BAYTEX ENERGY USA, INC. - Quarter Report: 2016 September (Form 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



¨	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.

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.

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.

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.

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.

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.

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”).

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.


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

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

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.

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.


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.


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.

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.

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.


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

______________________

¹The 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.


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.

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.


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

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

_______________________

¹Absent 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

_______________________

²Absent 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).


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.

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.

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.


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.

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.

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;


•	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.

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.

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.

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.

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.

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 costs¹	—		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.

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.

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.

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

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.

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.

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.

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.

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.

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.

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.

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.


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.

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,

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.


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.


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.

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)