,508	$	129,385	$	284,873
Crude oil prices per Bbl	$	43.35	$	42.75	$	42.42	$	43.35	$	35.21	$	47.35
Derivative settlements per Bbl	—		1.93		26.77		—		20.77		27.19
	$	43.35	$	44.68	$	69.19	$	43.35	$	55.98	$	74.54
Natural gas revenues as reported	$	475	$	1,889	$	6,312	$	475	$	6,208	$	22,143
Derivative settlements, net	—		—		—		—		—		681
	$	475	$	1,889	$	6,312	$	475	$	6,208	$	22,824
Natural gas prices per Mcf	$	2.73	$	2.72	$	2.68	$	2.73	$	2.06	$	2.71
Derivative settlements per Mcf	—		—		—		—		—		0.08
	$	2.73	$	2.72	$	2.68	$	2.73	$	2.06	$	2.79

Gain on Sales of Property and Equipment

The Predecessor periods in 2016 include the amortization of deferred gains from our 2014 sale of rights to construct a crude oil gathering and intermediate transportation system, which began in April 2016 when the associated central delivery point, or CDP, facilities became operational. The amortization of deferred gains from the 2014 sale of our South Texas natural gas gathering and gas lift assets is included for all Predecessor periods presented. As of the Effective Date, the unamortized portion of the deferred gains were reversed from our Condensed Consolidated Balance Sheet in connection with our application of Fresh Start Accounting and included as a component of Reorganization items, net.

Other Revenues

Other revenues, which includes gathering, transportation, marketing, compression, water supply and disposal fees that we charge to third parties, net of marketing and related expenses as well as accretion, through the Predecessor period, of our unused firm transportation obligation, decreased during the Successor and Predecessor periods in 2016 from the three and nine months ended September 30, 2015 due primarily to substantially lower drilling activity in our service areas. Certain of these revenue sources also declined following the sale of our assets in East Texas in August 2015. In addition, we realized lower water supply and disposal fees in the South Texas region during the Successor and Predecessor periods in 2016. We also provided for reserves of certain of our receivables from joint venture partners in the Predecessor periods in 2016 which are presented as contra-revenue items in this caption.

Lease Operating

	Successor		Predecessor				Successor		Predecessor
					Three Months						Nine Months
	September 13 to		July 1 to		Ended		September 13 to		January 1 to		Ended
	September 30,		September 12,		September 30,		September 30,		September 12,		September 30,
	2016		2016		2015		2016		2016		2015
Lease operating	$	756	$	4,209	$	11,304	$	756	$	15,626	$	33,780
Per unit of production ($/BOE)	4.13		5.29		5.86		$	4.13	$	4.67	$	5.37

Lease operating expense, or LOE, decreased during the Successor and Predecessor periods in 2016 on an absolute and per unit basis when compared to the three and nine months ended September 30, 2015 due primarily to lower overall production, cost containment efforts that we implemented throughout 2016 and lower industry-wide pricing for certain oilfield products and services. The Predecessor periods in 2015 included $0.9 million and $4.0 million of LOE attributable to our East Texas assets that were sold in August 2015.

40

Gathering, Processing and Transportation

	Successor		Predecessor				Successor		Predecessor
					Three Months						Nine Months
	September 13 to		July 1 to		Ended		September 13 to		January 1 to		Ended
	September 30,		September 12,		September 30,		September 30,		September 12,		September 30,
	2016		2016		2015		2016		2016		2015
Gathering, processing and transportation	$	576	$	4,767	$	5,654	$	576	$	13,235	$	19,535
Per unit of production ($/BOE)	$	3.15	$	5.99	$	2.93	$	3.15	$	3.96	$	3.10

Gathering, processing and transportation, or GPT, charges decreased during the the Successor and Predecessor periods in 2016 when compared to the three and nine months ended September 30, 2015 due primarily to substantially lower production volumes in the South Texas region as discussed above. We also experienced an absolute decline in the Predecessor periods in 2016 resulting from the sale of our East Texas assets in August 2015 as well as lower natural gas and NGL production in the Mid-Continent during the 2016 Successor and Predecessor periods when compared to the 2015 Predecessor periods. The effect of lower volumes on total cost during the Predecessor periods in 2016 was partially offset by charges associated with volume deficiencies attributable to our throughput commitments to Republic prior to the August 2016 effective date of the Amended Agreements, as well as higher cost costs for unused firm transportation services in the Marcellus prior to our termination of operations in that region. Per unit rates increased during the 2016 Successor and Predecessor periods as oil gathering services commenced by Republic at the South Texas CDP in April 2016.

Production and Ad Valorem Taxes

	Successor			Predecessor						Successor			Predecessor
							Three Months									Nine Months
	September 13 to			July 1 to			Ended			September 13 to			January 1 to			Ended
	September 30,			September 12,			September 30,			September 30,			September 12,			September 30,
	2016			2016			2015			2016			2016			2015
Production and ad valorem taxes
Production/severance taxes	$	288		$	1,316		$	2,800		$	288		$	2,695		$	9,857
Ad valorem taxes	87			(742		)	683			87			795			3,282
	$	375		$	574		$	3,483		$	375		$	3,490		$	13,139
Per unit production ($/BOE)	$	2.05		$	0.72		$	1.80		$	2.05		$	1.04		$	2.09
Production/severance tax rate as a percent of product revenue	4.6		%	4.9		%	4.6		%	4.6		%	2.9		%	4.5		%

Production taxes in the South Texas region declined substantially during the Successor and Predecessor periods in 2016 when compared to the three and nine months ended September 30, 2015 due primarily to the overall decline in production volume and commodity prices. In the 2016 Predecessor period, we adjusted our accruals for ad valorem taxes downward, primarily in South Texas, reflecting lower oil and gas property valuations attributable to the significant decline in commodity prices. These adjustments resulted in a net credit for ad valorem tax expense during the Predecessor period from July 1, 2016 through September 12, 2016 and had a significant downward impact on the per unit cost for both Predecessor periods in 2016. We also recognized certain severance tax refunds attributable to prior periods in the Mid-Continent and other region during the Predecessor periods in 2016.

41

General and Administrative

The following table sets forth the components of general and administrative expenses, or G&A, for the periods presented:

	Successor		Predecessor					Successor		Predecessor
					Three Months								Nine Months
	September 13 to		July 1 to		Ended			September 13 to		January 1 to			Ended
	September 30,		September 12,		September 30,			September 30,		September 12,			September 30,
	2016		2016		2015			2016		2016			2015
Primary general and administrative expenses	$	1,458	$	4,026	$	8,248		$	1,458	$	15,596		$	28,221
Share-based compensation (liability-classified)	—		—		(851		)	—		(19		)	(686		)
Share-based compensation (equity-classified)	—		5,433		1,263			—		1,511			3,369
Significant special charges:
Strategic and financial advisory costs	—		—		733			—		18,036			1,195
Restructuring expenses	18		2,722		23			18		3,821			766
Total general and administrative expenses	$	1,476	$	12,181	$	9,416		$	1,476	$	38,945		$	32,865
Per unit of production ($/BOE)	$	8.07	$	15.30	$	4.88		$	8.07	$	11.64		$	5.22
Per unit of production excluding all share-based compensation and other significant special charges identified above ($/BOE)	$	7.97	$	5.06	$	4.27		$	7.97	$	4.66		$	4.48

Our primary G&A expenses during the Successor period include $0.7 million of incentive compensation charges to our non-executive employees for the post-emergence period. This charge would have normally been accrued throughout the calendar year, but was charged exclusively to the Successor period as the accrual became effective after the emergence from bankruptcy. Our primary G&A expenses during both the Successor and Predecessor periods in 2016 reflect the effects of lower payroll and benefits attributable to lower employee headcount, reduced travel and entertainment and lower corporate support costs consistent with our efforts throughout the 2016 periods to reduce our support cost base.

Liability-classified share-based compensation in the Predecessor periods was attributable to our performance-based restricted stock units, or PBRSUs, and represents mark-to-market charges associated with the change in fair value of the then outstanding PBRSU grants. Our common stock performance relative to a defined peer group was less favorable during the 2016 periods resulting in a mark-to-market reversal in all periods. All of the unvested PBRSUs were canceled on the Effective Date.

Equity-classified share-based compensation charges during the Predecessor periods were attributable to the Predecessor's stock options and restricted stock units, which represented non-cash expenses. As described in Note 15 to the Condensed Consolidated Financial Statements, we recorded an adjustment of $5.3 million in the Predecessor period from July 1 to September 12, 2016 to correct for an error with respect to equity-classified share-based compensation that occurred during the three months ended June 30, 2016.

During the Predecessor periods, we incurred substantial professional fees and other consulting costs associated with our consideration of strategic financing alternatives and related activities in advance of our bankruptcy filing. In connection with our ongoing efforts to simplify and reduce our administrative cost structure, we terminated a total of 45 employees in 2016 and incurred termination and severance benefits during the Predecessor periods.

42

Exploration

The following table sets forth the components of exploration expense for the periods presented:

	Successor		Predecessor				Successor		Predecessor
					Three Months						Nine Months
	September 13 to		July 1 to		Ended		September 13 to		January 1 to		Ended
	September 30,		September 12,		September 30,		September 30,		September 12,		September 30,
	2016		2016		2015		2016		2016		2015
Unproved leasehold amortization	$	—	$	227	$	898	$	—	$	1,940	$	4,903
Drilling rig termination charges	—		279		517		—		1,705		6,182
Drilling carry commitment	—		—		—		—		1,964		—
Geological and geophysical costs	—		—		172		—		33		678
Other, primarily write-off of uncompleted wells	—		4,135		86		—		4,646		159
	$	—	$	4,641	$	1,673	$	—	$	10,288	$	11,922

On the Effective date we adopted the full cost method of accounting for our oil and gas properties. Accordingly, there are no exploration expenses recorded for the Successor period. With respect to the Predecessor periods in 2016, we experienced lower unproved leasehold amortization attributable to a declining leasehold asset base subject to amortization. We also incurred early termination charges in connection with the release of drilling rigs in the Eagle Ford in each of the 2016 and 2015 Predecessor periods; however, the 2015 periods include the release of multiple rigs while the 2016 periods reflect the release of only one rig. Seismic and delay rental costs declined in the Predecessor periods in 2016 compared to the three and nine month periods ended September 30, 2015 due to the suspension of our drilling program. These reductions were partially offset by a charge of $4.0 million for the write-off of certain uncompleted well costs prior to the aforementioned change in accounting method, a $2.0 million charge attributable to our failure to complete a drilling carry requirement attributable to certain acreage acquired in the Eagle Ford in 2014, and a charge of $0.6 million for coiled tubing services that were not utilized by the contract expiration date.

Depreciation, Depletion and Amortization (DD&A)

The following table sets forth total and per unit costs for DD&A:

	Successor		Predecessor				Successor		Predecessor
					Three Months						Nine Months
	September 13 to		July 1 to		Ended		September 13 to		January 1 to		Ended
	September 30,		September 12,		September 30,		September 30,		September 12,		September 30,
	2016		2016		2015		2016		2016		2015
DD&A expense	$	2,029	$	8,024	$	76,850	$	2,029	$	33,582	$	253,056
DD&A Rate ($/BOE)	$	11.09	$	10.08	$	39.82	$	11.09	$	10.04	$	40.20

The effects of lower production volumes and the effects of lower depletion rates resulting from impairments recorded in the fourth quarter of 2015 and an overall reduction in reserves were the primary factors attributable to the decline in DD&A during the Successor and Predecessor periods in 2016 when compared to the three and nine months ended September 30, 2015.

Impairments

We recorded an impairment charge of $1.1 million attributable to surplus tubular inventory and well materials which is reflected in the nine months ended September 30, 2015.

43

Interest Expense

The following table summarizes the components of our interest expense for the periods presented:

	Successor		Predecessor					Successor		Predecessor
					Three Months								Nine Months
	September 13 to		July 1 to		Ended			September 13 to		January 1 to			Ended
	September 30,		September 12,		September 30,			September 30,		September 12,			September 30,
	2016		2016		2015			2016		2016			2015
Interest on borrowings and related fees	$	180	$	1,363	$	23,239		$	180	$	36,013		$	69,371
Amortization of debt issuance costs	38		—		1,224			38		22,188			3,504
Capitalized interest	—		—		(1,478		)	—		(183		)	(4,854		)
	$	218	$	1,363	$	22,985		$	218	$	58,018		$	68,021

Interest expense during the Successor period is exclusively attributable to the Revolver. Interest expense during the Predecessor periods is attributable to the RBL and the Senior Notes except for the period from the Petition Date through September 12, 2016, which excludes interest on the Senior Notes due primarily to the suspension of interest accruals thereon in connection with the bankruptcy filing. The Predecessor period from January 1, 2016 to September 12, 2016 includes a $20.5 million accelerated write-off of our issuance costs associated with the RBL and Senior Notes in advance of our bankruptcy filings.

Derivatives

The following table summarizes the components of our derivative gains and losses income for the periods presented:

	Successor			Predecessor				Successor			Predecessor
						Three Months								Nine Months
	September 13 to			July 1 to		Ended		September 13 to			January 1 to			Ended
	September 30,			September 12,		September 30,		September 30,			September 12,			September 30,
	2016			2016		2015		2016			2016			2015
Crude oil derivative gains (losses)	$	(4,369	)	$	8,934	$	44,701	$	(4,369	)	$	(8,333	)	$	52,069
Natural gas derivative gains	—			—		—		—			—			4
	$	(4,369	)	$	8,934	$	44,701	$	(4,369	)	$	(8,333	)	$	52,073

We received cash settlements for crude oil derivatives during each of the Predecessor periods in 2016 and 2015 and received cash settlements of $0.7 million for natural gas derivatives during the nine months ended September 30, 2015. We had no natural gas derivatives outstanding after the three months ended March 31, 2015. The decline in total cash settlements is attributable to: (i) lower spreads between hedge and realized prices on our post-petition derivatives, (ii) lower overall crude oil volumes hedged, (iii) the early termination of our entire pre-petition portfolio of 2016 derivative contracts, most of the proceeds from which were directly provided to the RBL lenders to pay down borrowings under the RBL, prior to the Petition Date and (iv) the expiration of our natural gas hedges in the 2015 period.

Other

In the Predecessor periods in 2016 and 2015, we wrote-off unrecoverable amounts from prior years, including GPT charges and other revenue deductions, attributable primarily to properties that have been sold.

44

Reorganization Items, net

The following table summarizes the components included in “Reorganization items, net” for the periods presented:

	July 1 through			January 1 through
	September 12,			September 12,
	2016			2016
Gains on the settlement of liabilities subject to compromise	$	1,150,248		$	1,150,248
Fresh Start Accounting adjustments	28,319			28,319
Legal and professional fees and expenses	(22,739		)	(29,976		)
Settlements attributable to contract amendments	(2,550		)	(2,550		)
DIP Facility costs and commitment fees	(27		)	(170		)
Write-off of prepaid directors and officers insurance	(832		)	(832		)
Other reorganization items	(46		)	(46		)
	$	1,152,373		$	1,144,993

The gains on the settlement of liabilities subject to compromise are primarily attributable to the Senior Notes and interest thereon. The Fresh Start Accounting adjustments include those fair value adjustments attributable to our property and equipment, AROs, retiree benefit obligations and the accelerated recognition of previously deferred gains of the Predecessor. The legal and professional fees that we incurred were attributable to our advisers as well as those of the Ad Hoc Committee, the UCC, the RBL lenders and the indenture trustee under the Senior Notes. We paid settlements in cash with respect to certain critical contract amendments. While we did not borrow any amounts under the DIP facility from the Petition Date through the Effective Date, we paid certain costs and fees to arrange and maintain the DIP facility during this term. Upon emergence we wrote off certain prepaid directors and officers insurance attributable to the Predecessor. The items described herein are also described in further detail in Note 4 to the Condensed Consolidated Financial Statements.

Income Taxes

We recognized a federal income tax benefit for each of the periods ended September 12, 2016 (Predecessor) and September 30, 2016 (Successor) at the statutory rate of 35%; however, the federal tax benefit was fully offset by a valuation allowance against our net deferred tax assets. We considered both the positive and negative evidence in determining that it was more likely than not that some portion or all of our deferred tax assets will not be realized, primarily as a result of our cumulative losses. We recognized income tax benefits for the three and nine months ended September 30, 2015 due primarily to a federal return to provision adjustment partially offset by a minimal deferred state income tax expense.

We have evaluated the impact of the reorganization, including the change in control, resulting from our emergence from bankruptcy. From an income tax perspective, the most significant impact is attributable to our carryover tax attributes associated with our net operating losses, or NOLs. We believe that the Successor will be able to fully absorb the cancellation of debt income realized by the Predecessor in connection with the reorganization with its adjusted NOL carryovers. The amount of the remaining NOL carryovers and the tax basis of our properties will be limited under Section 382 of the Internal Revenue Code due to the change in control as referenced in the summary of Key Developments. As the tax basis of our assets, primarily our oil and gas properties, is in excess of the carrying value, as adjusted in the Fresh Start Accounting process, the Successor is in a net deferred tax asset position. We have determined that it is more likely than not that we will not realize future income tax benefits from the additional tax basis and our remaining NOL carryovers. Accordingly, we have provided for a full valuation allowance of the underlying deferred tax assets.

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Off Balance Sheet Arrangements

As of September 30, 2016, we had no off-balance sheet arrangements. 

Critical Accounting Estimates

The process of preparing financial statements in accordance with U.S. GAAP requires our management to make estimates and judgments regarding certain items and transactions. It is possible that materially different amounts could be recorded if these estimates and judgments change or if the actual results differ from these estimates and judgments. Disclosure of our most critical accounting estimates that involve the judgment of our management can be found in our Annual Report on Form 10-K for the year ended December 31, 2015.

As described in Note 2 to our Condensed Consolidated Financial Statements, we applied Fresh Start Accounting to our Condensed Consolidated Financial Statements and we also adopted the full cost method of accounting for our oil and gas properties on the Effective Date. Additional information can be found with respect to these items in Notes 4 and 7 to the Condensed Consolidated Financial Statements.

Disclosure of the Impact of Recently Issued Accounting Standards to be Adopted in the Future

In June 2016, the Financial Accounting Standards Board, or the FASB, issued Accounting Standards Update, or ASU, 2016–13, Measurement of Credit Losses on Financial Instruments, or ASU 2016–13, which changes the recognition model for the impairment of financial instruments, including accounts receivable, loans and held-to-maturity debt securities, among others. ASU 2016–13 is required to be adopted using the modified retrospective method by January 1, 2020, with early adoption permitted. ASU 2016–13 will have applicability to our accounts receivable portfolio, particularly those receivables attributable to our joint interest partners. At this time, we do not anticipate that the adoption of ASU 2016–13 will have a significant impact on our Consolidated Financial Statements and related disclosures; however, we are currently in the early stages of evaluating the requirements and the period for which we will adopt the standard.

In February 2016, the FASB issued ASU 2016–02, Leases, or ASU 2016–02, which will require organizations that lease assets to recognize on the balance sheet the assets and liabilities for the rights and obligations created by those leases with terms of more than twelve months. Consistent with current U.S. GAAP, the recognition, measurement, and presentation of expenses and cash flows arising from a lease by a lessee primarily will depend on its classification as a finance or operating lease. ASU 2016–02 also will require disclosures regarding the amount, timing, and uncertainty of cash flows arising from leases. The effective date of ASU 2016–02 is January 1, 2019, with early adoption permitted. We are continuing to evaluate the effect that ASU 2016–02 will have on our Consolidated Financial Statements and related disclosures as well as the period for which we will adopt the standard. We believe that ASU 2016–02 will likely be applicable to our oil and natural gas gathering commitment arrangements as described in Note 13, our existing leases for office facilities and certain office equipment and potentially to certain drilling rig contracts with terms in excess of twelve months.

In May 2014, the FASB issued ASU 2014–09, Revenues from Contracts with Customers, or ASU 2014–09, which requires an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. ASU 2014–09 will replace most existing revenue recognition guidance in U.S. GAAP when it becomes effective on January 1, 2018. The standard permits the use of either the retrospective or cumulative effect transition method upon adoption. While traditional commodity sales transactions, property conveyances and joint interest arrangements in the oil and gas industry are not expected to be significantly impacted by ASU 2014–09, natural gas imbalances and other non-product revenues, including our ancillary marketing, gathering and transportation and water service revenues could be affected. Accordingly, we are continuing to evaluate the effect that ASU 2014–09 will have on our Consolidated Financial Statements and related disclosures, with a more focused analysis on these other revenue sources. We have not yet selected a transition method nor have we determined the period for which we will adopt the new standard.

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Item 4. Controls and Procedures

(a) Disclosure Controls and Procedures

Under the supervision and with the participation of our management, including our Principal Executive Officer and our Chief Financial Officer, we performed an evaluation of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) of the Exchange Act) as of September 30, 2016. Our disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported accurately and on a timely basis. Based on that evaluation, our Principal Executive Officer and our Chief Financial Officer concluded that, as of September 30, 2016, such disclosure controls and procedures were effective.

(b) Changes in Internal Control Over Financial Reporting

During the three months ended September 30, 2016, we added new controls with respect to our adoption of the full cost method of accounting for oil and gas properties as well as controls over the application of Fresh Start Accounting to our Successor period financial statements. Aside from these changes, there were no other material changes were made in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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Part II. OTHER INFORMATION

Item 1. Legal Proceedings

See Note 13 to our Condensed Consolidated Financial Statements included in Part I, Item 1 “Financial Statements,” for a more detailed discussion of our legal proceedings. We are not aware of any material legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statutes to which we are subject.

Item 1A. Risk Factors

Our business and operations are subject to a number of risks and uncertainties as described in Item 1A to our Annual Report on Form 10-K for the year ended December 31, 2015. In addition to those risk factors, the following are risk factors associated with our bankruptcy proceedings.

We recently emerged from bankruptcy, which could adversely affect our business and relationships.

It is possible that our having filed for bankruptcy and our recent emergence from the Chapter 11 bankruptcy proceedings could adversely affect our business and relationships with customers, employees and suppliers. Due to uncertainties, many risks exist, including the following:

• key suppliers could terminate their relationship or require financial assurances or enhanced performance;

• the ability to renew existing contracts and compete for new business may be adversely affected;

• the ability to attract, motivate and/or retain key executives and employees may be adversely affected;

• employees may be distracted from performance of their duties or more easily attracted to other employment opportunities; and

• competitors may take business away from us, and our ability to attract and retain customers may be negatively impacted.

The occurrence of one or more of these events could have a material and adverse effect on our operations, financial condition and reputation. We cannot assure you that having been subject to bankruptcy protection will not adversely affect our operations in the future.

Our actual financial results after emergence from bankruptcy may not be comparable to our historical financial information as a result of the implementation of the plan of reorganization and the transactions contemplated thereby and our adoption of fresh start accounting.

In connection with the disclosure statement we filed with the bankruptcy court, and the hearing to consider confirmation of the plan of reorganization, we prepared projected financial information to demonstrate to the bankruptcy court the feasibility of the plan of reorganization and our ability to continue operations upon our emergence from bankruptcy. Those projections were prepared solely for the purpose of the bankruptcy proceedings and have not been, and will not be, updated on an ongoing basis and should not be relied upon by investors. At the time they were prepared, the projections reflected numerous assumptions concerning our anticipated future performance and with respect to prevailing and anticipated market and economic conditions that were and remain beyond our control and that may not materialize. Projections are inherently subject to substantial and numerous uncertainties and to a wide variety of significant business, economic and competitive risks and the assumptions underlying the projections and/or valuation estimates may prove to be wrong in material respects. Actual results will likely vary significantly from those contemplated by the projections. As a result, investors should not rely on these projections.

In addition, upon our emergence from bankruptcy, we adopted fresh start accounting. Accordingly, our future financial conditions and results of operations may not be comparable to the financial condition or results of operations reflected in the Company’s historical financial statements. The lack of comparable historical financial information may discourage investors from purchasing our common stock.

There is a limited trading market for our securities and the market price of our securities is subject to volatility.

Upon our emergence from bankruptcy, our old common stock was canceled and we issued new common stock. Our common stock is is currently listed on OTC Pink marketplace and intends to be listed on the OTCQX by the end of November in anticipation of subsequently listing on a national securities exchange. However, no assurances can be given regarding the Company’s ability to do so in a timely manner or at all. The market price of our common stock could be subject to wide fluctuations in response to, and the level of trading that develops with our common stock may be affected by, numerous factors, many of which are beyond our control. These factors include, among other things, our new capital structure as a result of the transactions contemplated by the plan of reorganization, our limited trading history subsequent to our emergence from bankruptcy, our limited trading volume, the concentration of holdings of our common stock, the lack of comparable historical financial information due to our adoption of fresh start accounting, actual or anticipated variations in our operating results and cash flow, the nature and content of our earnings releases, announcements or events that impact our products, customers, competitors or markets, business conditions in our markets and the general state of the securities markets and the market for energy-related stocks, as well as general economic and market conditions and other factors that may affect our future results,

48

including those described in this Report. No assurance can be given that an active market will develop for the common stock or as to the liquidity of the trading market for the common stock. The common stock may be traded only infrequently, and reliable market quotations may not be available. Holders of our common stock may experience difficulty in reselling, or an inability to sell, their shares. In addition, if an active trading market does not develop or is not maintained, significant sales of our common stock, or the expectation of these sales, could materially and adversely affect the market price of our common stock.

Upon our emergence from bankruptcy, the composition of our Board of Directors changed significantly.

Pursuant to the plan of reorganization, the composition of the Board changed significantly. Currently, the Board is made up of four directors, none of which previously served on the Board of the Company. The new directors have different backgrounds, experiences and perspectives from those individuals who previously served on the Board and, thus, may have different views on the issues that will determine the future of the Company. As a result, the future strategy and plans of the Company may differ materially from those of the past.

The ability to attract and retain key personnel is critical to the success of our business and may be affected by our emergence from bankruptcy.

The success of our business depends on key personnel. The ability to attract and retain these key personnel may be difficult in light of our emergence from bankruptcy, the uncertainties currently facing the business and changes we may make to the organizational structure to adjust to changing circumstances. We may need to enter into retention or other arrangements that could be costly to maintain. If executives, managers or other key personnel resign, retire or are terminated, or their service is otherwise interrupted, we may not be able to replace them in a timely manner and we could experience significant declines in productivity.

We do not expect to pay dividends in the foreseeable future.

We do not anticipate that cash dividends or other distributions will be paid with respect to our common stock in the foreseeable future. In addition, restrictive covenants in certain debt instruments to which we are, or may be a party, may limit our ability to pay dividends or for us to receive dividends from our operating companies, any of which may negatively impact the trading price of our common stock.

Certain provisions of our certificate of incorporation and our bylaws may make it difficult for stockholders to change the composition of our Board and may discourage, delay or prevent a merger or acquisition that some stockholders may consider beneficial.

Certain provisions of our Certificate of Incorporation and our Bylaws may have the effect of delaying or preventing changes in control if our Board determines that such changes in control are not in the best interests of the Company and our stockholders. The provisions in our Certificate of Incorporation and Bylaws include, among other things, those that:

• authorize our Board to issue preferred stock and to determine the price and other terms, including preferences and voting rights, of those shares without stockholder approval;

• establish advance notice procedures for nominating directors or presenting matters at stockholder meetings; and

• limit the persons who may call special meetings of stockholders.

While these provisions have the effect of encouraging persons seeking to acquire control of the Company to negotiate with our Board, they could enable the Board to hinder or frustrate a transaction that some, or a majority, of the stockholders may believe to be in their best interests and, in that case, may prevent or discourage attempts to remove and replace incumbent directors. These provisions may frustrate or prevent any attempts by our stockholders to replace or remove our current management by making it more difficult for stockholders to replace members of our Board, which is responsible for appointing the members of our management.

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Item 2. Unregistered Sales of Equity Securities

Pursuant to the Plan, a total of $50 million of proceeds were received on the Effective Date from the Rights Offering resulting in the issuance of 7,633,588 shares of New Common Stock to holders of claims arising under the Senior Notes, certain holders of general unsecured claims and to the Backstop Parties. The shares of New Common Stock issued to participants in the Rights Offering and to the Backstop Commitment Parties were issued under the exemption from the registration requirements of the Securities Act provided by Section 4(a)(2) thereof.

Item 3. Defaults Upon Senior Securities

The filing of the voluntary petitions seeking relief under Chapter 11 of the Bankruptcy Code constituted an event of default that accelerated our obligations under the indentures governing the Senior Notes. On September 12, 2016, the obligations of the Company and the Chapter 11 Subsidiaries with respect to these notes were canceled.

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Item 6. Exhibits

(2.1)	Second Amended Joint Plan of Reorganization of Penn Virginia Corporation and Its Debtor Affiliates (Technical Modifications) filed pursuant to Chapter 11 of the United States Bankruptcy Code filed on August 10, 2016 with the United States Bankruptcy Court for the Eastern Division of Virginia, Richmond Division (incorporated by reference to Exhibit 2.1 to Registrant’s Current Report on Form 8-K filed on August 17, 2016).
(2.2)	Disclosure Statement for the First Amended Joint Plan of Reorganization of Penn Virginia Corporation and Its Debtor Affiliates and Amended Exhibits Thereto filed pursuant to Chapter 11 of the United States Bankruptcy Code filed on June 28, 2016 with the United States Bankruptcy Court for the Eastern Division of Virginia, Richmond Division (incorporated by reference to Exhibit 2.1 to Registrant’s Current Report on Form 8-K filed on August 17, 2016).
(3.1)	Second Amended and Restated Articles of Incorporation of Penn Virginia Corporation (incorporated by reference to Exhibit 3.1 to Registrant’s Current Report on Form 8-K filed on September 14, 2016).
(3.2)	Second Amended and Restated Bylaws of Penn Virginia Corporation (incorporated by reference to Exhibit 3.2 to Registrant’s Current Report on Form 8-K filed on September 14, 2016).
(10.1)	Credit Agreement, dated as of September 12, 2016, by and among Penn Virginia Holding Corp., Penn Virginia Corporation, the lenders party thereto and Wells Fargo Bank, National Association, as administrative agent and issuing lender (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed on September 12, 2016).
(10.2)	Pledge and Security Agreement, dated as of September 12, 2016, by Penn Virginia Holding Corp., Penn Virginia Corporation and the other grantors party thereto in favor of Wells Fargo Bank, National Association, as administrative agent for the benefit of the secured parties thereunder (incorporated by reference to Exhibit 10.2 to Registrant’s Current Report on Form 8-K filed on September 12 2016).
(10.3)	Registration Rights Agreement, dated as of September 12, 2016, between Penn Virginia Corporation and the holders party thereto (incorporated by reference to Exhibit 10.3 to Registrant’s Current Report on Form 8-K filed on September 12 2016).
(10.4)	Shareholders Agreement, dated as of September 12, 2016, between Penn Virginia Corporation and the shareholders party thereto (incorporated by reference to Exhibit 10.4 to Registrant’s Current Report on Form 8-K filed on September 12 2016).
(10.5)*	Second Amended and Restated Construction and Field Gathering Agreement by and between Republic Midstream, LLC and Penn Virginia Oil & Gas, L.P. dated August 1, 2016.
(10.6)* +	First Amended and Restated Crude Oil Marketing Agreement dated as of August 1, 2016, by and between Penn Virginia Oil & Gas, L.P., Republic Midstream Marketing, LLC and solely for purposes of Article V therein, Penn Virginia Corporation.
(10.7)	Amendment No.1 to Employment Agreement, dated September 28, 2016 between the Company and John A. Brooks (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed on October 4, 2016).
(10.8)	Form of Director Indemnification Agreement (incorporated by reference to Exhibit 10.6 to Registrant’s Current Report on Form 8-K filed on October 11, 2016).
(31.1)	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
(31.2)	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
(32.1)	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
(32.2)	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
(101.INS)	XBRL Instance Document
(101.SCH)	XBRL Taxonomy Extension Schema Document
(101.CAL)	XBRL Taxonomy Extension Calculation Linkbase Document
(101.DEF)	XBRL Taxonomy Extension Definition Linkbase Document
(101.LAB)	XBRL Taxonomy Extension Label Linkbase Document
(101.PRE)	XBRL Taxonomy Extension Presentation Linkbase Document

* Filed herewith.

+ Filed herewith. Confidential treatment has been requested for this exhibit and confidential portions have been filed with the Securities and Exchange Commission.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	PENN VIRGINIA CORPORATION
	By:	/s/ STEVEN A. HARTMAN
		Steven A. Hartman
		Senior Vice President, Chief Financial Officer and Treasurer
November 14, 2016	By:	/s/ TAMMY L. HINKLE
		Tammy L. Hinkle
		Vice President and Controller
		(Principal Accounting Officer)

52

EX-10.5

Exhibit 10.5

Execution Copy

AMENDED AND RESTATED

CONSTRUCTION AND FIELD GATHERING AGREEMENT

by and between

REPUBLIC MIDSTREAM, LLC
(“Gatherer”)

and

PENN VIRGINIA OIL & GAS, L.P.
(“Shipper”)

Dated September 24, 2015

TABLE OF CONTENTS

Page

ARTICLE IDEFINITIONS    1

ARTICLE IIDEDICATION AND COMMITMENT    6

ARTICLE IIICONSTRUCTION AND OWNERSHIP OF THE GATHERING SYSTEM; CONSTRUCTION SCHEDULE    8

ARTICLE IVCHARACTERISTICS OF THE GATHERING SYSTEM    11

ARTICLE VQUANTITY, NOMINATION AND IMBALANCE PROCEDURES    12

ARTICLE VICONTROL OF OIL    13

ARTICLE VIIMEASUREMENT AND TESTING    14

ARTICLE VIIIQUALITY    14

ARTICLE IXMINIMUM VOLUME COMMITMENT; FEES    14

ARTICLE XTERM    15

ARTICLE XISTATEMENTS AND PAYMENTS    15

ARTICLE XIIREGULATION    16

ARTICLE XIIITAXES AND ROYALTIES    17

ARTICLE XIVREPRESENTATIONS AND WARRANTIES    18

ARTICLE XVEASEMENTS    18

ARTICLE XVIINDEMNITY    19

ARTICLE XVIINOTICES AND STATEMENTS    20

ARTICLE XVIIIFORCE MAJEURE    21

ARTICLE XIXCONFIDENTIAL INFORMATION    21

ARTICLE XXASSIGNMENT OR SALE OF GATHERING SYSTEM    22

ARTICLE XXIMISCELLANEOUS    23

EXHIBITS

EXHIBIT A-1    DEDICATION AREA

EXHIBIT A-2    INITIAL WELLS

EXHIBIT B    NOMINATION PROCEDURES

EXHIBIT C    MEASUREMENT AND TESTING

EXHIBIT D    REQUIRED INSURANCE

EXHIBIT E    FORM OF MEMORANDUM OF DEDICATION – GONZALES

EXHIBIT F     FORM OF MEMORANDUM OF DEDICATION – LAVACA

EXHIBIT G     DESIGN PROPOSAL

EXHIBIT H    FORM OF TARIFF

EXHIBIT I    FORM OF MEMORANDUM OF DEDICATION – FAYETTE

2

CONSTRUCTION AND FIELD GATHERING AGREEMENT

THIS AMENDED AND RESTATED CONSTRUCTION AND FIELD GATHERING AGREEMENT (this “Agreement”) is made and entered into this 24^th day of September, 2015 (the “Effective Date”) by and between Republic Midstream, LLC, a Delaware limited liability company (“Gatherer”), and Penn Virginia Oil & Gas, L.P., a Texas limited partnership (“Shipper”). Gatherer and Shipper may hereinafter be referred to singularly as a “Party” and, together, as the “Parties.” This Agreement supersedes and replaces that certain Construction and Field Gathering Agreement dated July 30, 2014, as amended, by and between the Parties.

WITNESSETH:

WHEREAS, the Parties desire that Gatherer construct, own and operate certain crude oil gathering lines to gather Shipper’s Oil (as defined in Article I) within the Dedication Area (as defined in Article I) and to deliver Shipper’s Oil to the Delivery Points (as defined in Article I); and

WHEREAS, Shipper desires to have Shipper’s Oil within the Dedication Area gathered by Gatherer and delivered to the Delivery Points;

NOW, THEREFORE, in consideration of the mutual covenants, terms and conditions herein contained, together with other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, and intending to be legally bound hereby, the Parties, for themselves and for their successors and assigns, do hereby mutually covenant and agree as follows:

ARTICLE IDEFINITIONS

For the purposes of this Agreement, the following terms are defined as follows:

“Acreage Swap” has the meaning given such term in Section 2.8.

“Additional Segment” means the Crude Oil gathering pipelines and other related facilities and equipment located in the Dedication Area necessary to gather and transport Crude Oil from a Receipt Point to any existing portion of the Gathering System.

“Additional Units” has the meaning given such term in Section 3.3(c).

“Affiliate” means, with respect to any Person, any other Person controlling, controlled by or under common control with such Person. For purposes of this definition, “control” means the possession, directly or indirectly, of the power to direct or cause the direction of the management or policies of such Person.

“Agreement” has the meaning given such term in the introductory paragraph hereto.

“API” means the American Petroleum Institute

“API Gravity” means a gravity (at sixty degrees (60°) Fahrenheit) determined in accordance with the specific gravity scale developed by the API and expressed in degrees.

“Applicable Law” means, with respect to any Person, all laws, statutes, codes, acts, treaties, ordinances, orders, judgments, writs, decrees, injunctions, rules, regulations, governmental approvals, licenses and permits, directives and requirements of all Governmental Authorities, including all official interpretations thereof by any such Governmental Authorities, as in effect at any time or from time to time and, in each case, applicable to or binding upon such Person and, in the case of Gatherer, Gatherer’s ownership, use and operation of the Gathering System.

“Barrel” means a standard barrel of 42 U.S. gallons liquid volume of oil or other liquid hydrocarbons corrected to sixty degrees (60°) Fahrenheit and equilibrium vapor pressure.

“Base Gathering System” means the Crude Oil gathering pipelines and other related facilities and equipment located in the Dedication Area necessary to gather and transport Crude Oil from the Receipt Points related to the Initial Wells to the pipeline inlet flanges at the CDP; provided, however, that the Base Gathering System shall not include any trucking services.

“CDP” means the central delivery point identified on the map attached hereto as Exhibit A-1.

“Change in Law” means any change to any Applicable Law in effect on the Effective Date.

“Claim” means any demand, claim, action, suit, legal proceeding (whether at law or in equity) or arbitration.

“Collateral Assignment” has the meaning given such term in Section 20.1.

“Completion Date” has the meaning given such term in Section 3.5.

2

“Confidential Information” means (i) the terms and conditions of this Agreement, (ii) the terms and conditions of Shipper’s gathering and/or transportation agreements with downstream pipelines, trucking company or purchasers and (iii) all information and data (including all copies thereof) that is furnished or submitted by any Party or its Affiliates, whether oral, written or electronic, to the other Party or its Affiliates in connection with the operation of the Gathering System or the services rendered by Gatherer hereunder, including customer, pricing and nomination information and the terms and conditions of any contracts to which such furnishing Party is a party. Notwithstanding the foregoing, the term “Confidential Information” shall not include any information that a claiming Party proves:

(a)is in the public domain at the time of its disclosure, other than as a result of a breach of this Agreement;

(b)was in the possession of any Party or any of its Affiliates prior to being furnished such information; or

(c)has been independently acquired or developed by a Party or any of its Affiliates without breaching this Agreement.

“Connection Units” means the Core Units and any Additional Units connected to the Gathering System.

“Construction Notice” has the meaning given such term in Section 3.3(a).

“Construction Plan” has the meaning given such term in Section 3.2.

“Crude Oil” means crude oil produced from lease production, including lower or higher API Gravity crude oil.

“Core Units” means those production units within the Dedication Area identified as “Core Units” on the map attached hereto as Exhibit A-1.

“Day” means a period of twenty-four (24) consecutive hours beginning at 7:00 a.m., Central Time, on each calendar day and ending at 7:00 a.m., Central Time, on the next succeeding calendar day or such other time period that any market and/or pipeline downstream of the Gathering System uses as the definition of “Day” for its operations if such time period is inconsistent with the preceding time period.

“Dedication Area” means all of the Interests within the areas of Gonzales, Lavaca and Fayette Counties, Texas identified on the map attached hereto as Exhibit A-1.

“Delivery Failure” has the meaning given such term in Section 3.5.

“Delivery Points” means the (i) outlet flange of Gatherer’s tank batteries located within the CDP where Gatherer redelivers Shipper’s Oil downstream by pipeline from the CDP, (ii) the outlet flange of Gatherer’s tank batteries located within the CDP where Gatherer redelivers Shipper’s Oil to truck loading connections at the CDP and (iii) any such other point(s) of interconnection as may be mutually agreed by Gatherer and Shipper.

“Easements” has the meaning given such term in Section 3.9.

“Effective Date” has the meaning given such term in the introductory paragraph hereto.

3

“Emissions” means any gaseous, liquid, solid or other substance emitted by the Gathering System, including carbon dioxide (“CO₂”), sulfur dioxide (“SO₂”), nitrogen oxides (“NO_x”), mercury (“Hg”), volatile organic compounds (“VOC”) and volatile organic material (“VOM”).

“Equivalent Volume” means a volume of Shipper’s Oil equal to (x) the volume of Shipper’s Oil received by Gatherer at the Receipt Points, minus (y) Shipper’s proportionate share of Lost Oil.

“Excess Receipt Point” has the meaning given such term in Section 3.3(b).

“Excluded Units” has the meaning given such term in Section 3.3(d).

“Excluded Volumes” has the meaning given such term in Section 9.2(b).

“Expected Production Date” has the meaning given such term in Section 3.3(a).

“Fees” means the fees payable to Gatherer hereunder as described in Section 9.2.

“FERC” has the meaning given such term in Section 12.2.

“Financing Parties” means institutions (including any trustee or agent on behalf of such institutions) providing debt financing or refinancing to Gatherer for the acquisition, development, construction, ownership, operation, maintenance or leasing of the Gathering System.

“Force Majeure” means any circumstance beyond the reasonable control of the Person experiencing such inability to perform, whether of the kind enumerated herein or not, including any such circumstances caused by the non-performance of, or breach of, the other Party of its obligations under this Agreement or acts of God, strikes, lockouts or other industrial disturbances, curtailments or shutdowns, acts of the public enemy, wars, blockades, insurrections, riots, epidemics, landslides, lightning, earthquakes, power failures, storms, floods, washouts, arrests and restraints of governments and people, civil disturbances, fires, explosions, breakage or accidents to machinery or lines of pipe, modification or maintenance of machinery or lines of pipe, freezing of lines of pipe, inability to obtain at reasonable cost any land use rights such as easements, servitudes, right-of-way grants, permits, governmental approvals or licenses and inability to obtain at reasonable cost materials or supplies for constructing or maintaining facilities, actions or failures to act of Governmental Authorities, including changes in Applicable Law, and which by the exercise of due diligence such Person is unable to prevent or overcome; provided, however, that “Force Majeure” shall not include any circumstance beyond the reasonable control of such Person where the circumstance is a direct result of the willful misconduct of such Person.

“Gatherer” has the meaning given such term in the introductory paragraph hereto.

“Gatherer Indemnitees” has the meaning given such term in Section 16.1.

“Gathering System” means, collectively, the Base Gathering System, the CDP, the Additional Segments and all associated facilities that Gatherer may construct as part thereof.

“Governmental Authority” means any government, court, tribunal, arbitrator, authority, agency, commission, official or other instrumentality of the United States or any state, county, city, tribal or other political subdivision or similar governing entity, and including any governmental, quasi-governmental or non-governmental body administering, regulating or having general oversight over oil, electricity, power or other markets.

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“Initial Production Date” means the date of first production of Shipper’s Oil from a well pad connected to an additional Receipt Point described in a Construction Notice.

“Initial Wells” means the wells of Shipper identified on Exhibit A-2 attached hereto.

“Interests” means all interests that Shipper (or any of its Affiliates or any successor in interest resulting from any merger, reorganization, consolidation or as part of a sale or other disposition of all or any portion of such interests) now or hereinafter owns, controls, acquires or has the right to market (as such marketing rights may change from time to time) in Shipper’s Oil reserves of, and production from, all formations in, under or attributable to the Dedication Area, together with any pool, communitized area or unit, and all interests in any wells, whether now existing or drilled hereafter, on or completed within the Dedication Area, or within any such pool, communitized area or unit, even though such interests may be incorrectly or incompletely stated, all as the same shall be enlarged by the discharge of any burdens or by the removal of any charges or encumbrances to which any of same maybe subject as of the Effective Date, and any and all replacements, renewals and extensions or amendments of any of the same; provided, however, that “Interests” shall not include (a) any Excluded Units or Outside Units or (b) any interest of Shipper or any of its Affiliates that must be offered to a third-party working interest partner pursuant to any applicable agreement with such partner in effect on the Effective Date, and which such partner receives or elects to receive, as applicable under the affected agreement.

“LACT/ACT Unit” means a Lease Automatic Custody Transfer unit or Automatic Custody Transfer unit, in each case with Coriolis mass metering devices and electronic temperature averaging capabilities.

“Losses” means any and all judgments, losses, liabilities, amounts paid in settlement, damages, fines, penalties, deficiencies, costs and expenses (including pre- and post-judgment interest, court costs, reasonable fees of attorneys, accountants and other experts or other reasonable expenses related to any Claim).

“Lost Oil” means the volume of crude oil (expressed in Barrels) which is lost and unaccounted for in the Gathering System. Shipper’s proportionate share of Lost Oil shall be stated in Barrels and shall be determined in accordance with Gatherer’s standard allocation procedures on a proportional basis.

“Minimum Volume Commitment” has the meaning given such term in Section 9.1.

“Month” means the period commencing at 7:00 a.m., Central Time, on the first day of a calendar month and ending at 7:00 a.m., Central Time, on the first day of the next succeeding calendar month or such other time period that any market and/or pipeline downstream of the Gathering System uses as the definition of “Month” for its operations if such time period is inconsistent with the preceding time period.

“Necessary Capacity” has the meaning given such term in Section 12.5.

“Non-Operated Interest” has the meaning given such term in Section 2.2(a).

“Outside Units” has the meaning given such term in Section 3.3(e).

“Party” and “Parties” have the meanings given such terms in the introductory paragraph hereto.

“Permissible Interruptions” has the meaning given such term in Section 5.4.

“Person” means any natural person, limited liability company, corporation, general or limited partnership, group, union, association, trust or Governmental Authority.

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“PPI Adjustment” has the meaning given such term in Section 9.3.

“Preferential Fee” has the meaning given such term in Section 9.2(b).

“Prime Rate” means the per annum rate of interest announced as the “prime rate” for commercial loans posted from time to time by Wells Fargo Bank, N.A. or its successor or other bank on which the Parties agree.

“Prior Dedicated Interest” has the meaning given such term in Section 2.2(b).

“Projected Volumes” has the meaning given such term in Section 3.3(a).

“Proposed Acquired Acreage” has the meaning given such term in Section 2.8.

“Proposed Exchange Acreage” has the meaning given such term in Section 2.8.

“Proposed Released Acreage” has the meaning given such term in Section 2.9.

“Psia” means pounds per square inch absolute.

“Psig” means pounds per square inch gauge.

“Receipt Points” means the outlet flange of each of Shipper’s tank batteries located within the Dedication Area.

“Reputable and Prudent Operator” has the meaning set forth in Section 20.2.

“Reservations” has the meaning given such term in Section 6.5.

“Shipper” has the meaning given such term in the introductory paragraph hereto.

“Shipper Indemnitees” has the meaning given such term in Section 16.2.

“Shipper’s Oil” means all Interests of Shipper in Crude Oil, including, without limitation, all Crude Oil that Shipper owns, controls, acquires or has the right to market within the Dedication Area.

“Specifications” has the meaning given such term in Section 8.1.

“Successor” means a successor in interest resulting from any merger, reorganization, consolidation or as part of a sale or other disposition of any portion of the Interests, except as set forth in Sections 2.8, 2.9 and 2.10.

“System Completion Date” has the meaning given such term in Section 3.2.

“Tariff” meansGatherer’s TRRC Tariff and the rules and regulations of TRRC Tariff, as initially set forth on Exhibit H attached hereto, including supplements thereto and reissues thereof, under which Crude Oil is transported through the Gathering System.

“Tax” means any tax or fee imposed by any Governmental Authority.

“Term” has the meaning given such term in Article X.

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“TRRC” means the Texas Railroad Commission.

ARTICLE IIDEDICATION AND COMMITMENT

2.1Subject to Sections 2.2, 2.7, 2.8, 2.9 and 2.10, Shipper hereby dedicates and commits to Gatherer, in consideration for the gathering, trucking and delivery services to be provided by Gatherer hereunder, all of the Interests.

2.2Shipper’s dedication and commitment of the Interests shall be subject to the Reservations as well as the following limitations:

(a)Any Interest, other than Connection Units, which is, at any time after the Effective Date, both (a) operated by an operator other than Shipper, its Affiliate or a Successor and (b) owned less than 51% by Shipper or an Affiliate of Shipper where such ownership is measured by working interests (a “Non-Operated Interest”) shall not be subject to the dedication and commitment provided for in Section 2.1.

(b)If Shipper acquires, after the Effective Date, any Interest which is subject to a prior dedication (a “Prior Dedicated Interest”), then such Prior Dedicated Interest shall not be subject to the dedication and commitment provided for in Section 2.1; provided, however, that, if any Prior Dedicated Interest is released from such prior dedication during the Term, then such Prior Dedicated Interest shall, effective upon such release, become subject to the dedication and commitment provided for in Section 2.1.

2.3Commencing on the System Completion Date, Shipper shall deliver all of Shipper’s Oil produced from wells located in the Core Units to Gatherer at the Receipt Points.

2.4Commencing on the System Completion Date, Gatherer shall provide gathering services for and accept and receive the volume of Shipper’s Oil (measured in Barrels) tendered by Shipper each Day at the Receipt Points located in the Core Units and deliver an Equivalent Volume to the Delivery Points. In the event that any Receipts Points in the Core Units are not connected to the Gathering System, Gatherer shall provide trucking services sufficient to transport all of Shipper’s Oil tendered by Shipper each Day at such Receipt Points and deliver an Equivalent Volume to the Delivery Points. If Gatherer elects to take truck delivery by a third party common carrier, Gatherer shall immediately notify Shipper of the carrier’s name and address. Gatherer shall furnish to Shipper delivery tickets for all volumes of Shipper’s Oil trucked from the Receipt Points.

2.5Commencing on the Initial Production Date, Shipper shall deliver all of Shipper’s Oil to Gatherer at the Receipt Point described in the applicable Construction Notice.

2.6Commencing on the Initial Production Date, Gatherer shall provide gathering services for and accept and receive the volume of Shipper’s Oil (measured in Barrels) tendered by Shipper each Day at the Receipt Point described in the applicable Construction Notice and deliver an Equivalent Volume to the Delivery Points.

2.7Subject to Sections 2.8, 2.9 and 2.10, such dedication and commitment by Shipper under this Article II shall be deemed an interest that runs with the land in the Dedication Area, and the Parties agree that the dedications and commitments with regard to any Interest existing as of the Effective Date shall be deemed fully vested, and further agree that future interests in the Interests shall vest upon Shipper’s acquiring ownership, control or right to market such Interest(s). Shipper agrees to execute and deliver a memorandum

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in the form attached hereto as Exhibit E for Gonzales County, Exhibit F for Lavaca County and Exhibit I for Fayette County to Gatherer for recording in the real property records of each county in which any portion of the Dedication Area is located in order to evidence the dedication provision of this Article II.

2.8If Shipper desires to sell or transfer to a third party acreage, excluding acreage within Connection Units, within the Dedication Area already dedicated under this Agreement (the “Proposed Exchange Acreage”) and receive in exchange for such acreage new acreage, not otherwise dedicated, within the Dedication Area (the “Proposed Acquired Acreage”) (such transaction, an “Acreage Swap”), Shipper shall notify Gatherer in writing of its desire for Gatherer to execute a dedication release of the Proposed Released Acreage in the Dedication Area. Shipper’s written notice will describe in reasonable detail the proposed Acreage Swap, including, as applicable: (i) a description of the portion of the Dedication Area to be released, including the number of net acres constituting the Proposed Exchange Acreage and (ii) a description of the Proposed Acquired Acreage, including the number netacres.

(a)If the number of net acres constituting the Proposed Acquired Acreage is greater than or not less than ninety percent (90%) of the number of net acres constituting the Proposed Exchange Acreage, Gatherer shall grant such dedication release pursuant to this Section 2.8 and shall promptly deliver a recordable copy of such dedication release to Shipper.

(b)If the number of net acres constituting the Proposed Acquired Acreage is less than ninety percent (90%) of number of net acres constituting the Proposed Exchange Acreage, Gatherer may, but shall not be required to (subject to Section 2.9), grant such dedication release pursuant to this Section 2.8.

2.9If Shipper desires to sell or transfer to a third party acreage, excluding acreage within Connection Units, within the Dedication Area already dedicated under this Agreement other than pursuant to Section 2.8 (the “Proposed Released Acreage”), Shipper shall notify Gatherer in writing of its desire for Gatherer to execute a dedication release of the Proposed Released Acreage in the Dedication Area. Shipper’s written notice will describe in reasonable detail the portion of the Dedication Area to be released, including the number of net acres constituting the Proposed Released Acreage.

(a)If the number of net acres constituting the Proposed Released Acreage is not more than five percent (5%) of the number of net acres included the Dedication Area at the time of such sale or transfer, Gatherer shall grant such dedication release pursuant to this Section 2.9 and shall promptly deliver a recordable copy of such dedication release to Shipper; provided, however, that Gatherer shall not be required to grant any such dedication release to the extent that the net acres included in the Dedication Area following such sell or transfer pursuant to this Section 2.9 is less than the net acres included in the Dedication Area on the Effective Date.

(b)If the number of net acres constituting the Proposed Releases Acreage is more than five percent (5%) of number of net acres constituting the Proposed Released Acreage included the Dedication Area at the time of such sale or transfer, Gatherer may, but shall not be required to, grant such dedication release pursuant to this Section 2.9.

2.10If, at any time, insufficient contiguous acreage remains in the Dedication Area for Shipper to create a drilling unit, or if Shipper is otherwise unable to create a pooled unit in which it is the operator of such pooled unit, Shipper shall notify Gatherer in writing, on a unit-by-unit basis, of its desire for Gatherer to execute a dedication release of a portion of the acreage in the Dedication Area necessary to create a pooled unit with one or more third parties. Shipper’s written notice will describe in reasonable detail the proposed pooled unit, including, as applicable: (i) an explanation of why Shipper’s acreage in the Dedication Area is

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insufficient to create a drilling unit, (ii) a description of the portion of the Dedication Area required to be released to form such pooled unit, (iii) the identification of the third party working interest owners of such pooled unit and (iv) the size of such pooled unit. Such proposed pooled units shall not exceed seven hundred four (704)acres. Upon receipt of the information set forth in this Section 2.9, Gatherer shall grant such dedication release pursuant to this Section 2.9 and shall promptly deliver a recordable copy of such dedication release to Shipper.

ARTICLE IIICONSTRUCTION AND OWNERSHIP OF THE GATHERING SYSTEM;
CONSTRUCTION SCHEDULE

3.1Gatherer shall, at its sole risk, cost and expense, design, acquire right-of-way for, obtain all permits from Governmental Authorities for, procure materials for, construct, equip, install, own, operate and maintain the Gathering System, all in accordance with Applicable Law and the provisions of Article IV.

3.2By not later than October 1, 2015, Gatherer shall prepare and deliver to Shipper a detailed construction plan (a “Construction Plan”) for the completion of the Base Gathering System and the CDP and shall review the design for constructing the Base Gathering System and the CDP with Shipper. Subject to Force Majeure, Gatherer shall use commercially reasonable efforts to complete construction of the Base Gathering System and CDP so that all of the Initial Wells are connected to the Gathering System, and the Base Gathering System and CDP are operational, by not later than January 1, 2016 (such completion date, the “System Completion Date”). If the System Completion Date has not occurred on or before March 31, 2016, Shipper may terminate this Agreement. Within thirty (30) Days of the System Completion Date, Shipper shall commence and thereafter continue on an uninterrupted basis (except for interruptions caused by Force Majeure, Permissible Interruptions or Gatherer) delivery of Shipper’s Oil into the Base Gathering System.

3.3Gatherer shall expand or extend, add or remove components and operate the Gathering System as necessary to connect Shipper’s wells within the Dedication Area as follows:

(a)Shipper shall notify Gatherer of the need to construct and install an Additional Segment to connect an additional Receipt Point within the Dedication Area not included as part of the Base Gathering System (a “Construction Notice”) at least 120 Days prior to the date on which the first well on the first well pad to be connected to such additional Receipt Point is expected to be spud. Each Construction Notice delivered by Shipper shall describe in reasonable detail (i) the expected date of first production of Shipper’s Oil from the first well pad to be connected to such additional Receipt Point (the “Expected Production Date”), (ii) the desired location for such additional Receipt Point, (iii) Shipper’s good faith projection of the daily volumes of Shipper’s Oil to be gathered during the initial two (2) years of production from the first well pad to be connected to such additional Receipt Point (“Projected Volumes”) and (iv)  the anticipated API Gravity of Shipper’s Oil to be produced from the first well pad to be connected to such additional Receipt Point.

(b)Within 30 Days following the receipt of a Construction Notice, Gatherer shall notify Shipper whether it elects to connect such additional Receipt Point to the Gathering System (it being understood that Gatherer must connect (and shall have no election with respect to) any additional Receipt Point within a Core Unit); provided, however, that Gatherer shall not be required to connect any additional Receipt Point pursuant to this Section 3.2 in a production unit which already has a Receipt Point connected to the Gathering System (subject to the following proviso) if the aggregate Receipt Points connected to the Gathering System following the installation of such additional Receipt Point (an “Excess Receipt Point”) would be more than one hundred and fifty percent (150%) of the number of total number of production units then connected to the Gathering System; provided,

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further, that Gatherer shall construct, install, own and operate any Excess Receipt Point if such Excess Receipt Point does not require an additional LACT/ACT Unit and if Shipper reimburses Gatherer for the lesser of (x) $100,000 and (y) 50% of the actual costs associated with construction and installation of such Excess Receipt Point. If Gatherer elects to connect any additional Receipt Point, it shall prepare and deliver to Shipper a detailed Construction Plan for the installation of the additional Receipt Point requested by such Construction Notice and the completion of the related Additional Segment and shall review with Shipper the design for constructing and/or modifying and operating such Additional Segment.

(c)Gatherer shall use commercially reasonable efforts to complete the construction of the additional Receipt Point described in such Construction Notice and the related Additional Segment so that such Additional Segment is operational by not later than 30 Days prior to the Expected Production Date, subject to Force Majeure. Any production units connected to the Gathering System by Gatherer pursuant to this Section 3.3 shall become “Additional Units.”

(d)Except as set forth in Section 3.3(b), if Gatherer elects not to install an additional Receipt Point or if Gatherer fails to make its election within the required 30-Day period, Shipper, its Affiliates or a third party at the direction of Shipper, shall have the right, at its sole risk, cost and expense, to install pipeline facilities and connect the wells connected or to be connected to such Additional Receipt Point. Any production units not connected to the Gathering System by Gatherer pursuant to this Section 3.3 shall be released from the Dedication Area. Any such production units connected to the Gathering System by Shipper pursuant to this Section 3.3 shall become “Excluded Units.” Shipper shall pay the Preferential Fee on Shipper’s Oil gathered from wells within an Excluded Unit.

(e)Shipper shall have the right, at its sole risk, cost and expense, to install pipeline facilities and connect any wells outside of the Dedication Area to a point on the Gathering System. Any production units outside of the Dedication Area connected to the Gathering System by Shipper will become “Outside Units.” Shipper shall pay the Preferential Fee on Shipper’s Oil gathered from wells within an Outside Unit.

3.4Gatherer shall design and construct the Base Gathering System, the CDP and each Additional Segment substantially as described in the applicable Construction Plan, as agreed by Gatherer and Shipper. All pipelines to be constructed pursuant to a Construction Plan (whether as part of the Base Gathering System or as part of an Additional Segment) shall be constructed of steel. Each Construction Plan shall be reasonably satisfactory to Shipper. Gatherer shall construct the Base Gathering System, the CDP and each Additional Segment with due diligence at its sole risk, cost and expense. Gatherer shall either provide a written report or schedule a conference call with Shipper regarding construction progress on a weekly basis while the Base Gathering System, the CDP and each Additional Segment are being constructed. Gatherer and Shipper shall work together to ensure completion of the Base Gathering System, the CDP and each Additional Segment in a timely manner.

3.5Gatherer shall notify Shipper of the date on which each Additional Segment constructed or modified by Gatherer hereunder has been completed and is operational (the “Completion Date”). Except as otherwise set forth herein, by not later than 120 Days after the later of the Completion Date or the Expected Production Date, Shipper shall (a) commence and thereafter continue on an uninterrupted basis (except for interruptions caused by Force Majeure, Permissible Interruptions or Gatherer) delivery of Shipper’s Oil into such Additional Segment from the first well pad connected to the additional Receipt Point described in the applicable Construction Notice and (b) commence to pay all Fees required to be paid hereunder in connection with the gathering of such Shipper’s Oil. If Shipper does not commence such delivery within such 120-Day

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period, or thereafter ceases such delivery (in either case, a “Delivery Failure”), then Shipper shall, commencing on the first Day after such Delivery Failure, and continuing until Shipper has commenced or recommenced such delivery, pay all Fees that would be have been required to be paid hereunder if all of the Projected Volumes described in the applicable Construction Notice were, in fact, delivered.

3.6In the event that (a) the Completion Date for an Additional Segment has not occurred prior to the Initial Production Date for such Additional Segment or (b) Gatherer is unable to take all of Shipper’s Oil volumes delivered at any Receipt Point (including because of events of Force Majeure), Shipper may sell any of Shipper’s Oil produced from the wells to be connected to such Additional Segment or connected to such Receipt Point, as applicable, free from the dedications under to this Agreement until such time as the Completion Date occurs or Gatherer can resume taking all of Shipper’s Oil volumes delivered at such Receipt Point, as applicable. If (a) the Completion Date for an Additional Segment has not occurred within 120 Days after the Initial Production Date for such Additional Segment or (b) Gatherer is unable to take all of Shipper’s Oil volumes delivered at any Receipt Point (including because of events of Force Majeure) for a period of 120 Days, Shipper may request that Gatherer release the wells connected to such Additional Segment from the Dedication Area, and Gatherer shall grant such dedication release and promptly deliver a recordable copy of such dedication release to Shipper.

3.7In the event that Shipper makes any payment of Fees on account of a Delivery Failure pursuant to Section 3.5, all Projected Volumes used in the calculation of such payment shall be deemed to have been actually delivered for the purpose of satisfying the Minimum Volume Commitment. In the event that Shipper sells Shipper’s Oil free from the dedications under to this Agreement pursuant to Section 3.6, all such volumes shall be deemed to have been actually delivered for the purpose of satisfying the Minimum Volume Commitment.

3.8Gatherer and Shipper shall collaborate to ensure that the Gathering System is configured in such a manner as to have reasonable ingress and egress to access roads and wells within the Dedication Area. With respect to any access roads constructed or to be constructed within the Dedication Area by a Party, such Party shall grant the other Party access to and use thereof. Each Party shall be responsible, and shall reimburse the other Party, for any damage caused by such Party to the other Party’s roads within the Dedication Area, ordinary wear and tear excepted.

3.9In the event that Gatherer requires additional easements, rights-of-way, surface leases and/or easement rights under oil and gas leases (collectively, “Easements”), as applicable, in connection with the construction and/or modification of the Base Gathering System, the CDP or any Additional Segment, Gatherer shall describe such requirements in the applicable Construction Plan delivered to Shipper.

3.10Ownership and operation of the Gathering System shall be solely vested in Gatherer, and Shipper shall have no rights to the same. Gatherer shall operate the Gathering System in accordance with the terms of the Tariff, this Agreement, Applicable Law and prevailing industry standards. In the event that trucking services are required to be provided by Gatherer, Gatherer shall provide such services in accordance with the terms of this Agreement, Applicable Law and prevailing industry standards

ARTICLE IVCHARACTERISTICS OF THE GATHERING SYSTEM

4.1Gatherer shall design, construct, equip, install, operate and maintain the Base Gathering System and any Additional Segments to have, at a minimum, the following characteristics:

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(a)the capability to reliably receive at the Receipt Points all volumes of Shipper’s Oil delivered by Shipper and re-deliver to the Delivery Points all the Equivalent Volume, in accordance with this Agreement and customary industry standards;

(b)the capability to segregate, whether through use of separate pipelines or other means, (i) production from units generally producing 45 degree or lower API Gravity Shipper’s Oil and (ii) production from units generally producing greater than 45 degree API Gravity Shipper’s Oil, as specified in the design proposal attached hereto as Exhibit G;

(c)LACT/ACT Units and pipeline sample posts with capabilities sufficient to support Shipper’s royalty accounting responsibilities with respect to quantity, API Gravity, sediment and water and sulfur content for each production unit, provided, that Shipper’s use of any such data is not intended to create, nor creates, any third-party beneficiary rights; and

(d)insulated above ground pipe, the ability to run scraper pigs and the capability to take such other actions as necessary to ensure flow reliability.

4.2Gatherer shall design, construct, equip, install, operate and maintain the CDP to have, at a minimum, the following characteristics:

(a)the capability to receive, store and re-deliver all of Shipper’s Oil volumes gathered from Shipper in accordance with this Agreement and customary industry standards;

(b)facilities available to Shipper on a first priority basis for loading and unloading volumes by truck utilizing six dual LACT/ACT Units; provided, however, that should Shipper determine that six dual LACT/ACT Units are not sufficient for loading and unloading Shipper’svolumes, Shipper shall provide written notice of such to Gatherer and Gatherer shall install, within sixty (60) Days of receipt of such notice, up to two additional LACT/ACT Units;

(c)at least four dedicated tanks with up to 180,000 barrels of combined tank shell storage capacity; and

(d)the capability to blend Shipper’s volumes of Shipper’s Oil in storage tanks in order to manage Shipper’s Oil API Gravity.

4.3Gatherer shall provide, at no additional cost to Shipper, blending services to Shipper at the CDP sufficient to blend Shipper’s Oil to between 36 degree API Gravity and 55 degree API Gravity as specified by Shipper; provided, however, that Gatherer shall perform such blending using only Shipper’s Oil and shall not use or be obligated to use Crude Oil purchased from third parties in connection with such blending services. Each Month, Shipper shall instruct Gatherer either to (a) blend Shipper’s Oil to be delivered at the Delivery Points (including trucking facilities) to a target API Gravity or (b) deliver Shipper’s Oil directly from one of Shipper’s dedicated tanks at the CDP without blending, in each case in accordance with the nomination procedures described on Exhibit B attached hereto.

4.4Gatherer shall provide batching capability to Shipper at the CDP to maintain segregation of grades described in Section 4.1(b) out of the Delivery Points at the CDP.

4.5Shipper shall reimburse Gatherer for the actual costs of the ongoing power requirements for operation of Gatherer’s LACT units and injection pump facilities at the Receipt Points. Gatherer shall provide, at its sole risk, cost and expense, power for the CDP.

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4.6Gatherer shall provide, at its sole risk, cost and expense, line fill and tank bottoms.

4.7Gatherer shall not prohibit or unreasonably restrict the ability of third party pipelines to connect to the CDP. Upon the connection of a third party pipeline to the CDP, the downstream connecting pipeline(s) shall become a Delivery Point.

ARTICLE VQUANTITY, NOMINATION AND IMBALANCE PROCEDURES

5.1During the Term, Shipper shall deliver and Gatherer shall take and receive 100% of Shipper’s Oil produced from wells located within the Core Units, Additional Units, the Excluded Units and the Outside Units, subject to the Reservations and the limitations described in Article II.

5.2Shipper shall provide nominations to Gatherer with respect to the quantity of Shipper’s Oil to be delivered at each Delivery Point, which nominations shall be made in accordance with the nomination procedures described on Exhibit B attached hereto.

5.3Gatherer shall not allow any third party Crude Oil to be commingled with Shipper’s Oil on the Gathering System; provided, however, that Gatherer may receive third party Crude Oil at the CDP so long as such third party Crude Oil is and remains segregated from Shipper’s Oil and may, subject to the Rules and Regulations and after consultation with Shipper, gather third party Crude Oil.

5.4Notwithstanding anything herein to the contrary and without liability hereunder to Shipper or any other Person (but subject to the requirements of Section 12.5), Gatherer may interrupt or reduce its receipt, gathering and delivery of Shipper’s Oil for reasons of Force Majeure, maintenance, repair, emergency, construction or other causes beyond Gatherer’s reasonable control that restrict or curtail capacity in the Gathering System or the failure or inability of the operator of the takeaway facilities at the Delivery Points to receive Crude Oil (collectively, “Permissible Interruptions”). Gatherer shall (a) provide to Shipper reasonably prompt notice of any such event, specifying the anticipated duration thereof, (b) proceed with due diligence to restore service as promptly as commercially practical under the circumstances and (c) subject to Applicable Law, take so much of Shipper’s Oil as may be physically gathered on the Gathering System given such event as a first priority and in preference to all other volumes of Crude Oil that Gatherer may otherwise receive into the Gathering System.

5.5Shipper shall be solely responsible for any and all Crude Oil imbalances it may have with the pipelines downstream of the Gathering System and Gatherer shall have no liability whatsoever, financial or otherwise, to any Person for any such Crude Oil imbalances. Gatherer shall work in good faith in conjunction with Shipper in administering and resolving any imbalance statements that may be issued by the downstream pipelines.

5.6The Parties shall meet by not later than two months after the Effective Date, and then at least every three months thereafter, to discuss Shipper’s Projected Volumes for the next six fiscal quarters.

ARTICLE VICONTROL OF OIL

6.1Shipper, at its sole risk, cost and expense, shall own, construct, equip, install, operate and maintain, or contract for, all lines and other necessary trucks and facilities, including atmospheric tank batteries, to transport and store Shipper’s Oil as contemplated by this Agreement.

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6.2As between Gatherer and Shipper, Shipper shall be in control and possession of Shipper’s Oil and responsible for any Losses incurred by any Person in connection with Shipper’s Oil (a) until Shipper’s Oil is delivered to Gatherer at the Receipt Points and (b) after the Equivalent Volume has been redelivered by Gatherer for the account of Shipper at the Delivery Points.

6.3As between Gatherer and Shipper, Gatherer shall be in control and possession of Shipper’s Oil and responsible for any Losses incurred by any Person in connection with Shipper’s Oil (a) after Shipper’s Oil has been delivered to Gatherer at the Receipt Points and (b) until the Equivalent Volume is redelivered for the account of Shipper at the Delivery Points.

6.4At all times, title to Shipper’s Oil shall remain with Shipper and not with Gatherer.

6.5Notwithstanding anything stated to the contrary herein, Shipper reserves the following rights (the Reservations”):

(a)The right to operate the Interests free from control by Gatherer and in such a manner as Shipper, in Shipper’s sole discretion, may deem advisable, including without limitation, the right, but never the obligation, to drill new wells, to repair and rework old wells, to renew or extend in whole or in part any leases and to abandon any well or surrender any lease in whole or in part.

(b)The right to deliver Shipper’s Oil to the “lessors” under any leases for which such lessors are entitled to receive Shipper’s Oil in kind from the Interests under the terms of such leases.

(c)The right to pool or unitize any leases (or any portion thereof) with other lands and leases. In the event of pooling or unitization, this Agreement shall cover Shipper’s Interest in the pool or unit and the Shipper’s Oil attributable thereto.

(d)The right to disconnect, at Shipper’s sole risk, cost and expense, any Excluded Unit or any Outside Unit from the Gathering System.

(e)The right to stabilize Shipper’s Oil for the purpose of lowering API Gravity, and the right to sell or transport natural gas liquids or condensate resulting from the stabilization and cooling process from the tank battery locations.

ARTICLE VIIMEASUREMENT AND TESTING

For purposes of this Agreement, (a) measurement of all volumes of Shipper’s Oil and determination of the sulfur content and API Gravity of Shipper’s Oil shall be undertaken on an “as delivered basis” and (b) determination of the API Gravity, sediment and water and sulfur content of Shipper’s Oil shall be undertaken in accordance with the procedures and requirements described on Exhibit C attached hereto. Each Day, Gatherer shall provide Shipper with all Receipt Point and Delivery Point Shipper’s Oil volumes attributable to Shipper’s Oil and tank levels in a computer file that may be uploaded by Shipper. Each Month, Gatherer shall determine the API Gravity, sediment and water and sulfur content of Shipper’s Oil received at a particular Receipt Point and provide such information to Shipper.

ARTICLE VIIIQUALITY

8.1Shipper’s Oil shall, in the aggregate at any given Receipt Point, conform to the specifications, as may be amended or enforced from time to time, of the Tariff (collectively, the “Specifications”); provided,

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however, that Shipper’s Oil must be able to be blended at the CDP to meet the stricter of the following specifications: (i) the Tariff and (ii) the downstream pipelines receiving the Equivalent Volumes of Shipper’s Oil.

8.2Should Shipper’s Oil fail at any time to conform to any and/or all of the Specifications, Gatherer may (without prior notice to Shipper) immediately suspend receipt of any off-specification Shipper’s Oil; provided, however, that Gatherer shall give notice to Shipper as promptly as is reasonably possible after Gatherer obtains knowledge of such nonconformance to allow Shipper to correct such condition(s). Should Shipper’s Oil fail to conform to any and/or all of the Specifications at a given Receipt Point, Shipper may sell such volumes of Shipper’s Oil free from the dedications under this Agreement until such time as Shipper’s Oil conforms to the Specifications. Gatherer shall not be obligated to accept Shipper’s Oil for delivery unless and until Shipper’s Oil conforms to the Specifications. Shipper shall be solely responsible for all Losses resulting from delivery of Shipper’s Oil that does not conform to the Specifications.

8.3The receipt by Gatherer of Shipper’s Oil that fails to meet any one of the Specifications shall not be held to be a waiver of Gatherer’s right to refuse future receipts of Shipper’s Oil or relieve Shipper of any indemnity obligation under Article XVI.

ARTICLE IXMINIMUM VOLUME COMMITMENT; FEES

9.1Each Month during the Term hereof, Shipper (together with its Affiliates and Successors) shall deliver to Gatherer at the Receipt Points a minimum of 15,000 Barrels per Day (the “Minimum Volume Commitment”) for ten (10) years beginning on the System Completion Date. For purpose of calculating Shipper’s delivery of the Minimum Volume Commitment, (a) volume shall be calculated based on the trailing three (3) Month average volume gathered by Gatherer on the Gathering System and trucked by Gatherer pursuant to this Agreement and (b) volumes gathered via the Gathering System shall be counted before volumes trucked by Gatherer. In the event that Shipper does not deliver the Minimum Volume Commitment in any given Month, Gatherer shall charge the Tier 1 Gathering Fee on the aggregate Minimum Volume Commitment for such Month in lieu of the Gathering Fees contemplated by Section 9.2(a).

9.2As consideration of the services rendered by Gatherer under this Agreement, Shipper shall pay to Gatherer the following fees (the “Fees”):

(a)A Gathering Fee on all of Shipper’s Oil delivered at the Delivery Points via the Gathering System from wells in the Core Units and the Additional Units based on the following volumetric tiers:

Tier 1:	First 15,000 Barrels per Day	-	$1.75 per Barrel
Tier 2:	Greater than 15,000 and less than 30,000 Barrels per Day	-	$1.50 per Barrel
Tier 3:	Greater than 30,000 Barrels per Day	-	$1.00 per Barrel
For the avoidance of doubt, the rates in the table above are tiered. The Tier 1 rate applies to the first 15,000 Barrels per Day of transported volumes, the Tier 2 rate applies to the next 15,000 Barrels per Day of transported volumes and the Tier 3 rate applies to volumes in excess of 30,000 Barrels per Day.

(b)A Gathering Fee on all of Shipper’s Oil delivered at the Delivery Points via the Gathering System from wells in the Excluded Units and the Outside Units (“Excluded Volumes”)

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equal to $1.00 per Barrel (the “Preferential Fee”); provided, however, that in the event Shipper has delivered less than the Minimum Volume Commitment in the applicable Month, the Preferential Fee will be equal to the Tier 1 Gathering Fee with respect to such amount of Excluded Volumes as is necessary for Shipper to meet the Minimum Volume Commitment.

(c)A Trucking Fee equal to (x) $1.75 per Barrel on all of Shipper’s Oil trucked by Gatherer from the Receipt Points to the CDP or any other Delivery Point until such time as Shipper has delivered the Minimum Volume Commitment and (y) $1.25 per Barrel on all additional Shipper’s Oil trucked by Gatherer from the Receipt Points to the CDP or any other Delivery Point above the Minimum Volume Commitment.

(d)A Truck Loading Fee equal to $0.25 per Barrel on all of Shipper’s Oil either loaded onto or unloaded from trucks at the CDP or any other Delivery Point agreed to by the Parties; provided, however, that no Truck Loading Fee shall apply to any Barrels of Shipper’s Oil trucked by Gatherer pursuant to the terms of this Agreement.

9.3Beginning in the second year following the System Completion Date, the Tier 2 Gathering Fee, the Tier 3 Gathering Fee, the Preferential Fee and the Truck Loading Fee will be increased by the amount equal to the annual percentage increase change in the Producer Price Index (the “PPI Adjustment”). The Tier 1 Gathering Fee will be subject to the PPI Adjustment beginning in the eleventh year following the Effective Date. In no event shall (i) the PPI Adjustment be greater than three percent (3%) in any given year or (ii) the Tier 2 Gathering Fee or the Tier 3 Gathering Fee exceed the Tier 1 Gathering Fee.

ARTICLE XTERM

The term of this Agreement shall commence on the Effective Date and shall terminate on the twenty-fifth (25^th) anniversary of the System Completion Date (the “Term”); provided, however, that if Gatherer has received no Shipper’s Oil from Shipper for any period of twelve (12) consecutive months, Gatherer may terminate this Agreement upon written notice to Shipper.

ARTICLE XISTATEMENTS AND PAYMENTS

11.1On or before the 20^th day of each Month, Gatherer shall render to Shipper a statement (in both a PDF format and an electronic format suitable for download (Excel, CVS)) showing, for the immediately preceding Month, the volume and specifications of Shipper’s Oil received at each Receipt Point and the Equivalent Volumes delivered for Shipper’s account at each Delivery Point. In such statement, Gatherer shall include a calculation of the Fees determined in accordance with Article IX. Shipper shall pay the amount shown on such statement for the Fees to Gatherer within ten (10) Days following the date of Gatherer’s statement under this Section 11.1. All amounts due hereunder and remaining unpaid when due shall bear interest at the Prime Rate plus two percent per annum until paid, except amounts disputed in good faith.

11.2Either Party or its agent shall have the right, at reasonable times during business hours and at its sole risk, cost and expense, to examine the books and records of the other to the extent necessary to audit and verify the accuracy of any statement made pursuant to this Agreement.

11.3In the event an error is discovered in any such statement, such error shall be adjusted without interest or penalty as soon as reasonably possible, but in any event, within two (2) months from the date that such

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error is discovered; provided however, that any such statement is hereby deemed final as to both Parties unless disputed in writing within two (2) years from the date of such statement.

ARTICLE XIIREGULATION

12.1This Agreement shall be governed by and shall be construed in accordance with the laws of the State of Texas without reference to its conflict of laws principles. This Agreement and each provision hereof shall be subject to all Applicable Laws. Should either of the Parties, by force of any such Applicable Law, at any time during the Term be ordered or required to do any act inconsistent with the provisions hereof, then for that period during which the requirements of such Applicable Law are applicable to this Agreement, this Agreement shall be deemed modified to conform with the requirement of such Applicable Law, while preserving the commercial terms provided for in this Agreement to the extent reasonably possible; provided, however, that nothing herein shall alter, modify or otherwise affect the respective rights of the Parties to cancel or terminate this Agreement under the terms and conditions hereof. Further, either Party shall have the right to contest the validity of any such Applicable Law and neither acquiescence thereto nor compliance therewith for any period of time, nor any other provision contained herein, shall be construed as a waiver of such right.

12.2Gatherer has informed Shipper, and Shipper hereby acknowledges and accepts, that the Gathering System will be an intrastate pipeline system operating only within the State of Texas, and is not intended to be subject to regulation under any Applicable Law by the Federal Energy Regulatory Commission (the “FERC”), or any successor thereof. Accordingly, as a principal condition to, and in consideration for, the execution of this Agreement by Gatherer, Shipper represents, warrants and covenants that (i) none of Shipper’s Oil delivered hereunder has been or will be dedicated to or delivered in interstate commerce, (ii) at the time Shipper’s Oil is delivered at the Receipt Points, Shipper shall not have identified any destination for Shipper’s Oil which is outside the State of Texas and Shipper does not intend to deliver any of Shipper’s Oil to be sold, transported or otherwise moved outside the State of Texas, (iii) all of Shipper’s Oil delivered to Gatherer under this Agreement shall be produced in the State of Texas, and (iv) Shipper’s Oil delivered hereunder is not intended to be transported or sold in interstate commerce in any manner which will subject the Gathering System to regulation by the FERC. In the event that Shipper breaches its representation, warranty and covenant contained in this Section 12.2, Gatherer, in addition to all other remedies at law or in equity, shall have the right, upon delivery of written notice to Shipper, to refuse receipt of Shipper’s Oil which has caused a breach of such representation, warranty and covenant. Gatherer’s election to refuse receipt of any of Shipper’s Oil pursuant to this Section 12.2 shall not release Shipper from any obligation to indemnify Gatherer for such breach under Article XVI or to pay for all Minimum Volume Commitments.

12.3The Parties acknowledge that Gatherer is a common carrier for hire, and this Agreement and all gathering services performed by it on the Gathering System for Shipper pursuant to this Agreement, shall be subject to the rules and regulations in the Tariff, including, without limitation, laws and regulations that prevent discrimination in favor of any given shipper or the provision of service for consideration other than the rate set forth in a published tariff; provided, however, that as between Gatherer and Shipper, if there is a conflict between the terms and conditions of this Agreement and the terms and conditions of the Tariff, the terms and conditions of the Tariff will govern and control.

12.4Shipper hereby covenants and agrees that it shall not, and shall not allow any Affiliate to, challenge any rate, fee, specification or other term of any tariff filed or proposed by Gatherer with any applicable Governmental Authority asserting or attempting to assert jurisdiction over all or any portion of the Gathering System so long as such rate, fee, specification or other term is no more unfavorable than the terms and conditions of this Agreement and the Tariff (it being understood that Gatherer and Shipper intend for this

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Agreement and the Tariff to constitute the sole terms and conditions relating to Shipper’s use of the Gathering System). This Section 12.4 shall be binding upon any Successor or any Affiliate of such Successor.

12.5If Gatherer does not have the capacity on the Gathering System to take and receive 100% of Shipper’s Oil in accordance with Section 5.1 (the “Necessary Capacity”) (including as a result of an Event of Force Majeure), Gatherer agrees to take commercially reasonable actions to replace or restore the portion of such capacity that is unavailable. Gatherer will commence and complete such action within a commercially reasonable period of time to minimize the service disruption. During any interim period when any portion of the Necessary Capacity is unavailable, Shipper may sell any of Shipper’s Oil produced from the wells affected by the capacity shortage free from the dedications under to this Agreement until such time as Gatherer has restored the Necessary Capacity. In the event that Shipper sells Shipper’s Oil free from the dedications under to this Agreement pursuant to this Section 12.5, all such volumes shall be deemed to have been actually delivered for the purpose of satisfying the Minimum Volume Commitment.

ARTICLE XIIITAXES AND ROYALTIES

13.1Shipper shall be obligated to pay all Taxes levied, assessed or collected with respect to the production of Shipper’s Oil or the delivery thereof to the Receipt Points, including any Tax levied, assessed or collected as a result of any Change in Law. In addition, Shipper shall be obligated to pay all Taxes levied, assessed or collected with respect to the services rendered hereunder to the extent that any such Tax is levied, assessed or collected as a result of any Change in Law. To the extent any such Taxes are not assessed directly with respect to Shipper’s Oil or the services rendered hereunder, Gatherer shall calculate and assess any such Taxes on a pro rata basis (calculated on a per Barrel basis based on the volume of Shipper’s Oil on the Gathering System at the time such calculation is made). Notwithstanding the foregoing, any (i) Tax that may be based on the gross revenues, operating income or net income of Gatherer, or (ii) ad valorem, real property, personal property or similar Taxes based on ownership of the Gathering System, shall be borne by Gatherer.

13.2Shipper shall timely pay all Taxes described in Section 13.1. In the event that Shipper fails to timely pay any such Taxes, Gatherer may, upon two (2) Days’ notice, pay them and deduct the amount so paid from any sums owned by Gatherer to Shipper hereunder.

13.3In addition to the Taxes described in Section 13.1, Shipper shall be responsible for the payment of all royalties, overriding royalties, production payments, fees, charges or other payments attributable to Shipper’s Oil (including any such royalties, overriding royalties, production payments, fees, charges or payments with respect to liquefiable hydrocarbons or other constituents contained therein or removed therefrom).

ARTICLE XIVREPRESENTATIONS AND WARRANTIES

14.1Each Party hereby represents and warrants to the other Party that:

(a)Such Party is a limited partnership or limited liability company, as applicable, duly formed, validly existing and in good standing under the laws of the State of Texas (in the case of Shipper) or the State of Delaware (in the case of Gatherer), with full limited partnership or limited liability company, as applicable, power, right and authority to own and lease the assets and properties it currently owns and leases, and to carry on its business as such business is currently being conducted.

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(b)Such Party has all requisite power and authority to execute and deliver this Agreement, to perform its obligations hereunder and to consummate the transactions contemplated hereby. The execution and delivery by such Party of this Agreement and the performance by each Party of its obligations hereunder have been duly and validly authorized by all necessary limited partnership or limited liability company, as applicable, proceedings on the part of such Party. This Agreement has been duly and validly executed and delivered by such Party and constitutes the legal, valid and binding obligation of such Party enforceable against such Party in accordance with its terms, except as the same may be limited by bankruptcy, insolvency, reorganization, arrangement, moratorium or other similar laws relating to or affecting the rights of creditors generally or by general equitable principles regardless of whether considered in a proceeding at law or in equity.

(c)The execution and delivery by such Party of this Agreement does not, and the performance by such Party of its obligations under this Agreement and the consummation of the transactions contemplated hereby will not (i) conflict with or result in a violation or breach of any of the terms, conditions or provisions of the organizational documents of such Party, (ii) violate or result in a default (or give rise to any right of termination, cancellation or acceleration) under any contract or agreement to which such Party is a party, or require any notice under any contract or agreement to which such Party is a party or by which it is bound, (iii) violate or breach any Applicable Law or (iv) require the consent, approval or authorization of, filing with or notice to any Person, which, if not obtained, would prevent such Party from performing its obligations hereunder.

14.2In addition to its representations and warranty in Section 12.2, Shipper represents and warrants, for itself, its successors and assigns, to Gatherer that (i) Shipper has good title to (or otherwise has the right to deliver) all of Shipper’s Oil delivered hereunder and all of Shipper’s Oil delivered hereunder is free and clear of any and all liens and encumbrances and (ii) as of the Effective Date, no Interest is a Prior Dedicated Interest.

14.3Gatherer represents and warrants, for itself, its successors and assigns, to Shipper that from the time of receipt at the Receipt Points to the time of delivery at the Delivery Points all of Shipper’s Oil delivered hereunder shall be free and clear of any and all liens and encumbrances.

ARTICLE XVEASEMENTS

To the extent that it may contractually or lawfully do so under its Easements, each Party hereby grants, assigns and transfers to the other Party or its designee an easement on or across the granting Party’s Easements, together with the right of ingress and egress, for the purpose of installing, using, inspecting, repairing, operating, replacing and/or removing pipe, meters, lines, electrical power-related equipment and other equipment used or useful in the performance of this Agreement. It is intended that any personal property of the Parties or their designees placed in or upon any of such real property shall remain the personal property of the respective Party or its designee, subject to removal by it within a reasonable time after the expiration or termination of this Agreement.

ARTICLE XVIINDEMNITY

16.1Shipper hereby agrees to indemnify, protect, defend and hold harmless Gatherer, its Affiliates and each of its and their respective officers, directors, employees, agents, partners, representatives, contractors, subcontractors, consultants and advisors (collectively, “Gatherer Indemnitees”) from and against any and all Losses arising out of or resulting from (a) Shipper’s Oil, except to the extent such Losses arise in connection

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with any action or failure to act by Gatherer while Shipper’s Oil is in the possession and control of Gatherer, (b) the breach of any representation or warranty of Shipper contained in this Agreement, (c) the breach of any other agreement, covenant or obligation of Shipper in this Agreement and (d) Shipper’s business operations, including all noise, odors, Emissions, pollution or other contamination whatsoever occurring in connection with such operations.

16.2Gatherer hereby agrees to indemnify, protect, defend and hold harmless Shipper, its Affiliates and each of its and their respective officers, directors, employees, agents, partners, representatives, contractors, subcontractors, consultants and advisors (collectively, “Shipper Indemnitees”) from and against any and all Losses arising out of or resulting from (a) Shipper’s Oil if such Losses arise in connection with any action or failure to act of Gatherer while Shipper’s Oil is in the possession and control of Gatherer, (b) the breach of any representation or warranty of Gatherer contained in in this Agreement, (c) the breach of any other agreement, covenant or obligation of Gatherer in this Agreement and (d) Gatherer’s business operations, including all noise, odors, Emissions, pollution or other contamination whatsoever occurring in connection with such operations.

16.3GATHERER HEREBY RELEASES SHIPPER FROM ANY LIABILITY FOR, AND HEREBY AGREES TO INDEMNIFY, PROTECT, DEFEND AND HOLD HARMLESS EACH SHIPPER INDEMNITEE FROM AND AGAINST, ALL LOSSES, WITHOUT REGARD TO THE CAUSE OR CAUSES THEREOF OR THE NEGLIGENCE OF ANY SHIPPER INDEMNITEE, ARISING IN CONNECTION HEREWITH IN FAVOR OF ANY EMPLOYEE, CONTRACTOR OR CONSULTANT OF ANY GATHERER INDEMNITEE ON ACCOUNT OF BODILY INJURY, DEATH OR DAMAGE TO PROPERTY OF SUCH EMPLOYEE OR CONSULTANT.

16.4SHIPPER HEREBY RELEASES GATHERER FROM ANY LIABILITY FOR, AND HEREBY AGREES TO INDEMNIFY, PROTECT, DEFEND AND HOLD HARMLESS EACH GATHERER INDEMNITEE, FROM AND AGAINST, ALL LOSSES, WITHOUT REGARD TO THE CAUSE OR CAUSES THEREOF OR THE NEGLIGENCE OF ANY GATHERER INDEMNITEE, ARISING IN CONNECTION HEREWITH IN FAVOR OF ANY EMPLOYEE, CONTRACTOR OR CONSULTANT OF ANY SHIPPER INDEMNITEE ON ACCOUNT OF BODILY INJURY, DEATH OR DAMAGE TO PROPERTY OF SUCH EMPLOYEE OR CONSULTANT.

16.5All indemnity obligations and liabilities assumed by the Parties under terms of this Agreement shall be without limit, and shall survive until the second (2^nd) anniversary of the termination of this Agreement.

16.6Each Party shall procure and maintain during the entire Term, at its own expense, with an insurance company or companies authorized to do business in the State of Texas or through a self-insurance program, insurance coverages of the kind and in the specified minimum amounts set forth on Exhibit D attached hereto.

ARTICLE XVIINOTICES AND STATEMENTS

17.1All notices, statements, payments and other communications required or permitted to be given hereunder shall be in writing and shall be deemed to have been effectively given when deposited in the United States mail or with an overnight courier service, or when sent via email or facsimile, as the case may be, addressed to:

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Notices:

If to Gatherer:	If to Shipper:
Republic Midstream, LLC c/o ArcLight Capital Partners, LLC 200 Clarendon Street, 55th Floor Boston, MA 02117 Attn: Christine Miller Email: cmiller@arclightcapital.com Facsimile: (617) 867-4698	Penn Virginia Oil & Gas, L.P. 840 Gessner, Suite 800 Houston, TX 77024 Attn: Vice President, Oil & Gas Marketing Email: jill.zivley@pennvirginia.com Facsimile: (713) 722-6601
With a copy to:	With a copy to:
American Midstream Partners, L.P. 1400 16th Street, Suite 310 Denver, CO 80202 Attn: William B. Mathews Email: bmathews@americanmidstream.com Facsimile: (720) 457-6040 and JP Energy Partners LP 600 East Las Colinas Blvd., Suite 2000 Irving, TX 75039 Attn: Legal Department Email: Legal@jpep.com Facsimile: (972) 444-0320	Penn Virginia Corporation Four Radnor Corporate Center, Suite 200 100 Matsonford Road Radnor, PA 19087-4564 Attn: General Counsel Email: nancy.snyder@pennvirginia.com Facsimile: (610) 687-3688

Statements:

Penn Virginia Oil & Gas, L.P.

840 Gessner, Suite 800

Houston, TX 77024

Attn: Vice President, Oil & Gas Marketing

Email: jill.zivley@pennvirginia.com

Facsimile: (713) 722-6601

Payments:

Comerica Bank

1717 Main Street

Dallas, Texas 75201

ABA Routing #111000753

For Account of: Republic Midstream, LLC

Account #: 1881761173

17.2Notices of change of address of either Party shall be given in writing to the other in the manner aforesaid and shall be observed in the giving of all future notices, statements or other communications required or permitted to be given hereunder.

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ARTICLE XVIIIFORCE MAJEURE

18.1Upon occurrence of an event of Force Majeure, Shipper’s or Gatherer’s obligation to perform, wholly or in part, any commitment or undertaking set forth in this Agreement, other than the obligation to make payments of amounts due hereunder (including the obligations set forth in Section 9.1), shall be suspended to the extent and for the period of such Force Majeure condition; provided, however, that the Party whose obligations are so affected shall promptly give written notice to the other Party describing the event of Force Majeure in reasonable detail.

18.2Should there be an event of Force Majeure affecting performance hereunder, such events shall be remedied with all reasonable dispatch to ensure resumption of normal performance.

18.3Notwithstanding Section 18.2, settlement of strikes and lockouts shall be entirely within the discretion of the Party affected, and the requirement in Section 18.2 that any event of Force Majeure shall be remedied with all reasonable dispatch shall not require the settlement of strikes and lockouts by acceding to the demands of the third parties directly or indirectly involved in such strikes or lockouts when such course is inadvisable in the discretion of the Party having such difficulty.

ARTICLE XIXCONFIDENTIAL INFORMATION

19.1Except as permitted by Section 19.2, (i) each Party shall keep confidential all Confidential Information and shall not disclose any Confidential Information to any Person and (ii) each Party shall use the Confidential Information only in connection with the operation of the Gathering System.

19.2Notwithstanding Section 19.1, but subject to the other provisions of this Article XIX, a Party may make the following disclosures and uses of Confidential Information:

(a)disclosures required for such Party to perform its duties under this Agreement;

(b)disclosures to an Affiliate of such Party, including the representatives of such Affiliate, for purposes in furtherance of the operation of the Gathering System and has agreed to abide by the terms of this Article XIX;

(c)disclosures to a Person that is not a Party or an Affiliate of a Party, if such Person has been retained by Gatherer to provide services in connection with the operation of the Gathering System and has agreed to abide by the terms of this Article XIX;

(d)disclosures to a bona-fide potential direct or indirect purchaser of the Gathering System and the advisors or representatives of such potential purchaser, if such potential purchaser has agreed to abide by the terms of this Article XIX;

(e)disclosures to working interest or joint venture partners with respect to leases or wells in the Dedication Area;

(f)disclosures required by Applicable Law or the rules of any national securities exchange or automated quotation system;

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(g)disclosures to financial institutions requiring such disclosure as a condition precedent to making or renewing a loan or in connection with any covenant made in connection with such loan(s) or any existing loan of such Party or its Affiliates; and

(h)disclosures to the legal advisors, financial advisors, consultants or independent certified public accountants for such Party or its Affiliates.

19.3Each Party shall take such precautionary measures as may be required to ensure (and such Party shall be responsible for) compliance with this Article XIX by any of its representatives and other Persons to which it may disclose Confidential Information in accordance with this Article XIX.

19.4The Parties agree that no adequate remedy at law exists for a breach or threatened breach of any of the provisions of this Article XIX, the continuation of which, if not remedied, shall cause the non-breaching Party to suffer irreparable harm. Accordingly, the Parties agree that each Party shall be entitled, in addition to other remedies that may be available to such Party, to immediate injunctive relief from any breach of any of the provisions of this Article XIX and to specific performance of its rights hereunder, as well as to any other remedies available at law or in equity.

19.5The obligations of the Parties under this Article XIX shall terminate on the second anniversary of the termination of this Agreement.

ARTICLE XXASSIGNMENT OR SALE OF GATHERING SYSTEM

20.1Gatherer may not sell, assign or transfer any of its rights or obligations under this Agreement, or any of its right, title and interests in or to the Gathering System, without the prior written consent of Shipper which shall not be unreasonably withheld, conditioned or delayed. Notwithstanding the foregoing, Gatherer may, without Shipper’s consent, (i) sell all, or any portion of, the Gathering System to JP Energy Partners, LP, American Midstream Partners L.P. or any respective subsidiary thereof, (ii) assign, mortgage, hypothecate, pledge or otherwise encumber all or any portion of Gatherer’s interest in and to this Agreement (including its rights and obligations hereunder), and/or its right, title and interest in and to the Gathering System in favor of any Financing Party and its successors and assigns (each a, “Collateral Assignment”), and (iii) following the System Completion Date, sell, assign or transfer all, but not less than all, of the Gathering System, and the associated rights and obligations under this Agreement, to a Reputable and Prudent Operator.

20.2As used herein, a “Reputable and Prudent Operator” shall mean any entity that: (i) is a pipeline operator which, in Shipper’s reasonable opinion, is experienced in operating gathering and pipelines systems similar to the Gathering System; (ii) has not filed a voluntary bankruptcy proceeding or been declared a bankrupt involuntarily; (iii) has not been blocked by any Governmental Authority from holding any permits, licenses or approvals necessary to operate the Gathering System as contemplated by this Agreement; (iv) has a health, safety and environmental compliance record reasonably satisfactory to Shipper; and (v) has a net worth of $100 million or more on a consolidated basis.

20.3Notwithstanding the foregoing or anything in this Agreement to the contrary, Shipper agrees that in connection with a Collateral Assignment, any such Financing Party may assign such right, title and interests in and to this Agreement and/or the Gathering System to a Reputable and Prudent Operator in connection with the sale, transfer or exchange of its rights under this Agreement or right, title, and interests in the Gathering System or for the purpose of operating the Gathering System pursuant to such assignment upon

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and after the exercise of its rights and enforcement of its remedies against the Gathering System under any deed of trust or other security instrument creating a lien, security interest or other rights in its favor.

20.4No assignment of this Agreement shall be made by Shipper except to a Person that is acquiring an interest in all or part of the Dedication Area contemporaneous with such assignment. Furthermore, Shipper may not sell, assign or transfer any of its rights or obligations under this Agreement without the prior written consent of Gatherer, which shall not be unreasonably withheld, conditioned or delayed. Notwithstanding the foregoing, Shipper may, without Gatherer’s consent, sell, assign or transfer any of its rights or obligations under this Agreement to a creditworthy entity with net assets at least equal to the net assets of Shipper on the date of assignment or transfer.

ARTICLE XXIMISCELLANEOUS

21.1All Article, Section and Exhibit references used in this Agreement are to Articles, Sections and Exhibits to this Agreement unless otherwise specified. The Exhibits attached to this Agreement constitute a part of this Agreement and are incorporated herein for all purposes.

21.2If a term is defined as one part of speech (such as a noun), it shall have a corresponding meaning when used as another part of speech (such as a verb). Unless the context of this Agreement clearly requires otherwise, words importing the masculine gender shall include the feminine and neutral genders and vice versa. The words “includes” or “including” shall mean “includes without limitation” or “including without limitation,” the words “hereof,” “hereby,” “herein,” “hereunder” and similar terms in this Agreement shall refer to this Agreement as a whole and not any particular Section or Article in which such words appear and any reference to an Applicable Law shall include any amendment thereof or any successor thereto and any rules and regulations promulgated thereunder. Currency amounts referenced herein are in U.S. Dollars.

21.3This Agreement may be executed in as many counterparts as deemed necessary. When so executed, the aggregate counterparts shall constitute one Agreement and shall have the same effect as if both Parties signing counterparts had executed the same instrument.

21.4This Agreement may not be amended or modified except pursuant to a written instrument signed by both of the Parties. Either Party may waive on its own behalf compliance by the other Party with any term or provision hereof; provided, however, that any such waiver shall be in writing and shall not bind the non-waiving Party. The waiver by either Party of a breach of any term or provision shall not be construed as a waiver of any subsequent breach of the same or any other provision.

21.5This Agreement is binding upon and shall inure to the benefit of the successors and permitted assigns of the Parties.

21.6The Parties agree and confirm that this Agreement was prepared jointly by both Parties and not by any one Party to the exclusion of the other.

21.7Except as provided in Article XVI, this Agreement is not intended to confer upon any Person not a party hereto any rights or remedies hereunder, and no Person other than the Parties is entitled to rely on or enforce any provision hereof.

21.8This Agreement (including the Exhibits attached hereto) contains the entire agreement between the Parties with respect to the subject matter hereof, and there are no prior agreements, understandings, representations or warranties between the Parties, other than those set forth or referred to herein or therein.

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21.9NO PARTY, INCLUDING AND ON BEHALF OF, GATHERER INDEMNITIES AND SHIPPER INDEMNITIES, SHALL UNDER ANY CIRCUMSTANCES BE LIABLE FOR SPECIAL, CONSEQUENTIAL, INCIDENTAL, PUNITIVE OR EXEMPLARY DAMAGES, WHETHER BY STATUTE, IN TORT OR BY CONTRACT OR OTHERWISE, EXCEPT WHERE SUCH DAMAGES WERE CAUSED BY THE WILLFUL MISCONDUCT OR FRAUD OF SUCH PARTY. THE PROVISIONS OF THIS SECTION 21.9 SHALL BE ENFORCEABLE ONLY TO THE EXTENT ALLOWED BY, AND SHALL BE SUBJECT TO, ANY APPLICABLE REQUIREMENTS AND PROCEDURES SET FORTH IN, APPLICABLE LAW.

21.10In the event of litigation arising with respect to this Agreement, either Party may offer into evidence an electronic image of the signed Agreement, any amendment hereto or any correspondence exchanged in connection herewith and shall not be required to maintain or produce an original paper copy of any such document. Any such electronic copy shall be deemed an original and may be admitted into evidence for all purposes, notwithstanding the “best evidence” rule or any other rule of evidence that would prohibit or restrict its admissibility.

[Signature Page Follows]

IN WITNESS WHEREOF, the Parties have executed this Agreement as of the day and year hereinabove first written.

REPUBLIC MIDSTREAM, LLC

By:

Name:    Daniel R. Revers

Title:    President

PENN VIRGINIA OIL & GAS, L.P.

By:    Penn Virginia Oil & Gas GP LLC,

its general partner

By:

Name:    Jill T. Zivley

Title:    Vice President, Oil & Gas Marketing

25

EX-10.6

Exhibit 10.6

* Confidential treatment has been requested with respect to portions of this agreement as indicated by “[***]” and such confidential portions have been deleted and filed separately with the Securities and Exchange Commission pursuant to Rule 24b-2 of the Exchange Act of 1934, as amended.

FIRST AMENDED AND RESTATED
CRUDE OIL MARKETING AGREEMENT

This First Amended and Restated Crude Oil Marketing Agreement (this "Agreement") is made and entered into this 1st day of August, 2016 (the "Effective Date") by and among Penn Virginia Oil & Gas, L.P. ("PVOG"), Republic Midstream Marketing, LLC ("Republic") and solely for purposes of Article V of this Agreement, Penn Virginia Corporation ("PVOG Guarantor"). PVOG and Republic may be referred to individually as a "Party" or collectively as the "Parties." This Agreement supersedes and replaces that certain Crude Oil Marketing Agreement, dated July 30, 2014, as amended on September 24, 2015, by and between the Parties.

WHEREAS, Republic is making a minimum volume commitment to the Kinder Morgan Crude & Condensate pipeline ("KMCC");

WHEREAS, PVOG desires to make a minimum volume commitment to sell 8,000 barrels per day of crude oil, and to deliver [***] crude oil (i) produced from PVOG-operated wells in Lavaca, Fayette, and Gonzalez Counties, Texas (insofar and only insofar as PVOG has the right to market such volumes) and (ii) produced from wells in Lavaca, Fayette, and Gonzalez Counties, Texas in which PVOG, on or after the Effective Date, resigns as operator (other than any resignation pursuant to a legitimate business purpose (other than circumvention of PVOG's obligations under Article I.3.)) and has the right to take its share of production in kind, to Republic or other parties [***] and to have the option to buy such barrels back at one or more delivery points [***] (the "KMCC Regulations Tariff");

WHEREAS, PVOG is making the Commitment (as defined below) to Republic to support Republic's minimum volume commitment to KMCC;

WHEREAS, the Parties desire to set forth the options available to PVOG to fulfill the Commitment; and

WHEREAS, the Parties desire to set forth the "form" Crude Oil Sale Agreement to be used by PVOG in the event it wishes to sell barrels outright to Republic (with no re-delivery obligation) at any location.

NOW THEREFORE, in consideration of the mutual covenants, terms and conditions herein contained, together with other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, and intending to be legally bound hereby, the Parties hereby agree as follows:

ARTICLE I    
PVOG'S MINIMUM VOLUME COMMITMENT TO REPUBLIC

1. Minimum Volume Commitment. Subject to any Force Majeure Event and any Enumerated Circumstance (each as defined below), during each month during the Term (as defined below), PVOG agrees to deliver on an aggregate average daily basis at least 8,000 barrels per day of crude oil pursuant to one of the methods set forth in this Agreement (such amount, the "Commitment"). For the avoidance of doubt, the Commitment shall be determined on a monthly basis.

a. In the event that PVOG's aggregate daily deliveries hereunder during any monthly period are less than the Commitment for that month, and no Over-Delivery Credits are then outstanding, then a deficiency (the "Deficiency") shall exist. PVOG will be obligated to pay to Republic an amount for each deficient barrel equal to the Transportation Deduction (such amount, the "Deficiency Fees").

b. Republic shall invoice PVOG monthly for any Deficiency Fees. In the event that PVOG ships volumes in excess of the Commitment in any given month, PVOG shall be entitled to a credit against any Deficiency Fees assessed by Republic in the subsequent twelve (12) months, or any Deficiency Fees paid by PVOG in the preceding twelve (12) months, in an amount equal to the surplus barrels multiplied by the Transportation Deduction (each, an "Over-Delivery Credit"). Over-Delivery Credits shall first be applied to any Deficiency Fees paid by PVOG during the preceding twelve (12) months, and shall be credited during the month corresponding to the applicable Over-Delivery Credit.

c. Over-Delivery Credits shall be applied only to volumes shipped in accordance with Article I, Section 2 below in excess of PVOG's Commitment for that month and shall be applied at all times on a first-in, first-out basis, so that the oldest month's Over-Delivery Credit is fully utilized before application of any subsequent month's Over-Delivery Credit. Over-Delivery Credits shall expire if not used by the end of the twelve (12) month period following the month during which such Over-Delivery Credit was created. At the end of the Term, any remaining unexpired or unutilized Over-Delivery Credits shall expire on the last day of the Term and will not be valid for use against any future shipments on KMCC.

2. Volumes Credited Toward PVOG's Commitment. Republic shall count toward the satisfaction of the Commitment all volumes shipped under each of the following arrangements:

a. PVOG Buy-Sell Volumes Delivered to KMCC. All crude oil volumes delivered and sold by PVOG to Republic at the PVOG Delivery Point (as defined below) and redelivered at a Republic Delivery Point (as defined below) pursuant to the provisions of Article II of this Agreement shall count toward the Commitment.

b. PVOG Outright Sales to Republic. All crude oil volumes sold outright (i.e., with no redelivery option or obligation) by PVOG to Republic at either (i) the CDP (as such term is defined in that certain First Amended and Restated Transportation Agreement by and between Republic Midstream, LLC and PVOG dated the date

2

* Confidential treatment has been requested with respect to portions of this agreement as indicated by “[***]” and such confidential portions have been deleted and filed separately with the Securities and Exchange Commission pursuant to Rule 24b-2 of the Exchange Act of 1934, as amended.

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hereof) or (ii) the PVOG Delivery Point pursuant to Article III of this Agreement shall, in either case, count toward the Commitment.

c. PVOG Outright Sales to Third Parties. All crude oil volumes sold outright by PVOG to third parties at either (i) the CDP or (ii) the PVOG Delivery Point ("Third Party Volumes") shall, in either case, count toward the Commitment so long as the following conditions are met:

i. Such Third Party Volumes must be transported on KMCC or, if such Third Party Volumes are not transported on KMCC, the third party must pay fees for each such barrel of Third Party Volumes to Republic equivalent to the Transportation Deduction per barrel of Third Party Volumes;

ii. If such Third Party Volumes are actually shipped on KMCC, the third party must enter into a crude oil purchase and sale agreement with Republic (each, a "Third Party Purchase and Sale Agreement") pursuant to which the third party will sell and deliver the Third Party Volumes to Republic at the PVOG Delivery Point and purchase and receive the Third Party Volumes at a Republic Delivery Point; and

iii. For the avoidance of doubt, each Third Party Purchase and Sale Agreement shall include a marketing fee of [***] per barrel purchased and sold thereunder (the "Marketing Fee"). Notwithstanding the foregoing, the Marketing Fee shall not be payable unless and until the Midstream Pipeline (as defined below) is operational. The foregoing fees shall be payable by the third party and not by PVOG.

d. Letter Agreement Regarding Buy-Sell Marketing Arrangements. The Parties acknowledge the existence of that certain Letter Agreement Regarding Buy-Sell Marketing Arrangements dated May 22, 2015, by and among the Parties and Republic Midstream, LLC, and agree that the terms set forth therein shall be incorporated in this Agreement for all purposes.

3. [***]. Beginning on the Effective Date and to the extent available, PVOG agrees to deliver (pursuant to one of the methods set forth in this Agreement) [***] crude oil (i) produced from PVOG-operated wells in Lavaca, Fayette, and Gonzalez Counties, Texas, which shall include volumes attributable to non-operating working interest owners insofar and only insofar as PVOG has the right to market such volumes and the non-operators have not elected to take their share of such production in kind and (ii) produced from wells in Lavaca, Fayette, and Gonzalez Counties, Texas in which PVOG, on or after the Effective Date, resigns as operator (other than any resignation pursuant to a legitimate business purpose (other than circumvention of PVOG's obligations under this Article I.3.)) and has the right to take its share of production in kind. Notwithstanding the foregoing, PVOG shall be deemed to have satisfied this obligation if the monthly average of the daily volumes delivered in a given month equals or exceeds [***].

3

* Confidential treatment has been requested with respect to portions of this agreement as indicated by “[***]” and such confidential portions have been deleted and filed separately with the Securities and Exchange Commission pursuant to Rule 24b-2 of the Exchange Act of 1934, as amended.

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ARTICLE II    
BUY-SELL OF VOLUMES TRANSPORTED ON KINDER PIPELINE

If PVOG desires to satisfy its volume commitment as provided in Article I, Section 2.a. above, then such transaction shall take the form of a buy-sell with Republic as specified below.

PVOG DELIVERY AND SALE TO REPUBLIC AT [***]

1. Quantity. Each month, PVOG shall provide Republic with written notice as to the nominations and quantity of volumes of crude oil it expects to tender for purchase by Republic at the PVOG Delivery Point during the following month (the "Shipment Schedule"). The Shipment Schedule shall also set forth the applicable Republic Delivery Point(s) to which PVOG desires that Republic re-deliver the crude oil. PVOG may nominate volumes in excess of the Commitment. PVOG shall deliver and sell to Republic, and Republic shall receive and purchase from PVOG, the quantity tendered by PVOG up to the Commitment. To the extent PVOG timely nominates and tenders more than the Commitment, Republic shall receive and purchase from PVOG such excess, but only to the extent that Republic and KMCC, as applicable, have physical capacity in excess of other commercial commitments sufficient to receive such excess.

2. Quality. The quality of the crude oil delivered by PVOG to Republic shall satisfy the requirements set forth in the KMCC Regulations Tariff (the "Specifications"). Republic will not be obligated to purchase crude oil that is contaminated or that otherwise fails to meet those Specifications ("Off-Spec Product"), except if such nonconformance is attributable to third party volumes commingled with PVOG's crude oil while in Republic or Republic Midstream, LLC's (or any applicable successor) control and possession.

3. Price. For each barrel of crude oil sold and delivered by PVOG to Republic hereunder, Republic agrees to pay to PVOG the Base Price less the Transportation Deduction (each as defined below).

a. "Base Price" means the calendar month average of the daily settlement price for the "Light Sweet Crude Oil" prompt month futures contracts reported by the New York Mercantile Exchange (NYMEX) from the first day of the delivery month through and including the last day of the delivery month, excluding weekends and NYMEX U.S. Holidays, plus the arithmetic average of the Daily Settlement Price for the Crude Contract reported by the NYMEX from the day the delivery month becomes the prompt trading month through the last day of trading for the delivery month, Trade Days Only, less the average of the daily settlement price for the second month NYMEX Crude Contract trading month the same period, times .6667 plus the arithmetic average of the Daily Settlement Price for the Crude Contract reported by the NYMEX from the day the delivery month becomes the prompt trading month through the last day of trading for the delivery month, Trade Days Only, less the average of the daily settlement price for the third month NYMEX contract trading over the same period, times .3333, plus or minus the average difference between Argus- LLS and Argus WTI-Cushing quotations for the applicable trading month.

4

* Confidential treatment has been requested with respect to portions of this agreement as indicated by “[***]” and such confidential portions have been deleted and filed separately with the Securities and Exchange Commission pursuant to Rule 24b-2 of the Exchange Act of 1934, as amended.

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b. "Transportation Deduction" means the sum of (i) the Committed Shipper B Base Rate Transportation Rate as defined in the KMCC Rate Tariff (the "KMCC Rate Tariff"), as may be adjusted downward as set forth below, [***] (ii) the pipeline loss allowance charged by KMCC, which rate is currently a deduction of 0.250% of the crude oil received with an API Gravity at or below 45.0 degrees and 0.375% of the crude oil received with an API Gravity above 45.0 degrees at the PVOG Delivery Point to cover for losses associated with the transportation of crude oil on KMCC, (iii) any other fees reflected in the KMCC Regulations Tariff that are charged to Republic for PVOG's crude oil movements (as such fees may be adjusted downward as set forth below), and (iv) a marketing fee of [***] per barrel purchased and sold hereunder. Republic shall pass through all adjustments to the KMCC Rate Tariff and to the KMCC Regulations Tariff. [***].

c. Rate Adjustments. The Committed Shipper B Base Rate Transportation Rate shall each first be adjusted effective July 1, 2017, and thereafter, effective on July 1^st of each subsequent year during the Term in an amount not greater than the adjustments that are made each year to the Federal Energy Regulatory Commission or any successor governmental agency thereto ("FERC") regulated interstate oil pipelines by the application of the annual Oil Pipeline Index published by FERC in advance of the annual July 1st adjustment of each year (the "FERC Index"); provided, however, that the FERC Index shall not be applied to any rates under this Agreement in any year in which the published FERC Index is less than zero.

4. Delivery Point / Title and Risk of Loss. Title and risk of loss shall pass from PVOG to Republic at the PVOG Delivery Point. PVOG shall deliver the crude oil delivered and sold to Republic hereunder at the outlet flange of the Midstream Pipeline immediately upstream of the inlet flange of KMCC's receipt point meter at the point of interconnection of the Midstream Pipeline with KMCC's Dewitt Station (the "PVOG Delivery Point"). The "Midstream Pipeline" means that certain 29 mile intrastate transportation pipeline system originating at the outlet flange of Republic Midstream, LLC's central delivery point in Lavaca County, Texas and extending to the interconnect of KMCC at Cuero in DeWitt County, Texas.

REPUBLIC SALE AND DELIVERY TO PVOG

5. Resale Quantity. During the Term, Republic commits to deliver and sell to PVOG, and PVOG commits to receive and purchase from Republic, a quantity of crude oil equal to the nominations reflected in the applicable Shipment Schedule.

6. Quality. The quality of the crude oil delivered by Republic to PVOG shall satisfy the Specifications.

7. Delivery Point / Title and Risk of Loss. Title and risk of loss shall pass from Republic to PVOG at the Republic Delivery Point. Republic shall deliver the crude oil delivered and sold to PVOG hereunder at the insulating flange of Republic's or Republic's agent's LACT

5

* Confidential treatment has been requested with respect to portions of this agreement as indicated by “[***]” and such confidential portions have been deleted and filed separately with the Securities and Exchange Commission pursuant to Rule 24b-2 of the Exchange Act of 1934, as amended.

US-DOCS\70393074.6

unit at the receiving facilities at PVOG's designated resale point, which may include the following (each, a "Republic Delivery Point"):

a. Phillips 66 Sweeny Refinery, Old Ocean, Texas;

b. Oiltanking LP, Houston Ship Channel;

c. Kinder Morgan Liquids Terminal, Pasadena, Texas;

d. Kinder Morgan Crude & Condensate Galena Park Splitter, Houston Ship Channel;

e. Such other delivery points on KMCC as KMCC may add at a later date; and

f. Any other delivery point agreed to by PVOG and Republic.

8. Price. For each barrel of crude oil sold and delivered by Republic to PVOG hereunder, PVOG agrees to pay Republic the Base Price.

ARTICLE III    
OUTRIGHT SALES OF CRUDE OIL BY PVOG TO REPUBLIC

If PVOG desires to make an outright sale of crude oil to Republic at any location, then such transaction shall be reflected in a Crude Oil Sale Agreement in substantially the form attached hereto as Exhibit A.

ARTICLE IV    
GENERAL PROVISIONS

1. Term. This Agreement shall be in effect for the period commencing on the Effective Date and ending on May 31, 2026 (the "Term").

2. Contaminated Oil. Should PVOG deliver crude oil to Republic that fails to meet the Specifications (other than if such failure is attributable to third party volumes commingled with PVOG's crude oil while in Republic or Republic Midstream, LLC's (or any applicable successor) control and possession), then PVOG shall pay or reimburse all costs and expense incurred by Republic for the removal, disposal or treatment of PVOG's Off-Spec Product and any damage to KMCC or associated tankage and facilities resulting from such Off-Spec Product, including, but not limited to, damage to crude oil in tankage due to commingling of PVOG's Off-Spec Product in Republic's tankage at the DeWitt Station. If PVOG desires to tender crude oil outside of the Specifications (excluding any crude oil tendered whereby the nonconformance is attributable to third party volumes commingled with PVOG's crude oil while in Republic or Republic Midstream, LLC's (or any applicable successor) control and possession), such product must first be approved by Republic at Republic's sole discretion. If any additional or special equipment is required to measure, store or transport this product, PVOG will be responsible for these additional costs and also the costs of necessary cleaning and restoration to return the equipment to its previous operating condition.

6

* Confidential treatment has been requested with respect to portions of this agreement as indicated by “[***]” and such confidential portions have been deleted and filed separately with the Securities and Exchange Commission pursuant to Rule 24b-2 of the Exchange Act of 1934, as amended.

US-DOCS\70393074.6

3. Manner of Payment. In the event of any transactions pursuant to Article II of this Agreement, on or before the 20^th day of each month, Republic shall render to Shipper a statement showing, for the immediately preceding month, the amounts owed by each Party pursuant to such transactions and showing the net amount that PVOG owes Republic. PVOG shall pay the net amount shown on such statement within ten (10) days following the date of Republic's statement. Either Party or its agent shall have the right, upon ten (10) days prior written notice and at reasonable times during business hours, but in no event more frequently than once per calendar year, and at its sole risk, cost and expense, to examine the books and records of the other Party to the extent necessary to audit and verify the accuracy of any statement made pursuant to this Agreement. In the event an error is discovered in any such statement, and such error is not disputed in writing by the other Party, such error shall be adjusted without interest or penalty as soon as reasonably possible, but in any event, within two (2) months from the date that such error is determined and agreed upon by the Parties; provided however, that any such statement is hereby deemed final as to both Parties unless disputed in writing within two (2) years from the date of such statement.

4. Warranty of Title and Authority to Sell. PVOG hereby warrants that (i) the title to the portion of the crude oil sold and delivered hereunder that is owned by PVOG is free and clear of all liens and encumbrances and (ii) as to the remaining portion of the crude oil sold and delivered hereunder, PVOG has the right and authority to sell and deliver such crude oil for the benefit of the true owners thereof. PVOG further warrants that the crude oil has been produced, handled and transported to the delivery point hereunder in accordance with the laws, rules and regulations of all governmental authorities having jurisdiction thereof. PVOG shall indemnify and hold Republic harmless from and against any and all cost, damage and expense suffered and incurred by reason of any failure of the title so warranted or any inaccuracy in the representation of PVOG's right and authority to sell such crude oil made herein.

5. Taxes. Except in the event of an outright sale to Republic in accordance with Article III of this Agreement, PVOG shall be responsible for the payment of severance taxes and PVOG hereby directs Republic to not withhold any amounts from the proceeds allocable to the sale and delivery of crude oil for the payment of such taxes. PVOG also agrees to indemnify Republic for any liability Republic incurs with respect to the payment of severance taxes.

6. Force Majeure.

a. Excused Performance. Neither Party shall be liable in damages or in any other remedy, legal or equitable, to the other Party for nonperformance or delay in performing its obligations under this Agreement to the extent such non-performance or delay is due or results from a Force Majeure Event or Enumerated Circumstance, and neither Party shall be required to perform hereunder (other than an obligation to make payments due and owing under this Agreement unless such payment is not permitted by applicable laws and regulations) to the extent and for the duration of any Force Majeure Event or Enumerated Circumstance.

7

* Confidential treatment has been requested with respect to portions of this agreement as indicated by “[***]” and such confidential portions have been deleted and filed separately with the Securities and Exchange Commission pursuant to Rule 24b-2 of the Exchange Act of 1934, as amended.

US-DOCS\70393074.6

b. Definitions: "Force Majeure Event" means any act, event, condition or occurrence that (i) prevents the affected Party from performing its obligations under this Agreement; (ii) is unforeseeable and beyond the reasonable control of and not the fault of the affected Party; and (iii) such affected Party has been unable to overcome by the exercise of due diligence. "Enumerated Circumstance" means any the following acts, events, conditions and occurrences: (A) act of God, fire, lightning, landslide, earthquake, storm, hurricane, flood, washout or explosion; (B) act of war, act of terrorism, blockade, insurrection, riot, order or act of civil or military authority; and (C) act, law, rule, regulation, order or requisition of any governmental authority.

c. Exclusions from Force Majeure and Enumerated Circumstance. Notwithstanding anything to the contrary set forth in this Agreement, none of the following shall, under any circumstances, constitute a Force Majeure Event or Enumerated Circumstance (as the case may be): (i) the lack of financial resources, or the inability of a Party to secure funds or make payments as required by this or any other Agreement; (ii) adverse market, financial or other economic conditions, including changes in market conditions, including changes that either directly or indirectly affect the demand for or price of petroleum products, natural gas products or crude oil; (iii) availability of more attractive markets for crude oil; (iv) PVOG's inability to receive, transport or deliver crude oil to, on or from KMCC under the terms of this Agreement in a manner that PVOG deems economic; (v) Republic's inability to receive, transport or deliver crude oil to, on or from KMCC under the terms of this Agreement in a manner that Republic deems economic; (vi) PVOG's inability to receive, transport or deliver crude oil to, on or from KMCC under the terms of this Agreement due to any cause or event whatsoever arising from or related to any condition upstream of the DeWitt Station; or (vii) inefficiencies in operations.

d. Notice of Force Majeure or Enumerated Circumstance Event. The Party affected by the Force Majeure Event or Enumerated Circumstance (as the case may be) shall: (i) promptly, but in all cases within five (5) days of the date the affected Party had knowledge of the Force Majeure Event or Enumerated Circumstance (as the case may be), notify the other Party in writing giving reasonably full particulars of the cause and expected duration of the Force Majeure Event or Enumerated Circumstance (as the case may be); (ii) keep the other Party informed of all significant developments; (iii) describe in its initial notice the efforts undertaken, or to be undertaken, by the affected Party to avoid, overcome the impacts of, or remove the Force Majeure Event or Enumerated Circumstance (as the case may be) and to minimize the potential adverse effects of non-performance due to the Force Majeure Event or Enumerated Circumstance (as the case may be); and (iv) not be relieved of liability for a Force Majeure Event or Enumerated Circumstance (as the case may be) in the event such Party fails to comply with the requirements of this Section 6.d.

e. Affected Party's Duty to Mitigate. A Party that suspends performance for a claimed Force Majeure Event or Enumerated Circumstance (as the case may be) shall take all steps that are commercially reasonable to mitigate the damages to either Party arising therefrom.

8

* Confidential treatment has been requested with respect to portions of this agreement as indicated by “[***]” and such confidential portions have been deleted and filed separately with the Securities and Exchange Commission pursuant to Rule 24b-2 of the Exchange Act of 1934, as amended.

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f. Extension of Term. For each period that performance was suspended in excess of fourteen (14) days for a claimed Force Majeure Event or Enumerated Circumstance ("Suspension Period"), the Term of this Agreement shall be extended by the cumulative number of days from all Suspension Periods over the Term ("FM Extension Period"), so that the Parties may complete the performance that would otherwise have occurred but for the suspension. If the last day of the FM Extension Period ends on a day that is not the last day of a calendar month, then PVOG may elect at its option to continue selling volumes protected from proration up to its Commitment for the remaining days in the then current calendar month, subject to Republic's nomination and scheduling policies, for the sole purpose of providing PVOG with the ability to conform to standard monthly crude oil marketing contracts.

g. Suspension of Obligations. If any Force Majeure Event or Enumerated Circumstance (as the case may be) claimed by Republic causes the suspension of the services provided hereunder to PVOG, PVOG's obligation to pay the Transportation Deduction and the Deficiency Fee shall be suspended for each day that such Force Majeure Event or Enumerated Circumstance (as the case may be) continues.

7. Prevailing Document. In the event of any conflict between the provisions of this Agreement and the provisions of any applicable division order executed in accordance with the terms hereof, the provisions of this Agreement shall control.

8. Assignment. No assignment of this Agreement shall be made by either Party except to a person or entity that is acquiring all or substantially all of the assets of such Party contemporaneous with such assignment.

9. Notice. Except as expressly provided herein, any notice shall be sent by certified mail, FedEx, fax or email. Such communication shall be deemed to have been given and received upon receipt of the recipient's answerback and shall be effective at such time.

Republic

Republic Midstream Marketing, LLC

c/o ArcLight Capital Partners, LLC

200 Clarendon Street, 55th Floor

Boston, MA 02117

Attn: Christine Miller

Email: cmiller@arclightcapital.com

Facsimile: (617) 867-4698

With a copy to:

Republic Midstream, LLC

10300 Town Park Dr., Suite SE1000

Houston, TX 77072

Attn: David Lipp

Email: dlipp@republicmidstream.com

Facsimile: (281) 849-9009

and:

9

* Confidential treatment has been requested with respect to portions of this agreement as indicated by “[***]” and such confidential portions have been deleted and filed separately with the Securities and Exchange Commission pursuant to Rule 24b-2 of the Exchange Act of 1934, as amended.

US-DOCS\70393074.6

American Midstream Partners, L.P.

1400 16^th Street, Suite 310

Denver, CO 80202

Attn: William B. Mathews

Email: bmathews@americanmidstream.com

Facsimile: (720) 457-6040

PVOG

Penn Virginia Oil & Gas, L.P.

840 Gessner Road, Suite 800

Houston, TX 77024

Attention: Jill T. Zivley

Email: jill.zivley@pennvirginia.com

Facsimile: (713) 722-6601

PVOG Guarantor

Penn Virginia Corporation

Four Radnor Corporate Center, Suite 200

100 Matsonford Road

Radnor, PA 19087-4564

Attention: General Counsel

Email: nancy.snyder@pennvirginia.com

Facsimile: (610) 687-3688

With a copy:

Penn Virginia Corporation

Four Radnor Corporate Center, Suite 200

100 Matsonford Road

Radnor, PA 19087-4564

Attention: General Counsel

Email: nancy.snyder@pennvirginia.com

Facsimile: (610) 687-3688

Notices of change of address of either Party shall be given in writing to the other in the manner aforesaid and shall be observed in the giving of all future notices, statements or other communications required or permitted to be given hereunder.

10. Limitation of Damages. Neither PVOG nor Republic shall be liable for specific performance, lost profits or other business interruption damages, or for special, consequential, incidental, punitive, exemplary or indirect damages, in tort, contract or otherwise, of any kind, arising out of or in any way connected to the performance, the suspension of performance, the failure to perform or the termination of this Agreement.

11. Compliance with Laws. Each Party shall, in the performance of this Agreement, comply with all applicable laws and regulations in effect on the date this Agreement is entered into, and as they may be amended from time to time.

12. Governing Law. This Agreement shall be governed by, construed and enforced under the laws of the State of Texas without giving effect to its conflicts of laws principles.

10

* Confidential treatment has been requested with respect to portions of this agreement as indicated by “[***]” and such confidential portions have been deleted and filed separately with the Securities and Exchange Commission pursuant to Rule 24b-2 of the Exchange Act of 1934, as amended.

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13. Entire Agreement. This Agreement (including the General Provisions referenced below) contains the entire agreement of both parties and supersedes all correspondence, representations, prior agreements, oral or written, in connection with the subject matter of this Agreement. The Parties confirm that they have not entered into this Agreement in reliance upon any representations that may have been given by the other party. No amendment, modification or waiver of any provision of this Agreement or of any right, power or remedy shall be effective unless made expressly and in writing. No waiver of any breach of any provision of this Agreement shall be considered to be a waiver of any subsequent or continuing breach of that provision or release, discharge or prejudice the right of the waiving party to require strict performance by the other party of any other provisions of this Agreement.

14. General Provisions: Except as described above, ConocoPhillips (formerly CONOCO) General Provisions dated January 1, 1993, amended August 1, 2009, shall govern this transaction and are hereby incorporated by reference. The term "buyer," as used in the Agreement shall mean (i) PVOG as to the crude oil purchased hereunder by PVOG and (ii) Republic as to the crude oil purchased hereunder by Republic. To the extent of any conflict between the provisions herein and any provisions incorporated herein (by Exhibit or otherwise), the provisions of this Agreement shall govern.

ARTICLE V
GUARANTEE

1. Guarantee.

a. In consideration of Republic entering into this Agreement, PVOG Guarantor unconditionally and irrevocably guarantees to Republic the due and punctual performance of each of PVOG's obligations to Republic pursuant to this Agreement (such obligations, the "Guaranteed Obligations"), as and when provided in this Agreement. PVOG Guarantor shall be liable for the payment of the Guaranteed Obligations (if not timely paid by PVOG), as set forth in this Article V, as a primary obligor, and not as a mere surety. The guaranty in this Article V is a continuing guaranty of payment and performance and not a guaranty of collection. If PVOG fails to pay the Guaranteed Obligations when due, or any part thereof, PVOG Guarantor shall, on written demand and without further notice of nonpayment, or any other notice whatsoever, pay the amount due and payable thereon to Republic as required per the terms of this Agreement, and it shall not be necessary for Republic, in order to enforce such payment or performance by PVOG Guarantor, first to institute suit or pursue or exhaust any rights or remedies against PVOG or others liable for such payment or performance. PVOG Guarantor's liability hereunder shall be limited to the payment or performance obligations expressly required of PVOG under this Agreement.

b. PVOG Guarantor hereby agrees that Republic's rights or remedies and all of PVOG Guarantor's obligations under the terms of the guaranty in this Article V shall remain in full force and effect and shall not be released or affected by, or deemed to be satisfied by, and PVOG Guarantor shall not be released (by virtue of any applicable

11

* Confidential treatment has been requested with respect to portions of this agreement as indicated by “[***]” and such confidential portions have been deleted and filed separately with the Securities and Exchange Commission pursuant to Rule 24b-2 of the Exchange Act of 1934, as amended.

US-DOCS\70393074.6

law, arrangement or relationship) by, any act or omission to act or delay of any kind by Republic, any other guarantor of the Guaranteed Obligations or any other person or entity or any other circumstance whatsoever which might, but for the provisions of this paragraph, constitute a legal or equitable discharge of PVOG Guarantor's obligations hereunder, and the liability of PVOG Guarantor under the guaranty under this Article V shall be absolute and unconditional irrespective thereof.

c. In the event any payment by PVOG or any other person or entity (other than PVOG Guarantor) to Republic in respect of the Guaranteed Obligations is held to constitute a preference, fraudulent transfer or other voidable payment under any bankruptcy, insolvency or similar applicable law, or if for any other reason, Republic is required to refund such payment or pay the amount thereof to any other creditor, such payment by PVOG or such other person or entity to Republic shall not constitute a release of PVOG Guarantor from any liability hereunder, and the guaranty under this Article V shall continue to be effective or shall be reinstated (notwithstanding any prior release, surrender or discharge by Republic of this Guaranty or of PVOG Guarantor), as the case may be, with respect to, and the guaranty under this Article V shall apply to, any and all amounts so refunded by Republic or paid by Republic to another person or entity (which amounts shall constitute part of the Guaranteed Obligations). Notwithstanding the foregoing, the obligations of PVOG Guarantor hereunder at any time shall be limited to the maximum amount as will result in the obligations of PVOG Guarantor hereunder not constituting a fraudulent transfer or conveyance to the extent applicable to this Agreement and the obligations of PVOG Guarantor hereunder.

d. PVOG Guarantor irrevocably waives acceptance hereof, presentment, demand, protest and, to the fullest extent permitted by applicable law, any notice not provided for herein, as well as any requirement that at any time any action be taken by any person or entity against PVOG, any other guarantor of all or any part of the Guaranteed Obligations or any other person or entity. Notwithstanding the foregoing or anything else to the contrary contained herein, PVOG Guarantor reserves to itself all rights, counterclaims and other defenses to its obligations hereunder which PVOG is or may be entitled to arising from or out of this Agreement, except to the extent such defenses are expressly waived in the preceding sentence.

[Signature page follows]

This document evidences our understanding of the entire agreement and shall constitute the formal contract.

REPUBLIC MIDSTREAM MARKETING, LLC

By: /s/ Daniel R. Revers    

Name:    Daniel R. Revers

Title:    President

PENN VIRGINIA OIL & GAS, L.P.

By:    Penn Virginia Oil & Gas GP LLC,

its general partner

By: /s/ R. Seth Bullock    

Name:    R. Seth Bullock

Title:    CRO

PENN VIRGINIA CORPORATION

By: /s/ R. Seth Bullock    

Name:    R. Seth Bullock

Title:    CRO

Exhibit A

Form of Crude Oil Sale Agreement
(Used for Outright Sales of Crude Oil by PVOG to Republic)

See attached

CRUDE OIL SALE AGREEMENT

Republic Contract Number: [___]

PVOG Contract Number: [___]

This Crude Oil Sale Agreement ("Agreement") is made effective as of [?], 20[?] by and between Penn Virginia Oil & Gas, L.P. ("Seller") and Republic Midstream Marketing, LLC ("Buyer").

WHEREAS, Seller agrees to sell and deliver and Buyer agrees to purchase and receive crude oil under the terms and conditions set forth herein:

1. Quantity. [___]

2. Quality Requirements. [__]

3. Price. [__]

4. Delivery Point / Title and Risk of Loss. Delivered at [__]. Title to and risk of loss, contamination or damage to the crude oil shall pass from Seller to Buyer [__].

5. Term. This Agreement shall be in effect for an initial period commencing [?], 20[?] and shall remain in effect until cancelled by either party on 30 days advanced written notice (the "Term").

6. Quality and Tests. All measurements hereunder shall be made from static tank gauges on 100 percent tank table basis or by positive displacement meters. All measurements and tests shall be made in accordance with the latest ASTM or ASME-API (Petroleum PD Meter Code) published methods then in effect, whichever apply. Volume and gravity shall be adjusted to 60 degrees Fahrenheit by the use of Table 6A and 5A of the Petroleum Measurement Tables ASTM Designation D1250 in their latest revision. The crude oil delivered hereunder shall be marketable and acceptable in the applicable common or segregated stream of the carriers involved but not to exceed 1% S&W. Full deduction for all free water and S&W content shall be made according to the API / ASTM Standard Method then in effect. Either party shall have the right to have a representative witness all gauges, tests, and measurements.

7. Manner of Payment. Buyer shall make payment for crude oil sold and delivered by wire on the twentieth (20^th) day of the month following the month of delivery, without any withholding, offset, counterclaim or deduction of any kind, into Seller's nominated bank account with full value, against presentation by Seller of Seller's commercial invoice with truck meter tickets evidencing net quality and quantity. If payment falls due on a Sunday or a Monday non-Business Day, then payment shall be made on the first following Business Day. If payment falls on a Saturday or non-Monday holiday, then payment shall be made on the preceding Business Day. "Business Day" means a weekday on which banks are open for general commercial business in New York.

8. Warranty of Title and Authority to Sell. Seller hereby warrants that (i) the title to the portion of the crude oil sold and delivered hereunder that is owned by Seller is free and clear of all liens and encumbrances and (ii) as to the remaining portion of the crude oil sold and delivered hereunder, Seller has the right and authority to sell and deliver such crude oil for the benefit of the true owners thereof. Seller further warrants that the crude oil has been produced, handled and transported to the delivery point hereunder in accordance with the laws, rules and regulations of all governmental authorities having jurisdiction thereof. Seller shall indemnify and hold Buyer harmless from and against any and all cost, damage and expense suffered and incurred by reason of any failure of the title so warranted or any inaccuracy in the representation of Seller's right and authority to sell such crude oil made herein.

9. Taxes. Buyer is hereby directed to withhold from the proceeds allocable to the sale and delivery of crude oil hereunder the amount of severance taxes.

10. Prevailing Document. In the event of any conflict between the provisions of this agreement and the provisions of any applicable division order executed in accordance with the terms hereof, the provisions of this agreement shall control.

11. Notice. Except as expressly provided herein, any notice shall be sent by certified mail, FedEx, fax or email. Such communication shall be deemed to have been given and received upon receipt of the recipient's answerback and shall be effective at such time.

Buyer

Republic Midstream Marketing, LLC

[__]

[__]

Attention: [__]

Fax: [__]

Email: [__]

Seller

Penn Virginia Oil & Gas, L.P.

[__]

Attention: [__]

Fax: [__]

Email: [__]

12. Limitation of Damages. Neither Seller nor Buyer shall be liable for specific performance, lost profits or other business interruption damages, or for special, consequential, incidental, punitive, exemplary or indirect damages, in tort, contract or otherwise, of any kind, arising out of or in any way connected to the performance, the suspension of performance, the failure to perform or the termination of this Agreement.

13. Compliance with Laws. Each Party shall, in the performance of this Agreement, comply with all applicable laws and regulations in effect on the date this Agreement is entered into, and as they may be amended from time to time.

14. Governing Law. This Agreement shall be governed by, construed and enforced under the laws of the State of Texas without giving effect to its conflicts of laws principles.

15. Entire Agreement. This Agreement contains the entire agreement of both parties and supersedes all correspondence, representations, prior agreements, oral or written, in connection with the subject matter of this Agreement. The parties confirm that they have not entered into this Agreement in reliance upon any representations that may have been given by the other party. No amendment, modification or waiver of any provision of this Agreement or of any right, power or remedy shall be effective unless made expressly and in writing. No waiver of any breach of any provision of this Agreement shall be considered to be a waiver of any subsequent or continuing breach of that provision or release, discharge or prejudice the right of the waiving party to require strict performance by the other party of any other provisions of this Agreement.

16. General Provisions: Except as described above, ConocoPhillips (formerly CONOCO) General Provisions dated January 1, 1993, amended August 1, 2009, shall govern this transaction and are hereby incorporated by reference.

[Signature page follows]

This document evidences our understanding of the entire agreement and shall constitute the formal contract.

BUYER

REPUBLIC MIDSTREAM MARKETING, LLC

By:

Name:    

Title:    

SELLER

PENN VIRGINIA OIL & GAS, L.P.

By:    Penn Virginia Oil & Gas GP LLC,

its general partner

By:

Name:    

Title:    

12

* Confidential treatment has been requested with respect to portions of this agreement as indicated by “[***]” and such confidential portions have been deleted and filed separately with the Securities and Exchange Commission pursuant to Rule 24b-2 of the Exchange Act of 1934, as amended.

US-DOCS\70393074.6

EX-31.1

Exhibit 31.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, John A. Brooks, Interim Principal Executive Officer of Penn Virginia Corporation (the “Registrant”), certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of the Registrant (this “Report”);

2. Based on my knowledge, this Report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this Report;

3. Based on my knowledge, the financial statements, and other financial information included in this Report, fairly present in all material respects the financial condition, results of operations and cash flows of the Registrant as of, and for, the periods presented in this Report;

4. The Registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the Registrant and we have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the Registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this Report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the Registrant’s disclosure controls and procedures and presented in this Report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this Report based on such evaluation; and

(d) Disclosed in this Report any change in the Registrant’s internal control over financial reporting that occurred during the Registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Registrant’s internal control over financial reporting; and

5. The Registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the Registrant’s auditors and the audit committee of the Registrant’s board of directors:

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the Registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the Registrant’s internal control over financial reporting.

Date: November 14, 2016

/s/ JOHN A. BROOKS

John A. Brooks

Interim Principal Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Steven A. Hartman, Senior Vice President, Chief Financial Officer and Treasurer of Penn Virginia Corporation (the “Registrant”), certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of the Registrant (this “Report”);

2. Based on my knowledge, this Report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this Report;

3. Based on my knowledge, the financial statements, and other financial information included in this Report, fairly present in all material respects the financial condition, results of operations and cash flows of the Registrant as of, and for, the periods presented in this Report;

4. The Registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the Registrant and we have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the Registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this Report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the Registrant’s disclosure controls and procedures and presented in this Report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this Report based on such evaluation; and

(d) Disclosed in this Report any change in the Registrant’s internal control over financial reporting that occurred during the Registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Registrant’s internal control over financial reporting; and

5. The Registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the Registrant’s auditors and the audit committee of the Registrant’s board of directors:

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the Registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the Registrant’s internal control over financial reporting.

Date: November 14, 2016

/s/ STEVEN A. HARTMAN

Steven A. Hartman

Senior Vice President, Chief Financial Officer and Treasurer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Penn Virginia Corporation (the “Company”) on Form 10-Q for the nine months ended September 30, 2016, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, John A. Brooks, Interim Principal Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: November 14, 2016

/s/ JOHN A. BROOKS

John A. Brooks

Interim Principal Executive Officer

This written statement is being furnished to the Securities and Exchange Commission as an exhibit to the Report. A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Penn Virginia Corporation (the “Company”) on Form 10-Q for the nine months ended September 30, 2016, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Steven A. Hartman, Senior Vice President, Chief Financial Officer and Treasurer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: November 14, 2016

/s/ STEVEN A. HARTMAN

Steven A. Hartman

Senior Vice President, Chief Financial Officer and Treasurer

This written statement is being furnished to the Securities and Exchange Commission as an exhibit to the Report. A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

XML

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2016	Nov. 14, 2016
Document Documentand Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2016
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	Q3
Trading Symbol
Entity Registrant Name	PENN VIRGINIA CORP
Entity Central Index Key	0000077159
Current Fiscal Year End Date	--12-31
Entity Filer Category	Smaller Reporting Accelerated Filer
Entity Common Stock, Shares Outstanding		14,992,018

XML

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands	1 Months Ended	2 Months Ended	3 Months Ended	8 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 12, 2016	Sep. 30, 2015	Sep. 12, 2016		Sep. 30, 2015
Revenues
Crude oil	$ 5,508,000	$ 23,392,000	$ 51,124,000	$ 81,377,000		$ 180,964,000
Natural gas liquids	333,000	1,680,000	3,254,000	6,064,000		13,841,000
Natural gas	475,000	1,889,000	6,312,000	6,208,000		22,143,000
Gain (loss) on sales of property and equipment, net	0	504,000	50,828,000	1,261,000		50,803,000
Other, net	33,000	(804,000)	466,000	(600,000)		2,376,000
Total revenues	6,349,000	26,661,000	111,984,000	94,310,000		270,127,000
Operating expenses
Lease operating	756,000	4,209,000	11,304,000	15,626,000		33,780,000
Gathering, processing and transportation	576,000	4,767,000	5,654,000	13,235,000		19,535,000
Production and ad valorem taxes	375,000	574,000	3,483,000	3,490,000		13,139,000
General and administrative	1,476,000	12,181,000	9,416,000	38,945,000		32,865,000
Exploration	0	4,641,000	1,673,000	10,288,000		11,922,000
Depreciation, depletion and amortization	2,029,000	8,024,000	76,850,000	33,582,000		253,056,000
Asset Impairment Charges	0			0		1,084,000
Total operating expenses	5,212,000	34,396,000	108,380,000	115,166,000		365,381,000
Operating income (loss)	1,137,000	(7,735,000)	3,604,000	(20,856,000)		(95,254,000)
Other income (expense)
Interest expense	(218,000.00)	(1,363,000)	(22,985,000)	(58,018,000)		(68,021,000)
Reorganization Items	0	1,152,373,000	0	1,144,993,000		0
Derivatives	(4,369,000)	8,934,000	44,701,000	(8,333,000)		52,073,000
Other	9,000	(2,154,000)	(44,000)	(3,184,000)		(586,000)
Reorganization items, net	(3,441,000)	1,150,055,000	25,276,000	1,054,602,000		(111,788,000)
Income tax benefit	0		624,000	0		394,000
Net income (loss)	(3,441,000)	1,150,055,000	25,900,000	1,054,602,000		(111,394,000)
Preferred stock dividends	0	0	(5,935,000)	(5,972,000)	[1]	(18,069,000)	[1]
Net income (loss) attributable to common shareholders	$ (3,441,000)	$ 1,150,055,000	$ 19,965,000	$ 1,048,630,000		$ (129,463,000)
Net income (loss) per share:
Basic (in dollars per share)	$ (0.23)	$ 12.88	$ 0.27	$ 11.91		$ (1.79)
Diluted (in dollars per share)	$ (0.23)	$ 10.32	$ 0.25	$ 8.50		$ (1.79)
Weighted average shares outstanding – basic	14,992	89,292	72,651	88,013		72,438
Weighted average shares outstanding – diluted	14,992	111,458	103,452	124,087		72,438

[1] Preferred stock dividends were excluded from the computation of diluted earnings (loss) per share for the period January 1, 2016 through September 12, 2016 and the nine months ended September 30, 2015, as the assumed conversion of the outstanding preferred stock would have been anti-dilutive.

XML

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($)	1 Months Ended	2 Months Ended	3 Months Ended	8 Months Ended	9 Months Ended
	Sep. 30, 2016	Sep. 12, 2016	Sep. 30, 2015	Sep. 12, 2016	Sep. 30, 2015
Net income (loss)	$ (3,441,000)	$ 1,150,055,000	$ 25,900,000	$ 1,054,602,000	$ (111,394,000)
Other comprehensive loss:
Change in pension and postretirement obligations, net of tax of $(6) in 2015	0	(383,000)	(11,000)	(421,000)	(32,000)
Total Other Comprehensive Income (Loss), Net of Tax	0	(383,000)	(11,000)	(421,000)	(32,000)
Comprehensive income (loss)	$ (3,441,000)	$ 1,149,672,000	$ 25,889,000	$ 1,054,181,000	$ (111,426,000)

XML

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Thousands	1 Months Ended	2 Months Ended	3 Months Ended	8 Months Ended	9 Months Ended
	Sep. 30, 2016	Sep. 12, 2016	Sep. 30, 2015	Sep. 12, 2016	Sep. 30, 2015
Change in pension and postretirement obligations, net of tax	$ 0	$ 0	$ (6)	$ 0	$ (17)

XML

CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands		1 Months Ended	8 Months Ended
		Sep. 30, 2016	Sep. 12, 2016	Dec. 31, 2015
Common Stock Issued in Exchange for Liabilities		$ 0	$ 140,952
Current assets
Cash and cash equivalents		13,994	31,414	$ 11,955
Accounts receivable, net of allowance for doubtful accounts		32,137		47,965
Derivative assets		446		97,956
Other current assets		3,518		7,104
Total current assets		50,095		164,980
Property and equipment, net		251,200		344,395
Other assets		5,571		8,350
Total assets		306,866		517,725
Current liabilities
Accounts payable and accrued liabilities		45,432		103,525
Derivative Liability, Current		3,888
Long-term Debt, Current Maturities		0		1,224,383
Total current liabilities		49,320		1,327,908
Derivative Liability, Noncurrent		11,291		0
Long-term Debt, Excluding Current Maturities		54,350		0
Other liabilities		4,451		104,938
Commitments and contingencies (Note 13)
Shareholders’ equity (deficit):
Predecessor preferred stock of $100 par value – 100,000 shares authorized; Series A – 3,915 shares issued as of December 31, 2015 and Series B – 27,551 issued as of December 31, 2015, each with a redemption value of $10,000 per share		0
Postconfirmation, Stockholders' Equity			190,895
Predecessor common stock of $0.01 par value – 228,000,000 shares authorized; 81,252,676 shares issued as of December 31, 2015		150	0
Retained Earnings (Accumulated Deficit)		(3,441)
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest		187,454		(915,121)
Other Deferred Compensation		0
Accumulated Other Comprehensive Income (Loss), Net of Tax		0
Treasury Stock, Value		0
Total shareholders’ equity (deficit)		187,454		(915,121)
Total liabilities and shareholders’ equity (deficit)		306,866		517,725
Predecessor [Member]
Shareholders’ equity (deficit):
Predecessor paid-in capital		0
Preferred stock
Shareholders’ equity (deficit):
Postconfirmation, Stockholders' Equity			0
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest		0		3,146
Common stock
Shareholders’ equity (deficit):
Postconfirmation, Stockholders' Equity			150
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest		150		628
Retained Earnings [Member]
Shareholders’ equity (deficit):
Postconfirmation, Stockholders' Equity			0
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest		(3,441)	0	(2,130,271)
Treasury Stock [Member]
Shareholders’ equity (deficit):
Postconfirmation, Stockholders' Equity			0
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest		0		3,574
Additional Paid-in Capital [Member]
Shareholders’ equity (deficit):
Postconfirmation, Stockholders' Equity			190,745
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest		190,745		1,211,088
Deferred Compensation, Share-based Payments [Member]
Shareholders’ equity (deficit):
Postconfirmation, Stockholders' Equity			0
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest		0		3,440
AOCI Attributable to Parent [Member]
Shareholders’ equity (deficit):
Postconfirmation, Stockholders' Equity	[1]		$ 0
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest		$ 0		$ 422

[1] Accumulated other comprehensive income (“AOCI”) is entirely attributable to our defined benefit pension and postretirement health care plans. The changes in the balance of AOCI for the period January 1, 2016 through September 12, 2016, represent reclassifications from AOCI to net periodic benefit expense, a component of “General and administrative expenses,” of $(38).

XML

CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Sep. 30, 2016	Dec. 31, 2015
Schedule of Stockholders' Equity [Line Items]
Preferred stock, par value	$ 0.01	$ 100
Preferred stock, shares authorized	5,000,000	100,000
Preferred stock, redemption value per share (in dollars per share)	$ 0	$ 10,000
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	45,000,000	228,000,000
Common stock, shares issued	14,992,018	81,252,676
Treasury stock, shares	0	455,689
Series A Preferred Stock
Schedule of Stockholders' Equity [Line Items]
Preferred stock, issued	0	3,915
Series B Preferred Stock
Schedule of Stockholders' Equity [Line Items]
Preferred stock, issued	0	27,551

XML

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)	1 Months Ended	8 Months Ended	9 Months Ended
	Sep. 30, 2016	Sep. 12, 2016	Sep. 30, 2015
Cash flows from operating activities
Net income (loss)	$ (3,441,000)	$ 1,054,602,000	$ (111,394,000)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Non-Cash Reorganization Items	0	(1,178,302,000)	0
Depreciation, depletion and amortization	2,029,000	33,582,000	253,056,000
Asset Impairment Charges	0	0	1,084,000
Accretion of firm transportation obligation	0	317,000	705,000
Derivative contracts:
Net losses (gains)	4,369,000	8,333,000	(52,073,000)
Cash settlements, net	0	48,008,000	104,590,000
Deferred income tax expense	0	0	266,000
Gain on sales of assets, net	0	(1,261,000)	(50,803,000)
Non-cash exploration expense	0	6,038,000	4,903,000
Non-cash interest expense	38,000	22,189,000	3,504,000
Share-based compensation (equity-classified)	0	1,511,000	3,369,000
Other, net	0	(13,000)	(17,000)
Changes in operating assets and liabilities, net	585,000	35,243,000	5,051,000
Net cash provided by operating activities	3,580,000	30,247,000	162,241,000
Cash flows from investing activities
Capital expenditures	0	(15,359,000)	(324,876,000)
Proceeds from sales of assets, net	0	224,000	73,670,000
Other Investing Activities, Net	0	1,186,000	0
Net cash used in investing activities	0	(13,949,000)	(251,206,000)
Cash flows from financing activities
Proceeds from revolving credit facility borrowings	0	75,350,000	203,000,000
Repayment of revolving credit facility borrowings	(21,000,000)	(119,121,000)	(98,000,000)
Payments of Debt Issuance Costs	0	(3,011,000)	(744,000)
Rights Offering, Rights Offering Amount		49,943,000
Dividends paid on preferred stock	0	0	(18,201,000)
Net cash (used in) provided by financing activities	(21,000,000)	3,161,000	86,055,000
Net (decrease) increase in cash and cash equivalents	(17,420,000)	19,459,000	(2,910,000)
Cash and cash equivalents – beginning of period	31,414,000	11,955,000	6,252,000
Cash paid for:
Interest	0	4,331,000	47,489,000
Income taxes paid (refunds received)	0	(35,000)	7,000
Payments for Restructuring	0	30,990,000	0
Common Stock Issued in Exchange for Liabilities	0	140,952,000	0
Non-cash Investing activities:
Changes in accrued liabilities related to capital expenditures	0	(11,301,000)	(41,800,000)
Derivatives Settled to Pay Down Revolver	$ 0	$ 51,979,000	$ 0

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Nature of Operations

9 Months Ended

Sep. 30, 2016

Accounting Policies [Abstract]

Nature of Operations

Nature of Operations

Penn Virginia Corporation (together with its consolidated subsidiaries, unless the context otherwise requires, “Penn Virginia,” the “Company,” “we,” “us” or “our”) is an independent oil and gas company engaged in the onshore exploration, development and production of oil, natural gas liquids (“NGLs”) and natural gas. Our current operations consist primarily of drilling unconventional horizontal development wells and operating our producing wells in the Eagle Ford Shale (the “Eagle Ford”) in South Texas. Our operations are substantially concentrated with over 90 percent of our production, revenues and capital expenditures being attributable to this region. We also have less significant operations in Oklahoma, primarily non-operated properties in the Granite Wash. In August 2016, we terminated our remaining operations in the Marcellus Shale in Pennsylvania and are currently in the process of remediating the sites of our former wells in that region.

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Basis of Presentation

9 Months Ended

Sep. 30, 2016

Accounting Policies [Abstract]

Basis of Presentation

Basis of Presentation

Our unaudited Condensed Consolidated Financial Statements include the accounts of Penn Virginia and all of our subsidiaries. Intercompany balances and transactions have been eliminated. Our Condensed Consolidated Financial Statements have been prepared in conformity with accounting principles generally accepted in the United States of America (“U.S. GAAP”). Preparation of these statements involves the use of estimates and judgments where appropriate. In the opinion of management, all adjustments, consisting of normal recurring accruals, considered necessary for a fair presentation of our Condensed Consolidated Financial Statements have been included. Our Condensed Consolidated Financial Statements should be read in conjunction with the Consolidated Financial Statements and Notes included in our Annual Report on Form 10-K for the year ended December 31, 2015. Operating results for the nine months ended September 30, 2016, are not necessarily indicative of the results that may be expected for the year ending December 31, 2016. Certain amounts for the corresponding 2015 periods have been reclassified to conform to the current year presentation. These reclassifications have no impact on our previously reported results of operations, balance sheets or cash flows.

Management has evaluated all of our activities through the issuance date of our Condensed Consolidated Financial Statements and has concluded that no subsequent events have occurred that would require recognition in our Condensed Consolidated Financial Statements or disclosure in the Notes thereto.

Comparability of Financial Statements to Prior Periods

As discussed in further detail in Note 4 below, we have adopted and applied the relevant guidance provided in U.S. GAAP with respect to the accounting and financial statement disclosures for entities that have emerged from bankruptcy proceedings (“Fresh Start Accounting”). Accordingly, our Condensed Consolidated Financial Statements and Notes after September 12, 2016, are not comparable to the Condensed Consolidated Financial Statements and Notes prior to that date. To facilitate our financial statement presentations, we refer to the reorganized company in these Condensed Consolidated Financial Statements and Notes as the “Successor” for periods subsequent to September 12, 2016, and “Predecessor” for periods prior to September 13, 2016. Furthermore, our Condensed Consolidated Financial Statements and Notes have been presented with a “black line” division to delineate the lack of comparability between the Predecessor and Successor. In addition, and as referenced in Note 7 below, we have adopted the full cost method of accounting for our oil and gas properties effective with our adoption of Fresh Start Accounting. Accordingly, our results of operations and financial position for the Successor periods will be substantially different from our historic trends.

We have applied the relevant guidance provided in U.S. GAAP with respect to the accounting and financial statement disclosures for entities that have filed petitions with the bankruptcy court and expect to reorganize as going concerns in preparing our Condensed Consolidated Financial Statements and Notes through the period ended September 12, 2016, or Predecessor periods. That guidance requires that, for periods subsequent to our bankruptcy filing on May 12, 2016, or post-petition periods, certain transactions and events that were directly related to our reorganization be distinguished from our normal business operations. Accordingly, certain revenues, expenses, realized gains and losses and provisions that were realized or incurred in the bankruptcy proceedings have been included in “Reorganization items, net” on our Condensed Consolidated Statement of Operations for the period ended September 12, 2016. In addition, certain liabilities and other obligations incurred prior to May 12, 2016, or pre-petition periods, have been classified in “Liabilities subject to compromise” on our Predecessor Condensed Consolidated Balance Sheet through September 12, 2016. Further detail for our “Reorganization items, net” and “Liabilities subject to compromise” are provided in Note 4 below.

Going Concern Presumption

Our unaudited Condensed Consolidated Financial Statements for the Successor periods have been prepared on a going concern basis, which contemplates the realization of assets and the satisfaction of liabilities and other commitments in the normal course of business. As referenced in Note 3 below, we operated as a “debtor-in-possession” through September 12, 2016, during which time there was inherent doubt as to our ability to continue as a going concern.

Recently Adopted Accounting Pronouncements

In March 2016, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”)2016–09, Improvements to Employee Share-based Payment Accounting (“ASU 2016–09”), which simplifies the accounting for share-based compensation. The areas for simplification that are applicable to publicly-held companies are as follows: (i) Accounting for Income Taxes, (ii) Classification of Excess Tax Benefits on the Statement of Cash Flows, (iii) Forfeitures, (iv) Minimum Statutory Tax Withholding Requirements and (v) Classification of Employee Taxes Paid on the Statement of Cash Flows when an employer withholds shares for tax-withholding purposes. The effective date of ASU 2016–09 is January 1, 2017, with early adoption permitted. We adopted ASU 2016–09 on September 12, 2016 effective upon our emergence from bankruptcy. As of September 30, 2016, we did not have any awards issued in the form of share-based compensation. Accordingly, the adoption of ASU 2016–09 had no impact on our Condensed Consolidated Financial Statements and Notes.

Recently Issued Accounting Pronouncements

In June 2016, the FASB issued ASU 2016–13, Measurement of Credit Losses on Financial Instruments (“ASU 2016–13”), which changes the recognition model for the impairment of financial instruments, including accounts receivable, loans and held-to-maturity debt securities, among others. ASU 2016–13 is required to be adopted using the modified retrospective method by January 1, 2020, with early adoption permitted. ASU 2016–13 will have applicability to our accounts receivable portfolio, particularly those receivables attributable to our joint interest partners. At this time, we do not anticipate that the adoption of ASU 2016–13 will have a significant impact on our Consolidated Financial Statements and related disclosures; however, we are currently in the early stages of evaluating the requirements and the period for which we will adopt the standard.

In February 2016, the FASB issued ASU 2016–02, Leases (“ASU 2016–02”), which will require organizations that lease assets to recognize on the balance sheet the assets and liabilities for the rights and obligations created by those leases with terms of more than twelve months. Consistent with current U.S. GAAP, the recognition, measurement, and presentation of expenses and cash flows arising from a lease by a lessee primarily will depend on its classification as a finance or operating lease. ASU 2016–02 also will require disclosures regarding the amount, timing, and uncertainty of cash flows arising from leases. The effective date of ASU 2016–02 is January 1, 2019, with early adoption permitted. We are continuing to evaluate the effect that ASU 2016–02 will have on our Consolidated Financial Statements and related disclosures as well as the period for which we will adopt the standard. We believe that ASU 2016–02 will likely be applicable to our oil and natural gas gathering commitment arrangements as described in Note 13, our existing leases for office facilities and certain office equipment and potentially to certain drilling rig contracts with terms in excess of twelve months.

In May 2014, the FASB issued ASU 2014–09, Revenues from Contracts with Customers (“ASU 2014–09”), which requires an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. ASU 2014–09 will replace most existing revenue recognition guidance in U.S. GAAP when it becomes effective on January 1, 2018. The standard permits the use of either the retrospective or cumulative effect transition method upon adoption. While traditional commodity sales transactions, property conveyances and joint interest arrangements in the oil and gas industry are not expected to be significantly impacted by ASU 2014–09, natural gas imbalances and other non-product revenues, including our ancillary marketing, gathering and transportation and water service revenues could be affected. Accordingly, we are continuing to evaluate the effect that ASU 2014–09 will have on our Consolidated Financial Statements and related disclosures, with a more focused analysis on these other revenue sources. We have not yet selected a transition method nor have we determined the period for which we will adopt the new standard.

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Chapter 11 Proceedings Chapter 11 Proceedings

9 Months Ended

Sep. 30, 2016

Reorganizations [Abstract]

Reorganization under Chapter 11 of US Bankruptcy Code Disclosure [Text Block]

Chapter 11 Proceedings and Emergence

On May 12, 2016 (the “Petition Date”), we and eight of our subsidiaries (the “Chapter 11 Subsidiaries”) filed voluntary petitions (In re Penn Virginia Corporation, et al, Case No. 16-32395) seeking relief under Chapter 11 of Title 11 of the United States Bankruptcy Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Eastern District of Virginia (the “Bankruptcy Court”).

On August 11, 2016 (the “Confirmation Date”), the Bankruptcy Court confirmed our Second Amended Joint Chapter 11 Plan of Reorganization of Penn Virginia Corporation and its Debtor Affiliates (the “Plan”), and we subsequently emerged from bankruptcy on September 12, 2016 (the “Effective Date”).

Debtors-In-Possession. From the Petition Date through the Effective Date, we and the Chapter 11 Subsidiaries operated our business as debtors-in-possession in accordance with the applicable provisions of the Bankruptcy Code. The Bankruptcy Court granted all “first day” motions filed by us and the Chapter 11 Subsidiaries, which were designed primarily to minimize the impact of the Chapter 11 proceedings on our normal day-to-day operations, our customers, regulatory agencies, including taxing authorities, and employees. As a result, we were able to conduct normal business activities and pay all associated obligations for the post-petition period and we were also authorized to pay and have paid (subject to limitations applicable to payments of certain pre-petition obligations) pre-petition employee wages and benefits, pre-petition amounts owed to certain lienholders, amounts due to taxing authorities for production and other related taxes and funds belonging to third parties, including royalty and working interest holders.

Pre-Petition Agreements. Immediately prior to the Petition Date, the holders (the “Ad Hoc Committee”) of approximately 86 percent of the $1,075 million principal amount of our 7.25% Senior Notes due 2019 (the “2019 Senior Notes”) and 8.50% Senior Notes due 2020 (the “2020 Senior Notes” and, together with the 2019 Senior Notes, the “Senior Notes”) agreed to a restructuring support agreement (the “RSA”) that set forth the general framework of the Plan and the timeline for the Chapter 11 proceedings. In addition, we entered into a backstop commitment agreement (the “Backstop Commitment Agreement”) with the parties thereto (collectively, the “Backstop Parties”), pursuant to which the Backstop Parties committed to provide a $50.0 million commitment to backstop a rights offering (the “Rights Offering”) that was conducted in connection with the Plan.

Plan of Reorganization. Pursuant to the terms of the Plan, which was supported by us, the holders (the “RBL Lenders”) of 100 percent of the claims attributable to our pre-petition revolving credit agreement (as amended, the “RBL”), the Ad Hoc Committee and the Official Committee of Unsecured Claimholders (the “UCC”), the following transactions were completed subsequent to the Confirmation Date and prior to or at the Effective Date:

• the approximately $1,122 million of indebtedness, including accrued interest, attributable to our Senior Notes and certain other unsecured claims were exchanged for 6,069,074 shares representing 41 percent of the Successor’s common stock (“New Common Stock”);

• a total of $50 million of proceeds were received on the Effective Date from the Rights Offering resulting in the issuance of 7,633,588 shares representing 51 percent of New Common Stock to holders of claims arising under the Senior Notes, certain holders of general unsecured claims and to the Backstop Parties;

• the Backstop Parties received a backstop fee comprised of 472,902 shares representing three percent of New Common Stock;

• an additional 816,454 shares representing five percent of New Common Stock were authorized for disputed general unsecured claims and non-accredited investor holders of the Senior Notes and 749,600 shares representing five percent of the New Common Stock outstanding were reserved for issuance under a new management incentive plan;

• on the Effective Date, we entered into a shareholders agreement and a registration rights agreement and amended our articles of incorporation and bylaws for the authorization of the New Common Stock and to provide customary registration rights thereunder, among other corporate governance actions;

• holders of claims arising under the RBL were paid in full from cash on hand, $75.4 million from borrowings under our new revolving credit agreement (the “Revolver”) (see Note 8 below) and proceeds from the Rights Offering;

• the debtor-in-possession credit facility (the “DIP Facility”), under which there were no outstanding borrowings at any time from the Petition Date through the Effective Date, was canceled and less than $0.1 million in fees were paid in full in cash;

• certain other priority claims were paid in full in cash, reinstated or otherwise treated in a manner acceptable to the creditor claim-holders;

• a cash reserve of $2.7 million was established for certain other secured, priority or convenience claims pending resolution as of the Effective Date;

• an escrow account for professional service fees attributable to our advisers and those of the UCC was funded by us with cash of $14.6 million, and we paid $7.2 million for professional fees and expenses on behalf of the RBL Lenders, the Ad Hoc Committee and the indenture trustee for the Senior Notes;

• on the Effective Date, our previous interim Chief Executive Officer, Edward B. Cloues, and each member of our board of directors resigned and was replaced by three new board members: Darin G. Holderness, CPA, Marc McCarthy and Harry Quarls;

• our Predecessor preferred stock and common stock was canceled, extinguished and discharged; and

• all of our Predecessor share-based compensation plans and supplemental employee retirement plan (the “SERP”) entitlements were canceled.

While our emergence from bankruptcy is effectively complete, certain administrative activities will continue under the authority of the Bankruptcy Court for the next several months.

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Fresh Start Accounting (Notes)

8 Months Ended

Sep. 12, 2016

Fresh-Start Balance Sheet [Abstract]

Fresh Start Accounting [Text Block]

Fresh Start Accounting

We adopted Fresh Start Accounting on the Effective Date in connection with our emergence from bankruptcy. As referenced below, our reorganization value of $334.0 million, immediately prior to emergence was substantially less than our post-petition liabilities and allowed claims. Furthermore and in connection with our reorganization, we experienced a change in control as the outstanding common and preferred shares of the Predecessor were canceled and substantially all of the New Common Stock was issued to the Predecessor’s creditors, primarily former holders of our Senior Notes. Accordingly, the holders of the Predecessor’s common and preferred shares effectively received no shares of the Successor. The adoption of Fresh Start Accounting results in a new reporting entity, the Successor, for financial reporting purposes. The presentation is analogous to that of a new business entity such that the Successor is presented with no beginning retained earnings or deficit on the Effective Date.

Reorganization Value

Reorganization value represents the fair value of the Successor’s total assets prior to the consideration of liabilities and is intended to approximate the amount a willing buyer would pay for the assets immediately after a restructuring. The reorganization value, which was derived from the Successor’s enterprise value, was allocated to our individual assets based on their estimated fair values.

Enterprise value represents the estimated fair value of an entity’s long term debt and shareholders’ equity. The Successor’s enterprise value, as approved by the Bankruptcy Court in support of the Plan, was estimated to be within a range of $218 million to $382 million with a mid-point value of $300 million. Based on the estimates and assumptions utilized in our Fresh Start Accounting process, we estimated the Successor’s enterprise value to be approximately $266.2 million after the consideration of cash and cash equivalents on hand at the Effective Date.

The following table reconciles the enterprise value, net of cash and cash equivalents, to the estimated fair value of our Successor common stock as of the Effective Date:

Enterprise value	$	234,831
Plus: Cash and cash equivalents	31,414
Less: Fair value of debt	(75,350		)
Fair value of Successor common stock	$	190,895
Shares outstanding as of September 12, 2016	14,992,018
Per share value	$	12.73

The following table reconciles the enterprise value to the reorganization value of our Successor assets as of the Effective Date:

Enterprise value	$	234,831
Plus: Cash and cash equivalents	31,414
Plus: Current liabilities	54,171
Plus: Noncurrent liabilities excluding long-term debt	13,558
Reorganization value	$	333,974

Valuation Process

Our valuation analysis was prepared with the assistance of an independent third-party consultant utilizing reserve information prepared by our independent reserve engineers, internal development plans and schedules, other internal financial information and projections and the application of standard valuation techniques including risked net asset value analysis and comparable public company metrics.

Our principal assets include the Successor’s oil and gas properties. We determined the fair value of our oil and gas properties based on the discounted cash flows expected to be generated from these assets. Our analyses were based on market conditions and reserves in place as confirmed by our independent petroleum engineers. The proved reserves were segregated into various geographic regions, including sub-regions within the Eagle Ford where a substantial portion of our assets are located, for which separate risk factors were determined based on geological characteristics. Due to the limited drilling plans that we have in place, proved undeveloped locations were risked accordingly. Future cash flows were estimated by using NYMEX forward prices for West Texas Intermediate crude oil and Henry Hub natural gas with inflation adjustments applied to periods beyond a five-year horizon. These prices were adjusted for differentials realized by us for location and product quality. Gathering and transportation costs were estimated based on agreements that we have in place and development and operating costs were based on our most recent experience and adjusted for inflation in future years. The risk-adjusted after-tax cash flows were discounted at a rate of 13.5%. This rate was determined from a weighted-average cost of capital computation which utilized a blended expected cost of debt and expected returns on equity for similar industry participants. Plugging and abandonment costs were also identified and measured in this process in order to determine the fair value of the Successor’s asset retirement obligations (“AROs”) attributable to our proved developed reserves on the Effective Date. Based on this valuation process, we determined fair values of $121.9 million for our proved reserves and $2.7 million for the related AROs.

With respect to the valuation of our undeveloped acreage, we segregated our current lease holdings in the Eagle Ford into prospect regions in which we have significant developed acreage and those in which we have not yet initiated any significant drilling activity. For those prospects within previously developed regions, we applied a multiple based on recent transactions involving acreage deemed comparable to our acreage for each targeted formation. Based on this valuation process, we determined a fair value of $92.5 million for our undeveloped acreage within previously developed regions of the Eagle Ford. For those lease holdings in other areas of the Eagle Ford, we disregarded those prospects for which lease expirations will occur during the remainder of 2016 as well as those for which future drilling is considered uneconomical at current commodity prices. A reduced multiple was then applied to this adjusted undeveloped acreage consistent with recent transactions for acreage deemed comparable to our acreage resulting in a fair value of $8.3 million. We attributed no value to our limited undeveloped lease holdings in all areas other than the Eagle Ford.

Our remaining equipment and other fixed assets were valued at $26.7 million primarily using a cost approach that incorporated depreciation and obsolescence to the extent applicable on an asset-by-asset basis. The most significant of these assets is our water facility in South Texas which is integral to our regional operations. Accordingly, this asset, for which we determined a fair value of $23.4 million, is included in our full cost pool for purposes of determining our depletion, depreciation and amortization (“DD&A”) attributable to our oil and gas production. Certain assets, particularly personal property including office equipment and vehicles, among others, were valued based on market data for comparable assets to the extent such information was available.

The remaining reorganization value is attributable to certain natural gas imbalance receivables, cash and cash equivalents, working capital assets including accounts receivable, prepaid items, current derivative assets and debt issuance costs. Our natural gas imbalance receivables, which are fully attributable to our Mid-Continent operations in the Granite Wash, were valued using NYMEX spot prices for Henry Hub natural gas adjusted for basis differentials for transportation. Our accounts receivable, including amounts receivable from our joint venture partners, were subjected to analysis on an individual basis and reserved to the extent we believe was appropriate. Collectively, these remaining assets, including our current derivative assets which are marked-to-market on a monthly basis, are stated at their fair values on the Effective Date. The reorganization value also includes $3.0 million of issuance costs attributable to the Revolver under which we initially borrowed $75.4 million. This amount has been capitalized in accordance with GAAP as it represents costs attributable to the access to credit over the term of the Revolver.

Our liabilities on the Effective Date include the aforementioned borrowings under the Revolver, working capital liabilities including accounts payable and accrued liabilities, a reserve for certain litigation matters, pension and health care obligations attributable to certain retirees, AROs, and derivative liabilities. As the Revolver is current and is a variable-rate financial instrument, it is stated at its fair value. Our working capital liabilities and litigation reserve are ordinary course obligations and their carrying amounts approximate their fair values. We revalued our retiree obligations based on data from our independent actuaries and have been stated at their fair values. The AROs were valued in connection with the valuation process attributable to our oil and gas reserves as discussed above. Finally, our derivative liabilities have also been stated at their fair value as they are marked-to-market on a monthly basis.

Successor Balance Sheet

The following table reflects the reorganization and application of Fresh Start Accounting adjustments on our Condensed Consolidated Balance Sheet as of September 12, 2016:

						Reorganization					Fresh Start
			Predecessor			Adjustments					Adjustments					Successor
Assets
Current assets
	Cash and cash equivalents		$	48,718		$	(17,304	)	(1	)	$	—				$	31,414
	Accounts receivable, net of allowance for doubtful accounts		35,606			4,292			(2	)	—					39,898
	Derivative assets		397			—					—					397
	Other current assets		3,966			(832		)	(3	)	—					3,134
		Total current assets	88,687			(13,844		)			—					74,843
Property and equipment, net			309,261			—					(55,751		)	(12	)	253,510
Other assets			6,902			(1,281		)	(4	)	—					5,621
		Total assets	$	404,850		$	(15,125	)			$	(55,751	)			$	333,974
Liabilities and Shareholders’ Deficit
Current liabilities
	Accounts payable and accrued liabilities		$	77,151		$	(21,166	)	(5	)	$	(3,455	)	(13	)	$	52,530
	Derivative liabilities		1,641			—					—					1,641
	Current maturities of long-term debt		113,653			(113,653		)	(6	)	—					—
		Total current liabilities	192,445			(134,819		)			(3,455		)			54,171
Other liabilities			84,953			100			(5	)	(80,615		)	(14	)	4,438
Derivative liabilities			9,120			—					—					9,120
Long-term debt			—			75,350			(7	)	—					75,350
Liabilities subject to compromise			1,154,163			(1,154,163		)	(8	)	—					—
Shareholders’ equity (deficit)
	Preferred stock (Predecessor)		1,880			(1,880		)	(9	)	—					—
	Common stock (Predecessor)		697			(697		)	(9	)	—					—
	Paid-in capital (Predecessor)		1,213,797			(1,213,797		)	(9	)	—					—
	Deferred compensation obligation (Predecessor)		3,440			(3,440		)	(9	)	—					—
	Accumulated other comprehensive income (Predecessor)		383			(383		)	(9	)	—					—
	Treasury stock (Predecessor)		(3,574		)	3,574			(9	)	—					—
	Common stock (Successor)		—			150			(10	)	—					150
	Paid-in capital (Successor)		—			190,745			(10	)	—					190,745
	Accumulated deficit		(2,252,454		)	2,224,135			(11	)	28,319			(15	)	—
		Total shareholders’ equity (deficit)	(1,035,831		)	1,198,407					28,319					190,895
		Total liabilities and shareholders’ equity (deficit)	$	404,850		$	(15,125	)			$	(55,751	)			$	333,974

Reorganization Adjustments

1. Represents the net cash payments that occurred on the Effective Date:

Sources:
Proceeds from the Revolver	$	75,350
Proceeds from the Rights Offering, net of issuance costs	49,943
Total sources			$	125,293
Uses:
Repayment of RBL	$	113,653
Accrued interest payable on RBL	1,374
DIP Facility fees	12
Debt issue costs of the Revolver	3,011
Funding of professional fee escrow account	14,575
RBL lender professional fees and expenses	455
Ad Hoc Committee and indenture trustee professional fees and expenses	6,782
Payment of certain allowed claims and settlements	2,735
Total uses			142,597
			$	(17,304	)

2. Represents the reclassification of SERP assets to a current receivable from other noncurrent assets upon the cancellation of the underlying plan and the reversion of the assets to the Successor.

3. Represents the write-off of certain prepaid directors and officers tail insurance.

4. Represents the capitalization of debt issuance costs attributable to the Revolver, net of the reclassification of SERP assets as discussed in item (2) above.

5. Represents the payment of professional fees on behalf of the RBL Lenders, the Ad Hoc Committee and the UCC, indenture trustee fees and expenses, interest payable on the RBL as well as certain allowed claims and settlements net of the establishment of reserves and the reinstatement of certain other obligations.

6. Represents the repayment of the RBL in cash in full.

7. Represents the initial borrowings under the Revolver.

8. Liabilities subject to compromise were settled as follows in accordance with the Plan:

Liabilities subject to compromise prior to the Effective Date:
Senior Notes	$	1,075,000
Interest on Senior Notes	47,213
Firm transportation obligation	11,077
Compensation – related	9,733
Deferred compensation	4,676
Trade accounts payable	1,487
Litigation claims	1,092
Other accrued liabilities	3,885
			$	1,154,163
Amounts settled in cash, reinstated or otherwise reserved at emergence			(3,915		)
Gain on settlement of liabilities subject to compromise			$	1,150,248

9. Represents the cancellation of our Predecessor preferred and common stock and related components of our Predecessor shareholders’ deficit.

10. Represents the issuance of 14,992,018 shares of New Common Stock with a fair value of $12.73 per share.

11. Represents the cumulative impact of the reorganization adjustments described above:

Gain on settlement of of liabilities subject to compromise		$	1,150,248
Fair value of equity allocated to:
Unsecured creditors on the Effective Date	174,477
Unsecured creditors pending resolution on the Effective Date	10,396
Backstop Parties in the form of a Commitment Premium	6,022
		190,895
Cancellation of Predecessor shareholders’ deficit		882,992
Net impact to Predecessor accumulated deficit		$	2,224,135

Fresh Start Adjustments

12. Represents the Fresh Start Accounting valuation adjustments applied to our oil and gas properties and other equipment.

13. Represents the accelerated recognition of the current portion of previously deferred gains on sales of assets attributable to the accounting presentation required by GAAP under the Predecessor.

14. Represents the recognition of Fresh Start Accounting adjustments to: (i) our AROs attributable to the revalued oil and gas properties and (ii) our retiree obligations based on actuarial measurements, as well as the accelerated recognition of the noncurrent portion of previously deferred gains on sales of assets attributable to the accounting presentation required by GAAP under the Predecessor.

15. Represents the cumulative impact of the Fresh Start Accounting adjustments discussed above.

Reorganization Items. As described above in Note 2, our Condensed Consolidated Statements of Operations for the periods ended September 12, 2016 include “Reorganization items, net,” which reflects gains recognized on the settlement of liabilities subject to compromise and costs and other expenses associated with the Chapter 11 proceedings, principally professional fees, and the costs associated with the DIP Facility. These post-petition costs for professional fees, as well as administrative fees charged by the U.S. Trustee, have been reported in “Reorganization items, net” in our Condensed Consolidated Statement of Operations as described above. Similar costs that were incurred during the pre-petition periods have been reported in “General and administrative” expenses.

The following table summarizes the components included in “Reorganization items, net” in our Condensed Consolidated Statements of Operations for the periods presented:

	July 1 through			January 1 through
	September 12,			September 12,
	2016			2016
Gains on the settlement of liabilities subject to compromise	$	1,150,248		$	1,150,248
Fresh start accounting adjustments	28,319			28,319
Legal and professional fees and expenses	(22,739		)	(29,976		)
Settlements attributable to contract amendments	(2,550		)	(2,550		)
DIP Facility costs and commitment fees	(27		)	(170		)
Write-off of prepaid directors and officers insurance	(832		)	(832		)
Other reorganization items	(46		)	(46		)
	$	1,152,373		$	1,144,993

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Accounts Receivable and Major Customers

9 Months Ended

Sep. 30, 2016

Receivables [Abstract]

Accounts Receivable and Major Customers

Accounts Receivable and Major Customers

The following table summarizes our accounts receivable by type as of the dates presented:

	Successor			Predecessor
	September 30,			December 31,
	2016			2015
Customers	$	19,221		$	23,481
Joint interest partners	8,201			18,381
Other 1	7,158			7,658
	34,580			49,520
Less: Allowance for doubtful accounts	(2,443		)	(1,555		)
	$	32,137		$	47,965

_______________________

¹ Includes amounts owed to us from joint venture partners for acquisitions in prior periods, severance tax refunds approved by state taxing authorities to be returned to us and other miscellaneous non-operating items. The balance as of September 30, 2016 also includes a $4.3 million receivable from the trustee of the SERP for the reversion of plan assets to the Successor.

For the nine months ended September 30, 2016, or combined Predecessor and Successor periods, three customers accounted for $93.5 million, or approximately 94%, of our consolidated product revenues. The revenues generated from these customers during the nine months ended September 30, 2016 were $64.1 million, $15.8 million and $13.6 million or 64%, 16% and 14% of the consolidated total, respectively. As of September 30, 2016, $16.2 million, or approximately 88%, of our consolidated accounts receivable from customers was related to these customers. For the nine months ended September 30, 2015, two customers accounted for $108.4 million, or approximately 50%, of our consolidated product revenues. The revenues generated from these customers during the nine months ended September 30, 2015 were $62.3 million and $46.1 million, or approximately 29%, and 21% of the consolidated total, respectively. As of December 31, 2015, $21.1 million, or approximately 90%, of our consolidated accounts receivable from customers was related to these customers. No significant uncertainties exist related to the collectability of amounts owed to us by any of these customers.

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Derivative Instruments

9 Months Ended

Sep. 30, 2016

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments

Derivative Instruments

We utilize derivative instruments to mitigate our financial exposure to crude oil and natural gas price volatility. Our derivative instruments are not formally designated as hedges in the context of U.S. GAAP.

Commodity Derivatives

We typically utilize collars and swaps, which are placed with financial institutions that we believe are acceptable credit risks, to hedge against the variability in cash flows associated with anticipated sales of our future oil and gas production. While the use of derivative instruments limits the risk of adverse price movements, such use may also limit future revenues from favorable price movements.

The counterparty to a collar or swap contract is required to make a payment to us if the settlement price for any settlement period is below the floor or swap price for such contract. We are required to make a payment to the counterparty if the settlement price for any settlement period is above the ceiling or swap price for such contract. Neither party is required to make a payment to the other party if the settlement price for any settlement period is equal to or greater than the floor price and equal to or less than the ceiling price for such contract.

We determine the fair values of our commodity derivative instruments based on discounted cash flows derived from third-party quoted forward prices for NYMEX Henry Hub gas and West Texas Intermediate crude oil closing prices as of the end of the reporting period. The discounted cash flows utilize discount rates adjusted for the credit risk of our counterparties if the derivative is in an asset position and our own credit risk if the derivative is in a liability position.

We terminated all of our pre-petition derivative contracts for $22.9 million, $22.6 million and $17.5 million and reduced our amounts outstanding under the RBL by $22.9 million, $16.6 million and $12.5 million in March 2016, April 2016 and May 2016, respectively. In connection with these transactions, the counterparties to the derivative contracts, which are also affiliates of lenders under the RBL, transferred the cash proceeds that were used for RBL repayments directly to the administrative agent under the RBL. Accordingly, all of these RBL repayments have been presented as non-cash financing activities on our Condensed Consolidated Statement of Cash Flows for the period January 1, 2016 through September 12, 2016.

On May 13, 2016, the Bankruptcy Court approved our motion to enter into new commodity derivative contracts. Accordingly, we hedged a substantial portion of our future crude oil production through the end of 2019, as required in the RSA, at a weighted-average price of approximately $48.62 per barrel. We are currently unhedged with respect to natural gas production.

The following table sets forth our commodity derivative positions as of September 30, 2016:

		Average
		Volume Per	Weighted Average Price			Fair Value
	Instrument	Day	Floor/Swap		Ceiling	Asset		Liability
Crude Oil:		(barrels)	($/barrel)
Fourth quarter 2016	Swaps	5,940	$	47.69		$	—	$	709
First quarter 2017	Swaps	4,408	$	48.62		—		737
Second quarter 2017	Swaps	4,408	$	48.62		—		1,106
Third quarter 2017	Swaps	4,408	$	48.62		—		1,335
Fourth quarter 2017	Swaps	4,408	$	48.62		—		1,518
First quarter 2018	Swaps	3,476	$	49.12		—		1,131
Second quarter 2018	Swaps	3,476	$	49.12		—		1,244
Third quarter 2018	Swaps	3,476	$	49.12		—		1,353
Fourth quarter 2018	Swaps	3,476	$	49.12		—		1,451
First quarter 2019	Swaps	2,916	$	49.90		—		1,051
Second quarter 2019	Swaps	2,916	$	49.90		—		1,117
Third quarter 2019	Swaps	2,916	$	49.90		—		1,179
Fourth quarter 2019	Swaps	2,916	$	49.90		—		1,247

Financial Statement Impact of Derivatives

The impact of our derivative activities on income is included in “Derivatives” in our Condensed Consolidated Statements of Operations. The following tables summarize the effects of our derivative activities for the periods presented:

	Successor			Predecessor
	Period From September 13, 2016			Period from July 1, 2016		Three Months Ended
	Through September 30, 2016			through September 12, 2016		September 30, 2015
Derivative gains (losses)	$	(4,369	)	$	8,934	$	44,701

	Successor			Predecessor
	Period From September 13, 2016			Period From January 1, 2016			Nine Months Ended
	Through September 30, 2016			Through September 12, 2016			September 30, 2015
Derivative gains (losses)	$	(4,369	)	$	(8,333	)	$	52,073

The effects of derivative gains and (losses) and cash settlements (except for those cash settlements attributable to the aforementioned termination transactions) are reported as adjustments to reconcile net income (loss) to net cash provided by operating activities. These items are recorded in “Derivative contracts” on our Condensed Consolidated Statements of Cash Flows under “Net losses (gains)” and “Cash settlements, net.”

The following table summarizes the fair values of our derivative instruments, as well as the locations of these instruments on our Condensed Consolidated Balance Sheets as of the dates presented:

		Successor				Predecessor
		Fair Values as of
		September 30, 2016				December 31, 2015
		Derivative		Derivative		Derivative		Derivative
Type	Balance Sheet Location	Assets		Liabilities		Assets		Liabilities
Commodity contracts	Derivative assets/liabilities – current	$	446	$	3,888	$	97,956	$	—
Commodity contracts	Derivative assets/liabilities - noncurrent	—		11,291		—		—
		$	446	$	15,179	$	97,956	$	—

As of September 30, 2016, we reported a net commodity derivative liability of $14.7 million. The contracts associated with this position are with three counterparties, all of which are investment grade financial institutions. This concentration may impact our overall credit risk, either positively or negatively, in that these counterparties may be similarly affected by changes in economic or other conditions. We have neither paid to, nor received from, our counterparties any cash collateral in connection with our derivative positions. Furthermore, our derivative contracts are not subject to margin calls or similar accelerations. No significant uncertainties exist related to the collectability of amounts that may be owed to us by these counterparties.

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Property and Equipment

9 Months Ended

Sep. 30, 2016

Property, Plant and Equipment [Abstract]

Property and Equipment

Property and Equipment

The following table summarizes our property and equipment as of the dates presented: 

	Successor			Predecessor
	September 30,			December 31,
	2016			2015
Oil and gas properties:
Proved	$	241,308		$	2,678,415
Unproved	8,338			6,881
Total oil and gas properties	249,646			2,685,296
Other property and equipment	3,574			31,365
Total properties and equipment	253,220			2,716,661
Accumulated depreciation, depletion and amortization	(2,020		)	(2,372,266		)
	$	251,200		$	344,395

We account for our oil and gas properties by applying the full cost method in the Successor period whereas we utilized the successful efforts method during the Predecessor periods.

The following describes our accounting policies with respect to our oil and gas properties and equipment:

Under the full cost method of accounting for oil and gas properties, all costs incurred in the exploration, development and acquisition of oil and gas reserves are capitalized. Such costs may be incurred both prior to and after the acquisition of a property and include lease acquisitions, geological and geophysical, or seismic, drilling, completion and equipment costs. Internal costs incurred that are directly attributable to exploration, development and acquisition activities undertaken by us for our own account, and which are not attributable to production, general corporate overhead or similar activities are also capitalized.

Depreciation, depletion and amortization (“DD&A”) of our oil and gas properties is computed using the units-of-production method. We apply this method by multiplying the unamortized cost of our proved oil and gas properties, net of estimated salvage plus future development costs, by a rate determined by dividing the physical units of oil and gas produced during the period by the total estimated units of proved oil and gas reserves at the beginning of the period.

At the end of each quarterly reporting period, the unamortized cost of our oil and gas properties, net of deferred income taxes, is limited to the sum of the estimated discounted future net revenues from proved properties adjusted for costs excluded from amortization and related income taxes (“Ceiling Test”). The estimated discounted future net revenues are determined using the prior 12-month’s average price based on closing prices on the first day of each month, adjusted for differentials, discounted at 10%. The calculation of the Ceiling Test and provision for DD&A are based on estimates of proved reserves. There are significant uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production, timing and plan of development.

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Long-Term Debt

9 Months Ended

Sep. 30, 2016

Debt Disclosure [Abstract]

Long-Term Debt

Debt Obligations

The following table summarizes our debt obligations as of the dates presented:

	Successor				Predecessor
	September 30, 2016				December 31, 2015
	Principal		Unamortized Issuance Costs 1		Principal			Unamortized Issuance Costs 1
Revolving credit facility 2	$	54,350			$	—
Pre-petition revolving credit facility 3	—				170,000
Senior notes due 2019	—		$	—	300,000			$	3,295
Senior notes due 2020	—		—		775,000			17,322
Totals	54,350		$	—	1,245,000			$	20,617
Less: Unamortized issuance costs	—				(20,617		)
Less: Amounts classified as current	—				(1,224,383		)
Long-term debt, net of unamortized issuance costs	$	54,350			$	—

____________________

¹ Issuance costs attributable to the Senior Notes were subject to an accelerated write-off in advance of our bankruptcy filing during the three months ended June 30, 2016.

² Issuance costs attributable to the Revolver, which represent costs attributable to the access to credit over the Revolver’s contractual term, have been presented as a component of Other assets (see Note 11).

³ Issuance costs attributable to the RBL were presented as a component of Other assets (see Note 11) prior to the accelerated write-off in advance of our bankruptcy filing during the three months ended June 30, 2016.

Revolving Credit Facility

Upon the Effective Date, we entered into the Revolver. The Revolver provides for a $200 million revolving commitment and has an initial borrowing base of $128 million. The Revolver also includes a $5.0 million sublimit for the issuance of letters of credit, of which $0.8 million was outstanding as of September 30, 2016. The Revolver is governed by a borrowing base calculation, which is redetermined semi-annually, and the availability under the Revolver may not exceed the lesser of the aggregate commitments and the borrowing base. The Revolver is scheduled for its initial redetermination in April 2017. The Revolver is available to us to pay expenses associated with Chapter 11 and for general corporate purposes including working capital. The Revolver matures in September 2020.

The outstanding borrowings under the Revolver bear interest at a rate equal to, at our option, either (a) a customary reference rate plus an applicable margin ranging from 2.00% to 3.00%, determined based on the average availability under the Revolver or (b) a customary London interbank offered rate (“LIBOR”) plus an applicable margin ranging from 3.00% to 4.00%, determined based on the average availability under the Revolver. Interest on reference rate borrowings is payable quarterly in arrears and is computed on the basis of a year of 365/366 days, and interest on eurocurrency borrowings is payable every one, three or six months, at the election of the Borrower, and is computed on the basis of a 360-day year. As of September 30, 2016, the actual interest rate on the outstanding borrowings under the Revolver was 3.770% which is derived from the LIBOR rate of 0.520% plus an applicable margin of 3.250%. Unused commitment fees are charged at a rate of 0.50%.

The Revolver is guaranteed by us and all of our subsidiaries (the “Guarantor Subsidiaries”). The guarantees under the Revolver are full and unconditional and joint and several. Substantially all of our consolidated assets are held by the Guarantor Subsidiaries. The parent company has no material independent assets or operations. The obligations under the Revolver are secured by a first priority lien on substantially all of our assets.

The Revolver requires us to maintain (1) a minimum interest coverage ratio (adjusted earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses as defined in the Revolver (“EBITDAX”) to adjusted interest expense), measured as of the last day of each fiscal quarter, of 3.00 to 1.00, (2) a minimum current ratio (as defined in the Revolver), measured as of the last day of each fiscal quarter of 1.00 to 1.00, and (3) a maximum leverage ratio (consolidated indebtedness to adjusted EBITDAX), measured as of the last day of each fiscal quarter, initially of 4.00 to 1.00, decreasing on December 31, 2017 to 3.75 to 1.00 and on March 31, 2018 and thereafter to 3.50 to 1.00. In accordance with the terms of the Revolver, the quarter ending December 31, 2016 will be the first period for which we are required to comply with these covenants.

The Revolver also contains customary affirmative and negative covenants, including as to compliance with laws (including environmental laws, ERISA and anti-corruption laws), maintenance of required insurance, delivery of quarterly and annual financial statements, oil and gas engineering reports and budgets, maintenance and operation of property (including oil and gas properties), restrictions on the incurrence of liens and indebtedness, merger, consolidation or sale of assets, payment of dividends, and transactions with affiliates and other customary covenants.

The Revolver contains customary events of default and remedies for credit facilities of this nature. If we do not comply with the financial and other covenants in the Revolver, the lenders may, subject to customary cure rights, require immediate payment of all amounts outstanding under the Revolver.

Pre-Petition Revolving Credit Agreement

As described in Notes 3 and 4, our principal and interest obligations outstanding under the RBL as well as certain associated fees and expenses were satisfied in cash in full on the Effective Date. These obligations were funded from a combination of cash on hand, proceeds from the Rights Offering and proceeds from initial borrowings under the Revolver.

2019 Senior Notes and 2020 Senior Notes

The Senior Notes have been included in “Liabilities subject to compromise” on the Condensed Consolidated Balance Sheet of the Predecessor as of September 12, 2016 (see Note 4) and have been included in “Current liabilities” as of December 31, 2015. As described in Notes 3 and 4, the Senior Notes were canceled upon our emergence from bankruptcy.

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Income Taxes

9 Months Ended

Sep. 30, 2016

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

We recognized a federal income tax benefit for each of the periods ended September 12, 2016 (Predecessor) and September 30, 2016 (Successor) at the statutory rate of 35%; however, the federal tax benefit was fully offset by a valuation allowance against our net deferred tax assets. We considered both the positive and negative evidence in determining that it was more likely than not that some portion or all of our deferred tax assets will not be realized, primarily as a result of cumulative losses. We recognized income tax benefits for the three and nine months ended September 30, 2015 due primarily to a federal return to provision adjustment partially offset by a minimal deferred state income tax expense. We received a state income tax refund of less than $0.1 million during the period ended September 12, 2016.

We have evaluated the impact of the reorganization, including the change in control, resulting from our emergence from bankruptcy. From an income tax perspective, the most significant impact is attributable to our carryover tax attributes associated with our net operating losses (“NOLs”). We believe that the Successor will be able to fully absorb the cancellation of debt income realized by the Predecessor in connection with the reorganization with its adjusted NOL carryovers. The amount of the remaining NOL carryovers and the tax basis of our properties will be limited under Section 382 of the Internal Revenue Code due to the change in control as referenced in Notes 3 and 4. As the tax basis of our assets, primarily our oil and gas properties, is in excess of the carrying value, as adjusted in the Fresh Start Accounting process, the Successor is in a net deferred tax asset position. We have determined that it is more likely than not that we will not realize future income tax benefits from the additional tax basis and our remaining NOL carryovers. Accordingly, we have provided for a full valuation allowance of the underlying deferred tax assets.

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Exit Activities

9 Months Ended

Sep. 30, 2016

Restructuring and Related Activities [Abstract]

Exit Activities

Exit Activities

We have committed to a number of actions, or exit activities, consistent with our current business plans for which we have continuing financial commitments. The most significant of these activities are attributable to an overall reduction in the scope and scale of our organization and require payments to satisfy obligations associated with the underlying commitments. The following summarizes our most significant exit activities.

Reductions in Force

In connection with efforts to reduce our administrative costs, we took certain actions to reduce our total employee headcount. In February, June and September, we reduced our total employee headcount by 45 employees. We paid a total of $1.9 million, including $1.2 million in severance and termination benefits and $0.7 million in retention bonuses during the nine months ended September 2016, and $0.1 million in severance and termination benefits during October 2016. The employment of nine employees scheduled for termination was extended with a payout of $0.2 million in retention bonuses, included in the above retention. Estimated severance and termination benefits for these employees is expected to be $0.3 million. The affected employees must continue to provide services through each of their extension dates in order to receive these benefits. Accordingly, we incurred a charge and established an accrual representing the period for which these benefits have been earned.

The costs associated with these reduction-in-force and retention actions are included as a component of our “General and administrative” expenses on our Condensed Consolidated Statements of Operations. The related obligations are included in “Accounts payable and accrued liabilities” on our Condensed Consolidated Balance Sheet.

Drilling Rig Termination

In connection with the suspension of our 2016 drilling program in the Eagle Ford, we terminated our one remaining drilling rig contract and incurred $1.3 million in early termination charges. As this obligation represented a pre-petition liability of the Predecessor, it was discharged and included in “Reorganization items, net” on our Condensed Consolidated Statements of Operations. The vendor recovered a portion of the amount in the form of New Common Stock.

Firm Transportation Obligation

We had a contractual obligation for certain firm transportation capacity in the Appalachian region that was scheduled to expire in 2022 and, as a result of the sale of our natural gas assets in this region in 2012, we no longer had production available to satisfy this commitment. We originally recognized a liability in 2012 representing this obligation for the estimated discounted future net cash outflows over the remaining term of the contract. The accretion of the obligation through the Petition Date, net of any recoveries from periodic sales of our contractual capacity, was charged as an offset to Other revenue. In connection with our emergence from bankruptcy, we rejected the underlying contract and the obligation was discharged and included in “Reorganization items, net” on our Condensed Consolidated Statements of Operations. The vendor recovered a portion of the amount in the form of New Common Stock.

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Additional Balance Sheet Detail

9 Months Ended

Sep. 30, 2016

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Additional Balance Sheet Detail

Additional Balance Sheet Detail

The following table summarizes components of selected balance sheet accounts as of the dates presented:

	Successor		Predecessor
	September 30,		December 31,
	2016		2015
Other current assets:
Tubular inventory and well materials	$	2,154	$	2,878
Prepaid expenses	1,357		4,184
Other	7		42
	$	3,518	$	7,104
Other assets:
Assets of SERP 1	$	—	$	4,123
Deferred issuance costs of the revolving credit facilities 2	2,973		1,572
Other	2,598		2,655
	$	5,571	$	8,350
Accounts payable and accrued liabilities:
Trade accounts payable	$	7,926	$	11,603
Drilling costs	1,475		12,074
Royalties and revenue – related	28,203		39,119
Compensation – related	2,164		9,904
Interest	125		15,531
Other	5,539		15,294
	$	45,432	$	103,525
Other liabilities:
Deferred gains on sales of assets	$	—	$	82,943
Firm transportation obligation	—		10,705
Asset retirement obligations	2,696		2,621
Defined benefit pension obligations	1,132		1,129
Postretirement health care benefit obligations	523		731
Compensation – related	—		1,447
Deferred compensation – SERP obligations and other	—		4,434
Other	100		928
	$	4,451	$	104,938

_______________________

¹ In connection with our emergence from bankruptcy, the assets of the SERP reverted to us upon the release of claims by our employees attributable to certain deferred compensation arrangements in September 2016. The SERP assets were liquidated by the plan trustee in November 2016 and the cash value was transferred to us (see Notes 3, 4 and 5).

² The balance as of September 30, 2016 includes those costs, net of amortization, attributable to the Revolver. Deferred issuance costs attributable to the RBL, which represents the amounts outstanding as of December 31, 2015, were charged in full to interest expense during the three months ended June 30, 2016 in advance of our Chapter 11 filing.

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Fair Value Measurements

9 Months Ended

Sep. 30, 2016

Fair Value Disclosures [Abstract]

Fair Value Measurements

Fair Value Measurements

We apply the authoritative accounting provisions for measuring fair value of both our financial and nonfinancial assets and liabilities. Fair value is an exit price representing the expected amount we would receive upon the sale of an asset or that we would expect to pay to transfer a liability in an orderly transaction with market participants at the measurement date.

Our financial instruments that are subject to fair value disclosure consist of cash and cash equivalents, accounts receivable, accounts payable, derivatives and long-term debt. As of September 30, 2016, the carrying values of all of these financial instruments approximated fair value.

The following table summarizes the fair value of our debt obligations with fixed interest rates, which is estimated based on the published market prices for these financial liabilities, as of the dates presented:

	Successor				Predecessor
	September 30, 2016				December 31, 2015
	Fair Value		Carrying Value		Fair Value		Carrying Value
Senior Notes due 2019 1	$	—	$	—	$	40,830	$	300,000
Senior Notes due 2020 1	—		—		125,473		775,000
	$	—	$	—	$	166,303	$	1,075,000

______________________

¹ The Senior Notes were canceled upon our emergence from bankruptcy.

Recurring Fair Value Measurements

Certain financial assets and liabilities are measured at fair value on a recurring basis in our Condensed Consolidated Balance Sheets. The following tables summarize the valuation of those assets and liabilities as of the dates presented:

	Successor As of September 30, 2016
	Fair Value			Fair Value Measurement Classification
Description	Measurement			Level 1		Level 2			Level 3
Assets:
Commodity derivative assets – current	$	446		$	—	$	446		$	—
Assets of SERP 1	4,292			4,292		—			—
Liabilities:
Commodity derivative liabilities – current	(3,888		)	—		(3,888		)	—
Commodity derivative liabilities – noncurrent	(11,291		)	—		(11,291		)	—

______________________

¹ In connection with our emergence from bankruptcy, the assets of the SERP reverted to us upon the release of claims by our employees attributable to certain deferred compensation arrangements in September 2016. The SERP assets were liquidated by the plan trustee in October 2016 and the cash value, which was included in accounts receivable as of September 30, 2016, was transferred to us for general corporate purposes.

	Predecessor As of December 31, 2015
	Fair Value			Fair Value Measurement Classification
Description	Measurement			Level 1			Level 2		Level 3
Assets:
Commodity derivative assets – current	$	97,956		$	—		$	97,956	$	—
Assets of SERP	4,123			4,123			—		—
Liabilities:
Deferred compensation – SERP obligations	(4,125		)	(4,125		)	—		—

Changes in economic conditions or model-based valuation techniques may require the transfer of financial instruments from one level of the fair value hierarchy to another level. In such instances, the transfer is deemed to have occurred at the beginning of the quarterly period in which the event or change in circumstances that caused the transfer occurred. There were no transfers during the nine months ended September 30, 2016 and 2015.

We used the following methods and assumptions to estimate fair values for the financial assets and liabilities described below:

• Commodity derivatives: We determine the fair values of our commodity derivative instruments based on discounted cash flows derived from third-party quoted forward prices for West Texas Intermediate crude oil and NYMEX Henry Hub gas closing prices as of the end of the reporting periods. We generally use the income approach, using valuation techniques that convert future cash flows to a single discounted value. Each of these is a level 2 input.

• Assets of SERP: We held various publicly traded equity securities in a Rabbi Trust as assets for funding certain deferred compensation obligations. The fair values were based on quoted market prices, which are level 1 inputs.

• Deferred compensation – SERP obligations: Certain of our deferred compensation obligations were ultimately to be settled in cash based on the underlying fair value of certain assets, including those held in the Rabbi Trust. The fair values were based on quoted market prices, which are level 1 inputs.

Non-Recurring Fair Value Measurements

The most significant non-recurring fair value measurements utilized in the preparation of our Condensed Consolidated Financial Statements are those attributable to the recognition and measurement of the Successor's net assets with respect to the application of Fresh Start Accounting. Those measurements are more fully described in Note 4. In addition, we utilize non-recurring fair value measurements with respect to the recognition and measurement of asset impairments, particularly during our Predecessor periods during which time we applied the successful efforts method to our oil and gas properties, as well as the initial determination of AROs associated with the ongoing development of new oil and gas properties.

The factors used to determine fair value for purposes of recognizing and measuring asset impairments while we applied the successful efforts method to our oil and gas properties during our Predecessor periods included, but were not limited to, estimates of proved and risk-adjusted probable reserves, future commodity prices, indicative sales prices for properties, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties. Under the full cost method, we apply a ceiling test determination utilizing prescribed procedures as described in Note 7. The full cost method is substantially different from the successful efforts method which relies upon fair value measurements. Because these significant fair value inputs were typically not observable, we have categorized the amounts as level 3 inputs.

The determination of the fair value of AROs is based upon regional market and facility specific information. The amount

of an ARO and the costs capitalized represent the estimated future cost to satisfy the abandonment obligation using current

prices that are escalated by an assumed inflation factor after discounting the future cost back to the date that the abandonment

obligation was incurred using a rate commensurate with the risk, which approximates our cost of funds. Because these

significant fair value inputs are typically not observable, we have categorized the initial estimates as level 3 inputs.

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Commitments and Contingencies

9 Months Ended

Sep. 30, 2016

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments and Contingencies

Gathering and Intermediate Transportation Commitments

We have long-term agreements with Republic Midstream, LLC (“Republic Midstream”) and Republic Midstream Marketing, LLC (“Republic Marketing” and, together with Republic Midstream, collectively, “Republic”) to provide for gathering and intermediate pipeline transportation services for a substantial portion of our crude oil and condensate production in the South Texas region as well as volume capacity support for certain downstream interstate pipeline transportation.

In August 2016, the Bankruptcy Court approved a settlement with Republic and authorized the assumption of certain amended agreements with Republic (the “Amended Agreements”). We paid Republic $0.3 million in connection with the settlement which is included in “Reorganization items, net” in our Condensed Consolidated Statements of Operations.

Under the terms of the Amended Agreements, Republic is obligated to gather and transport our crude oil and condensate from within a dedicated area in the Eagle Ford (the “Dedication Area”) via a gathering system and intermediate takeaway pipeline connecting to a downstream interstate pipeline operated by a third party. The amended gathering agreement reduced our minimum volume commitment from 15,000 to 8,000 barrels of oil per day. The term of the amended gathering agreement runs through 2041, with the term of the minimum volume commitment extended from 10 to 15 years.

Under the amended marketing agreement, we have a 10-year commitment to sell 8,000 barrels per day of crude oil to Republic, or any third party, utilizing Republic Marketing’s capacity on a certain downstream interstate pipeline.

Excluding the potential impact of the effects of price escalation from commodity price changes, the minimum fee requirements under the Amended Agreements are as follows: $3.9 million for the remainder of 2016, $9.6 million for 2017, $10.4 million for 2018, $11.7 million for 2019, $13.0 million for 2020 through 2025, $7.4 million for 2026, $3.8 million for 2027 through 2030 and $2.2 million for 2031.

Legal and Regulatory

We are involved, from time to time, in various legal proceedings arising in the ordinary course of business. While the ultimate results of these proceedings cannot be predicted with certainty, our management believes that these claims will not have a material effect on our financial position, results of operations or cash flows. During the quarter ended September 30, 2016, we reduced our reserve for a litigation matter to $0.1 million from $0.9 million due to our expected dismissal from the subject litigation. As of September 30, 2016, we also had AROs of approximately $2.7 million attributable to the plugging of abandoned wells. 

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Shareholders' Equity

9 Months Ended

Sep. 30, 2016

Equity [Abstract]

Shareholders' Equity

Shareholders’ Equity

The following tables summarize the components of our shareholders’ equity (deficit) and the changes therein as of and for the Predecessor period from December 31, 2015, through September 12, 2016 and the Successor period from September 13, 2016 through September 30, 2016:

																Accumulated
													Deferred			Other
	Preferred			Common			Paid-in			Accumulated			Compensation			Comprehensive			Treasury
	Stock 2			Stock 2			Capital 2			Deficit			Obligation			Income 3			Stock			Total
Balance, December 31, 2015 (Predecessor)	$	3,146		$	628		$	1,211,088		$	(2,130,271	)	$	3,440		$	422		$	(3,574	)	$	(915,121	)
Net Loss	—			—			—			1,054,602			—			—			—			1,054,602
All Other Changes 1	(1,266		)	69			2,709			—			—			(39		)	—			1,473
Balance, September 12, 2016 (Predecessor)	$	1,880		$	697		$	1,213,797		$	(1,075,669	)	$	3,440		$	383		$	(3,574	)	$	140,954
Cancellation of Predecessor equity	(1,880		)	(697		)	(1,213,797		)	1,075,669			(3,440		)	(383		)	3,574			(140,954		)
Balance, September 12, 2016 (Predecessor)	$	—		$	—		$	—		$	—		$	—		$	—		$	—		$	—
Issuance of Successor common stock - Rights Offering	$	—		$	76		$	49,867		$	—		$	—		$	—		$	—		$	49,943
Issuance of Successor common stock - Backstop Fee	—			5			9,054			—			—			—			—			9,059
Issuance of Successor common stock - exchange of claims	—			69			131,824			—			—			—			—			131,893
Balance, September 12, 2016 (Successor)	—			150			190,745			—			—			—			—			190,895
Net Loss	—			—			—			(3,441		)	—			—			—			(3,441		)
Balance, September 30, 2016 (Successor)	$	—		$	150		$	190,745		$	(3,441	)	$	—		$	—		$	—		$	187,454

_______________________

¹ Includes equity-classified share-based compensation of $(3,918) for the period January 1, 2016 through September 12, 2016. Share-based compensation awards that were outstanding on the Effective Date were canceled in connection with our emergence from bankruptcy.

² A total of 52 shares, or 5,159 depositary shares, of our Series A 6% Convertible Perpetual Preferred Stock (the “Series A Preferred Stock”) were converted into 85,982 shares of our common stock during the period January 1, 2016 through September 12, 2016. A total of 12,619 shares, or 1,261,850 depositary shares, of our Series B 6% Convertible Perpetual Preferred Stock (the “Series B Preferred Stock”) were converted into 6,879,222 shares of our common stock during the period January 1, 2016 through September 12, 2016. Preferred Stock was canceled in connection with our emergence from bankruptcy.

³ Accumulated other comprehensive income (“AOCI”) is entirely attributable to our defined benefit pension and postretirement health care plans. The changes in the balance of AOCI for the period January 1, 2016 through September 12, 2016, represent reclassifications from AOCI to net periodic benefit expense, a component of “General and administrative expenses,” of $(38).

In September 2015, we announced a suspension of quarterly dividends on the Series A Preferred Stock and Series B Preferred Stock for the quarter ended September 30, 2015, which was extended through the bankruptcy period. The accumulated dividends were discharged as a result of our emergence from bankruptcy.

We do not anticipate that cash dividends or other distributions will be paid with respect to our common stock in the foreseeable future. In addition, our Revolver has restrictive covenants that limit our ability to pay dividends.

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Share-Based Compensation and Other Benefit Plans

9 Months Ended

Sep. 30, 2016

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Share-Based Compensation and Other Benefit Plans

Share-Based Compensation and Other Benefit Plans

Share-Based Compensation

We recognize share-based compensation expense related to our share-based compensation plans as a component of “General and administrative” expense in our Condensed Consolidated Statements of Operations.

In the Predecessor periods in 2016 and 2015 we had outstanding equity-classified awards in the form of stock options, restricted stock units and deferred stock unit. As discussed in Notes 3 and 4, all remaining equity-classified share-based compensation awards were canceled in connection with our emergence from bankruptcy. On the Effective Date, we authorized 749,600 shares of New Common Stock for future share-based compensation awards, none of which were outstanding as of September 30, 2016.

With the exception of performance-based restricted stock units (“PBRSUs”), all of our Predecessor’s share-based compensation awards were classified as equity instruments because they would result in the issuance of common stock on the date of grant, upon exercise or were otherwise payable in common stock upon vesting, as applicable. The compensation cost attributable to these awards was measured at the grant date and recognized over the applicable vesting period as a non-cash item of expense. Because the PBRSUs were payable in cash, they were typically considered liability-classified awards and were included in “Accounts payable and accrued liabilities” (current portion) and “Other liabilities” (noncurrent portion) on our Condensed Consolidated Balance Sheets of the Predecessor. Compensation cost associated with the PBRSUs was measured at the end of each reporting period and recognized based on the period of time that had elapsed during each of the individual performance periods. Similar to the equity-classified awards referenced above, all outstanding PBRSUs were canceled as well upon our emergence from bankruptcy.

The following tables summarize our share-based compensation expense (benefit) recognized for the periods presented:

	Successor		Predecessor
	Period from September 13,		Period from July 1,
	2016 through September		2016 through September		Three Months Ended
	30, 2016		12, 2016		September 30, 2015
Equity-classified awards	$	—	$	5,433	$	1,263
Liability-classified awards	—		—		(851		)
	$	—	$	5,433	$	412

	Successor		Predecessor
	Period from September 13,		Period from January 1,
	2016 through September		2016 through September			Nine Months Ended
	30, 2016		12, 2016			September 30, 2015
Equity-classified awards	$	—	$	1,511		$	3,369
Liability-classified awards	—		(19		)	(686		)
	$	—	$	1,492		$	2,683

The equity-classified share-based compensation expense for the Predecessor periods from July 1, 2016 and January 1, 2016, each through September 12, 2016, include an adjustment of $5.3 million to correct for an error that occurred in the reporting of equity-classified share-based compensation expense for the three months ended June 30, 2016. We have assessed the quantitative and qualitative factors with respect to this error as well as the effect of the correcting adjustment being recorded in the Predecessor period from July 1, 2016 through September 12, 2016 and determined that the amount and timing of the adjustment is not material to the Condensed Consolidated Financial Statements taken as a whole for any of the subject periods.

The substance of the error was attributable to the accounting for the voluntary cancellation of certain restricted stock unit awards that were scheduled to vest immediately prior to the Petition Date. While we believe the dollar amount of the error is not insignificant, the non-cash nature of the underlying compensation expense and the overall variability of all of our share-based compensation awards as a component of general and administrative expenses are factors to which we gave strong consideration in our assessment. In general and specifically in the industry in which we operate, non-cash share-based compensation expense is generally viewed independently of traditional cash-based general and administrative expenses. Accordingly, significant variability of such expense in any discrete period is not indicative of a trend in general and administrative expenses that would influence a user of our financial statements. Furthermore, the Condensed Consolidated Financial Statements that included the original error were issued approximately two and one-half months after we entered bankruptcy. Accordingly, we do not believe that the error which occurred within and was subsequently corrected in a sequential Predecessor period would influence any current users of our financial statements as the subject compensations plans were ultimately canceled and we are a substantially different company, particularly with respect to total employee headcount, as the Successor from an overall general and administrative cost perspective.

Other Benefit Plans

We maintain the Penn Virginia Corporation and Affiliated Companies Employees 401(k) Plan (the “401(k) Plan”), a defined contribution plan, which covers substantially all of our employees. We recognized $0.4 million for the period January 1, 2016 through September 12, 2016, less then $0.1 million for the period September 13, 2016 through September 30, 2016 and $0.6 million of expense attributable the 401(k) Plan for the nine months ended September 30, 2015.

We maintain unqualified legacy defined benefit pension and defined benefit postretirement plans that cover a limited number of former employees, all of whom retired prior to 2000. The combined expense recognized with respect to these plans was less than $0.1 million for the period January 1, 2016 through September 12, 2016, less than $0.1 million for the period September 13, 2016 through September 30, 2016 and $0.1 million for the nine months ended September 30, 2015.

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Interest Expense

9 Months Ended

Sep. 30, 2016

Banking and Thrift [Abstract]

Interest Expense

Interest Expense

The following tables summarize the components of interest expense for the periods presented:

	Successor		Predecessor
	Period from September 13, 2016		Period from July 1, 2016		Three Months Ended
	through September 30, 2016		through September 12, 2016		September 30, 2015
Interest on borrowings and related fees 1	$	180	$	1,363	$	23,239
Amortization of debt issuance costs	38		—		1,224
Capitalized interest	—		—		(1,478		)
	$	218	$	1,363	$	22,985

_______________________

¹ Absent the bankruptcy proceedings and the corresponding suspension of the accrual of interest on unsecured debt, we would have recorded total contractual interest expense of $19.3 million for the period July 1, 2016 through September 12, 2016, including $4.4 million attributable to the 2019 Senior Notes and $13.4 million attributable to the 2020 Senior Notes.

	Successor		Predecessor
	Period from September 13, 2016		Period from January 1, 2016			Nine Months Ended
	through September 30, 2016		through September 12, 2016			September 30, 2015
Interest on borrowings and related fees 2	$	180	$	36,013		$	69,371
Amortization of debt issuance costs 3	38		22,188			3,504
Capitalized interest	—		(183		)	(4,854		)
	$	218	$	58,018		$	68,021

	Successor		Predecessor
	Period from September 13, 2016		Period from January 1, 2016			Nine Months Ended
	through September 30, 2016		through September 12, 2016			September 30, 2015
Interest on borrowings and related fees 2	$	180	$	36,013		$	69,371
Amortization of debt issuance costs 3	38		22,188			3,504
Capitalized interest	—		(183		)	(4,854		)
	$	218	$	58,018		$	68,021

_______________________

² Absent the bankruptcy proceedings and the corresponding suspension of the accrual of interest on unsecured debt, we would have recorded total contractual interest expense of $66.1 million for the period from January 1, 2016 through September 12, 2016, including $15.3 million attributable to the 2019 Senior Notes and $46.3 million attributable to the 2020 Senior Notes.

³ Includes$20.5 million related to the accelerated write-off of unamortized debt issuance costs associated with the RBL and Senior Notes (see Note 8).

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Earnings (Loss) per Share

9 Months Ended

Sep. 30, 2016

Earnings Per Share [Abstract]

Earnings (Loss) per Share

Earnings (Loss) per Share

The following tables provide a reconciliation of the components used in the calculation of basic and diluted earnings per share for the periods presented:

	Successor			Predecessor
	Period from September 13,			Period from July 1,
	2016 through September			2016 through September		Three Months Ended
	30, 2016			12, 2016		9/30/2015
Net (loss) income	$	(3,441	)	$	1,150,055	$	25,900
Less: Preferred stock dividends	—			—		$	(5,935	)
Net (loss) income attributable to common shareholders – basic	$	(3,441	)	$	1,150,055	$	19,965
Add: Preferred stock dividends	—			—		5,935
Net (loss) income attributable to common shareholders – diluted	$	(3,441	)	$	1,150,055	$	25,900
Weighted-average shares – basic	14,992			89,292		72,651
Effect of dilutive securities	—			22,166		30,801
Weighted-average shares – diluted	14,992			111,458		103,452

	Successor			Predecessor
	Period from September 13,			Period from January 1,
	2016 through September			2016 through September			Nine Months Ended
	30, 2016			12, 2016			2015
Net (loss) income	$	(3,441	)	$	1,054,602		$	(111,394	)
Less: Preferred stock dividends 1	—			(5,972		)	(18,069		)
Net (loss) income attributable to common shareholders – basic and diluted	$	(3,441	)	$	1,048,630		$	(129,463	)
Weighted-average shares – basic	14,992			88,013			72,438
Effect of dilutive securities 2	—			36,074			—
Weighted-average shares – diluted	14,992			124,087			72,438

_______________________

¹ Preferred stock dividends were excluded from the computation of diluted earnings (loss) per share for the period January 1, 2016 through September 12, 2016 and the nine months ended September 30, 2015, as the assumed conversion of the outstanding preferred stock would have been anti-dilutive.

² For the nine months ended September 30, 2015, approximately 31.1 million of potentially dilutive securities, including the Series A Preferred Stock and Series B Preferred Stock, stock options and restricted stock units, had the effect of being anti-dilutive and were excluded from the calculation of diluted earnings (loss) per common share.

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Basis of Presentation (Policies)

9 Months Ended

Sep. 30, 2016

Schedule of Policies [Line Items]

New Accounting Pronouncements

Recently Adopted Accounting Pronouncements

In March 2016, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”)2016–09, Improvements to Employee Share-based Payment Accounting (“ASU 2016–09”), which simplifies the accounting for share-based compensation. The areas for simplification that are applicable to publicly-held companies are as follows: (i) Accounting for Income Taxes, (ii) Classification of Excess Tax Benefits on the Statement of Cash Flows, (iii) Forfeitures, (iv) Minimum Statutory Tax Withholding Requirements and (v) Classification of Employee Taxes Paid on the Statement of Cash Flows when an employer withholds shares for tax-withholding purposes. The effective date of ASU 2016–09 is January 1, 2017, with early adoption permitted. We adopted ASU 2016–09 on September 12, 2016 effective upon our emergence from bankruptcy. As of September 30, 2016, we did not have any awards issued in the form of share-based compensation. Accordingly, the adoption of ASU 2016–09 had no impact on our Condensed Consolidated Financial Statements and Notes.

Recently Issued Accounting Pronouncements

In June 2016, the FASB issued ASU 2016–13, Measurement of Credit Losses on Financial Instruments (“ASU 2016–13”), which changes the recognition model for the impairment of financial instruments, including accounts receivable, loans and held-to-maturity debt securities, among others. ASU 2016–13 is required to be adopted using the modified retrospective method by January 1, 2020, with early adoption permitted. ASU 2016–13 will have applicability to our accounts receivable portfolio, particularly those receivables attributable to our joint interest partners. At this time, we do not anticipate that the adoption of ASU 2016–13 will have a significant impact on our Consolidated Financial Statements and related disclosures; however, we are currently in the early stages of evaluating the requirements and the period for which we will adopt the standard.

In February 2016, the FASB issued ASU 2016–02, Leases (“ASU 2016–02”), which will require organizations that lease assets to recognize on the balance sheet the assets and liabilities for the rights and obligations created by those leases with terms of more than twelve months. Consistent with current U.S. GAAP, the recognition, measurement, and presentation of expenses and cash flows arising from a lease by a lessee primarily will depend on its classification as a finance or operating lease. ASU 2016–02 also will require disclosures regarding the amount, timing, and uncertainty of cash flows arising from leases. The effective date of ASU 2016–02 is January 1, 2019, with early adoption permitted. We are continuing to evaluate the effect that ASU 2016–02 will have on our Consolidated Financial Statements and related disclosures as well as the period for which we will adopt the standard. We believe that ASU 2016–02 will likely be applicable to our oil and natural gas gathering commitment arrangements as described in Note 13, our existing leases for office facilities and certain office equipment and potentially to certain drilling rig contracts with terms in excess of twelve months.

In May 2014, the FASB issued ASU 2014–09, Revenues from Contracts with Customers (“ASU 2014–09”), which requires an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. ASU 2014–09 will replace most existing revenue recognition guidance in U.S. GAAP when it becomes effective on January 1, 2018. The standard permits the use of either the retrospective or cumulative effect transition method upon adoption. While traditional commodity sales transactions, property conveyances and joint interest arrangements in the oil and gas industry are not expected to be significantly impacted by ASU 2014–09, natural gas imbalances and other non-product revenues, including our ancillary marketing, gathering and transportation and water service revenues could be affected. Accordingly, we are continuing to evaluate the effect that ASU 2014–09 will have on our Consolidated Financial Statements and related disclosures, with a more focused analysis on these other revenue sources. We have not yet selected a transition method nor have we determined the period for which we will adopt the new standard.

Basis of Presentation

Basis of Presentation

Our unaudited Condensed Consolidated Financial Statements include the accounts of Penn Virginia and all of our subsidiaries. Intercompany balances and transactions have been eliminated. Our Condensed Consolidated Financial Statements have been prepared in conformity with accounting principles generally accepted in the United States of America (“U.S. GAAP”). Preparation of these statements involves the use of estimates and judgments where appropriate. In the opinion of management, all adjustments, consisting of normal recurring accruals, considered necessary for a fair presentation of our Condensed Consolidated Financial Statements have been included. Our Condensed Consolidated Financial Statements should be read in conjunction with the Consolidated Financial Statements and Notes included in our Annual Report on Form 10-K for the year ended December 31, 2015. Operating results for the nine months ended September 30, 2016, are not necessarily indicative of the results that may be expected for the year ending December 31, 2016. Certain amounts for the corresponding 2015 periods have been reclassified to conform to the current year presentation. These reclassifications have no impact on our previously reported results of operations, balance sheets or cash flows.

Management has evaluated all of our activities through the issuance date of our Condensed Consolidated Financial Statements and has concluded that no subsequent events have occurred that would require recognition in our Condensed Consolidated Financial Statements or disclosure in the Notes thereto.

Comparability of Financial Statements to Prior Periods

As discussed in further detail in Note 4 below, we have adopted and applied the relevant guidance provided in U.S. GAAP with respect to the accounting and financial statement disclosures for entities that have emerged from bankruptcy proceedings (“Fresh Start Accounting”). Accordingly, our Condensed Consolidated Financial Statements and Notes after September 12, 2016, are not comparable to the Condensed Consolidated Financial Statements and Notes prior to that date. To facilitate our financial statement presentations, we refer to the reorganized company in these Condensed Consolidated Financial Statements and Notes as the “Successor” for periods subsequent to September 12, 2016, and “Predecessor” for periods prior to September 13, 2016. Furthermore, our Condensed Consolidated Financial Statements and Notes have been presented with a “black line” division to delineate the lack of comparability between the Predecessor and Successor. In addition, and as referenced in Note 7 below, we have adopted the full cost method of accounting for our oil and gas properties effective with our adoption of Fresh Start Accounting. Accordingly, our results of operations and financial position for the Successor periods will be substantially different from our historic trends.

We have applied the relevant guidance provided in U.S. GAAP with respect to the accounting and financial statement disclosures for entities that have filed petitions with the bankruptcy court and expect to reorganize as going concerns in preparing our Condensed Consolidated Financial Statements and Notes through the period ended September 12, 2016, or Predecessor periods. That guidance requires that, for periods subsequent to our bankruptcy filing on May 12, 2016, or post-petition periods, certain transactions and events that were directly related to our reorganization be distinguished from our normal business operations. Accordingly, certain revenues, expenses, realized gains and losses and provisions that were realized or incurred in the bankruptcy proceedings have been included in “Reorganization items, net” on our Condensed Consolidated Statement of Operations for the period ended September 12, 2016. In addition, certain liabilities and other obligations incurred prior to May 12, 2016, or pre-petition periods, have been classified in “Liabilities subject to compromise” on our Predecessor Condensed Consolidated Balance Sheet through September 12, 2016. Further detail for our “Reorganization items, net” and “Liabilities subject to compromise” are provided in Note 4 below.

Going Concern Presumption

Our unaudited Condensed Consolidated Financial Statements for the Successor periods have been prepared on a going concern basis, which contemplates the realization of assets and the satisfaction of liabilities and other commitments in the normal course of business. As referenced in Note 3 below, we operated as a “debtor-in-possession” through September 12, 2016, during which time there was inherent doubt as to our ability to continue as a going concern.

Recently Adopted Accounting Pronouncements

In March 2016, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”)2016–09, Improvements to Employee Share-based Payment Accounting (“ASU 2016–09”), which simplifies the accounting for share-based compensation. The areas for simplification that are applicable to publicly-held companies are as follows: (i) Accounting for Income Taxes, (ii) Classification of Excess Tax Benefits on the Statement of Cash Flows, (iii) Forfeitures, (iv) Minimum Statutory Tax Withholding Requirements and (v) Classification of Employee Taxes Paid on the Statement of Cash Flows when an employer withholds shares for tax-withholding purposes. The effective date of ASU 2016–09 is January 1, 2017, with early adoption permitted. We adopted ASU 2016–09 on September 12, 2016 effective upon our emergence from bankruptcy. As of September 30, 2016, we did not have any awards issued in the form of share-based compensation. Accordingly, the adoption of ASU 2016–09 had no impact on our Condensed Consolidated Financial Statements and Notes.

Recently Issued Accounting Pronouncements

In June 2016, the FASB issued ASU 2016–13, Measurement of Credit Losses on Financial Instruments (“ASU 2016–13”), which changes the recognition model for the impairment of financial instruments, including accounts receivable, loans and held-to-maturity debt securities, among others. ASU 2016–13 is required to be adopted using the modified retrospective method by January 1, 2020, with early adoption permitted. ASU 2016–13 will have applicability to our accounts receivable portfolio, particularly those receivables attributable to our joint interest partners. At this time, we do not anticipate that the adoption of ASU 2016–13 will have a significant impact on our Consolidated Financial Statements and related disclosures; however, we are currently in the early stages of evaluating the requirements and the period for which we will adopt the standard.

In February 2016, the FASB issued ASU 2016–02, Leases (“ASU 2016–02”), which will require organizations that lease assets to recognize on the balance sheet the assets and liabilities for the rights and obligations created by those leases with terms of more than twelve months. Consistent with current U.S. GAAP, the recognition, measurement, and presentation of expenses and cash flows arising from a lease by a lessee primarily will depend on its classification as a finance or operating lease. ASU 2016–02 also will require disclosures regarding the amount, timing, and uncertainty of cash flows arising from leases. The effective date of ASU 2016–02 is January 1, 2019, with early adoption permitted. We are continuing to evaluate the effect that ASU 2016–02 will have on our Consolidated Financial Statements and related disclosures as well as the period for which we will adopt the standard. We believe that ASU 2016–02 will likely be applicable to our oil and natural gas gathering commitment arrangements as described in Note 13, our existing leases for office facilities and certain office equipment and potentially to certain drilling rig contracts with terms in excess of twelve months.

In May 2014, the FASB issued ASU 2014–09, Revenues from Contracts with Customers (“ASU 2014–09”), which requires an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. ASU 2014–09 will replace most existing revenue recognition guidance in U.S. GAAP when it becomes effective on January 1, 2018. The standard permits the use of either the retrospective or cumulative effect transition method upon adoption. While traditional commodity sales transactions, property conveyances and joint interest arrangements in the oil and gas industry are not expected to be significantly impacted by ASU 2014–09, natural gas imbalances and other non-product revenues, including our ancillary marketing, gathering and transportation and water service revenues could be affected. Accordingly, we are continuing to evaluate the effect that ASU 2014–09 will have on our Consolidated Financial Statements and related disclosures, with a more focused analysis on these other revenue sources. We have not yet selected a transition method nor have we determined the period for which we will adopt the new standard.

Fair Value Measurements

We apply the authoritative accounting provisions for measuring fair value of both our financial and nonfinancial assets and liabilities. Fair value is an exit price representing the expected amount we would receive upon the sale of an asset or that we would expect to pay to transfer a liability in an orderly transaction with market participants at the measurement date.

Fair Value, Measurements, Recurring

Schedule of Policies [Line Items]

Fair Value Measurements

We used the following methods and assumptions to estimate fair values for the financial assets and liabilities described below:

• Commodity derivatives: We determine the fair values of our commodity derivative instruments based on discounted cash flows derived from third-party quoted forward prices for West Texas Intermediate crude oil and NYMEX Henry Hub gas closing prices as of the end of the reporting periods. We generally use the income approach, using valuation techniques that convert future cash flows to a single discounted value. Each of these is a level 2 input.

• Assets of SERP: We held various publicly traded equity securities in a Rabbi Trust as assets for funding certain deferred compensation obligations. The fair values were based on quoted market prices, which are level 1 inputs.

• Deferred compensation – SERP obligations: Certain of our deferred compensation obligations were ultimately to be settled in cash based on the underlying fair value of certain assets, including those held in the Rabbi Trust. The fair values were based on quoted market prices, which are level 1 inputs.

Fair Value, Measurements, Nonrecurring

Schedule of Policies [Line Items]

Fair Value Measurements

Non-Recurring Fair Value Measurements

The most significant non-recurring fair value measurements utilized in the preparation of our Condensed Consolidated Financial Statements are those attributable to the recognition and measurement of the Successor's net assets with respect to the application of Fresh Start Accounting. Those measurements are more fully described in Note 4. In addition, we utilize non-recurring fair value measurements with respect to the recognition and measurement of asset impairments, particularly during our Predecessor periods during which time we applied the successful efforts method to our oil and gas properties, as well as the initial determination of AROs associated with the ongoing development of new oil and gas properties.

The factors used to determine fair value for purposes of recognizing and measuring asset impairments while we applied the successful efforts method to our oil and gas properties during our Predecessor periods included, but were not limited to, estimates of proved and risk-adjusted probable reserves, future commodity prices, indicative sales prices for properties, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties. Under the full cost method, we apply a ceiling test determination utilizing prescribed procedures as described in Note 7. The full cost method is substantially different from the successful efforts method which relies upon fair value measurements. Because these significant fair value inputs were typically not observable, we have categorized the amounts as level 3 inputs.

The determination of the fair value of AROs is based upon regional market and facility specific information. The amount

of an ARO and the costs capitalized represent the estimated future cost to satisfy the abandonment obligation using current

prices that are escalated by an assumed inflation factor after discounting the future cost back to the date that the abandonment

obligation was incurred using a rate commensurate with the risk, which approximates our cost of funds. Because these

significant fair value inputs are typically not observable, we have categorized the initial estimates as level 3 inputs.

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Property, Plant and Equipment DD&A (Policies)

9 Months Ended

Sep. 30, 2016

Accounting Policies [Abstract]

Depreciation, Depletion, and Amortization [Policy Text Block]

The following describes our accounting policies with respect to our oil and gas properties and equipment:

Under the full cost method of accounting for oil and gas properties, all costs incurred in the exploration, development and acquisition of oil and gas reserves are capitalized. Such costs may be incurred both prior to and after the acquisition of a property and include lease acquisitions, geological and geophysical, or seismic, drilling, completion and equipment costs. Internal costs incurred that are directly attributable to exploration, development and acquisition activities undertaken by us for our own account, and which are not attributable to production, general corporate overhead or similar activities are also capitalized.

Depreciation, depletion and amortization (“DD&A”) of our oil and gas properties is computed using the units-of-production method. We apply this method by multiplying the unamortized cost of our proved oil and gas properties, net of estimated salvage plus future development costs, by a rate determined by dividing the physical units of oil and gas produced during the period by the total estimated units of proved oil and gas reserves at the beginning of the period.

At the end of each quarterly reporting period, the unamortized cost of our oil and gas properties, net of deferred income taxes, is limited to the sum of the estimated discounted future net revenues from proved properties adjusted for costs excluded from amortization and related income taxes (“Ceiling Test”). The estimated discounted future net revenues are determined using the prior 12-month’s average price based on closing prices on the first day of each month, adjusted for differentials, discounted at 10%. The calculation of the Ceiling Test and provision for DD&A are based on estimates of proved reserves. There are significant uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production, timing and plan of development.

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Fresh Start Accounting Fresh Start Accounting (Tables)

8 Months Ended

Sep. 12, 2016

Fresh-Start Balance Sheet [Abstract]

Schedule of Cumulative impact of Reorganization Adjustments [Table Text Block]

11. Represents the cumulative impact of the reorganization adjustments described above:

Gain on settlement of of liabilities subject to compromise		$	1,150,248
Fair value of equity allocated to:
Unsecured creditors on the Effective Date	174,477
Unsecured creditors pending resolution on the Effective Date	10,396
Backstop Parties in the form of a Commitment Premium	6,022
		190,895
Cancellation of Predecessor shareholders’ deficit		882,992
Net impact to Predecessor accumulated deficit		$	2,224,135

Reconcile Enterprise Value to FV of Successor CS [Table Text Block]

The following table reconciles the enterprise value, net of cash and cash equivalents, to the estimated fair value of our Successor common stock as of the Effective Date:

Enterprise value	$	234,831
Plus: Cash and cash equivalents	31,414
Less: Fair value of debt	(75,350		)
Fair value of Successor common stock	$	190,895
Shares outstanding as of September 12, 2016	14,992,018
Per share value	$	12.73

Reconciliation of Enterprise Value to Reorganization Value [Table Text Block]

The following table reconciles the enterprise value to the reorganization value of our Successor assets as of the Effective Date:

Enterprise value	$	234,831
Plus: Cash and cash equivalents	31,414
Plus: Current liabilities	54,171
Plus: Noncurrent liabilities excluding long-term debt	13,558
Reorganization value	$	333,974

Schedule of Fresh-Start Adjustments [Table Text Block]

The following table reflects the reorganization and application of Fresh Start Accounting adjustments on our Condensed Consolidated Balance Sheet as of September 12, 2016:

						Reorganization					Fresh Start
			Predecessor			Adjustments					Adjustments					Successor
Assets
Current assets
	Cash and cash equivalents		$	48,718		$	(17,304	)	(1	)	$	—				$	31,414
	Accounts receivable, net of allowance for doubtful accounts		35,606			4,292			(2	)	—					39,898
	Derivative assets		397			—					—					397
	Other current assets		3,966			(832		)	(3	)	—					3,134
		Total current assets	88,687			(13,844		)			—					74,843
Property and equipment, net			309,261			—					(55,751		)	(12	)	253,510
Other assets			6,902			(1,281		)	(4	)	—					5,621
		Total assets	$	404,850		$	(15,125	)			$	(55,751	)			$	333,974
Liabilities and Shareholders’ Deficit
Current liabilities
	Accounts payable and accrued liabilities		$	77,151		$	(21,166	)	(5	)	$	(3,455	)	(13	)	$	52,530
	Derivative liabilities		1,641			—					—					1,641
	Current maturities of long-term debt		113,653			(113,653		)	(6	)	—					—
		Total current liabilities	192,445			(134,819		)			(3,455		)			54,171
Other liabilities			84,953			100			(5	)	(80,615		)	(14	)	4,438
Derivative liabilities			9,120			—					—					9,120
Long-term debt			—			75,350			(7	)	—					75,350
Liabilities subject to compromise			1,154,163			(1,154,163		)	(8	)	—					—
Shareholders’ equity (deficit)
	Preferred stock (Predecessor)		1,880			(1,880		)	(9	)	—					—
	Common stock (Predecessor)		697			(697		)	(9	)	—					—
	Paid-in capital (Predecessor)		1,213,797			(1,213,797		)	(9	)	—					—
	Deferred compensation obligation (Predecessor)		3,440			(3,440		)	(9	)	—					—
	Accumulated other comprehensive income (Predecessor)		383			(383		)	(9	)	—					—
	Treasury stock (Predecessor)		(3,574		)	3,574			(9	)	—					—
	Common stock (Successor)		—			150			(10	)	—					150
	Paid-in capital (Successor)		—			190,745			(10	)	—					190,745
	Accumulated deficit		(2,252,454		)	2,224,135			(11	)	28,319			(15	)	—
		Total shareholders’ equity (deficit)	(1,035,831		)	1,198,407					28,319					190,895
		Total liabilities and shareholders’ equity (deficit)	$	404,850		$	(15,125	)			$	(55,751	)			$	333,974

Schedule of Net Cash Payments [Table Text Block]

1. Represents the net cash payments that occurred on the Effective Date:

Sources:
Proceeds from the Revolver	$	75,350
Proceeds from the Rights Offering, net of issuance costs	49,943
Total sources			$	125,293
Uses:
Repayment of RBL	$	113,653
Accrued interest payable on RBL	1,374
DIP Facility fees	12
Debt issue costs of the Revolver	3,011
Funding of professional fee escrow account	14,575
RBL lender professional fees and expenses	455
Ad Hoc Committee and indenture trustee professional fees and expenses	6,782
Payment of certain allowed claims and settlements	2,735
Total uses			142,597
			$	(17,304	)

Liabilities Subject to Compromise, Period Increase (Decrease)

8. Liabilities subject to compromise were settled as follows in accordance with the Plan:

Liabilities subject to compromise prior to the Effective Date:
Senior Notes	$	1,075,000
Interest on Senior Notes	47,213
Firm transportation obligation	11,077
Compensation – related	9,733
Deferred compensation	4,676
Trade accounts payable	1,487
Litigation claims	1,092
Other accrued liabilities	3,885
			$	1,154,163
Amounts settled in cash, reinstated or otherwise reserved at emergence			(3,915		)
Gain on settlement of liabilities subject to compromise			$	1,150,248

Schedule of Reorganization Items [Table Text Block]

The following table summarizes the components included in “Reorganization items, net” in our Condensed Consolidated Statements of Operations for the periods presented:

	July 1 through			January 1 through
	September 12,			September 12,
	2016			2016
Gains on the settlement of liabilities subject to compromise	$	1,150,248		$	1,150,248
Fresh start accounting adjustments	28,319			28,319
Legal and professional fees and expenses	(22,739		)	(29,976		)
Settlements attributable to contract amendments	(2,550		)	(2,550		)
DIP Facility costs and commitment fees	(27		)	(170		)
Write-off of prepaid directors and officers insurance	(832		)	(832		)
Other reorganization items	(46		)	(46		)
	$	1,152,373		$	1,144,993

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Accounts Receivable and Major Customers (Tables)

9 Months Ended

Sep. 30, 2016

Receivables [Abstract]

Summary of Accounts Receivable

The following table summarizes our accounts receivable by type as of the dates presented:

	Successor			Predecessor
	September 30,			December 31,
	2016			2015
Customers	$	19,221		$	23,481
Joint interest partners	8,201			18,381
Other 1	7,158			7,658
	34,580			49,520
Less: Allowance for doubtful accounts	(2,443		)	(1,555		)
	$	32,137		$	47,965

_______________________

¹ Includes amounts owed to us from joint venture partners for acquisitions in prior periods, severance tax refunds approved by state taxing authorities to be returned to us and other miscellaneous non-operating items. The balance as of September 30, 2016 also includes a $4.3 million receivable from the trustee of the SERP for the reversion of plan assets to the Successor.

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Derivative Instruments (Tables)

9 Months Ended

Sep. 30, 2016

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Commodity Derivative Positions

The following table sets forth our commodity derivative positions as of September 30, 2016:

		Average
		Volume Per	Weighted Average Price			Fair Value
	Instrument	Day	Floor/Swap		Ceiling	Asset		Liability
Crude Oil:		(barrels)	($/barrel)
Fourth quarter 2016	Swaps	5,940	$	47.69		$	—	$	709
First quarter 2017	Swaps	4,408	$	48.62		—		737
Second quarter 2017	Swaps	4,408	$	48.62		—		1,106
Third quarter 2017	Swaps	4,408	$	48.62		—		1,335
Fourth quarter 2017	Swaps	4,408	$	48.62		—		1,518
First quarter 2018	Swaps	3,476	$	49.12		—		1,131
Second quarter 2018	Swaps	3,476	$	49.12		—		1,244
Third quarter 2018	Swaps	3,476	$	49.12		—		1,353
Fourth quarter 2018	Swaps	3,476	$	49.12		—		1,451
First quarter 2019	Swaps	2,916	$	49.90		—		1,051
Second quarter 2019	Swaps	2,916	$	49.90		—		1,117
Third quarter 2019	Swaps	2,916	$	49.90		—		1,179
Fourth quarter 2019	Swaps	2,916	$	49.90		—		1,247

Impact of Derivative Activities on Condensed Consolidated Statements of Income

The impact of our derivative activities on income is included in “Derivatives” in our Condensed Consolidated Statements of Operations. The following tables summarize the effects of our derivative activities for the periods presented:

	Successor			Predecessor
	Period From September 13, 2016			Period from July 1, 2016		Three Months Ended
	Through September 30, 2016			through September 12, 2016		September 30, 2015
Derivative gains (losses)	$	(4,369	)	$	8,934	$	44,701

	Successor			Predecessor
	Period From September 13, 2016			Period From January 1, 2016			Nine Months Ended
	Through September 30, 2016			Through September 12, 2016			September 30, 2015
Derivative gains (losses)	$	(4,369	)	$	(8,333	)	$	52,073

Fair Value of Derivative Instruments on Condensed Consolidated Balance Sheets

The following table summarizes the fair values of our derivative instruments, as well as the locations of these instruments on our Condensed Consolidated Balance Sheets as of the dates presented:

		Successor				Predecessor
		Fair Values as of
		September 30, 2016				December 31, 2015
		Derivative		Derivative		Derivative		Derivative
Type	Balance Sheet Location	Assets		Liabilities		Assets		Liabilities
Commodity contracts	Derivative assets/liabilities – current	$	446	$	3,888	$	97,956	$	—
Commodity contracts	Derivative assets/liabilities - noncurrent	—		11,291		—		—
		$	446	$	15,179	$	97,956	$	—

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Property and Equipment (Tables)

9 Months Ended

Sep. 30, 2016

Property, Plant and Equipment [Abstract]

Summary of Property and Equipment

The following table summarizes our property and equipment as of the dates presented: 

	Successor			Predecessor
	September 30,			December 31,
	2016			2015
Oil and gas properties:
Proved	$	241,308		$	2,678,415
Unproved	8,338			6,881
Total oil and gas properties	249,646			2,685,296
Other property and equipment	3,574			31,365
Total properties and equipment	253,220			2,716,661
Accumulated depreciation, depletion and amortization	(2,020		)	(2,372,266		)
	$	251,200		$	344,395

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Long-Term Debt (Tables)

9 Months Ended

Sep. 30, 2016

Debt Disclosure [Abstract]

Carrying Amount of Components of Long-term Debt

The following table summarizes our debt obligations as of the dates presented:

	Successor				Predecessor
	September 30, 2016				December 31, 2015
	Principal		Unamortized Issuance Costs 1		Principal			Unamortized Issuance Costs 1
Revolving credit facility 2	$	54,350			$	—
Pre-petition revolving credit facility 3	—				170,000
Senior notes due 2019	—		$	—	300,000			$	3,295
Senior notes due 2020	—		—		775,000			17,322
Totals	54,350		$	—	1,245,000			$	20,617
Less: Unamortized issuance costs	—				(20,617		)
Less: Amounts classified as current	—				(1,224,383		)
Long-term debt, net of unamortized issuance costs	$	54,350			$	—

____________________

¹ Issuance costs attributable to the Senior Notes were subject to an accelerated write-off in advance of our bankruptcy filing during the three months ended June 30, 2016.

² Issuance costs attributable to the Revolver, which represent costs attributable to the access to credit over the Revolver’s contractual term, have been presented as a component of Other assets (see Note 11).

³ Issuance costs attributable to the RBL were presented as a component of Other assets (see Note 11) prior to the accelerated write-off in advance of our bankruptcy filing during the three months ended June 30, 2016.

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Additional Balance Sheet Detail (Tables)

9 Months Ended

Sep. 30, 2016

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Components of Selected Balance Sheet Accounts

The following table summarizes components of selected balance sheet accounts as of the dates presented:

	Successor		Predecessor
	September 30,		December 31,
	2016		2015
Other current assets:
Tubular inventory and well materials	$	2,154	$	2,878
Prepaid expenses	1,357		4,184
Other	7		42
	$	3,518	$	7,104
Other assets:
Assets of SERP 1	$	—	$	4,123
Deferred issuance costs of the revolving credit facilities 2	2,973		1,572
Other	2,598		2,655
	$	5,571	$	8,350
Accounts payable and accrued liabilities:
Trade accounts payable	$	7,926	$	11,603
Drilling costs	1,475		12,074
Royalties and revenue – related	28,203		39,119
Compensation – related	2,164		9,904
Interest	125		15,531
Other	5,539		15,294
	$	45,432	$	103,525
Other liabilities:
Deferred gains on sales of assets	$	—	$	82,943
Firm transportation obligation	—		10,705
Asset retirement obligations	2,696		2,621
Defined benefit pension obligations	1,132		1,129
Postretirement health care benefit obligations	523		731
Compensation – related	—		1,447
Deferred compensation – SERP obligations and other	—		4,434
Other	100		928
	$	4,451	$	104,938

_______________________

¹ In connection with our emergence from bankruptcy, the assets of the SERP reverted to us upon the release of claims by our employees attributable to certain deferred compensation arrangements in September 2016. The SERP assets were liquidated by the plan trustee in November 2016 and the cash value was transferred to us (see Notes 3, 4 and 5).

² The balance as of September 30, 2016 includes those costs, net of amortization, attributable to the Revolver. Deferred issuance costs attributable to the RBL, which represents the amounts outstanding as of December 31, 2015, were charged in full to interest expense during the three months ended June 30, 2016 in advance of our Chapter 11 filing.

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Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2016

Fair Value Disclosures [Abstract]

Fair Value Summary of Long-Term Debt with Fixed Interest Rates

The following table summarizes the fair value of our debt obligations with fixed interest rates, which is estimated based on the published market prices for these financial liabilities, as of the dates presented:

	Successor				Predecessor
	September 30, 2016				December 31, 2015
	Fair Value		Carrying Value		Fair Value		Carrying Value
Senior Notes due 2019 1	$	—	$	—	$	40,830	$	300,000
Senior Notes due 2020 1	—		—		125,473		775,000
	$	—	$	—	$	166,303	$	1,075,000

______________________

¹ The Senior Notes were canceled upon our emergence from bankruptcy.

Assets and Liabilities Measured at Fair Value on Recurring Basis

The following tables summarize the valuation of those assets and liabilities as of the dates presented:

	Successor As of September 30, 2016
	Fair Value			Fair Value Measurement Classification
Description	Measurement			Level 1		Level 2			Level 3
Assets:
Commodity derivative assets – current	$	446		$	—	$	446		$	—
Assets of SERP 1	4,292			4,292		—			—
Liabilities:
Commodity derivative liabilities – current	(3,888		)	—		(3,888		)	—
Commodity derivative liabilities – noncurrent	(11,291		)	—		(11,291		)	—

______________________

¹ In connection with our emergence from bankruptcy, the assets of the SERP reverted to us upon the release of claims by our employees attributable to certain deferred compensation arrangements in September 2016. The SERP assets were liquidated by the plan trustee in October 2016 and the cash value, which was included in accounts receivable as of September 30, 2016, was transferred to us for general corporate purposes.

	Predecessor As of December 31, 2015
	Fair Value			Fair Value Measurement Classification
Description	Measurement			Level 1			Level 2		Level 3
Assets:
Commodity derivative assets – current	$	97,956		$	—		$	97,956	$	—
Assets of SERP	4,123			4,123			—		—
Liabilities:
Deferred compensation – SERP obligations	(4,125		)	(4,125		)	—		—

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Shareholders' Equity (Tables)

9 Months Ended

Sep. 30, 2016

Equity [Abstract]

Schedule of Stockholders Equity

The following tables summarize the components of our shareholders’ equity (deficit) and the changes therein as of and for the Predecessor period from December 31, 2015, through September 12, 2016 and the Successor period from September 13, 2016 through September 30, 2016:

																Accumulated
													Deferred			Other
	Preferred			Common			Paid-in			Accumulated			Compensation			Comprehensive			Treasury
	Stock 2			Stock 2			Capital 2			Deficit			Obligation			Income 3			Stock			Total
Balance, December 31, 2015 (Predecessor)	$	3,146		$	628		$	1,211,088		$	(2,130,271	)	$	3,440		$	422		$	(3,574	)	$	(915,121	)
Net Loss	—			—			—			1,054,602			—			—			—			1,054,602
All Other Changes 1	(1,266		)	69			2,709			—			—			(39		)	—			1,473
Balance, September 12, 2016 (Predecessor)	$	1,880		$	697		$	1,213,797		$	(1,075,669	)	$	3,440		$	383		$	(3,574	)	$	140,954
Cancellation of Predecessor equity	(1,880		)	(697		)	(1,213,797		)	1,075,669			(3,440		)	(383		)	3,574			(140,954		)
Balance, September 12, 2016 (Predecessor)	$	—		$	—		$	—		$	—		$	—		$	—		$	—		$	—
Issuance of Successor common stock - Rights Offering	$	—		$	76		$	49,867		$	—		$	—		$	—		$	—		$	49,943
Issuance of Successor common stock - Backstop Fee	—			5			9,054			—			—			—			—			9,059
Issuance of Successor common stock - exchange of claims	—			69			131,824			—			—			—			—			131,893
Balance, September 12, 2016 (Successor)	—			150			190,745			—			—			—			—			190,895
Net Loss	—			—			—			(3,441		)	—			—			—			(3,441		)
Balance, September 30, 2016 (Successor)	$	—		$	150		$	190,745		$	(3,441	)	$	—		$	—		$	—		$	187,454

_______________________

¹ Includes equity-classified share-based compensation of $(3,918) for the period January 1, 2016 through September 12, 2016. Share-based compensation awards that were outstanding on the Effective Date were canceled in connection with our emergence from bankruptcy.

² A total of 52 shares, or 5,159 depositary shares, of our Series A 6% Convertible Perpetual Preferred Stock (the “Series A Preferred Stock”) were converted into 85,982 shares of our common stock during the period January 1, 2016 through September 12, 2016. A total of 12,619 shares, or 1,261,850 depositary shares, of our Series B 6% Convertible Perpetual Preferred Stock (the “Series B Preferred Stock”) were converted into 6,879,222 shares of our common stock during the period January 1, 2016 through September 12, 2016. Preferred Stock was canceled in connection with our emergence from bankruptcy.

³ Accumulated other comprehensive income (“AOCI”) is entirely attributable to our defined benefit pension and postretirement health care plans. The changes in the balance of AOCI for the period January 1, 2016 through September 12, 2016, represent reclassifications from AOCI to net periodic benefit expense, a component of “General and administrative expenses,” of $(38).

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Share-Based Compensation (Tables)

9 Months Ended

Sep. 30, 2016

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Summary of Share-Based Compensation Expense

The following tables summarize our share-based compensation expense (benefit) recognized for the periods presented:

	Successor		Predecessor
	Period from September 13,		Period from July 1,
	2016 through September		2016 through September		Three Months Ended
	30, 2016		12, 2016		September 30, 2015
Equity-classified awards	$	—	$	5,433	$	1,263
Liability-classified awards	—		—		(851		)
	$	—	$	5,433	$	412

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Interest Expense (Tables)

9 Months Ended

Sep. 30, 2016

Banking and Thrift [Abstract]

Interest Expense Net Disclosure

	Successor		Predecessor
	Period from September 13, 2016		Period from January 1, 2016			Nine Months Ended
	through September 30, 2016		through September 12, 2016			September 30, 2015
Interest on borrowings and related fees 2	$	180	$	36,013		$	69,371
Amortization of debt issuance costs 3	38		22,188			3,504
Capitalized interest	—		(183		)	(4,854		)
	$	218	$	58,018		$	68,021

_______________________

² Absent the bankruptcy proceedings and the corresponding suspension of the accrual of interest on unsecured debt, we would have recorded total contractual interest expense of $66.1 million for the period from January 1, 2016 through September 12, 2016, including $15.3 million attributable to the 2019 Senior Notes and $46.3 million attributable to the 2020 Senior Notes.

³ Includes$20.5 million related to the accelerated write-off of unamortized debt issuance costs associated with the RBL and Senior Notes (see Note 8).

Interest Expense

Interest Expense

The following tables summarize the components of interest expense for the periods presented:

	Successor		Predecessor
	Period from September 13, 2016		Period from July 1, 2016		Three Months Ended
	through September 30, 2016		through September 12, 2016		September 30, 2015
Interest on borrowings and related fees 1	$	180	$	1,363	$	23,239
Amortization of debt issuance costs	38		—		1,224
Capitalized interest	—		—		(1,478		)
	$	218	$	1,363	$	22,985

_______________________

¹ Absent the bankruptcy proceedings and the corresponding suspension of the accrual of interest on unsecured debt, we would have recorded total contractual interest expense of $19.3 million for the period July 1, 2016 through September 12, 2016, including $4.4 million attributable to the 2019 Senior Notes and $13.4 million attributable to the 2020 Senior Notes.

	Successor		Predecessor
	Period from September 13, 2016		Period from January 1, 2016			Nine Months Ended
	through September 30, 2016		through September 12, 2016			September 30, 2015
Interest on borrowings and related fees 2	$	180	$	36,013		$	69,371
Amortization of debt issuance costs 3	38		22,188			3,504
Capitalized interest	—		(183		)	(4,854		)
	$	218	$	58,018		$	68,021

	Successor		Predecessor
	Period from September 13, 2016		Period from January 1, 2016			Nine Months Ended
	through September 30, 2016		through September 12, 2016			September 30, 2015
Interest on borrowings and related fees 2	$	180	$	36,013		$	69,371
Amortization of debt issuance costs 3	38		22,188			3,504
Capitalized interest	—		(183		)	(4,854		)
	$	218	$	58,018		$	68,021

_______________________

² Absent the bankruptcy proceedings and the corresponding suspension of the accrual of interest on unsecured debt, we would have recorded total contractual interest expense of $66.1 million for the period from January 1, 2016 through September 12, 2016, including $15.3 million attributable to the 2019 Senior Notes and $46.3 million attributable to the 2020 Senior Notes.

³ Includes$20.5 million related to the accelerated write-off of unamortized debt issuance costs associated with the RBL and Senior Notes (see Note 8).

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Earnings per Share (Tables)

9 Months Ended

Sep. 30, 2016

Earnings Per Share [Abstract]

Components of Calculation of Basic and Diluted Earnings Per Share

The following tables provide a reconciliation of the components used in the calculation of basic and diluted earnings per share for the periods presented:

	Successor			Predecessor
	Period from September 13,			Period from July 1,
	2016 through September			2016 through September		Three Months Ended
	30, 2016			12, 2016		9/30/2015
Net (loss) income	$	(3,441	)	$	1,150,055	$	25,900
Less: Preferred stock dividends	—			—		$	(5,935	)
Net (loss) income attributable to common shareholders – basic	$	(3,441	)	$	1,150,055	$	19,965
Add: Preferred stock dividends	—			—		5,935
Net (loss) income attributable to common shareholders – diluted	$	(3,441	)	$	1,150,055	$	25,900
Weighted-average shares – basic	14,992			89,292		72,651
Effect of dilutive securities	—			22,166		30,801
Weighted-average shares – diluted	14,992			111,458		103,452

	Successor			Predecessor
	Period from September 13,			Period from January 1,
	2016 through September			2016 through September			Nine Months Ended
	30, 2016			12, 2016			2015
Net (loss) income	$	(3,441	)	$	1,054,602		$	(111,394	)
Less: Preferred stock dividends 1	—			(5,972		)	(18,069		)
Net (loss) income attributable to common shareholders – basic and diluted	$	(3,441	)	$	1,048,630		$	(129,463	)
Weighted-average shares – basic	14,992			88,013			72,438
Effect of dilutive securities 2	—			36,074			—
Weighted-average shares – diluted	14,992			124,087			72,438

_______________________

¹ Preferred stock dividends were excluded from the computation of diluted earnings (loss) per share for the period January 1, 2016 through September 12, 2016 and the nine months ended September 30, 2015, as the assumed conversion of the outstanding preferred stock would have been anti-dilutive.

² For the nine months ended September 30, 2015, approximately 31.1 million of potentially dilutive securities, including the Series A Preferred Stock and Series B Preferred Stock, stock options and restricted stock units, had the effect of being anti-dilutive and were excluded from the calculation of diluted earnings (loss) per common share.

XML

Nature of Operations Nature of Operations (Details)	9 Months Ended
	Sep. 30, 2016
TEXAS | Eagle Ford Shale
Concentration Risk [Line Items]
Concentration risk, percentage (more than)	90.00%

XML

Basis of Presentation (Details) $ in Thousands	1 Months Ended	2 Months Ended	3 Months Ended	8 Months Ended	9 Months Ended
	Sep. 30, 2016 USD ($)	Sep. 12, 2016 USD ($)	Sep. 30, 2015 USD ($)	Sep. 12, 2016 USD ($)	Sep. 30, 2016 USD ($)	Sep. 30, 2015 USD ($)	Dec. 31, 2015 USD ($)
Accounting Policies [Abstract]
Net income (loss) attributable to common shareholders	$ (3,441)	$ 1,150,055	$ 19,965	$ 1,048,630		$ (129,463)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Long-term Debt	$ 54,350				$ 54,350		$ 1,245,000
Restructuring and Related Cost, Number of Positions Eliminated					45
Severance and Termination Benefits					$ 1,200

XML

Chapter 11 Proceedings Chapter 11 Proceedings (Details)		8 Months Ended
	May 12, 2016 subsidiary	Sep. 12, 2016 USD ($) board_member shares	Sep. 30, 2016 USD ($) shares	Aug. 11, 2016	May 11, 2016	May 10, 2016 USD ($)
Debt Instrument [Line Items]
Number of Subsidiaries Filing Chapter 11 Bankruptcy | subsidiary	8
Number Of Board Members Replaced | board_member		3
Plan of Reorganization, Cash Reserve		$ 2,700,000
Plan of Reorganization, DIP Fees		100,000
Percentage of Common Stock Holders agreed to RSA			86.00%
Preconfirmation, Senior Notes		1,075,000,000
Debtor Reorganization Items, Legal and Advisory Professional Fees		7,200,000
Liabilities Subject to Compromise, Debt and Accrued Interest		1,122,000,000
Backstop Commitment Agreement, Backstop Commitment		6,022,000				$ 50,000,000
Percentage of claims responsible for related to pre-petition revolving credit agreement				100.00%
Rights Offering, Rights Offering Amount		$ 49,943,000
Plan of Reorganization, Senior Notes and Unsecured Claims Common Stock Exchanged | shares			6,069,074
Plan of Reorganization, Rights Offering Issuance of Common Stock | shares		7,633,588
Plan of Reorganization, Percentage of Common Stock to holders of claims arising under the Senior Notes, general unsecured claims and to the Backstop Parties		51.00%
Plan of Reorganization, percentage of commons stock lenders to receive net of backstop fee		41.00%
Plan of Reorganization, Backstop Parties Common Shares Received | shares		472,902
Plan Of Reorganization, Backstop Parties Common Shares Received, Percent Of Common Stock		3.00%
Plan of Reorganization, CS authorized for Disputed General Unsecured Claims and Non-Accredited Investor Holders of Senior Notes | shares		816,454
Plan of Reorganization, Common Stock reserved for Issuance of Management Incentive Plan | shares		749,600
Plan of Reorganization, Line of Credit Facility, Initial Borrowing		$ 75,400,000	$ 75,400,000
Plan of Reorganization, Escrow Account for Professional Fees		14,575,000
DIP Facility [Member]
Debt Instrument [Line Items]
Debtor-in-Possession Financing, Borrowings Outstanding		$ 0
Share-based Compensation Award, Tranche One [Member]
Debt Instrument [Line Items]
Plan Of Reorganization, Shares Authorized, Percent Of Common Stock		5.00%
Share-based Compensation Award, Tranche Two [Member]
Debt Instrument [Line Items]
Plan Of Reorganization, Shares Authorized, Percent Of Common Stock		5.00%
Senior Notes [Member] | 7.25% Senior Notes due 2019
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage					7.25%
Senior Notes [Member] | 8.50% Senior Notes due 2020
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage					8.50%

XML

Fresh Start Accounting Fresh Start Accounting (Details) - USD ($) $ / shares in Units, $ in Thousands	2 Months Ended	8 Months Ended
	Sep. 12, 2016	Sep. 12, 2016	Sep. 30, 2016	May 10, 2016	Dec. 31, 2015	Sep. 30, 2015	Dec. 31, 2014
Fresh-Start Adjustment [Line Items]
Preconfirmation, Senior Notes	$ 1,075,000	$ 1,075,000
Common stock, shares issued	14,992,018	14,992,018	14,992,018		81,252,676
Proceeds from Long-term Lines of Credit		$ 75,350
Fresh Start Valuation - Discount Rate for Gathering and Transportation Costs	1350.00%	1350.00%
Fresh-Start Adjustment, Enterprise Value	$ 234,831	$ 234,831	$ 266,200
Cash and cash equivalents	31,414	31,414	$ 13,994		$ 11,955	$ 3,342	$ 6,252
Short-term Debt, Fair Value	(75,350)	(75,350)
Fair Value of Successor Common Stock	$ 190,895	$ 190,895
Common Stock, Shares, Outstanding	14,992,018,000	14,992,018,000
Common stock, par value	$ 12.73	$ 12.73	$ 0.01		$ 0.01
Postconfirmation, Current Liabilities	$ 54,171	$ 54,171
Postconfirmation, Noncurrent Liabilities Excluding Long-term Debt	13,558	13,558
Reorganization Value	333,974	333,974
Fair Value of Proved Reserves	121,900	121,900
Asset Retirement Obligation	2,700	2,700	$ 2,700
Fair Value of Undeveloped Acreage - Eagle Ford	92,500	92,500
Fair Value of Undeveloped Acreage - Other than Eagle Ford	8,300	8,300
Fair Value of Other Fixed Assets	26,700	26,700
Fair Value of South Texas Water Facility	23,400	23,400
Debt Issuance Costs, Line of Credit Arrangements, Gross	3,011	3,011
Plan of Reorganization, Line of Credit Facility, Initial Borrowing	75,400	75,400	75,400
Preconfirmation, Liabilities Subject to Compromise			0		$ 1,224,383
Postconfirmation, Additional Paid-in Capital	190,895	190,895
Fresh-Start Adjustment, Increase (Decrease), Retained Earnings (Deficit)	28,319	28,319
Preconfirmation, Stockholders' Equity	140,954	140,954
Fresh-Start Adjustment, Increase (Decrease), Stockholders' Equity	28,319	28,319
Postconfirmation, Stockholders' Equity	190,895	190,895
Fresh-Start Adjustment, Increase (Decrease), Liabilities and Stockholders' Equity	(55,751)	(55,751)
Rights Offering, Rights Offering Amount	49,943	49,943
Total Reorganization Proceeds	125,293	125,293
Repayments of Long-term Debt		113,653
Interest Paid		1,374
DIP Facility Fees Paid		12
Plan of Reorganization, Escrow Account for Professional Fees	14,575	14,575
RBL lender fees and expenses		455
Ad Hoc Committee and indenture trustee fees and expenses		6,782
Payment of certain allowed claims and settlements		2,735
Total Reorganization Uses		142,597
Net Cash Payments off Reorganization Adjustments		(17,304)
Liabilities Subject to Compromise, Interest on Senior Notes	47,213	47,213
Liabilities Subject to Compromise, Firm Transportation Obligation	11,077	11,077
Liabilities Subject to Compromise, Compensation	9,733	9,733
Liabilities Subject to Compromise, Deferred Compensation	4,676	4,676
Liabilities Subject to Compromise, Accounts Payable	1,487	1,487
Liabilities Subject to Compromise, Litigation claims	1,092	1,092
Liabilities Subject to Compromise, Other accrued liabilities	3,885	3,885
Liabilities Subject to Compromise	1,154,163	1,154,163
Cash settlements paid or reserved at emergence	(3,915)	(3,915)
Liabilities subject to compromise, gain	1,150,248	1,150,248
Fair Value of Equity Allocated to Unsecured Creditors	174,477	174,477
Fair Value of Unsecured Creditors Pending Resolution	10,396	10,396
Backstop Commitment Agreement, Backstop Commitment	6,022	6,022		$ 50,000
Cancellation of Equity Upon Emergence from Bankruptcy	$ 882,992	$ 882,992
Fresh-Start Adjustment, Description	28319	28319
Reorganization items, legal and professional fees	$ (22,739)	$ (29,976)
Reorganization items, Settlements related to contract amendments	(2,550)	(2,550)
Debtor Reorganization Items, DIP Facility Costs and Commitment fees	(27)	(170)
Reorganization Items, Write-off Prepaid D&O Insurance	(832)
Debtor Reorganization Items, Other Expense (Income)	(46)	(46)
Debtor Reorganization Items	1,152,373	1,144,993
Minimum [Member]
Fresh-Start Adjustment [Line Items]
Fresh-Start Adjustment, Enterprise Value			218,000
Maximum [Member]
Fresh-Start Adjustment [Line Items]
Fresh-Start Adjustment, Enterprise Value			382,000
Mid-point
Fresh-Start Adjustment [Line Items]
Fresh-Start Adjustment, Enterprise Value			$ 300,000
Revaluation of Assets [Member]
Fresh-Start Adjustment [Line Items]
Fresh-Start Adjustment, Increase (Decrease), Property and Equipment, Net	(55,751)	(55,751)
Fresh-Start Adjustment, Increase (Decrease), Assets	(55,751)	(55,751)
Revaluation of Liabilities [Member]
Fresh-Start Adjustment [Line Items]
Fresh-Start Adjustments, Increase (Decrease), Accounts Payable and Accrued Liabilities	(3,455)	(3,455)
Fresh-Start Adjustment, Increase (Decrease), Current Liabilities	(3,455)	(3,455)
Fresh-Start Adjustment, Increase (Decrease), Deferred Income Tax Assets, Noncurrent	(80,615)	(80,615)
Fair Value, Measurements, Recurring | Level 1
Fresh-Start Adjustment [Line Items]
Deferred Compensation Plan Liabilities Fair Value Disclosure					$ 4,125
Predecessor [Member]
Fresh-Start Adjustment [Line Items]
Preconfirmation, Cash and Cash Equivalents	48,718	48,718
Preconfirmation, Receivables, Net	35,606	35,606
Preconfirmation, Derivative Assets	397	397
Preconfirmation, Prepaid and Other Current Assets	3,966	3,966
Preconfirmation, Current Assets	88,687	88,687
Preconfirmation, Property and Equipment, Net	309,261	309,261
Preconfirmation, Other Assets, Noncurrent	6,902	6,902
Preconfirmation, Assets	404,850	404,850
Preconfirmation, Accounts Payable and Accrued Liabilities	77,151	77,151
Preconfirmation, Current Derivative Liabilities	1,641	1,641
Preconfirmation, Current Maturities of Long-term Debt	113,653	113,653
Preconfirmation, Current Liabilities	192,445	192,445
Preconfirmation, Other Noncurrent Obligations	84,953	84,953
Preconfirmation, Noncurrent Derivative Liabilities	9,120	9,120
Preconfirmation, Liabilities Subject to Compromise	1,154,163	1,154,163
Preconfirmation, Preferred Stock	1,880	1,880
Preconfirmation, Common Stock	697	697
Fresh-Start Adjustment, Increase (Decrease), Common Stock	(697)	(697)
Preconfirmation, Additional Paid-in Capital	1,213,797	1,213,797
Fresh-Start Adjustment, Increase (Decrease), Additional Paid-in Capital	(1,213,797)	(1,213,797)
Preconfirmation, Other Deferred Compensation	3,440	3,440
Preconfirmation, Accumulated Other Comprehensive Income (Loss)	383	383
Preconfirmation, Treasury Stock	(3,574)	(3,574)
Preconfirmation, Retained Earnings (Deficit)	(2,252,454)	(2,252,454)
Preconfirmation, Stockholders' Equity	(1,035,831)	(1,035,831)
Preconfirmation, Liabilities and Stockholders' Equity	404,850	404,850
Restatement Adjustment [Member]
Fresh-Start Adjustment [Line Items]
Fresh-Start Adjustment, Increase (Decrease), Cash and Cash Equivalents	(17,304)	(17,304)
Fresh-Start Adjustment, Increase (Decrease), Receivables, Net	4,292	4,292
Fresh-Start Adjustment, Increase (Decrease), Other Current Liabilities	(832)	(832)
Fresh-Start Adjustment, Increase (Decrease), Current Assets	(13,844)	(13,844)
Fresh-Start Adjustment, Increase (Decrease), Property and Equipment, Net	0	0
Fresh-Start Adjustment, Increase (Decrease), Other Assets, Noncurrent	(1,281)	(1,281)
Fresh-Start Adjustment, Increase (Decrease), Assets	(15,125)	(15,125)
Fresh-Start Adjustments, Increase (Decrease), Accounts Payable and Accrued Liabilities	(21,166)	(21,166)
Fresh-Start Adjustment, Increase (Decrease), Current Maturities of Long-term Debt	(113,653)	(113,653)
Fresh-Start Adjustment, Increase (Decrease), Current Liabilities	(134,819)	(134,819)
Fresh-Start Adjustment, Increase (Decrease), Long-term Debt	75,350	75,350
Fresh-Start Adjustment, Increase (Decrease), Liabilities Subject to Compromise	(1,154,163)	(1,154,163)
Fresh-Start Adjustment, Increase (Decrease), Preferred Stock	(1,880)	(1,880)
Fresh-Start Adjustment, Increase (Decrease) Other Deferred Compensation	(3,440)	(3,440)
Fresh-Start Adjustment, Increase (Decrease), Accumulated Other Comprehensive Income (Loss)	(383)	(383)
Fresh-Start Adjustment, Increase (Decrease) Treasury Stock	3,574	3,574
Fresh-Start Adjustment, Increase (Decrease), Retained Earnings (Deficit)	2,224,135	2,224,135
Fresh-Start Adjustment, Increase (Decrease), Stockholders' Equity	1,198,407	1,198,407
Fresh-Start Adjustment, Increase (Decrease), Liabilities and Stockholders' Equity	(15,125)	(15,125)
Successor [Member]
Fresh-Start Adjustment [Line Items]
Postconfirmation, Cash and Cash Equivalents	31,414	31,414
Postconfirmation, Current Liabilities	54,171	54,171
Postconfirmation, Receivables, Net	39,898	39,898
Postconfirmation, Derivative Assets	397	397
Postconfirmation, Prepaid and Other Current Assets	3,134	3,134
Postconfirmation, Current Assets	74,843	74,843
Postconfirmation, Property and Equipment, Net	253,510	253,510
Postconfirmation, Other Assets, Noncurrent	5,621	5,621
Postconfirmation, Assets	333,974	333,974
Postconfirmation, Accounts Payable and Accrued Liabilities	52,530	52,530
Postconfirmation, Current Derivative Liabilities	1,641	1,641
Postconfirmation, Other Noncurrent Obligations	4,438	4,438
Postconfirmation, Noncurrent Derivative Liabilities	9,120	9,120
Postconfirmation, Long-term Debt	75,350	75,350
Fresh-Start Adjustment, Increase (Decrease), Common Stock	150	150
Postconfirmation, Common Stock	150	150
Fresh-Start Adjustment, Increase (Decrease), Additional Paid-in Capital	190,745	190,745
Postconfirmation, Additional Paid-in Capital	190,745	190,745
Postconfirmation, Stockholders' Equity	190,895	190,895
Postconfirmation, Liabilities and Stockholders' Equity	$ 333,974	$ 333,974

XML

Summary of Accounts Receivable (Detail) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Accounts Receivable and Major Customers [Line Items]
Customers	$ 19,221	$ 23,481
Joint interest partners	8,201	18,381
Other	7,158	7,658
Accounts Receivable, Gross, Current, Total	34,580	49,520
Less: Allowance for doubtful accounts	(2,443)	(1,555)
Accounts receivable, net of allowance for doubtful accounts	32,137	$ 47,965
Trustee [Member]
Accounts Receivable and Major Customers [Line Items]
Other	$ 4,300

XML

Accounts Receivable and Major Customers - Additional Information (Detail) $ in Millions	9 Months Ended
	Sep. 30, 2016 USD ($) Customer	Sep. 30, 2015 USD ($) Customer	Dec. 31, 2015 USD ($)
Sales Revenue | Customer Concentration Risk
Accounts, Notes, Loans and Financing Receivable [Line Items]
Number of major customers | Customer	3	2
Revenues, major customers	$ 93.5	$ 108.4
Concentration risk, percentage	94.00%	50.00%
Sales Revenue | Customer Concentration Risk | Major Customer 1
Accounts, Notes, Loans and Financing Receivable [Line Items]
Revenues, major customers	$ 64.1	$ 62.3
Concentration risk, percentage	64.00%	29.00%
Sales Revenue | Customer Concentration Risk | Major Customer 2
Accounts, Notes, Loans and Financing Receivable [Line Items]
Revenues, major customers	$ 15.8	$ 46.1
Concentration risk, percentage	16.00%	21.00%
Sales Revenue | Customer Concentration Risk | Major Customer 3
Accounts, Notes, Loans and Financing Receivable [Line Items]
Revenues, major customers	$ 13.6
Concentration risk, percentage	14.00%
Accounts Receivable | Credit Concentration Risk
Accounts, Notes, Loans and Financing Receivable [Line Items]
Concentration risk, percentage	88.00%	90.00%
Accounts receivable, major customers	$ 16.2		$ 21.1

XML

Derivative Instruments - Additional Information (Detail) $ in Thousands	1 Months Ended	8 Months Ended	9 Months Ended
	Sep. 30, 2016 USD ($) Entity $ / bbl	Sep. 12, 2016 USD ($)	Sep. 30, 2016 USD ($) Entity $ / bbl	Sep. 30, 2015 USD ($)	Dec. 31, 2015 USD ($)
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Derivative assets	$ 446		$ 446		$ 97,956
Derivatives Settled to Pay Down Revolver	$ 0	$ 51,979		$ 0
Crude Oil
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Derivative, Swap Type, Average Fixed Price | $ / bbl	48.62		48.62
Commodity contracts
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Derivative assets	$ 14,700		$ 14,700
Number of derivative counterparties | Entity	3		3
Commodity contracts | Natural Gas
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Third-party quoted forward prices			NYMEX Henry Hub gas
Commodity contracts | Crude Oil
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Third-party quoted forward prices			West Texas Intermediate crude oil
April 2016 [Member]
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Derivatives Settled			$ 22,600
Derivatives Settled to Pay Down Revolver			16,600
May 2016 [Member]
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Derivatives Settled			17,500
Derivatives Settled to Pay Down Revolver			12,500
March 2016 [Domain]
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Derivatives Settled			$ 22,900

XML

Commodity Derivative Positions (Detail) $ in Thousands	9 Months Ended
	Sep. 30, 2016 USD ($) bbl $ / bbl	Dec. 31, 2015 USD ($)
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative Liability	$ 15,179	$ 0
Crude Oil
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Swap Type, Average Fixed Price | $ / bbl	48.62
Crude Oil | Fourth quarter 2016
Derivative Instruments Related to Oil and Gas Production [Line Items]
Instrument	Swaps
Notional Volume, per day | bbl	5,940
Derivative, Swap Type, Average Fixed Price | $ / bbl	47.69
Fair Value Asset	$ 0
Fair Value Liability	$ 709
Crude Oil | First Quarter 2017 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Instrument	Swaps
Notional Volume, per day | bbl	4,408
Derivative, Swap Type, Average Fixed Price | $ / bbl	48.62
Fair Value Asset	$ 0
Fair Value Liability	$ 737
Crude Oil | Second Quarter 2017 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Instrument	Swaps
Notional Volume, per day | bbl	4,408
Derivative, Swap Type, Average Fixed Price | $ / bbl	48.62
Fair Value Asset	$ 0
Fair Value Liability	$ 1,106
Crude Oil | Third Quarter 2017 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Instrument	Swaps
Notional Volume, per day | bbl	4,408
Derivative, Swap Type, Average Fixed Price | $ / bbl	48.62
Fair Value Asset	$ 0
Fair Value Liability	$ 1,335
Crude Oil | Fourth Quarter 2017 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Instrument	Swaps
Notional Volume, per day | bbl	4,408
Derivative, Swap Type, Average Fixed Price | $ / bbl	48.62
Fair Value Asset	$ 0
Fair Value Liability	$ 1,518
Crude Oil | First Quarter 2018 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Instrument	Swaps
Notional Volume, per day | bbl	3,476
Derivative, Swap Type, Average Fixed Price | $ / bbl	49.12
Fair Value Asset	$ 0
Fair Value Liability	$ 1,131
Crude Oil | Second Quarter 2018 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Instrument	Swaps
Notional Volume, per day | bbl	3,476
Derivative, Swap Type, Average Fixed Price | $ / bbl	49.12
Fair Value Asset	$ 0
Fair Value Liability	$ 1,244
Crude Oil | Third Quarter 2018 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Instrument	Swaps
Notional Volume, per day | bbl	3,476
Derivative, Swap Type, Average Fixed Price | $ / bbl	49.12
Fair Value Asset	$ 0
Fair Value Liability	$ 1,353
Crude Oil | Fourth Quarter 2018 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Instrument	Swaps
Notional Volume, per day | bbl	3,476
Derivative, Swap Type, Average Fixed Price | $ / bbl	49.12
Fair Value Asset	$ 0
Fair Value Liability	$ 1,451
Crude Oil | First Quarter 2019 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Instrument	Swaps
Notional Volume, per day | bbl	2,916
Derivative, Swap Type, Average Fixed Price | $ / bbl	49.90
Fair Value Asset	$ 0
Fair Value Liability	$ 1,051
Crude Oil | Second Quarter 2019 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Instrument	Swaps
Notional Volume, per day | bbl	2,916
Derivative, Swap Type, Average Fixed Price | $ / bbl	49.90
Fair Value Asset	$ 0
Fair Value Liability	$ 1,117
Crude Oil | Fourth Quarter 2019 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Instrument	Swaps
Notional Volume, per day | bbl	2,916
Derivative, Swap Type, Average Fixed Price | $ / bbl	49.90
Fair Value Asset	$ 0
Fair Value Liability	$ 1,247
Crude Oil | Third Quarter 2019 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Instrument	Swaps
Notional Volume, per day | bbl	2,916
Derivative, Swap Type, Average Fixed Price | $ / bbl	49.90
Fair Value Asset	$ 0
Fair Value Liability	$ 1,179

XML

Impact of Derivative Activities on Condensed Consolidated Statements of Income (Detail) - USD ($) $ in Thousands	1 Months Ended	2 Months Ended	3 Months Ended	8 Months Ended	9 Months Ended
	Sep. 30, 2016	Sep. 12, 2016	Sep. 30, 2015	Sep. 12, 2016	Sep. 30, 2015
Derivative Instruments, Gain (Loss) [Line Items]
Derivatives	$ (4,369)	$ 8,934	$ 44,701	$ (8,333)	$ 52,073

XML

Fair Value of Derivative Instruments on Condensed Consolidated Balance Sheets (Detail) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Derivatives, Fair Value [Line Items]
Derivative assets, current	$ 446	$ 97,956
Derivative assets	446	97,956
Commodity derivative liabilities – current	(3,888)
Derivative Liability, Noncurrent	11,291	0
Derivative Liability	15,179	0
Commodity contracts
Derivatives, Fair Value [Line Items]
Derivative assets	14,700
Commodity contracts | Derivative assets/liabilities - current
Derivatives, Fair Value [Line Items]
Derivative assets, current	446	97,956
Commodity derivative liabilities – current	(3,888)	0
Commodity contracts | Noncurrent Derivative Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Noncurrent	0	0
Derivative Liability, Noncurrent	$ 11,291	$ 0

XML

Summary of Property and Equipment (Detail) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Oil and gas properties:
Proved	$ 241,308	$ 2,678,415
Unproved	8,338	6,881
Total oil and gas properties	249,646	2,685,296
Other property and equipment	3,574	31,365
Total properties and equipment	253,220	2,716,661
Accumulated depreciation, depletion and amortization	(2,020)	(2,372,266)
Property and equipment, net (successful efforts method)	$ 251,200	$ 344,395

XML

Summary of Long-Term Debt (Detail) - USD ($) $ in Thousands	Sep. 30, 2016		Dec. 31, 2015
Debt Instrument [Line Items]
Revolving credit facility			$ 0
Long-term Debt	$ 54,350		1,245,000
Unamortized issuance costs	0		(20,617)
Preconfirmation, Liabilities Subject to Compromise	0		1,224,383
Debt Instrument, Unamortized Discount (Premium) and Debt Issuance Costs, Net	54,350		0
7.25% Senior Notes due 2019
Debt Instrument [Line Items]
Senior notes	0		300,000
Unamortized issuance costs	0		(3,295)
8.50% Senior Notes due 2020
Debt Instrument [Line Items]
Senior notes	0		775,000
Unamortized issuance costs	0		(17,322)
Maximum [Member] | Line of Credit [Member]
Debt Instrument [Line Items]
Available borrowing capacity	$ 54,350	[1]	$ 170,000	[2]

[1] Issuance costs attributable to the RBL were presented as a component of Other assets (see Note 11) prior to the accelerated write-off in advance of our bankruptcy filing during the three months ended June 30, 2016.

[2] Issuance costs attributable to the RBL were presented as a component of Other assets (see Note 11) prior to the accelerated write-off in advance of our bankruptcy filing during the three months ended June 30, 2016.

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Long-Term Debt - Additional Information (Detail) - USD ($)	1 Months Ended		8 Months Ended	9 Months Ended
	Sep. 30, 2016		Sep. 12, 2016	Sep. 30, 2016		Sep. 30, 2015	Dec. 31, 2015
Debt Disclosure [Line Items]
Derivatives Settled to Pay Down Revolver	$ 0		$ 51,979,000			$ 0
Repayments of Lines of Credit	21,000,000		$ 119,121,000			$ 98,000,000
Line of Credit Facility, Maximum Borrowing Capacity	$ 128,000,000			$ 128,000,000
Interest Coverage Ratio, Maximum	3.00			3.00
Current Ratio	1.00			1.00
Revolving Credit Facility
Debt Disclosure [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 200,000,000			$ 200,000,000
Interest rate option two, applicable margin rate	3.25%			3.25%
Interest Rate at Period End	3.77%			3.77%
Interest Rate at Period End, LIBOR component	0.52%			0.52%
Revolving Credit Facility | Future Period [Member]
Debt Disclosure [Line Items]
Debt To E B I T D Ratio Maximum	4.00			4.00
Revolving Credit Facility | Future Period Two [Member]
Debt Disclosure [Line Items]
Debt To E B I T D Ratio Maximum	3.75			3.75
Revolving Credit Facility | Future Period Three [Member]
Debt Disclosure [Line Items]
Debt To E B I T D Ratio Maximum	3.50			3.50
Letter of Credit
Debt Disclosure [Line Items]
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage				0.50%
Line of Credit [Member]
Debt Disclosure [Line Items]
Letters of Credit Outstanding, Amount	$ 5,000,000			$ 5,000,000
Line of Credit [Member] | Letter of Credit
Debt Disclosure [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	800,000			800,000
7.25% Senior Notes due 2019
Debt Disclosure [Line Items]
Senior Notes, Noncurrent	0			0			$ 300,000,000
8.50% Senior Notes due 2020
Debt Disclosure [Line Items]
Senior Notes, Noncurrent	$ 0			$ 0			775,000,000
Maximum [Member] | Revolving Credit Facility
Debt Disclosure [Line Items]
Interest rate option one, applicable margin rate over Adjusted LIBOR				3.00%
Interest rate option two, applicable margin rate	4.00%			4.00%
Maximum [Member] | Line of Credit [Member]
Debt Disclosure [Line Items]
Available borrowing capacity	$ 54,350,000	[1]		$ 54,350,000	[1]		$ 170,000,000	[2]
Minimum [Member] | Revolving Credit Facility
Debt Disclosure [Line Items]
Interest rate option one, applicable margin rate over Adjusted LIBOR				2.00%
Interest rate option two, applicable margin rate	3.00%			3.00%
Interest Payable One [Member] | Revolving Credit Facility
Debt Disclosure [Line Items]
Debt Instrument, Interest Payable Period				1 month
Interest Payable Two [Member] | Revolving Credit Facility
Debt Disclosure [Line Items]
Debt Instrument, Interest Payable Period				3 months
Interest Payable Three [Member] | Revolving Credit Facility
Debt Disclosure [Line Items]
Debt Instrument, Interest Payable Period				6 months

[1] Issuance costs attributable to the RBL were presented as a component of Other assets (see Note 11) prior to the accelerated write-off in advance of our bankruptcy filing during the three months ended June 30, 2016.

[2] Issuance costs attributable to the RBL were presented as a component of Other assets (see Note 11) prior to the accelerated write-off in advance of our bankruptcy filing during the three months ended June 30, 2016.

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Income Taxes (Details) $ in Millions	9 Months Ended
	Sep. 30, 2016 USD ($)
Income Tax Disclosure [Abstract]
Federal statutory income tax rate	35.00%
Income taxes paid	$ 0.1

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Exit Activities (Detail) $ in Millions	9 Months Ended
	Sep. 30, 2016 USD ($) contract
Restructuring and Related Activities [Abstract]
Restructuring and Related Cost, Number of Positions Eliminated	45
Severance and Termination Benefits Paid	$ 1.9
Severance and Termination Benefits	1.2
Severance and Termination Benefits Expected	$ 0.1
Restructuring and Related Cost, Expected Number of Positions Eliminated	9
Retention Bonuses Expected	$ 0.2
Retention Bonuses	0.7
Severance, Termination and Retention Benefits Expected	$ 0.3
Number Of Drilling Rig Contracts Terminated | contract	1
Liabilities Subject to Compromise, Early Contract Termination Fees	$ 1.3

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Components of Selected Balance Sheet Accounts (Detail) - USD ($) $ in Thousands	Sep. 30, 2016		Dec. 31, 2015
Other current assets:
Tubular inventory and well materials	$ 2,154		$ 2,878
Prepaid expenses	1,357		4,184
Other Assets, Miscellaneous, Current	7		42
Other Assets, Current	3,518		7,104
Other assets:
Assets of SERP 1	0	[1]	4,123
Deferred issuance costs of the Revolver	2,973		1,572
Other	2,598		2,655
Other assets	5,571		8,350
Accounts payable and accrued liabilities:
Trade accounts payable	7,926		11,603
Drilling costs	1,475		12,074
Royalties and revenue – related	28,203		39,119
Compensation – related	2,164		9,904
Interest	125		15,531
Other	5,539		15,294
Accounts payable and accrued liabilities	45,432		103,525
Other liabilities:
Deferred gains on sale of assets	0		82,943
Firm transportation obligation	0		10,705
Asset retirement obligations	2,696		2,621
Defined benefit pension obligations	1,132		1,129
Postretirement health care benefit obligations	523		731
Compensation-related	0		1,447
Deferred compensation – SERP obligations and other	0		4,434
Other	100		928
Other liabilities	$ 4,451		$ 104,938

[1] 1 In connection with our emergence from bankruptcy, the assets of the SERP reverted to us upon the release of claims by our employees attributable to certain deferred compensation arrangements in September 2016. The SERP assets were liquidated by the plan trustee in November 2016 and the cash value was transferred to us (see Notes 3, 4 and 5).

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Fair Value Summary of Long-Term Debt with Fixed Interest Rates (Detail) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt with fixed interest rates	$ 0	$ 166,303
Fair Value | 7.25% Senior Notes due 2019
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt with fixed interest rates	0	40,830
Fair Value | 8.50% Senior Notes due 2020
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt with fixed interest rates	0	125,473
Carrying Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt with fixed interest rates	0	1,075,000
Carrying Value | 7.25% Senior Notes due 2019
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt with fixed interest rates	0	300,000
Carrying Value | 8.50% Senior Notes due 2020
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt with fixed interest rates	$ 0	$ 775,000

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Assets and Liabilities Measured at Fair Value on Recurring Basis (Detail) - USD ($) $ in Thousands	Sep. 30, 2016		Dec. 31, 2015
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability, Current	$ 3,888
Derivative Asset, Current	446		$ 97,956
Liabilities:
Derivative Liability, Noncurrent	(11,291)		0
Fair Value, Measurements, Recurring
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long Term Investments Fair Value Disclosure	4,292	[1]	4,123
Fair Value, Measurements, Recurring | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long Term Investments Fair Value Disclosure	4,292	[1]	4,123
Liabilities:
Deferred Compensation Plan Liabilities Fair Value Disclosure			4,125
Fair Value, Measurements, Recurring | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long Term Investments Fair Value Disclosure	0		0
Liabilities:
Deferred Compensation Plan Liabilities Fair Value Disclosure			0
Fair Value, Measurements, Recurring | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long Term Investments Fair Value Disclosure	0		0
Liabilities:
Deferred Compensation Plan Liabilities Fair Value Disclosure			0
Fair Value, Measurements, Recurring | Commodity contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability, Current	3,888
Derivative Asset, Current	446		97,956
Liabilities:
Derivative Liability, Noncurrent	(11,291)
Fair Value, Measurements, Recurring | Commodity contracts | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability, Current	0
Derivative Asset, Current	0		0
Liabilities:
Derivative Liability, Noncurrent	0
Fair Value, Measurements, Recurring | Commodity contracts | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability, Current	3,888
Derivative Asset, Current	446		97,956
Liabilities:
Derivative Liability, Noncurrent	(11,291)
Fair Value, Measurements, Recurring | Commodity contracts | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability, Current	0
Derivative Asset, Current	0		0
Liabilities:
Derivative Liability, Noncurrent	$ 0
Predecessor [Member] | Fair Value, Measurements, Recurring
Liabilities:
Deferred Compensation Plan Liabilities Fair Value Disclosure			$ 4,125

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Commitments and Contingencies - Additional Information (Detail) $ in Thousands	2 Months Ended	8 Months Ended	9 Months Ended	12 Months Ended
	Sep. 12, 2016 USD ($)	Sep. 12, 2016 USD ($)	Sep. 30, 2016 USD ($) bbl	Dec. 31, 2010 USD ($)
Commitments and Contingencies Disclosure [Line Items]
Reorganization items, Settlements related to contract amendments	$ 2,550	$ 2,550
Long-term Purchase Commitment, Minimum Volume Required | bbl			8,000
Crude Oil Gathering Agreement			15
Marketing Agreement			10
Asset Retirement Obligation	2,700	$ 2,700	$ 2,700
Legal Reserve
Commitments and Contingencies Disclosure [Line Items]
Reserve established for contingency matters			100	$ 900
Crude Oil Gathering And Transportation Services
Commitments and Contingencies Disclosure [Line Items]
Reorganization items, Settlements related to contract amendments	$ 300
Contractual obligation, balance of 2015			9,600
Contractual Obligation, Due in Third Year			10,400
Contractual Obligation, Due in Fourth Year			11,700
Contractual Obligation, Due 2020 through 2025			13,000
Contractual Obligation, Due 2026			7,400
Contractual Obligation, Due 2027 through 2030			3,800
Contractual Obligation, Due 2031			2,200
Contractual obligation, annual			$ 3,900
Original Volume Required [Domain]
Commitments and Contingencies Disclosure [Line Items]
Long-term Purchase Commitment, Minimum Volume Required | bbl			15,000
Original Term [Domain]
Commitments and Contingencies Disclosure [Line Items]
Crude Oil Gathering Agreement			10

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Shareholders' Equity Rollforward (Details) - USD ($)		1 Months Ended	2 Months Ended	3 Months Ended	8 Months Ended	9 Months Ended
		Sep. 30, 2016	Sep. 12, 2016	Sep. 30, 2015	Sep. 12, 2016	Sep. 30, 2016	Sep. 30, 2015
Schedule of Stockholders' Equity [Line Items]
Issuance of Common Stock, Exchange of Claims			$ 131,893,000		$ 131,893,000
Issuance of Common Stock, Backstop Fee			9,059,000		9,059,000
Issuance of Common Stock, Rights Offering			49,943,000		49,943,000
Share-based compensation		$ 0			1,511,000	$ 3,918,000	$ 3,369,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
As of beginning balance					915,121,000	915,121,000
Net income (loss)		(3,441,000)	1,150,055,000	$ 25,900,000	1,054,602,000		$ (111,394,000)
All Other Changes					(1,473,000)
As of ending balance		(187,454,000)				(187,454,000)
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Adjustment, before Tax						0
Preconfirmation, Liabilities and Stockholders' Equity			(140,954,000)		(140,954,000)
Cancellation of Equity Upon Emergence from Bankruptcy			882,992,000		882,992,000
Cancellation of Total Equity Upon Emergence from Bankruptcy			(140,954,000)		(140,954,000)
Postconfirmation, Stockholders' Equity			190,895,000		190,895,000
Preferred stock
Increase (Decrease) in Stockholders' Equity [Roll Forward]
As of beginning balance					(3,146,000)	(3,146,000)
All Other Changes					1,266,000
As of ending balance		0				0
Preconfirmation, Liabilities and Stockholders' Equity			(1,880,000)		(1,880,000)
Cancellation of Equity Upon Emergence from Bankruptcy			(1,880,000)		(1,880,000)
Postconfirmation, Stockholders' Equity			0		0
Common stock
Increase (Decrease) in Stockholders' Equity [Roll Forward]
As of beginning balance					(628,000)	(628,000)
All Other Changes					(69,000)
As of ending balance		(150,000)				(150,000)
Preconfirmation, Liabilities and Stockholders' Equity			(697,000)		(697,000)
Cancellation of Equity Upon Emergence from Bankruptcy			(697,000)		(697,000)
Postconfirmation, Common Stock - Rights Offering			76,000		76,000
Postconfirmation, Common Stock			69,000		69,000
Postconfirmation, Additional Paid-in Capital			131,824,000		131,824,000
Postconfirmation, Stockholders' Equity			150,000		150,000
Postconfirmation, Common Stock - Backstop Fee			5,000		5,000
Postconfirmation, Additional Paid-in Capital - Rights Offering			49,867,000		49,867,000
Postconfirmation, Additional paid-in capital - Backstop Fee			9,054,000		9,054,000
Additional Paid-in Capital [Member]
Increase (Decrease) in Stockholders' Equity [Roll Forward]
As of beginning balance					(1,211,088,000)	(1,211,088,000)
All Other Changes					(2,709,000)
As of ending balance		(190,745,000)				(190,745,000)
Preconfirmation, Liabilities and Stockholders' Equity			(1,213,797,000)		(1,213,797,000)
Cancellation of Equity Upon Emergence from Bankruptcy			(1,213,797,000)		(1,213,797,000)
Postconfirmation, Stockholders' Equity			190,745,000		190,745,000
Retained Earnings [Member]
Increase (Decrease) in Stockholders' Equity [Roll Forward]
As of beginning balance		0			2,130,271,000	2,130,271,000
Net income (loss)		(3,441,000)			1,054,602,000
As of ending balance		3,441,000	0		0	3,441,000
Preconfirmation, Liabilities and Stockholders' Equity			1,075,669,000		1,075,669,000
Cancellation of Equity Upon Emergence from Bankruptcy			1,075,669,000		1,075,669,000
Postconfirmation, Stockholders' Equity			0		0
Deferred compensation obligation
Increase (Decrease) in Stockholders' Equity [Roll Forward]
As of beginning balance					(3,440,000)	(3,440,000)
All Other Changes						0
As of ending balance		0				0
Preconfirmation, Liabilities and Stockholders' Equity			(3,440,000)		(3,440,000)
Cancellation of Equity Upon Emergence from Bankruptcy			(3,440,000)		(3,440,000)
Postconfirmation, Stockholders' Equity			0		0
AOCI Attributable to Parent [Member]
Increase (Decrease) in Stockholders' Equity [Roll Forward]
As of beginning balance					(422,000)	(422,000)
All Other Changes					39,000
As of ending balance		0				0
Preconfirmation, Liabilities and Stockholders' Equity	[1]		(383,000)		(383,000)
Cancellation of Equity Upon Emergence from Bankruptcy	[1]		(383,000)		(383,000)
Postconfirmation, Stockholders' Equity	[1]		0		0
Treasury stock
Increase (Decrease) in Stockholders' Equity [Roll Forward]
As of beginning balance					(3,574,000)	(3,574,000)
All Other Changes						0
As of ending balance		$ 0				$ 0
Preconfirmation, Liabilities and Stockholders' Equity			(3,574,000)		(3,574,000)
Cancellation of Equity Upon Emergence from Bankruptcy			3,574,000		3,574,000
Postconfirmation, Stockholders' Equity			$ 0		$ 0
Convertible Preferred Stock
Schedule of Stockholders' Equity [Line Items]
Conversion of Stock, Shares Converted						52	12,619
Depositary Shares
Schedule of Stockholders' Equity [Line Items]
Conversion of Stock, Shares Converted						5,159	1,261,850
Preferred Stock, Dividend Rate, Percentage						6.00%
Series A Preferred Stock Converted to Common [Member] | Common stock
Schedule of Stockholders' Equity [Line Items]
Stock Issued During Period, Shares, Conversion of Convertible Securities					85,982
Series B Preferred Stock Converted to Common [Member] | Common stock
Schedule of Stockholders' Equity [Line Items]
Stock Issued During Period, Shares, Conversion of Convertible Securities					6,879,222

[1] Accumulated other comprehensive income (“AOCI”) is entirely attributable to our defined benefit pension and postretirement health care plans. The changes in the balance of AOCI for the period January 1, 2016 through September 12, 2016, represent reclassifications from AOCI to net periodic benefit expense, a component of “General and administrative expenses,” of $(38).

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Shareholders' Equity - Additional Information (Detail) - USD ($) $ in Thousands	1 Months Ended	8 Months Ended	9 Months Ended
	Sep. 30, 2016	Sep. 12, 2016	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Class of Stock [Line Items]
Stockholders' Equity, Other		$ 1,473
Share-based compensation (equity-classified)	$ 0	$ (1,511)	$ (3,918)	$ (3,369)
Other Comprehensive loss, pension and postretirements obligations, before tax			$ 0
Common stock, shares authorized	45,000,000		45,000,000		228,000,000
Series A Preferred Stock
Class of Stock [Line Items]
Preferred Stock, Shares Issued	0		0		3,915
Series B Preferred Stock
Class of Stock [Line Items]
Preferred Stock, Shares Issued	0		0		27,551
Convertible Preferred Stock
Class of Stock [Line Items]
Conversion of Stock, Shares Converted			52	12,619
Depositary Shares
Class of Stock [Line Items]
Conversion of Stock, Shares Converted			5,159	1,261,850
Preferred Stock, Dividend Rate, Percentage			6.00%

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Summary of Share-Based Compensation Expense (Detail) - USD ($) $ in Thousands	1 Months Ended	2 Months Ended	3 Months Ended	8 Months Ended	9 Months Ended
	Sep. 30, 2016	Sep. 12, 2016	Sep. 30, 2015	Sep. 12, 2016	Sep. 30, 2016	Sep. 30, 2015
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Share-based Compensation Expense adjustment					$ 5,300
Defined Contribution Plan, Cost Recognized	$ 100			$ 400		$ 600
Other Stock Based Compensation Expense	0	$ 5,433	$ 1,263	1,511		3,369
Share-based compensation	0			1,511	$ 3,918	3,369
Allocated Share-based Compensation Expense	$ 0	5,433	412	1,492		2,683
Deferred Compensation Arrangement with Individual, Common Stock Reserved for Future Issuance	749,600				749,600
Liability-classified awards
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Share-based compensation	$ 0	$ 0	$ (851)	(19)		(686)
Other Pension Plan, Postretirement or Supplemental Plans [Member]
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Pension and Other Postretirement Benefit Expense	$ 100			$ 100		$ 100

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Components of Interest Expense (Detail) - USD ($)	1 Months Ended	2 Months Ended		3 Months Ended	8 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 12, 2016		Sep. 30, 2015	Sep. 12, 2016		Sep. 30, 2016	Sep. 30, 2015
Contractual Interest Expense [Line Items]
Contractual Interest Expense on Prepetition Liabilities Not Recognized in Statement of Operations		$ 19,300,000			$ 66,100,000
Debtor Reorganization Items, Write-off of Debt Issuance Costs and Debt Discounts							$ 20,500,000
Interest on borrowings and related fees 1	$ 180,000	1,363,000	[1]	$ 23,239,000	36,013,000	[2]		$ 69,371,000
Amortization of debt issuance costs	38,000	0		1,224,000	22,188,000	[3]		3,504,000
Capitalized interest	0	0		(1,478,000)	(183,000)			(4,854,000)
Interest expense	$ 218,000.00	1,363,000		$ 22,985,000	58,018,000			$ 68,021,000
7.25% Senior Notes due 2019
Contractual Interest Expense [Line Items]
Contractual Interest Expense on Prepetition Liabilities Not Recognized in Statement of Operations		4,400,000			$ 15,300,000
Senior Notes Due 2020 [Member]
Contractual Interest Expense [Line Items]
Contractual Interest Expense on Prepetition Liabilities Not Recognized in Statement of Operations		$ 13,400,000					$ 46,300,000

[1] Preferred stock dividends were excluded from the computation of diluted earnings (loss) per share for the period January 1, 2016 through September 12, 2016 and the nine months ended September 30, 2015, as the assumed conversion of the outstanding preferred stock would have been anti-dilutive.

[2] Absent the bankruptcy proceedings and the corresponding suspension of the accrual of interest on unsecured debt, we would have recorded total contractual interest expense of $66.1 million for the period from January 1, 2016 through September 12, 2016, including $15.3 million attributable to the 2019 Senior Notes and $46.3 million attributable to the 2020 Senior Notes.

[3] Includes $20.5 million related to the accelerated write-off of unamortized debt issuance costs associated with the RBL and Senior Notes (see Note 8).

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Components of Calculation of Basic and Diluted Earnings Per Share (Detail) - USD ($) shares in Thousands	1 Months Ended	2 Months Ended	3 Months Ended	8 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 12, 2016	Sep. 30, 2015	Sep. 12, 2016		Sep. 30, 2015
Schedule of Earnings per Share, Basic and Diluted [Line Items]
Dilutive Securities, Effect on Basic Earnings Per Share, Dilutive Convertible Securities	$ 0	$ 0	$ 5,935,000
Net income (loss)	(3,441,000)	1,150,055,000	25,900,000	$ 1,054,602,000		$ (111,394,000)
Less: Preferred stock dividends	0	0	(5,935,000)	(5,972,000)	[1]	(18,069,000)	[1]
Net income (loss) attributable to common shareholders, Basic	(3,441,000)	1,150,055,000	19,965,000	1,048,630,000		(129,463,000)
Net loss attributable to common shareholders, Diluted	$ (3,441,000)	$ 1,150,055,000	$ 25,900,000	$ 1,048,630,000		$ (129,463,000)
Weighted-average shares – basic	14,992	89,292	72,651	88,013		72,438
Effect of dilutive securities	0	22,166	30,801	36,074	[2]	0	[2]
Weighted-average shares – diluted	14,992	111,458	103,452	124,087		72,438
Potentially dilutive securities with the effect of being anti-dilutive excluded from the calculation of diluted earnings per common share						31,100

[1] Preferred stock dividends were excluded from the computation of diluted earnings (loss) per share for the period January 1, 2016 through September 12, 2016 and the nine months ended September 30, 2015, as the assumed conversion of the outstanding preferred stock would have been anti-dilutive.

[2] For the nine months ended September 30, 2015, approximately 31.1 million of potentially dilutive securities, including the Series A Preferred Stock and Series B Preferred Stock, stock options and restricted stock units, had the effect of being anti-dilutive and were excluded from the calculation of diluted earnings (loss) per common share.