PETROQUEST ENERGY INC - FORM 10-Q - August 7, 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: June 30, 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 July 27, 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)
 
June 30,
2018
 
December 31,
2017
 
(unaudited)
 
(Note 1)
ASSETS
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
5,792

 
$
15,655

Revenue receivable
7,860

 
15,340

Joint interest billing receivable
2,277

 
6,597

Other receivable
4,822

 
7,750

Derivative asset
—

 
1,174

Deposit for surety bonds
12,300

 
8,300

Other current assets
1,813

 
2,125

Total current assets
34,864

 
56,941

Property and equipment:
 
 
 
Oil and gas properties:
 
 
 
Oil and gas properties, full cost method
1,352,355

 
1,369,861

Unevaluated oil and gas properties
17,997

 
21,854

Accumulated depreciation, depletion and amortization
(1,291,462
)
 
(1,285,660
)
Oil and gas properties, net
78,890

 
106,055

Other property and equipment
9,253

 
9,353

Accumulated depreciation of other property and equipment
(8,947
)
 
(8,843
)
Total property and equipment
79,196

 
106,565

Other assets
792

 
792

Total assets
$
114,852

 
$
164,298

LIABILITIES AND STOCKHOLDERS’ EQUITY
 
 
 
Current liabilities:
 
 
 
Accounts payable to vendors
$
6,581

 
$
32,148

Advances from co-owners
613

 
1,730

Oil and gas revenue payable
9,778

 
19,344

Accrued interest
11,057

 
1,724

Asset retirement obligation
877

 
687

Derivative liability
—

 
731

Other accrued liabilities
9,865

 
6,476

Total current liabilities
38,771

 
62,840

Multi-draw Term Loan
30,808

 
27,963

10% Senior Secured Notes due 2021
9,744

 
9,821

10% Senior Secured PIK Notes due 2021
274,591

 
271,577

Asset retirement obligation
2,301

 
30,623

Preferred stock dividend payable
12,848

 
10,278

Other long-term liabilities
36

 
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 25,587 and 25,521 shares, respectively
26

 
26

Paid-in capital
313,893

 
313,244

Accumulated other comprehensive income (loss)
(802
)
 
278

Accumulated deficit
(567,365
)
 
(562,484
)
Total stockholders’ equity
(254,247
)
 
(248,935
)
Total liabilities and stockholders’ equity
$
114,852

 
$
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
 
Six Months Ended
 
June 30,
 
June 30,
 
2018
 
2017
 
2018
 
2017
Revenues:
 
 
 
 
 
 
 
Oil and gas sales
$
21,561

 
$
24,251

 
$
46,478

 
$
45,023

Expenses:
 
 
 
 
 
 
 
Lease operating expenses
4,972

 
7,113

 
12,012

 
14,189

Production taxes
334

 
570

 
1,561

 
878

Depreciation, depletion and amortization
6,023

 
6,841

 
12,528

 
12,958

General and administrative
4,004

 
4,314

 
7,304

 
7,467

Accretion of asset retirement obligation
42

 
553

 
240

 
1,100

Interest expense
7,636

 
7,147

 
15,117

 
14,405

 
23,011

 
26,538

 
48,762

 
50,997

Other income:
 
 
 
 
 
 
 
Other income (expense)
178

 
(2
)
 
191

 
52

Derivative expense
(54
)
 
—

 
(54
)
 
—

 
124

 
(2
)
 
137

 
52

 
 
 
 
 
 
 
 
Loss from operations
(1,326
)
 
(2,289
)
 
(2,147
)
 
(5,922
)
Income tax expense (benefit)
—

 
(189
)
 
106

 
(189
)
Net loss
(1,326
)
 
(2,100
)
 
(2,253
)
 
(5,733
)
Preferred stock dividend
1,285

 
1,285

 
2,570

 
2,570

Loss available to common stockholders
$
(2,611
)
 
$
(3,385
)
 
$
(4,823
)
 
$
(8,303
)
Loss per common share:
 
 
 
 
 
 
 
Basic
 
 
 
 
 
 
 
Net loss per share
$
(0.10
)
 
$
(0.16
)
 
$
(0.19
)
 
$
(0.39
)
Diluted
 
 
 
 
 
 
 
Net loss per share
$
(0.10
)
 
$
(0.16
)
 
$
(0.19
)
 
$
(0.39
)
Weighted average number of common shares:
 
 
 
 
 
 
 
Basic
25,568

 
21,215

 
25,554

 
21,212

Diluted
25,568

 
21,215

 
25,554

 
21,212

See accompanying Notes to Consolidated Financial Statements.


2

PETROQUEST ENERGY, INC.
Consolidated Statements of Comprehensive Loss
(unaudited)
(Amounts in Thousands)
 
Three Months Ended
 
Six Months Ended
 
June 30,
 
June 30,
 
2018
 
2017
 
2018
 
2017
Net loss
$
(1,326
)
 
$
(2,100
)
 
$
(2,253
)
 
$
(5,733
)
Change in fair value of derivative instruments, accounted for as hedges, net of income tax expense (benefit) of $172, $189, ($106) and $189, respectively
(84
)
 
1,882

 
(1,080
)
 
5,070

Comprehensive loss
$
(1,410
)
 
$
(218
)
 
$
(3,333
)
 
$
(663
)
See accompanying Notes to Consolidated Financial Statements.


3

PETROQUEST ENERGY, INC.
Consolidated Statements of Cash Flows
(unaudited)
(Amounts in Thousands)
 
Six Months Ended
 
June 30,
 
2018
 
2017
Cash flows from operating activities:
 
 
 
Net loss
$
(2,253
)
 
$
(5,733
)
Adjustments to reconcile net loss to net cash (used in) provided by operating activities:
 
 
 
Deferred tax expense (benefit)
106

 
(189
)
Depreciation, depletion and amortization
12,528

 
12,958

Accretion of asset retirement obligation
240

 
1,100

Share-based compensation expense
593

 
825

Amortization costs and other
402

 
450

Non-cash interest expense on PIK Notes
2,961

 
11,179

Payments to settle asset retirement obligations
(75
)
 
(1,357
)
Changes in working capital accounts:
 
 
 
Revenue receivable
7,480

 
689

Joint interest billing receivable
4,078

 
2,239

Accounts payable and accrued liabilities
(24,104
)
 
(8,368
)
Advances from co-owners
(1,117
)
 
2,215

Deposit for surety bonds
(4,000
)
 
—

Other
242

 
(2,314
)
Net cash (used in) provided by operating activities
(2,919
)
 
13,694

Cash flows used in investing activities:
 
 
 
Investment in oil and gas properties
(9,785
)
 
(21,661
)
Investment in other property and equipment
(136
)
 
(37
)
Sale of oil and gas properties
(2,428
)
 
2,207

Sale of unevaluated oil and gas properties
2,928

 
—

Net cash used in investing activities
(9,421
)
 
(19,491
)
Cash flows provided by (used in) financing activities:
 
 
 
Net proceeds from share based compensation
43

 
32

Deferred financing costs
(55
)
 
(125
)
Redemption of 2017 Notes
—

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

Proceeds from borrowings
2,500

 
20,000

Net cash provided by (used in) financing activities
2,477

 
(2,743
)
Net decrease in cash and cash equivalents
(9,863
)
 
(8,540
)
Cash and cash equivalents, beginning of period
15,655

 
28,312

Cash and cash equivalents, end of period
$
5,792

 
$
19,772

Supplemental disclosure of cash flow information:
 
 
 
Cash paid during the period for:
 
 
 
Interest
$
3,304

 
$
3,743

See accompanying Notes to Consolidated Financial Statements.

4

PETROQUEST ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
Note 1—Basis of Presentation
The consolidated financial information for the three and six month periods ended June 30, 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 June 30, 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 - Going Concern

The accompanying consolidated financial statements have been prepared assuming the Company will continue as a going concern, which contemplates continuity of operations, realization of assets and the satisfaction of liabilities in the normal course of business for the twelve month period following the date of these consolidated financial statements. As such, the accompanying consolidated financial statements do not include any adjustments relating to the recoverability and classification of assets and their carrying amounts, or the amount and classification of liabilities that may result should the Company be unable to continue as a going concern.
The Company's overall liquidity position and cash available for capital expenditures continue to be negatively impacted by continued weak natural gas prices, declining production and increasing cash interest expense on its outstanding indebtedness. Due to the sale of the Company's Gulf of Mexico properties in January 2018 and normal production declines, production has declined by 35% in the second quarter of 2018 when compared to the fourth quarter of 2017 and cash flow from operations for the six months ended June 30, 2018 was a negative $2.9 million. At June 30, 2018, the Company had approximately $5.8 million of cash and approximately $317.0 million aggregate principal amount of outstanding indebtedness, and had deferred nine dividend payments with respect to the Company's Series B Preferred Stock and accrued a $12.8 million payable related to the nine deferred payments and the quarterly dividend that was payable on July 15, 2018. In addition, beginning with the August 15, 2018 interest payment on the Company's 2021 PIK Notes (as defined below), the Company will be required to pay interest on its 2021 PIK Notes at 10% in cash (instead of 1% in cash and 9% in payment in kind). The cash interest payment due on August 15, 2018 under the Company's 2021 PIK Notes and 2021 Notes (as defined below) will total approximately $14.2 million. In addition, available borrowings under the Multidraw Term Loan Agreement (as defined below) are subject to reductions on a calendar quarter basis based on the Coverage Ratio (as defined below) and the Company's ability to utilize such available borrowings is subject to the Company's ability to comply with certain covenants included in the agreement.
As a result of the forgoing, the Company is analyzing and evaluating various alternatives with respect to its capital structure, including the significant amount of indebtedness, liquidity and upcoming cash interest payment on the Company's 2021 PIK Notes and 2021 Notes. To assist its Board of Directors and management team in analyzing and evaluating these alternatives, the Company has retained Seaport Global Securities as its financial advisor and Porter Hedges LLP as its legal advisor. These alternatives include private debt exchanges, asset sales, draws under the Multidraw Term Loan Agreement, alternative financing arrangements to replace the Multidraw Term Loan Agreement and filing for protection under Chapter 11 of the U.S. bankruptcy code. The Company does not intend to disclose or comment on developments related to its review unless and until the Board has approved a specific alternative or transaction or otherwise determined that further disclosure is appropriate. The Company cannot provide any assurance that any of the alternatives being evaluated will provide additional liquidity or enable the Company to refinance its outstanding indebtedness. These conditions raise substantial doubt about the Company's ability to continue as a going concern.


5

Note 3—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, which is included in other accrued liabilities on the Company's Consolidated Balance Sheet as of June 30, 2018. Additionally, based on final purchase price adjustments of $2.8 million, the Company paid $2.4 million and has a payable of $0.4 million as of June 30, 2018 in connection with the sale. 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 $12.7 million ($12.3 million at June 30, 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 June 30, 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. The Company has invested approximately $10.7 million as of June 30, 2018 in acquisition, engineering and geological costs and issued 2.0 million shares of common stock with respect to these interests.
Note 4—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 3). 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 6).
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.

6

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 June 30, 2018, the Company has deferred nine dividend payments and has accrued a $12.8 million payable related to the nine deferred payments and the quarterly dividend that was payable on July 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 and on June 18, 2018, the Company received written notices from separate holders of the Series B Preferred Stock 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. These requests were subsequently withdrawn. The Board continues to evaluate various options with respect to the Series B Preferred Stock, including the unpaid dividends, in connection with the Company's review of alternatives related to its capital structure as discussed in Note 2. While the Board is committed to continuing to evaluate such options, the Company cannot provide any assurance that any transaction will be completed or that any dividends will ultimately be paid.
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.


7

Note 5—Earnings Per Share
A reconciliation between the basic and diluted earnings per share computations (in thousands, except per share amounts) is as follow:
For the Three Months Ended June 30, 2018
Loss
(Numerator)
 
Shares
(Denominator)
 
Per
Share Amount
BASIC EPS
 
 
 
 
 
Net loss available to common stockholders
$
(2,611
)
 
25,568

 
$
(0.10
)
Stock options
—

 
—

 
 
Attributable to participating securities
—

 
—

 
 
DILUTED EPS
$
(2,611
)
 
25,568

 
$
(0.10
)
 
 
 
 
 
 
For the Six Months Ended June 30, 2018
Loss
(Numerator)
 
Shares
(Denominator)
 
Per
Share Amount
BASIC EPS
 
 
 
 
 
Net loss available to common stockholders
$
(4,823
)
 
25,554

 
$
(0.19
)
  Stock options
—

 
—

 
 
Attributable to participating securities
—

 
—

 
 
DILUTED EPS
$
(4,823
)
 
25,554

 
$
(0.19
)
 
 
 
 
 
 
For the Three Months Ended June 30, 2017
Loss (Numerator)
 
Shares
(Denominator)
 
Per
Share Amount
BASIC EPS
 
 
 
 
 
Net loss available to common stockholders
$
(3,385
)
 
21,215

 
$
(0.16
)
Stock options
—

 
—

 
 
Attributable to participating securities
—

 
—

 
 
DILUTED EPS
$
(3,385
)
 
21,215

 
$
(0.16
)
 
 
 
 
 
 
For the Six Months Ended June 30, 2017
Loss (Numerator)
 
Shares
(Denominator)
 
Per
Share Amount
BASIC EPS
 
 
 
 
 
Net loss available to common stockholders
$
(8,303
)
 
21,212

 
$
(0.39
)
Stock options
—

 
—

 
 
Attributable to participating securities
—

 
—

 
 
DILUTED EPS
$
(8,303
)
 
21,212

 
$
(0.39
)

An aggregate of 2.0 million and 1.4 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 and six month periods ended June 30, 2018 and 2017, respectively, because the inclusion would have been anti-dilutive as a result of the net loss reported for such periods.
    

8

Note 6—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. 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 June 30, 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 June 30, 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 June 30, 2018, $0.5 million of the shortfall remained as part of the carrying value of the 2021 PIK Notes and the Company recognized $53,000 of amortization expense as an increase to interest expense during the six months ended June 30, 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

9

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 June 30, 2018, $0.5 million of the excess remained as part of the carrying value of the 2021 Notes and the Company recognized $87,000 of amortization expense as a reduction to interest expense during the six months ended June 30, 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 provided 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 June 30, 2018, the Company had $32.5 million of borrowings outstanding under the Term Loans and $13.5 million of available borrowings under the Multidraw Term Loan Agreement based on the reduced Term Loan Commitments discussed below. However, the amount of available borrowings is subject to further reductions on a calendar quarter basis as a result of the Coverage Ratio discussed below and the Company's ability to utilize such available borrowings is subject to the Company's ability to comply with certain covenants included in the agreement.
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. As of June 30, 2018, the Coverage Ratio was less than 2.0 to 1.0 and as a result, the Company elected to permanently reduce the then outstanding Term Loan Commitments to $46 million such that after giving effect to such reduction the Coverage Ratio was satisfied. As a result, the Company was deemed to have satisfied the Coverage Ratio as of June 30, 2018, and the applicable default or event of default was deemed waived and not to have occurred for all purposes under the Multidraw Term Loan Agreement.
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. On June 21, 2018, the Company entered into a waiver and consent with respect to the Multidraw Term Loan Agreement and borrowed an additional $2.5 million thereunder, subject to certain payment conditions

10

with respect to specified past due obligations. In connection therewith, any related defaults or events of default with respect to such obligations and certain conditions to such borrowing relating to the financial condition of the Company were waived. As of June 30, 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 June 30, 2018 and December 31, 2017 and the Term Loans are reflected net of $1.7 million and $2.0 million of related unamortized financing costs as of June 30, 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 June 30, 2018 and December 31, 2017 (in thousands):
 
June 30, 2018
 
December 31, 2017
 
2021 Notes
2021 PIK Notes
Term Loans
 
2021 Notes
2021 PIK Notes
Term Loans
Face Value
$
9,427

$
275,046

$
32,500

 
$
9,427

$
263,202

$
30,000

Unamortized Deferred Financing Costs
(201
)
—

(1,692
)
 
(212
)
—

(2,037
)
Excess (Shortfall) Carrying Value
518

(455
)
—

 
606

(508
)
—

Accrued PIK Interest
—

—

—

 
—

8,883

—

Carrying Value
$
9,744

$
274,591

$
30,808

 
$
9,821

$
271,577

$
27,963


Note 7—Asset Retirement Obligation

The following table describes the changes to the Company’s asset retirement obligation liability (in thousands):
 
Six Months Ended June 30,
 
2018
 
2017
Asset retirement obligation, beginning of period
$
31,310

 
$
36,610

Liabilities incurred
7

 
574

Liabilities settled
(98
)
 
(1,357
)
Accretion expense
240

 
1,100

Revisions in estimates
(67
)
 
(161
)
Divestiture of oil and gas properties
(28,214
)
 
(248
)
Asset retirement obligation, end of period
3,178

 
36,518

Less: current portion of asset retirement obligation
(877
)
 
(2,759
)
Long-term asset retirement obligation
$
2,301

 
$
33,759


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 8—Derivative Instruments
    
The Company seeks to reduce its exposure to commodity price volatility by hedging a portion of its production through commodity derivative instruments. When the conditions for hedge accounting are met, the Company may designate its commodity derivatives as cash flow hedges. The changes in fair value of derivative instruments that qualify for hedge accounting treatment are recorded in other comprehensive income (loss) until the hedged oil or natural gas quantities are produced. If a derivative does not qualify for hedge accounting treatment, the changes in the fair value of the derivative are recorded in the income statement as derivative income (expense). At June 30, 2018, the Company had no outstanding derivative contracts.

Oil and gas sales include additions (reductions) related to the settlement of gas hedges of $0 and $108,000 and oil hedges of ($307,000) and $0 for the three months ended June 30, 2018 and 2017, respectively. Oil and gas sales include additions (reductions) related to the settlement of gas hedges of $805,000 and $(214,000) and oil hedges of ($571,000) and $0 for the six months ended June 30, 2018 and 2017, respectively. On June 14, 2018, the Company's hedging counterparty, Koch Supply &

11

Trading, LP, terminated the only outstanding hedge contract resulting in a liability of $0.9 million, which is included in other accrued liabilities in the Company's Consolidated Balance Sheet as of June 30, 2018. The loss at the termination date remained in accumulated other comprehensive loss and will be reclassified to earnings as the hedged volumes are produced over the original term of the contract.

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 June 30, 2018 and December 31, 2017:    
 
Commodity Derivatives
Period
Balance Sheet
Location
Fair Value
June 30, 2018
Derivative liability
$
—

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 June 30, 2018 and 2017:
Instrument
Amount of Gain Recognized in Other
Comprehensive Income
 
Location of
Gain Reclassified
into Income
 
Amount of Gain (Loss) Reclassified into
Oil and Gas Sales
Commodity Derivatives - June 30, 2018
$
(445
)
 
Oil and gas sales
 
$
(307
)
Commodity Derivatives - June 30, 2017
$
2,179

 
Oil and gas sales
 
$
108


Effect of Cash Flow Hedges on the Consolidated Statements of Operations and Comprehensive Loss for the six months ended June 30, 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 - June 30, 2018
$
(990
)
 
Oil and gas sales
 
$
233

Commodity Derivatives - June 30, 2017
$
5,045

 
Oil and gas sales
 
$
(214
)


Note 9 – Fair Value Measurements
As defined in ASC Topic 820, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. ASC Topic 820 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. As presented in the tables below, this hierarchy consists of three broad levels:
•
Level 1: valuations consist of unadjusted quoted prices in active markets for identical assets and liabilities and has the highest priority;
•
Level 2: valuations rely on quoted prices in markets that are not active or observable inputs over the full term of the asset or liability;
•
Level 3: valuations are based on prices or third party or internal valuation models that require inputs that are significant to the fair value measurement and are less observable and thus have the lowest priority.
The Company classifies its commodity derivatives based upon the data used to determine fair value. The Company’s derivative instruments at December 31, 2017 were in the form of swaps based on NYMEX pricing for oil and natural gas. The fair value of these derivatives were 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

12

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 June 30, 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:
 
 
 
 
 
June 30, 2018
$
—

 
$
—

 
$
—

December 31, 2017
$
—

 
$
443

 
$
—

The fair value of the Company's cash and cash equivalents approximated book value at June 30, 2018 and December 31, 2017. The fair value of the Term Loans was determined using Level 2 inputs and approximated face value as of June 30, 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 represent 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 June 30, 2018 and December 31, 2017 (in thousands):
 
June 30, 2018
 
December 31, 2017
 
Fair Value
Face Value
Carrying Value
 
Fair Value
Face Value
Carrying Value
2021 Notes
$
4,396

$
9,427

$
9,744

 
$
7,306

$
9,427

$
9,821

2021 PIK Notes
128,246

275,046

274,591

 
198,717

263,202

271,577

 
$
132,642

$
284,473

$
284,335

 
$
206,023

$
272,629

$
281,398


Note 10—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 $116.7 million and $115.9 million as of June 30, 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 June 30, 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.


13

Note 11 - Other Comprehensive Income

The following table represents the changes in accumulated other comprehensive income (loss), net of tax, for the three month period ended June 30, 2018 (in thousands):
 
Gains and Losses on Cash Flow Hedges
 
Change in Valuation Allowance
 
Total
Balance as of March 31, 2018
$
(546
)
 
$
(172
)
 
$
(718
)
Other comprehensive income before reclassifications:
 
 
 
 
 
 Change in fair value of cash flow derivatives
(445
)
 
—

 
(445
)
 Income tax effect
107

 
(107
)
 
—

 Net of tax
(338
)
 
(107
)
 
(445
)
Amounts reclassified from accumulated other comprehensive loss:
 
 
 
 
 
 Oil and gas sales
307

 
—

 
307

 Income tax effect
(74
)
 
74

 
—

 Net of tax
233

 
74

 
307

 
 
 
 
 
 
Derivatives expense
54

 
—

 
54

Income tax effect
(13
)
 
13

 
—

Net of tax
41

 
13

 
54

Net other comprehensive income
(64
)
 
(20
)
 
(84
)
Balance as of June 30, 2018
$
(610
)
 
$
(192
)
 
$
(802
)

    
The following table represents the changes in accumulated other comprehensive income (loss), net of tax, for the six
month period ended June 30, 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 cash flow derivatives
(990
)
 
—

 
(990
)
 Income tax effect
238

 
(238
)
 
—

 Net of tax
(752
)
 
(238
)
 
(990
)
Amounts reclassified from accumulated other comprehensive income:
 
 
 
 
 
 Oil and gas sales
(233
)
 
—

 
(233
)
 Income tax effect
56

 
33

 
89

 Net of tax
(177
)
 
33

 
(144
)
Amounts reclassified from accumulated other comprehensive loss:
 
 
 
 
 
Derivatives expense
54

 
—

 
54

Income tax effect
(13
)
 
13

 
—

Net of tax
41

 
13

 
54

Net other comprehensive loss
(888
)
 
(192
)
 
(1,080
)
Balance as of June 30, 2018
$
(610
)
 
$
(192
)
 
$
(802
)


14

The following table represents the changes in accumulated other comprehensive income (loss), net of tax, for the three month period ended June 30, 2017 (in thousands):
 
Gains and Losses on Cash Flow Hedges
 
Change in Valuation Allowance
 
Total
Balance as of March 31, 2017
$
(981
)
 
$
(581
)
 
$
(1,562
)
Other comprehensive income before reclassifications:
 
 
 
 
 
 Change in fair value of derivatives
2,179

 
—

 
2,179

 Income tax effect
(810
)
 
581

 
(229
)
 Net of tax
1,369

 
581

 
1,950

Amounts reclassified from accumulated other comprehensive income:
 
 
 
 
 
 Oil and gas sales
(108
)
 
—

 
(108
)
 Income tax effect
40

 
—

 
40

 Net of tax
(68
)
 
—

 
(68
)
Net other comprehensive loss
1,301

 
581

 
1,882

Balance as of June 30, 2017
$
320

 
$
—

 
$
320


The following table represents the changes in accumulated other comprehensive income (loss), net of tax, for the six month period ended June 30, 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
5,045

 
—

 
5,045

 Income tax effect
(1,876
)
 
1,767

 
(109
)
 Net of tax
3,169

 
1,767

 
4,936

Amounts reclassified from accumulated other comprehensive income:
 
 
 
 
 
 Oil and gas sales
214

 
—

 
214

 Income tax effect
(80
)
 
—

 
(80
)
 Net of tax
134

 
—

 
134

Net other comprehensive loss
3,303

 
1,767

 
5,070

Balance as of June 30, 2017
$
320

 
$
—

 
$
320




15

Note 12 - 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 $7.9 million of revenue receivable at June 30, 2018, comprised of $2.4 million of oil revenue, $4.1 million of natural gas revenue and $1.4 million of NGL revenue.
The following table includes a disaggregation of revenue by product including the effects of hedges in place (in thousands):
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2018
 
2017
 
2018
 
2017
Oil production
$
5,660

 
$
7,300

 
$
11,982

 
$
14,171

Natural gas production
11,825

 
13,751

 
26,709

 
24,413

Natural gas liquids production
4,076

 
3,200

 
7,788

 
6,439

Total
$
21,561

 
$
24,251

 
$
46,478

 
$
45,023

    
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.
    

16

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 provide greater exposure to 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 beginning in 2014. In response to the lower commodity prices, we executed the following actions beginning in 2015 aimed at increasing liquidity, reducing overall debt levels and extending debt maturities:
•
Completed the sale of our Oklahoma assets for $292.6 million;
•
Completed two debt exchanges in 2016 to extend maturities on a significant portion of debt and to reduce cash interest expense until August 2018;
•
Reduced total debt 25% from $425 million at December 31, 2014 to $317 million at June 30, 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 $12.7 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); and
•
Reduced capital spending in 2018.
Despite the foregoing actions, our overall liquidity position and our cash available for capital expenditures continue to be negatively impacted by continued weak natural gas prices, declining production and increasing cash interest expense on outstanding indebtedness. Due to the sale of our Gulf of Mexico properties in January 2018 and normal production declines, our production declined by 35% in the second quarter of 2018 when compared to the fourth quarter of 2017 and our cash flow from operations for the six months ended June 30, 2018 was a negative $2.9 million. The sale of our Gulf of Mexico properties when combined with reduced capital spending in 2018 is expected to result in declining production, proved reserves and cash flow from operations during 2018 when compared to 2017. At June 30, 2018, we had approximately $5.8 million of cash and approximately $317.0 million aggregate principal amount of outstanding indebtedness, and we had deferred nine dividend payments with respect to our Series B Preferred Stock and accrued a $12.8 million payable related to the nine deferred payments and the quarterly dividend that was payable on July 15, 2018. In addition, beginning with the August 15, 2018 interest payment on our 2021 PIK Notes (as defined below), we will be required to pay interest on our 2021 PIK Notes at 10% in cash (instead of 1% in cash and 9% in payment in kind). The cash interest payment due on August 15, 2018 under our 2021 PIK Notes and 2021 Notes (as defined below) will total approximately $14.2 million. In addition, our available borrowings under the Multidraw Term Loan Agreement are subject to reductions on a calendar quarter basis based on the Coverage Ratio and our ability to utilize such available borrowings is subject to our ability to comply with certain covenants included in the agreement.
As a result of the forgoing, we are analyzing and evaluating various alternatives with respect to our capital structure, including our significant amount of indebtedness, liquidity and upcoming cash interest payment on our 2021 PIK Notes and 2021 Notes. See “- Liquidity and Capital Resources” below for more information.
Critical Accounting Policies
Reserve Estimates
Our estimates of proved oil and gas reserves constitute those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. At the end of each year, our proved reserves are estimated

17

by independent petroleum engineers in accordance with guidelines established by the SEC. These estimates, however, represent projections based on geologic and engineering data. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that are difficult to measure. The accuracy of any reserve estimate is a function of the quantity and quality of available data, engineering and geological interpretation and professional judgment. Estimates of economically recoverable oil and gas reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effect of regulations by governmental agencies, and assumptions governing future oil and gas prices, future operating costs, severance taxes, 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.

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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 12 for additional disclosures.
Results of Operations
The following table sets forth certain information with respect to our oil and gas operations for the periods noted. These historical results are not necessarily indicative of results to be expected in future periods.         
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2018
 
2017
 
2018
 
2017
Production:
 
 
 
 
 
 
 
Oil (Bbls)
84,879

 
147,723

 
185,054

 
280,401

Gas (Mcf)
4,186,629

 
4,357,390

 
8,790,650

 
7,882,356

Ngl (Mcfe)
901,151

 
1,080,100

 
1,798,254

 
1,984,306

Total Production (Mcfe)
5,597,054

 
6,323,828

 
11,699,228

 
11,549,068

Sales:
 
 
 
 
 
 
 
Total oil sales
$
5,659,813

 
$
7,299,518

 
$
11,981,670

 
$
14,170,927

Total gas sales
11,825,143

 
13,750,945

 
26,709,256

 
24,413,287

Total ngl sales
4,076,079

 
3,200,165

 
7,787,554

 
6,438,711

Total oil, gas, and ngl sales
$
21,561,035

 
$
24,250,628

 
$
46,478,480

 
$
45,022,925

Average sales prices:
 
 
 
 
 
 
 
Oil (per Bbl)
$
66.68

 
$
49.41

 
$
64.75

 
$
50.54

Gas (per Mcf)
2.82

 
3.16

 
3.04

 
3.10

Ngl (per Mcfe)
4.52

 
2.96

 
4.33

 
3.24

Per Mcfe
3.85

 
3.83

 
3.97

 
3.90

The above sales and average sales prices include increases (decreases) to revenue related to the settlement of gas hedges of $0 and $108,000 and oil hedges of ($307,000) and $0 for the three months ended June 30, 2018 and 2017, respectively. The above sales and average sales prices include increases (decreases) to revenue related to the settlement of gas hedges of $805,000 and ($214,000) and oil hedges of ($571,000) and $0 for the six months ended June 30, 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.

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In January 2018, we completed the sale of our Gulf of Mexico assets. During the three and six months ended June 30, 2017, these assets contributed the following to our oil and gas operations:

Three months ended June 30, 2017
 
Percent of Total Company
 
Six months ended June 30, 2017
 
Percent of Total Company
Production:

 

 
 
 
 
Oil (Bbls)
74,772

 
51
%
 
155,245

 
55
%
Gas (Mcf)
795,357

 
18
%
 
1,611,193

 
20
%
Ngl (Mcfe)
82,048

 
8
%
 
177,094

 
9
%
Total Production (Mcfe)
1,326,037

 
21
%
 
2,719,757

 
24
%
Sales:

 

 
 
 
 
Total oil sales
$
3,670,695

 
50
%
 
$
7,859,798

 
55
%
Total gas sales
2,453,479

 
18
%
 
5,036,244

 
21
%
Total ngl sales
285,014

 
9
%
 
582,578

 
9
%
Total oil and gas sales
$
6,409,188

 
26
%
 
$
13,478,620

 
30
%
Net loss available to common stockholders totaled $2,611,000 and $3,385,000 for the three months ended June 30, 2018 and 2017, respectively, while net loss available to common stockholders totaled $4,823,000 and $8,303,000 for the six months ended June 30, 2018 and 2017, respectively. The primary fluctuations were as follows:
Production Total production decreased 11% and increased 1% during the three and six month periods ended June 30, 2018, respectively, as compared to the 2017 periods, but has decreased by 35% in the second quarter of 2018 when compared to the fourth quarter of 2017. The decreases in production as compared to the second quarter of 2017 and the fourth quarter of 2017 were due primarily 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. Partially offsetting these decreases were increases as a result of the success of our East Texas drilling program. As a result of reduced capital spending and the sale of our Gulf of Mexico assets which contributed 24% of our total production in 2017, we expect our total production during the remainder of 2018 to decline as compared to 2017.
Gas production during the three and six month periods ended June 30, 2018 decreased 4% and increased 12%, respectively, from the comparable periods in 2017, but has decreased by 35% in the second quarter of 2018 when compared to the fourth quarter of 2017. The increase in gas production as compared to the first half of 2017 was primarily the result of our successful East Texas drilling program and the successful recompletion of our Thunder Bayou well. Partially offsetting this increase was a decrease 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 20% 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 and six month periods ended June 30, 2018 decreased 43% and 34%, respectively, from the comparable 2017 periods, but has decreased by 50% in the second quarter of 2018 when compared to the fourth quarter of 2017. The decrease in oil production as compared to the first half of 2017 was due primarily to the sale of our Gulf of Mexico assets and the sale of our E. Lake Verret field during the second quarter of 2017. Partially offsetting this decrease was an increase as a result of the successful recompletion of our Thunder Bayou well 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 55% 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 and six month periods ended June 30, 2018 decreased 17% and 9%, respectively, from the comparable 2017 periods 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. These decreases were 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 hedges, average gas prices per Mcf for the three and six month periods ended June 30, 2018 were $2.82 and $3.04, respectively, as compared to $3.16 and $3.10, respectively, for the 2017 periods. Average oil prices per Bbl for the three and six months ended June 30, 2018 were $66.68 and $64.75, respectively, as compared to $49.41 and $50.54, respectively, for the 2017 periods and average Ngl prices per Mcfe for the three and six month periods ended June 30, 2018 were $4.52 and $4.33, respectively, as compared to $2.96 and $3.24, respectively, for the 2017 periods. Stated on an Mcfe basis, unit prices received during the six months ended June 30, 2018 were 2% higher than prices received during the comparable 2017 period.

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Revenue Including the effects of hedges, oil and gas sales during the three months ended June 30, 2018 decreased 11% to $21,561,000 as compared to $24,251,000 during the 2017 period. Including the effects of hedges, oil and gas sales during the six months ended June 30, 2018 increased 3% to $46,478,000, as compared to $45,023,000 during the 2017 period. The decrease during the second quarter of 2018 was primarily the result of the production decreases due to the sale of our Gulf of Mexico assets.
Expenses Lease operating expenses for the three and six months ended June 30, 2018 totaled $4,972,000 and $12,012,000, respectively, as compared to $7,113,000 and $14,189,000, respectively, during the 2017 periods. Per unit lease operating expenses totaled $0.89 and $1.03 per Mcfe for the three and six months ended June 30, 2018, respectively, as compared to $1.12 and $1.23 per Mcfe, respectively during the 2017 periods. The decreases in per unit lease operating expenses for the three and six months ended June 30, 2018 are 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 and six months ended June 30, 2018 totaled $334,000 and $1,561,000, respectively, as compared to $570,000 and $878,000 during the 2017 periods. Per unit production taxes totaled $0.06 and $0.13 per Mcfe, respectively, during the three and six months ended June 30, 2018, as compared to $0.09 and $0.08 per Mcfe, respectively, during the 2017 periods. The increase in production taxes during the first half of 2018 was primarily due to the expiration of the two-year tax exemption on our Thunder Bayou well in June 2017 while the decrease during the second quarter of 2018 was a result of refunds received for previously paid severance tax for wells in East Texas which qualified for a high cost tax deduction.
General and administrative expenses during the three and six months ended June 30, 2018 totaled $4,004,000 and $7,304,000, respectively, as compared to $4,314,000 and $7,467,000 during the respective 2017 periods. Share-based compensation costs totaled $164,000 and $348,000, respectively, during the three and six months ended June 30, 2018 as compared to $402,000 and $822,000 during the respective 2017 periods. We capitalized $1,636,000 and $3,066,000, respectively, of general and administrative expenses during the three and six month periods ended June 30, 2018 compared to $2,010,000 and $3,344,000 during the respective 2017 periods.
Depreciation, depletion and amortization (“DD&A”) expense on oil and gas properties for the three and six months ended June 30, 2018 totaled $5,925,000, or $1.06 per Mcfe, and $12,379,000, or $1.06 per Mcfe, respectively, as compared to $6,746,000, or $1.07 per Mcfe, and $12,761,000, or $1.10 per Mcfe, during the respective 2017 periods. The decrease in the per unit DD&A rate for the six months ended June 30, 2018 is primarily the result of the 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 second quarter rate during the remainder of 2018.
Interest expense, net of amounts capitalized on unevaluated properties, totaled $7,636,000 and $15,117,000 during the three and six months ended June 30, 2018, as compared to $7,147,000 and $14,405,000 during the respective 2017 periods. During the three and six month periods ended June 30, 2018, our capitalized interest totaled $436,000 and $857,000, respectively, as compared to $403,000 and $708,000 during the respective 2017 periods. 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. Therefore, although our total interest expense for the year ended 2018 is expected to approximate interest expense during 2017, our cash interest expense will be significantly higher during the remainder of 2018 as compared to 2017.
Income tax expense (benefit) during the six month period ended June 30, 2018 was $106,000 as compared to $(189,000) during the six months ended June 30, 2017. 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 $116,661,000 as of June 30, 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.

21

Liquidity and Capital Resources
At June 30, 2018, we had a working capital deficit of approximately $3.9 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 beginning in 2014. In response to lower commodity prices we executed a number of transactions described in "Overview" above aimed at increasing liquidity, reducing overall debt levels and extending debt maturities.
Despite such actions, our overall liquidity position and our cash available for capital expenditures continue to be negatively impacted by continued weak natural gas prices, declining production and increasing cash interest expense on our outstanding indebtedness. Due to the sale of our Gulf of Mexico properties in January 2018 and normal production declines, our production declined by 35% in the second quarter of 2018 when compared to the fourth quarter of 2017, and our cash flow from operations for the six months ended June 30, 2018, was a negative $2.9 million. The sale of our Gulf of Mexico properties when combined with reduced capital spending in 2018 is expected to result in declining production, proved reserves and cash flow from operations during 2018 when compared to 2017. At June 30, 2018, we had approximately $5.8 million of cash and approximately $317.0 million aggregate principal amount of outstanding indebtedness, and we had deferred nine dividend payments with respect to our Series B Preferred Stock and accrued a $12.8 million payable related to the nine deferred payments and the quarterly dividend that was payable on July 15, 2018. In addition, beginning with the August 15, 2018 interest payment on our 2021 PIK Notes (as defined below), we will be required to pay interest on our 2021 PIK Notes at 10% in cash (instead of 1% in cash and 9% in payment in kind). The cash interest payment due on August 15, 2018 under our 2021 PIK Notes and 2021 Notes (as defined below) will total approximately $14.2 million. In addition, available borrowings under the Multidraw Term Loan Agreement are subject to reductions on a calendar quarter basis based on the Coverage Ratio and our ability to utilize such available borrowings is subject to our ability to comply with certain covenants included in the agreement.
As a result of the forgoing, we are analyzing and evaluating various alternatives with respect to our capital structure, including our significant amount of indebtedness, liquidity and upcoming cash interest payment on our 2021 PIK Notes and 2021 Notes. To assist our Board of Directors and management team in analyzing and evaluating these alternatives, we have retained Seaport Global Securities as our financial advisor and Porter Hedges LLP as our legal advisor. These alternatives include private debt exchanges, asset sales, draws under the Multidraw Term Loan Agreement, alternative financing arrangements to replace the Multidraw Term Loan Agreement and filing for protection under Chapter 11 of the U.S. bankruptcy code. We do not intend to disclose or comment on developments related to our review unless and until the Board has approved a specific alternative or transaction or otherwise determined that further disclosure is appropriate. We cannot provide any assurance that any of the alternatives being evaluated will provide additional liquidity or enable us to refinance our outstanding indebtedness. See "Item 1A Risk Factors - We may seek the protection of the Bankruptcy Court, which may harm our business and place equity holders at significant risk of losing all of their interests in the Company".
Source of Capital: Operations
Net cash flow (used in) provided by operations decreased from $13.7 million during the six months ended June 30, 2017 to ($2.9) million during the 2018 period. The decrease in operating cash flow during 2018 as compared to 2017 is primarily attributable to reductions in 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.
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 $12.7 million ($12.3 million at June 30, 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".

22

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 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 June 30, 2018, $0.5 million of the shortfall remained as part of the carrying value of the 2021 PIK Notes and we recognized $53,000 of amortization expense as an increase to interest expense during the six months ended June 30, 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 June 30, 2018, $0.5 million of the excess remained as part of the carrying value of the 2021 Notes and the

23

Company recognized $87,000 of amortization expense as a reduction to interest expense during the six months ended June 30, 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 provided 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 $32.5 million of borrowings outstanding under the Term Loans and $13.5 million of available borrowings under the Multidraw Term Loan Agreement based on the reduced Term Loan Commitments discussed below. However, the amount of available borrowings is subject to further reductions on a calendar quarter basis as a result of the Coverage Ratio discussed below and our ability to utilize such available borrowings is subject to our ability to comply with certain covenants included in the 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. As of June 30, 2018, the Coverage Ratio was less than 2.0 to 1.0 and as a result, we elected to permanently reduce the then outstanding Term Loan Commitments to $46 million such that after giving effect to such reduction the Coverage Ratio was satisfied. As a result, we were deemed to have satisfied the Coverage Ratio as of June 30, 2018, and the applicable default or event of default was deemed waived and not to have occurred for all purposes under the Multidraw Term Loan Agreement.
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.
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. On June 21, 2018, we entered into a waiver and consent with respect to the Multidraw Term Loan Agreement and borrowed an additional $2.5 million thereunder, subject to certain payment conditions with respect to specified past due obligations. In connection therewith, any related defaults or events of default with respect to such obligations and certain conditions to such borrowing relating to our financial condition were waived. 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.

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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 June 30, 2018 and December 31, 2017 (in thousands):
 
June 30, 2018
 
December 31, 2017
 
2021 Notes
2021 PIK Notes
Term Loans
 
2021 Notes
2021 PIK Notes
Term Loans
Face Value
$
9,427

$
275,046

$
32,500

 
$
9,427

$
263,202

$
30,000

Unamortized Deferred Financing Costs
(201
)
—

(1,692
)
 
(212
)
—

(2,037
)
Excess (Shortfall) Carrying Value
518

(455
)
—

 
606

(508
)
—

Accrued PIK Interest
—

—

—

 
—

8,883

—

Carrying Value
$
9,744

$
274,591

$
30,808

 
$
9,821

$
271,577

$
27,963


Use of Capital: Exploration and Development
Our 2018 capital budget is planned 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 half of 2018 we incurred $7.0 million in capital expenditures primarily related to two completions in our East Texas drilling program, various plugging and abandonment projects and leasing efforts in the Austin Chalk. 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.
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. We have invested approximately $10.7 million as of June 30, 2018 in acquisition, engineering and geological costs and issued 2.0 million shares of common stock with respect to these interests. We plan to drill our initial horizontal test well during the first quarter of 2019 utilizing data from existing vertical and unfracked horizontal wells that have been drilled in the area.
We expect to finance our future acquisition activities, if consummated, with cash on hand, sales of equity or debt securities, sales of properties or assets or joint venture arrangements with industry partners, if necessary. We cannot assure you that such additional financings will be available on acceptable terms, if at all.
Disclosure Regarding Forward Looking Statements
This Quarterly Report on Form 10-Q contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements other than statements of historical facts included in and incorporated by reference into this Form 10-Q are forward looking statements. These forward-looking statements are subject to certain risks, trends and uncertainties that could cause actual results to differ materially from those projected.
Among those risks, trends and uncertainties are: our ability to identify, evaluate and complete any alternative or transaction with respect to our capital structure and to refinance or restructure our indebtedness or improve our liquidity position; the impact of the announcement of our review of such alternatives or transactions on our business, including our financial and operating results, or our employees, suppliers and customers; the potential need to seek bankruptcy protection; our indebtedness and the significant amount of cash required to service our indebtedness, including the August 15, 2018 cash interest payment on our 2021 PIK Notes and 2021 Notes; our estimate of the sufficiency of our existing capital sources, including availability under the Multidraw Term Loan Agreement, to fund our exploration and development activities and to service our indebtedness, including the August 15, 2018 cash interest payment on our 2021 PIK Notes and 2021 Notes; the volatility of oil and natural gas prices; our receipt of a cash refund with respect to our offshore bonds and the timing and amount of the same; our ability to hedge future production to reduce our exposure to price volatility in the current commodity pricing market; 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 responsibility for offshore decommissioning liabilities for offshore interests we no longer own; 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; our ability to fund our capital needs and respond to changing conditions imposed by the Multidraw Term Loan Agreement and restrictive debt covenants;

25

approximately 43% 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 common 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 $5.7 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 six months ended June 30, 2018, we received $0.2 million from the counterparties to our derivative instruments in connection with hedge settlements. We had no outstanding hedge contracts as of June 30, 2018.
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. We currently have no hedge contracts in place.
Interest Rate Risk
As of June 30, 2018, we had no debt subject to variable interest rates.


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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.
On March 23, 2015, BCR Holdings, Inc. filed suit in state district court in Lafourche Parish, Louisiana against PetroQuest Energy L.L.C. ("PQ LLC") and seven other defendant companies claiming damages arising from oilfield operations conducted pursuant to a November 14, 1941 oil, gas and mineral lease on certain lands located in Lafourche Parish, Louisiana, part of a field commonly known as "Bully Camp Field". On July 16, 2018 the Court signed an order approving the complete settlement of the case. As part of the settlement, PQ LLC expects to be dismissed from the lawsuit and released from any obligations owed to BCR Holdings, Inc., as well as the other defendants, for all claims brought in the lawsuit.
There have been no other significant changes with respect to the legal matters disclosed in our Annual Report on Form 10-K for the year ended December 31, 2017.
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 June 30, 2018 was $311.2 million. We currently have $13.5 million of additional availability under the Multidraw Term Loan Agreement. However, our available borrowings under the Multidraw Term Loan Agreement are subject to reductions on a calendar quarter basis based on

27

the Coverage Ratio and our ability to utilize such available borrowings is subject to our ability to comply with certain covenants included in the agreement.
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 $15.9 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 (including $14.2 million of interest due on August 15, 2018 with respect to our 2021 Notes and 2021 PIK Notes) 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 $14.2 million of interest due on August 15, 2018 with respect to our 2021 Notes and 2021 PIK Notes) and meet our other obligations. If we do not have enough cash to service our debt, we may be required to refinance all or part of our existing debt, including our 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 $317.0 million at June 30, 2018, is expected to total approximately $15.9 million for the remainder of 2018 (or approximately $32 million per year, including $14.2 million of interest due on August 15, 2018 with respect to our 2021 Notes and 2021 PIK Notes), as compared to $7.4 million in 2017. As a result of higher cash interest expense and the impact of the sale 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.

28

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 $12.7 million 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.
We may seek the protection of the Bankruptcy Court, which may harm our business and place equity holders at significant risk of losing all of their interest in the Company.
We are analyzing and evaluating various alternatives with respect to our capital structure, including our significant amount of indebtedness, liquidity and the August 15, 2018 cash interest payment on our 2021 PIK Notes and 2021 Notes. If we are unable to improve our liquidity position and refinance or restructure our debt, a filing under Chapter 11 of the U. S. Bankruptcy Code may be unavoidable. Seeking Bankruptcy Court protection could have a material adverse effect on our business, financial condition, results of operations and liquidity. So long as a proceeding related to a Chapter 11 proceeding continues, our senior management would be required to spend a significant amount of time and effort dealing with the reorganization instead of focusing exclusively on our business operations. Bankruptcy Court protection also might make it more difficult to retain management and other key personnel necessary to the success and growth of our business. In addition, the longer a proceeding related to a Chapter 11 proceeding continues, the more likely it is that our customers and suppliers would lose confidence in our ability to reorganize our business successfully and would seek to establish alternative commercial relationships.
Additionally, we have a significant amount of secured indebtedness that is senior to our 2021 Notes and 2021 PIK Notes in our capital structure, which in turn are senior to our existing preferred stock and common stock in our capital structure. As a result, we believe that seeking Bankruptcy Court protection under a Chapter 11 proceeding could result in a limited recovery for holders of our 2021 Notes and 2021 PIK Notes and place equity holders at significant risk of losing all of their interests in the Company.
We do not expect to be able to borrow under the Multidraw Term Loan Agreement, which limits our liquidity position.
As of June 30, 2018, we had $32.5 million of borrowings outstanding and $13.5 million of available borrowings under the Multidraw Term Loan Agreement. However, we expect that we will not be able to utilize such available borrowings due to our inability to comply with certain covenants with respect to borrowings under the agreement. In addition, available borrowings are subject to reductions on a calendar quarter basis based on the coverage ratio covenant in the agreement. The unavailability of the Multidraw Term Loan Agreement limits our liquidity position.
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 that 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.

29

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 June 30, 2018, the Company has deferred nine dividend payments and has accrued a $12.8 million payable related to the nine deferred payments and the quarterly dividend that was payable on July 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 and on June 18, 2018, we received written notices from separate holders 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. These requests were subsequently withdrawn. The Board continues to evaluate various options with respect to the Series B preferred stock, including the unpaid dividends, in connection with the Company's review of alternatives related to our capital structure as discussed in "Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources." While the Board is committed to continuing to evaluate such options, the Company cannot provide any assurance that any transaction will be completed or that any dividends will ultimately be paid.
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.

30

Item 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
 
There were no repurchases of our common stock during the quarter ended June 30, 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 $12.8 million.

Item 4. MINE SAFETY DISCLOSURES
NONE.

Item 5. OTHER INFORMATION
NONE.

Item 6. EXHIBITS
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 



31


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

 
PETROQUEST ENERGY, INC.



Date:
August 7, 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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