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Form 10-Q PETROQUEST ENERGY INC For: Jun 30

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August 3, 2016 4:14 PM EDT

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
FORM 10-Q
(Mark One)
x
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended: June 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: 001-32681
_________________________________________________________________
PETROQUEST ENERGY, INC.
(Exact name of registrant as specified in its charter)
––––––––––––––––––––––––––––––––––––––––––––––––––––––––––––––––––
DELAWARE
 
72-1440714
(State of Incorporation)
 
(I.R.S. Employer
Identification No.)
400 E. Kaliste Saloom Rd., Suite 6000
Lafayette, Louisiana
 
70508
(Address of principal executive offices)
 
(Zip code)
Registrant’s telephone number, including area code: (337) 232-7028
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 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  x    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 (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  x    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 definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
 
Large accelerated filer
¨
Accelerated filer
x
Non-accelerated filer
¨
Smaller reporting company
¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  x
As of July 29, 2016 there were 17,627,748 shares of the registrant’s common stock, par value $.001 per share, outstanding.

 
 
 

PETROQUEST ENERGY, INC.
Table of Contents
 
 
Page No.
Part I. Financial Information
 
 
 
Item 1. Financial Statements
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 



PETROQUEST ENERGY, INC.
Consolidated Balance Sheets
(Amounts in Thousands)
 
June 30,
2016
 
December 31,
2015
 
(unaudited)
 
(Note 1)
ASSETS
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
68,896

 
$
148,013

Revenue receivable
6,452

 
6,476

Joint interest billing receivable
18,560

 
49,374

Derivative asset
—

 
1,508

Other current assets
5,219

 
3,874

Total current assets
99,127

 
209,245

Property and equipment:
 
 
 
Oil and gas properties:
 
 
 
Oil and gas properties, full cost method
1,318,737

 
1,310,891

Unevaluated oil and gas properties
6,000

 
12,516

Accumulated depreciation, depletion and amortization
(1,223,051
)
 
(1,157,455
)
Oil and gas properties, net
101,686

 
165,952

Other property and equipment
11,257

 
11,229

Accumulated depreciation of other property and equipment
(10,020
)
 
(8,737
)
Total property and equipment
102,923

 
168,444

Other assets, net of accumulated amortization of $4,005 and $3,842, respectively
6,674

 
1,630

Total assets
$
208,724

 
$
379,319

LIABILITIES AND STOCKHOLDERS’ EQUITY
 
 
 
Current liabilities:
 
 
 
Accounts payable to vendors
$
54,379

 
$
97,999

Advances from co-owners
577

 
16,118

Oil and gas revenue payable
29,386

 
18,911

Accrued interest and preferred stock dividend
9,938

 
12,795

Asset retirement obligation
1,496

 
6,015

Derivative liability
473

 
—

Accrued acquisition cost
—

 
4,409

Other accrued liabilities
3,131

 
2,537

Total current liabilities
99,380

 
158,784

10% Senior Unsecured Notes due 2017
134,766

 
347,008

10% Senior Secured Notes due 2021
156,524

 
—

Asset retirement obligation
39,986

 
36,541

Other long-term liabilities
2,670

 
53

Commitments and contingencies


 


Stockholders’ equity:
 
 
 
Preferred stock, $.001 par value; authorized 5,000 shares; issued and outstanding 1,495 shares
1

 
1

Common stock, $.001 par value; authorized 150,000 shares; issued and outstanding 17,548 and 16,411 shares, respectively
18

 
16

Paid-in capital
293,595

 
290,432

Accumulated other comprehensive (loss) income
(473
)
 
947

Accumulated deficit
(517,743
)
 
(454,463
)
Total stockholders’ equity
(224,602
)
 
(163,067
)
Total liabilities and stockholders’ equity
$
208,724

 
$
379,319

See accompanying Notes to Consolidated Financial Statements.

1

PETROQUEST ENERGY, INC.
Consolidated Statements of Operations
(unaudited)
(Amounts in Thousands, Except Per Share Data)
 
Three Months Ended
 
Six Months Ended
 
June 30,
 
June 30,
 
2016
 
2015
 
2016
 
2015
Revenues:
 
 
 
 
 
 
 
Oil and gas sales
$
15,824

 
$
32,550

 
$
33,144

 
$
66,001

Expenses:
 
 
 
 
 
 
 
Lease operating expenses
6,864

 
11,191

 
15,041

 
22,093

Production taxes
(48
)
 
948

 
290

 
1,904

Depreciation, depletion and amortization
7,193

 
18,345

 
17,331

 
38,999

Ceiling test write-down
12,782

 
65,495

 
31,639

 
174,406

General and administrative
3,871

 
6,519

 
12,470

 
11,858

Accretion of asset retirement obligation
618

 
823

 
1,226

 
1,682

Interest expense
6,503

 
8,596

 
14,760

 
16,470

 
37,783

 
111,917

 
92,757

 
267,412

Other income (expense):
 
 
 
 
 
 
 
Gain on sale of oil and gas properties
—

 
21,531

 
—

 
21,531

Other income (expense)
(424
)
 
40

 
(327
)
 
197

 
(424
)
 
21,571

 
(327
)
 
21,728

 
 
 
 
 
 
 
 
Loss from operations
(22,383
)
 
(57,796
)
 
(59,940
)
 
(179,683
)
Income tax expense
475

 
2,000

 
561

 
1,073

Net loss
(22,858
)
 
(59,796
)
 
(60,501
)
 
(180,756
)
Preferred stock dividend
1,285

 
1,287

 
2,779

 
2,567

Loss available to common stockholders
$
(24,143
)
 
$
(61,083
)
 
$
(63,280
)
 
$
(183,323
)
Loss per common share:
 
 
 
 
 
 
 
Basic
 
 
 
 
 
 
 
Net loss per share
$
(1.38
)
 
$
(3.77
)
 
$
(3.67
)
 
$
(11.31
)
Diluted
 
 
 
 
 
 
 
Net loss per share
$
(1.38
)
 
$
(3.77
)
 
$
(3.67
)
 
$
(11.31
)
Weighted average number of common shares:
 
 
 
 
 
 
 
Basic
17,539

 
16,223

 
17,248

 
16,208

Diluted
17,539

 
16,223

 
17,248

 
16,208

See accompanying Notes to Consolidated Financial Statements.


2

PETROQUEST ENERGY, INC.
Consolidated Statements of Comprehensive Income (Loss)
(unaudited)
(Amounts in Thousands)
 
Three Months Ended
 
Six Months Ended
 
June 30,
 
June 30,
 
2016
 
2015
 
2016
 
2015
Net loss
$
(22,858
)
 
$
(59,796
)
 
$
(60,501
)
 
$
(180,756
)
Change in fair value of derivative instruments, accounted for as hedges, net of income tax benefit of $475, $2,046, $561 and $1,099, respectively
(1,275
)
 
(3,454
)
 
(1,420
)
 
(1,856
)
Comprehensive loss
$
(24,133
)
 
$
(63,250
)
 
$
(61,921
)
 
$
(182,612
)
See accompanying Notes to Consolidated Financial Statements.


3

PETROQUEST ENERGY, INC.
Consolidated Statements of Cash Flows
(unaudited)
(Amounts in Thousands)
 
Six Months Ended
 
June 30,
 
2016
 
2015
Cash flows from operating activities:
 
 
 
Net loss
$
(60,501
)
 
$
(180,756
)
Adjustments to reconcile net loss to net cash (used in) provided by operating activities:
 
 
 
Deferred tax expense
561

 
1,073

Depreciation, depletion and amortization
17,331

 
38,999

Ceiling test writedown
31,639

 
174,406

Accretion of asset retirement obligation
1,226

 
1,682

Share-based compensation expense
925

 
2,828

Amortization costs and other
810

 
1,162

Payments to settle asset retirement obligations
(2,515
)
 
(1,186
)
Gain on sale of oil and gas properties
—

 
(21,531
)
Costs incurred to issue 2021 Notes
4,808

 
—

Changes in working capital accounts:
 
 
 
Revenue receivable
24

 
8,735

Joint interest billing receivable
30,814

 
(1,171
)
Accounts payable and accrued liabilities
(31,260
)
 
(36,051
)
Advances from co-owners
(15,541
)
 
17,846

Other
(4,387
)
 
(410
)
Net cash (used in) provided by operating activities
(26,066
)
 
5,626

Cash flows provided by investing activities:
 
 
 
Investment in oil and gas properties
(18,166
)
 
(62,451
)
Investment in other property and equipment
(28
)
 
(134
)
Sale of oil and gas properties
24,909

 
257,698

Net cash provided by investing activities
6,715

 
195,113

Cash flows used in financing activities:
 
 
 
Net proceeds for share based compensation
52

 
432

Deferred financing costs
(100
)
 
(829
)
Payment of preferred stock dividend
(1,284
)
 
(2,569
)
Redemption of 2017 Notes
(53,626
)
 
—

Costs incurred to issue 2021 Notes
(4,808
)
 
—

Proceeds from bank borrowings
—

 
70,000

Repayment of bank borrowings
—

 
(145,000
)
Net cash used in financing activities
(59,766
)
 
(77,966
)
Net (decrease) increase in cash and cash equivalents
(79,117
)
 
122,773

Cash and cash equivalents, beginning of period
148,013

 
18,243

Cash and cash equivalents, end of period
$
68,896

 
$
141,016

Supplemental disclosure of cash flow information:
 
 
 
Cash paid during the period for:
 
 
 
Interest
$
16,783

 
$
18,626

Income taxes
$
—

 
$
(26
)
See accompanying Notes to Consolidated Financial Statements.

4

PETROQUEST ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
Note 1—Basis of Presentation
The consolidated financial information for the three and six month periods ended June 30, 2016 and 2015, have been prepared by the Company and were not audited by its independent registered public accountants. In the opinion of management, all normal and recurring adjustments have been made to present fairly the financial position, results of operations, and cash flows of the Company at June 30, 2016 and for all reported periods. Results of operations for the interim periods presented are not necessarily indicative of the operating results for the full year or any future periods.
The balance sheet at December 31, 2015 has been derived from the audited financial statements at that date. Certain information and footnote disclosures normally included in financial statements prepared in accordance with U.S. generally accepted accounting principles have been condensed or omitted. These consolidated financial statements should be read in conjunction with the audited financial statements and related notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2015. Certain prior period amounts have been reclassified to conform to current year presentation.
Unless the context otherwise indicates, any references in this Quarterly Report on Form 10-Q to the “Company,” "we," or "us" refer to PetroQuest Energy, Inc. ("PetroQuest") and its wholly-owned consolidated subsidiaries, PetroQuest Energy, L.L.C. (a single member Louisiana limited liability company), PetroQuest Oil & Gas, L.L.C. (a single member Louisiana limited liability company), TDC Energy LLC (a single member Louisiana limited liability company) and Pittrans, Inc. (an Oklahoma corporation).

Note 2—Acquisitions and Divestitures
Acquisition:
In June 2014, the Company entered into a joint venture in Louisiana for an aggregate purchase price of $24 million. The assets acquired under the joint venture include an average 37% working interest in an approximately 30,000 acre leasehold position in Louisiana and exclusive rights, along with the Company's joint venture partner, to a 200 square mile proprietary 3D survey which has generated several conventional and shallow non-conventional oil focused prospects.
The purchase price was comprised of $10 million in cash and $14 million in cash funding for future drilling, completion and lease acquisition costs. At December 31, 2015, $4.4 million of this drilling carry remained outstanding and was reflected as accrued acquisition costs in the Consolidated Balance Sheet. During February 2016, the Company paid $4.4 million to settle this liability with its joint venture partner in connection with the terms of the agreement.
Divestitures:
On June 4, 2015, the Company completed the sale of a majority of its interests in the Woodford and Mississippian Lime (the “Sold Assets”) for $260.2 million. At December 31, 2014, the estimated proved reserves attributable to the Sold Assets totaled approximately 227 Bcfe, which represented approximately 57% of the Company's estimated proved reserves. Under the full cost method of accounting, sales of oil and gas properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless the adjustment significantly alters the relationship between capitalized costs and proved reserves. A significant alteration is generally not expected to occur for sales involving less than 25% of the total proved reserves. If the divestiture of the Sold Assets was accounted for as an adjustment of capitalized costs with no gain or loss recognized, the adjustment would have significantly altered the relationship between capitalized costs and proved reserves. Accordingly, the Company recognized a gain on the sale of $21.5 million in June 2015. The carrying value of the properties sold was determined by allocating total capitalized costs within the full cost pool between properties sold and properties retained based on their relative fair values.
In March 2016, the Company sold certain non-producing assets in East Texas for $7 million in connection with the negotiation of a joint venture. This sale was accounted for as an adjustment to the capitalized costs of oil and gas properties. Negotiations of the terms and conditions of this joint venture are currently ongoing. If the Company is unable to reach an agreement with respect to the joint venture, the Company will be required to purchase the non-producing assets for $5.0 million on or before December 31, 2016.
On April 20, 2016, the Company completed the sale of a majority of its remaining Woodford Shale assets in the East Hoss field (the "East Hoss Assets") for approximately $18 million, subject to customary post-closing purchase price adjustments, effective April 1, 2016. This sale was accounted for as an adjustment to the capitalized costs of oil and gas properties.

5

Note 3—Equity
Common Stock
On May 18, 2016, the Company effected a reverse split of the Company's common stock at a ratio of one share of newly issued common stock for each four shares of issued and outstanding common stock (the "Reverse Split"). The purpose of the Reverse Split was to increase the per share trading price of the Company's common stock in order to regain compliance with the New York Stock Exchange continued listing standards. The Reverse Split proportionately reduced the total number of outstanding shares of common stock from approximately 70.1 million shares to approximately 17.5 million shares. All references in the consolidated financial statements and notes to consolidated financial statements to the number of shares, per share data, restricted stock and stock option data have been retroactively adjusted to give effect to the Reverse Split.
Convertible Preferred Stock
The Company has 1,495,000 shares of 6.875% Series B Cumulative Convertible Perpetual Preferred Stock (the “Series B Preferred Stock”) outstanding.
The following is a summary of certain terms of the Series B Preferred Stock:
Dividends. The Series B Preferred Stock accumulates dividends at an annual rate of 6.875% for each share of Series B Preferred Stock. Dividends are cumulative from the date of first issuance and, to the extent payment of dividends is not prohibited by the Company’s debt agreements, assets are legally available to pay dividends and the Company’s board of directors or an authorized committee of the board declares a dividend payable, the Company pays dividends in cash, every quarter.
In connection with an amendment to the Company's bank credit facility prohibiting the Company from declaring or paying dividends on the Series B Preferred Stock, the Company suspended the quarterly cash dividend on its Series B Preferred Stock beginning with the dividend payment due on April 15, 2016. Under the terms of the Series B Preferred Stock, any unpaid dividends will accumulate. As of June 30, 2016, the Company has deferred one dividend payment and has accrued a $2.6 million payable which is included in Other long-term liabilities on the Consolidated Balance Sheet at June 30, 2016. If the Company fails to pay six quarterly dividends on the Series B Preferred Stock, whether or not consecutive, holders of the Series B Preferred Stock, voting as a single class, will have the right to elect two additional directors to the Company's Board of Directors until all accumulated and unpaid dividends on the Series B Preferred Stock are paid in full.
Mandatory conversion. The Company may, at its option, cause shares of the Series B Preferred Stock to be automatically converted at the applicable conversion rate, but only if the closing sale price of the Company’s common stock for 20 trading days within a period of 30 consecutive trading days ending on the trading day immediately preceding the date the Company gives the conversion notice equals or exceeds 130% of the conversion price in effect on each such trading day.
Conversion rights. Each share of Series B Preferred Stock may be converted at any time, at the option of the holder, into 0.8608 shares of the Company’s common stock (which is based on a conversion price of approximately $58.08 per share of common stock as adjusted for the Reverse Split, subject to further adjustment) plus cash in lieu of fractional shares, subject to the Company’s right to settle all or a portion of any such conversion in cash or shares of the Company’s common stock. If the Company elects to settle all or any portion of its conversion obligation in cash, the conversion value and the number of shares of the Company’s common stock it will deliver upon conversion (if any) will be based upon a 20 trading day averaging period.
Upon any conversion, the holder will not receive any cash payment representing accumulated and unpaid dividends on the Series B Preferred Stock, whether or not in arrears, except in limited circumstances. The conversion rate is equal to $50 divided by the conversion price at the time. The conversion price is subject to adjustment upon the occurrence of certain events. The conversion price on the conversion date and the number of shares of the Company’s common stock, as applicable, to be delivered upon conversion may be adjusted if certain events occur.

6

Note 4—Earnings Per Share
A reconciliation between the basic and diluted earnings per share computations (in thousands, except per share amounts) is as follow:
For the Three Months Ended June 30, 2016
Loss
(Numerator)
 
Shares
(Denominator)
 
Per
Share Amount
BASIC EPS
 
 
 
 
 
Net loss available to common stockholders
$
(24,143
)
 
17,539

 
$
(1.38
)
Stock options
—

 
—

 
 
Attributable to participating securities
—

 
—

 
 
DILUTED EPS
$
(24,143
)
 
17,539

 
$
(1.38
)
 
 
 
 
 
 
For the Six Months Ended June 30, 2016
Loss
(Numerator)
 
Shares
(Denominator)
 
Per
Share Amount
BASIC EPS
 
 
 
 
 
Net loss available to common stockholders
$
(63,280
)
 
17,248

 
$
(3.67
)
  Stock options
—

 
—

 
 
Attributable to participating securities
—

 
—

 
 
DILUTED EPS
$
(63,280
)
 
17,248

 
$
(3.67
)
 
 
 
 
 
 
For the Three Months Ended June 30, 2015
Loss (Numerator)
 
Shares
(Denominator)
 
Per
Share Amount
BASIC EPS
 
 
 
 
 
Net loss available to common stockholders
$
(61,083
)
 
16,223

 
$
(3.77
)
Stock options
—

 
—

 
 
Attributable to participating securities
—

 
—

 
 
DILUTED EPS
$
(61,083
)
 
16,223

 
$
(3.77
)
 
 
 
 
 
 
For the Six Months Ended June 30, 2015
Loss (Numerator)
 
Shares
(Denominator)
 
Per
Share Amount
BASIC EPS
 
 
 
 
 
Net loss available to common stockholders
$
(183,323
)
 
16,208

 
$
(11.31
)
Stock options
—

 
—

 
 
Attributable to participating securities
—

 
—

 
 
DILUTED EPS
$
(183,323
)
 
16,208

 
$
(11.31
)

An aggregate of 0.3 million and 0.1 million shares of common stock representing options to purchase common stock and unvested shares of restricted common stock and common shares issuable upon the assumed conversion of the Series B preferred stock totaling 1.3 million shares were not included in the computation of diluted earnings per share for the three month periods ended June 30, 2016 and 2015, respectively, because the inclusion would have been anti-dilutive as a result of the net loss reported for such periods.

An aggregate of 0.3 million and 0.1 million shares of common stock representing options to purchase common stock and unvested shares of restricted common stock and common shares issuable upon the assumed conversion of the Series B preferred stock totaling 1.3 million shares were not included in the computation of diluted earnings per share for the six months ended June 30, 2016 and 2015, respectively, because the inclusion would have been anti-dilutive as a result of the net loss reported for such periods.

Note 5—Long-Term Debt
On August 19, 2010, the Company issued $150 million in principal amount of its 10% Senior Notes due 2017. On July 3, 2013, the Company issued an additional $200 million in principal amount of its 10% Senior Notes due 2017 (collectively, the "2017 Notes").

7

On January 14, 2016, the Company announced the commencement of a private exchange offer (the "Exchange") and consent solicitation (the "Consent Solicitation") to certain eligible holders of its outstanding 2017 Notes. The Exchange closed on February 17, 2016, and in satisfaction of the tender of $214.4 million in aggregate principal amount of the 2017 Notes, representing approximately 61% of the outstanding aggregate principal amount of 2017 Notes, in the Exchange the Company (i) paid approximately $53.6 million of cash, (ii) issued $144.7 million aggregate principal amount of its new 10% Second Lien Senior Secured Notes due 2021 (the "2021 Notes") and (iii) issued approximately 1.1 million shares of its common stock. Following the completion of the Exchange, $135.6 million in aggregate principal amount of the 2017 Notes remain outstanding. The Consent Solicitation eliminated or waived substantially all of the restrictive covenants contained in the indenture governing the 2017 Notes.
The Exchange was accounted for as a troubled debt restructuring pursuant to guidance provided by FASB Accounting Standards Codification ("ASC") section 470-60 "Troubled Debt Restructurings by Debtors." The Company determined that the future undiscounted cash flows from the 2021 Notes issued in the Exchange through the maturity date exceeded the adjusted carrying amount of the 2017 Notes tendered in the Exchange. Accordingly, no gain on extinguishment of debt was recognized in connection with the Exchange. The excess of the future undiscounted cash flows from the 2021 Notes issued in the Exchange over the remaining carrying value of the 2017 Notes tendered in the Exchange of $13.9 million is reflected as part of the carrying value of the 2021 Notes. Such excess will be amortized under the effective interest method as a reduction of interest expense over the term of the 2021 Notes. At June 30, 2016, $13.0 million of the excess remained as part of the carrying value of the 2021 Notes and the Company recognized $0.9 million of amortization expense as a reduction to interest expense during the first half of 2016.
The indenture governing the 2021 Notes contains affirmative and negative covenants that, among other things, limit the ability of the Company and the subsidiary guarantors of the 2021 Notes to incur indebtedness; purchase or redeem stock; make certain investments; create liens that secure debt; enter into transactions with affiliates; sell assets; refinance certain indebtedness; merge with or into other companies or transfer substantially all of their assets; and, in certain circumstances, to pay dividends or make other distributions on stock. The 2021 Notes are fully and unconditionally guaranteed on a senior basis by certain wholly-owned subsidiaries of the Company.
The 2021 Notes are secured by second-priority liens on substantially all of the Company's and the subsidiary guarantors' oil and gas properties and substantially all of their other assets to the extent such properties and assets secure the Credit Agreement (as defined below), except for certain excluded assets. Pursuant to the terms of an intercreditor agreement, the security interest in those properties and assets that secure the 2021 Notes and the guarantees are contractually subordinated to liens that secure the Credit Agreement and certain other permitted indebtedness. Consequently, the 2021 Notes and the guarantees will be effectively subordinated to the Credit Agreement and such other indebtedness to the extent of the value of such assets.
The 2021 Notes bear interest at a rate of 10% per annum on the principal amount and interest is payable semi-annually in arrears on February 15 and August 15 of each year, beginning August 15, 2016. At June 30, 2016, $5.4 million had been accrued in connection with the August 15, 2016 payment and the Company was in compliance with all of the covenants under the 2021 Notes. Interest on the 2017 Notes is payable semi-annually on March 1 and September 1 and the 2017 Notes mature on September 1, 2017. At June 30, 2016, $4.5 million had been accrued in connection with the September 1, 2016 interest payment and the Company was in compliance with all of the covenants under the 2017 Notes.
During 2015, the Company adopted ASU No. 2015-03, "Simplifying the Presentation of Debt Issuance Costs", which changes the presentation of debt issuance costs in financial statements to present such costs as a direct deduction from the related liability rather than as an asset. As a result, the 2017 Notes are reflected net of $0.9 million and $3.0 million of related financing costs at June 30, 2016 and December 31, 2015, respectively. The 2021 Notes are reflected net of $1.2 million of related financing costs as of June 30, 2016.
The following table reconciles the face value of the 2017 Notes and 2021 Notes to the carrying value included in the Company's Consolidated Balance Sheet as of June 30, 2016 and December 31, 2015 (in thousands):
 
June 30, 2016
December 31, 2015
 
2017 Notes
2021 Notes
2017 Notes
2021 Notes
Face Value
$
135,621

$
144,674

$
350,000

$
—

Deferred Financing Costs
(855
)
(1,174
)
(2,992
)
—

Excess Carrying Value
—

13,024

—

—

Carrying Value
$
134,766

$
156,524

$
347,008

$
—


The Company and PetroQuest Energy, L.L.C. (the “Borrower”) have a Credit Agreement (as amended, the “Credit Agreement”) with JPMorgan Chase Bank, N.A., Wells Fargo Bank, N.A., Capital One, N.A., IberiaBank, Bank of America, N.A. and The Bank of Nova Scotia. The Credit Agreement provides the Company with a revolving credit facility that permits borrowings based on the commitments of the lenders and the available borrowing base as determined in accordance with the Credit Agreement.

8

The Credit Agreement does not presently allow the Company to issue letters of credit thereunder. The credit facility matures on the earlier of June 4, 2020 or February 19, 2017 if any portion of the Company’s 2017 Notes remains outstanding as of such date which has not been refinanced with either permitted refinancing debt or permitted second lien debt with a maturity date no earlier than 180 days after June 4, 2020, all as defined in the Credit Agreement.
The borrowing base under the Credit Agreement is determined by March 31 and September 30 of each year and is based upon the valuation of the reserves attributable to the Company’s oil and gas properties as of January 1 and July 1 of each year. If the Company incurs any borrowings, or causes the lenders to issue any letters of credit, under the Credit Agreement (the “Financial Covenant Reinstatement Date”), two interim redeterminations would occur on July 31 and December 31 of each year commencing on the first July 31 or December 31 subsequent to the Financial Covenant Reinstatement Date. The Company or the lenders may also request two additional borrowing base re-determinations each year. Each time the borrowing base is to be re-determined, the administrative agent under the Credit Agreement will propose a new borrowing base as it deems appropriate in its sole discretion, which must be approved by all lenders if the borrowing base is to be increased, or by lenders holding two-thirds of the amounts outstanding under the Credit Agreement if the borrowing base remains the same or is reduced. As of June 30, 2016, the borrowing base and aggregate commitments of the lenders were both $22.5 million. The Company has no borrowings outstanding under (and no letters of credit issued pursuant to) the Credit Agreement.
The obligation of the lenders to make loans on the account of any borrowing or issue letters of credit under the Credit Agreement, include that (i) at the time of and after giving effect to the requested borrowing or issuance, the Company will be in compliance with the restrictive financial covenants described below, (ii) at the time of and after giving effect to the requested borrowing or issuance, there will be no Excess Cash, defined as any unrestricted cash and cash equivalents of the Company or any of its other Subsidiaries that exceeds $10 million, and (iii) after giving effect to the requested borrowing or issuance, the aggregate amount of borrowings outstanding under (and letters of credit issued pursuant to) the Credit Agreement will not exceed $5 million. In addition, the Company is obligated to make mandatory prepayments on each business day from and after the Financial Covenant Reinstatement Date in the amount of any Excess Cash on such day and, once the borrowings are fully prepaid, the Company is required to pay any Excess Cash to the administrative agent under the Credit Agreement to provide cash collateral for any outstanding letters of credit. The Company anticipates that, pursuant to the restrictive financial covenants described below, the Company will not be able to utilize the borrowing base for the foreseeable future.
The Credit Agreement is secured by a first priority lien on substantially all of the assets of the Company and its subsidiaries, including a lien on all equipment and at least 90% of the aggregate total value of the Borrower’s oil and gas properties. Outstanding balances under the Credit Agreement bear interest at the alternate base rate (“ABR”) plus a margin (based on a sliding scale of 1% to 2% depending on total commitments) or the adjusted LIBO rate (“Eurodollar”) plus a margin (based on a sliding scale of 2% to 3% depending on total commitments). The alternate base rate is equal to the highest of (i) the JPMorgan Chase prime rate, (ii) the Federal Funds Effective Rate plus 0.5% or (iii) the adjusted LIBO rate (subject to a floor of 0.0%) plus 1%.  For the purposes of the definition of alternate base rate only, the adjusted LIBO rate for any day is based on the LIBO Rate at approximately 11:00 a.m. London time on such day. For all other purposes, the adjusted LIBO rate is equal to the rate at which Eurodollar deposits in the London interbank market for one, two, three or six months (as selected by the Company) are quoted, as adjusted for statutory reserve requirements for Eurocurrency liabilities. Outstanding letters of credit will be charged a participation fee at a per annum rate equal to the margin applicable to Eurodollar loans, a fronting fee and customary administrative fees. In addition, the Company pays commitment fees of 0.5% of the average daily unused amount of the commitments.
The Company and its subsidiaries are not presently, but will become, subject to certain restrictive financial covenants under the Credit Agreement after the Financial Covenant Restatement Date, including (i) a maximum ratio of total debt to EBITDAX (as of the last day of any fiscal quarter for the fiscal quarter period then ending) multiplied by four of 4.00 to 1.0 as of the last day of any fiscal quarter, (ii) a minimum ratio of consolidated current assets (including unused availability but excluding non-cash assets under ASC 815) to consolidated current liabilities (excluding non-cash obligations under ASC 815 and ASC 410 and, for the fiscal quarters ending September 30, 2016 and December 31, 2016, liabilities in respect of the Company’s 2017 Notes) of 1.0 to 1.0 as of the last day of any fiscal quarter and (iii) a minimum ratio of EBITDAX to total cash interest expense, determined on a four quarter basis as of the end of each fiscal quarter, of 3.0 to 1.0, as of the last day of any fiscal quarter, all as defined in the Credit Agreement.
The Credit Agreement also includes customary restrictions with respect to debt, liens, dividends, distributions and redemptions, investments, loans and advances, nature of business, international operations and foreign subsidiaries, leases, sale or discount of receivables, mergers or consolidations, sales of properties, transactions with affiliates, negative pledge agreements, gas imbalances and swap agreements. The Credit Agreement also currently prohibits the Company from declaring and paying dividends on its Series B Preferred Stock.


9

Note 6—Asset Retirement Obligation
The following table describes the changes to the Company’s asset retirement obligation liability (in thousands):
 
Six Months Ended June 30,
 
2016
 
2015
Asset retirement obligation, beginning of period
$
42,556

 
$
54,970

Liabilities incurred
—

 
397

Liabilities settled
(2,574
)
 
(1,186
)
Accretion expense
1,226

 
1,682

Revisions in estimates
291

 
554

Divestiture of oil and gas properties
(17
)
 
(1,794
)
Asset retirement obligation, end of period
41,482

 
54,623

Less: current portion of asset retirement obligation
(1,496
)
 
(1,405
)
Long-term asset retirement obligation
$
39,986

 
$
53,218


Note 7—Ceiling Test

The Company uses the full cost method to account for its oil and gas properties. Accordingly, the costs to acquire, explore for and develop oil and gas properties are capitalized. Capitalized costs of oil and gas properties, net of accumulated DD&A and related deferred taxes, are limited to the estimated future net cash flows from estimated proved oil and gas reserves, including the effects of cash flow hedges in place, discounted at 10%, plus the lower of cost or fair value of unevaluated properties, as adjusted for related income tax effects (the full cost ceiling). If capitalized costs exceed the full cost ceiling, the excess is charged to ceiling test write-down of oil and gas properties in the quarter in which the excess occurs.

In accordance with SEC requirements, the estimated future net cash flows from estimated proved reserves are based on an average of the first day of the month spot price for a historical 12-month period, adjusted for quality, transportation fees and market differentials. At March 31, 2016 and June 30, 2016, the prices used in computing the estimated future net cash flows from the Company’s estimated proved reserves, including the effect of hedges in place at that date, averaged $2.19 and $2.15 per Mcf of natural gas, $45.92 and $42.12 per barrel of oil and $1.91 and $1.71 per Mcfe of Ngl, respectively. As a result of lower commodity prices and their negative impact on the Company's estimated proved reserves and estimated future net cash flows, the Company recognized ceiling test write-downs of approximately $18.9 million and $12.8 million during the three months ended March 31, 2016 and June 30, 2016, respectively. The Company’s cash flow hedges in place at March 31, 2016 and June 30, 2016 decreased the ceiling test write-downs by approximately $0.8 million and $0.2 million, respectively.

At March 31, 2015 and June 30, 2015, the prices used in computing the estimated future net cash flows from the Company's estimated proved reserves, including the effect of hedges in place at that date, averaged $3.31 and $3.20 per Mcf of natural gas, $81.33 and $71.27 per barrel of oil and $3.52 and $3.35 per Mcfe of Ngl, respectively. As a result of lower commodity prices and their negative impact on the Company's estimated proved reserves and estimated future net cash flows, the Company recognized ceiling test write-downs of approximately $108.9 million and $65.5 million during the three months ended March 31, 2015 and June 30, 2015, respectively. The Company's cash flow hedges in place at March 31, 2015 and June 30, 2015 increased the ceiling test write-downs by approximately $14 million and $1 million, respectively.

Note 8—Derivative Instruments
    
The Company seeks to reduce its exposure to commodity price volatility by hedging a portion of its production through commodity derivative instruments. When the conditions for hedge accounting are met, the Company may designate its commodity derivatives as cash flow hedges. The changes in fair value of derivative instruments that qualify for hedge accounting treatment are recorded in other comprehensive income (loss) until the hedged oil or natural gas quantities are produced. If a derivative does not qualify for hedge accounting treatment, the changes in the fair value of the derivative are recorded in the income statement as derivative income (expense). At June 30, 2016, the Company's derivative instrument was designated as an effective cash flow hedge.
Oil and gas sales include additions (reductions) related to the settlement of gas hedges of $1,155,000 and $4,181,000, oil hedges of $0 and ($288,000) and Ngl hedges of $0 and $136,000 for the three months ended June 30, 2016 and 2015, respectively.

10

Oil and gas sales include additions (reductions) related to the settlement of gas hedges of $2,187,000 and $6,505,000, oil hedges of $0 and ($261,000) and Ngl hedges of $0 and $157,000 for the six months ended June 30, 2016 and 2015, respectively.
As of June 30, 2016, the Company had entered into the following commodity derivative instrument:
Production Period
Instrument
Type
 
Daily Volumes
 
Weighted
Average Price
Natural Gas:
 
 
 
 
 
July 2016 - December 2016
Swap
 
5,000 Mmbtu
 
$2.50
At June 30, 2016, the Company had recognized an accumulated other comprehensive loss of approximately $0.5 million related to the estimated fair value of its effective cash flow hedges. Based on estimated future commodity prices as of June 30, 2016, the Company would reclassify approximately $0.3 million, net of taxes, of accumulated other comprehensive loss into earnings during the next six months. These losses are expected to be reclassified to oil and gas sales based on the schedule of gas volumes stipulated in the derivative contracts.
Derivatives designated as hedging instruments:
The following tables reflect the fair value of the Company’s effective cash flow hedge in the consolidated financial statements (in thousands):
Effect of Cash Flow Hedges on the Consolidated Balance Sheet at June 30, 2016 and December 31, 2015:    
 
Commodity Derivatives
Period
Balance Sheet
Location
Fair Value
June 30, 2016
Derivative liability
$
(473
)
December 31, 2015
Derivative asset
$
1,508

Effect of Cash Flow Hedges on the Consolidated Statement of Operations for the three months ended June 30, 2016 and 2015:
Instrument
Amount of Loss
Recognized in Other
Comprehensive Income
 
Location of
Gain Reclassified
into Income
 
Amount of Gain Reclassified into
Income
Commodity Derivatives at June 30, 2016
$
(595
)
 
Oil and gas sales
 
$
1,155

Commodity Derivatives at June 30, 2015
$
(1,471
)
 
Oil and gas sales
 
$
4,029


Effect of Cash Flow Hedges on the Consolidated Statement of Operations for the six months ended June 30, 2016 and 2015
Instrument
Amount of Gain  Recognized in Other
Comprehensive Income
 
Location of
Gain Reclassified
into Income
 
Amount of Gain Reclassified into
Income
Commodity Derivatives at June 30, 2016
$
206

 
Oil and gas sales
 
$
2,187

Commodity Derivatives at June 30, 2015
$
3,446

 
Oil and gas sales
 
$
6,401


Note 9 – Fair Value Measurements
As defined in ASC Topic 820, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. ASC Topic 820 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. As presented in the tables below, this hierarchy consists of three broad levels:
•
Level 1: valuations consist of unadjusted quoted prices in active markets for identical assets and liabilities and has the highest priority;
•
Level 2: valuations rely on quoted prices in markets that are not active or observable inputs over the full term of the asset or liability;
•
Level 3: valuations are based on prices or third party or internal valuation models that require inputs that are significant to the fair value measurement and are less observable and thus have the lowest priority.

11

The Company classifies its commodity derivatives based upon the data used to determine fair value. The Company’s derivative instrument at June 30, 2016 was in the form of a swap based on NYMEX pricing for natural gas. The fair value of this derivative is derived using an independent third-party’s valuation model that utilizes market-corroborated inputs that are observable over the term of the derivative contract. The Company’s fair value calculations also incorporate an estimate of the counterparties’ default risk for derivative assets and an estimate of the Company’s default risk for derivative liabilities. As a result, the Company designates its commodity derivatives as Level 2 in the fair value hierarchy.
The following table summarizes the net valuation of the Company’s derivatives subject to fair value measurement on a recurring basis as of June 30, 2016 and December 31, 2015 (in thousands):
 
Fair Value Measurements Using
Instrument
Quoted Prices
in Active
Markets (Level 1)
 
Significant Other
Observable
Inputs (Level 2)
 
Significant
Unobservable
Inputs (Level 3)
Commodity Derivatives:
 
 
 
 
 
June 30, 2016
$
—

 
$
(473
)
 
$
—

December 31, 2015
$
—

 
$
1,508

 
$
—

The fair value of the Company's cash and cash equivalents approximated book value at June 30, 2016 and December 31, 2015. The fair value of the 2017 Notes was approximately $68.6 million and $238 million as of June 30, 2016 and December 31, 2015, respectively, as compared to the book value of $135.6 million and $350.0 million, respectively. The fair value of the 2021 Notes was approximately $98.4 million as of June 30, 2016 as compared to the book value of $157.7 million (including the $13.0 million excess of future undiscounted cash flows from the 2021 Notes over the remaining carrying value of the 2017 Notes described in Note 5) and the face value of $144.7 million. The fair value of the 2017 and 2021 Notes was determined based upon market quotes provided by an independent broker, which represents a Level 2 input.
Note 10—Income Taxes
The Company typically provides for income taxes at a statutory rate of 35% adjusted for permanent differences expected to be realized, primarily statutory depletion, non-deductible stock compensation expenses and state income taxes. As a result of ceiling test write-downs recognized, the Company has incurred a cumulative three year loss. Because of the impact the cumulative loss has on the determination of the recoverability of deferred tax assets through future earnings, the Company assessed the realizability of its deferred tax assets based on the future reversals of existing deferred tax liabilities. Accordingly, the Company established a valuation allowance for a portion of the deferred tax asset. The valuation allowance was $166.6 million as of June 30, 2016.


12

Note 11 - Other Comprehensive Income

The following table represents the changes in accumulated other comprehensive income (loss), net of tax, for the three month period ended June 30, 2016 (in thousands):
 
Gains and Losses on Cash Flow Hedges
 
Change in Valuation Allowance
 
Total
Balance as of March 31, 2016
$
802

 
$
—

 
$
802

Other comprehensive income before reclassifications:
 
 
 
 
 
 Change in fair value of derivatives
(595
)
 
—

 
(595
)
 Income tax effect
221

 
(176
)
 
45

 Net of tax
(374
)
 
(176
)
 
(550
)
Amounts reclassified from accumulated other comprehensive income:
 
 
 
 
 
 Oil and gas sales
(1,155
)
 
—

 
(1,155
)
 Income tax effect
430

 
—

 
430

 Net of tax
(725
)
 
—

 
(725
)
Net other comprehensive loss
(1,099
)
 
(176
)
 
(1,275
)
Balance as of June 30, 2016
$
(297
)
 
$
(176
)
 
$
(473
)

The following table represents the changes in accumulated other comprehensive income (loss), net of tax, for the six month period ended June 30, 2016 (in thousands):
 
Gains and Losses on Cash Flow Hedges
 
Change in Valuation Allowance
 
Total
Balance as of December 31, 2015
$
947

 
$
—

 
$
947

Other comprehensive income before reclassifications:
 
 
 
 
 
 Change in fair value of derivatives
206

 
—

 
206

 Income tax effect
(77
)
 
(176
)
 
(253
)
 Net of tax
129

 
(176
)
 
(47
)
Amounts reclassified from accumulated other comprehensive income:
 
 
 
 
 
 Oil and gas sales
(2,187
)
 
—

 
(2,187
)
 Income tax effect
814

 
—

 
814

 Net of tax
(1,373
)
 
—

 
(1,373
)
Net other comprehensive loss
(1,244
)
 
(176
)
 
(1,420
)
Balance as of June 30, 2016
$
(297
)
 
$
(176
)
 
$
(473
)


13

The following table represents the changes in accumulated other comprehensive income (loss), net of tax, for the three month period ended June 30, 2015 (in thousands):
 
Gains and Losses on Cash Flow Hedges
Balance as of March 31, 2015
$
7,018

Other comprehensive loss before reclassifications:
 
 Change in fair value of derivatives
(1,471
)
 Income tax effect
547

 Net of tax
(924
)
Amounts reclassified from accumulated other comprehensive loss:
 
 Oil and gas sales
(4,029
)
 Income tax effect
1,499

 Net of tax
(2,530
)
Net other comprehensive income
(3,454
)
Balance as of June 30, 2015
$
3,564


The following table represents the changes in accumulated other comprehensive income (loss), net of tax, for the six month period ended June 30, 2015 (in thousands):
 
Gains and Losses on Cash Flow Hedges
Balance as of December 31, 2014
$
5,420

Other comprehensive income before reclassifications:
 
 Change in fair value of derivatives
3,446

 Income tax effect
(1,282
)
 Net of tax
2,164

Amounts reclassified from accumulated other comprehensive income:
 
 Oil and gas sales
(6,401
)
 Income tax effect
2,381

 Net of tax
(4,020
)
Net other comprehensive income
(1,856
)
Balance as of June 30, 2015
$
3,564



Note 12 - Recently Issued Accounting Standards
In February 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update No. 2016-02, "Leases" ("ASU 2016-02"), which will require lessees to recognize lease assets and lease liabilities on the balance sheet for leases classified as operating leases under previous guidance. Public entities are required to adopt ASU 2016-02 for reporting periods beginning after December 15, 2018. The Company is currently evaluating the impact of the new standard on its consolidated financial statements.


14

Item 2.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Overview
PetroQuest Energy, Inc. is an independent oil and gas company incorporated in the State of Delaware with primary operations in Texas, Louisiana and the shallow waters of the Gulf of Mexico. We seek to grow our production, proved reserves, cash flow and earnings at low finding and development costs through a balanced mix of exploration, development and acquisition activities. From the commencement of our operations through 2002, we were focused exclusively in the Gulf Coast Basin with onshore properties principally in southern Louisiana and offshore properties in the shallow waters of the Gulf of Mexico shelf. During 2003, we began the implementation of our strategic goal of diversifying our reserves and production into longer life and lower risk onshore properties. As part of the strategic shift to diversify our asset portfolio and lower our geographic and geologic risk profile, we refocused our opportunity selection processes to reduce our average working interest in higher risk projects, shift capital to higher probability of success onshore wells and mitigate the risks associated with individual wells by expanding our drilling program across multiple basins.
We have successfully diversified into onshore, longer life basins through a combination of selective acquisitions and drilling activity, partially offset by our recent asset divestitures in Oklahoma as discussed below. As a result of our transition to lower-risk, longer life basins, we have realized a 95% drilling success rate on 913 gross wells drilled over the last 10 years.
On June 4, 2015, we completed the sale of a majority of our interests in the Woodford Shale and Mississippian Lime for $260.2 million. In March 2016, we sold certain non-producing assets in East Texas for $7 million and in April 2016, we sold the majority of the remainder of our Woodford Shale assets for approximately $18 million.
Our liquidity position continues to be negatively impacted by the prolonged decline in commodity prices that began in late 2014. At June 30, 2016, we had $68.9 million in cash and approximately $280 million of debt represented by our 2017 Notes and 2021 Notes, $136 million of which becomes due in September 2017. For the six months ended June 30, 2016, our net loss available to common stockholders totaled $63.3 million and our negative cash flow from operating activities totaled $26.1 million. Although we have no borrowings outstanding under our Credit Agreement, we do not believe we will be able to utilize the Credit Agreement for the foreseeable future as a result of the financial covenants thereunder. We are evaluating additional sources of liquidity including asset sales, joint ventures, exchange offers and alternative financing arrangements to replace the Credit Agreement, but there is no assurance that these sources will provide sufficient, if any, incremental liquidity.
In response to lower commodity prices we have implemented a variety of initiatives aimed at preserving liquidity. In addition to the recent asset sales discussed above, we have reduced our 2016 capital expenditure budget to between $15 million and $20 million, a significant reduction from 2015 spending of approximately $65 million, as well as suspended the quarterly dividend on our outstanding Series B Preferred Stock beginning with the dividend payment in April 2016 (which will save $5.1 million annually). We are also working to reduce our cash costs by at least 25% from 2015 levels.
Our significantly decreased level of capital spending has had and is expected to continue to have a negative impact on our production and cash flow from operating activities. We expect production to continue to decline throughout 2016 and when combined with current commodity prices and our existing cost structure, including 10% interest expense on the $280 million of debt, we believe that we will continue to incur significant losses and negative cash flow from operating activities for the remainder of 2016. We are evaluating various options to address the September 2017 maturity of our remaining 2017 Notes as well as assessing our overall capital structure. See "Liquidity and Capital Resources" below for more information.
Critical Accounting Policies
Reserve Estimates
Our estimates of proved oil and gas reserves constitute those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. At the end of each year, our proved reserves are estimated by independent petroleum engineers in accordance with guidelines established by the SEC. These estimates, however, represent projections based on geologic and engineering data. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that are difficult to measure. The accuracy of any reserve estimate is a function of the quantity and quality of available data, engineering and geological interpretation and professional judgment. Estimates of economically recoverable oil and gas reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effect of regulations by governmental agencies, and assumptions governing future oil and gas prices, future operating costs, severance taxes,

15

development costs and workover costs. The future drilling costs associated with reserves assigned to proved undeveloped locations may ultimately increase to the extent that these reserves may be later determined to be uneconomic. Any significant variance in the assumptions could materially affect the estimated quantity and value of the reserves, which could affect the carrying value of our oil and gas properties and/or the rate of depletion of such oil and gas properties.
Disclosure requirements under Staff Accounting Bulletin 113 (“SAB 113”) include provisions that permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes. The rules also allow companies the option to disclose probable and possible reserves in addition to the existing requirement to disclose proved reserves. The disclosure requirements also require companies to report the independence and qualifications of third party preparers of reserves and file reports when a third party is relied upon to prepare reserves estimates. Pricing is based on a 12-month average price using beginning of the month pricing during the 12-month period prior to the ending date of the balance sheet to report oil and natural gas reserves. In addition, the 12-month average will also be used to measure ceiling test impairments and to compute depreciation, depletion and amortization.
Full Cost Method of Accounting
We use the full cost method of accounting for our investments in oil and gas properties. Under this method, all acquisition, exploration and development costs, including certain related employee costs, incurred for the purpose of exploring for and developing oil and natural gas are capitalized. Acquisition costs include costs incurred to purchase, lease or otherwise acquire property. Exploration costs include the costs of drilling exploratory wells, including those in progress and geological and geophysical service costs in exploration activities. Development costs include the costs of drilling development wells and costs of completions, platforms, facilities and pipelines. Costs associated with production and general corporate activities are expensed in the period incurred. Sales of oil and gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas.
The costs associated with unevaluated properties are not initially included in the amortization base and primarily relate to ongoing exploration activities, unevaluated leasehold acreage and delay rentals, seismic data and capitalized interest. These costs are either transferred to the amortization base with the costs of drilling the related well or are assessed quarterly for possible impairment or reduction in value.
We compute the provision for depletion of oil and gas properties using the unit-of-production method based upon production and estimates of proved reserve quantities. Unevaluated costs and related carrying costs are excluded from the amortization base until the properties associated with these costs are evaluated. In addition to costs associated with evaluated properties, the amortization base includes estimated future development costs related to non-producing reserves. Our depletion expense is affected by the estimates of future development costs, unevaluated costs and proved reserves, and changes in these estimates could have an impact on our future earnings.
We capitalize certain internal costs that are directly identified with acquisition, exploration and development activities. The capitalized internal costs include salaries, employee benefits, costs of consulting services and other related expenses and do not include costs related to production, general corporate overhead or similar activities. We also capitalize a portion of the interest costs incurred on our debt. Capitalized interest is calculated using the amount of our unevaluated property and our effective borrowing rate.
Capitalized costs of oil and gas properties, net of accumulated DD&A and related deferred taxes, are limited to the estimated future net cash flows from proved oil and gas reserves, including the effect of cash flow hedges in place, discounted at 10 percent, plus the lower of cost or fair value of unproved properties, as adjusted for related income tax effects (the full cost ceiling). If capitalized costs exceed the full cost ceiling, the excess is charged to write-down of oil and gas properties in the quarter in which the excess occurs.
Given the volatility of oil and gas prices, it is probable that our estimate of discounted future net cash flows from proved oil and gas reserves will change in the near term. If oil or gas prices remain at current levels or decline further, even for only a short period of time, or if we have downward revisions to our estimated proved reserves, it is possible that write-downs of oil and gas properties could occur in the future.
Future Abandonment Costs
Future abandonment costs include costs to dismantle and relocate or dispose of our production platforms, gathering systems, wells and related structures and restoration costs of land and seabed. We develop estimates of these costs for each of our properties based upon the type of production structure, depth of water, reservoir characteristics, depth of the reservoir, market demand for equipment, currently available procedures and consultations with construction and engineering consultants. Because these costs typically extend many years into the future, estimating these future costs is difficult and requires management to make estimates and judgments that are subject to future revisions based upon numerous factors, including changing technology, the timing of estimated costs, the impact of future inflation on current cost estimates and the political and regulatory environment.

16

Derivative Instruments
We seek to reduce our exposure to commodity price volatility by hedging a portion of our production through commodity derivative instruments. The estimated fair values of our commodity derivative instruments are recorded in the consolidated balance sheet. The changes in fair value of those derivative instruments that qualify for hedge accounting treatment are recorded in other comprehensive income (loss) until the hedged oil and natural gas quantities are produced. If a hedge becomes ineffective because the hedged production does not occur, or the hedge otherwise does not qualify for hedge accounting treatment, the changes in the fair value of the derivative are recorded in the income statement as derivative income (expense).
Our hedges are specifically referenced to NYMEX prices for natural gas. We evaluate the effectiveness of our hedges at the time we enter the contracts, and periodically over the life of the contracts, by analyzing the correlation between NYMEX prices and the posted prices we receive from our designated production. Through this analysis, we are able to determine if a high correlation exists between the prices received for the designated production and the NYMEX prices at which the hedges will be settled. At June 30, 2016, our derivative instrument was designated as an effective cash flow hedge.
Estimating the fair value of derivative instruments requires valuation calculations incorporating estimates of future NYMEX prices, discount rates and price movements. As a result, we calculate the fair value of our commodity derivatives using an independent third-party’s valuation model that utilizes market-corroborated inputs that are observable over the term of the derivative contract. Our fair value calculations also incorporate an estimate of the counterparties’ default risk for derivative assets and an estimate of our default risk for derivative liabilities.
Results of Operations
The following table sets forth certain information with respect to our oil and gas operations for the periods noted. These historical results are not necessarily indicative of results to be expected in future periods.
    
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2016
 
2015
 
2016
 
2015
Production:
 
 
 
 
 
 
 
Oil (Bbls)
114,319

 
151,223

 
254,308

 
298,437

Gas (Mcf)
4,272,820

 
7,167,270

 
9,820,297

 
15,082,774

Ngl (Mcfe)
1,045,858

 
1,584,284

 
2,292,490

 
3,160,826

Total Production (Mcfe)
6,004,592

 
9,658,892

 
13,638,635

 
20,034,222

Sales:
 
 
 
 
 
 
 
Total oil sales
$
4,936,757

 
$
8,587,332

 
$
9,295,501

 
$
15,540,233

Total gas sales
8,853,527

 
19,927,230

 
19,571,735

 
41,577,325

Total ngl sales
2,034,342

 
4,035,571

 
4,277,104

 
8,883,616

Total oil, gas, and ngl sales
$
15,824,626

 
$
32,550,133

 
$
33,144,340

 
$
66,001,174

Average sales prices:
 
 
 
 
 
 
 
Oil (per Bbl)
$
43.18

 
$
56.79

 
$
36.55

 
$
52.07

Gas (per Mcf)
2.07

 
2.78

 
1.99

 
2.76

Ngl (per Mcfe)
1.95

 
2.55

 
1.87

 
2.81

Per Mcfe
2.64

 
3.37

 
2.43

 
3.29

The above sales and average sales prices include increases (decreases) to revenue related to the settlement of gas hedges of $1,155,000 and $4,181,000, oil hedges of $0 and ($288,000) and Ngl hedges of $0 and $136,000 for the three months ended June 30, 2016 and 2015, respectively. The above sales and average sales prices include increases (decreases) to revenue related to the settlement of gas hedges of $2,187,000 and $6,505,000, oil hedges of $0 and ($261,000) and Ngl hedges of $0 and $157,000 for the six months ended June 30, 2016 and 2015, respectively. Please see Item 3. Quantitative and Qualitative Disclosures About Market Risk in this Form 10-Q for further details on our hedging program and our current hedging arrangements.
Net loss available to common stockholders totaled $24,143,000 and $61,083,000 for the quarters ended June 30, 2016 and 2015, respectively, while net loss available to common stockholders totaled $63,280,000 and $183,323,000 for the six months ended June 30, 2016 and 2015, respectively. The primary fluctuations were as follows:
Production Total production decreased 38% and 32% during the three and six month periods ended June 30, 2016, respectively, as compared to the 2015 periods. The decreases in total production were primarily the result of the divestment of a majority of our Oklahoma assets on June 4, 2015 and normal production declines at our Gulf Coast and East Texas fields. Partially offsetting

17

these decreases was the successful completion of our Thunder Bayou discovery, which commenced production in June 2015. Due to the current low commodity price environment, our capital expenditures budget for 2016 is significantly reduced as compared to 2015. As a result of the substantial decrease in capital spending, combined with our 2015 and 2016 Oklahoma divestments, we expect our total production for the remainder of 2016 to continue to decrease as compared to 2015.
Gas production during the three and six month periods ended June 30, 2016 decreased 40% and 35%, respectively, from the comparable periods in 2015. The decreases were primarily the result of the divestment of a majority of our Oklahoma assets on June 4, 2015 and normal production declines at our Gulf Coast and East Texas fields. Partially offsetting these decreases was the successful completion of our Thunder Bayou discovery. We expect our average daily gas production to decrease during the remainder of 2016 as compared to 2015 due to our 2015 and 2016 Oklahoma divestments and substantial decrease in capital spending.
Oil production during the three and six month periods ended June 30, 2016 decreased 24% and 15%, respectively, from the 2015 periods due primarily to normal production declines at our Gulf Coast and East Texas fields and downtime at certain of our Gulf of Mexico properties during the first quarter of 2016 due to a damaged third party pipeline. Partially offsetting these decreases was an increase due to the commencement of production at our Thunder Bayou discovery in June 2015. As a result of normal production declines and substantial decrease in capital spending, we expect our average daily oil production to continue to decrease during the remainder of 2016 as compared to 2015.
Ngl production during the three and six month periods ended June 30, 2016 decreased 34% and 27%, respectively, from the respective 2015 periods primarily due to our 2015 Oklahoma divestiture and normal production declines at certain of our Gulf Coast and East Texas fields. Additionally, Ngl production declined at several of our fields in the Gulf Coast where we decided to cease processing until prices improve for the residual products. Offsetting these decreases was the successful completion of our Thunder Bayou discovery. We expect our average daily Ngl production to continue to decrease during the remainder of 2016 as compared to 2015 primarily due to the divestment of the liquids rich portion of our Oklahoma acreage position and substantial decrease in capital spending.
Prices Including the effects of our hedges, average gas prices per Mcf for the three and six month periods ended June 30, 2016 were $2.07 and $1.99, respectively, as compared to $2.78 and $2.76 for the respective 2015 periods. Average oil prices per Bbl for the three and six months ended June 30, 2016 were $43.18 and $36.55, respectively, as compared to $56.79 and $52.07 for the respective 2015 periods and average Ngl prices per Mcfe were $1.95 and $1.87 for the three and six months ended June 30, 2016, respectively, as compared to $2.55 and $2.81 for the respective 2015 periods. Stated on an Mcfe basis, unit prices received during the three and six months ended June 30, 2016 were 22% and 26% lower, respectively, than the prices received during the comparable 2015 periods.
Revenue Including the effects of hedges, oil and gas sales during the three months ended June 30, 2016 decreased 51% to $15,824,000, as compared to oil and gas sales of $32,550,000 during the 2015 period. Including the effects of hedges, oil and gas sales during the six months ended June 30, 2016 decreased 50% to $33,144,000, as compared to oil and gas sales of $66,001,000 during the 2015 period. These decreases were primarily the result of lower average realized prices for our production during 2016 as well as decreased production as discussed above.
Expenses Lease operating expenses for the three and six months ended June 30, 2016 totaled $6,864,000 and $15,041,000, respectively, as compared to $11,191,000 and $22,093,000 during the respective 2015 periods. Per unit lease operating expenses totaled $1.14 and $1.10 per Mcfe, respectively, during the three and six month periods ended June 30, 2016 as compared to $1.16 and $1.10 per Mcfe during the respective 2015 periods. Total lease operating expenses decreased during the three and six months ended June 30, 2016 primarily as a result of our Oklahoma divestitures. As a result of our Oklahoma divestitures, we expect total lease operating expenses during the remainder of 2016 to decrease as compared to 2015.
Production taxes for the three and six months ended June 30, 2016 totaled ($48,000) and $290,000, respectively, as compared to $948,000 and $1,904,000, respectively, during the 2015 periods. Per unit production taxes totaled ($0.01) and $0.02 per Mcfe, respectively, during the three and six month periods ended June 30, 2016 as compared to $0.10 per Mcfe during the comparable 2015 periods. The decreases in production taxes were primarily due to lower commodity prices for our production during the 2016 periods as compared to the 2015 periods as severance taxes for the majority of our properties that are subject to severance taxes are assessed on the value of oil and gas sales. Additionally, during the second quarter of 2016 we received production tax refunds on certain of our East Texas wells which have now qualified for a gas tax credit. As a result of the current commodity pricing environment and lower estimated production as a result of our 2015 and 2016 Oklahoma divestitures, we expect a continued decrease in our total and per unit production taxes during 2016 as compared to 2015.
General and administrative expenses during the three and six months ended June 30, 2016 totaled $3,871,000 and $12,470,000, respectively, as compared to $6,519,000 and $11,858,000 during the 2015 periods. General and administrative expenses during the six months ended June 30, 2016 included $4,808,000 of costs related to the issuance of the 2021 Notes. ASC Topic 470-60

18

"Troubled Debt Restructurings by Debtors" requires financing costs related to a troubled debt restructuring to be expensed in the period incurred. Offsetting this increase were lower employee related costs, including share-based compensation. Included in general and administrative expenses for the three and six month periods ended June 30, 2016 were share-based compensation costs of $582,000 and $1,095,000, respectively, compared to $1,434,000 and $2,952,000, respectively, during the 2015 periods. We capitalized $1,634,000 and $3,188,000, respectively, of general and administrative expenses during the three and six month periods ended June 30, 2016 compared to $2,357,000 and $4,597,000, respectively, during the 2015 periods. We expect total general and administrative expenses during the remainder of 2016 to be lower than 2015.
Depreciation, depletion and amortization (“DD&A”) expense on oil and gas properties for the three and six months ended June 30, 2016 totaled $7,014,000, or $1.17 per Mcfe, and $16,964,000, or $1.24 per Mcfe, respectively, as compared to $17,996,000, or $1.86 per Mcfe, and $38,313,000, or $1.91 per Mcfe, respectively, during the comparable 2015 periods. The decreases in the per unit DD&A rate are primarily the result of the recent ceiling test write-downs. As a result of current year ceiling test write-downs, we expect our DD&A rate to be lower for the remainder of 2016.
At March 31, 2016 and June 30, 2016, the prices used in computing the estimated future net cash flows from our estimated proved reserves, including the effect of hedges in place at that date, averaged $2.19 and $2.15 per Mcf of natural gas, $45.92 and $42.12 per barrel of oil and $1.91 and $1.71 per Mcfe of Ngl, respectively. As a result of lower commodity prices and their negative impact on our estimated proved reserves and estimated future net cash flows, we recognized ceiling test write-downs of approximately $12,782,000 and $31,639,000 during the three and six month periods ended June 30, 2016, respectively.  At March 31, 2015 and June 30, 2015, the prices used in computing the estimated future net cash flows from our estimated proved reserves, including the effect of hedges in place at that date, averaged $3.31 and $3.20 per Mcf of natural gas, $81.33 and $71.27 per barrel of oil and $3.52 and $3.35 per Mcfe of Ngl, respectively. As a result of lower commodity prices and their negative impact on our estimated proved reserves and estimated future net cash flows, we recognized ceiling test write-downs of approximately $65,495,000 and $174,406,000 during the three and six month periods ended June 30, 2015, respectively. See Note 7, “Ceiling Test” for further discussion of the ceiling test write-downs. Utilizing current strip prices for oil and gas prices for the third quarter of 2016 and projecting the effect on the estimated future net cash flows from our estimated proved reserves as of June 30, 2016, we expect to recognize an additional ceiling test write-down of $4 million to $8 million in the third quarter of 2016.
Interest expense, net of amounts capitalized on unevaluated properties, totaled $6,503,000 and $14,760,000 during the three and six months ended June 30, 2016, respectively, as compared to $8,596,000 and $16,470,000, respectively, during the 2015 periods. During the three and six month periods ended June 30, 2016, our capitalized interest totaled $247,000 and $555,000, respectively, as compared to $1,379,000 and $3,376,000, respectively, during the 2015 periods. The decrease in interest expense during the 2016 periods was the result of the Exchange, including an $868,000 non-cash reduction related to the amortization of the excess carrying value on the Exchange (see Note 5 - Long-Term Debt), as well as the repayment of our bank debt in June 2015.
Income tax expense during the three and six months ended June 30, 2016 was $475,000 and $561,000, respectively, as compared to income tax expense of $2,000,000 and $1,073,000 during the comparable 2015 periods. We typically provide for income taxes at a statutory rate of 35% adjusted for permanent differences expected to be realized, primarily statutory depletion, non-deductible stock compensation expenses and state income taxes.
As a result of ceiling test write-downs, we have incurred a cumulative three-year loss. Because of the impact the cumulative loss has on the determination of the recoverability of deferred tax assets through future earnings, we assessed the realizability of our deferred tax assets based on the future reversals of existing deferred tax liabilities. Accordingly, we established a valuation allowance for a portion of our deferred tax asset. The valuation allowance was $166,551,000 as of June 30, 2016.
Liquidity and Capital Resources
We have historically financed our acquisition, exploration and development activities principally through cash flow from operations, bank borrowings, issuances of equity and debt securities, joint ventures and sales of assets. However, our liquidity position continues to be negatively impacted by the prolonged decline in commodity prices that began in late 2014. At June 30, 2016, we had $68.9 million in cash and approximately $280 million of debt represented by our 2017 Notes and 2021 Notes. In addition, at June 30, 2016, we had a working capital deficit of approximately $0.3 million as compared to a working capital surplus of approximately $50.5 million as of December 31, 2015. The decrease in working capital is primarily due to the $58.4 million in cash payments made in connection with the Exchange discussed in "Source of Capital: Debt" below. In addition, due to the prolonged decline in commodity prices and our substantial debt outstanding, we have continued to incur significant losses and negative cash flow from operating activities. For the six months ended June 30, 2016, our net loss available to common stockholders totaled $63.3 million and negative cash flow from operating activities totaled $26.1 million.

19

Although we have no borrowings outstanding under our Credit Agreement, we are not permitted to borrow under the Credit Agreement until such time as we are able to comply with the financial covenants thereunder. We expect that for the foreseeable future we will not be permitted to borrow under the Credit Agreement, and when we are able to comply with the financial covenants under the Credit Agreement, our ability to utilize the borrowing base thereunder will be limited to $5 million, subject to certain terms and conditions. For additional information, see "Source of Capital: Debt" below.
Our liquidity may be further negatively impacted by federal bonding requirements related to our properties located on the Outer Continental Shelf (the "OCS"). To cover the various obligations of lessees on the OCS, the BOEM and the BSEE generally require that lessees have substantial net worth or post bonds or other acceptable assurances that such obligations will be satisfied. Because we are not exempt from the BOEM's supplemental bonding requirements, we engage surety companies to post the requisite bonds. Pursuant to the terms of our surety agreements, we may be required to post collateral at the surety companies' discretion. Two of our surety companies have requested collateral be posted to support certain of the bonds issued on our behalf and to date, we have provided cash deposits totaling $5.2 million to partially satisfy these requests. The surety companies may request additional collateral which could have a material adverse effect on our liquidity position. If we fail to satisfy the request for collateral, we may be in default under our agreements with the surety companies, which could cause a cross-default under our Credit Agreement and potentially the indenture governing the 2021 Notes. In addition, recently updated BOEM financial assurance and risk management requirements may increase the amount of surety bonds or other security required to be provided by us. For additional information, see "Item 1A Risk Factors - We may be required to post additional collateral to satisfy the collateral requirements related to the surety bonds that secure our offshore decommissioning obligations or to increase the amount of surety bonds or other security required pursuant to updated BOEM financial assurance and risk management requiremrnts".
In response to lower commodity prices and the resulting impact to our liquidity, we have recently completed asset sales generating approximately $25 million in net proceeds. In addition, we have implemented a variety of cost cutting initiatives aimed at preserving liquidity:
•
we have reduced our 2016 capital expenditure budget to between $15 million and $20 million, a significant reduction from 2015 spending of approximately $65 million;
•
we have suspended the quarterly dividend on our outstanding Series B Preferred Stock beginning with the dividend payment in April 2016, which will save $5.1 million annually; and
•
we are also working to reduce our cash costs by at least 25% from 2015 levels, including the interest expense savings realized through debt repayments under our Credit Agreement as well as through the Exchange discussed in "Source of Capital; Debt" below.
Our substantially decreased level of capital spending has had and is expected to continue to have a negative impact on our production and cash flow from operating activities. We expect production to continue to decline throughout 2016 and when combined with current commodity prices and our existing cost structure, including 10% interest expense on the $280 million of debt represented by our 2017 Notes and 2021 Notes, we believe that we will continue to incur significant losses and negative cash flow from operating activities for the remainder of 2016. In addition, $136 million of the indebtedness represented by our 2017 Notes will mature on September 1, 2017 and would be reflected as a current liability on our September 30, 2016 balance sheet if not refinanced prior to the filing of our Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2016, which would raise substantial doubt about our ability to continue as a going concern.
We are evaluating additional sources of liquidity including asset sales, joint ventures, exchange offers and alternative financing arrangements to replace the Credit Agreement, but there is no assurance that these sources will provide sufficient, if any, incremental liquidity. We are also evaluating various options to address the September 2017 maturity of our 2017 Notes as well as assessing our overall capital structure. These options include additional public or private exchanges of 2017 Notes for new secured debt and/or common stock, refinancing the 2017 Notes with unsecured debt and/or common stock as well as a broader restructuring of our 2017 and 2021 Notes. To assist the Board of Directors and management team in evaluating these options, we have retained Jefferies LLC and Seaport Global as our financial advisors and Porter Hedges LLP as our legal advisor. There is no assurance that any refinancing or debt or equity restructuring will be possible or that additional equity or debt financing can be obtained on acceptable terms, if at all. If we are unable to improve our liquidity position, and refinance or restructure our debt, we may seek bankruptcy protection to continue our efforts to restructure our business and capital structure. As a part of that process, we may have to liquidate our assets and may receive less than the value at which those assets are carried on our consolidated financial statements. See "Item 1A Risk Factors - We may seek the protection of the Bankruptcy Court, which may harm our business and place equity holders at significant risk of losing all of their interests in the Company".
Source of Capital: Operations
Net cash flow provided by (used in) operations decreased from $5.6 million during the six months ended June 30, 2015 to ($26.1) million during the 2016 period. The decrease in operating cash flow during 2016 as compared to 2015 is primarily attributable to decreases in oil and gas revenues as well as the timing of payment of payables based on operational activity.

20

Source of Capital: Divestitures
We do not budget for property divestitures; however, we are continuously evaluating our property base to determine if there are assets in our portfolio that no longer meet our strategic objectives. From time to time we may divest certain assets in order to provide liquidity to strengthen our balance sheet or capital to be reinvested in higher rate of return projects. We are currently exploring divestment opportunities for certain of our assets. We cannot assure you that we will be able to sell any of our assets in the future.
In June 2015, we sold a majority of our interests in the Woodford and Mississippian Lime fields for cash proceeds of $260.2 million. Net proceeds from the sale were used to repay all borrowings outstanding under our bank credit facility and increase our cash on hand. In April 2016, we sold the majority of our remaining Woodford Shale assets in Oklahoma for approximately $18 million.
In March 2016, we sold certain non-producing assets in East Texas for $7 million in connection with the negotiation of a joint venture. Negotiations of the terms and conditions of this joint venture are currently ongoing. If we are unable to reach an agreement with respect to the joint venture, we will be required to purchase the non-producing assets for $5.0 million on or before December 31, 2016.
Source of Capital: Debt
On August 19, 2010, we issued $150 million in principal amount of our 10% Senior Notes due 2017. On July 3, 2013, we issued an additional $200 million in principal amount of our 10% Senior Notes due 2017 (collectively, the "2017 Notes").
On January 14, 2016, we announced the commencement of the Exchange and consent solicitation (the "Consent Solicitation") to certain eligible holders of our outstanding 2017 Notes. The Exchange closed on February 17, 2016, and in satisfaction of the tender of $214.4 million in aggregate principal amount of the 2017 Notes, representing approximately 61% of the outstanding aggregate principal amount of 2017 Notes, in the Exchange, we (i) paid approximately $53.6 million of cash, (ii) issued $144.7 million aggregate principal amount of our new 10% Second Lien Senior Secured Notes due 2021 (the "2021 Notes") and (iii) issued approximately 1.1 million shares of our common stock. Following the completion of the Exchange, $135.6 million in aggregate principal amount of the 2017 Notes remain outstanding. The Consent Solicitation eliminated or waived substantially all of the restrictive covenants contained in the indenture governing the 2017 Notes.
The following table reconciles the face value of the 2017 Notes and 2021 Notes to the carrying value included in our Consolidated Balance Sheet as of June 30, 2016 and December 31, 2015 (in thousands):
 
June 30, 2016
December 31, 2015
 
2017 Notes
2021 Notes
2017 Notes
2021 Notes
Face Value
$
135,621

$
144,674

$
350,000

$
—

Deferred Financing Costs
(855
)
(1,174
)
(2,992
)
—

Excess Carrying Value
—

13,024

—

—

Carrying Value
$
134,766

$
156,524

$
347,008

$
—

The indenture governing the 2021 Notes contains affirmative and negative covenants that, among other things, limit our ability and the subsidiary guarantors of the 2021 Notes to incur indebtedness; purchase or redeem stock; make certain investments; create liens that secure debt; enter into transactions with affiliates; sell assets; refinance certain indebtedness; merge with or into other companies or transfer substantially all of their assets; and, in certain circumstances, to pay dividends or make other distributions on stock. The 2021 Notes are fully and unconditionally guaranteed on a senior basis by certain of our wholly-owned subsidiaries.
The 2021 Notes are secured by second-priority liens on substantially all of our and our subsidiary guarantors' oil and gas properties and substantially all of our other assets to the extent such properties and assets secure the Credit Agreement (as defined below), except for certain excluded assets. Pursuant to the terms of an intercreditor agreement, the security interest in those properties and assets that secure the 2021 Notes and the guarantees are contractually subordinated to liens that secure the Credit Agreement and certain other permitted indebtedness. Consequently, the 2021 Notes and the guarantees will be effectively subordinated to the Credit Agreement and such other indebtedness to the extent of the value of such assets.
The 2021 Notes bear interest at a rate of 10% per annum on the principal amount and interest is payable semi-annually in arrears on February 15 and August 15 of each year beginning August 15, 2016. At June 30, 2016, $5.4 million had been accrued in connection with the August 15, 2016 payment. Interest on the 2017 Notes is payable semi-annually on March 1 and September 1 and the 2017 Notes mature on September 1, 2017. At June 30, 2016, $4.5 million had been accrued in connection with the September 1, 2016 interest payment.
We have a Credit Agreement (as amended, the “Credit Agreement”) with JPMorgan Chase Bank, N.A., Wells Fargo Bank, N.A., Capital One, N.A., IberiaBank, Bank of America, N.A. and The Bank of Nova Scotia. The Credit Agreement provides us

21

with a revolving credit facility that permits borrowings based on the commitments of the lenders and the available borrowing base as determined in accordance with the Credit Agreement. The Credit Agreement does not presently allow us to issue letters of credit thereunder. The credit facility matures on the earlier of June 4, 2020 or February 19, 2017 if any portion of our 2017 Notes remains outstanding as of such date which has not been refinanced with either permitted refinancing debt or permitted second lien debt with a maturity date no earlier than 180 days after June 4, 2020, all as defined in the Credit Agreement.
The borrowing base under the Credit Agreement is determined by March 31 and September 30 of each year and is based upon the valuation of the reserves attributable to our oil and gas properties as of January 1 and July 1 of each year. If we incur any borrowings, or cause the lenders to issue any letters of credit, under the Credit Agreement (the “Financial Covenant Reinstatement Date”), two interim redeterminations would occur on July 31 and December 31 of each year commencing on the first July 31 or December 31 subsequent to the Financial Covenant Reinstatement Date. We or the lenders may also request two additional borrowing base re-determinations each year. Each time the borrowing base is to be re-determined, the administrative agent under the Credit Agreement will propose a new borrowing base as it deems appropriate in its sole discretion, which must be approved by all lenders if the borrowing base is to be increased, or by lenders holding two-thirds of the amounts outstanding under the Credit Agreement if the borrowing base remains the same or is reduced. As of June 30, 2016, the borrowing base and aggregate commitments of the lenders were both $22.5 million. We have no borrowings outstanding under (and no letters of credit issued pursuant to) the Credit Agreement.
The obligation of the lenders to make loans on the account of any borrowing or issue letters of credit under the Credit Agreement, include that (i) at the time of and after giving effect to the requested borrowing or issuance, we will be in compliance with the restrictive financial covenants described below, (ii) at the time of and after giving effect to the requested borrowing or issuance, there will be no Excess Cash, defined as any unrestricted cash and cash equivalents of the Company or any of its other Subsidiaries that exceeds $10 million, and (iii) after giving effect to the requested borrowing or issuance, the aggregate amount of borrowings outstanding under (and letters of credit issued pursuant to) the Credit Agreement will not exceed $5 million. In addition, we are obligated to make mandatory prepayments on each business day from and after the Financial Covenant Reinstatement Date in the amount of any Excess Cash on such day and, once the borrowings are fully prepaid, we are required to pay any Excess Cash to the administrative agent under the Credit Agreement to provide cash collateral for any outstanding letters of credit. Based on our expectations for the third quarter of 2016, we anticipate that, pursuant to the restrictive financial covenants described below, we will not be able to utilize the borrowing base for the foreseeable future.
The Credit Agreement is secured by a first priority lien on substantially all of our assets and our subsidiaries, including a lien on all equipment and at least 90% of the aggregate total value of the Borrower’s oil and gas properties. Outstanding balances under the Credit Agreement bear interest at the alternate base rate (“ABR”) plus a margin (based on a sliding scale of 1% to 2% depending on total commitments) or the adjusted LIBO rate (“Eurodollar”) plus a margin (based on a sliding scale of 2% to 3% depending on total commitments). The alternate base rate is equal to the highest of (i) the JPMorgan Chase prime rate, (ii) the Federal Funds Effective Rate plus 0.5% or (iii) the adjusted LIBO rate (subject to a floor of 0.0%) plus 1%.  For the purposes of the definition of alternate base rate only, the adjusted LIBO rate for any day is based on the LIBO Rate at approximately 11:00 a.m. London time on such day. For all other purposes, the adjusted LIBO rate is equal to the rate at which Eurodollar deposits in the London interbank market for one, two, three or six months (as selected by us) are quoted, as adjusted for statutory reserve requirements for Eurocurrency liabilities. Outstanding letters of credit will be charged a participation fee at a per annum rate equal to the margin applicable to Eurodollar loans, a fronting fee and customary administrative fees. In addition, we pay commitment fees of 0.5% of the average daily unused amount of the commitments.
We and our subsidiaries are not presently, but will become, subject to certain restrictive financial covenants under the Credit Agreement after the Financial Covenant Restatement Date, including (i) a maximum ratio of total debt to EBITDAX (as of the last day of any fiscal quarter for the fiscal quarter period then ending) multiplied by four of 4.00 to 1.0 as of the last day of any fiscal quarter, (ii) a minimum ratio of consolidated current assets (including unused availability but excluding non-cash assets under ASC 815) to consolidated current liabilities (excluding non-cash obligations under ASC 815 and ASC 410 and, for the fiscal quarters ending September 30, 2016 and December 31, 2016, liabilities in respect of our 2017 Notes) of 1.0 to 1.0 as of the last day of any fiscal quarter and (iii) a minimum ratio of EBITDAX to total cash interest expense, determined on a four quarter basis as of the end of each fiscal quarter, of 3.0 to 1.0, as of the last day of any fiscal quarter, all as defined in the Credit Agreement.
The Credit Agreement also includes customary restrictions with respect to debt, liens, dividends, distributions and redemptions, investments, loans and advances, nature of business, international operations and foreign subsidiaries, leases, sale or discount of receivables, mergers or consolidations, sales of properties, transactions with affiliates, negative pledge agreements, gas imbalances and swap agreements. The Credit Agreement also currently prohibits us from declaring and paying dividends on its Series B Preferred Stock.

22

Source of Capital: Issuance of Securities
Our shelf registration statement, which expires in September 2016, allows us to publicly offer and sell up to $350 million of any combination of debt securities, shares of common and preferred stock, depositary shares and warrants. The registration statement does not provide any assurance that we will or could sell any such securities.
Use of Capital: Exploration and Development
Our 2016 capital expenditure budget, which includes capitalized interest and general and administrative costs, is expected to range between $15 million and $20 million (which from the midpoint of such range, represents a 73% reduction from our 2015 capital expenditures), of which $8.4 million was incurred during the first six months of 2016, before consideration of $7 million of proceeds received from the sale of certain East Texas non-producing assets. During the six months ended June 30, 2016, we funded our capital expenditures with cash on hand. We plan to fund our capital expenditures during the remainder of 2016 with cash on hand.
Use of Capital: Acquisitions
We do not budget for acquisitions; however, we are continuously evaluating opportunities to expand our existing asset base or establish positions in new core areas.
We expect to finance our future acquisition activities, if consummated, through cash on hand. We may also utilize sales of equity or debt securities, sales of properties or assets or joint venture arrangements with industry partners, if necessary. We cannot assure you that such additional financings will be available on acceptable terms, if at all.
Disclosure Regarding Forward Looking Statements
This Quarterly Report on Form 10-Q contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements other than statements of historical facts included in and incorporated by reference into this Form 10-Q are forward looking statements. These forward-looking statements are subject to certain risks, trends and uncertainties that could cause actual results to differ materially from those projected.
Among those risks, trends and uncertainties are: the volatility of oil and natural gas prices and significantly depressed oil prices since the end of 2014; our indebtedness and the significant amount of cash required to service our indebtedness; our ability to improve our liquidity position and refinance or restructure our indebtedness, including our remaining 2017 Notes; the potential need to sell assets or seek bankruptcy protection; our estimate of the sufficiency of our existing capital sources, including availability under our bank credit facility and the result of any borrowing base redetermination; our ability to post additional collateral to satisfy our offshore decommissioning obligations; our ability to hedge future production to reduce our exposure to price volatility in the current commodity pricing market; ceiling test write-downs resulting, and that could result in the future, from lower oil and natural gas prices; our ability to raise capital to fund cash requirements for future operations; limits on our growth and our ability to finance our operations, fund our capital needs and respond to changing conditions imposed by our bank credit facility and restrictive debt covenants; our ability to find, develop, produce oil and natural gas reserves that are economically recoverable and to replace reserves and sustain production; approximately 50% of our production being exposed to the additional risk of severe weather, including hurricanes and tropical storms and flooding, and natural disasters; losses and liabilities from uninsured or underinsured drilling and operating activities; changes in laws and governmental regulations as they relate to our operations; the operating hazards attendant to the oil and gas business; the volatility of our stock price; and our ability to meet the continued listing standards of the New York Stock Exchange with respect to our common stock or to cure any deficiency with respect thereto.
Although we believe that the expectations reflected in these forward-looking statements are reasonable, we cannot assure you that such expectations reflected in these forward looking statements will prove to have been correct.
When used in this Quarterly Report on Form 10-Q, the words “expect,” “anticipate,” “intend,” “plan,” “believe,” “seek,” “estimate” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain these identifying words. Because these forward-looking statements involve risks and uncertainties, actual results could differ materially from those expressed or implied by these forward-looking statements for a number of important reasons, including those discussed under “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Risk Factors” and elsewhere in this Quarterly Report on Form 10-Q.
You should read these statements carefully because they discuss our expectations about our future performance, contain projections of our future operating results or our future financial condition, or state other “forward-looking” information. You should be aware that the occurrence of any of the events described under “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Risk Factors” and elsewhere in this Quarterly Report on Form 10-Q could substantially harm our business, results of operations and financial condition and that upon the occurrence of any of these events, the trading price of our common stock could decline, and you could lose all or part of your investment.

23

We cannot guarantee any future results, levels of activity, performance or achievements. Except as required by law, we undertake no obligation to update any of the forward-looking statements in this Quarterly Report on Form 10-Q after the date of this Quarterly Report on Form 10-Q.
Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We experience market risks primarily in two areas: commodity prices and interest rates. Because our properties are located within the United States, we do not believe that our business operations are exposed to significant foreign currency exchange risks.
Commodity Price Risk
Our revenues are derived from the sale of our crude oil, natural gas and natural gas liquids production. Based on projected sales volumes for the remainder of 2016, a 10% change in the prices we receive for our crude oil, natural gas and natural gas liquids production would have a $2.5 million impact on our revenues.
We seek to reduce our exposure to commodity price volatility by hedging a portion of production through commodity derivative instruments. In the settlement of a typical hedge transaction, we will have the right to receive from the counterparties to the hedge the excess of the fixed price specified in the hedge over a floating price based on a market index multiplied by the quantity hedged. If the floating price exceeds the fixed price, we are required to pay the counterparties this difference multiplied by the quantity hedged. During the six months ended June 30, 2016, we received $2.2 million from the counterparties to our derivative instruments in connection with hedge settlements.
We are required to pay the difference between the floating price and the fixed price (when the floating price exceeds the fixed price) regardless of whether we have sufficient production to cover the quantities specified in the hedge. Significant reductions in production at times when the floating price exceeds the fixed price could require us to make payments under the hedge agreements even though such payments are not offset by sales of production. Hedging will also prevent us from receiving the full advantage of increases in oil or gas prices above the fixed amount specified in the hedge.
Our Credit Agreement requires that the counterparties to our hedge contracts be lenders under the Credit Agreement or, if not a lender under the Credit Agreement, rated A-/A3 or higher by S&P or Moody’s. Currently, the counterparty to our existing hedge contract is a lender under the Credit Agreement.
As of June 30, 2016, we had entered into the following commodity derivative instrument:
Production Period
Instrument
Type
Daily Volumes
Weighted
Average Price
Natural Gas:
 
 
 
July 2016 - December 2016
Swap
5,000 Mmbtu
$2.50
The Company has approximately 0.9 Bcf of gas volumes at $2.50 per Mcf hedged for the remainder of 2016. For further discussion of our commodity derivative instruments, please see Item 1, Note 8 "Derivative Instruments" in this Form 10-Q.
Interest Rate Risk
Debt outstanding under our bank credit facility is subject to a floating interest rate. As of June 30, 2016, we had no borrowings outstanding under our credit facility.
Item 4. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
As of the end of the period covered by this report, the Company’s management, including its Chief Executive Officer and Chief Financial Officer, completed an evaluation of the effectiveness of the Company’s disclosure controls and procedures pursuant to Rule 13a-15 of the Securities and Exchange Act of 1934, as amended (the “Exchange Act”). Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded:
i.
that the Company’s disclosure controls and procedures are designed to ensure (a) that information required to be disclosed by the Company in the reports it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms, and (b) that such information is accumulated and communicated to the Company’s management, including the Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure; and
ii.
that the Company's disclosure controls and procedures are effective.

24

Notwithstanding the foregoing, there can be no assurance that the Company’s disclosure controls and procedures will detect or uncover all failures of persons within the Company and its consolidated subsidiaries to disclose material information otherwise required to be set forth in the Company’s periodic reports. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures.
Changes in Internal Control Over Financial Reporting
There have been no changes in the Company’s internal control over financial reporting during the period covered by this report that have materially affected, or that are reasonably likely to materially affect, the Company’s internal control over financial reporting.
Part II
Item 1. LEGAL PROCEEDINGS
In May 2016, a class action lawsuit on behalf of holders of the Company's 10% Senior Notes due 2017 (the "2017 Notes") was filed in the U.S. District Court for the Southern District of New York, relating to the Company's February 2016 debt exchange, whereby the Company privately exchanged a combination of cash, shares of the Company's common stock and newly issued 10% Second Lien Senior Secured Notes due 2021 (the "2021 Notes") for the 2017 Notes. The lawsuit alleges that the Company violated the Trust Indenture Act of 1939, the indenture governing the 2017 Notes and the implied covenant of good faith and fair dealing by benefiting itself and a minority of noteholders who are qualified institutional buyers ("QIBs"). According to the lawsuit, as a result of the Company's private debt exchange in which only QIBs (and non-U.S. persons under Regulation S) were eligible to participate, the Company unjustly enriched itself at the expense of class members by reducing indebtedness, extending the maturity date of its long term debt and reducing the value of the 2017 Notes. The lawsuit seeks damages and attorney's fees, in addition to declaratory relief that the debt exchange and the liens created for the benefit of the 2021 Notes are null and void and that the debt exchange effectively resulted in a default under the indenture for the 2017 Notes.
PetroQuest is involved in litigation relating to claims arising out of its operations in the normal course of business, including worker's compensation claims, tort claims and contractual disputes. Some of the existing known claims against us are covered by insurance subject to the limits of such policies and the payment of deductible amounts by us. Management believes that the ultimate disposition of all uninsured or unindemnified matters resulting from existing litigation will not have a material adverse effect on PetroQuests's business or financial position.

Item 1A. RISK FACTORS
Oil and natural gas prices are volatile, and an extended decline in the prices of oil and natural gas would likely have a material adverse effect on our financial condition, liquidity, ability to meet our financial obligations and results of operations.

Our future financial condition, revenues, results of operations, profitability and future growth, and the carrying value of our oil and natural gas properties depend primarily on the prices we receive for our oil and natural gas production. Our ability to maintain or increase our borrowing capacity and to obtain additional capital on attractive terms also substantially depends upon oil and natural gas prices. Historically, the markets for oil and natural gas have been volatile and oil prices have been significantly depressed since the end of 2014 as demonstrated by the SEC pricing for the value of crude oil and natural gas, which has decreased significantly as of December 31, 2015 as compared to December 31, 2014. For example, the SEC pricing at December 31, 2015 for crude oil (WTI Cushing) and natural gas (Henry Hub) was $50.28 per Bbl and $2.58 per MMBtu, respectively, as compared to $94.99 per Bbl to a low of $4.35 per MMBtu for crude oil and natural gas, respectively, as of December 31, 2014. These markets will likely continue to be volatile in the future. The prices we will receive for our production, and the levels of our production, will depend on numerous factors beyond our control.
These factors include:
•
relatively minor changes in the supply of or the demand for oil and natural gas;
•
the condition of the United States and worldwide economies;
•
market uncertainty;
•
the level of consumer product demand;
•
weather conditions in the United States, such as hurricanes;

25

•
the actions of the Organization of Petroleum Exporting Countries;
•
domestic and foreign governmental regulation and taxes, including price controls adopted by the Federal Energy Regulatory Commission;
•
political conditions or hostilities in oil and natural gas producing regions, including the Middle East and South America;
•
the price and level of foreign imports of oil and natural gas; and
•
the price and availability of alternate fuel sources.
We cannot predict future oil and natural gas prices and such prices may decline further. An extended decline in oil and natural gas prices may adversely affect our financial condition, liquidity, ability to meet our financial obligations and results of operations. Lower prices have reduced and may further reduce the amount of oil and natural gas that we can produce economically and has required and will likely require us to record additional ceiling test write-downs and may cause our estimated proved reserves at December 31, 2016 to decline compared to our estimated proved reserves at December 31, 2015. Substantially all of our oil and natural gas sales are made in the spot market or pursuant to contracts based on spot market prices. Our sales are not made pursuant to long-term fixed price contracts.
To attempt to reduce our price risk, we periodically enter into hedging transactions with respect to a portion of our expected future production. We cannot assure you that we can enter into effective hedging transactions in the future or that such transactions will reduce the risk or minimize the effect of any decline in oil or natural gas prices. Any substantial or extended decline in the prices of or demand for oil or natural gas would have a material adverse effect on our financial condition, liquidity, ability to meet our financial obligations and results of operations.
We are not permitted to borrow under our bank credit facility, which limits our liquidity position and could impact the development of our properties and thus limit future cash flow from operations.
Historically, we have financed our acquisition, exploration and development activities principally through cash flow from operations, borrowings under our bank credit facility, issuances of equity and debt securities, joint ventures and sales of assets. However, we are not permitted to borrow under our bank credit facility until such time as we can comply with the financial covenants thereunder. We expect that for the foreseeable future, we will not be permitted to borrow under the facility, and when we are able to comply with the financial covenants under the facility, our ability to utilize the borrowing base under the facility will be limited to $5 million, subject to certain terms and conditions. The unavailability of our bank credit facility limits our liquidity position. As a result, we may be unable to fund the planned development of our properties, which could limit our future cash flows from operations.
Our outstanding indebtedness may adversely affect our cash flow and our ability to operate our business, remain in compliance with debt covenants and make payments on our debt.
As of June 30, 2016, the aggregate amount of our outstanding indebtedness, net of cash on hand, was $222.4 million. We may also incur additional indebtedness in the future. Our high level of debt could have important consequences for you, including the following:
•
it may be more difficult for us to satisfy our obligations with respect to our outstanding indebtedness, including our 2017 Notes and 2021 Notes, and any failure to comply with the obligations of any of our debt agreements, including financial and other restrictive covenants, could result in an event of default under the agreements governing such indebtedness;
•
the covenants contained in our debt agreements limit our ability to borrow money in the future for acquisitions, capital expenditures or to meet our operating expenses or other general corporate obligations and may limit our flexibility in operating our business;
•
we will need to use a substantial portion of our cash flows to pay interest on our debt, approximately $28.0 million per year for interest on our 2017 Notes and 2021 Notes alone, and to pay quarterly dividends (which we suspended beginning with the dividend payment due in April 2016), if permissable under the terms of our debt agreements and declared by our Board of Directors, on our Series B Preferred Stock of approximately $5.1 million per year, which will reduce the amount of money we have for operations, capital expenditures, expansion, acquisitions or general corporate or other business activities;

26

•
the amount of our interest expense may increase because certain of our borrowings in the future may be at variable rates of interest, which, if interest rates increase, could result in higher interest expense;
•
we may have a higher level of debt than some of our competitors, which may put us at a competitive disadvantage;
•
we may be more vulnerable to economic downturns and adverse developments in our industry or the economy in general, especially extended or further declines in oil and natural gas prices; and
•
our debt level could limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate.
Our ability to meet our expenses and debt obligations will depend on our future performance, which will be affected by financial, business, economic, regulatory and other factors. We will not be able to control many of these factors, such as economic conditions and governmental regulation. We cannot be certain that our cash flow from operations will be sufficient to allow us to pay the principal and interest on our debt, including our 2017 Notes and 2021 Notes, and meet our other obligations. If we do not have enough cash to service our debt, we may be required to refinance all or part of our existing debt, including our 2017 Notes and 2021 Notes, sell assets, borrow more money or raise equity. We may not be able to refinance our debt, sell assets, borrow more money or raise equity on terms acceptable to us, if at all.
We may seek the protection of the Bankruptcy Court, which may harm our business and place equity holders at significant risk of losing all of their interests in the Company.
We are in the process of analyzing various options to address our liquidity as well as assessing our overall capital structure, including the September 2017 maturity of our 2017 Notes. If we are unable to improve our liquidity position and refinance or restructure our debt, a filing under Chapter 11 of the U. S. Bankruptcy Code may be unavoidable. Seeking Bankruptcy Court protection could have a material adverse effect on our business, financial condition, results of operations and liquidity. So long as a proceeding related to a Chapter 11 proceeding continues, our senior management would be required to spend a significant amount of time and effort dealing with the reorganization instead of focusing exclusively on our business operations. Bankruptcy Court protection also might make it more difficult to retain management and other key personnel necessary to the success and growth of our business. In addition, the longer a proceeding related to a Chapter 11 proceeding continues, the more likely it is that our customers and suppliers would lose confidence in our ability to reorganize our businesses successfully and would seek to establish alternative commercial relationships.
Additionally, we have a significant amount of secured indebtedness that is senior to our unsecured indebtedness and a significant amount of total indebtedness that is senior to our existing preferred stock and common stock in our capital structure. As a result, we believe that seeking Bankruptcy Court protection under a Chapter 11 proceeding could result in a limited recovery for unsecured noteholders, if any, and place equity holders at significant risk of losing all of their interests in the Company.
We may be required to post additional collateral to satisfy the collateral requirements related to the surety bonds that secure our offshore decommissioning obligations or to increase the amount of surety bonds or other security required pursuant to updated BOEM financial assurance and risk management requirements.
     To cover the costs for various obligations of lessees on the OCS, including costs for such decommissioning obligations as the plugging of wells, the removal of platforms and other facilities, the decommissioning of pipelines and the clearing of the seafloor of obstructions typically performed at the end of production, the BOEM generally requires that the lessees post substantial bonds or other acceptable financial assurances that such obligations will be met. Failure to post the requisite bonds or otherwise satisfy the BOEM’s security requirements could have a material adverse effect on our ability to operate in the U.S. Gulf of Mexico.
Because we are not exempt from the BOEM's supplemental bonding requirements, we engage surety companies to post the requisite bonds. Pursuant to the terms of our surety agreements, we may be required to post collateral at the surety companies' discretion. Two of our surety companies have requested collateral be posted to support certain of the bonds issued on our behalf. To date, we have provided cash deposits totaling $5.2 million to partially satisfy these requests. The surety companies may request additional collateral which could have a material adverse effect on our liquidity position. If we fail to satisfy the request for collateral, we may be in default under our agreements with the surety companies, which could cause a cross-default under our bank credit facility and potentially the indenture governing the 2021 Notes.
     In addition, on July 14, 2016, the BOEM issued a notice to lessees to clarify the procedures and criteria that the BOEM will use to determine if and when additional security is required for OCS leases. This notice, which becomes effective on September 12, 2016, may result in an increase to the amount of surety bonds or other security required to be posted by us pursuant to these updated BOEM financial assurance and risk management requirements.
We can provide no assurance that we can continue to obtain bonds or other surety in all cases given these new expenses and updated BOEM requirements, and if we are unable to obtain the additional required bonds or the increased amount of required

27

collateral as requested, the BOEM may require any or all of our operations on federal leases to be suspended or canceled or otherwise impose monetary penalties, and any one or more of such actions could have a material adverse effect on our business, prospects, results of operations, financial condition, and liquidity.
Lower oil and natural gas prices may cause us to record ceiling test write-downs, which could negatively impact our results of operations.
We use the full cost method of accounting to account for our oil and natural gas operations. Accordingly, we capitalize the cost to acquire, explore for and develop oil and natural gas properties. Under full cost accounting rules, the net capitalized costs of oil and natural gas properties may not exceed a “full cost ceiling” which is based upon the present value of estimated future net cash flows from proved reserves, including the effect of hedges in place, discounted at 10%, plus the lower of cost or fair market value of unevaluated properties. If at the end of any fiscal period we determine that the net capitalized costs of oil and natural gas properties exceed the full cost ceiling, we must charge the amount of the excess to earnings in the period then ended. This is called a “ceiling test write-down.” This charge does not impact cash flow from operating activities, but does reduce our net income and stockholders' equity. Once incurred, a write-down of oil and natural gas properties is not reversible at a later date.
We review the net capitalized costs of our properties quarterly, using a single price based on the beginning of the month average of oil and natural gas prices for the prior 12 months. We also assess investments in unevaluated properties periodically to determine whether impairment has occurred. The risk that we will be required to recognize further write-downs of the carrying value of our oil and gas properties increases when oil and natural gas prices are low or volatile. In addition, write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves or our unevaluated property values, or if estimated future development costs increase. As a result of the decline in commodity prices, we recognized a ceiling test write-down of approximately $31.6 million during the six months ended June 30, 2016. Utilizing current strip prices for oil and gas prices for the third quarter of 2016 and projecting the effect on the estimated future net cash flows from our estimated proved reserves as of June 30, 2016, we expect to recognize an additional ceiling test write-down of $4 million to $8 million in the third quarter of 2016.
Item 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
The following table sets forth certain information with respect to repurchases of our common stock during the quarter ended June 30, 2016.
 
Total Number of
Shares Purchased (1)
 
Average Price
Paid Per Share
 
Total Number of
Shares
Purchased as
Part of Publicly
Announced Plan
or Program
 
Maximum Number (or
Approximate Dollar
Value) of Shares that
May be Purchased
Under the Plans or
Programs
April 1 - April 30, 2016
3,475

 
$
2.48

 
—

 
—

May 1 - May 31, 2016
302

 
2.53

 
—

 
—

June 1 - June 30, 2016
1,403

 
$
3.27

 
—

 
—

Total
5,180

 
$
2.70

 
—

 
—

 ________________________
(1)
All shares repurchased were surrendered by employees to pay tax withholding upon the vesting of restricted stock awards.

We have not paid dividends on our common stock, in cash or otherwise, and intend to retain our cash flow from operations for the future operation and development of our business. We are currently restricted from paying dividends on our common stock by our bank credit facility, the indenture governing the 2021 Notes and, in some circumstances, by the terms of our Series B Preferred Stock. Any future dividends also may be restricted by our then-existing debt agreements.

Item 3. DEFAULTS UPON SENIOR SECURITIES
The Company's Board of Directors did not declare a dividend on the Company's 6.875% Series B Cumulative Convertible Perpetual Preferred Stock for the quarterly period ended April 15, 2016. As of the date of this report, the Company had dividends in arrears of approximately $2.6 million.

Item 4. MINE SAFETY DISCLOSURES
NONE.

28


Item 5. OTHER INFORMATION
NONE.

Item 6. EXHIBITS
Exhibit 2.1*#, Purchase and Sale Agreement dated as of April 20, 2016, by and between PetroQuest Energy, L.L.C. and GR Woodford Properties, LLC.
 
Exhibit 3.1, Certificate of Amendment to Certificate of Incorporation dated May 18, 2016 (incorporated herein by reference to Exhibit 3.1 to Form 8-K filed on May 20, 2016).
 
Exhibit 3.2, Certificate of Amendment to Certificate of Incorporation dated May 18, 2016 (incorporated herein by reference to Exhibit 3.2 to Form 8-K filed on May 20, 2016).
 
Exhibit 10.1, PetroQuest Energy, Inc. 2016 Long Term Incentive Plan (incorporated herein by reference to Appendix A to the Company's Definitive Proxy Statement on Schedule 14A filed on April 7, 2016).
 
Exhibit 10.2, Fourteenth Amendment to Credit Agreement dated as of June 20, 2016, among PetroQuest Energy, Inc., PetroQuest Energy, L.L.C., TDC Energy LLC, JPMorgan Chase Bank, N.A., Wells Fargo Bank, N.A., Capital One, N.A., IberiaBank, Bank of America, N.A. and The Bank of Nova Scotia (incorporated herein by reference to Exhibit 10.1 to Form 8-K filed on June 21, 2016).
 
Exhibit 31.1, Certification of Chief Executive Officer pursuant to Rule 13-a-14(a)/Rule 15d-14(a), promulgated under the Securities Exchange Act of 1934, as amended.
 
Exhibit 31.2, Certification of Chief Financial Officer pursuant to Rule 13-a-14(a)/Rule 15d-14(a), promulgated under the Securities Exchange Act of 1934, as amended.
 
Exhibit 32.1, Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
 
Exhibit 32.2, Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
 
Exhibit 101.INS, XBRL Instance Document
 
Exhibit 101.SCH, XBRL Taxonomy Extension Schema Document.
 
Exhibit 101.CAL, XBRL Taxonomy Extension Calculation Linkbase Document.
 
Exhibit 101.DEF, XBRL Taxonomy Definitions Linkbase Document
 
Exhibit 101.LAB, XBRL Taxonomy Extension Label Linkbase Document.
 
Exhibit 101.PRE, XBRL Taxonomy Extension Presentation Linkbase Document

* The registrant agrees to furnish supplementally a copy of any omitted schedule to the Purchase and Sale Agreement to the SEC upon request.
# Confidential treatment has been requested for portions of this exhibit. Omissions are designated with brackets containing asterisks. As part of our confidential treatment request, a complete version of this exhibit has been filed separately with the SEC.


29

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 thereunto duly authorized.
 

 
PETROQUEST ENERGY, INC.



Date:
August 3, 2016
/s/ J. Bond Clement

 
J. Bond Clement
Executive Vice President, Chief Financial Officer
(Authorized Officer and Principal
Financial and Accounting Officer)

30
Execution Version HN\1378916.125654385v1 CONFIDENTIAL INFORMATION, MARKED BY BRACKETS AND ASTERISKS ([***]), IN THIS EXHIBIT HAS BEEN OMITTED AND FILED SEPARATELY WITH THE SECURITIES AND EXCHANGE COMMISSION. CONFIDENTIAL TREATMENT HAS BEEN REQUESTED WITH RESPECT TO THIS OMITTED INFORMATION. PURCHASE AND SALE AGREEMENT BETWEEN PETROQUEST ENERGY, L.L.C. AS SELLER AND GR WOODFORD PROPERTIES, LLC AS BUYER

 
ii [***] Confidential information has been omitted and filed separately with the Securities and Exchange Commission. Confidential treatment has been requested with respect to this omitted information. TABLE OF CONTENTS Page ARTICLE 1 DEFINITIONS ............................................................................................................1 1.1 Definitions; References and Construction ...............................................................1 ARTICLE 2 SALE OF ASSETS/PURCHASE PRICE .................................................................12 2.1 Purchase and Sale of Assets ...................................................................................12 2.2 Purchase Price .......................................................................................................15 2.3 Purchase Price Adjustments ..................................................................................15 2.4 Preliminary Settlement Statement ..........................................................................16 2.5 Final Settlement Statement ....................................................................................16 2.6 Purchase Price Allocation .....................................................................................17 2.7 Suspense Funds ......................................................................................................17 2.8 Assumed Liabilities ................................................................................................17 2.9 Disputed Well Interests ..........................................................................................18 ARTICLE 3 [INTENTIONALLY OMITTED] ..............................................................................18 ARTICLE 4 ALLOCATION OF RESPONSIBILITIES AND INDEMNITIES ...........................18 4.1 Opportunity for Review ..........................................................................................18 4.2 Seller’s Indemnity Obligation ................................................................................18 4.3 Buyer’s Indemnity Obligation ................................................................................18 4.4 Threshold, Aggregate Threshold, Cap ...................................................................18 4.5 Tax Treatment .........................................................................................................18 4.6 Notice of Claims .....................................................................................................18 4.7 Defense of Non-Party Claims ................................................................................19 4.8 Investigation and Knowledge .................................................................................20 4.9 Waiver of Certain Damages ...................................................................................20 4.10 Extent of Indemnification .......................................................................................20 4.11 Survival ..................................................................................................................20 4.12 Environmental Liabilities .......................................................................................20 ARTICLE 5 DISCLAIMERS ........................................................................................................21 ARTICLE 6 SELLER’S REPRESENTATIONS AND WARRANTIES .......................................22 6.1 Organization and Good Standing ..........................................................................23 6.2 Authority; Authorization of Agreement ..................................................................23 6.3 No Violations ..........................................................................................................23 6.4 Liability for Brokers’ Fees .....................................................................................23 6.5 Legal Proceedings ..................................................................................................23 6.6 Bankruptcy .............................................................................................................23 6.7 Taxes .......................................................................................................................24 6.8 Material Contracts .................................................................................................24 6.9 [***] .......................................................................................................................24 6.10 Preferential Rights .................................................................................................24 6.11 Consents .................................................................................................................24 6.12 [***] .......................................................................................................................24 6.13 Current Commitments ............................................................................................24 6.14 [***] .......................................................................................................................24

 
iii [***] Confidential information has been omitted and filed separately with the Securities and Exchange Commission. Confidential treatment has been requested with respect to this omitted information. 6.15 Production Imbalances ..........................................................................................24 6.16 [***] .......................................................................................................................24 6.17 [***] .......................................................................................................................24 6.18 [***] .......................................................................................................................24 6.19 Liens .......................................................................................................................24 6.20 [Intentionally Omitted]...........................................................................................24 6.21 [***] .......................................................................................................................24 6.22 [***] .......................................................................................................................24 6.23 [***] .......................................................................................................................24 6.24 [***] .......................................................................................................................24 ARTICLE 7 BUYER’S REPRESENTATIONS AND WARRANTIES ........................................25 7.1 Organization and Good Standing ..........................................................................25 7.2 Authority; Authorization of Agreement ..................................................................25 7.3 No Violations ..........................................................................................................25 7.4 Liability for Brokers’ Fees .....................................................................................25 7.5 Claims, Disputes and Litigation ............................................................................25 7.6 Bankruptcy .............................................................................................................26 7.7 Financing; Resources and Other Capabilities .......................................................26 7.8 Independent Evaluation .........................................................................................26 7.9 Accredited Investor ................................................................................................26 ARTICLE 8 COVENANTS ...........................................................................................................26 8.1 Release of Liens .....................................................................................................26 8.2 Consents .................................................................................................................26 8.3 Approvals of Governmental Authorities.................................................................27 8.4 Efforts .....................................................................................................................28 8.5 Governmental Bonds ..............................................................................................29 8.6 Records in Seller’s Possession ...............................................................................29 8.7 Operatorship ..........................................................................................................29 ARTICLE 9 [INTENTIONALLY OMITTED] ..............................................................................30 ARTICLE 10 THE CLOSING .......................................................................................................30 10.1 Closing ...................................................................................................................30 10.2 Obligations of Seller at Closing .............................................................................30 10.3 Obligations of Buyer at Closing ............................................................................31 10.4 DDA .......................................................................................................................31 10.5 Employees ..............................................................................................................31 ARTICLE 11 [INTENTIONALLY OMITTED] ............................................................................32 ARTICLE 12 TAXES ....................................................................................................................32 12.1 Tax Partnership ......................................................................................................32 12.2 Cooperation on Tax Matters ..................................................................................32 12.3 Property and Excise Taxes .....................................................................................32 12.4 Severance Taxes .....................................................................................................33 12.5 Transfer Taxes ........................................................................................................33

 
iv ARTICLE 13 MISCELLANEOUS................................................................................................33 13.1 Notices....................................................................................................................33 13.2 Transaction and Filing Costs .................................................................................34 13.3 Amendments and Severability ................................................................................34 13.4 Successors and Assigns ..........................................................................................34 13.5 Headings ................................................................................................................35 13.6 Governing Law; Jurisdiction; Waiver of Trial by Jury ..........................................35 13.7 No Partnership Created .........................................................................................35 13.8 Public Announcements ...........................................................................................35 13.9 No Third Party Beneficiaries .................................................................................36 13.10 Waiver; Rights Cumulative ....................................................................................36 13.11 Construction ...........................................................................................................36 13.12 Conspicuousness of Provisions ..............................................................................36 13.13 Execution in Counterparts .....................................................................................36 13.14 Entire Agreement ....................................................................................................36 EXHIBITS AND SCHEDULES EXHIBIT A-1 Leases EXHIBIT A-2 Wells EXHIBIT A-3 Pooling Orders EXHIBIT A-4 Marketing Agreements EXHIBIT B Excluded Assets EXHIBIT C Certificate of Non-Foreign Status EXHIBIT D Form of Assignment SCHEDULE 2.4 Preliminary Settlement Statement SCHEDULE 6.3 Consents or Approvals SCHEDULE 6.5 Legal Proceedings SCHEDULE 6.7 Tax Matters SCHEDULE 6.8 Material Contracts SCHEDULE 6.9 Violation of Laws SCHEDULE 6.10 Preferential Purchase Rights SCHEDULE 6.12 Contested Royalties SCHEDULE 6.13 Current Commitments SCHEDULE 6.14 Environmental SCHEDULE 6.15 Imbalances SCHEDULE 6.16 Lease Termination Notices SCHEDULE 6.17 Permit Violations SCHEDULE 6.18 Well Issues SCHEDULE 6.22 Operation of Assets SCHEDULE 6.23 Salt Water Injection Violations SCHEDULE 6.24 Claims of Personal Injury or Death SCHEDULE 8.1 Liens SCHEDULE 8.5 Bonds

 
1 5654385v1 PURCHASE AND SALE AGREEMENT This Purchase and Sale Agreement (together with the Exhibits and Schedules made a part hereof, this “Agreement”), dated the 20th day of April, 2016 (the “Execution Date”), is made by and between PetroQuest Energy, L.L.C., a Louisiana limited liability company (“Seller”), and GR WOODFORD PROPERTIES, LLC, a Delaware limited liability company (“Buyer”). Seller and Buyer are sometimes hereinafter referred to individually as a “Party” and collectively as the “Parties”: WHEREAS, Seller and Buyer are parties to a certain Drilling and Development Agreement made and entered into on June 18, 2014 originally by and between Seller and Buyer’s predecessor-in-interest (the “DDA”) pursuant to which Buyer acquired certain undivided interests in the Assets (hereinafter defined), all as more particularly set forth in the DDA and any assignment from Seller to Buyer pursuant to the DDA; WHEREAS, pursuant to the DDA, Seller was designated “Operator” pursuant to certain Applicable Operating Agreements (as defined in the DDA); WHEREAS, Seller desires to sell and Buyer desires to purchase the oil and gas leases, wells, royalty interests, operating rights and other properties, interests, assets and rights comprising the Assets (hereinafter defined); NOW, THEREFORE, for a good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the Parties agree as follows: ARTICLE 1 DEFINITIONS 1.1 Definitions; References and Construction. In this Agreement, capitalized terms have the meanings provided in this Article 1, unless defined elsewhere in this Agreement. All defined terms include both the singular and the plural of such terms. All references to Sections refer to Sections in this Agreement, and all references to Exhibits or Schedules refer to Exhibits or Schedules made a part of this Agreement. When the term “herein” is used in this Agreement, reference is made to the entire Agreement and not to any particular Section or subparagraph of a Section. The word “including” shall mean including without limitation. The words “shall” and “will” are interchangeably used throughout this Agreement and shall accordingly be given the same meaning, regardless of which word is used. “Accounting Referee” means PricewaterhouseCoopers, or similar nationally recognized firm. “Adjusted Purchase Price” has the meaning set forth in Section 2.2. “Adjustments” means the adjustments to the Base Purchase Price pursuant to Section 2.3. “AFEs” has the meaning set forth in Section 6.13.

 
2 [***] Confidential information has been omitted and filed separately with the Securities and Exchange Commission. Confidential treatment has been requested with respect to this omitted information. 5654385v1 “Affiliate” means any Person that, directly or indirectly, through one or more entities, controls or is controlled by or is under common control with the Person specified. For the purpose of the immediately preceding sentence, the term “control” means the power to direct or cause the direction of the management and policies of such Person, whether through the ownership of voting securities or by contract or agency or otherwise. “Affiliate COSA” means that certain Contract Operating Services Agreement dated June 4, 2015, by and between Seller and WSGP Gas Producing, LLC. “Aggregate Indemnity Deductible” means [***]. “Agreement” has the meaning set forth in the introductory paragraph “Applicable JOAs” means all Contracts that are joint operating agreements, pooling orders and pre-pooling agreements and under which Seller is the designated operator. “Assets” has the meaning set forth in Section 2.1. “Assignment” means a document in the form of Exhibit D. “Assumed Liabilities” has the meaning set forth in Section 2.8. “Barrel” or “Bbl” means 42 U.S. gallons. “Base Purchase Price” has the meaning set forth in Section 2.2. “BLM” means the Bureau of Land Management, Department of the Interior, United States of America. “Business Day” means a Day other than Saturday, Sunday or any other Day when federally chartered banks in the United States are required to be closed. “Buyer” has the meaning set forth in the introductory paragraph. “Buyer Group” means Buyer and its Affiliates together with its and their members, partners, officers, directors, managers, agents, representatives, consultants and employees. “Certificate of Non-Foreign Status” means a certificate in the form of Exhibit C. “Claims” means any and all written claims, demands, suits, causes of action, losses, damages, liabilities, fines, penalties, fees, expenses and costs (including reasonable attorneys’ fees and costs of litigation). “Close” or “Closing” means the consummation of the sale of the Assets from Seller to Buyer, including execution and delivery of all documents and other legal consideration as provided for in this Agreement pursuant to Article 10.

 
3 [***] Confidential information has been omitted and filed separately with the Securities and Exchange Commission. Confidential treatment has been requested with respect to this omitted information. 5654385v1 “Closing Amount” has the meaning set forth in Section 2.2. “Closing Date” has the meaning set forth in Section 10.1. “Code” means the Internal Revenue Code of 1986, as amended. “Contracts” has the meaning set forth in Section 2.1(c). “Customary Post-Closing Consents” means consents and approvals from Governmental Authorities that are customarily obtained after Closing in connection with a transaction similar to the one contemplated by this Agreement. “Day” means a calendar day consisting of 24 hours from midnight to midnight. “Disputed Well Interests” has the meaning set forth in Section 2.9. “Dollars” means United States Dollars. “E&P Business” means the business and operations conducted by Seller in its ordinary course of business to the extent pertaining to the Assets. “Effective Time” means April 1, 2016, at 12:01 a.m. local time where the Assets are located. “Environmental Condition” shall mean (a) any condition existing on or prior to the Closing Date with respect to the air, soil, subsurface, surface waters, ground waters and/or sediments that causes any Asset to not be in material compliance with any Environmental Laws, or (b) any environmental release of Hazardous Substance which could reasonably be expected to result in any material liability to Seller (including with respect to any remedial or corrective action) arising under existing Environmental Laws. “Environmental Laws” means any and all Laws relating to the prevention of pollution, the preservation and restoration of environmental quality, the protection of human health, wildlife or environmentally sensitive areas, the remediation of contamination, the generation, handling, treatment, storage, transportation, disposal or release into the environment of waste materials, or the regulation of or exposure to hazardous, toxic or other substances alleged to be harmful. Environmental Laws include all applicable judicial and administrative Orders, consent decrees or directives issued by a Governmental Authority pursuant to the foregoing. Unless expressly included in and required by applicable requirements of statutes, regulations, judicial and administrative Orders, consent decrees or directives issued by a Governmental Authority included in Environmental Laws, Environmental Laws do not include good or desirable operating practices or standards that may be employed or adopted by other oil or gas well or pipeline operators or recommended but not required by a Governmental Authority. Furthermore, Environmental Laws do not include the Occupational Safety and Health Act or any other Law governing worker safety or workplace conditions. “Environmental Liabilities” means any and all liabilities, responsibilities, claims, suits, losses, costs (including remediation, removal, response, abatement, clean-up, investigative,

 
4 [***] Confidential information has been omitted and filed separately with the Securities and Exchange Commission. Confidential treatment has been requested with respect to this omitted information. 5654385v1 and/or monitoring costs and any other related costs and expenses), damages, natural resource damages, settlements, consulting fees, expenses, assessments, liens, penalties, fines, orphan share, prejudgment and post-judgment interest, court costs, and reasonable attorney fees incurred or imposed (a) pursuant to any order, notice of responsibility, directive (including requirements embodied in Environmental Laws), injunction, judgment or similar ruling or act (including settlements) by any Governmental Authority to the extent arising out of any violation of, or remedial obligation under, any Environmental Law that is attributable to (or for which any liability or responsibility is incurred or imposed as a result of) the ownership or operation of the Assets prior to, at or after the Closing Date, or (b) pursuant to any claim or cause of action by a Governmental Authority or other Person for personal injury, death, property damage, damage to natural resources, remediation or response costs, or similar costs or expenses to the extent arising out of a release of Hazardous Materials or any violation of, or any remediation obligation under, any Environmental Laws that is attributable to (or for which any liability or responsibility is incurred or imposed as a result of) the ownership or operation of the Assets prior to, at or after the Closing Date, or (c) as a result of Environmental Conditions; provided, however, that Environmental Liabilities shall not include any Claims for which Seller is required to indemnify Buyer pursuant to Article 4. “Equipment” has the meaning set forth in Section 2.1(f). “Excise Taxes” has the meaning set forth in Section 12.3. “Excluded Assets” means (a) those assets, interests, rights and contracts described on Exhibit B; (b) any Assets subject to a Hard Consent which are excluded from the Assets pursuant to Section 8.2; (c) all trade credits, all accounts, receivables and all other proceeds, income or revenues attributable to the Assets with respect to any period of time prior to the Effective Time; (d) all claims and causes of action of Seller arising under or with respect to any Contracts that are attributable to periods of time prior to the Effective Time (including claims for adjustments or refunds); (e) all rights and interests relating to the Assets, (i) under any existing policy or agreement of insurance, (ii) under any bond or (iii) to any insurance or condemnation proceeds or awards arising, in each case, from acts, omissions or events, or damage to or destruction of property; (f) all Hydrocarbons produced and sold from the Assets with respect to all periods prior to the Effective Time; (g) any Tax refunds or Tax carry-forwards amounts attributable to the Assets prior to the Effective Time or to Seller’s business generally; (h) all personal computers, network equipment and associated peripherals and telephone equipment (including cellular telephones); (i) vehicles; (j) all of Seller’s proprietary computer software (including the CC 9000 security software), patents, trade secrets, copyrights, names, trademarks, logos and other intellectual property; (k) to the extent not materially interfering with Buyer’s ownership and operation of the Assets, concurrent rights and interests with Buyer in, to and under the Contracts, Surface Contracts and Permits, to the extent, and only to the extent, necessary to own, operate and/or develop the Retained Depths and/or any of the other Excluded Assets. “Excluded Chesapeake Liabilities” has the meaning set forth in Section 2.9. “Excluded Records” has the meaning set forth in Section 2.1(h).

 
5 [***] Confidential information has been omitted and filed separately with the Securities and Exchange Commission. Confidential treatment has been requested with respect to this omitted information. 5654385v1 “Excluded Working Interest” means [***]. “Execution Date” has the meaning set forth in the introductory paragraph. “Final Settlement Statement” has the meaning set forth in Section 2.5. “Governmental Authority” means any federal, state, local, municipal or other government; any governmental, regulatory or administrative agency, commission, body or other authority exercising or entitled to exercise any administrative, executive, judicial, legislative, police, regulatory or taxing authority or power; and any court or governmental tribunal, including any tribal authority having jurisdiction. “Hard Consent” has the meaning set forth in Section 8.2(b). “Hazardous Materials” shall mean any substance or material that is, or if released or disposed of would be, designated, classified, characterized or regulated as a “hazardous substance”, “hazardous waste”, “hazardous material”, “toxic substance”, “pollutant” or “contaminant” under Environmental Laws. “Hedges” means any swap, collar, floor, cap, option or other Contract that is intended to eliminate or reduce the risk of fluctuations in the price of Hydrocarbons. “Hydrocarbons” means oil, gas, natural gas liquids, casinghead gas, coal bed methane, condensate and other gaseous and liquid hydrocarbons or any combination thereof. “Imbalance” means over-production or under-production or over-deliveries or under-deliveries on account of (a) any imbalance at the wellhead between the amount of Hydrocarbons produced from a Well constituting part of the Assets and allocable to the interests of Seller, and the shares of production from the relevant Well that are actually taken by or delivered to or for the account of Seller and (b) any marketing imbalance between the quantity of Hydrocarbons constituting part of the Assets and required to be delivered by or to Seller under any Contracts relating to the purchase and sale, gathering, transportation, storage, treating, processing, or marketing of Hydrocarbons and the quantity of Hydrocarbons actually delivered by or to Seller pursuant to the applicable Contracts. “Indemnity Claim” has the meaning set forth in Section 4.6. “Indemnity Claim Notice” has the meaning set forth in Section 4.6. “Indemnity Obligations” mean the obligations of a Party to RELEASE, DEFEND, INDEMNIFY and HOLD HARMLESS the other Party from and against specified Claims as provided in this Agreement. “Individual Indemnity Threshold” has the meaning set forth in Section 4.4(b). “Intended Tax Treatment” has the meaning set forth in Section 12.1.

 
6 [***] Confidential information has been omitted and filed separately with the Securities and Exchange Commission. Confidential treatment has been requested with respect to this omitted information. 5654385v1 “Knowledge” means (a) with respect to Seller, the actual knowledge of the following individuals [***] and (b) with respect to Buyer, the actual knowledge of the following individuals [***]. “Laws” means any and all laws, statutes, ordinances, permits, decrees, writs, injunctions, Orders, codes, judgments, principles of common law, rules or regulations that are promulgated, issued or enacted by a Governmental Authority having jurisdiction. “Leases” has the meaning set forth in Section 2.1(a). “Legal Proceedings” means any and all proceedings, suits and causes of action by or before any Governmental Authority and all arbitration proceedings. “Lowest Cost Remediation Amount” means, with respect to an Environmental Condition, the lowest cost of response and/or remediation required or permitted under Environmental Law that completely addresses and resolves (for current use in the same manner as currently used) the identified Environmental Condition in its entirety. “Material Adverse Effect” means a change, event, circumstance, development, state of facts or condition that (a) results, or would reasonably be expected to result, in a material adverse effect on the Assets (as currently owned and operated) or the results of operations of Seller with respect to the Assets, individually, or taken as a whole or (b) materially impairs, prevents, delays or makes impossible the consummation of the transactions contemplated by this Agreement; provided, however, that a Material Adverse Effect shall not include any material adverse effects resulting from: (i) entering into this Agreement or the announcement of the transactions contemplated by this Agreement; (ii) changes in general market, economic, financial or political conditions (including changes in commodity prices (including Hydrocarbons), fuel supply or transportation markets, interest or rates) in the area in which the Assets are located, the United States or worldwide; (iii) conditions (or changes in such conditions) generally affecting the oil and gas and/or gathering, processing or transportation industry whether as a whole or specifically in any area or areas where the Assets are located; (iv) acts of God, including storms or meteorological events; (v) orders, actions or failures to act of Governmental Authorities; (vi) civil unrest or similar disorder, the outbreak of hostilities, terrorist acts or war; (vii) any actions taken or omitted to be taken (A) by or at the written request or with the prior written consent of Buyer or (B) as expressly permitted or prescribed hereunder; (viii) a change in Laws or in GAAP interpretation from and after the Execution Date; (ix) reclassification or recalculation of reserves in the ordinary course of business; and (x) natural declines in well performance. “Material Contracts” has the meaning set forth in Section 6.8(a). “MCF” means thousand cubic feet.

 
7 HN\1378916.125654385v1 “Net Revenue Interest” means the interest (expressed as a percentage or decimal fraction) as set forth on Exhibit A-2, in and to Hydrocarbons produced from or allocated to a Well. “Non-Party” means any Person other than the Parties or their respective Affiliates. “Oil and Gas Properties” has the meaning set forth in Section 2.1(b). “Operating Expenses” shall mean Seller’s obligation for any and all costs and expenses (including lease operating expenses, drilling and completion costs, plugging and abandonment costs, seismic costs, workover costs, capital expenditures, costs of performing title due diligence (including the preparation of title opinions and mineral ownership reports), permitting costs, costs related to obtaining rights-of-ways or easements for operations, joint interest billings, overhead charges, Taxes and all insurance premiums or any other costs of insurance attributable to Seller’s and/or its Affiliates’ insurance and to coverage periods from and after the Effective Time but excluding in all cases, all costs and expenses of bonds, letters of credit or other surety instruments) which relate to the Assets and are incurred by Seller in connection with the ownership, operation, development or maintenance of the Assets in the ordinary course of business, and excluding liabilities, losses, costs, and expenses attributable to: (i) claims, investigations, administrative proceedings, arbitration or litigation directly or indirectly arising out of or resulting from actual or claimed personal injury or other torts, illness or death; property damage (other than damage to structures, fences, irrigation systems and other fixtures, crops, livestock, and other personal property in the ordinary course of business); (ii) violation of any Law (or private cause or right of action under any Law); (iii) environmental damage or liabilities, including obligations to remediate any contamination of groundwater, surface water, soil, sediments, or Equipment under applicable Environmental Law; (iv) title and environmental claims (including claims that Leases have terminated); (v) claims of improper calculation or payment of royalties (including overriding royalties and other burdens on production) related to deduction of post- production costs or use of posted or index prices or prices paid by Affiliates; (vi) gas balancing and other production balancing obligations for which there is an adjustment to the Base Purchase Price hereunder; (vii) overhead, except to the extent due and owing pursuant to a joint operating agreement associated with the Assets; (viii) any claims for indemnification, contribution, or reimbursement from any third Person with respect to liabilities, losses, costs, and expenses of the

 
8 HN\1378916.125654385v1 type described in preceding clauses (i) through (vii), whether such claims are made pursuant to contract or otherwise. “Operative Documents” means those documents referenced in Sections 10.2 and 10.3. “Order” means any order, judgment, injunction, non-appealable final order, ruling or decree of any court or other Governmental Authority. “Party” or “Parties” has the meaning set forth in the introductory paragraph. “Permits” has the meaning set forth in Section 2.1(e). “Permitted Encumbrances” means with respect to any Asset any and all of the following: (a) consents to assignment and similar contractual provisions affecting such Asset including Customary Post-Closing Consents to the extent such consents are addressed pursuant to Section 8.2; (b) preferential rights to purchase and similar contractual provisions affecting such Asset insofar as the same have been waived or the counterparties’ preference rights thereunder have expired in accordance with the terms thereof; (c) required notices to and filings with any Governmental Authority in connection with the consummation of the transaction contemplated by this Agreement; (d) rights reserved to or vested in a Governmental Authority having jurisdiction to control or regulate such Asset in any manner whatsoever and all Laws of such Governmental Authorities, provided that the foregoing does not reduce the Net Revenue Interest or increase the Working Interest of the associated Well(s); (e) easements, rights-of-way, permits, licenses, servitudes, surface leases, sub-surface leases, equipment, pipelines, utility lines and structures on, over or through such Asset that do not (i) materially detract from the value of or materially affect or impair the ownership, use or operation of such Asset or (ii) reduce the Net Revenue Interest or increase the Working Interest of the associated Well(s); (f) liens for Taxes or assessments not yet delinquent or, if delinquent, that are being contested in good faith in the normal course of business, the responsibility for which is retained by Seller; (g) liens of operators relating to obligations not yet delinquent or, if delinquent, that are being contested in good faith in the normal course of business, the responsibility for which is retained by Seller; (h) any (i) undetermined or inchoate liens or charges constituting or securing the payment of expenses that were incurred incidental to maintenance, development, production

 
9 HN\1378916.125654385v1 or operation of such Asset or for the purpose of developing, producing or processing Hydrocarbons therefrom or therein, and (ii) materialman’s, mechanics’, repairmen’s, employees’, contractors’ or other similar liens or charges relating to obligations not yet delinquent or, if delinquent, that are being contested in good faith in the normal course of business, the responsibility for which is retained by Seller; (i) conventional rights of reassignment upon final intention to abandon or release an Asset; (j) any liens or security interests created by Law or reserved in oil and gas leases for royalty, bonus or rental, or created to secure compliance with the terms of the agreements, instruments and documents or records that create or reserve such Asset; (k) any obligations or duties affecting such Asset to any Governmental Authority with respect to any franchise, grant, license or permit of record or contained in the Records; (l) the terms and conditions of the Leases; (m) the Contracts set forth on Schedule 6.8; (n) zoning and planning ordinances and municipal regulations; and (o) the terms and conditions of this Agreement. “Person” means an individual, group, partnership, corporation, limited liability company, trust or other entity. “Preferential Right” has the meaning set forth in Section 6.10. “Preliminary Settlement Statement” has the meaning set forth in Section 2.4. “Prime Rate” means the rate of interest published and updated from time to time by the Wall Street Journal as the “prime” rate. “Property Taxes” has the meaning set forth in Section 12.3. “Records” has the meaning set forth in Section 2.1(h). “Retained Depths” means the oil, gas and/or mineral leases, covering those depths that are excluded as set forth on Exhibit B. “Retained Liabilities” means the following obligations: (a) any and all obligations, liabilities and Claims in any way relating to the ownership and/or operation of the Assets, excluding, in each case, Environmental Liabilities, arising during, related to or otherwise attributable to the period prior to the Effective Time;

 
10 HN\1378916.125654385v1 (b) all obligations and amounts owed to any employees of Seller relating to the employment of such individuals by Seller or the termination of employment of such individuals by Seller; (c) all obligations and liabilities owed to any employees of Seller arising under any employee benefit or welfare plan maintained by Seller; (d) all Claims asserted by any employee of Seller for bodily injury or death prior to the Effective Time; (e) all Claims asserted by any Non-Parties for bodily injury to or death of such Non-Parties or damage to property owned by such Non-Parties to the extent resulting or arising from, or attributable to, the use, ownership or operation of the Assets and attributable to periods prior to the Effective Time; (f) all Hedges of Seller; (g) the disposal or transportation of any Hazardous Material to any location not on the Assets or lands pooled or unitized therewith to the extent resulting or arising from, or attributable to, the use, ownership or operation of the Assets and attributable to periods prior to the Closing Date; (h) the responsibility for the disposition of and the liabilities and obligations with respect to the Legal Proceedings relating to the Assets and filed prior to the Effective Time, including those described on Schedule 6.5; (i) subject to the DDA and Applicable JOAs, Seller’s liabilities with respect to any Operating Expenses related to Seller’s Working Interest in the Assets and accrued during the period prior to the Effective Time; (j) all Claims relating to any Taxes imposed on or with respect to Seller or any of its Affiliates other than Taxes allocated to Buyer pursuant to Sections 12.3, 12.4 and 12.5; and (k) the Excluded Chesapeake Liabilities; provided, however, nothing herein related to the definition of Retained Liabilities (or any obligations of Seller related thereto (including Indemnity Obligations)) shall affect or restrict Seller’s rights against Buyer under any prior agreement between Seller or its Affiliates, on the one hand, and Buyer or its Affiliates, on the other hand, (including rights off contribution, offset or indemnity). “Seller” has the meaning set forth in the introductory paragraph. “Seller Bonds” has the meaning set forth in Section 8.5. “Seller Employees” has the meaning set forth in Section 10.5.

 
11 HN\1378916.125654385v1 “Seller Group” means Seller and its Affiliates, together with its and their members, partners, officers, directors, managers agents, representatives, consultants and employees. “Shallow Depth Properties” means the Retained Depths, together with Seller’s right, title and interest in any royalties, overriding royalties, net profits interests, carried interests, or mineral fee interests to the extent attributable to the Retained Depths, and any Hydrocarbon wells producing from the Retained Depths and any other real or personal property associated with the ownership and/or operation of any of the foregoing. “Specified Representations and Warranties” means the representations and warranties of Seller set forth in Sections 6.1, 6.2, 6.3, 6.4, 6.6 and 6.12. “Surface Contracts” has the meaning set forth in Section 2.1(d). “Suspense Funds” means those proceeds from the sale of Hydrocarbons attributable to the Assets and payable to owners of working interests, royalties, overriding royalties and other similar interests that are held by Seller in suspense as of the Closing Date including royalty proceeds held in suspense. “Tax” or “Taxes” means any taxes, assessments, fees and other governmental charges imposed by any Taxing Authority, including without limitation income, profits, gross receipts, net proceeds, alternative or add-on minimum, ad valorem, value added, turnover, sales, use, property, personal property (tangible and intangible), environmental, stamp, leasing, lease, user, excise, duty, franchise, capital stock, transfer, registration, license, withholding, social security (or similar), unemployment, disability, payroll, employment, fuel, excess profits, occupational, premium, windfall profit, severance, estimated, or other charge of any kind whatsoever, including any interest, penalty, or addition thereto, and including any liability for any of the foregoing items that arises by reason of transferee or successor liability. “Tax Partnership” has the meaning set forth in Section 12.1. “Tax Purposes” has the meaning set forth in Section 12.1. “Tax Return” means any return, declaration, report, claim for refund, or information return or statement relating to Taxes, including any schedule or attachment thereto. “Taxing Authority” means, with respect to any Tax, the governmental entity or political subdivision thereof that imposes such Tax, and the agency (if any) charged with the collection of such Tax for such entity or subdivision, including any governmental or quasi- governmental entity or agency that imposes, or is charged with collecting, social security or similar charges or premiums. “Transfer Taxes” has the meaning set forth in Section 12.5. “Treasury” means the United States Department of the Treasury. “Units” has the meaning set forth in Section 2.1(b).

 
12 HN\1378916.125654385v1 “Wells” has the meaning set forth in Section 2.1(a). “Working Interest” means the percentage of costs and expenses associated with the exploration, drilling, development, operation and abandonment of any Well required to be borne with respect thereto as set forth on Exhibit A-2. ARTICLE 2 SALE OF ASSETS/PURCHASE PRICE 2.1 Purchase and Sale of Assets. Subject to and in accordance with the terms and conditions of this Agreement (including Section 8.7), Seller agrees to sell and assign to Buyer, and Buyer agrees to purchase and acquire from Seller, all of Seller’s right, title and interest in and to the following (such right, title and interest of Seller in and to the following (less and except the Excluded Assets and the Excluded Working Interest), collectively, the “Assets”): (a) all oil and gas leases, oil, gas and mineral leases, mineral servitudes, subleases and other leaseholds, royalties, overriding royalties, net profits interests, carried interests, mineral fee interests, farmout rights and operating and record title rights (as such terms are commonly used by the BLM) that are described on Exhibit A-1 (in each case, subject to the depth limitations set forth on Exhibit A-1), and including all other right, title and interest of Seller in and to the lands covered by or described in the instruments described on Exhibit A-1 (subject to the depth limitations set forth on Exhibit A-1), whether or not such rights, titles and interests are listed on Exhibit A-1 (collectively, the “Leases”); and any and all Hydrocarbon, source water, CO2, (whether producing, inactive, temporarily or permanently abandoned, shut-in or otherwise) on the Leases or Units, including, but not limited to, the interests in the wells described on Exhibit A-2 but provided the term “Wells” does not include any disposal or injection wells (whether producing, inactive, temporarily or permanently abandoned, shut-in or otherwise) (the foregoing collectively, subject to the exclusions, the “Wells”); (b) all pooled, communitized or unitized acreage, whether voluntarily formed or established by order of the Oklahoma Corporation Commission or under communitization agreements with the Bureau of Indian Affairs, that includes all or part of any Leases or the Wells, including those formed pursuant to the pooling orders set forth on Exhibit A-3 (the “Units”), and all tenements, hereditaments and appurtenances belonging to the Leases, Wells and Units but provided the term “Oil and Gas Properties” does not include any interest in disposal or injection wells (the foregoing, subject to such exclusions, together with the Leases, Wells, and Units, the “Oil and Gas Properties”); (c) all contracts, agreements and instruments existing as of the Closing Date to the extent by which the Oil and Gas Properties are bound or subject or that relate to or are otherwise applicable with respect to the Oil and Gas Properties, including operating agreements, unitization, pooling, and communitization agreements, declarations and orders, area of mutual interest agreements, joint venture agreements, farm in and farm out agreements, exploration agreements, participation agreements, marketing agreements (including those marketing agreements set forth on Exhibit A-4), exchange agreements, transportation agreements, gathering agreements, agreements for the sale and purchase of Hydrocarbons, processing and treating agreements, including, to the extent applicable, the contracts, agreements and instruments listed

 
13 HN\1378916.125654385v1 on Schedule 6.8, but provided the term “Contracts” does not include (i) the Leases and the Surface Contracts, (ii) any item listed on Schedule 6.8 that has expired or is otherwise of no further force or effect as of the Effective Date with respect to the Oil and Gas Properties notwithstanding its inclusion on Schedule 6.8, and (iii) any contract, agreement or instrument that would otherwise fall within the definition of “Material Contract” but is not listed on Schedule 6.8 unless such document is appurtenant to the Oil and Gas Properties and transfers therewith as a matter of law (the foregoing, subject to such exclusions, the “Contracts”); (d) to the extent assignable, all surface fee interests, easements, permits, licenses, servitudes, rights-of-way, surface leases and other rights to use the surface appurtenant to, and used or held for use in connection with, the Oil and Gas Properties, but provided the term “Surface Contracts” does not include any interest in disposal or injection wells or equipment related to such wells (the foregoing, subject to such exclusions, the “Surface Contracts”); (e) to the extent assignable, all permits, water rights (including water withdrawal, storage, discharge, treatment, injection and disposal rights), licenses, registrations, consents, orders, approvals, variances, exemptions, waivers, franchises, rights and other authorizations issued by any Governmental Authority that are primarily related to the use, ownership or operation of any of the Oil and Gas Property or Equipment but provided the term “Permits” does not include any interest in disposal or injection wells or equipment (the foregoing collectively, subject to the exclusions, the “Permits”); (f) all equipment, machinery, fixtures, facilities, gathering systems, pipelines, flow lines, tank batteries, and materials, and other tangible personal property, fixtures and improvements used or held for use in connection with the ownership or operation of the Oil and Gas Properties or the Surface Contracts, together with any movables and immovables located on the Oil and Gas Properties or the Surface Contracts but provided the term “Equipment” does not include any equipment or infrastructure associated with disposal or injection wells (whether producing, inactive, temporarily or permanently abandoned, shut-in or otherwise) (the foregoing collectively, subject to such exclusions, the “Equipment”) ; (g) all Hydrocarbons produced from or attributable to the Oil and Gas Properties after the Effective Time; all oil, condensate and scrubber liquids inventories and ethane, propane, iso-butane, nor-butane and gasoline inventories from the Oil and Gas Properties in storage as of the Effective Time (including pipeline inventories and linefill); all Imbalances as of the Effective Time, together with all proceeds of any thereof; and all make-up rights attributable to the period of time from and after the Effective Time with respect to take-or-pay arrangements; (h) to the extent assignable, the data and records of Seller (including lease files; land files; well files; gas and oil sales contract files; gas processing files; division order files; abstracts; title opinions; land surveys; logs; maps; engineering data and reports; geological and geophysical data and files; technical evaluations and technical outputs; and other books, records, data, files and accounting records) to the extent relating to the Oil and Gas Properties or the other Assets, excluding:

 
14 HN\1378916.125654385v1 (1) all corporate, financial, Tax and legal data and records of Seller that relate to Seller’s business generally; (2) any data and records to the extent disclosure or transfer is prohibited, or subjected to payment of a fee or other consideration, by any license agreement or other agreement with a Person other than Affiliates of Seller, or by applicable Law, and for which no consent to transfer has been received or for which Buyer has not agreed in writing to pay the fee or other consideration, as applicable; (3) all legal records and legal files of Seller, including, but not limited to, all work product of, and attorney-client communications with, Seller’s legal counsel (other than Leases, Surface Contracts, title opinions, Contracts and Seller’s working files for any Claims included in the Assumed Liabilities); (4) any data and records relating to the sale of the Assets, including bids received from and records of negotiations with Non-Parties; (5) any data and records constituting or relating solely to the Excluded Assets; (6) to the extent not assignable without the payment of fees or other penalties to Persons other than Affiliates of Seller or the securing of a licensor’s consent, unless Buyer has secured such consent in writing, all seismic, geological, geochemical or geophysical data licensed by Seller and interpretations of such data; and (7) employee information, internal valuation data, business plans, reserve reports, business studies, and transaction proposals pertaining to the sale of the Assets and related correspondence. (The data and records referred to in Clauses (1) through (7) shall hereinafter be referred to as the “Excluded Records” and, subject to such exclusions, the data and records described in this Section 2.1(h) shall be referred to as the “Records”); (i) All (A) trade credits, accounts receivable, notes receivable, take-or-pay amounts receivable, and other receivables and general intangibles, attributable to the Assets with respect to periods of time from and after the Effective Time; (B) liens and security interests in favor of Seller, whether choate or inchoate, under any Law or Contract to the extent arising from, or relating to, the ownership, operation, or sale or other disposition on or after the Effective Time of any of the Assets or to the extent arising in favor of Seller as the operator or non-operator of any Oil and Gas Property; and (C) indemnity, contribution, and other such rights in favor of Seller or its Affiliates, to the extent relating to obligations or liabilities assumed by Buyer pursuant to this Agreement or otherwise borne or paid by Buyer or with respect to which Buyer has an obligation to indemnify Seller; (j) All rights of Seller to audit the records of any Person and to receive refunds or payments of any nature, and all amounts of money relating thereto, whether before,

 
15 HN\1378916.125654385v1 on, or after the Effective Time, to the extent relating to the obligations assumed by Buyer pursuant to this Agreement or with respect to which Buyer has an obligation to indemnify Seller; and (k) To the extent assignable, all franchises, licenses, permits, approvals, consents, certificates and other authorizations, and other rights granted by third Persons, and all certificates of convenience or necessity, immunities, privileges, grants, and other such rights that relate to, or arise from, the Assets or the ownership or operation thereof. The Assets shall not include the Excluded Assets or the Excluded Working Interest. 2.2 Purchase Price. The total purchase price, subject to adjustment in accordance with the terms of this Agreement, to be paid to Seller by Buyer for the Assets is $18,000,000.00 (the “Base Purchase Price”). The Base Purchase Price shall be adjusted as set forth in Section 2.3 (as so adjusted, the “Adjusted Purchase Price”). The estimate set forth on Schedule 2.4 constitutes the Dollar amount to be paid by Buyer to Seller at Closing by wire transfer of immediately available funds to an account designated by Seller (the “Closing Amount”). 2.3 Purchase Price Adjustments. The Base Purchase Price shall be adjusted, without duplication, as follows: (a) Upward by the sum of the following: (i) an amount equal to the value of all oil, condensate and scrubber liquids inventories and ethane, propane, iso-butane, nor-butane, and gasoline inventories from the Assets in storage as of the Effective Time, with the value to be based on $1.95 per MCF and $36.00 per Barrel, less amounts payable as royalties, overriding royalties and other burdens upon, measured by or payable in respect of such Hydrocarbons; (ii) an amount equal to all Operating Expenses, paid by Seller that are attributable to the Assets from and after the Effective Time, whether paid before or after the Effective Time, including, without duplication of any other amounts set forth in this Section 2.3(a); (iii) without duplication of any other amounts set forth in this Section 2.3(a), the amount of all Taxes, if any, allocated to Buyer pursuant to Article 12 but paid by Seller; (iv) an amount equal to the value of Imbalances attributable to the Assets owing to Seller as of the Effective Time, with the value to be based on $1.95 per MCF and $36.00 per Barrel; and (v) except as expressly provided otherwise herein, any other amount provided for elsewhere in this Agreement or otherwise agreed in writing by the Parties.

 
16 HN\1378916.125654385v1 (b) Downward by the sum of the following: (i) an amount equal to all proceeds received by Seller for the sale of the Hydrocarbons produced from the Assets from and after the Effective Time less amounts actually paid by Seller as royalties, overriding royalties and other burdens measured by or payable out of such production, and less severance taxes actually paid by Seller applicable to such production, except as otherwise accounted for pursuant to Section 2.3(a)(i); (ii) without duplication of any other amounts set forth in this Section 2.3(b), the amount of all Taxes, if any, allocated to Seller pursuant to pursuant to Article 12 but paid by Buyer; (iii) an amount equal to the value of Imbalances attributable to the Assets owed by Seller as of the Effective Time, with the value to be based on $1.95 per MCF and $36.00 per Barrel; (iv) the sum of the mutually agreed upon value of the Assets subject to a Hard Consent being retained by Seller pursuant to Sections 8.2; and (v) except as expressly provided otherwise herein, any other amount provided for elsewhere in this Agreement or otherwise agreed in writing by the Parties. (c) To the extent applicable, the Adjustments pursuant to this Section 2.3 shall be determined in accordance with U.S. generally accepted accounting principles. 2.4 Preliminary Settlement Statement. A mutually agreed upon preliminary settlement statement (the “Preliminary Settlement Statement”) is attached hereto as Schedule 2.4 and sets forth an estimate of the Adjustments and the Adjusted Purchase Price through and including the Closing Date. 2.5 Final Settlement Statement. No later than 180 Days after the Closing Date, Seller will deliver to Buyer a final settlement statement (the “Final Settlement Statement”) setting forth the actual amounts of Adjustments and the resulting Adjusted Purchase Price, together with associated back-up documentation. As soon as reasonably practicable, but in no event later than 30 Days after Buyer receives the Final Settlement Statement, Buyer may deliver to Seller a written report containing any changes that Buyer proposes to be made to such statement. If Buyer fails to timely deliver the written report to Seller containing changes Buyer proposes to be made to the Final Settlement Statement, the statement as delivered by Seller will be deemed to be correct and will be final and binding on the Parties and not subject to further audit or arbitration. As soon as reasonably practicable, but in no event later than 15 Days after Seller receives Buyer’s written report, the Parties shall meet and undertake to agree on the final adjustments to the Final Settlement Statement. If the Parties fail to agree on the final adjustments within such 15-Day period, either Party may submit the disputed items to the Accounting Referee for resolution. The Parties shall direct the Accounting Referee to resolve the disputes within 20 Days after having the relevant materials submitted for review. The decision of the Accounting Referee will be binding on and non-appealable by the Parties. The fees and

 
17 HN\1378916.125654385v1 expenses associated with the Accounting Referee will be borne equally by the Parties. Any amounts owed by one Party to the other as a result of the Final Settlement Statement, together with interest on such amount from (and including) the Closing Date to (and excluding) the date of payment at the Prime Rate, will be paid within five Business Days after the date when the amounts are agreed upon by the Parties or the Parties receive a decision of the Accounting Referee, and the Adjustments included in the Final Settlement Statement will be final and binding between the Parties and not subject to further audit or arbitration. 2.6 Purchase Price Allocation. Seller and Buyer agree that the Base Purchase Price and any liabilities assumed by Buyer under this Agreement (to the extent properly taken into account under the Code) shall be allocated among the Assets in a manner consistent with Section 743, 754 and 755 of the Code and the Treasury Regulations thereunder. 2.7 Suspense Funds. Seller shall retain the Suspense Funds and shall remain responsible for administering the Suspense Funds in accordance with all applicable Laws, rules and regulations and shall be liable for the payment thereof to the proper parties, and such obligations shall be deemed part of the Retained Liabilities. 2.8 Assumed Liabilities. Upon Closing, subject to the provisions of Section 8.7, Buyer assumes and hereby agrees to fulfill, perform, be bound by, pay and discharge (or cause to be fulfilled, performed, paid or discharged) all obligations and liabilities of any kind whatsoever of Seller arising from or relating to the Assets, or the use and/or ownership thereof, that are attributable to periods before, on or after the Effective Time, including obligations to (a) furnish makeup gas and/or settle Imbalances according to the terms of applicable gas sales, processing, gathering or transportation Contracts included in the Assets, (b) pay working interests, royalties, overriding royalties and other interests, owners’ revenues or proceeds attributable to sales of Hydrocarbons, including those held in suspense (excluding the Suspense Funds) to the extent attributable to the Assets, (c) properly plug and abandon any and all wells and pipelines, including future wells, inactive wells or temporarily abandoned wells, drilled on the Assets, (d) to re-plug any well, wellbore or previously plugged Well on the Assets to the extent required or necessary under applicable Laws or under Contracts or Surface Contracts, (e) dismantle or decommission and remove any Equipment and other property of whatever kind located on the Assets related to or associated with activities conducted by whomever on the Assets, (f) clean up and/or remediate the Assets in accordance with any Contracts, Surface Contracts and applicable Laws, including all Environmental Laws, and (g) perform all obligations applicable to or imposed on the lessee or owner under the Leases, Permits, Surface Contracts and/or the Contracts, or as required by Law (the “Assumed Liabilities”); provided, Buyer does not assume (and Assumed Liabilities shall not include): (i) the Retained Liabilities, (ii) any obligations or liabilities of Seller to the extent that they are attributable to or arise out of the ownership, use or operation of the Excluded Assets, (iii) any other Claims for which Seller is required to indemnify Buyer pursuant to Article 4; and (iv) any Environmental Liabilities arising during, related to or otherwise attributable to the period prior to the Closing Date.

 
18 HN\1378916.125654385v1 2.9 Disputed Well Interests. The Parties acknowledge and agree that Chesapeake Exploration, L.L.C. has questioned its working interest ownership in certain wells located in the Shannon and Larissa Units in Sections 26 and 27, T7N, R17E, Pittsburgh County, OK (the “Disputed Well Interests”). The Parties further acknowledge and agree (a) that the current circumstances surrounding the Disputed Well Interests shall not constitute a breach of any of the representations or warranties of Seller herein and (b) that Buyer and Seller hereby reserve all rights, obligations and liabilities each Party may have with respect to any Claims which may be brought by Chesapeake Exploration, L.L.C. in connection with the Disputed Well Interests. All rights, obligations and liabilities arising from or related to the Disputed Well Interests to the extent (and only to the extent) arising from Seller’s undivided interest in the Shannon and Larissa Units (or any Leases or Wells related thereto) as of the period immediately prior to the Execution Date (the “Excluded Chesapeake Liabilities”) shall be excluded from the Assumed Liabilities; provided that, for the avoidance of doubt, the Excluded Chesapeake Liabilities do not include any rights, obligations or liabilities arising from or related to the Disputed Well Interests to the extent arising from Buyer’s existing undivided interest in the Shannon and Larissa Units (or any Leases or Wells related thereto) as of the period immediately prior to the Execution Date. ARTICLE 3 [INTENTIONALLY OMITTED] ARTICLE 4 ALLOCATION OF RESPONSIBILITIES AND INDEMNITIES 4.1 Opportunity for Review. Each Party represents that it has had an adequate opportunity to review the release and indemnity provisions in this Agreement, including the opportunity to submit the same to legal counsel for review and comment. Based upon the foregoing representation, the Parties agree to the provisions set forth below. 4.2 Seller’s Indemnity Obligation [***] 4.3 Buyer’s Indemnity Obligation. [***] 4.4 Threshold, Aggregate Threshold, Cap. [***] 4.5 Tax Treatment. The Parties shall treat, for Tax purposes, any amounts paid under this Article 4 as an adjustment to the Adjusted Purchase Price. 4.6 Notice of Claims. If a Claim is asserted against a Person for which a Party may have Indemnity Obligations under this Agreement (an “Indemnity Claim”), the indemnified Person shall give the indemnifying Party written notice of the underlying Claim setting forth the particulars associated with the underlying Claim (including a copy of the written underlying Claim, if any) as then known by the indemnified Person (“Indemnity Claim Notice”). The indemnified Person shall, to the extent practicable, give an Indemnity Claim Notice within such time as will allow the indemnifying Party a reasonable period in which to evaluate and timely respond to the underlying Claim; provided failure to do so shall not affect an indemnified Person’s rights hereunder except for, and only to the extent of, any incremental increase in the cost of the Indemnity Claim resulting from the failure to give notice.

 
19 HN\1378916.125654385v1 4.7 Defense of Non-Party Claims. Upon receipt of an Indemnity Claim Notice involving a Non-Party for which an indemnifying Party believes it may have an obligation of indemnity under this Agreement, the indemnifying Party shall, if it so elects in accordance with this Section 4.7 (without prejudice to its right to contest its obligation of indemnity under this Agreement), assume the defense of the Non-Party Claim with counsel selected by the indemnifying Party, and the indemnified Person shall cooperate in all reasonable respects. If any Non-Party Claim involves a fact pattern wherein each Party may have an obligation to indemnify the other Party, each Party may assume the defense of and hire counsel for that portion of the Non-Party Claim for which it may have an obligation of indemnity. In all instances, the indemnified Person may employ separate counsel and participate in the defense of any Non- Party Claim; provided, if the indemnifying Party has assumed the defense of a Non-Party Claim pursuant to this Section 4.7 and has agreed to indemnify the indemnified Person, the fees and expenses of counsel employed by the indemnified Person shall be borne solely by the indemnified Person. If the indemnifying Party elects by written notice to undertake the defense of the Non-Party Claim within 30 Days after receipt of the Indemnity Claim Notice, then (i) the indemnifying Party shall defend the indemnified Person against such Non-Party Claim, (ii) the indemnifying Party shall pay any judgment entered or settlement with respect to such Non-Party Claim, (iii) the indemnifying Party shall not consent to the entry of any judgment or enter into any settlement with respect to such Non-Party Claim that (A) does not include a provision whereby the plaintiff or claimant in the matter releases the indemnified Person from all liability with respect to such Non-Party Claim, or (B) would restrict such indemnified Person’s ability to conduct its business in the ordinary course, and (iv) the indemnified Person shall not consent to the entry of any judgment or enter into any settlement with respect to such Non-Party Claim without the indemnifying Party’s prior written consent. If the indemnifying Party has not elected to undertake the defense of a Non-Party Claim, or if the indemnifying Party assumes the defense of a Non-Party Claim pursuant to this Section 4.7 but fails to diligently defend against the Non- Party Claim within 30 Days following any written notice from such indemnified Person asserting such failure, then the indemnified Person shall have the right to defend, at the sole cost and expense of the indemnifying Party (to the extent the indemnified Person is entitled to indemnification hereunder), the Non-Party Claim by all appropriate proceedings. In such instances, the indemnified Person shall have full control of such defense and proceedings; provided, the indemnified Person shall not settle such Non-Party Claim without the written consent of the indemnifying Party; provided further, if the indemnifying Party fails to notify the indemnified Person in writing as to whether or not it consents to such settlement within 30 Days following its receipt of notice of such settlement from the indemnified Person, then such consent shall be deemed given. The indemnifying Party may participate in, but not control, any defense or settlement controlled by an indemnified Person pursuant to this Section 4.7, and the indemnifying Party shall bear its own costs and expenses with respect to such participation. Notwithstanding the other provisions of this Section 4.7, if the indemnifying Party disputes its potential liability to the indemnified Person under this Section 4.7 and if such dispute is resolved in favor of the indemnifying Party, the indemnifying Party shall not be required to bear the costs and expenses of the indemnified Person’s defense pursuant to this Section 4.7.

 
20 HN\1378916.125654385v1 4.8 Investigation and Knowledge. Buyer acknowledges that it has had the opportunity to conduct due diligence and investigation with respect to the Assets, and in no event shall Seller have any liability to Buyer with respect to any breach of Seller’s representations, warranties or covenants under this Agreement to the extent Buyer had Knowledge of such breach as of the Closing Date. 4.9 Waiver of Certain Damages. EACH OF THE PARTIES EXPRESSLY WAIVES AND RELEASES, AND SHALL CAUSE ITS AFFILIATES TO WAIVE AND RELEASE, SPECIAL, INDIRECT, CONSEQUENTIAL, PUNITIVE, REMOTE, SPECULATIVE AND EXEMPLARY DAMAGES, INCLUDING DAMAGES FOR LOST PROFITS OF ANY KIND WITH RESPECT TO ANY DISPUTE ARISING UNDER, RELATED TO, OR IN CONNECTION WITH THIS AGREEMENT OR ANY OTHER AGREEMENT, CONTRACT OR INSTRUMENT CONTEMPLATED HEREIN OR IN CONNECTION WITH THE TRANSACTIONS CONTEMPLATED HEREBY, EXCEPT, IN EACH CASE, TO THE EXTENT ANY SUCH PARTY SUFFERS SUCH DAMAGES (INCLUDING COSTS OF DEFENSE AND REASONABLE ATTORNEY’S FEES INCURRED IN CONNECTION WITH DEFENDING OF SUCH DAMAGES) TO A THIRD PARTY, WHICH DAMAGES (INCLUDING COSTS OF DEFENSE AND REASONABLE ATTORNEY’S FEES INCURRED IN CONNECTION WITH DEFENDING AGAINST SUCH DAMAGES) SHALL NOT BE EXCLUDED BY THIS PROVISION AS TO RECOVERY HEREUNDER. 4.10 Extent of Indemnification. WITHOUT LIMITING THE SCOPE OF THE INDEMNIFICATION, DISCLAIMER, RELEASE AND ASSUMPTION OBLIGATIONS SET FORTH IN THIS AGREEMENT, TO THE FULLEST EXTENT PERMITTED BY LAW, AN INDEMNIFIED PERSON SHALL BE ENTITLED TO INDEMNIFICATION HEREUNDER IN ACCORDANCE WITH THE TERMS HEREOF, REGARDLESS OF WHETHER THE CLAIM OR INDEMNIFIABLE LOSS GIVING RISE TO ANY SUCH INDEMNITY OBLIGATION IS THE RESULT OF THE SOLE, PARTIAL, ACTIVE, PASSIVE, CONCURRENT OR COMPARATIVE NEGLIGENCE, GROSS NEGLIGENCE, STRICT LIABILITY, OTHER LEGAL FAULT OR RESPONSIBILITY, OR VIOLATION OF ANY LAW OF OR BY ANY SUCH INDEMNIFIED PERSON. 4.11 Survival. [***] 4.12 Environmental Liabilities. [***]

 
21 HN\1378916.125654385v1 ARTICLE 5 DISCLAIMERS BUYER ACKNOWLEDGES AND AGREES THAT, EXCEPT AS OTHERWISE EXPRESSLY PROVIDED IN ARTICLE 6 AND IN THE SPECIAL WARRANTY SET FORTH IN THE ASSIGNMENT, NEITHER SELLER NOR ANY AFFILIATE OF SELLER MAKES ANY REPRESENTATION OR WARRANTY, EXPRESS, STATUTORY, IMPLIED OR OTHERWISE WITH RESPECT TO THE ASSETS. EXCEPT AS OTHERWISE EXPRESSLY PROVIDED IN ARTICLE 6 AND IN THE SPECIAL WARRANTY SET FORTH IN THE ASSIGNMENT, SELLER, FOR ITSELF AND ITS AFFILIATES, HEREBY EXPRESSLY DISCLAIMS AND NEGATES ANY AND ALL REPRESENTATIONS AND WARRANTIES, EXPRESS, STATUTORY, IMPLIED OR OTHERWISE, AND PROJECTIONS, FORECASTS, STATEMENTS OR INFORMATION MADE, COMMUNICATED OR FURNISHED (ORALLY OR IN WRITING) TO BUYER OR ANY OF ITS AFFILIATES OR REPRESENTATIVES, ASSOCIATED WITH THE ASSETS. EXCEPT AS AND TO THE LIMITED EXTENT EXPRESSLY REPRESENTED OTHERWISE IN ARTICLE 6 AND IN THE SPECIAL WARRANTY SET FORTH IN THE ASSIGNMENT, AND WITHOUT LIMITING THE GENERALITY OF THE FOREGOING, SELLER EXPRESSLY DISCLAIMS ANY REPRESENTATION OR WARRANTY, EXPRESS, STATUTORY OR IMPLIED, AS TO (a) TITLE TO ANY OF THE ASSETS, (b) THE CONTENTS, CHARACTER OR NATURE OF ANY REPORT OF ANY PETROLEUM ENGINEERING CONSULTANT OR ANY ENGINEERING, GEOLOGICAL OR SEISMIC DATA OR INTERPRETATION, RELATING TO THE ASSETS, (c) THE QUANTITY, QUALITY OR RECOVERABILITY OF HYDROCARBONS IN OR FROM THE ASSETS, (d) ANY ESTIMATES OF THE VALUE OF THE ASSETS OR FUTURE REVENUES GENERATED BY THE ASSETS, (e) THE PRODUCTION OF HYDROCARBONS FROM THE ASSETS, (f) THE MAINTENANCE, REPAIR, CONDITION, QUALITY, SUITABILITY, DESIGN OR MARKETABILITY OF THE ASSETS, (g) THE CONTENT, CHARACTER OR NATURE OF ANY INFORMATION MEMORANDUM, REPORTS, BROCHURES, CHARTS OR STATEMENTS PREPARED BY SELLERS OR THIRD PARTIES WITH RESPECT TO THE ASSETS, (h) ANY OTHER MATERIALS OR INFORMATION THAT MAY HAVE BEEN MADE AVAILABLE TO BUYER OR ITS AFFILIATES OR ITS OR THEIR EMPLOYEES, AGENTS, CONSULTANTS, REPRESENTATIVES OR ADVISORS IN CONNECTION WITH THE TRANSACTIONS CONTEMPLATED BY THIS AGREEMENT OR ANY DISCUSSION OR PRESENTATION RELATING THERETO AND (i) ANY IMPLIED OR EXPRESS WARRANTY OF FREEDOM FROM PATENT OR TRADEMARK INFRINGEMENT. EXCEPT AS AND TO THE LIMITED EXTENT EXPRESSLY REPRESENTED OTHERWISE IN ARTICLE 6 OR THE ASSIGNMENT, SELLER FURTHER DISCLAIMS ANY REPRESENTATION OR WARRANTY, EXPRESS, STATUTORY OR IMPLIED, OF MERCHANTABILITY, FREEDOM FROM LATENT VICES OR DEFECTS, FITNESS FOR A PARTICULAR PURPOSE OR CONFORMITY TO MODELS OR SAMPLES OF MATERIALS OF ANY OF THE ASSETS, RIGHTS OF A PURCHASER UNDER APPROPRIATE STATUTES TO CLAIM DIMINUTION OF CONSIDERATION OR RETURN OF THE PURCHASE PRICE, IT

 
22 HN\1378916.125654385v1 BEING EXPRESSLY UNDERSTOOD AND AGREED BY THE PARTIES THAT BUYER SHALL BE DEEMED TO BE OBTAINING THE ASSETS IN THEIR PRESENT STATUS, CONDITION AND STATE OF REPAIR, “AS IS” AND “WHERE IS” WITH ALL FAULTS OR DEFECTS (KNOWN OR UNKNOWN, LATENT, DISCOVERABLE OR UNDISCOVERABLE), AND THAT BUYER HAS MADE OR CAUSED TO BE MADE SUCH INSPECTIONS OF THE ASSETS AS BUYER DEEMS APPROPRIATE. OTHER THAN AS AND TO THE LIMITED EXTENT EXPRESSLY REPRESENTED OTHERWISE IN SECTION 6.14, SELLER HAS NOT AND WILL NOT MAKE ANY REPRESENTATION OR WARRANTY REGARDING ANY MATTER OR CIRCUMSTANCE RELATING TO ENVIRONMENTAL LAWS, THE RELEASE OF HAZARDOUS SUBSTANCES INTO THE ENVIRONMENT OR THE PROTECTION OF HUMAN HEALTH, SAFETY, NATURAL RESOURCES OR THE ENVIRONMENT, OR ANY OTHER ENVIRONMENTAL CONDITION OF THE ASSETS, AND NOTHING IN THIS AGREEMENT OR OTHERWISE SHALL BE CONSTRUED AS SUCH A REPRESENTATION OR WARRANTY, AND SUBJECT TO BUYER’S LIMITED RIGHTS AS EXPRESSLY SPECIFIED IN THIS AGREEMENT FOR A BREACH OF SELLER’S REPRESENTATIONS SET FORTH IN SECTION 6.14, BUYER SHALL BE DEEMED TO BE OBTAINING THE ASSETS “AS IS” AND “WHERE IS” WITH ALL FAULTS FOR PURPOSES OF THEIR ENVIRONMENTAL CONDITION AND THAT BUYER HAS MADE OR CAUSED TO BE MADE SUCH ENVIRONMENTAL INSPECTIONS OF THE ASSETS AS BUYER DEEMS APPROPRIATE. BUYER ACKNOWLEDGES THAT THE ASSETS HAVE BEEN USED FOR EXPLORATION, DEVELOPMENT, PRODUCTION, GATHERING AND TRANSPORTATION OF OIL AND GAS AND THERE MAY BE PETROLEUM, PRODUCED WATER, WASTES OR OTHER SUBSTANCES OR MATERIALS LOCATED IN, ON OR UNDER THE ASSETS OR ASSOCIATED WITH THE ASSETS. EQUIPMENT AND SITES INCLUDED IN THE ASSETS MAY CONTAIN ASBESTOS, NORM OR OTHER HAZARDOUS SUBSTANCES. NORM MAY AFFIX OR ATTACH ITSELF TO THE INSIDE OF WELLS, PIPELINES, MATERIALS AND EQUIPMENT AS SCALE, OR IN OTHER FORMS. THE WELLS, MATERIALS AND EQUIPMENT LOCATED ON THE ASSETS OR INCLUDED IN THE ASSETS MAY CONTAIN NORM AND OTHER WASTES OR HAZARDOUS SUBSTANCES. NORM CONTAINING MATERIAL AND/OR OTHER WASTES OR HAZARDOUS SUBSTANCES MAY HAVE COME IN CONTACT WITH VARIOUS ENVIRONMENTAL MEDIA, INCLUDING, WATER, SOILS OR SEDIMENT. SPECIAL PROCEDURES MAY BE REQUIRED FOR THE ASSESSMENT, REMEDIATION, REMOVAL, TRANSPORTATION OR DISPOSAL OF ENVIRONMENTAL MEDIA, WASTES, ASBESTOS, NORM AND OTHER HAZARDOUS SUBSTANCES FROM THE ASSETS. FOR THE AVOIDANCE OF DOUBT, NORM SHALL NOT CONSTITUTE THE BASIS OF A BREACH OF SELLER’S REPRESENTATIONS AND WARRANTIES SET FORTH IN SECTION 6.14. ARTICLE 6 SELLER’S REPRESENTATIONS AND WARRANTIES Seller represents and warrants to Buyer the following:

 
23 HN\1378916.125654385v1 6.1 Organization and Good Standing. (a) Seller is a limited liability company organized, validly existing and in good standing under the Laws of the State of Louisiana and has all requisite power and authority to own and/or dispose of the Assets. 6.2 Authority; Authorization of Agreement. Seller has all requisite power and authority to execute and deliver this Agreement and the Operative Documents to which it is a party, to consummate the transactions contemplated by this Agreement and the Operative Documents to which it is a party and to perform all of its obligations under this Agreement and the Operative Documents to which it is a party. This Agreement constitutes, and the Operative Documents to which it is a party, when executed and delivered by Seller, shall constitute, the valid and binding obligations of Seller, enforceable against it in accordance with their respective terms, except as such enforceability may be limited by bankruptcy, insolvency or other Laws relating to or affecting the enforcement of creditors’ rights and general principles of equity (regardless of whether such enforceability is considered in a proceeding at law or in equity). 6.3 No Violations. Except for (i) Customary Post-Closing Consents and (ii) any consents or approvals listed on Schedule 6.3, Seller’s execution and delivery of this Agreement and the Operative Documents to which it is a party and the consummation of the transactions contemplated by this Agreement by it shall not: (a) conflict with any of the terms, conditions or provisions of the organizational documents of Seller; (b) violate any material provision of, or require any material filing, consent or approval under, any Laws applicable to Seller; (c) conflict with, result in a breach of, constitute a default under or constitute an event that with notice or lapse of time, or both, would constitute a default under, accelerate or permit the acceleration of the performance required by, or require any consent, authorization or approval under any Material Contract or financing instrument; or (d) result in the creation or imposition of any lien or encumbrance upon one or more of the Assets, except for the Permitted Encumbrances. 6.4 Liability for Brokers’ Fees. Seller has not incurred any liability, contingent or otherwise, for investment bankers’, brokers’ or finders’ fees relating to the transactions contemplated by this Agreement for which Buyer or any Affiliate of Buyer shall, directly or indirectly, have any responsibility whatsoever. 6.5 Legal Proceedings. Schedule 6.5 sets forth all Legal Proceedings pending or, to Seller’s Knowledge, threatened in writing, against Seller in respect of any of the Assets. 6.6 Bankruptcy. There are no bankruptcy, reorganization or receivership proceedings pending, being contemplated by or, to Seller’s Knowledge, threatened against Seller.

 
24 HN\1378916.125654385v1 6.7 Taxes. [***] 6.8 Material Contracts. [***] 6.9 [***] 6.10 Preferential Rights. Except as set forth on Schedule 6.10, there are no preferential rights to purchase that are applicable to the transaction contemplated hereby (each, a “Preferential Right”). 6.11 Consents. Except as set forth on Schedule 6.3, there are no third party consent requirements that are applicable to the transaction contemplated hereby. 6.12 [***] 6.13 Current Commitments. Schedule 6.13 sets forth as of the Execution Date all authorities for expenditures in excess of $50,000 (“AFE’s”) (net to the interest of Seller) relating to the Oil and Gas Properties to drill or rework Wells or for other capital expenditures pursuant to any of the Material Contracts for which all of the activities anticipated in such AFE’s or commitments have not been completed as of the Execution Date. 6.14 [***] 6.15 Production Imbalances. Schedule 6.15 sets forth all Imbalances with respect to Oil and Gas Properties. 6.16 [***] 6.17 [***] 6.18 [***] 6.19 Liens. Except for Permitted Encumbrances, the Assets shall be conveyed to Buyer at the Closing free and clear of all liens and encumbrances by, through or under Seller. 6.20 [Intentionally Omitted]. 6.21 [***] 6.22 [***] 6.23 [***] 6.24 [***]

 
25 HN\1378916.125654385v1 ARTICLE 7 BUYER’S REPRESENTATIONS AND WARRANTIES Buyer represents and warrants to Seller the following: 7.1 Organization and Good Standing. Buyer is a limited liability company duly organized, validly existing and in good standing under the Laws of the State of Delaware and has all requisite power and authority to own the Assets. 7.2 Authority; Authorization of Agreement. Buyer has all requisite power and authority to execute and deliver this Agreement and the Operative Documents to which it is a party, to consummate the transactions contemplated by this Agreement and the Operative Documents to which it is a party and to perform all of its obligations under this Agreement and the Operative Documents to which it is a party. This Agreement constitutes, and the Operative Documents to which it is a party, when executed and delivered by Buyer, shall constitute, the valid and binding obligation of Buyer, enforceable against it in accordance with their terms, except as such enforceability may be limited by bankruptcy, insolvency or other Laws relating to or affecting the enforcement of creditors’ rights and general principles of equity (regardless of whether such enforceability is considered in a proceeding at law or in equity). 7.3 No Violations. No consent is required to be obtained with respect to the consummation of the transactions contemplated by this Agreement by Buyer. Buyer’s execution and delivery of this Agreement and the Operative Documents, to which it is a party and the consummation of the transactions contemplated by this Agreement by it shall not: (a) conflict with or require the consent of any Person under any of the terms, conditions or provisions of the organizational documents of Buyer; (b) violate any provision of, or require any filing, consent or approval under any Laws applicable to Buyer; or (c) conflict with, result in a breach of, constitute a default under or constitute an event that with notice or lapse of time, or both, would constitute a default under, accelerate or permit the acceleration of the performance required by, or require any consent, authorization or approval under: (i) any material agreement or any mortgage, indenture, loan, credit agreement or other agreement evidencing indebtedness for borrowed money to which Buyer is a party or by which Buyer is bound, except (in each case) where such conflict, breach or default would not materially affect Buyer’s ability to consummate the transactions contemplated hereby or (ii) any order, judgment or decree of any Governmental Authority. 7.4 Liability for Brokers’ Fees. Buyer has not incurred any liability, contingent or otherwise, for investment bankers’, brokers’ or finders’ fees relating to the transactions contemplated by this Agreement for which Seller or any Affiliate of Seller shall, directly or indirectly, have any responsibility whatsoever. 7.5 Claims, Disputes and Litigation. There are no Legal Proceedings pending or, to Buyer’s Knowledge, threatened in writing against Buyer, that would prevent the consummation of the transactions contemplated by this Agreement.

 
26 HN\1378916.125654385v1 7.6 Bankruptcy. There are no bankruptcy, reorganization or receivership proceedings pending, being contemplated by or, to Buyer’s Knowledge, threatened against Buyer. 7.7 Financing; Resources and Other Capabilities. Buyer has sufficient funds with which to pay the Adjusted Purchase Price and consummate the transactions contemplated by this Agreement. Buyer has the financial, technical and other capabilities to perform all of Buyer’s other obligations under this Agreement and all of the obligations assumed from Seller with respect to the Assets. 7.8 Independent Evaluation. Buyer is sophisticated in the evaluation, purchase, ownership and operation of oil and gas properties and related facilities. In making its decision to enter into this Agreement and to consummate the transactions contemplated hereby, Buyer has (a) relied on the representations and warranties of Sellers set forth in Article 6 and in the other Operative Documents and (b) relied on its own independent investigation and evaluation of the Assets and the advice of its own legal, Tax, economic, environmental, engineering, geological and geophysical advisors and not on any comments, statements, projections or other material made or given by any representative, consultant or advisor of any Seller. Buyer acknowledges and affirms that on or prior to Closing, Buyer will have completed its independent investigation, verification, analysis, and evaluation of the Assets and made all such reviews and inspections of the Assets as it has deemed necessary or appropriate to consummate the transaction contemplated hereunder; provided, however, no such investigation, verification, analysis or evaluation (or absence thereof) shall reduce, modify, release or waive any of Seller’s obligations or liabilities hereunder or under any of the other Operative Documents. 7.9 Accredited Investor. Buyer is an “accredited investor,” as such term is defined in Regulation D of the Securities Act of 1933, as amended, and will acquire the Assets for its own account and not with a view to a sale or distribution thereof in violation of the Securities Act of 1933, as amended, and the rules and regulations thereunder, any applicable state blue sky Laws or any other applicable securities Laws. ARTICLE 8 COVENANTS 8.1 Release of Liens. Concurrent with the Closing, Seller shall procure and deliver to Buyer a release or releases, in recordable form, executed by the applicable Person of those liens and security interests encumbering any of the Assets, including those set forth on Schedule 8.1, and secure any debt facilities maintained by Seller or any Affiliate. 8.2 Consents. (a) Following Closing, Seller shall send to each holder of a right to consent to assignment pertaining to the Assets and the transactions contemplated hereby set forth on Schedule 6.3, a notice seeking such holder’s consent to the transactions contemplated hereby. Seller shall use commercially reasonable efforts to procure the consents set forth on Schedule 6.3, and Buyer shall reasonably cooperate with Seller in seeking to obtain such consents, but, in each case, without being obligated to pay any consideration or waive or release any right or privilege to obtain such consent.

 
27 HN\1378916.125654385v1 (b) For each consent to assignment set forth on Schedule 6.3, the failure to obtain such consent would cause or give rise to a Non-Party having a right to cause (i) the assignment of the Asset(s) affected thereby to Buyer to be void or voidable, (ii) the termination of a Lease or Surface Contract, or the right of the counterparty thereunder to terminate a Lease or Surface Contract as a result of such assignment, under the express terms thereof, or (iii) impose additional conditions on the proposed assignee that involve the payment of money, the posting of collateral security or the performance of other obligations by the assignee that would not be required in the absence of Seller’s assignment of the affected Asset (each, a “Hard Consent”), the affected Asset(s) shall be excluded from the Assets to be acquired by Buyer at Closing hereunder and the Purchase Price shall be reduced by the sum of the mutually agreed upon value of the Asset(s) so excluded. In the event that a Hard Consent (with respect to any applicable Asset(s) excluded pursuant to this Section 8.2) that was not obtained prior to Closing is obtained within 180 days following Closing, then, Buyer shall purchase, within 10 days after such Hard Consent is obtained, such Asset(s) so excluded by Seller under the terms of this Agreement for the amount by which the Purchase Price was reduced at Closing due to the exclusion of such Asset(s) (as such amount is appropriately adjusted in accordance to Section 2.3 with respect to such Asset(s)), and Seller shall assign to Buyer such Asset(s) pursuant to an assignment in form substantially similar to the Assignment. Any portion of the Assets which are excluded from Closing and retained by Seller pursuant to the terms of this Section 8.2 shall be deemed to be Excluded Assets for all purposes under this Agreement unless and until such Assets are assigned to Buyer in accordance with the terms hereof. (c) For all Customary Post-Closing Consents and all consents to assignment set forth in Schedule 6.3, other than Hard Consents, for which Seller is unable to obtain consent from the applicable holders of such consents, (i) the Asset(s) subject to such un-obtained consents shall be acquired by Buyer at Closing as part of the Assets and (ii) Seller shall defend and indemnify the Buyer Group from any and all Claims arising from the failure to obtain such consent, but, in each case, only up to the sum of the mutually agreed upon value of the affected Asset; provided that, for the avoidance of doubt, the defense and indemnity obligations set forth in this Section 8.2, if applicable, shall not be subject to the limitations set forth in Section 4.4. 8.3 Approvals of Governmental Authorities. (a) Seller and Buyer shall use their commercially reasonable efforts to take or cause to be taken all appropriate action, and to do, or cause to be done, all things necessary or reasonably advisable under applicable Laws to consummate and make effective the transactions contemplated by this Agreement, including using their commercially reasonable efforts to obtain, or cause to be obtained, all waivers, permits, consents, approvals, authorizations, qualifications and orders of all Governmental Authorities and officials and parties to contracts with the Parties that may be or become necessary for the performance of obligations pursuant to this Agreement and the consummation of the transactions contemplated by this Agreement and all Parties hereto will cooperate fully with the other Parties hereto in promptly seeking to obtain all such waivers, permits, consents, approvals, authorizations, qualifications and orders. (b) The Parties hereto shall cooperate and assist one another in connection with all actions to be taken pursuant to Section 8.3(a), including the preparation and making of the filings referred to therein and, if requested, amending or furnishing additional information hereunder.

 
28 HN\1378916.125654385v1 Each Party shall use its commercially reasonable efforts to provide or cause to be provided promptly to the other Party all necessary information and assistance as any Governmental Authority may from time to time require in connection with obtaining the relevant waivers, permits, consents, approvals, authorizations, qualifications, orders or expiration of waiting periods in relation to these filings or in connection with any other review or investigation of the transactions contemplated by this Agreement by a Governmental Authority. Each Party shall permit the other Party to review and discuss in advance, and shall consider in good faith the views of the other Party in connection with, any analyses, presentations, memoranda, briefs, written arguments, opinions, written proposals or other materials to be submitted to the Governmental Authorities with respect to such filings. In addition, neither Party shall agree to participate in any substantive meeting or discussion with any Governmental Authority in respect of any filing, review, investigation or other inquiry concerning this Agreement or the transactions contemplated by this Agreement, or enter into any agreements with any Governmental Authority, including, without limitation, extending any antitrust waiting periods, unless it consults with the other Party in advance and, to the extent permitted by such Governmental Authority, gives the other Party the opportunity to attend and participate thereat. Each Party shall keep the other apprised of the material content and status of any material communications with, and material communications from, any Governmental Authority with respect to the transactions contemplated by this Agreement. The Parties shall, and shall cause their respective Affiliates to use their commercially reasonable efforts to, provide each other with copies of all material, substantive correspondence, filings or communications between them or any of their respective representatives, on the one hand, and any Governmental Authority or members of its staff, on the other hand, with respect to this Agreement and the transactions contemplated by this Agreement; provided, however, that materials may be redacted (i) to remove references concerning the valuation of the Assets; (ii) as necessary to comply with contractual arrangements or applicable Laws; and (iii) as necessary to address reasonable attorney-client or other privilege or confidentiality concerns. (c) Notwithstanding the foregoing, nothing contained in this Agreement shall be construed so as to require Buyer or Seller, or any of their respective Affiliates, without its written consent, to sell, license, dispose of, hold separate or operate in any specified manner any assets or businesses of Buyer or Seller (or to require Buyer or Seller or any of their respective Affiliates to agree to any of the foregoing). 8.4 Efforts. Each Party shall use commercially reasonable efforts to take all actions and to do all things necessary to consummate, make effective and comply with all of the terms of this Agreement. Without limiting the generality of the foregoing, from time to time after Closing, Seller and Buyer shall each execute, acknowledge and deliver to the other such further instruments as may be reasonably requested by the other Party, at such requesting Party’s cost, and as are commercially reasonable to be performed in order to accomplish more effectively the purposes of the transactions contemplated by this Agreement, including those post-Closing actions contemplated by Section 8.2. Promptly after Closing, Buyer shall: (a) record the Assignment and all state and federal assignments executed at the Closing in all applicable real property records and/or, if applicable, all state and federal Governmental Authorities and Buyer shall provide to Seller copies of such recorded documents; (b) actively pursue the approval of all Customary Post-Closing Consents from the applicable Governmental Authorities; and (c) except as otherwise provided for herein, actively pursue all other consents and approvals that may be

 
29 HN\1378916.125654385v1 required in connection with the assignment of the Assets to Buyer and the assumption of the rights, interests, obligations and liabilities assumed by Buyer hereunder that have not been obtained prior to Closing, provided that Seller shall reasonably cooperate with Buyer in obtaining such other consents and approvals. Promptly after Closing, Seller shall deliver all notices that are required to be delivered in connection with the assignment of the Assets to Buyer and the assumption of the rights, interests, obligations and liabilities assumed by Buyer hereunder. 8.5 Governmental Bonds. Buyer acknowledges that none of the bonds, letters of credit and guarantees, if any, posted by any Seller or its Affiliates with Governmental Authorities and relating to the Assets (collectively, the “Seller Bonds”) are transferable to Buyer. For so long as Seller remains as operator under the Applicable JOAs, Seller shall use commercially reasonable efforts to retain and continue to maintain the Seller Bonds after Closing, at Buyer’s sole cost, to the extent necessary to operate the Assets. On or before 30 days following Seller’s resignation or termination as operator under the Applicable JOAs, Buyer, at its sole cost, shall obtain replacement bonds, letters of credit and guarantees, including those described on Schedule 8.5, to the extent such replacements are necessary for Buyer’s ownership and/or operation of the Assets. Following Seller’s resignation or removal as operator under the Applicable JOAs, Buyer and Seller shall cooperate and use commercially reasonable efforts to cause the cancellation of the Seller Bonds; provided that any costs required for the cancellation of the Seller Bonds shall be borne solely by Seller. In addition, promptly following Seller’s resignation or removal as operator under the Applicable JOAs, Buyer shall, to the extent applicable, deliver to Seller evidence of the posting of bonds or other security with all applicable Governmental Authorities meeting the requirements of such authorities to own and, where appropriate, operate, the Assets. 8.6 Records in Seller’s Possession. For so long as Seller remains operator under the Applicable JOAs, Seller shall retain originals of all Records following Closing, and shall provide Buyer, its Affiliates and each of their officers, employees and representatives with access to the Records during normal business hours for review and copying at Buyer’s expense during such time. Within 10 Business Days following Seller’s resignation or removal as operator under the Applicable JOAs, Seller shall make available to Buyer the Records for pickup from Seller’s (and/or its Affiliates’) offices during normal business hours. Buyer shall retain and maintain the Records received from Seller for a period of 5 years after Closing. During such period of time, Buyer shall (a) provide Seller, its Affiliates and each of their officers, employees and representatives with access to the Records (to the extent that Seller has not retained the original or a copy) during normal business hours for review and copying at Seller’s expense, and (b) provide Seller, and its Affiliates and each of their officers, employees, and representatives with access, during normal business hours, to materials received or produced after the Closing relating to any indemnity claim made under Section 4.2 for review and copying at Seller’s expense subject to such reasonable limitations as Buyer may place upon such review as a result of such materials being subject to legal privilege, confidentiality obligations, or Buyer’s trade secrets. 8.7 Operatorship. The Parties acknowledge and agree that subject to this Section 8.7, from and after Closing, Seller shall continue to serve as the designated operator under each of the Applicable JOAs in accordance with and subject to the terms of the Applicable JOAs. Notwithstanding anything in the Applicable JOAs to the contrary, the Parties agree as follows:

 
30 HN\1378916.125654385v1 (a) With respect to any invoice issued under the terms of any Applicable JOA, Buyer shall pay Seller (subject to Buyer’s right under the Applicable JOAs) for any costs and expenses set forth on such invoice (including estimated costs and expenses for the subsequent month to the extent permitted under the Applicable JOAs) within fifteen (15) days of Buyer’s receipt of such invoice. If Buyer fails to pay any undisputed amounts due Seller under any Applicable JOA or this Section 8.7, then within fifteen (15) days after receipt of written notice from Seller that such amounts are past due and owing, Seller shall have the right to resign as designated operator under all (but not less than all) of the Applicable JOAs and such resignation shall not limit any rights of Seller to pursue any other available legal remedies. (b) Upon termination of the Affiliate COSA, (i) Seller shall have the right to resign as designated operator under all (but not less than all) of the Applicable JOAs, effective as of the termination date of the Affiliate COSA, and (ii) Buyer shall have the right to remove Seller as designated operator under all (but not less than all) the Applicable JOAs, effective as of the termination date of the Affiliate COSA. Promptly following (but in any event, no more than 30 days following) Seller’s resignation or removal as designated operator under all Applicable JOAs, Seller shall assign the Excluded Working Interest to Buyer pursuant to an assignment (effective as of the date of such resignation or removal) in the form of Exhibit D attached hereto. Following the resignation or removal of Seller as designated operator under the Applicable JOAs and Seller’s assignment of the Excluded Working Interest to Buyer under this Section 8.7(b), the terms of this Section 8.7 shall have no further force and effect. ARTICLE 9 [INTENTIONALLY OMITTED] ARTICLE 10 THE CLOSING 10.1 Closing. Contemporaneously with the execution of this Agreement, the closing of the transactions contemplated by this Agreement shall take place at the offices of Latham & Watkins LLP, 811 Main Street, Suite 3700 Houston, Texas 77002, on this 20th day of April, 2016 (the “Closing Date”). Seller has provided Buyer with wiring instructions designating the account or accounts to which the Closing Amount is to be delivered. 10.2 Obligations of Seller at Closing. At Closing, Seller shall deliver or cause to be delivered to Buyer, unless waived by Buyer, the following: (a) originals of the Assignment executed by Seller in sufficient counterparts and modified as necessary for recording in all applicable jurisdictions; (b) assignments in form required by any Governmental Authority for the assignment of any Assets controlled by such Governmental Authority, duly executed by Seller, in sufficient duplicate originals to allow recording and/or filing in all appropriate offices; (c) executed originals of the Certificate of Non-Foreign Status; (d) certificates of good standing from the states of Oklahoma and Louisiana;

 
31 HN\1378916.125654385v1 (d) letters-in-lieu of transfer or division orders executed by Seller relating to the Assets to reflect the transaction contemplated hereby, which letters shall be on forms prepared by Seller and reasonably satisfactory to Buyer; (e) any other forms required by any Governmental Authority relating to the assignments of the Assets to Buyer; and (f) duly executed releases and terminations of the mortgages, deeds of trust, assignments of production, financing statements, fixture filings, and other encumbrances and interests burdening the Assets (or any thereof), including those set forth on Schedule 8.1, which shall, in each case, be in form and substance reasonably satisfactory to Buyer and forms of which shall have been delivered to Buyer on or before the Closing Date. Seller shall take such other actions and deliver such other documents as are contemplated by this Agreement or as may be reasonably requested by Buyer. 10.3 Obligations of Buyer at Closing. At Closing, Buyer shall deliver or cause to be delivered to Seller, unless waived by Seller, the Closing Amount by wire transfer. Buyer shall also take such other actions and deliver such other documents as are contemplated by this Agreement or as may be reasonably requested by Seller. 10.4 DDA. The Parties acknowledge and agree that this Agreement provides for the acquisition of Seller’s remaining Oil and Gas Rights within the “AMI” (as defined in the DDA) and that neither Seller nor any Affiliate, successor or assign of Seller, is entitled to any carried cost or carried interest pursuant to the DDA, other than with respect to the Excluded Working Interest. With the exception of the Applicable JOAs, effective as of the Closing Date, the DDA shall terminate in accordance with the terms of Section 9.1 of the DDA, subject to the provisions of Section 9.2(a) of the DDA; provided, however, the Parties agree that terms of Section 9.2(b) and Section 9.2(c) have no force and effect upon such termination and the DDA shall be deemed to be amended to remove Section 9.2(b) and Section 9.2(c) thereof; provided further that from and after the Closing Date, Buyer shall continue to carry 15% of all Drilling Costs (as defined in the DDA) related to any remaining Commitment Wells (as defined in the DDA) attributable to Seller’s Excluded Working Interest. 10.5 Employees. Buyer or its Affiliates may offer employment, effective as of or after the Closing Date, to any Oklahoma based employees of Seller or any of its Affiliates who provide services in relation to the Assets (“Seller Employees”); provided, however, that the actual hiring date of any Seller Employees to be employed by Buyer, but required by Seller or its Affiliates for the provision of “Services” under the Affiliate COSA, shall not be earlier than the termination date of the Affiliate COSA without the mutual agreement of the Parties. Seller Employees hired by the Buyer or its Affiliates shall be treated as newly hired employees of the Buyer or its Affiliates for all purposes. Seller shall, and shall cause its Affiliates to, cooperate with the Buyer or its Affiliates to effect an orderly and cost effective transition of any such Seller Employees. Seller shall, and shall cause its Affiliates to, cooperate with the Buyer or its Affiliates by releasing Seller Employees from any covenants not to compete or any similar applicable agreements.

 
32 HN\1378916.125654385v1 ARTICLE 11 [INTENTIONALLY OMITTED] ARTICLE 12 TAXES 12.1 Tax Partnership. The Parties acknowledge that the Assets are subject to a Tax partnership (the “Tax Partnership”) with Buyer and Seller treated as partners therein for U.S. federal income tax purposes, and for the purposes of certain state tax laws that incorporate or follow U.S. federal income tax principles (“Tax Purposes”). Accordingly, the Parties acknowledge and agree that the transactions herein shall be treated for Tax Purposes as (i) a sale by Seller of an interest in the Tax Partnership, and (ii) a purchase by Buyer of an interest in the Tax Partnership (the “Intended Tax Treatment”). Neither Buyer nor Seller shall take any position inconsistent with the Intended Tax Treatment. 12.2 Cooperation on Tax Matters. Buyer and Seller shall cooperate fully, as and to the extent reasonably requested by the other party, in connection with the filing of any Tax Return and any audit, litigation or other proceeding with respect to Taxes. Such cooperation shall include the retention and (upon the other party’s request) the provision of records and information which are reasonably relevant to any such Tax Return, audit, litigation or other proceeding and making employees available on a mutually convenient basis to provide additional information and explanation of any material provided hereunder. Each of Buyer and Seller agrees (a) to retain all books and records with respect to Tax matters pertinent to the acquired Assets relating to any taxable period beginning before the Closing Date until the expiration of the statute of limitations (and, to the extent notified by Buyer or Seller, any extensions thereof) of the respective taxable periods, and to abide by all record retention agreements entered into with any Taxing Authority, and (b) to give the other party reasonable written notice prior to transferring, destroying or discarding any such books and records and, if the other Party so requests, each party shall allow the other Party the option of taking possession of such books and records prior to their disposal. Buyer and Seller further agree, upon request, to use their commercially reasonable efforts to obtain any certificate or other document from any Taxing Authority or any other Person as may be necessary to mitigate, reduce or eliminate any Tax that could be imposed with respect to the transactions contemplated. 12.3 Property and Excise Taxes. All ad valorem, real property, personal property, and similar Taxes assessed on the Assets (“Property Taxes”) and excise Taxes associated with any of the Assets (“Excise Taxes”) are Seller’s obligation for periods before the Effective Time and Buyer’s obligation for periods from and after the Effective Time; provided that, if the taxable period with respect to such a Tax begins on or before and ends after the Effective Time, then such Tax shall be attributable to the portions of such taxable period before and after the Effective Time based on the relative number days in each portion of such taxable period. If either party pays Property Taxes or Excise Taxes for which the other party is responsible, and the amount of such payment is not taken into account as an adjustment to the Base Purchase Price under Section 2.3, then upon receipt of evidence of payment the nonpaying party will reimburse the paying party promptly for the nonpaying party’s share of such Taxes.

 
33 HN\1378916.125654385v1 12.4 Severance Taxes. Seller shall bear and pay all severance or other Taxes based upon or measured by Hydrocarbon production from the Assets, or the receipt of proceeds therefrom, to the extent attributable to production from the Assets before the Effective Time. Buyer shall bear and pay all such Taxes on production from the Assets from and after the Effective Time. Seller shall withhold and pay on behalf of Buyer all such Taxes on production from the Assets between the Effective Time and the Closing Date, and the amount of any such payment shall be reimbursed to Seller as an adjustment to the Base Purchase Price pursuant to Section 2.3. If either party pays any such Taxes owed by the other, and the amount of such payment is not taken into account as an adjustment to the Base Purchase Price under Section 2.3, then upon receipt of evidence of payment the nonpaying party will reimburse the paying party promptly for the nonpaying party’s share of such Taxes 12.5 Transfer Taxes. Seller shall pay all state and local transfer, sales, use, stamp, registration or other similar Taxes (the “Transfer Taxes”) resulting from the acquisition of the Assets contemplated by this Agreement or any other transaction document. Upon receipt of invoice from Seller, Buyer shall promptly reimburse Seller for all Transfer Taxes paid by Seller. Buyer and Seller shall cooperate in good faith to minimize, to the extent permissible under applicable Law, the amount of any such Transfer Taxes. ARTICLE 13 MISCELLANEOUS 13.1 Notices. All notices and other communications required or desired to be given hereunder must be in writing and sent (properly addressed as set forth below) by: (a) U.S. mail with all postage and other charges fully prepaid, (b) electronic mail with a PDF of the notice or other communication attached (with the original sent by U.S. mail the same day such electronic mail is sent), or (c) facsimile transmission. A notice shall be deemed effective on the date on which such notice is received by the addressee, if by mail, or on the date sent, if by facsimile (as evidenced by fax machine confirmation of receipt) or if by electronic mail (as evidenced by computer generated confirmation of receipt); provided, if such date is not a Business Day, then date of receipt shall be on the next date that is a Business Day. Each Party may change its address by notifying the other Party in writing of such address change. If to Seller: PetroQuest Energy, L.L.C. 1800 Hughes Landing Blvd., Suite 200 The Woodlands, Texas 77380 Attn: Tracy Price, Vice President of Business Development & Land Telephone: (281) 465-3920 Facsimile: (281) 465-3999 Email: [email protected] With a copy to (which shall not constitute notice): PetroQuest Energy, L.L.C. 400 East Kaliste Saloom Road, Suite 6000

 
34 HN\1378916.125654385v1 Lafayette, Louisiana 70508 Attn: Ed Abels, Executive Vice President & General Counsel Facsimile: (337) 232-0044 Email: [email protected] If to Buyer: GR Woodford Properties, LLC 700 Universe Boulevard Juno Beach, FL 33408-0420 Attn: Sam Forrest, Vice President, Energy Marketing and Trading Email: [email protected] With a copy to (which shall not constitute notice): c/o NextEra Energy, Legal Department 700 Universe Boulevard Juno Beach, FL 33408-0420 Attn: Charles Lande Email: [email protected] 13.2 Transaction and Filing Costs. Buyer, at its sole cost, shall be responsible for recording and filing documents associated with the transfer of the Assets to it, including filing the assignments with appropriate federal, state and local Governmental Authorities as required by applicable Law. Buyer, at its sole cost, shall also be responsible for any and all stamp, documentary, real property transfer, sales, gross receipts, use or similar Taxes or assessments resulting from its acquisition of the Assets contemplated by this Agreement. As soon as practicable after recording or filing, Buyer shall furnish Seller with all recording data and evidence of all required filings including filings with the appropriate state counties and parishes. 13.3 Amendments and Severability. No amendments or other modifications to this Agreement shall be effective or binding on either of the Parties unless the same are in writing, designated as an amendment or modification, and signed by both Seller and Buyer. The invalidity of any one or more provisions of this Agreement shall not affect the validity of this Agreement as a whole, and in case of any such invalidity, this Agreement shall be construed as if the invalid provision had not been included herein. 13.4 Successors and Assigns. Except as set forth in this Section 13.4, this Agreement may not be assigned, either in whole or in part, without the express written consent of the non- assigning Party, such consent not to be unreasonably withheld, conditioned or delayed. The terms, covenants and conditions contained in this Agreement are binding upon and inure to the benefit of Seller and Buyer and their respective successors and permitted assigns. Notwithstanding the foregoing, either Party may assign this Agreement and its rights and obligations hereunder to any Affiliate of such Party; provided, however, that no such assignment shall relieve either Party of any of its obligations or liabilities under this Agreement.

 
35 HN\1378916.125654385v1 13.5 Headings. The titles and headings set forth in this Agreement have been included solely for ease of reference and may not be considered in the interpretation or construction of this Agreement. 13.6 Governing Law; Jurisdiction; Waiver of Trial by Jury. (A) THIS AGREEMENT IS GOVERNED BY THE LAWS OF THE STATE OF TEXAS, EXCLUDING ANY CHOICE OF LAW RULES THAT MAY DIRECT THE APPLICATION OF THE LAWS OF ANOTHER JURISDICTION. (B) THE PARTIES AGREE THAT ANY SUIT, ACTION OR PROCEEDING SEEKING TO ENFORCE ANY PROVISION OF, OR BASED ON ANY MATTER ARISING OUT OF OR IN CONNECTION WITH, THIS AGREEMENT OR THE TRANSACTION CONTEMPLATED HEREBY SHALL BE BROUGHT IN THE UNITED STATES DISTRICT COURT FOR THE SOUTHERN DISTRICT OF TEXAS, SO LONG AS SUCH COURT HAS SUBJECT MATTER JURISDICTION OVER SUCH SUIT, ACTION OR PROCEEDING (OR, IF REQUIREMENTS FOR FEDERAL JURISDICTION ARE NOT MET, STATE COURTS LOCATED IN HARRIS COUNTY, TEXAS), AND THAT ANY CAUSE OF ACTION ARISING OUT OF THIS AGREEMENT SHALL BE DEEMED TO HAVE ARISEN FROM A TRANSACTION OF BUSINESS IN THE STATE OF TEXAS, AND EACH OF THE PARTIES HEREBY IRREVOCABLY CONSENTS TO THE JURISDICTION OF SUCH COURTS (AND OF THE APPROPRIATE APPELLATE COURTS THEREFROM) IN ANY SUCH SUIT, ACTION OR PROCEEDING AND IRREVOCABLY WAIVES, TO THE FULLEST EXTENT PERMITTED BY LAW, ANY OBJECTION THAT IT MAY NOW OR HEREAFTER HAVE TO THE LAYING OF THE VENUE OF ANY SUCH SUIT, ACTION OR PROCEEDING IN ANY SUCH COURT OR THAT ANY SUCH SUIT, ACTION OR PROCEEDING BROUGHT IN ANY SUCH COURT HAS BEEN BROUGHT IN AN INCONVENIENT FORUM. PROCESS IN ANY SUCH SUIT, ACTION OR PROCEEDING MAY BE SERVED ON ANY PARTY ANYWHERE IN THE WORLD, WHETHER WITHIN OR WITHOUT THE JURISDICTION OF ANY SUCH COURT. (C) WITH RESPECT TO ANY SUIT, ACTION OR PROCEEDING SEEKING TO ENFORCE ANY PROVISION OF, OR BASED ON ANY MATTER ARISING OUT OF OR IN CONNECTION WITH, THIS AGREEMENT OR THE TRANSACTION CONTEMPLATED HEREBY, THE PARTIES AGREE TO WAIVE TRIAL BY JURY. 13.7 No Partnership Created. It is not the purpose or intention of this Agreement to create (and it should not be construed as creating) a joint venture, partnership or any type of association, and the Parties are not authorized to act as an agent or principal for each other with respect to any matter related hereto. 13.8 Public Announcements. Neither Seller nor Buyer (including any of their agents, employees or Affiliates in either case) may issue a public statement or press release with respect to the transaction contemplated hereby (including the price and other terms) without the prior

 
36 HN\1378916.125654385v1 written consent of the other Party, except as required by any applicable securities or other Laws or regulations or the applicable rules of any stock exchange having jurisdiction over the Parties or their respective Affiliates. 13.9 No Third Party Beneficiaries. Nothing contained in this Agreement shall entitle anyone other than Seller and Buyer, their successors and permitted assigns or the express beneficiaries of indemnity provisions to any Claim, cause of action, remedy or right of any kind whatsoever; provided that only a Party and its respective successors and permitted assigns will have the right to enforce the provisions of this Agreement on its own behalf or on behalf of the express beneficiaries of the indemnity provisions (but shall not be obligated to do so). 13.10 Waiver; Rights Cumulative. Any of the terms, covenants, representations, warranties or conditions hereof may be waived only by a written instrument executed by or on behalf of the Party waiving compliance. No course of dealing on the part of Seller or Buyer, or their respective officers, employees, agents or representatives or any failure by Seller or Buyer to exercise any of its rights under this Agreement shall operate as a waiver thereof or affect in any way the right of such Person at a later time to enforce the performance of such provision. No waiver by Seller or Buyer of any condition or any breach of any term, covenant, representation or warranty contained in this Agreement, in any one or more instances, shall be deemed to be or construed as a further or continuing waiver of any such condition or breach or a waiver of any other condition or of any breach of any other term, covenant, representation or warranty. The rights of Seller and Buyer under this Agreement shall be cumulative, and the exercise or partial exercise of any such right shall not preclude the exercise of any other right. 13.11 Construction. The Parties acknowledge that they have had an adequate opportunity to review each and every provision contained in this Agreement and to submit the same to legal counsel for review and comment. Moreover, the Parties have participated jointly in the negotiation and drafting of this Agreement. Based on the foregoing, the Parties agree that the rule of construction that a contract be construed against the drafter, if any, not be applied in the interpretation or construction of this Agreement. 13.12 Conspicuousness of Provisions. THE PARTIES ACKNOWLEDGE AND AGREE THAT THE PROVISIONS CONTAINED IN THIS AGREEMENT THAT ARE SET OUT IN “BOLD” AND/OR ALL CAPS SATISFY THE REQUIREMENT OF THE “EXPRESS NEGLIGENCE RULE” AND ANY OTHER REQUIREMENT AT LAW OR IN EQUITY THAT PROVISIONS CONTAINED IN A CONTRACT BE CONSPICUOUSLY MARKED OR HIGHLIGHTED. 13.13 Execution in Counterparts. This Agreement may be executed in any number of counterparts, each of which shall be deemed to be an original, all of which when taken together shall constitute one and the same agreement. 13.14 Entire Agreement. This Agreement supersedes all prior and contemporaneous negotiations, understandings, letters of intent and agreements (whether oral or written) between the Parties with respect to the subject matter hereof and constitute the entire understanding and agreement between the Parties with respect thereto.

 
37 HN\1378916.125654385v1 [signatures follow on next page]

 
[Signature Page to Purchase and Sale Agreement] 5654385v1 IN WITNESS WHEREOF, the Parties have executed this Agreement on the day and year first set forth above. SELLER: PETROQUEST ENERGY, L.L.C. By: /s/ Tracy Price Name: Tracy Price Title: Executive Vice President – Business Development and Land BUYER: GR WOODFORD PROPERTIES, LLC By: /s/ Sam Forrest Name: Sam Forrest Title: President

 


EXHIBIT 31.1
I, Charles T. Goodson, certify that:
1.
I have reviewed this Form 10-Q of PetroQuest Energy, Inc.;
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.
The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
(a)
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b)
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
(c)
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d)
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b)
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
/s/ Charles T. Goodson                            
Charles T. Goodson
Chief Executive Officer
August 3, 2016




EXHIBIT 31.2
I, J. Bond Clement, certify that:
1.
I have reviewed this Form 10-Q of PetroQuest Energy, Inc.;
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.
The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
(a)
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b)
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
(c)
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d)
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.
The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
(a)
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b)
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

/s/ J. Bond Clement                        
J. Bond Clement
Chief Financial Officer
August 3, 2016




Exhibit 32.1
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO SECTION 906
OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Quarterly Report of PetroQuest Energy, Inc. (the “Company”) on Form 10-Q for the quarter ending June 30, 2016 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, I, Charles T. Goodson, Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:
1.The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and
2.The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
/s/ Charles T. Goodson
Charles T. Goodson
Chief Executive Officer
August 3, 2016
A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.




Exhibit 32.2
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO SECTION 906
OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Quarterly Report of PetroQuest Energy, Inc. (the “Company”) on Form 10-Q for the quarter ending June 30, 2016 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, I, J. Bond Clement, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:
1.The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and
2.The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
 
/s/ J. Bond Clement
J. Bond Clement
Chief Financial Officer
August 3, 2016
A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.



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