8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d)

of the Securities Exchange Act of 1934

Date of Report: May 12, 2016 (May 12, 2016)

(Date of Earliest Event Reported)

PENN VIRGINIA CORPORATION

(Exact Name of Registrant as Specified in Charter)

Virginia	1-13283	23-1184320
(State or other jurisdiction of incorporation)	(Commission File Number)	(IRS Employer Identification No.)

Four Radnor Corporate Center; Suite 200 100 Matsonford Road, Radnor, Pennsylvania	19087
(Address of Principle Executive Offices)	(Zip Code)

Registrant’s telephone number, including area code: (610) 687-8900

Not Applicable

(Former Name or Former Address, If Changed Since Last Report)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):

¨ Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

¨ Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

¨ Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

¨ Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 1.03 Bankruptcy or Receivership.

On May 12, 2016, Penn Virginia Corporation (the “Company”) and certain of its subsidiaries (collectively with the Company, the “Debtors”) filed a voluntary petition for relief (the “Bankruptcy Filing”) under chapter 11 (“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”), under the caption In re Penn Virginia Corporation, et al. Case No. 16-32395. The Debtors will continue to operate their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and the orders of the Bankruptcy Court.

A copy of the press release announcing the Bankruptcy Filing is attached hereto as Exhibit 99.1 and is incorporated herein by reference.

Item 2.04 Triggering Events That Accelerate or Increase a Direct Financial Obligation or an Obligation under an Off-Balance Sheet Arrangement.

The Bankruptcy Filing described in Item 1.03 above constituted an event of default with respect to the following debt instruments (the “Debt Documents”):

• Senior Indenture, dated as of June 15, 2009, as amended, restated, modified, supplemented, or replaced from time to time, among Penn Virginia Corporation, as issuer, the guarantors party thereto, and Wells Fargo Bank, National Association, as Trustee, with respect to (a) $300,000,000 in aggregate principal amount of 7.250% Senior Notes due 2019; and (b) $775,000,000 in aggregate principal amount of 8.500% Senior Notes due 2020; and

• Credit Agreement, dated as of September 28, 2012, as amended, restated, modified, supplemented or replaced from time to time, by and among Penn Virginia Holding Corp., as borrower, Penn Virginia Corporation, as parent, each of the guarantors party thereto, the lenders party thereto and Wells Fargo Bank, National Association, as administrative agent, with respect to approximately $112.6 million principal amount, together with accrued and unpaid interest outstanding.

The Debt Documents provide that as a result of the Bankruptcy Filing the principal and interest due thereunder shall be immediately due and payable. Any efforts to enforce such payment obligations under the Debt Documents are stayed as a result of the Bankruptcy Filing and the creditors’ rights of enforcement in respect of the Debt Documents are subject to the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court.

Item 7.01 Regulation FD Disclosure.

Pursuant to certain confidentiality agreements, the Company provided certain non-public information to certain holders of the Debtors’ $1,075,000,000 in outstanding senior unsecured notes (the “Disclosure Information”). The Disclosure Information is included in Exhibit 99.2 hereto. The Company is making the disclosures herein in accordance with the terms of the confidentiality agreements and Regulation FD.

The financial projections or forecasts included in the Disclosure Information (the “projections”) were not prepared with a view toward public disclosure or compliance with the published guidelines of the Securities and Exchange Commission (the “Commission”) or the guidelines established by the American Institute of Certified Public Accountants regarding projections or forecasts. The projections do not purport to present the Company’s financial condition in accordance with accounting principles generally accepted in the United States. The Company’s independent accountants have not examined, compiled or otherwise applied procedures to the projections and, accordingly, do not express an opinion or any other form of assurance with respect to the projections. The inclusion of the projections should not be regarded as an indication that the Company or its affiliates or representatives consider the projections to be a reliable prediction of future events, and the projections should not be relied upon as such. Neither the Company nor any of its affiliates or representatives has made or makes any representation to any person regarding the ultimate outcome of the Company’s Chapter 11 process or its future performance compared to the projections, and none of them undertakes any obligation to publicly update the projections to reflect circumstances existing after the date when the projections were made or to reflect the occurrence of future events, even in the event that any or all of the assumptions underlying the projections are shown to be in error.

In accordance with General Instruction B.2 of Form 8-K, Exhibit 99.2 is being furnished and shall not be deemed to be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), or otherwise subject to the liabilities of that section, and shall not be deemed to be incorporated by reference into any of the Company’s filings under the Securities Act of 1933, as amended (the “Securities Act”) or the Exchange Act, whether made before or after the date hereof and regardless of any general incorporation language in such filings, except to the extent expressly set forth by specific reference in such a filing.

Cautionary Note Regarding Forward-Looking Statements

Certain statements contained herein, and in the Exhibits hereto, that are not descriptions of historical facts are “forward-looking” statements within the meaning of Section 27A of the Securities Act and Section 21E of 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:

• the ability of the Company to continue as a going concern, to meet financial obligations during the Chapter 11 process and to maintain contracts that are critical to the Company’s operations;

• the ability of the Company and certain of its creditors to develop and consummate one or more plans of reorganization with respect to the Chapter 11 process, including with respect to claims of senior noteholders, trade creditors and equity holders, among others, thereunder;

• the Bankruptcy Court’s rulings in the Chapter 11 case and the outcome of the Chapter 11 process in general;

• the length of time that certain of the Company’s creditors will operate under the Chapter 11 case;

• risks associated with third party motions in the Chapter 11 case, which may interfere with the the Company’s creditors’ ability to develop and consummate one or more plans of reorganization once such plans are developed;

• the effect of the Chapter 11 filings on the Company’s relationships with third parties, regulatory authorities and employees;

• the potential adverse effects of the Chapter 11 process on the Company’s liquidity, results of operations, or business prospects, the Company’s ability to execute its business and a potential restructuring plan;

• increased administrative and legal costs related to the Chapter 11 process and other litigation and the inherent risks involved in a bankruptcy process;

• the sufficiency of the liquidity purported to be made available by the Company’s third party loans and receivables financing approved in connection with the Chapter 11 process; and

• other factors set forth in our periodic filings with the Commission, including the risks set forth in Item 1A of the Company’s Annual Report on Form 10-K for the year ended December 31, 2015 filed with the Commission on March 15, 2016.

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.

The Company cautions that the trading in its securities during the pendency of Chapter 11 proceedings is highly speculative and poses substantial risks. If a plan of reorganization is approved through the Chapter 11 process, it is likely that Company’s existing common stock will be extinguished, and existing equity holders will likely not receive consideration in respect of their existing equity interests. Accordingly, the Company’s future performance and financial results may differ materially and/or adversely from those expressed or implied in any forward-looking statements made by the Company in this Current Report

Item 9.01 Financial Statements and Exhibits.

(d) Exhibits

Exhibit No.	Description
99.1	Press release dated May 12, 2016.
99.2	Disclosure Information provided in connection with discussions with certain of the Company’s creditors.

SIGNATURE

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

	Penn Virginia Corporation
	(Registrant)
By:	/s/ Nancy M. Snyder
Name:	Nancy M. Snyder
Title:	Executive Vice President, Chief Administrative Officer, General Counsel and Corporate Secretary

Date: May 12, 2016

Exhibit Index

Exhibit No.	Description
99.1	Press release dated May 12, 2016.
99.2	Disclosure Information provided in connection with discussions with certain of the Company’s creditors.

EX-99.1

Exhibit 99.1

PENN VIRGINIA CORPORATION FILES VOLUNTARY CHAPTER 11 PETITIONS TO FACILITATE RESTRUCTURING WITH THE OVERWHELMING SUPPORT OF ITS FUNDED DEBT HOLDERS

Restructuring Will Reduce Company’s Long-Term Debt by More Than $1 Billion, With the Support of Approximately 86% of its Senior Noteholders and 100% of its Bank Lenders

Receives Commitment for $25 Million in DIP Financing, up to $128 Million in Committed Exit Financing, and a $50 Million Backstopped Rights Offering

RADNOR, PA, (May 12, 2016) — Penn Virginia Corporation (OTC Pink: PVAH) (“Penn Virginia” or the “Company”) announced that it and certain of its subsidiaries have filed voluntary petitions for relief under chapter 11 of the U.S. Bankruptcy Code in the United States Bankruptcy Court for the Eastern District of Virginia, Richmond Division, to facilitate the deleveraging of their consolidated balance sheet through a prearranged restructuring that will reduce the Company’s long-term debt by more than $1 billion. In connection with the chapter 11 filing, the Company announced its entry into a restructuring support agreement with holders of 87% (or $1.03 billion) of the Company’s nearly $1.20 billion in total funded-debt obligations. Subject to Court approval, the Company has received a commitment for $25 million in debtor-in-possession (DIP) financing from its RBL lenders, which combined with the Company’s cash reserves and cash from operations, is expected to provide liquidity throughout the chapter 11 process. Additionally, the Company has obtained a commitment for up to $128 million in exit financing from its RBL lenders, led by Wells Fargo as agent, as well as a $50 million rights offering that is backstopped and supported by certain of the Company’s senior unsecured noteholders.

“This is an important step forward for Penn Virginia,” said Edward B. Cloues, II, Chairman and interim Chief Executive Officer of Penn Virginia. “Once the restructuring is implemented, the Company will have substantially less debt and a much stronger balance sheet. We will be in a better position to navigate the current industry environment and leverage the value of our underlying assets and operational expertise. Importantly, the announcement today provides Penn Virginia with an expedited plan to emerge from this process with committed financing, a new money investment, and a clear path to future production and success.”

As part of the Company’s “first day” motions, Penn Virginia has asked the Court for authorization to generally continue its ongoing employee compensation and benefit programs without change or interruption. Additionally, Penn Virginia has filed a Plan of Reorganization and Disclosure Statement, which incorporate the terms of the restructuring agreement and other commitments made by the RBL Lenders and the supporting noteholders. The Company anticipates emerging from chapter 11 by the end of the summer.

“Like many other exploration and production companies, Penn Virginia has been significantly affected by the recent and continued dramatic decline in oil and natural gas prices. We believe using the chapter 11 process is the most efficient way to achieve our financial objectives and deleverage the Company’s balance sheet,” said Mr. Cloues. “The ongoing commitment from our valued business partners and hard-working employees is a testament to the strength of our organization, and we sincerely appreciate their loyalty and support.”

Jefferies is acting as financial advisor, Alvarez & Marsal is acting as restructuring advisor (with R. Seth Bullock of Alvarez & Marsal serving as Chief Restructuring Officer), and Kirkland & Ellis LLP is acting as legal counsel to the Company in connection with the debt restructuring. PJT Partners is acting as financial advisor and Milbank, Tweed, Hadley & McCloy LLP is acting as legal advisor to the ad hoc committee of noteholders. Opportune LLP is acting as financial advisor and Bracewell LLP is acting as legal advisor to Wells Fargo (as agent) and the RBL lenders. For more information about the chapter 11 case, including access to Court documents, please visit: http://dm.epiq11.com/PVA.

* * * * *

ABOUT PENN VIRGINIA CORPORATION

Penn Virginia Corporation is an independent oil and gas company engaged in the exploration, development and production of oil, NGLs and natural gas in various domestic onshore regions of the United States, with a primary focus in the Eagle Ford Shale in South Texas. For more information, please visit the Company’s website at www.pennvirginia.com.

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. Because such statements include risks, uncertainties and contingencies, actual results may differ materially from those expressed or implied by such forward-looking statements. Additional information concerning these and other factors can be found in our press releases and public periodic filings with the SEC. 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. 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.

CONTACTS

Sard Verbinnen & Co.

Bryan Locke/Patrick Scanlan

(212) 687-8080

EX-99.2

Exhibit 99.2

Penn Virginia Corporation Aggregated Cleansing Materials May 2016 / Confidential Jefferies LLC, Alvarez & Marsal North America LLC, Kirkland & Ellis LLP Member SIPC

PVA Cash Flow Summary (1-Rig Drilling Schedule) Assumes NYMEX Strip Pricing as of 5/6/2016 Key Assumptions ? Business plan contemplates a 1-rig drilling schedule ? Assumes crude oil minimum volume commitment of 15 MBbls/d gross and current midstream contractual rates Summary Cash Flows Sep-16 Q4 ‘16 FY ‘16 Q1 ‘17 Q2 ‘17 Q3 ‘17 Q4 ‘17 FY ‘17 Q1 ‘18 Q2 ‘18 Q3 ‘18 Q4 ‘18 FY ‘18 Gross Wells Drilled 2.0 5.0 7.0 6.0 6.0 6.0 7.0 25.0 5.0 7.0 6.0 6.0 24.0 Net Daily Production (MBoe/d) 9.6 9.7 9.7 12.0 13.8 13.6 15.3 13.7 14.4 16.8 16.2 17.0 16.1 Benchmark Crude Oil Price ($ / Bbl) $ 47.72 $ 48.35 $ 48.20 $ 48.96 $ 49.41 $ 49.75 $ 50.19 $ 49.58 $ 50.80 $ 51.17 $ 51.59 $ 52.11 $ 51.42 Benchmark Gas Price ($ / MMBtu) $ 2.37 $ 2.70 $ 2.61 $ 3.09 $ 2.88 $ 2.93 $ 3.05 $ 2.99 $ 3.24 $ 2.86 $ 2.91 $ 3.01 $ 3.00 Product Revenue $ 9 $ 29 $ 39 $ 38 $ 45 $ 46 $ 53 $ 181 $ 49 $ 58 $ 58 $ 61 $ 227 Other Income 0 0 0 0 0 0 0 1 0 0 0 0 1 Total Revenue $ 9 $ 30 $ 39 $ 38 $ 45 $ 46 $ 53 $ 182 $ 49 $ 59 $ 58 $ 62 $ 228 Operating Expenses $ (3) $ (10) $ (13) $ (11) $ (13) $ (13) $ (14) $ (51) $ (13) $ (15) $ (15) $ (15) $ (59) Minimum Volume Commitment (1) (1) (2) (3) (1) (0) (0) — (1) (0) ——— (0) Production Taxes (1) (2) (2) (2) (3) (3) (3) (11) (3) (4) (3) (4) (14) General and Administrative (2) (1) (4) (6) (4) (4) (4) (4) (17) (4) (4) (4) (4) (17) Total Operating Costs $ (6) $ (18) $ (24) $ (19) $ (20) $ (20) $ (21) $ (80) $ (21) $ (23) $ (22) $ (23) $ (89) EBITDA $ 3 $ 12 $ 15 $ 20 $ 26 $ 26 $ 31 $ 103 $ 29 $ 36 $ 35 $ 38 $ 138 Total Capital Expenditures $ (7) $ (28) $ (35) $ (28) $ (28) $ (28) $ (34) $ (118) $ (24) $ (32) $ (29) $ (29) $ (114) Change in Net Working Capital 8 2 11 (4) 1 (1) (1) (5) 0 (3) 0 1 (2) Asset-Level Cash Flow $ 4 $ (14) $ (9) $ (12) $ (2) $ (3) $ (4) $ (20) $ 5 $ 1 $ 6 $ 10 $ 23 Cum. Asset-Level Cash Flow $ 4 $ (9) $ (9) $ (22) $ (23) $ (26) $ (30) $ (30) $ (25) $ (23) $ (17) $ (7) $ (7) (1) Contracts remain subject to ongoing negotiations. (2) Assumes annual G&A of $16.875 MM. Jefferies LLC, Alvarez & Marsal North America LLC, Kirkland & Ellis LLP / May 2016 1 For Settlement Discussion Purposes Only / Subject to FRE 408 / Pursuant to NDA

PVA Cash Flow Summary (0-Rig Drilling Schedule) Assumes NYMEX Strip Pricing as of 5/6/2016 Key Assumptions ? Business plan contemplates no development drilling ? Assumes crude oil minimum volume commitment of 15 MBbls/d gross and current midstream contractual rates Summary Cash Flows Sep-16 Q4 ‘16 FY ‘16 Q1 ‘17 Q2 ‘17 Q3 ‘17 Q4 ‘17 FY ‘17 Q1 ‘18 Q2 ‘18 Q3 ‘18 Q4 ‘18 FY ‘18 Gross Wells Drilled —————————————Net Daily Production (MBoe/d) 10.1 9.4 9.6 8.7 8.1 7.6 7.1 7.9 6.8 6.4 6.2 5.9 6.3 Benchmark Crude Oil Price ($ / Bbl) $ 47.72 $ 48.35 $ 48.20 $ 48.96 $ 49.41 $ 49.75 $ 50.19 $ 49.58 $ 50.80 $ 51.17 $ 51.59 $ 52.11 $ 51.42 Benchmark Gas Price ($ / MMBtu) $ 2.37 $ 2.70 $ 2.61 $ 3.09 $ 2.88 $ 2.93 $ 3.05 $ 2.99 $ 3.24 $ 2.86 $ 2.91 $ 3.01 $ 3.00 Product Revenue $ 10 $ 28 $ 38 $ 26 $ 25 $ 24 $ 22 $ 97 $ 21 $ 20 $ 20 $ 19 $ 80 Other Income 0 0 0 0 0 0 0 1 0 0 0 0 1 Total Revenue $ 10 $ 29 $ 38 $ 26 $ 25 $ 24 $ 23 $ 98 $ 21 $ 20 $ 20 $ 19 $ 81 Operating Expenses $ (3) $ (9) $ (13) $ (9) $ (9) $ (8) $ (8) $ (34) $ (8) $ (8) $ (8) $ (8) $ (31) Minimum Volume Commitment (1) (1) (2) (3) (3) (3) (3) (4) (13) (4) (4) (4) (4) (16) Production Taxes (1) (2) (2) (2) (1) (1) (1) (6) (1) (1) (1) (1) (5) General and Administrative (2) (1) (4) (5) (4) (4) (4) (4) (15) (4) (4) (4) (4) (15) Total Operating Costs $ (6) $ (17) $ (23) $ (17) $ (17) $ (17) $ (17) $ (68) $ (17) $ (17) $ (17) $ (17) $ (67) EBITDA $ 4 $ 11 $ 15 $ 9 $ 8 $ 7 $ 6 $ 30 $ 5 $ 4 $ 3 $ 3 $ 14 Total Capital Expenditures $ (0) $ (0) $ (0) $ (0) $ (0) $ (0) $ (0) $ (0) $ (0) $ (0) $ (0) $ (0) $ (0) Change in Net Working Capital 1 0 1 1 1 0 0 2 0 1 0 0 1 Asset-Level Cash Flow $ 5 $ 12 $ 16 $ 10 $ 9 $ 7 $ 6 $ 31 $ 5 $ 4 $ 3 $ 2 $ 15 Cum. Asset-Level Cash Flow $ 5 $ 16 $ 16 $ 26 $ 35 $ 42 $ 47 $ 47 $ 52 $ 56 $ 60 $ 62 $ 62 (1) Contracts remain subject to ongoing negotiations. (2) Assumes annual G&A of $15.1 MM. Jefferies LLC, Alvarez & Marsal North America LLC, Kirkland & Ellis LLP / May 2016 2 For Settlement Discussion Purposes Only / Subject to FRE 408 / Pursuant to NDA

PVA Cash Flow Summary (3 MMBOE Case) Assumes NYMEX Strip Pricing as of 5/6/2016 Key Assumptions ? Business plan contemplates a drilling plan designed to maintain approximately 3 MMBOE of annual net production ? Assumes no crude oil minimum volume commitment Summary Cash Flows Sep-16 Q4 ‘16 FY ‘16 Q1 ‘17 Q2 ‘17 Q3 ‘17 Q4 ‘17 FY ‘17 Q1 ‘18 Q2 ‘18 Q3 ‘18 Q4 ‘18 FY ‘18 Gross Wells Drilled 1.0 — 1.0 —— 3.0 — 3.0 3.0 — 3.0 — 6.0 Net Wells Drilled 0.5 — 0.5 —— 2.9 — 2.9 2.6 — 2.9 — 5.5 Net Daily Production (MBoe/d) 10.1 10.1 10.1 9.2 8.4 7.8 9.5 8.8 8.1 9.4 7.9 9.1 8.6 Benchmark Crude Oil Price ($ / Bbl) $ 47.72 $ 48.35 $ 48.20 $ 48.96 $ 49.41 $ 49.75 $ 50.19 $ 49.58 $ 50.80 $ 51.17 $ 51.59 $ 52.11 $ 51.42 Benchmark Gas Price ($ / MMBtu) $ 2.37 $ 2.70 $ 2.61 $ 3.09 $ 2.88 $ 2.93 $ 3.05 $ 2.99 $ 3.24 $ 2.86 $ 2.91 $ 3.01 $ 3.00 Product Revenue $ 10 $ 31 $ 41 $ 28 $ 26 $ 25 $ 31 $ 110 $ 26 $ 31 $ 26 $ 31 $ 115 Hedging Gains / (Losses) —————————————Other Income 0 0 0 0 0 0 0 1 0 0 0 0 1 Total Revenue $ 10 $ 31 $ 41 $ 28 $ 26 $ 25 $ 32 $ 111 $ 26 $ 32 $ 27 $ 32 $ 116 Operating Expenses $ (3) $ (10) $ (13) $ (9) $ (9) $ (9) $ (10) $ (37) $ (9) $ (10) $ (9) $ (10) $ (37) Minimum Volume Commitment —————————————Production Taxes (1) (2) (2) (2) (2) (1) (2) (7) (2) (2) (2) (2) (7) General and Administrative (1) (1) (4) (5) (4) (4) (4) (4) (15) (4) (4) (4) (4) (15) Total Operating Costs $ (5) $ (16) $ (21) $ (15) $ (14) $ (14) $ (16) $ (58) $ (14) $ (16) $ (14) $ (15) $ (59) EBITDA $ 5 $ 16 $ 20 $ 14 $ 12 $ 11 $ 16 $ 52 $ 12 $ 16 $ 12 $ 16 $ 56 Total Capital Expenditures $ (2) $ (3) $ (5) $ (0) $ (0) $ (16) $ (0) $ (16) $ (15) $ (0) $ (14) $ (0) $ (29) Change in Net Working Capital 3 (3) 0 1 1 0 (1) 1 1 (1) 1 (1) 0 Non-Recurring Expenses —————————————Asset-Level Cash Flow $ 5 $ 10 $ 15 $ 15 $ 13 $ (4) $ 15 $ 38 $ (2) $ 15 $ (1) $ 15 $ 28 Interest Expense and Undrawn Line $ (0) $ (2) $ (2) $ (2) $ (2) $ (2) $ (2) $ (6) $ (2) $ (2) $ (2) $ (2) $ (7) Levered Cash Flow $ 5 $ 8 $ 13 $ 13 $ 11 $ (6) $ 13 $ 31 $ (3) $ 14 $ (3) $ 13 $ 21 RBL Draw / (Paydown) (5) (8) (13) (13) (11) 6 (13) (31) 3 (14) 3 (13) (21) Net Cash Flow $—$—$—$—$—$—$—$—$—$—$—$—$—RBL, BOP $ 101 $ 96 $ 101 $ 87 $ 74 $ 63 $ 69 $ 87 $ 56 $ 60 $ 46 $ 49 $ 56 RBL, EOP $ 96 $ 87 $ 87 $ 74 $ 63 $ 69 $ 56 $ 56 $ 60 $ 46 $ 49 $ 36 $ 36 Cash, EOP $ 10 $ 10 $ 10 $ 10 $ 10 $ 10 $ 10 $ 10 $ 10 $ 10 $ 10 $ 10 $ 10 Net Debt, EOP $ 86 $ 77 $ 77 $ 64 $ 53 $ 59 $ 46 $ 46 $ 50 $ 36 $ 39 $ 26 $ 26 (1) Assumes annual G&A of $15.1 MM. Jefferies LLC, Alvarez & Marsal North America LLC, Kirkland & Ellis LLP / May 2016 3 For Settlement Discussion Purposes Only / Subject to FRE 408 / Pursuant to NDA

PVA Rolling PDP PV-10 Summary (1-Rig Drilling Schedule) Assumes NYMEX Strip Pricing as of 5/6/2016 Rolling PDP PV-10 Value ($MM) $ 453 $ 433 $ 412 $ 363 $ 361 $ 317 $302 $ 284 $ 258 $278 $ 231 $268 $ 168 $ 173 $254 $241 $242 $89 $ 113 $56 $10 $232 $222 $213 $ 204 $ 196 $ 188 $ 181 $ 175 $ 169 Q1 16 Q2 16 Q3 16 Q4 16 Q1 17 Q2 17 Q3 17 Q4 17 Q1 18 Q2 18 Q3 18 Q4 18 Existing PDP New PDP (From Development Drilling) Note: PDP per PVA management estimates; excludes shut-ins for offset fracs which are included in cash flow model. Note: Production, operating and commercial assumptions, capital costs and drilling schedule provided by PVA. Jefferies LLC, Alvarez & Marsal North America LLC, Kirkland & Ellis LLP / May 2016 4 For Settlement Discussion Purposes Only / Subject to FRE 408 / Pursuant to NDA

2016-2018 Net D&C Capex and Wells Drilled (1-Rig Drilling Schedule) Wells Drilled vs. Net Capex 8.0 $40 7.0 7.0 7.0 6.8 6.6 6.0 6.0 5.8 6.0 5.8 6.0 5.8 6.0 5.8 6.0 5.8 $30 5.0 5.0 5.0 4.8 4.6 Drilled M 4.0 $20 M s $ Well 3.0 2.0 2.0 2.0 $10 1.4 1.0 1.0 — — $- Q1 16 Q2 16 Q3 16 Q4 16 Q1 17 Q2 17 Q3 17 Q4 17 Q1 18 Q2 18 Q3 18 Q4 18 Gross Wells Drilled Net Wells Drilled Net D&C Capex Note: Production, operating and commercial assumptions, capital costs and drilling schedule provided by PVA. Jefferies LLC, Alvarez & Marsal North America LLC, Kirkland & Ellis LLP / May 2016 5 For Settlement Discussion Purposes Only / Subject to FRE 408 / Pursuant to NDA

PVA Cash Flow Summary (3 MMBOE Case) Assumes NYMEX Strip Pricing as of 5/6/2016 Monthly PVA Cash Flows Sep-16 Oct-16 Nov-16 Dec-16 Jan-17 Feb-17 Mar-17 Apr-17 May-17 Jun-17 Jul-17 Aug-17 Total Total Net Production (MBoe) 305.9 292.9 326.9 303.6 290.0 281.1 270.5 263.1 255.7 249.7 243.5 238.0 3,321.1 Net Daily Production (MBoe/d) 10.1 9.6 10.8 10.0 9.5 9.2 8.9 8.7 8.4 8.2 8.0 7.8 9.1 Benchmark Crude Oil Price ($ / Bbl) $ 47.72 $ 48.04 $ 48.37 $ 48.65 $ 48.79 $ 48.97 $ 49.13 $ 49.27 $ 49.41 $ 49.54 $ 49.63 $ 49.74 $ 48.94 Benchmark Gas Price ($ / MMBtu) $ 2.37 $ 2.45 $ 2.67 $ 2.98 $ 3.11 $ 3.10 $ 3.05 $ 2.87 $ 2.86 $ 2.89 $ 2.93 $ 2.94 $ 2.85 Oil Revenue $ 8.5 $ 8.4 $ 9.5 $ 9.0 $ 8.6 $ 7.6 $ 8.1 $ 7.6 $ 7.6 $ 7.2 $ 7.3 $ 7.1 $ 96.5 Gas Revenue 0.7 0.7 0.8 0.9 0.9 0.8 0.8 0.7 0.8 0.7 0.7 0.7 9.3 NGL Revenue 0.5 0.5 0.5 0.5 0.5 0.4 0.5 0.4 0.4 0.4 0.4 0.4 5.5 Other Income 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 1.0 Total Revenue $ 9.8 $ 9.7 $ 10.9 $ 10.5 $ 10.1 $ 8.9 $ 9.4 $ 8.9 $ 8.9 $ 8.4 $ 8.5 $ 8.3 $ 112.3 Operating Expenses $ (3.2) $ (3.2) $ (3.4) $ (3.3) $ (3.2) $ (3.0) $ (3.1) $ (3.0) $ (3.0) $ (2.9) $ (2.9) $ (2.9) $ (37.2) MVC —— — — —————— ———Production Taxes (0.6) (0.6) (0.6) (0.6) (0.6) (0.5) (0.6) (0.5) (0.5) (0.5) (0.5) (0.5) (6.7) General and Administrative (1.3) (1.3) (1.3) (1.3) (1.3) (1.3) (1.3) (1.3) (1.3) (1.3) (1.3) (1.3) (15.1) Total Operating Expenses $ (5.0) $ (5.0) $ (5.3) $ (5.2) $ (5.1) $ (4.8) $ (4.9) $ (4.8) $ (4.8) $ (4.7) $ (4.7) $ (4.7) $ (59.0) EBITDA $ 4.7 $ 4.7 $ 5.6 $ 5.3 $ 5.0 $ 4.1 $ 4.5 $ 4.1 $ 4.1 $ 3.7 $ 3.8 $ 3.7 $ 53.3 Total Capital Expenditures (1) $ (2.3) $ (0.0) $ (2.8) $ (0.0) $ (0.0) $ (0.0) $ (0.0) $ (0.0) $ (0.0) $ (0.0) $ (15.6) $ (0.0) $ (21.0) ? in Net Working Capital 2.8 (2.1) 1.9 (2.4) 0.4 1.0 (0.3) 0.5 (0.1) 0.4 15.6 (15.4) 2.2 Non-Recurring Expenses —— — — —————— ———PA Firm Pipeline Payments —— — — —————— ———WV Firm Pipeline Payments —— — — —————— ———Unlevered Free Cash Flow $ 5.2 $ 2.5 $ 4.6 $ 2.8 $ 5.4 $ 5.1 $ 4.2 $ 4.6 $ 4.0 $ 4.1 $ 3.7 $ (11.8) $ 34.5 Interest Expense and Undrawn Line Fee (0.5) (0.5) (0.5) (0.5) (0.5) (0.5) (0.5) (0.5) (0.5) (0.5) (0.5) (0.5) (6.3) Draw / (Paydown) of Exit RBL (4.7) (2.0) (4.1) (2.3) (4.9) (4.5) (3.6) (4.0) (3.5) (3.6) (3.2) 12.3 (28.2) Levered Free Cash Flow $—$—$ —$ —$ —$—$—$—$—$—$ —$—$—EOP Cash Balance $ 10.0 $ 10.0 $ 10.0 $ 10.0 $ 10.0 $ 10.0 $ 10.0 $ 10.0 $ 10.0 $ 10.0 $ 10.0 $ 10.0 $ 10.0 Debt Schedule: Total Debt (Exit RBL) $ 95.9 $ 93.9 $ 89.8 $ 87.5 $ 82.6 $ 78.1 $ 74.4 $ 70.4 $ 66.9 $ 63.3 $ 60.1 $ 72.5 $ 72.5 Net Debt $ 85.9 $ 83.9 $ 79.8 $ 77.5 $ 72.6 $ 68.1 $ 64.4 $ 60.4 $ 56.9 $ 53.3 $ 50.1 $ 62.5 $ 62.5 Rolling PDP PV-10 $ 241.3 $ 237.2 $ 247.0 $ 242.4 $ 238.0 $ 234.6 $ 230.7 $ 227.3 $ 223.7 $ 220.6 $ 217.4 $ 214.2 $ 214.2 PDP PV-10 / Secured Debt 2.51x 2.53x 2.75x 2.77x 2.88x 3.00x 3.10x 3.23x 3.34x 3.48x 3.61x 2.96x 2.96x $ Opex / Boe $ 10.49 $ 10.96 $ 10.37 $ 10.87 $ 11.08 $ 10.67 $ 11.44 $ 11.41 $ 11.76 $ 11.71 $ 12.05 $ 12.19 $ 11.20 $ G&A / Boe $ 4.11 $ 4.30 $ 3.85 $ 4.14 $ 4.34 $ 4.48 $ 4.65 $ 4.78 $ 4.92 $ 5.04 $ 5.17 $ 5.29 $ 4.55 % Prod. Taxes of Revenue 6.0% 6.0% 6.0% 6.0% 6.0% 6.0% 6.0% 6.0% 6.0% 6.0% 6.0% 6.0% 6.0% Notes: Assumes $15.1 MM annual general and administrative costs. Other Income reflects approximately $80k / month of water and marketing revenue received from WI partners. Assumes Exit RBL interest expense of L+300 to L+400, depending on amount drawn. PDP PV-10 reflects only asset-level costs (excludes G&A and working capital). PV-9 at 4/30/2016 of $ 272 MM at NYMEX, $ 209 MM at NYMEX minus 10% and $ 147 MM at NYMEX minus 20%, PV-9 as of 11/30/2016 of $ 254 MM at NYMEX, $195 MM at NYMEX minus 10% and $135 MM at NYMEX minus 20% and PV-9 as of 4/30/2017 of $234 MM at NYMEX, $177 MM at NYMEX minus 10% and $ 121 MM at NYMEX minus 20%. (1) November 2016 D&C capital expenditures include completion costs for the previously drilled Sable wells. Jefferies LLC, Alvarez & Marsal North America LLC, Kirkland & Ellis LLP / May 2016 6 For Settlement Discussion Purposes Only / Subject to FRE 408 / Pursuant to NDA

Production Overview Production Mix Q1 2016 Q4 2018 Oil: 70% Oil: 78% 1-Rig Case Gas: 15% Gas: 12% NGL: 15% NGL: 11% Oil: 70% Oil: 65% 0-Rig Case (No Development Drilling) Gas: 15% Gas: 19% NGL: 15% NGL: 15% Average Projected Differentials Projected South Texas Differentials Oil $ (5.67) + LLS spread off WTI Gas $ (0.11) NGL 24% of WTI oil benchmark Jefferies LLC, Alvarez & Marsal North America LLC, Kirkland & Ellis LLP / May 2016 7 For Settlement Discussion Purposes Only / Subject to FRE 408 / Pursuant to NDA

Sources and Uses Sources and Uses 5/11/2016 to 9/1/2016 ($Millions) The preliminary sources and uses analysis based on an illustrative transaction (assumes 3 MMBOE and $15.1MM G&A Case) Key Assumptions ? 4-Month prenegotiated case ? $50mm injection of capital from the bondholder and a full- equitization of bondholder claims Sources Uses Low High Low High ? $128mm pro forma borrowing base that remains constant over the 12 months post emergence Total Capital Required $ 147 $ 156 Existing RBL at Petition $ 112 Capital Provided by Bondholders 50 Net Costs (through 9/1/2016) $ 35 $ 44 RBL draw at 8/5/2016 $ 97 $ 106 Net Operating Cash Flow (35) (35) Restructuring Costs(1) 31 38 Employee Related Costs(2) 3 5 Interest and Fees 6 6 Cash to Balance Sheet 10 10 Contingency Costs 6 6 Vendor Payments & Others(3) 15 15 Total Sources $ 147 $ 156 Total Uses $ 147 $ 156 (1) Restructuring costs include debtor, bondholder and RBL advisory fees and other fees and expenses. (2) Includes severance and KEIP / KERP related costs. Subject to ongoing negotiations. (3) Includes utility deposits and potential lienholder payments. Jefferies LLC, Alvarez & Marsal North America LLC, Kirkland & Ellis LLP / May 2016 8 For Settlement Discussion Purposes Only / Subject to FRE 408 / Pursuant to NDA

D&M YE 2015 Proved Reserve Report summary Key Points ? Based on year-end 2015 DeGolyer and MacNaughton Reserve Report ? Assumes 5/6/2016 NYMEX strip pricing for five years and held flat thereafter Gross Net Reserves Capex PV-10 PV-15 PV-20 Reserve Category Locations Oil (MBbls) Gas (MMcf) NGL (MBbls) Total (MBoe) ($ MM) ($ MM) ($ MM) ($ MM) Proved Developed Producing 426 19,968 38,020 6,321 32,626 $ 16 $ 317 $ 264 $ 226 Proved Developed Shut-In 3 576 377 77 716 7 4 2 1 Proved Developed Non-Producing 15 — — 1 (1) (1) (1) Total Proved Developed 444 20,544 38,397 6,398 33,342 $ 23 $ 320 $ 265 $ 226 Proved Undeveloped 69 9,700 5,976 1,202 11,898 198 (9) (31) (44) Total Proved 513 30,244 44,373 7,600 45,240 $ 221 $ 311 $ 234 $ 182 Jefferies LLC, Alvarez & Marsal North America LLC, Kirkland & Ellis LLP / May 2016 9 For Settlement Discussion Purposes Only / Subject to FRE 408 / Pursuant to NDA

Operational Wells Update Well Performance Analysis – Generation 1 Slickwater Wells Key Points Generation 1: Slickwater Wells Munson Munson Bertha Bertha Bertha Chicken Hawk Berger ? The Munson 11H has a normalized 30-day IP of 1,436 11H 12H 2H 3H 4H 1H 1H Boe/d 1st Production Date 12-Aug 12-Aug 8-Sep 7-Sep 6-Sep 18-Sep 20-Sep ? The Munson 12H had operational issues as heel Days on Production (1) 270 270 243 244 245 233 231 stages of the well frac’d into Normalized IP30 (Bo/d) 1,345 571 778 1,078 1,089 1,218 1,327 the Austin Chalk so it was excluded from the analysis Normalized IP30 (Boe/d) 1,436 616 848 1,171 1,177 1,361 1,482 ? Both wells have responded Lat. Length (Ft.) 1,905 3,635 4,876 6,083 5,140 6,151 5,355 favorably to gas lift Stages 10 15 21 26 23 25 22 ? The Bertha 2H, 3H and 4H Perfs / Stage 90 90 90 90 90 60 60 have been on production for over eight months Fluid (gal /ft.) 2,170 2,168 2,180 1,970 2,116 1,917 1,941 ? Normalized IP 30: 1,065 Well Spacing (Ft.) 600+ 600+ <400 <400 <400 600+ 600+ Boe/d Proppant (Lbs / Foot) 2,035 1,722 2,040 2,115 2,086 1,958 2,025 ? Bertha wells were spaced Tubing Size 2-3/8” 2-3/8” 2-7/8” 2-7/8” 2-7/8” 2-7/8” 2-7/8” less than 400’ apart, testing Artificial Lift Gas Lift Gas Lift Gas Lift Gas Lift Gas Lift Gas Lift Gas Lift downspacing program 100 Mesh | 40/70 55 / 45 52 / 48 55 / 45 53 / 47 55 / 45 55 / 45 54 / 46 ? Wells were flowed with a conservative choke Perf Distribution Even Even Even Even Even Even Even ? Wells are now on gas lift Actual Drilling Cost ($ MM) $5.4 $4.6 $6.2 $7.4 $6.0 $6.0 $5.9 ? Chicken Hawk 1H and Berger 1H wells have been producing for over seven months ? Normalized IP 30: 1,421 Boe/d ? Employed limited entry ? Wells were flowed back with a more aggressive choke profile Source: IHS. Note: Initial production rates normalized to 6,000 foot lateral length. (1) As of May 8, 2016. Jefferies LLC, Alvarez & Marsal North America LLC, Kirkland & Ellis LLP / May 2016 10 For Settlement Discussion Purposes Only / Subject to FRE 408 / Pursuant to NDA

Operational Wells Update (Cont’d) Well Performance Analysis – Generation 2 Slickwater Wells Key Points Generation 2: Slickwater Wells Cinco J Cinco J Cinco J L&J Lee L&J Lee L&J Lee Washington Washington ? Generation 2 slickwater wells utilized limited entry with 45 Ranch 3H Ranch 4H Ranch 5H 4H 5H 6H 2H 3H Perfs / Stage and a tapered perf design intended to 1st Production Date 2-Nov 31-Oct 29-Oct 7-Dec 27-Nov 27-Nov 13-Jan 12-Jan achieve better distribution of Days on Production(1) 188 190 192 153 163 163 116 117 proppant Normalized IP30 (Bo/d) 1,270 910 1,073 522 1,485 1,150 892 692 ? The Cinco J Ranch wells have been on production for over Normalized IP30 (Boe/d) 1,397 1,028 1,205 575 1,649 1,275 950 738 six months Lat. Length (Ft.) 5,971 5,676 5,297 4,021 3,442 4,372 5,197 5,356 ? Employed limited entry and more fluid / ft. Stages 24 23 22 16 14 18 22 22 ? Wells are being flowed Perfs / Stage 45 45 45 45 45 45 45 45 back with a more Fluid (gal /ft.) 2,231 2,324 2,177 2,084 2,196 2,252 1,931 1,925 aggressive choke program Well Spacing (Ft.) 600+ 600+ 600+ 600+ 600+ 600+ 600+ 600+ ? Cinco J Ranch 4H tested 72% 100 Mesh and the Proppant (Lbs / Foot) 1,823 2,205 1,922 1,758 1,980 2,122 2,274 2,244 well has underperformed ~50/50 blend, and is not Tubing Size 2-3/8” 2-3/8” 2-3/8” 2-3/8” 2-3/8” 2-3/8” 2-3/8” 2-3/8” included in the type curve Artificial Lift Gas Lift Gas Lift Gas Lift Gas Lift Gas Lift Gas Lift Gas Lift Gas Lift ? L&J Lee wells were choked 100 Mesh | 40/70 58 / 42 72 / 28 54 / 46 52 / 48 53 / 47 54 / 46 54/45 54/45 back due to extended clean out time for the L&J Lee 4H Perf Distribution Tapered Tapered Tapered Tapered Tapered Tapered Tapered Tapered Actual Drilling Cost ($ MM) $6.1 $5.2 $5.6 $4.9 $3.8 $4.3 $5.3 $5.8 Source: IHS. Note: Initial production rates normalized to 6,000 foot lateral length. (1) As of May 8, 2016. Jefferies LLC, Alvarez & Marsal North America LLC, Kirkland & Ellis LLP / May 2016 11 For Settlement Discussion Purposes Only / Subject to FRE 408 / Pursuant to NDA

Operational Wells Update (Cont’d) Well Performance Analysis – Generation 3 Slickwater Wells Key Points Generation 3: Slickwater Wells ??Generation 3 fracs on Hawg Hawg Hawg Hawg Hunter wells have delivered the highest performing wells Hunter 3H Hunter 4H Hunter 5H to date ? Average normalized 30-day 1st Production Date 6-Feb 6-Feb 10-Feb IP rates of >1,500 Bo/d for Hawg Hunter wells Days on Production(1) 92 92 88 ? All 3 Hawg Hunter wells rank within the top 1% of Normalized IP30 (Bo/d) 1,494 1,574 1,460 Eagle Ford oil 30-day IPs despite a conservative Normalized IP30 (Boe/d) 1,592 1,695 1,563 choke profile There were two key Lat. Length (Ft.) 5,987 6,979 7,769 ? adjustments to this frac design that likely contributed Stages 22 29 31 to increased fracture network complexity yielding early time Perfs / Stage 54 55 54 productivity improvement Fluid (gal /ft.) 2,074 2,324 2,130 ? Tapered perforating schedule in concert with Well Spacing (Ft.) 600+ 600+ 600+ more perforations (54-55 vs. 45 Perfs / Stage) and Proppant (Lbs / Foot) 1,685 1,788 1,711 increased linear gel sweeps ? Similar fluid / ft. to Tubing Size NA NA NA generation 2 (2,176 vs. 2,140 gal /ft.) Artificial Lift Flowing Flowing Flowing 100 Mesh | 40/70 59/41 60/40 60/40 Perf Distribution Tapered Tapered Tapered Actual Drilling Cost ($ MM) $5.2 $5.4 $5.7 Source: IHS. Note: Initial production rates normalized to 6,000 foot lateral length. (1) As of May 8, 2016. Jefferies LLC, Alvarez & Marsal North America LLC, Kirkland & Ellis LLP / May 2016 12 For Settlement Discussion Purposes Only / Subject to FRE 408 / Pursuant to NDA

2016-2018 Quarterly Net Production (3 MMBOE Annual Production – Maintenance Case) Eagle Ford 20.0 oe/d) 16.0 14.2 2.0 11.1 9.6 ( MB 12.0 1.7 1.5 9.3 8.5 7.7 7.1 8.8 7.4 8.8 7.3 8.5 n 8.0 1.5 1.3 1.2 1.1 1.1 1.0 o i 10.5 1.3 1.3 1. 1.1 2 1. 1.0 1 1. 1.0 0 1.1 1. 1.0 0 1.1 0. 0.9 9 1.0 oduct 4.0— 8.1 7.0 6.8 6.2 5.6 5.1 6.7 5.5 6.7 5.4 6.5 Pr Q1 2016 Q2 2016 Q3 2016 Q4 2016 Q1 2017 Q2 2017 Q3 2017 Q4 2017 Q1 2018 Q2 2018 Q3 2018 Q4 2018 t e N Oil (MBbls/d) Gas (MBoe/d) NGL (MBbls/d) Granite Wash 2.0 e /d) 1.5 MBo 1.1 ( 1.0 0.3 0.8 0.8 0.8 0.8 0.7 0.7 0.7 0.7 0.7 0.6 0.6 t ion 0.5 0.6 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 duc 0.5 0.5 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 Pro—0.2 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 t Q1 2016 Q2 2016 Q3 2016 Q4 2016 Q1 2017 Q2 2017 Q3 2017 Q4 2017 Q1 2018 Q2 2018 Q3 2018 Q4 2018 e N Oil (MBbls/d) Gas (MBoe/d) NGL (MBbls/d) Total Company 20.0 e /d) 16.0 15.3 o 2.3 11.9 10.4 10.1 (MB 12.0 2.3 1.7 9.2 8.4 7.8 9.5 8.1 9.4 7.9 9.1 n 2.0 1.5 1.5 1.3 1.2 1. 1.3 1.2 o 8.0 1.8 1.7 1.6 1.5 2 1.5 1.1 1.4 1.1 1. 1.2 4 ti 10.7 1.4 1.4 1.3 duc 4.0 8.2 7.1 7.0 6.3 5.7 5.3 6.8 5.6 6.8 5.5 6.6 Pro— t Q1 2016 Q2 2016 Q3 2016 Q4 2016 Q1 2017 Q2 2017 Q3 2017 Q4 2017 Q1 2018 Q2 2018 Q3 2018 Q4 2018 e N Oil (MBbls/d) Gas (MBoe/d) NGL (MBbls/d) Jefferies LLC, Alvarez & Marsal North America LLC, Kirkland & Ellis LLP / May 2016 13 For Settlement Discussion Purposes Only / Subject to FRE 408 / Pursuant to NDA

2016-2018 Quarterly Gross Production (3 MMBOE Annual Production – Maintenance Case) Eagle Ford 30.0 27.6 d) 23.7 / 24.0 3.7 20.6 20.4 (MBoe 18.0 3.1 2.9 2.9 2.6 2.5 18.4 16.6 15.3 17.4 15.0 17.1 14.5 16.0 2.6 2.6 2.3 2.1 2.0 1.8 tion 12.0 20.8 2.3 2.1 2.1 2.0 1.9 2.2 1.9 1.9 2.1 1.9 1.8 2.0 c 6.0 17.9 15.4 15.3 13.8 12.4 11.4 13.1 11.2 13.0 10.9 12.1 Produ— s s Q1 2016 Q2 2016 Q3 2016 Q4 2016 Q1 2017 Q2 2017 Q3 2017 Q4 2017 Q1 2018 Q2 2018 Q3 2018 Q4 2018 ro G Oil (MBbls/d) Gas (MBoe/d) NGL (MBbls/d) Granite Wash 5.0 d) 3.9 e / 4.0 o 3.0 2.9 (MB 3.0 1.2 2.8 2.7 2.6 2.5 2.5 2.4 2.3 2.3 2.2 on 2.0 0.8 0.8 0.7 0.7 0.7 0.7 0.7 0.6 0.6 0.6 0.6 c ti 2.1 u 1.0 1.7 1.7 1.6 1.6 1.5 1.5 1.4 1.4 1.4 1.3 1.3 d o Pr—0.6 0.5 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.3 0.3 s s Q1 2016 Q2 2016 Q3 2016 Q4 2016 Q1 2017 Q2 2017 Q3 2017 Q4 2017 Q1 2018 Q2 2018 Q3 2018 Q4 2018 ro G Oil (MBbls/d) Gas (MBoe/d) NGL (MBbls/d) Total Company 35.0 31.5 d) 26.7 e/ 28.0 4.9 23.5 23.2 o (MB 21.0 5.2 4.7 3.7 3.4 3.2 21.1 3.0 19.2 17.8 19.8 2.7 17.4 19.4 2. 16.8 18.2 n 4.3 4.2 2.8 6 2.4 o 14.0 3.9 3.6 3.4 2.6 3.6 3.3 2.5 3.5 3.2 2.4 3.3 ti 21.4 duc 7.0 18.3 15.8 15.8 14.2 12.8 11.8 13.5 11.6 13.3 11.3 12.4 ro P— s s Q1 2016 Q2 2016 Q3 2016 Q4 2016 Q1 2017 Q2 2017 Q3 2017 Q4 2017 Q1 2018 Q2 2018 Q3 2018 Q4 2018 ro G Oil (MBbls/d) Gas (MBoe/d) NGL (MBbls/d) Jefferies LLC, Alvarez & Marsal North America LLC, Kirkland & Ellis LLP / May 2016 14 For Settlement Discussion Purposes Only / Subject to FRE 408 / Pursuant to NDA

2016-2018 Net D&C Capex and Wells Drilled (3 MMBOE Annual Production – Maintenance Case) 3.5 $20 3.0 3.0 3.0 3.0 2.9 2.9 2.6 2.5 2.0 Drilled 2.0 $10 MM s $ Well 1.5 1.0 1.0 1.0 0.5 0.5 — — — — — — —— $- Q1 16 Q2 16 Q3 16 Q4 16 Q1 17 Q2 17 Q3 17 Q4 17 Q1 18 Q2 18 Q3 18 Q4 18 Gross Wells Drilled Net Wells Drilled Net D&C Capex Jefferies LLC, Alvarez & Marsal North America LLC, Kirkland & Ellis LLP / May 2016 15 For Settlement Discussion Purposes Only / Subject to FRE 408 / Pursuant to NDA

Other Information Material Midstream Considerations: Accounting for Gain on Sale of Gathering/Intermediate Transportation Rights in 2014 ? $147 million gain composed of two parts ? $63 million gain recognized immediately ? $84 million related to the obligation created under the related marketing / transportation agreement was deferred ? Amount deferred was revalued in 2015 when the agreement was amended, and an additional $8.4 million was recognized ? Remaining deferred amount ($75.6 million) will be amortized to gain/loss on sale over the life of the agreement beginning when the pipeline construction commitment is deemed to be 100% complete Business Plan Cost Optimization Status ? Goal is to create a low cost operator that is positioned to exploit commodity price upside ? Currently evaluating a number of alternatives to further reduce G&A, LOE and F&D costs Note: The estimated public company costs are approximately $1.7 million to $2.2 million annually. Company estimates material contract damage claim estimates of $150—$250 million with all but one of the damage claims cumulatively totaling less than approximately $10 million. Jefferies LLC, Alvarez & Marsal North America LLC, Kirkland & Ellis LLP / May 2016 16 For Settlement Discussion Purposes Only / Subject to FRE 408 / Pursuant to NDA

Other Information Initial Budget ($s in millions) 1 2 3 4 5 6 7 8 9 10 11 12 13 Fcst Fcst Fcst Fcst Fcst Fcst Fcst Fcst Fcst Fcst Fcst Fcst Fcst w/e w/e w/e w/e w/e w/e w/e w/e w/e w/e w/e w/e w/e 5/13 5/20 5/27 6/3 6/10 6/17 6/24 7/1 7/8 7/15 7/22 7/29 8/5 Total Beginning Cash Balance $ 26.5 $ 26.4 $ 36.9 $ 21.4 $ 15.2 $ 10.0 $ 10.0 $ 14.3 $ 10.5 $ 10.0 $ 10.0 $ 13.7 $ 12.6 $ 26.5 Receipts Oil & Gas Receipts: South Texas—15.3 0.9 ——14.4 0.9 — 13.8 0.9—46.1 Oklahoma—0.4 0.1 —— 0.3 0.1 — 0.3 0.1—1.4 JIB Receipts—0.3 1.2 —— 1.3 ——1.0 — 3.8 Access to Hedge Proceeds — — — — — — — Total Receipts—16.0 2.1 ——16.0 1.0 — 15.1 1.0—51.3 Operating Disbursements Payroll-Related—0.8 0.6 0.5 0.0 0.7 0.0 0.5 0.0 0.5 0.2 0.5 0.0 4.2 Non-Payroll Related: CapEx—0.1 0.1 0.1 0.1 0.1 0.1 0.2 0.1 0.1 0.1 0.1 0.1 1.4 LOE—0.3 0.3 0.3 0.5 0.8 0.8 0.7 0.7 0.7 0.7 0.7 0.6 7.2 G&A—0.1 0.2 0.4 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.2 3.2 Other/GPT—0.2 0.2 0.5 0.3 0.5 0.5 0.5 0.7 0.4 0.4 0.4 0.7 5.4 Royalties & Working Interest — 9.2 —— 7.6 ——7.3 — 24.1 Est. Royalties & Working Interest in suspense — 2.0 —— 1.3 ——1.3 — 4.5 Severance taxes—0.2 1.2 0.0 — 1.3 ——1.2 0.0—3.9 Total Operating Disbursements—1.7 13.8 1.8 1.2 2.3 11.7 2.1 1.9 2.0 11.4 2.0 1.6 53.7 Restructuring Related Disbursements Professional Fees — — 2.5——2.0 2.5 ——2.0 9.0 Prepetition Opex, JIB’s, Mkt, S&W, 503b9 claims—3.8 3.8 3.8 3.8— — — ——15.1 Utility Deposit—0.0 — — — — ——0.0 Total Restructuring-Related Payments—3.8 3.8 3.8 6.2——2.0 2.5 ——2.0 24.1 Net Cash Flow Prior To Financing Activities—10.5 (15.5) (5.6) (7.5) (2.3) 4.3 (3.1) (4.3) (2.0) 3.7 (1.0) (3.6) (26.5) Financing Related Disbursements Adequate Protection Payments ——0.5 — —0.5 — — 0.6 1.7 DIP Fees & Interest 0.1 — 0.2 0.0 0.0 —0.2 0.0 0.0 — 0.2 0.7 Total Financing Related Disbursements 0.1 — 0.7 0.0 0.0 —0.7 0.0 0.0 — 0.8 2.3 DIP Loan Advances — — 2.3 2.3 — 3.9 2.0 — 1.8 12.3 Total Net Cash Flow (0.1) 10.5 (15.5) (6.3) (5.2) (0.0) 4.3 (3.8) (0.5) (0.0) 3.7 (1.0) (2.7) (16.6) Ending Cash Balance $ 26.4 $ 36.9 $ 21.4 $ 15.2 $ 10.0 $ 10.0 $ 14.3 $ 10.5 $ 10.0 $ 10.0 $ 13.7 $ 12.6 $ 10.0 $ 10.0 Memo: DIP Balance $—$—$—$—$ 2.3 $ 4.6 $ 4.6 $ 4.6 $ 8.5 $ 10.5 $ 10.5 $ 10.5 $ 12.3 $ 12.3 Jefferies LLC, Alvarez & Marsal North America LLC, Kirkland & Ellis LLP / May 2016 17 For Settlement Discussion Purposes Only / Subject to FRE 408 / Pursuant to NDA