PETROQUEST ENERGY INC - FORM 10-Q - May 8, 2018

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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: March 31, 2018
¨
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, a smaller reporting company or an emerging growth company. See definitions of “large accelerated filer”, “accelerated filer”, “smaller reporting company” and "emerging growth company" in Rule 12b-2 of the Exchange Act. 
Large accelerated filer
¨
Accelerated filer
¨
Non-accelerated filer
¨
Smaller reporting company
x
Emerging growth company
¨
 
 
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨
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 April 26, 2018 there were 25,587,441 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)
 
March 31,
2018
 
December 31,
2017
 
(unaudited)
 
(Note 1)
ASSETS
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
14,178

 
$
15,655

Revenue receivable
7,847

 
15,340

Joint interest billing receivable
3,024

 
6,597

Other receivable
6,000

 
7,750

Derivative asset
—

 
1,174

Deposit for surety bonds
11,100

 
8,300

Other current assets
1,960

 
2,125

Total current assets
44,109

 
56,941

Property and equipment:
 
 
 
Oil and gas properties:
 
 
 
Oil and gas properties, full cost method
1,351,048

 
1,369,861

Unevaluated oil and gas properties
16,918

 
21,854

Accumulated depreciation, depletion and amortization
(1,285,640
)
 
(1,285,660
)
Oil and gas properties, net
82,326

 
106,055

Other property and equipment
9,451

 
9,353

Accumulated depreciation of other property and equipment
(8,894
)
 
(8,843
)
Total property and equipment
82,883

 
106,565

Other assets
792

 
792

Total assets
$
127,784

 
$
164,298

LIABILITIES AND STOCKHOLDERS’ EQUITY
 
 
 
Current liabilities:
 
 
 
Accounts payable to vendors
$
15,382

 
$
32,148

Advances from co-owners
1,181

 
1,730

Oil and gas revenue payable
18,451

 
19,344

Accrued interest
4,689

 
1,724

Asset retirement obligation
938

 
687

Derivative liability
718

 
731

Other accrued liabilities
11,318

 
6,476

Total current liabilities
52,677

 
62,840

Multi-draw Term Loan
28,131

 
27,963

10% Senior Secured Notes due 2021
9,788

 
9,821

10% Senior Secured PIK Notes due 2021
274,563

 
271,577

Asset retirement obligation
2,304

 
30,623

Preferred stock dividend payable
11,563

 
10,278

Other long-term liabilities
567

 
131

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 25,550 and 25,521 shares, respectively
26

 
26

Paid-in capital
313,637

 
313,244

Accumulated other comprehensive income (loss)
(718
)
 
278

Accumulated deficit
(564,755
)
 
(562,484
)
Total stockholders’ equity
(251,809
)
 
(248,935
)
Total liabilities and stockholders’ equity
$
127,784

 
$
164,298


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
 
March 31,
 
2018
 
2017
Revenues:
 
 
 
Oil and gas sales
$
24,917

 
$
20,772

Expenses:
 
 
 
Lease operating expenses
7,040

 
7,076

Production taxes
1,227

 
308

Depreciation, depletion and amortization
6,505

 
6,117

General and administrative
3,300

 
3,153

Accretion of asset retirement obligation
198

 
547

Interest expense
7,481

 
7,258

 
25,751

 
24,459

Other income:
 
 
 
Other income
13

 
54

Loss from operations
(821
)
 
(3,633
)
Income tax expense
106

 
—

Net loss
(927
)
 
(3,633
)
Preferred stock dividend
1,285

 
1,285

Loss available to common stockholders
$
(2,212
)
 
$
(4,918
)
Loss per common share:
 
 
 
Basic
 
 
 
Net loss per share
$
(0.09
)
 
$
(0.23
)
Diluted
 
 
 
Net loss per share
$
(0.09
)
 
$
(0.23
)
Weighted average number of common shares:
 
 
 
Basic
25,540

 
21,208

Diluted
25,540

 
21,208

See accompanying Notes to Consolidated Financial Statements.


2

PETROQUEST ENERGY, INC.
Consolidated Statements of Comprehensive Loss
(unaudited)
(Amounts in Thousands)
 
Three Months Ended
 
March 31,
 
2018
 
2017
Net loss
$
(927
)
 
$
(3,633
)
Change in fair value of derivative instruments, accounted for as hedges, net of income tax benefit of $106 and $0, respectively
(996
)
 
3,188

Comprehensive loss
$
(1,923
)
 
$
(445
)
See accompanying Notes to Consolidated Financial Statements.


3

PETROQUEST ENERGY, INC.
Consolidated Statements of Cash Flows
(unaudited)
(Amounts in Thousands)
 
Three Months Ended
 
March 31,
 
2018
 
2017
Cash flows from operating activities:
 
 
 
Net loss
$
(927
)
 
$
(3,633
)
Adjustments to reconcile net loss to net cash provided by operating activities:
 
 
 
Deferred tax expense
106

 
—

Depreciation, depletion and amortization
6,505

 
6,117

Accretion of asset retirement obligation
198

 
547

Share-based compensation expense
340

 
425

Amortization costs and other
211

 
238

Non-cash interest expense on PIK Notes
2,961

 
5,512

Payments to settle asset retirement obligations
(3
)
 
(402
)
Changes in working capital accounts:
 
 
 
Revenue receivable
7,493

 
1,025

Joint interest billing receivable
3,016

 
460

Accounts payable and accrued liabilities
(11,583
)
 
3,037

Advances from co-owners
(549
)
 
1,549

Deposit for surety bonds
(2,800
)
 
—

Other
112

 
(1,462
)
Net cash provided by operating activities
5,080

 
13,413

Cash flows used in investing activities:
 
 
 
Investment in oil and gas properties
(5,810
)
 
(10,898
)
Investment in other property and equipment
(98
)
 
(16
)
Disposition of oil and gas properties
(2,405
)
 
—

Sale of unevaluated oil and gas properties
1,750

 
—

Net cash used in investing activities
(6,563
)
 
(10,914
)
Cash flows provided by (used in) financing activities:
 
 
 
Net proceeds from share based compensation
43

 
40

Deferred financing costs
(26
)
 
(10
)
Redemption of 2017 Notes
—

 
(22,650
)
Costs incurred to redeem 2021 Notes
(11
)
 
—

Proceeds from borrowings
—

 
20,000

Net cash provided by (used in) financing activities
6

 
(2,620
)
Net decrease in cash and cash equivalents
(1,477
)
 
(121
)
Cash and cash equivalents, beginning of period
15,655

 
28,312

Cash and cash equivalents, end of period
$
14,178

 
$
28,191

Supplemental disclosure of cash flow information:
 
 
 
Cash paid during the period for:
 
 
 
Interest
$
1,789

 
$
2,975

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 month periods ended March 31, 2018 and 2017, 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 March 31, 2018 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, 2017 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, 2017. 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
Divestitures:
On April 17, 2017, the Company completed the sale of its interest in the East Lake Verret field in Louisiana for approximately $2.2 million. This sale was accounted for as an adjustment to the capitalized costs of oil and gas properties. On December 15, 2017, the Company completed the sale of its saltwater disposal assets in East Texas for approximately $8.5 million. This sale was accounted for as an adjustment to the capitalized costs of oil and gas properties.
On January 31, 2018, the Company sold its Gulf of Mexico properties. The Company received no consideration from the sale of these properties and is required to contribute approximately $3.8 million towards the future abandonment costs for the properties. As a result of the sale, the Company extinguished approximately $28.2 million of its discounted asset retirement obligations. In connection with the sale, the Company expects to receive a cash refund of $11.5 million ($11.1 million at March 31, 2018) related to a depositary account that serves to collateralize a portion of the Company's offshore bonds related to these properties (subject to the Company's obligation to pay approximately $3.8 million to the purchaser of these properties), which is included in deposits for surety bonds on the Company's Consolidated Balance Sheet as of March 31, 2018. This sale was accounted for as an adjustment to the capitalized costs of oil and gas properties.
Acquisitions:
In December 2017, the Company entered into an oil focused play in central Louisiana targeting the Austin Chalk formation through the execution of agreements to acquire interests in approximately 24,600 gross acres for a purchase price of approximately $9.3 million and the issuance of 2.0 million shares of common stock.

Note 3—Equity
Common Stock
During December 2017, the Company issued 2.0 million shares of common stock in connection with the acquisition of Austin Chalk acreage (see Note 2). Additionally, during December 2017, the Company issued approximately 2.2 million shares of common stock related to the extinguishment of a portion of the outstanding 2021 Notes (see Note 5).

5

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 prior bank credit facility (which was terminated and replaced by the Multidraw Term Loan Agreement with Franklin Custodian Funds in October 2016) 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. The Multidraw Term Loan Agreement also prohibits the Company from declaring and paying cash dividends on the Series B Preferred Stock. Under the terms of the Series B Preferred Stock, any unpaid dividends will accumulate. As of March 31, 2018, the Company has deferred eight dividend payments and has accrued an $11.6 million payable related to the eight deferred payments and the quarterly dividend that was payable on April 15, 2018, which is included in Preferred stock dividend payable on the Consolidated Balance Sheet. As a result of the restrictions under the Multidraw Term Loan Agreement, the Company did not pay the dividend that was payable on July 15, 2017, which represented the sixth deferred dividend payment. As a result, the holders of the Series B Preferred Stock, voting as a single class, currently have the right to elect two additional directors to the Company's Board of Directors (the "Board") until all accumulated and unpaid dividends on the Series B Preferred Stock are paid in full. On April 12, 2018, the Company received written notice from a holder of the Series B Preferred Stock (the "Requesting Holder") exercising this right by requesting that the Board call a special meeting of the holders of the preferred stock for the purposes of electing the additional directors, as set forth in Section 4(ii) of the Certificate of Designations establishing the preferred stock, dated September 24, 2007. The Company intends to comply with the Certificate of Designations, which provides that the Board will provide notice of such meeting within 60 days of such request.
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, 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 March 31, 2018
Loss
(Numerator)
 
Shares
(Denominator)
 
Per
Share Amount
BASIC EPS
 
 
 
 
 
Net loss available to common stockholders
$
(2,212
)
 
25,540

 
$
(0.09
)
Stock options
—

 
—

 
 
Attributable to participating securities
—

 
—

 
 
DILUTED EPS
$
(2,212
)
 
25,540

 
$
(0.09
)
 
 
 
 
 
 
For the Three Months Ended March 31, 2017
Loss (Numerator)
 
Shares
(Denominator)
 
Per
Share Amount
BASIC EPS
 
 
 
 
 
Net loss available to common stockholders
$
(4,918
)
 
21,208

 
$
(0.23
)
Stock options
—

 
—

 
 
Attributable to participating securities
—

 
—

 
 
DILUTED EPS
$
(4,918
)
 
21,208

 
$
(0.23
)
 
 
 
 
 
 

An aggregate of 2.0 million and 1.5 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 March 31, 2018 and 2017, 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").
On February 17, 2016, the Company closed a private exchange offer (the "February Exchange") and consent solicitation (the "February Consent Solicitation") to certain eligible holders of its outstanding 2017 Notes. In satisfaction of the tender of $214.4 million in aggregate principal amount of the 2017 Notes, representing approximately 61% of the then outstanding aggregate principal amount of 2017 Notes, 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 February Exchange, $135.6 million in aggregate principal amount of the 2017 Notes remained outstanding. The February Consent Solicitation eliminated or waived substantially all of the restrictive covenants contained in the indenture governing the 2017 Notes.
On September 27, 2016, the Company closed private exchange offers (the "September Exchange") and a consent solicitation (the "September Consent Solicitation") to certain eligible holders of its outstanding 2017 Notes and 2021 Notes. In satisfaction of the consideration of $113.0 million in aggregate principal amount of the 2017 Notes, representing approximately 83% of the then outstanding aggregate principal amount of 2017 Notes, and $130.5 million in aggregate principal amount of the 2021 Notes, representing approximately 90% of the then outstanding aggregate principal amount of 2021 Notes, the Company issued (i) $243.5 million in aggregate principal amount of its new 10% Second Lien Senior Secured PIK Notes due 2021 (the "2021 PIK Notes") and (ii) approximately 3.5 million shares of its common stock. The Company also paid, in cash, accrued and unpaid interest on the 2017 Notes and 2021 Notes accepted in the September Exchange from the last applicable interest payment date to, but not including, September 27, 2016. Following the consummation of the September Exchange, there were $22.7 million in aggregate principal amount of the 2017 Notes outstanding and $14.2 million in aggregate principal amount of the 2021 Notes outstanding. The September Consent Solicitation amended certain provisions of the indenture governing the 2021 Notes and amended the registration rights agreement with respect to the 2021 Notes.
On March 31, 2017, the Company redeemed its remaining outstanding 2017 Notes at a redemption price of $22.8 million. The redemption was funded by cash on hand and amounts borrowed under the Multidraw Term Loan Agreement described below.

7

On December 28, 2017, the Company issued approximately 2.2 million shares of common stock to extinguish approximately $4.8 million of outstanding principal amount of 2021 Notes.
The 2021 PIK 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. The Company was permitted, at its option, for the first three interest payment dates of the 2021 PIK Notes, to instead pay interest at (i) the annual rate of 1% in cash plus (ii) the annual rate of 9% PIK (the "PIK Interest") payable by increasing the principal amount outstanding of the 2021 PIK Notes or by issuing additional 2021 PIK Notes in certificated form. The Company exercised this PIK option in connection with the interest payments due on February 15, 2017, August 15, 2017 and February 15, 2018. As of March 31, 2018, the Company was in compliance with all of the covenants under the 2021 PIK Notes.
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. As of March 31, 2018, the Company was in compliance with all of the covenants under the 2021 Notes.
The February Exchange and September Exchange were accounted for as troubled debt restructurings pursuant to guidance provided by Financial Accounting Standards Board ("FASB") Accounting Standards Codification ("ASC") Topic 470-60 "Troubled Debt Restructurings by Debtors." The Company determined that the future undiscounted cash flows from the 2021 PIK Notes issued in the September Exchange through the maturity date exceeded the adjusted carrying amount of the 2017 Notes and the 2021 Notes tendered in the September Exchange. Accordingly, no gain or loss on extinguishment of debt was recognized in connection with the September Exchange. The net shortfall of the remaining carrying value of the 2017 Notes and 2021 Notes tendered as compared to the principal amount of the 2021 PIK Notes issued in the September Exchange of $0.6 million is reflected as part of the carrying value of the 2021 PIK Notes. Such shortfall is being amortized under the effective interest method over the term of the 2021 PIK Notes. At March 31, 2018, $0.5 million of the shortfall remained as part of the carrying value of the 2021 PIK Notes and the Company recognized $26,000 of amortization expense as an increase to interest expense during the three months ended March 31, 2018.
The Company previously determined that the future undiscounted cash flows from the 2021 Notes issued in the February Exchange through the maturity date exceeded the adjusted carrying amount of the 2017 Notes tendered in the February Exchange. Accordingly, no gain on extinguishment of debt was recognized in connection with the February Exchange. The excess of the remaining carrying value of the 2017 Notes tendered over the principal amount of the 2021 Notes issued in the February Exchange of $13.9 million was reflected as part of the carrying value of the 2021 Notes. The amount of the excess carrying value attributable to the 2021 Notes tendered in the September Exchange is now reflected as part of the carrying value of the 2021 PIK Notes. The excess carrying value attributable to the remaining 2021 Notes is being amortized under the effective interest method over the term of the 2021 Notes. At March 31, 2018, $0.6 million of the excess remained as part of the carrying value of the 2021 Notes and the Company recognized $43,000 of amortization expense as a reduction to interest expense during the three months ended March 31, 2018.
The indentures governing the 2021 PIK Notes and the 2021 Notes contain affirmative and negative covenants that, among other things, limit the ability of the Company and the subsidiary guarantors of the 2021 PIK Notes and 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 PIK Notes and the 2021 Notes are fully and unconditionally guaranteed on a senior basis, jointly and severally, by certain wholly-owned subsidiaries of the Company.
The 2021 PIK Notes and the 2021 Notes are secured equally and ratably 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 Multidraw Term Loan 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 PIK Notes and the 2021 Notes and the guarantees are contractually subordinated to liens that secure the Multidraw Term Loan Agreement and certain other permitted indebtedness. Consequently, the 2021 PIK Notes and the 2021 Notes and the guarantees will be effectively subordinated to the Multidraw Term Loan Agreement and such other indebtedness to the extent of the value of such assets.
On October 17, 2016, the Company entered into the Multidraw Term Loan Agreement (the "Multidraw Term Loan Agreement") with Franklin Custodian Funds - Franklin Income Fund ("Franklin"), as a lender, and Wells Fargo Bank, National Association, as administrative agent, replacing the prior credit agreement with JPMorgan Chase Bank, N.A. The Multidraw Term Loan Agreement provides a multi-advance term loan facility, with borrowing availability for three years, in a principal amount of up to $50 million. The loans drawn under the Multidraw Term Loan Agreement (collectively, the “Term Loans”) may be used to repay existing debt, to pay transaction fees and expenses, to provide working capital for exploration and production operations and for general corporate purposes. The Term Loans mature on October 17, 2020. As of March 31, 2018, the Company had $30.0 million of borrowings outstanding under the Term Loans and $20.0 million of available borrowings under the Multidraw Term Loan Agreement.

8

The Company’s obligations under the Multidraw Term Loan Agreement and the Term Loans are secured by a first priority lien on substantially all of the assets of the Company and certain of its subsidiaries, including a lien on all equipment and at least 90% of the aggregate total value of the oil and gas properties of the Company and its subsidiaries, a pledge of the equity interests of PetroQuest Energy, L.L.C. (the "Borrower") and certain of the Company’s other subsidiaries, and corporate guarantees of the Company and certain of the Company’s other subsidiaries of the indebtedness of the Borrower. Term Loans under the Multidraw Term Loan Agreement bear interest at the rate of 10% per annum.
The Company and its subsidiaries are subject to a restrictive covenant under the Multidraw Term Loan Agreement, consisting of maintaining a ratio of (i) the present value, discounted at 10% per annum, of the estimated future net revenues in respect of the Company’s and its subsidiaries’ oil and gas properties, before any state, federal, foreign or other income taxes, attributable to proved developed reserves, using three-year strip prices in effect at the end of each calendar quarter, including swap agreements in place at the end of each quarter, to (ii) the sum of the outstanding Term Loans and the then outstanding commitments to provide Term Loans, that shall not be less than 2.0 to 1.0 as measured on the last day of each calendar quarter (the "Coverage Ratio"). If the Coverage Ratio is less than 2.0 to 1.0 as of any quarterly measurement date, the Company may, at its option, prepay outstanding Term Loans or permanently reduce the then outstanding Term Loan Commitments (i.e. the available borrowings) under the Multidraw Term Loan Agreement, or a combination thereof, by a proportionate amount. The Coverage Ratio was greater than 2.0 to 1.0 as of March 31, 2018.
Sales of the Company’s and its subsidiaries’ oil and gas properties outside the ordinary course of business are limited under the terms of the Multidraw Term Loan Agreement. In addition, the Multidraw Term Loan Agreement prohibits the Company from declaring and paying dividends on its Series B Preferred Stock.
The Multidraw Term Loan 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. As of March 31, 2018, no default or event of default existed under the Multidraw Term Loan Agreement and the Company was in compliance with all covenants contained in the Multidraw Term Loan Agreement.
The 2021 Notes are reflected net of $0.2 million of related unamortized financing costs as of March 31, 2018 and December 31, 2017 and the Term Loans are reflected net of $1.9 million and $2.0 million of related unamortized financing costs as of March 31, 2018 and December 31, 2017, respectively.
The following table reconciles the face value of the 2021 Notes, 2021 PIK Notes and Term Loans to the carrying value included in the Company's Consolidated Balance Sheet as of March 31, 2018 and December 31, 2017 (in thousands):
 
March 31, 2018
 
December 31, 2017
 
2021 Notes
2021 PIK Notes
Term Loans
 
2021 Notes
2021 PIK Notes
Term Loans
Face Value
$
9,427

$
275,046

$
30,000

 
$
9,427

$
263,202

$
30,000

Unamortized Deferred Financing Costs
(201
)
—

(1,869
)
 
(212
)
—

(2,037
)
Excess (Shortfall) Carrying Value
562

(483
)
—

 
606

(508
)
—

Accrued PIK Interest
—

—

—

 
—

8,883

—

Carrying Value
$
9,788

$
274,563

$
28,131

 
$
9,821

$
271,577

$
27,963



9

Note 6—Asset Retirement Obligation

The following table describes the changes to the Company’s asset retirement obligation liability (in thousands):
 
Three Months Ended March 31,
 
2018
 
2017
Asset retirement obligation, beginning of period
$
31,310

 
$
36,610

Liabilities incurred
7

 
13

Liabilities settled
(57
)
 
(540
)
Accretion expense
198

 
547

Revisions in estimates
(2
)
 
(381
)
Divestiture of oil and gas properties
(28,214
)
 
—

Asset retirement obligation, end of period
3,242

 
36,249

Less: current portion of asset retirement obligation
(938
)
 
(3,291
)
Long-term asset retirement obligation
$
2,304

 
$
32,958


The divestiture of oil and gas properties during 2018 totaling $28.2 million relates to the sale of the Company's Gulf of Mexico assets. The liabilities incurred, revisions in estimated cash flows and divestitures represent non-cash investing activities for purposes of the statement of cash flows.


Note 7—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 March 31, 2018, 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 $804,000 and ($321,000) for the three months ended March 31, 2018 and 2017, respectively. Oil and gas sales include reductions related to the settlement of oil hedges of $264,000 and $0 for the three months ended March 31, 2018 and 2017, respectively.
As of March 31, 2018, the Company had entered into the following commodity derivative instrument:
Production Period
Instrument
Type
 
Daily Volumes
 
Weighted
Average Price
Crude Oil:

 

 

2018
Swap
 
250 Bbl
 
$55.00
At March 31, 2018, the Company had recognized an accumulated other comprehensive loss of approximately $0.7 million related to the estimated fair value of its effective cash flow hedge. Based on estimated future commodity prices as of March 31, 2018, the Company would reclassify approximately $0.5 million, net of taxes, of accumulated other comprehensive loss into oil and gas sales during the next twelve months.

10

Derivatives designated as hedging instruments:
The following tables reflect the fair value of the Company’s effective cash flow hedges in the consolidated financial statements (in thousands):
Effect of Cash Flow Hedges on the Consolidated Balance Sheets at March 31, 2018 and December 31, 2017:    
 
Commodity Derivatives
Period
Balance Sheet
Location
Fair Value
March 31, 2018
Derivative liability
$
(718
)
December 31, 2017
Derivative asset
$
1,174

December 31, 2017
Derivative liability
$
(731
)
Effect of Cash Flow Hedges on the Consolidated Statements of Operations and Comprehensive Loss for the three months ended March 31, 2018 and 2017:
Instrument
Amount of Gain (Loss) Recognized in Other
Comprehensive Income
 
Location of
Gain Reclassified
into Income
 
Amount of Gain (Loss) Reclassified into
Oil and Gas Sales
Commodity Derivatives at March 31, 2018
$
(545
)
 
Oil and gas sales
 
$
540

Commodity Derivatives at March 31, 2017
$
2,867

 
Oil and gas sales
 
$
(321
)

Note 8 – 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.
The Company classifies its commodity derivatives based upon the data used to determine fair value. The Company’s derivative instruments at March 31, 2018 and December 31, 2017 were in the form of swaps based on NYMEX pricing for oil and natural gas. The fair value of these derivatives are 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 credit 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 fair value of the Company’s derivatives subject to fair value measurement on a recurring basis as of March 31, 2018 and December 31, 2017 (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:
 
 
 
 
 
March 31, 2018
$
—

 
$
(718
)
 
$
—

December 31, 2017
$
—

 
$
443

 
$
—


11

The fair value of the Company's cash and cash equivalents approximated book value at March 31, 2018 and December 31, 2017. The fair value of the Term Loans was determined using Level 2 inputs and approximated face value as of March 31, 2018 and December 31, 2017. The fair value of the 2021 Notes and 2021 PIK Notes was determined based upon market quotes provided by an independent broker, which represents a Level 2 input. The following table summarizes the fair value, carrying value and face value of the 2021 Notes and 2021 PIK Notes as of March 31, 2018 and December 31, 2017 (in thousands):
 
March 31, 2018
 
December 31, 2017
 
Fair Value
Face Value
Carrying Value
 
Fair Value
Face Value
Carrying Value
2021 Notes
$
7,580

$
9,427

$
9,788

 
$
7,306

$
9,427

$
9,821

2021 PIK Notes
219,419

275,046

274,563

 
198,717

263,202

271,577

 
$
226,999

$
284,473

$
284,351

 
$
206,023

$
272,629

$
281,398


Note 9—Income Taxes
The Company typically provides for income taxes at a statutory rate 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 $116.3 million and $115.9 million as of March 31, 2018 and December 31, 2017, respectively.
The Tax Cuts and Jobs Act (the "Act") was enacted on December 22, 2017. The Act, among other things, reduces the U.S. federal corporate tax rate from 35% to 21%, eliminates the corporate alternative minimum tax and changes how existing alternative minimum tax credits are realized, creates a new limitation on deductible interest expense and changes the rules related to uses and limitations of net operating loss carryforwards generated in tax years beginning after December 31, 2017. As of March 31, 2018, the Company has not completed its accounting for the tax effects of enactment of the Act. However, the Company made a reasonable estimate of the effects on its existing deferred tax balances and recognized a provisional amount of $64.9 million as of December 31, 2017 to remeasure deferred tax assets and liabilities based on the rate at which they are expected to reverse in the future, which is generally 21%. This amount was included as a component of income tax expense (benefit) from continuing operations and was fully offset by the related adjustment to the Company's valuation allowance. The Company is still analyzing certain aspects of the Act and refining its calculations, which could potentially affect the measurement of these balances or potentially give rise to new deferred tax amounts.


12

Note 10 - Other Comprehensive Income

The following table represents the changes in accumulated other comprehensive income (loss), net of tax, for the three month period ended March 31, 2018 (in thousands):
 
Gains and Losses on Cash Flow Hedges
 
Change in Valuation Allowance
 
Total
Balance as of December 31, 2017
$
278

 
$
—

 
$
278

Other comprehensive income before reclassifications:
 
 
 
 
 
 Change in fair value of derivatives
(545
)
 
—

 
(545
)
 Income tax effect
131

 
(131
)
 
—

 Net of tax
(414
)
 
(131
)
 
(545
)
Amounts reclassified from accumulated other comprehensive loss:
 
 
 
 
 
 Oil and gas sales
(540
)
 
—

 
(540
)
 Income tax effect
130

 
(41
)
 
89

 Net of tax
(410
)
 
(41
)
 
(451
)
Net other comprehensive income
(824
)
 
(172
)
 
(996
)
Balance as of March 31, 2018
$
(546
)
 
$
(172
)
 
$
(718
)

The following table represents the changes in accumulated other comprehensive income (loss), net of tax, for the three month period ended March 31, 2017 (in thousands):
 
Gains and Losses on Cash Flow Hedges
 
Change in Valuation Allowance
 
Total
Balance as of December 31, 2016
$
(2,983
)
 
$
(1,767
)
 
$
(4,750
)
Other comprehensive income before reclassifications:
 
 
 
 
 
 Change in fair value of derivatives
2,867

 
—

 
2,867

 Income tax effect
(1,066
)
 
1,066

 
—

 Net of tax
1,801

 
1,066

 
2,867

Amounts reclassified from accumulated other comprehensive income:
 
 
 
 
 
 Oil and gas sales
321

 
—

 
321

 Income tax effect
(120
)
 
120

 
—

 Net of tax
201

 
120

 
321

Net other comprehensive loss
2,002

 
1,186

 
3,188

Balance as of March 31, 2017
$
(981
)
 
$
(581
)
 
$
(1,562
)



13

Note 11 - Recently Issued Accounting Standards
In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-09, “Revenue from Contracts with Customers,” to clarify the principles for recognizing revenue and to develop a common revenue standard and disclosure requirements. The core principle of ASU 2014-09 is that an entity will recognize revenue when it transfers control of goods or services to customers at an amount that reflects the consideration to which it expects to be entitled in exchange for those goods and or services. In August 2015, the FASB issued ASU 2015-14 deferring the effective date of ASU 2014-09 by one year to interim and annual periods beginning on or after December 31, 2017. Entities can choose to apply the standard using either a full retrospective approach or a modified retrospective approach, with the cumulative effect of initially applying ASU 2014-09 recognized at the date of initial application. The Company adopted the new standard effective January 1, 2018 using the modified retrospective approach, which resulted in no cumulative effect adjustment upon adoption.
The Company’s sources of revenue are oil, natural gas and NGL production from its oil and gas properties. Oil and natural gas production is typically sold to purchasers through monthly contracts at negotiated sales prices based on published market indices. The sale takes place at the wellhead for oil production and at the wellhead or gas processing plant for natural gas. NGL production is sold once natural gas is processed and the related liquids are removed at the processing plant. The contracts for sale of NGL production are with the processing plant with prices based on what the processing plant is able to receive from third party purchasers.
Sales of oil, natural gas and NGL production are recognized when the product is delivered and title transfers to the purchaser and payment is generally received one to two months after the sale has occurred. The Company had $7.8 million of revenue receivable at March 31, 2018, comprised of $2.2 million of oil revenue, $4.3 million of natural gas revenue and $1.3 million of NGL revenue.
The following table includes a disaggregation of revenue by product (in thousands):
 
Three Months Ended March 31,
 
2018
 
2017
Oil production
$
6,322

 
$
6,871

Natural gas production
14,884

 
10,662

Natural gas liquids production
3,711

 
3,239

Total
$
24,917

 
$
20,772

    
In February 2016, the FASB issued ASU 2016-02, "Leases" (Topic 842), to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The standard is effective for public entities for fiscal years beginning after December 15, 2018, and for interim periods within those fiscal years, with earlier application permitted. Upon adoption the lessee will apply the new standard retrospectively to all periods presented or retrospectively using a cumulative effect adjustment in the year of adoption. The Company is currently evaluating the impact of the new standard on its consolidated financial statements.
In August 2017, the FASB issued ASU 2017-12, "Derivative and Hedging," to improve the financial reporting of hedging relationships to better portray the economic results of an entity's risk management activities in its consolidated financial statements and make certain targeted improvements to simplify the application of the hedge accounting guidance in current US GAAP. ASU 2017-12 is effective for public entities for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years, with earlier application permitted. The Company is currently evaluating the effect that this new standard may have 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 and Louisiana. 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 with our acquisition of the Carthage Field in East Texas. From 2005 through 2015, we further implemented this strategy by focusing our efforts in the Woodford Shale play in Oklahoma. In response to lower commodity prices and to strengthen our balance sheet, we sold all of our Oklahoma assets in three transactions that closed in June 2015, April 2016 and October 2016. In December 2017, we acquired approximately 24,600 gross acres in central Louisiana targeting the Austin Chalk to attempt to increase our oil production and reserves. During January 2018, we sold all of our Gulf of Mexico assets to further reduce our liabilities and strengthen our liquidity position.
Our liquidity position has been negatively impacted by lower commodity prices. In response to the lower commodity prices, we executed the following actions aimed at preserving liquidity, reducing overall debt levels and extending debt maturities:
•
Completed the sale of our Oklahoma assets for $292.6 million;
•
Completed two debt exchanges to extend maturities on a significant portion of debt;
•
Reduced total debt 26% from $425 million at December 31, 2014 to $314.5 million at March 31, 2018;
•
Entered into a new $50 million Multidraw Term Loan Agreement maturing in 2020,
•
Sold our Gulf of Mexico assets resulting in the extinguishment of $28.2 million of discounted asset retirement obligations from our balance sheet and the expected refund of $11.5 million of cash collateral used to secure our offshore bonding (subject to our obligation to pay approximately $3.8 million to the purchaser of these assets);
In addition to extending the maturity on approximately $113 million of debt due in 2017 to 2021, our September 2016 debt exchange permitted us to reduce our cash interest expense on our 2021 PIK Notes (as defined below) from 10% in cash to 1% in cash and 9% in payment-in-kind for the first three semi-annual interest payments ending with the February 2018 interest payment, which provided us with approximately $31.6 million of cash interest savings.
As a result of our successful recompletion and drilling operations during 2017, we grew production and estimated proved reserves significantly during 2017 as compared to 2016. Our average daily production during the year ended December 31, 2017 increased 17% over average daily production during the year ended December 31, 2016 and our estimated proved reserves at December 31, 2017 grew 35% from 2016. However, our production has declined by 29% in the first quarter of 2018 when compared to the fourth quarter of 2017 due to the sale of our Gulf of Mexico properties in January 2018 and normal production declines. In addition, beginning with the August 15, 2018 interest payment, we will be required to pay the entire 10% interest payment in cash with respect to the 2021 PIK Notes. The return of higher cash interest costs will have a significant impact on our cash available for capital expenditures. As a result, we expect capital expenditures during 2018 to be greatly reduced from capital spending in 2017. The combined impact of reduced capital spending and the sale of our Gulf of Mexico production in January 2018 is expected to result in declining production, proved reserves and cash flow from operations during 2018, as compared to 2017. See - "Liquidity and Capital Resources."
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

15

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, 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, first day of month, average price 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 decline, 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.

16

Revenue Recognition
In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-09, “Revenue from Contracts with Customers,” to clarify the principles for recognizing revenue and to develop a common revenue standard and disclosure requirements. The core principle of ASU 2014-09 is that an entity will recognize revenue when it transfers control of goods or services to customers at an amount that reflects the consideration to which it expects to be entitled in exchange for those goods and or services. In August 2015, the FASB issued ASU 2015-14 deferring the effective date of ASU 2014-09 by one year to interim and annual periods beginning on or after December 31, 2017. Entities can choose to apply the standard using either a full retrospective approach or a modified retrospective approach, with the cumulative effect of initially applying ASU 2014-09 recognized at the date of initial application. The Company adopted the new standard effective January 1, 2018 using the modified retrospective approach, which resulted in no cumulative effect adjustment upon adoption. See Note 11 for additional disclosures.
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.
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 hedge is specifically referenced to NYMEX prices for oil. 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 March 31, 2018, 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 credit risk for derivative liabilities.

17

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 March 31,
 
2018
 
2017
Production:
 
 
 
Oil (Bbls)
100,175

 
132,678

Gas (Mcf)
4,604,021

 
3,524,966

Ngl (Mcfe)
897,103

 
904,206

Total Production (Mcfe)
6,102,174

 
5,225,240

Sales:
 
 
 
Total oil sales
$
6,321,857

 
$
6,871,409

Total gas sales
14,884,113

 
10,662,342

Total ngl sales
3,711,475

 
3,238,546

Total oil, gas, and ngl sales
$
24,917,445

 
$
20,772,297

Average sales prices:
 
 
 
Oil (per Bbl)
$
63.11

 
$
51.79

Gas (per Mcf)
3.23

 
3.02

Ngl (per Mcfe)
4.14

 
3.58

Per Mcfe
4.08

 
3.98

The above sales and average sales prices include increases (decreases) to revenue related to the settlement of gas hedges of $804,000 and ($321,000) for the three months ended March 31, 2018 and 2017, respectively. The above sales and average sales prices include decreases to revenue related to the settlement of oil hedges of $264,000 and $0 for the three months ended March 31, 2018 and 2017, 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.
In January 2018, we completed the sale of our Gulf of Mexico assets. During the first quarter of 2017, these assets contributed the following to our oil and gas operations:

Three months ended March 31, 2017
 
Percent of Total Company
Production:

 

Oil (Bbls)
80,473

 
61
%
Gas (Mcf)
815,836

 
23
%
Ngl (Mcfe)
95,046

 
11
%
Total Production (Mcfe)
1,393,720

 
27
%
Sales:

 

Total oil sales
$
4,189,103

 
61
%
Total gas sales
2,582,765

 
24
%
Total ngl sales
297,564

 
9
%
Total oil and gas sales
$
7,069,432

 
34
%
Net loss available to common stockholders totaled $2,212,000 and $4,918,000 for the three months ended March 31, 2018 and 2017, respectively. The primary fluctuations were as follows:
Production Total production increased 17% during the three month period ended March 31, 2018 as compared to the 2017 period, but was down 29% as compared to the fourth quarter of 2017. The increase in production as compared to the first quarter of 2017 was due primarily to the successful drilling of ten East Texas wells and the successful recompletion of our Thunder Bayou well in the first quarter of 2017. Partially offsetting the increase were decreases due to the sale of our Gulf of Mexico assets in January 2018 and normal production declines at our legacy Gulf Coast and East Texas fields. As a result of reduced capital spending and the sale of our Gulf of Mexico assets which contributed 25% of our total production in 2017, we expect our total production during the remainder of 2018 to decline as compared to 2017.

18

Gas production during the three month period ended March 31, 2018 increased 31% from the comparable period in 2017 but was down 28% as compared to the fourth quarter of 2017. The increase in gas production as compared to the first quarter of 2017 was primarily the result of our successful East Texas drilling program and the successful recompletion of our Thunder Bayou well. Partially offsetting the increase were decreases due to the sale of our Gulf of Mexico assets and normal production declines at our legacy Gulf Coast and East Texas fields. As a result of reduced capital spending and the sale of our Gulf of Mexico assets which contributed 24% of our gas production in 2017, we expect our 2018 average daily gas production to decline as compared to the average daily gas production realized during 2017.
Oil production during the three month period ended March 31, 2018 decreased 24% from the comparable 2017 period but was down 40% as compared to the fourth quarter of 2017. The decrease in oil production as compared to the first quarter of 2017 was due primarily to the divestiture of our Gulf of Mexico assets and the sale of our E. Lake Verret field during the second quarter of 2017. Partially offsetting the decrease was an increase as a result of the the successful recompletion of our Thunder Bayou wells and our successful East Texas drilling program. As a result of reduced capital spending and the sale of our Gulf of Mexico assets which contributed 51% of our oil production in 2017, we expect our 2018 average daily oil production to decline as compared to the average daily oil production realized during 2017.
Ngl production during the three month period ended March 31, 2018 decreased 1% from the comparable 2017 period primarily as a result of the sale of our Gulf of Mexico assets and normal production declines at our legacy Gulf Coast and East Texas fields. This decrease was partially offset by the successful recompletion of our Thunder Bayou well during the first quarter of 2017 and our successful drilling program in East Texas. We expect our 2018 average daily Ngl production to decline as compared to the average daily Ngl production realized during 2017.
Prices Including the effects of our hedges, average gas prices per Mcf for the three month period ended March 31, 2018 were $3.23 as compared to $3.02 for the 2017 period. Average oil prices per Bbl for the three months ended March 31, 2018 were $63.11 as compared to $51.79 for the 2017 period and average Ngl prices per Mcfe for the three month period ended March 31, 2018 were $4.14 as compared to $3.58 for the 2017 period. Stated on an Mcfe basis, unit prices received during the three months ended March 31, 2018 were 3% higher than the prices received during the comparable 2017 period.
Revenue Including the effects of hedges, oil and gas sales during the three months ended March 31, 2018 increased 20% to $24,917,000, as compared to oil and gas sales of $20,772,000 during the 2017 period. This increase was primarily the result of the production increases noted above as well as higher average realized prices for our production during 2018. However, oil and gas sales for the first quarter of 2018 were down 29% from the previous quarter due to the sale of our Gulf of Mexico assets.
Expenses Lease operating expenses for the three months ended March 31, 2018 totaled $7,040,000, or $1.15 per Mcfe, as compared to $7,076,000, or $1.35 per Mcfe, during the 2017 period. The decrease in per unit lease operating expenses for the three months ended March 31, 2018 is primarily a result of the divestiture of our Gulf of Mexico wells which had a higher per unit rate as compared to our remaining East Texas and South Louisiana wells. We expect lease operating expenses during the remainder of 2018 to decrease on an absolute value basis and a per unit basis as compared to 2017 as a result of the Gulf of Mexico sale.
Production taxes for the three months ended March 31, 2018 totaled $1,227,000, or $0.20 per Mcfe, as compared to $308,000, or $0.06 per Mcfe, during the 2017 period. The increase in production taxes was primarily due to the expiration of the two-year tax exemption on our Thunder Bayou well in June 2017. Additionally, 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, the amount also increased as a result of the increase in revenue noted above.
General and administrative expenses during the three months ended March 31, 2018 totaled $3,300,000 as compared to $3,153,000 during the 2017 period. Share-based compensation costs totaled $184,000 during the three months ended March 31, 2018 as compared to $420,000 during the 2017 period. We capitalized $1,430,000 of general and administrative expenses during the three month period ended March 31, 2018 compared to $1,334,000 during the 2017 period.
Depreciation, depletion and amortization (“DD&A”) expense on oil and gas properties for the three months ended March 31, 2018 totaled $6,454,000, or $1.06 per Mcfe, as compared to $6,014,000, or $1.15 per Mcfe, during the 2017 period. The decrease in the per unit DD&A rate for the three months ended March 31, 2018 is primarily the result of divestiture of our Gulf of Mexico assets in January 2018 and the sale of our East Texas saltwater assets during the fourth quarter of 2017. We expect our DD&A rate to approximate the first quarter rate during the remainder of 2018.
Interest expense, net of amounts capitalized on unevaluated properties, totaled $7,481,000 during the three months ended March 31, 2018, as compared to $7,258,000 during the 2017 period. During the three month period ended March 31, 2018, our capitalized interest totaled $421,000 as compared to $305,000 during the 2017 period. The terms of our 2021 PIK Notes allowed us the option to pay interest on the 2021 PIK Notes at 1% in cash and 9% in payment in kind through the payment due on February 15, 2018. Starting with the interest payment due on August 15, 2018, we will be required to pay interest at 10% in cash only. Therefore,

19

although our total interest expense for the year ended 2018 is expected to approximate interest expense during 2017, we expect our cash interest expense to be significantly higher during the remainder of 2018 as compared to 2017.
Income tax expense during the three month period ended March 31, 2018 was $106,000. We had no such income tax expense during the 2017 period. We typically provide for income taxes at a statutory federal income tax rate 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 in 2016 and prior years, we have incurred a three-year cumulative 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 $116,316,000 as of March 31, 2018.
The Tax Cuts and Jobs Act (the "Act") was enacted on December 22, 2017. We have not yet completed our accounting for the tax effects of enactment of the Act. However, we have made a reasonable estimate of the effects on existing deferred tax balances and recognized a provisional amount of approximately $64.9 million as of December 31, 2017 to remeasure deferred tax assets and liabilities based on the rate at which they are expected to reverse in the future, which is generally 21%. We are still analyzing certain aspects of the Act and refining our calculations, which could potentially affect the measurement of these balances or potentially give rise to new deferred tax amounts.
Liquidity and Capital Resources
At March 31, 2018, we had a working capital deficit of approximately $8.6 million as compared to a working capital deficit of approximately $5.9 million as of December 31, 2017. We have historically financed our acquisition, exploration and development activities principally through cash flow from operations, borrowings from banks and other lenders, issuances of equity and debt securities, joint ventures and sales of assets. However, our liquidity position has been negatively impacted by lower commodity prices. In response to lower commodity prices we executed a number of transactions aimed at preserving liquidity, reducing overall debt levels and extending debt maturities. Through these transactions, which included two debt exchanges, we refinanced or repaid all debt that was scheduled to mature in 2017 and reduced the face value of our total debt 26% from $425 million at December 31, 2014 to $314.5 million at March 31, 2018. In addition our September 2016 debt exchange permitted us to reduce our cash interest expense on our 2021 PIK Notes from 10% in cash to 1% in cash and 9% in payment-in-kind for the first three semi-annual interest payments ending with the February 2018 interest payment, which provided us with approximately $31.6 million of total cash interest savings during 2017 and 2018.
However, beginning with the interest payment on August 15, 2018, we will be required to pay the entire 10% interest payment in cash with respect to the 2021 PIK Notes. As a result, we expect our cash interest expense will be significantly higher during 2018 as compared to 2017, which will limit our cash available for capital expenditures. Cash interest expense on our outstanding indebtedness of $314.5 million at March 31, 2018, is expected to total approximately $19.1 million for the remainder of 2018 (or approximately $31 million per year) as compared to $7.4 million in 2017. As a result of lower capital spending and the sale of our Gulf of Mexico assets, we expect production, proved reserves and cash flow from operations to decline in 2018 as compared to 2017. We are evaluating additional sources of liquidity to provide capital for our exploration and development activities and to service our indebtedness. These additional sources of liquidity include joint ventures, asset sales, credit facilities, as well as alternate financing arrangements, including additional debt exchanges or other capital raising transactions. We cannot assure you that such additional liquidity sources will be available on acceptable terms, if at all, and our attempts to obtain additional sources of liquidity may be unsuccessful or may not permit us to meet scheduled debt service obligations, which could cause us to default on our obligations and could further impair our liquidity. See "Part II, Item 1A. Risk Factors" of this Form 10-Q for additional information.
Source of Capital: Operations
Net cash flow provided by operations decreased from $13.4 million during the three months ended March 31, 2017 to $5.1 million during the 2018 period. The decrease in operating cash flow during 2018 as compared to 2017 is primarily attributable to payments made to reduce our accounts payable to vendors and additional payments made to post collateral into a depositary account to support the bonds that cover our offshore decommissioning liabilities, which we expect will be refunded during 2018. Our operating cash flow during the remainder of 2018 is expected to be negatively impacted by higher cash interest expense related to our 2021 PIK Notes.

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 cannot assure you that we will be able to sell any of our assets in the future.
On January 31, 2018, we sold our Gulf of Mexico properties. Although we received no cash proceeds from the sale of these properties and are required to contribute approximately $3.8 million toward future abandonment costs, we will no longer have an obligation for $35.1 million of estimated undiscounted future abandonment costs related to the properties sold. Additionally, we expect to receive a refund of $11.5 million ($11.1 million at March 31, 2018) related to a depositary account that served to collateralize a portion of our offshore bonds related to these properties (subject to our obligation to pay approximately $3.8 million to the purchaser of these properties). See "Item 1A Risk Factors - Our ability to receive a refund of our cash deposits posted as collateral to support certain bonds that satisfy our offshore decommissioning obligations with respect to our recently sold Gulf of Mexico assets is dependent on the successful assumption of operatorship and the posting of bonds or other acceptable assurances with respect to these assets by the purchaser of the assets".
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 February 17, 2016, we closed a private exchange offer (the "February Exchange") and consent solicitation (the "February Consent Solicitation") to certain eligible holders of our outstanding 2017 Notes. In satisfaction of the tender of $214.4 million in aggregate principal amount of the 2017 Notes, representing approximately 61% of the then outstanding aggregate principal amount of 2017 Notes, 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 February Exchange, $135.6 million in aggregate principal amount of the 2017 Notes remained outstanding. The February Consent Solicitation eliminated or waived substantially all of the restrictive covenants contained in the indenture governing the 2017 Notes.
On September 27, 2016, we closed private exchange offers (the "September Exchange") and a consent solicitation (the "September Consent Solicitation") to certain eligible holders of our outstanding 2017 Notes and 2021 Notes. In satisfaction of the consideration of $113.0 million in aggregate principal amount of the 2017 Notes, representing approximately 83% of the then outstanding aggregate principal amount of 2017 Notes, and $130.5 million in aggregate principal amount of the 2021 Notes, representing approximately 90% of the then outstanding aggregate principal amount of 2021 Notes, we issued (i) $243.5 million in aggregate principal amount of our new 10% Second Lien Senior Secured PIK Notes due 2021 (the "2021 PIK Notes") and (ii) approximately 3.5 million shares of our common stock. We also paid, in cash, accrued and unpaid interest on the 2017 Notes and 2021 Notes accepted in the September Exchange from the last applicable interest payment date to, but not including, September 27, 2016. Following the consummation of the September Exchange, there was $22.7 million in aggregate principal amount of the 2017 Notes outstanding and $14.2 million in aggregate principal amount of the 2021 Notes outstanding. The September Consent Solicitation amended certain provisions of the indenture governing the 2021 Notes and amended the registration rights agreement with respect to the 2021 Notes.
On March 31, 2017, we redeemed our remaining outstanding 2017 Notes at a redemption price of $22.8 million. The redemption was funded by cash on hand and $20 million borrowed under the Multidraw Term Loan Agreement described below. On December 28, 2017, we issued approximately 2.2 million shares of common stock to extinguish $4.8 million of outstanding principal amount of 2021 Notes.
The 2021 PIK 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. We were permitted, at our option, for the first three interest payment dates of the 2021 PIK Notes ending with the February 2018 interest payment, to instead pay interest at (i) the annual rate of 1% per annum in cash plus (ii) the annual rate of 9% PIK (the "PIK Interest") payable by increasing the principal amount outstanding of the 2021 PIK Notes or by issuing additional 2021 PIK Notes in certificated form. We exercised this PIK option in connection with the interest payments due on February 15, 2017, August 15, 2017 and February 15, 2018. As of the date hereof, we are in compliance with all of the covenants under the 2021 PIK Notes.
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. As of the date hereof, we are in compliance with all of the covenants under the 2021 Notes.
The February Exchange and September Exchange were accounted for as troubled debt restructurings pursuant to guidance provided by ASC 470-60 "Troubled Debt Restructurings by Debtors." We determined that the future undiscounted cash flows from the 2021 PIK Notes issued in the September Exchange through the maturity date exceeded the adjusted carrying amount of

21

the 2017 Notes and the 2021 Notes tendered in the September Exchange. Accordingly, no gain or loss on extinguishment of debt was recognized in connection with the September Exchange. The net shortfall of the remaining carrying value of the 2017 Notes and 2021 Notes tendered as compared to the principal amount of the 2021 PIK Notes issued in the September Exchange of $0.6 million is reflected as part of the carrying value of the 2021 PIK Notes. Such shortfall is being amortized under the effective interest method as an addition to interest expense over the term of the 2021 PIK Notes. At March 31, 2018, $0.5 million of the shortfall remained as part of the carrying value of the 2021 PIK Notes and we recognized $26,000 of amortization expense as an increase to interest expense during the three months ended March 31, 2018.
We previously determined that the future undiscounted cash flows from the 2021 Notes issued in the February Exchange through the maturity date exceeded the adjusted carrying amount of the 2017 Notes tendered in the February Exchange. Accordingly, no gain on extinguishment of debt was recognized in connection with the February Exchange. The excess of the remaining carrying value of the 2017 Notes tendered over the principal amount of the 2021 Notes issued in the February Exchange of $13.9 million was reflected as part of the carrying value of the 2021 Notes. The amount of the excess carrying value attributable to the 2021 Notes tendered in the September Exchange is now reflected as part of the carrying value of the 2021 PIK Notes. The excess carrying value attributable to the remaining 2021 Notes is being amortized under the effective interest method over the term of the 2021 Notes. At March 31, 2018, $0.6 million of the excess remained as part of the carrying value of the 2021 Notes and the Company recognized $43,000 of amortization expense as a reduction to interest expense during the three months ended March 31, 2018.
The indentures governing the 2021 PIK Notes and the 2021 Notes contains affirmative and negative covenants that, among other things, limit our ability and the subsidiary guarantors of the 2021 PIK Notes and 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 our assets; and, in certain circumstances, to pay dividends or make other distributions on stock. The 2021 PIK Notes and the 2021 Notes are fully and unconditionally guaranteed on a senior basis by certain of our wholly-owned subsidiaries.
The 2021 PIK Notes and the 2021 Notes are equally and ratably secured by second-priority liens on substantially all of our and the subsidiary guarantors' oil and gas properties and substantially all of our other assets to the extent such properties and assets secure the Multidraw Term Loan 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 PIK Notes and the 2021 Notes and the guarantees are contractually subordinated to liens that secure the Multidraw Term Loan Agreement and certain other permitted indebtedness. Consequently, the 2021 PIK Notes and the 2021 Notes and the guarantees will be effectively subordinated to the Multidraw Term Loan Agreement and such other indebtedness to the extent of the value of such assets.
On October 17, 2016, we entered into the Multidraw Term Loan Agreement (the “Multidraw Term Loan Agreement”) with Franklin Custodian Funds - Franklin Income Fund ("Franklin"), as a lender, and Wells Fargo Bank, National Association, as administrative agent, replacing the prior credit agreement with JPMorgan Chase Bank, N.A. The Multidraw Term Loan Agreement provides a multi-advance term loan facility, with borrowing availability for three years, in a principal amount of up to $50 million. The loans drawn under the Multidraw Term Loan Agreement (collectively, the “Term Loans”) may be used to repay existing debt, including the 2017 Notes, to pay transaction fees and expenses, to provide working capital for exploration and production operations and for general corporate purposes. The Term Loans mature on October 17, 2020. As of the date hereof, we had $30 million of borrowings outstanding under the Term Loans and $20.0 million of available borrowings under the Multidraw Term Loan Agreement.
Our obligations under the Multidraw Term Loan Agreement and the Term Loans are secured by a first priority lien on substantially all of our assets, including a lien on all equipment and at least 90% of the aggregate total value of our oil and gas properties, a pledge of the equity interests of PetroQuest Energy, L.L.C. (the "Borrower") and certain of our other subsidiaries, and corporate guarantees by us and certain of our subsidiaries of the indebtedness of the Borrower. Term Loans under the Multidraw Term Loan Agreement bear interest at the rate of 10% per annum.
We are subject to a restrictive covenant under the Multidraw Term Loan Agreement, consisting of maintaining a ratio of (i) the present value, discounted at 10% per annum, of the estimated future net revenues in respect of our oil and gas properties, before any state, federal, foreign or other income taxes, attributable to proved developed reserves, using three-year strip prices in effect at the end of each calendar quarter, including swap agreements in place at the end of each quarter, to (ii) the sum of the outstanding Term Loans and the then outstanding commitments to provide Term Loans, that shall not be less than 2.0 to 1.0 as measured on the last day of each calendar quarter (the "Coverage Ratio"). If the Coverage Ratio is less than 2.0 to 1.0 as of any quarterly measurement date, we may, at our option, prepay outstanding Term Loans or permanently reduce the then outstanding Term Loan Commitments (i.e. the available borrowings) under the Multidraw Term Loan Agreement, or a combination thereof, by a proportionate amount. The Coverage Ratio was greater than 2.0 to 1.0 as of March 31, 2018.
Sales of our oil and gas properties outside the ordinary course of business are limited under the terms of the Multidraw Term Loan Agreement. In addition, the Multidraw Term Loan Agreement prohibits us from declaring and paying dividends on the Series B Preferred Stock.

22

The Multidraw Term Loan 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. As of the date hereof, no default or event of default exists under the Multidraw Term Loan Agreement and we were in compliance with all covenants contained in the Multidraw Term Loan Agreement.
The following table reconciles the face value of the 2021 Notes, 2021 PIK Notes and Term Loans to the carrying value included in our Consolidated Balance Sheet as of March 31, 2018 and December 31, 2017 (in thousands):
 
March 31, 2018
 
December 31, 2017
 
2021 Notes
2021 PIK Notes
Term Loans
 
2021 Notes
2021 PIK Notes
Term Loans
Face Value
$
9,427

$
275,046

$
30,000

 
$
9,427

$
263,202

$
30,000

Unamortized Deferred Financing Costs
(201
)
—

(1,869
)
 
(212
)
—

(2,037
)
Excess (Shortfall) Carrying Value
562

(483
)
—

 
606

(508
)
—

Accrued PIK Interest
—

—

—

 
—

8,883

—

Carrying Value
$
9,788

$
274,563

$
28,131

 
$
9,821

$
271,577

$
27,963


Use of Capital: Exploration and Development
Our 2018 capital budget is expected to be substantially reduced as compared to 2017 as a result of the expected increase in our cash interest expense during 2018. During the first quarter of 2018 we incurred $4.5 million in capital expenditures primarily related to the last two completions in our East Texas drilling program and various plugging and abandonment projects. Because we operate the majority of our drilling activities, we expect to be able to control the timing of a substantial portion of our capital investments. We plan to fund our capital expenditures with cash flow from operations and cash on hand. To the extent additional capital is required, we may utilize our Multidraw Term Loan Agreement, sales of equity or debt securities, evaluate the sale of additional assets, enter into joint venture arrangements or we may reduce our capital expenditures to manage our liquidity position.
Use of Capital: Acquisitions
In December 2017, we entered into an oil focused play in central Louisiana targeting the Austin Chalk formation through the execution of agreements to acquire interest in approximately 24,600 gross acres for a purchase price of approximately $9.3 million and the issuance of 2.0 million shares of common stock. We plan to drill our initial horizontal test well during the third quarter of 2018 utilizing data from existing vertical and unfracked horizontal wells that have been drilled in the area.
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, with cash on hand, sales of equity or debt securities, borrowings under our Multidraw Term Loan Agreement, 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; our indebtedness and the significant amount of cash required to service our indebtedness; our estimate of the sufficiency of our existing capital sources, including availability under the Multidraw Term Loan Agreement; our ability to raise additional capital to fund cash requirements for future operations and to service our indebtedness; our ability to fund and execute our Cotton Valley and Austin Chalk development programs as planned; our ability to increase recoveries in the Austin Chalk formation and to increase our overall oil production as planned; our estimates with respect to fracked Austin Chalk wells in Louisiana, including production EURs and costs; our estimates with respect to production, reserve replacement ratio and finding and development costs; our receipt of a cash refund with respect to our offshore bonds and the timing and amount of the same; our responsibility for offshore decommissioning liabilities for offshore interests we no longer own; our ability to hedge future production to reduce our exposure to price volatility

23

in the current commodity pricing market; our ability to find, develop and produce oil and natural gas reserves that are economically recoverable and to replace reserves and sustain and/or increase production; ceiling test write-downs resulting, and that could result in the future, from lower oil and natural gas prices; limits on our growth and our ability to finance our operations, fund our capital needs and respond to changing conditions imposed by the Multidraw Term Loan Agreement and restrictive debt covenants; approximately 46% of our production being exposed to the additional risk of severe weather, including hurricanes, 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 the limited trading market for our common stock.
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.
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 with respect to commodity prices. 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 2018, a 10% decline in the estimated average prices we expect to receive for our crude oil, natural gas and natural gas liquids production would result in an approximate $3.9 million decline in our revenues for 2018.
We periodically seek to reduce our exposure to commodity price volatility by hedging a portion of our 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 three months ended March 31, 2018, we received $0.5 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 Multidraw Term Loan Agreement requires that the counterparties to our hedge contracts be rated A-/A3 or higher by S&P or Moody's. Currently, the counterparty to our existing hedge contract is Koch Supply and Trading LP.

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As of March 31, 2018, we had entered into the following commodity derivative instrument:
Production Period
Instrument
Type
Daily Volumes
Weighted
Average Price
Crude Oil:



2018
Swap
250 Bbl
$55.00
We have approximately 69,000 Bbls of oil volumes, at an average price of $55.00 per Bbl hedged for 2018. For further discussion of our commodity derivative instruments, please see Item 1, Note 8 "Derivative Instruments" in this Form 10-Q.
Interest Rate Risk
As of March 31, 2018, we had no debt subject to variable interest rates.

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.
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

The Company 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. Although a single or multiple adverse rulings or settlements could possibly have a material adverse effect on the Company's business or financial position, the Company only accrues for losses from litigation and claims if the Company determines that a loss is probable and the amount can be reasonably estimated.
There have been no significant changes with respect to the legal matters disclosed in our Annual Report on Form 10-K for the year ended December 31, 2017.

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Item 1A. RISK FACTORS

We are subject to certain risks. For a discussion of these risks, see "Risk Factors" in our Annual Report on Form 10-K for the year ended December 31, 2017. Except as set forth below, there have been no material changes to the risk factors disclosed in our Annual Report on Form 10-K.
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.
The aggregate principal amount of our outstanding indebtedness, net of cash on hand, as of March 31, 2018 was $298.3 million. We currently have $20 million of additional availability under the Multidraw Term Loan Agreement, subject to compliance with the covenants contained therein. 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 2021 Notes, 2021 PIK Notes and amounts borrowed under the Multidraw Term Loan Agreement, 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 $19.1 million in the remainder of 2018 for interest on our 2021 Notes, 2021 PIK Notes and amounts borrowed under our Multidraw Term Loan Agreement alone and to pay quarterly dividends (which we suspended beginning with the dividend payment due in April 2016), if permissible 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;
•
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 2021 Notes, 2021 PIK Notes and amounts borrowed under the Multidraw Term Loan Agreement, 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 2021 Notes, 2021 PIK Notes and the Multidraw Term Loan Agreement, 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.
To service or refinance our indebtedness and to fund planned capital expenditures, we will require a significant amount of cash. Our ability to generate cash will be limited by our cash interest expense, which is expected to be significantly higher in 2018 than in 2017, and any failure to meet our debt obligations could harm our business, financial condition and results of operations.
Our ability to make payments on and to refinance our indebtedness, including our 2021 Notes, 2021 PIK Notes and amounts borrowed under the Multidraw Term Loan Agreement, and to fund planned capital expenditures will depend on our ability to generate sufficient cash flow from operations in the future. To a certain extent, this is subject to general economic, financial, competitive, legislative and regulatory conditions and other factors that are beyond our control, including the prices that we receive for our oil and natural gas production. In particular, our ability to fund planned capital expenditures and generate cash flow from operations will be limited by our cash interest expense, which is expected to be significantly higher in 2018 as compared to 2017 as a result of the expiration of the PIK option related to our 2021 PIK Notes. Cash interest expense on our outstanding indebtedness of $314.5 million at March 31, 2018, is expected to total approximately $19.1 million for the remainder of 2018 (or approximately $31 million per year), as compared to $7.4 million in 2017. As a result of higher cash interest expense and the impact of the sale

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of our Gulf of Mexico properties in January 2018, we expect production, proved reserves and cash flow from operations to decline in 2018 as compared to 2017.
Accordingly, we cannot assure you that our business will generate sufficient cash flow from operations or that future borrowings will be available to us under the Multidraw Term Loan Agreement in an amount sufficient to enable us to pay principal and interest on our indebtedness, including our 2021 Notes and 2021 PIK Notes, or to fund our other liquidity needs. We are evaluating additional sources of liquidity to service our indebtedness and to provide capital to fund our planned capital expenditures. These additional sources of liquidity include joint ventures, asset sales, credit facilities, as well as alternate financing arrangements, including additional debt exchanges or other capital raising transactions. We cannot assure you that such additional liquidity sources will be available on acceptable terms, if at all, and our attempts to obtain additional sources of liquidity may be unsuccessful or may not permit us to meet scheduled debt service obligations, which could cause us to default on our obligations and could further impair our liquidity.
Our hedging program may limit potential gains from increases in commodity prices or may result in losses or may be inadequate to protect us against continuing and prolonged declines in commodity prices.
We enter into hedging arrangements from time to time to reduce our exposure to fluctuations in oil and natural gas prices and to achieve more predictable cash flows. Our hedge at March 31, 2018 and as of the date of this report is in the form of a swap placed with Koch Supply and Trading LP. We cannot assure you that this or future counterparties will not become credit risks in the future. Hedging arrangements expose us to risks in some circumstances, including situations when the counterparty to the hedging contract defaults on the contractual obligations or there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received. This hedging arrangement may also limit the benefit we could receive from increases in the market or spot prices for oil and natural gas. For the three months ended March 31, 2018, our total oil and gas sales included additions related to the settlement of oil and gas hedges of $0.5 million, which in total represented approximately 2% of our total oil and gas sales for the period. We cannot assure you that the hedging transactions we have entered into, or will enter into, will adequately protect us from fluctuations in oil and natural gas prices. In addition, as of the date of this report, we had approximately 69,000 barrels of oil volumes hedged for the remainder of 2018. This hedge may be inadequate to protect us from continuing and prolonged declines in oil and natural gas prices. To the extent that oil and natural gas prices remain at current levels or decline further, we will not be able to hedge future production at the same pricing level as our current hedges and our results of operations and financial condition would be negatively impacted.
Our ability to receive a refund of our cash deposits posted as collateral to support certain bonds that satisfy our offshore decommissioning obligations with respect to our recently sold Gulf of Mexico assets is dependent on the successful assumption of operatorship and the posting of bonds or other acceptable assurances with respect to these assets by the purchaser of the assets.
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.
Because we were not exempt from the BOEM's supplemental bonding requirements, we engaged surety companies to post the requisite bonds. Pursuant to the terms of our agreements with these surety companies, we have provided cash deposits totaling $11.5 million ($11.1 million at March 31, 2018) as collateral to support certain of the bonds that are issued on our behalf with respect to the Gulf of Mexico assets that we sold in January 2018. We expect to receive a refund of these cash deposits (subject to our obligation to pay approximately $3.8 million to the purchaser of these assets) following the successful assumption of operatorship and the posting of bonds or other acceptable assurances with respect to these assets by the purchaser of the assets. While the purchaser of the assets has agreed to assume the operatorship of, and to post bonds or other acceptable assurances with respect to, the assets, this may not occur and we may not receive a refund of these cash deposits.
Our shares of common stock are quoted on the OTCQX and have a limited trading market.
On May 7, 2018, our shares of common stock commenced being quoted on the OTCQX market. The OTCQX is not an exchange and the quotation of our shares of common stock on the OTCQX does not assure that a liquid trading market exists or will develop. Securities traded on the OTCQX marketplace generally have limited trading volume and exhibit a wider spread between the bid/ask quotations compared to securities traded on national securities exchanges such as the NYSE, on which our shares of common stock were previously listed. As a result, investors may find it difficult to dispose of, or to obtain accurate quotations of the price of our shares of common stock. This significantly limits the liquidity of the common stock and may adversely affect the market price of our common stock. Moreover, a significant number of institutional investors have investment policies tha

27

t prohibit them from trading in securities on the OTCQX market. In addition, since our shares of common stock are quoted on the OTCQX, our shares of common stock are not "covered securities" for purposes of the Securities Act and our stockholders may face significant restrictions on the resale of our shares of common stock due to a state's own securities laws, often called "blue sky" laws. Not being listed on a national securities exchange and a limited trading market may also impair our ability to raise additional financing through public or private sales of equity securities and could also have other negative results, including the loss of institutional investor interest and fewer business development opportunities.
The terms of our debt agreements currently restrict, and Delaware law may restrict, us from making cash payments with respect to our Series B Preferred Stock, and as a result the holders of our Series B Preferred Stock are entitled to additional rights with respect to the management of the Company.
Quarterly dividends and cash payments upon conversion or repurchase of our Series B preferred stock will be paid only if payment of such amounts is not prohibited by our debt agreements, such as the Multidraw Term Loan Agreement, and assets are legally available to pay such amounts. Quarterly dividends will only be paid if such dividends are declared by our board of directors. The board of directors is not obligated or required to declare quarterly dividends even if we have funds available for such purposes.
In connection with an amendment to our prior bank credit facility (which was replaced by the Multidraw Term Loan Agreement in October 2016) restricting us from declaring or paying dividends on our Series B preferred stock, we suspended the cash dividend on our Series B preferred stock beginning with the dividend payment due on April 15, 2016. The terms of the Multidraw Term Loan Agreement also restrict us from declaring and paying cash dividends on our Series B preferred stock. Under the terms of the Series B preferred stock, any unpaid dividends will accumulate. As of March 31, 2018, the Company has deferred eight dividend payments and has accrued an $11.6 million payable related to the eight deferred payments and the quarterly dividend that was payable on April 15, 2018, which is included in Preferred stock dividend payable on the Consolidated Balance Sheet. As a result of the restrictions in the Multidraw Term Loan Agreement and our failure to pay six quarterly dividends on the Series B preferred stock as of the date hereof, holders of the Series B preferred stock, voting as a single class, currently have the right to elect two additional directors to our board of directors until all accumulated and unpaid dividends on the Series B preferred stock are paid in full. On April 12, 2018, we received written notice from a holder of the Series B preferred stock exercising this right by requesting that our board call a special meeting of the holders of the Series B preferred stock for the purposes of electing the additional directors as set forth in the certificate of designations establishing the Series B preferred stock. We intend to comply with the certificate of designations, which provides that the Board will provide notice of such meeting within 60 days of such request.
If in the future we are permitted to pay such cash dividends under the terms of our existing debt agreements, including the Multidraw Term Loan Agreement, and any debt agreements that we enter into in the future, we may continue to be limited in our ability to pay cash dividends on our Series B preferred stock and our ability to make any cash payment upon conversion or repurchase of our Series B preferred stock by the terms of such debt agreements. Furthermore, if we are in default under the Multidraw Term Loan Agreement or the indentures governing the 2021 Notes or the 2021 PIK Notes, we will not be permitted to pay any cash dividends on our Series B preferred stock or make any cash payment upon conversion or repurchase of our Series B preferred stock in the absence of a waiver of such default or an amendment or refinancing of such debt agreements.
Delaware law provides that we may pay dividends on our Series B preferred stock only to the extent that assets are legally available to pay such dividends. Cash payments we may make upon repurchase or conversion of our Series B preferred stock would be generally subject to the same restrictions under Delaware law. Legally available assets is defined as the amount of surplus. Our surplus is the amount by which the fair value of total assets exceeds the sum of:
•the fair value of our total liabilities, including our contingent liabilities; and
•the amount of our capital.
If there is no surplus, legally available assets will mean, in the case of a dividend, our net profits for the fiscal year in which the dividend payment occurs and/or the preceding fiscal year.

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Item 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
 
There were no repurchases of our common stock during the quarter ended March 31, 2018.

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 Multidraw Term Loan Facility, the indentures governing the 2021 Notes and the 2021 PIK 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 periods starting with April 15, 2016. As of the date of this report, the Company had dividends in arrears of approximately $11.6 million.

Item 4. MINE SAFETY DISCLOSURES
NONE.

Item 5. OTHER INFORMATION
NONE.

Item 6. EXHIBITS
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

# Confidential treatment has been requested for portions of this exhibit. Omissions are designated with brackets containing asterisks. As part of the Company's confidential treatment request, a complete version of this exhibit has been filed separately with the SEC.

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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:
May 8, 2018
/s/ J. Bond Clement

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

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