PETROQUEST ENERGY, INC.
Consolidated Balance Sheets
(Amounts in Thousands)
|
|
|
|
|
|
|
|
|
|
June 30,
2017
|
|
December 31,
2016
|
|
(unaudited)
|
|
(Note 1)
|
ASSETS
|
|
|
|
Current assets:
|
|
|
|
Cash and cash equivalents
|
$
|
19,772
|
|
|
$
|
28,312
|
|
Revenue receivable
|
9,605
|
|
|
10,294
|
|
Joint interest billing receivable
|
5,268
|
|
|
7,632
|
|
Derivative asset
|
966
|
|
|
—
|
|
Other current assets
|
3,612
|
|
|
2,353
|
|
Total current assets
|
39,223
|
|
|
48,591
|
|
Property and equipment:
|
|
|
|
Oil and gas properties:
|
|
|
|
Oil and gas properties, full cost method
|
1,344,653
|
|
|
1,323,333
|
|
Unevaluated oil and gas properties
|
14,867
|
|
|
9,015
|
|
Accumulated depreciation, depletion and amortization
|
(1,258,254
|
)
|
|
(1,243,286
|
)
|
Oil and gas properties, net
|
101,266
|
|
|
89,062
|
|
Other property and equipment
|
9,336
|
|
|
10,951
|
|
Accumulated depreciation of other property and equipment
|
(8,654
|
)
|
|
(10,109
|
)
|
Total property and equipment
|
101,948
|
|
|
89,904
|
|
Other assets
|
7,402
|
|
|
6,365
|
|
Total assets
|
$
|
148,573
|
|
|
$
|
144,860
|
|
LIABILITIES AND STOCKHOLDERS’ EQUITY
|
|
|
|
Current liabilities:
|
|
|
|
Accounts payable to vendors
|
$
|
28,725
|
|
|
$
|
25,265
|
|
Advances from co-owners
|
4,545
|
|
|
2,330
|
|
Oil and gas revenue payable
|
18,692
|
|
|
22,146
|
|
Accrued interest
|
1,851
|
|
|
2,047
|
|
Asset retirement obligation
|
2,759
|
|
|
4,160
|
|
Derivative liability
|
457
|
|
|
3,947
|
|
10% Senior Unsecured Notes due 2017
|
—
|
|
|
22,568
|
|
Other accrued liabilities
|
1,051
|
|
|
3,938
|
|
Total current liabilities
|
58,080
|
|
|
86,401
|
|
Multi-draw Term Loan
|
27,605
|
|
|
7,249
|
|
10% Senior Secured Notes due 2021
|
15,008
|
|
|
15,228
|
|
10% Senior Secured PIK Notes due 2021
|
259,816
|
|
|
248,600
|
|
Asset retirement obligation
|
33,759
|
|
|
32,450
|
|
Other long-term liabilities
|
7,742
|
|
|
6,027
|
|
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 21,219 and 21,197 shares, respectively
|
21
|
|
|
21
|
|
Paid-in capital
|
305,232
|
|
|
304,341
|
|
Accumulated other comprehensive income (loss)
|
320
|
|
|
(4,750
|
)
|
Accumulated deficit
|
(559,011
|
)
|
|
(550,708
|
)
|
Total stockholders’ equity
|
(253,437
|
)
|
|
(251,095
|
)
|
Total liabilities and stockholders’ equity
|
$
|
148,573
|
|
|
$
|
144,860
|
|
See accompanying Notes to Consolidated Financial Statements.
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,
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
Revenues:
|
|
|
|
|
|
|
|
Oil and gas sales
|
$
|
24,251
|
|
|
$
|
15,824
|
|
|
$
|
45,023
|
|
|
$
|
33,144
|
|
Expenses:
|
|
|
|
|
|
|
|
Lease operating expenses
|
7,113
|
|
|
6,864
|
|
|
14,189
|
|
|
15,041
|
|
Production taxes
|
570
|
|
|
(48
|
)
|
|
878
|
|
|
290
|
|
Depreciation, depletion and amortization
|
6,841
|
|
|
7,193
|
|
|
12,958
|
|
|
17,331
|
|
Ceiling test write-down
|
—
|
|
|
12,782
|
|
|
—
|
|
|
31,639
|
|
General and administrative
|
4,314
|
|
|
3,871
|
|
|
7,467
|
|
|
12,470
|
|
Accretion of asset retirement obligation
|
553
|
|
|
618
|
|
|
1,100
|
|
|
1,226
|
|
Interest expense
|
7,147
|
|
|
6,503
|
|
|
14,405
|
|
|
14,760
|
|
|
26,538
|
|
|
37,783
|
|
|
50,997
|
|
|
92,757
|
|
Other income:
|
|
|
|
|
|
|
|
Other income (expense)
|
(2
|
)
|
|
(424
|
)
|
|
52
|
|
|
(327
|
)
|
Loss from operations
|
(2,289
|
)
|
|
(22,383
|
)
|
|
(5,922
|
)
|
|
(59,940
|
)
|
Income tax (benefit) expense
|
(189
|
)
|
|
475
|
|
|
(189
|
)
|
|
561
|
|
Net loss
|
(2,100
|
)
|
|
(22,858
|
)
|
|
(5,733
|
)
|
|
(60,501
|
)
|
Preferred stock dividend
|
1,285
|
|
|
1,285
|
|
|
2,570
|
|
|
2,779
|
|
Loss available to common stockholders
|
$
|
(3,385
|
)
|
|
$
|
(24,143
|
)
|
|
$
|
(8,303
|
)
|
|
$
|
(63,280
|
)
|
Loss per common share:
|
|
|
|
|
|
|
|
Basic
|
|
|
|
|
|
|
|
Net loss per share
|
$
|
(0.16
|
)
|
|
$
|
(1.38
|
)
|
|
$
|
(0.39
|
)
|
|
$
|
(3.67
|
)
|
Diluted
|
|
|
|
|
|
|
|
Net loss per share
|
$
|
(0.16
|
)
|
|
$
|
(1.38
|
)
|
|
$
|
(0.39
|
)
|
|
$
|
(3.67
|
)
|
Weighted average number of common shares:
|
|
|
|
|
|
|
|
Basic
|
21,215
|
|
|
17,539
|
|
|
21,212
|
|
|
17,248
|
|
Diluted
|
21,215
|
|
|
17,539
|
|
|
21,212
|
|
|
17,248
|
|
See accompanying Notes to Consolidated Financial Statements.
PETROQUEST ENERGY, INC.
Consolidated Statements of Comprehensive Loss
(unaudited)
(Amounts in Thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Six Months Ended
|
|
June 30,
|
|
June 30,
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
Net loss
|
$
|
(2,100
|
)
|
|
$
|
(22,858
|
)
|
|
$
|
(5,733
|
)
|
|
$
|
(60,501
|
)
|
Change in fair value of derivative instruments, accounted for as hedges, net of income tax expense (benefit) of $189, ($475), $189 and ($561), respectively
|
1,882
|
|
|
(1,275
|
)
|
|
5,070
|
|
|
(1,420
|
)
|
Comprehensive loss
|
$
|
(218
|
)
|
|
$
|
(24,133
|
)
|
|
$
|
(663
|
)
|
|
$
|
(61,921
|
)
|
See accompanying Notes to Consolidated Financial Statements.
PETROQUEST ENERGY, INC.
Consolidated Statements of Cash Flows
(unaudited)
(Amounts in Thousands)
|
|
|
|
|
|
|
|
|
|
Six Months Ended
|
|
June 30,
|
|
2017
|
|
2016
|
Cash flows from operating activities:
|
|
|
|
Net loss
|
$
|
(5,733
|
)
|
|
$
|
(60,501
|
)
|
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
|
|
|
|
Deferred tax (benefit) expense
|
(189
|
)
|
|
561
|
|
Depreciation, depletion and amortization
|
12,958
|
|
|
17,331
|
|
Ceiling test writedown
|
—
|
|
|
31,639
|
|
Accretion of asset retirement obligation
|
1,100
|
|
|
1,226
|
|
Share-based compensation expense
|
825
|
|
|
925
|
|
Amortization costs and other
|
450
|
|
|
810
|
|
Non-cash interest expense on PIK Notes
|
11,179
|
|
|
—
|
|
Payments to settle asset retirement obligations
|
(1,357
|
)
|
|
(2,515
|
)
|
Costs incurred to issue 2021 Notes
|
—
|
|
|
4,808
|
|
Changes in working capital accounts:
|
|
|
|
Revenue receivable
|
689
|
|
|
24
|
|
Joint interest billing receivable
|
2,239
|
|
|
30,814
|
|
Accounts payable and accrued liabilities
|
(8,368
|
)
|
|
(31,260
|
)
|
Advances from co-owners
|
2,215
|
|
|
(15,541
|
)
|
Other
|
(2,314
|
)
|
|
(4,387
|
)
|
Net cash provided by (used in) operating activities
|
13,694
|
|
|
(26,066
|
)
|
Cash flows (used in) provided by investing activities:
|
|
|
|
Investment in oil and gas properties
|
(21,661
|
)
|
|
(18,166
|
)
|
Investment in other property and equipment
|
(37
|
)
|
|
(28
|
)
|
Sale of oil and gas properties
|
2,207
|
|
|
24,909
|
|
Net cash (used in) provided by investing activities
|
(19,491
|
)
|
|
6,715
|
|
Cash flows used in financing activities:
|
|
|
|
Net proceeds from share based compensation
|
32
|
|
|
52
|
|
Deferred financing costs
|
(125
|
)
|
|
(100
|
)
|
Payment of preferred stock dividend
|
—
|
|
|
(1,284
|
)
|
Redemption of 2017 Notes
|
(22,650
|
)
|
|
(53,626
|
)
|
Costs incurred to issue 2021 Notes
|
—
|
|
|
(4,808
|
)
|
Proceeds from borrowings
|
20,000
|
|
|
—
|
|
Net cash used in financing activities
|
(2,743
|
)
|
|
(59,766
|
)
|
Net decrease in cash and cash equivalents
|
(8,540
|
)
|
|
(79,117
|
)
|
Cash and cash equivalents, beginning of period
|
28,312
|
|
|
148,013
|
|
Cash and cash equivalents, end of period
|
$
|
19,772
|
|
|
$
|
68,896
|
|
Supplemental disclosure of cash flow information:
|
|
|
|
Cash paid during the period for:
|
|
|
|
Interest
|
$
|
3,743
|
|
|
$
|
16,783
|
|
See accompanying Notes to Consolidated Financial Statements.
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, 2017 and 2016
, 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, 2017
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, 2016
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, 2016
.
Unless the context otherwise indicates, any references in this Quarterly Report on Form 10-Q to the “Company,” "we," or "us" refer to PetroQuest Energy, Inc. ("PetroQuest") and its wholly-owned consolidated subsidiaries, PetroQuest Energy, L.L.C. (a single member Louisiana limited liability company), PetroQuest Oil & Gas, L.L.C. (a single member Louisiana limited liability company), TDC Energy LLC (a single member Louisiana limited liability company) and Pittrans, Inc. (an Oklahoma corporation).
Note 2—Acquisitions and Divestitures
Divestitures:
In March 2016, the Company sold certain non-producing assets in East Texas for
$7 million
to a potential joint venture partner. This sale was accounted for as an adjustment to the capitalized costs of oil and gas properties. After determining it would not pursue a joint venture with this party, the Company repurchased the non-producing assets for
$5.0 million
in December 2016 pursuant to the terms of the purchase and sale agreement related to this sale. The Company subsequently entered into a new drilling joint venture in East Texas with another group of partners.
On
April 20, 2016
, the Company completed the sale of a majority of its remaining Woodford Shale assets in the East Hoss field for approximately
$18 million
. This sale was accounted for as an adjustment to the capitalized costs of oil and gas properties.
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.
Note 3—Equity
Common Stock
On May 18, 2016, the Company effected a reverse split of its common stock at a ratio of
one
share of newly issued common stock for each
four
shares of issued and outstanding common stock (the "Reverse Split"). The purpose of the Reverse Split was to increase the per share trading price of the Company's common stock in order to regain compliance with the New York Stock Exchange continued listing standards. The Reverse Split proportionately reduced the total number of outstanding shares of common stock from approximately
70.5 million
shares to approximately
17.6 million
shares.
Convertible Preferred Stock
The Company has
1,495,000
shares of
6.875%
Series B Cumulative Convertible Perpetual Preferred Stock (the “Series B Preferred Stock”) outstanding.
The following is a summary of certain terms of the Series B Preferred Stock:
Dividends
. The Series B Preferred Stock accumulates dividends at an annual rate of
6.875%
for each share of Series B Preferred Stock. Dividends are cumulative from the date of first issuance and, to the extent payment of dividends is not prohibited by the Company’s debt agreements, assets are legally available to pay dividends and the Company’s board of directors or an authorized committee of the board declares a dividend payable, the Company pays dividends in cash, every quarter.
In connection with an amendment to the Company's prior bank credit facility (which was terminated and replaced by the Multidraw Term Loan Agreement with Franklin Custodian Funds in October 2016) prohibiting the Company from declaring or paying dividends on the Series B Preferred Stock, the Company suspended the quarterly cash dividend on its Series B Preferred Stock beginning with the dividend payment due on April 15, 2016. The Multidraw Term Loan Agreement also prohibits the Company from declaring and paying cash dividends on the Series B Preferred Stock. Under the terms of the Series B Preferred Stock, any unpaid dividends will accumulate. As of
June 30, 2017
, the Company has deferred
five
dividend payments and has accrued a
$7.7 million
payable related to the
five
deferred payments and the quarterly dividend that was payable on July 15, 2017, which is included in other long-term liabilities 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 until all accumulated and unpaid dividends on the Series B Preferred Stock are paid in full. No such election has been held and no holder of the Series B Preferred Stock has exercised its right to request such election as of the date of this report.
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.
Note 4—Earnings Per Share
A reconciliation between the basic and diluted earnings per share computations (in thousands, except per share amounts) is as follow:
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months Ended June 30, 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
|
)
|
|
|
|
|
|
|
For the Three Months Ended June 30, 2016
|
Loss (Numerator)
|
|
Shares
(Denominator)
|
|
Per
Share Amount
|
BASIC EPS
|
|
|
|
|
|
Net loss available to common stockholders
|
$
|
(24,143
|
)
|
|
17,539
|
|
|
$
|
(1.38
|
)
|
Stock options
|
—
|
|
|
—
|
|
|
|
Attributable to participating securities
|
—
|
|
|
—
|
|
|
|
DILUTED EPS
|
$
|
(24,143
|
)
|
|
17,539
|
|
|
$
|
(1.38
|
)
|
|
|
|
|
|
|
For the Six Months Ended June 30, 2016
|
Loss (Numerator)
|
|
Shares
(Denominator)
|
|
Per
Share Amount
|
BASIC EPS
|
|
|
|
|
|
Net loss available to common stockholders
|
$
|
(63,280
|
)
|
|
17,248
|
|
|
$
|
(3.67
|
)
|
Stock options
|
—
|
|
|
—
|
|
|
|
Attributable to participating securities
|
—
|
|
|
—
|
|
|
|
DILUTED EPS
|
$
|
(63,280
|
)
|
|
17,248
|
|
|
$
|
(3.67
|
)
|
An aggregate of
1.4 million
and
0.3 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, 2017 and 2016
, respectively, because the inclusion would have been anti-dilutive as a result of the net loss reported for such periods.
Note 5—Long-Term Debt
On August 19, 2010, the Company issued
$150 million
in principal amount of its
10%
Senior Notes due 2017. On July 3, 2013, the Company issued an additional
$200 million
in principal amount of its
10%
Senior Notes due 2017 (collectively, the "2017 Notes").
On
February 17, 2016
, the Company closed a private exchange offer (the "February Exchange") and consent solicitation (the "February Consent Solicitation") to certain eligible holders of its outstanding 2017 Notes. In satisfaction of the tender of
$214.4 million
in aggregate principal amount of the 2017 Notes, representing approximately
61%
of the then outstanding aggregate principal amount of 2017 Notes, the Company (i) paid approximately
$53.6 million
of cash, (ii) issued
$144.7 million
aggregate principal amount of its new
10%
Second Lien Senior Secured Notes due 2021 (the "2021 Notes") and (iii) issued approximately
1.1 million
shares of its common stock. Following the completion of the February Exchange,
$135.6 million
in aggregate principal amount of the 2017 Notes remained outstanding. The February Consent Solicitation eliminated or waived substantially all of the restrictive covenants contained in the indenture governing the 2017 Notes.
On
September 27, 2016
, the Company closed private exchange offers (the "September Exchange") and a consent solicitation (the "September Consent Solicitation") to certain eligible holders of its outstanding 2017 Notes and 2021 Notes. In satisfaction of the consideration of
$113.0 million
in aggregate principal amount of the 2017 Notes, representing approximately
83%
of the then outstanding aggregate principal amount of 2017 Notes, and
$130.5 million
in aggregate principal amount of the 2021 Notes, representing approximately
90%
of the then outstanding aggregate principal amount of 2021 Notes, the Company issued (i)
$243.5 million
in aggregate principal amount of its new 10% Second Lien Senior Secured PIK Notes due 2021 (the "2021 PIK Notes") and (ii) approximately
3.5 million
shares of its common stock. The Company also paid, in cash, accrued and unpaid interest on the 2017 Notes and 2021 Notes accepted in the September Exchange from the last applicable interest payment date to, but not including,
September 27, 2016
. Following the consummation of the September Exchange, there were
$22.7 million
in aggregate principal amount of the 2017 Notes outstanding and
$14.2 million
in aggregate principal amount of the 2021 Notes outstanding. The September Consent Solicitation amended certain provisions of the indenture governing the 2021 Notes and amended the registration rights agreement with respect to the 2021 Notes.
On
March 31, 2017
, the Company redeemed its remaining outstanding 2017 Notes at a redemption price of
100%
of the principal amount thereof, plus accrued interest to the redemption date, in the amount of
$22.8 million
. The redemption was funded by cash on hand and amounts borrowed under the Multidraw Term Loan Agreement described below.
Unless the Company exercises its payable in kind ("PIK") interest option, 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 may, at its option, for one or more of the first
three
interest payment dates of the 2021 PIK Notes, 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. The Company exercised this PIK option in connection with the interest payment due on February 15, 2017. As of
June 30, 2017
, 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, 2017
, 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, 2017
,
$0.6 million
of the shortfall remained as part of the carrying value of the 2021 PIK Notes and the Company recognized
$37 thousand
of amortization expense as an increase to interest expense during the six months ended
June 30, 2017
.
The Company previously determined that the future undiscounted cash flows from the 2021 Notes issued in the February Exchange through the maturity date exceeded the adjusted carrying amount of the 2017 Notes tendered in the February Exchange. Accordingly,
no
gain on extinguishment of debt was recognized in connection with the February Exchange. The excess of the remaining carrying value of the 2017 Notes tendered over the principal amount of the 2021 Notes issued in the February Exchange of
$13.9 million
was reflected as part of the carrying value of the 2021 Notes. The amount of the excess carrying value attributable to the 2021 Notes tendered in the September Exchange is now reflected as part of the carrying value of the 2021 PIK Notes. The excess carrying value attributable to the remaining 2021 Notes is being amortized under the effective interest method over the
term of the 2021 Notes. At
June 30, 2017
,
$1.0 million
of the excess remained as part of the carrying value of the 2021 Notes and the Company recognized
$0.1 million
of amortization expense as a reduction to interest expense during the six months ended
June 30, 2017
.
The issuance of the 2021 Notes, 2021 PIK Notes and shares of common stock, as well as the exchange of the 2017 Notes and 2021 Notes, in the February Exchange and September Exchange represent non-cash financing activities for purposes of the Statement of Cash Flows.
The indentures governing the 2021 PIK Notes and the 2021 Notes contain affirmative and negative covenants that, among other things, limit the ability of the Company and the subsidiary guarantors of the 2021 PIK Notes and the 2021 Notes to incur indebtedness; purchase or redeem stock; make certain investments; create liens that secure debt; enter into transactions with affiliates; sell assets; refinance certain indebtedness; merge with or into other companies or transfer substantially all of their assets; and, in certain circumstances, to pay dividends or make other distributions on stock. The 2021 PIK Notes and the 2021 Notes are fully and unconditionally guaranteed on a senior basis, jointly and severally, by certain wholly-owned subsidiaries of the Company.
The 2021 PIK Notes and the 2021 Notes are secured equally and ratably by second-priority liens on substantially all of the Company's and the subsidiary guarantors' oil and gas properties and substantially all of their other assets to the extent such properties and assets secure the Multidraw Term Loan Agreement (as defined below), except for certain excluded assets. Pursuant to the terms of an intercreditor agreement, the security interest in those properties and assets that secure the 2021 PIK Notes and the 2021 Notes and the guarantees are contractually subordinated to liens that secure the Multidraw Term Loan Agreement and certain other permitted indebtedness. Consequently, the 2021 PIK Notes and the 2021 Notes and the guarantees will be effectively subordinated to the Multidraw Term Loan Agreement and such other indebtedness to the extent of the value of such assets.
On
October 17, 2016
, the Company entered into the Multidraw Term Loan Agreement (the "Multidraw Term Loan Agreement") with Franklin Custodian Funds - Franklin Income Fund ("Franklin"), as a lender, and Wells Fargo Bank, National Association, as administrative agent, replacing the prior credit agreement with JPMorgan Chase Bank, N.A. The Multidraw Term Loan Agreement provides a multi-advance term loan facility, with borrowing availability for
three
years, in a principal amount of up to
$50 million
. The loans drawn under the Multidraw Term Loan Agreement (collectively, the “Term Loans”) may be used to repay existing debt, to pay transaction fees and expenses, to provide working capital for exploration and production operations and for general corporate purposes. The Term Loans mature on
October 17, 2020
. As of
June 30, 2017
, the Company had
$30.0 million
of borrowings outstanding under the Term Loans.
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 financial 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 June 30, 2017, and the last day of each calendar quarter thereafter (the "Coverage Ratio").
Sales of the Company’s and its subsidiaries’ oil and gas properties outside the ordinary course of business are limited under the terms of the Multidraw Term Loan Agreement. In addition, the Multidraw Term Loan Agreement prohibits the Company from declaring and paying dividends on its Series B Preferred Stock.
The Multidraw Term Loan Agreement also includes customary restrictions with respect to debt, liens, dividends, distributions and redemptions, investments, loans and advances, nature of business, international operations and foreign subsidiaries, leases, sale or discount of receivables, mergers or consolidations, sales of properties, transactions with affiliates, negative pledge agreements, gas imbalances and swap agreements. As of
June 30, 2017
, 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, including the Coverage Ratio.
The following table reconciles the face value of the 2017 Notes, 2021 Notes, 2021 PIK Notes and Term Loans to the carrying value included in the Company's Consolidated Balance Sheet as of
June 30, 2017
and
December 31, 2016
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2017
|
|
December 31, 2016
|
|
2017 Notes
|
2021 Notes
|
2021 PIK Notes
|
Term Loans
|
|
2017 Notes
|
2021 Notes
|
2021 PIK Notes
|
Term Loans
|
Face Value
|
$
|
—
|
|
$
|
14,177
|
|
$
|
251,868
|
|
$
|
30,000
|
|
|
$
|
22,650
|
|
$
|
14,177
|
|
$
|
243,468
|
|
$
|
10,000
|
|
Unamortized Deferred Financing Costs
|
—
|
|
(206
|
)
|
—
|
|
(2,395
|
)
|
|
(82
|
)
|
(108
|
)
|
—
|
|
(2,751
|
)
|
Excess (shortfall) Carrying Value
|
—
|
|
1,037
|
|
(553
|
)
|
—
|
|
|
—
|
|
1,159
|
|
(590
|
)
|
—
|
|
Accrued PIK Interest
|
—
|
|
—
|
|
8,501
|
|
—
|
|
|
—
|
|
—
|
|
5,722
|
|
—
|
|
Carrying Value
|
$
|
—
|
|
$
|
15,008
|
|
$
|
259,816
|
|
$
|
27,605
|
|
|
$
|
22,568
|
|
$
|
15,228
|
|
$
|
248,600
|
|
$
|
7,249
|
|
Note 6—Asset Retirement Obligation
The following table describes the changes to the Company’s asset retirement obligation liability (in thousands):
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30,
|
|
2017
|
|
2016
|
Asset retirement obligation, beginning of period
|
$
|
36,610
|
|
|
$
|
42,556
|
|
Liabilities incurred
|
574
|
|
|
—
|
|
Liabilities settled
|
(1,357
|
)
|
|
(2,574
|
)
|
Accretion expense
|
1,100
|
|
|
1,226
|
|
Revisions in estimates
|
(161
|
)
|
|
291
|
|
Divestiture of oil and gas properties
|
(248
|
)
|
|
(17
|
)
|
Asset retirement obligation, end of period
|
36,518
|
|
|
41,482
|
|
Less: current portion of asset retirement obligation
|
(2,759
|
)
|
|
(1,496
|
)
|
Long-term asset retirement obligation
|
$
|
33,759
|
|
|
$
|
39,986
|
|
Note 7—Ceiling Test
The Company uses the full cost method to account for its oil and gas properties. Accordingly, the costs to acquire, explore for and develop oil and gas properties are capitalized. Capitalized costs of oil and gas properties, net of accumulated DD&A and related deferred taxes, are limited to the estimated future net cash flows from estimated proved oil and gas reserves, including the effects of cash flow hedges in place, discounted at
10%
, plus the lower of cost or fair value of unevaluated properties, as adjusted for related income tax effects (the full cost ceiling). If capitalized costs exceed the full cost ceiling, the excess is charged to ceiling test write-down of oil and gas properties in the quarter in which the excess occurs.
In accordance with SEC requirements, the estimated future net cash flows from estimated proved reserves are based on an average of the first day of the month spot price for a historical 12-month period, adjusted for quality, transportation fees and market differentials. At
June 30, 2016
, the prices used in computing the estimated future net cash flows from the Company's estimated proved reserves, including the effect of hedges in place at that date, averaged
$2.15
per Mcf of natural gas,
$42.12
per barrel of oil and
$1.71
per Mcfe of Ngl. As a result of lower commodity prices and their negative impact on the Company's estimated proved reserves and estimated future net cash flows, the Company recognized ceiling test write-downs of approximately
$12.8 million
and
$31.6 million
, respectively, during the three and six month periods ended
June 30, 2016
. The Company's cash flow hedges in place at
June 30, 2016
decreased the ceiling test write-down by approximately
$0.2 million
.
No
such write-downs occurred during the three or six month periods ended
June 30, 2017
.
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, 2017
, the Company's derivative instruments were designated as effective cash flow hedges.
Oil and gas sales include additions related to the settlement of gas hedges of
$108,000
and
$1,155,000
for the
three months ended
June 30, 2017 and 2016
, respectively. Oil and gas sales include (reductions) additions related to the settlement of gas hedges of
($214,000)
and
$2,187,000
for the
six months ended
June 30, 2017 and 2016
, respectively.
As of
June 30, 2017
, the Company had entered into the following commodity derivative instruments:
|
|
|
|
|
|
|
Production Period
|
Instrument
Type
|
|
Daily Volumes
|
|
Weighted
Average Price
|
Natural Gas:
|
|
|
|
|
|
July - December 2017
|
Swap
|
|
30,000 Mmbtu
|
|
$3.22
|
October - December 2017
|
Swap
|
|
10,000 Mmbtu
|
|
$3.22
|
January - March 2018
|
Swap
|
|
35,000 Mmbtu
|
|
$3.24
|
At
June 30, 2017
, the Company had recognized accumulated other comprehensive income of approximately
$0.3 million
related to the estimated fair value of its effective cash flow hedges. Based on estimated future commodity prices as of
June 30, 2017
, the Company would reclassify approximately
$0.3 million
, net of taxes, of accumulated other comprehensive income into oil and gas sales during the next
twelve months
.
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, 2017
and
December 31, 2016
:
|
|
|
|
|
|
|
Commodity Derivatives
|
Period
|
Balance Sheet
Location
|
Fair Value
|
June 30, 2017
|
Derivative asset
|
$
|
966
|
|
June 30, 2017
|
Derivative liability
|
$
|
(457
|
)
|
December 31, 2016
|
Derivative liability
|
$
|
(3,947
|
)
|
December 31, 2016
|
Other long-term liabilities
|
$
|
(803
|
)
|
Effect of Cash Flow Hedges on the Consolidated Statements of Operations and Comprehensive Loss for the three months ended
June 30, 2017 and 2016
:
|
|
|
|
|
|
|
|
|
|
|
Instrument
|
Amount of Gain (Loss)
Recognized in Other
Comprehensive Income
|
|
Location of
Gain Reclassified
into Income
|
|
Amount of Gain Reclassified into
oil and gas sales
|
Commodity Derivatives at June 30, 2017
|
$
|
2,179
|
|
|
Oil and gas sales
|
|
$
|
108
|
|
Commodity Derivatives at June 30, 2016
|
$
|
(595
|
)
|
|
Oil and gas sales
|
|
$
|
1,155
|
|
Effect of Cash Flow Hedges on the Consolidated Statements of Operations and Comprehensive Loss for the six months ended
June 30, 2017 and 2016
:
|
|
|
|
|
|
|
|
|
|
|
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 at June 30, 2017
|
$
|
5,045
|
|
|
Oil and gas sales
|
|
$
|
(214
|
)
|
Commodity Derivatives at June 30, 2016
|
$
|
206
|
|
|
Oil and gas sales
|
|
$
|
2,187
|
|
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
June 30, 2017
and
December 31, 2016
were in the form of swaps based on NYMEX pricing for natural gas. The fair value of these derivatives are derived using an independent third-party’s valuation model that utilizes market-corroborated inputs that are observable over the term of the derivative contract. The Company’s fair value calculations also incorporate an estimate of the counterparties’ default risk for derivative assets and an estimate of the Company’s credit risk for derivative liabilities. As a result, the Company designates its commodity derivatives as Level 2 in the fair value hierarchy.
The following table summarizes the fair value of the Company’s derivatives subject to fair value measurement on a recurring basis as of
June 30, 2017
and
December 31, 2016
(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, 2017
|
$
|
—
|
|
|
$
|
509
|
|
|
$
|
—
|
|
December 31, 2016
|
$
|
—
|
|
|
$
|
(4,750
|
)
|
|
$
|
—
|
|
The fair value of the Company's cash and cash equivalents approximated book value at
June 30, 2017
and
December 31, 2016
. The fair value of the Term Loans approximated face value as of
June 30, 2017
and
December 31, 2016
. The fair value of the 2017 Notes, 2021 Notes and 2021 PIK Notes was determined based upon market quotes provided by an independent broker, which represents a Level 2 input. The following table summarizes the fair value, carrying value and face value of the 2017 Notes, 2021 Notes and 2021 PIK Notes as of
June 30, 2017
and
December 31, 2016
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2017
|
|
December 31, 2016
|
|
Fair Value
|
Face Value
|
Carrying Value
|
|
Fair Value
|
Face Value
|
Carrying Value
|
2017 Notes
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
|
$
|
21,970
|
|
$
|
22,650
|
|
22,568
|
|
2021 Notes
|
10,391
|
|
14,177
|
|
15,008
|
|
|
12,192
|
|
14,177
|
|
15,228
|
|
2021 PIK Notes
|
178,196
|
|
251,868
|
|
259,816
|
|
|
177,732
|
|
243,468
|
|
248,600
|
|
|
$
|
188,587
|
|
$
|
266,045
|
|
$
|
274,824
|
|
|
$
|
211,894
|
|
$
|
280,295
|
|
$
|
286,396
|
|
Note 10—Income Taxes
The Company typically provides for income taxes at a statutory rate of
35%
adjusted for permanent differences expected to be realized, primarily statutory depletion, non-deductible stock compensation expenses and state income taxes. As a result of ceiling test write-downs recognized, the Company has incurred a cumulative
three
year loss. Because of the impact the cumulative loss has on the determination of the recoverability of deferred tax assets through future earnings, the Company assessed the realizability of its deferred tax assets based on the future reversals of existing deferred tax liabilities. Accordingly, the Company established a valuation allowance for a portion of the deferred tax asset. The valuation allowance was
$182.1 million
and
$177.4 million
as of
June 30, 2017
and
December 31, 2016
, respectively.
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, 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 loss:
|
|
|
|
|
|
Oil and gas sales
|
(108
|
)
|
|
—
|
|
|
(108
|
)
|
Income tax effect
|
40
|
|
|
—
|
|
|
40
|
|
Net of tax
|
(68
|
)
|
|
—
|
|
|
(68
|
)
|
Net other comprehensive income
|
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
|
|
The following table represents the changes in accumulated other comprehensive income (loss), net of tax, for the three month period ended
June 30, 2016
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gains and Losses on Cash Flow Hedges
|
|
Change in Valuation Allowance
|
|
Total
|
Balance as of March 31, 2016
|
$
|
802
|
|
|
$
|
—
|
|
|
$
|
802
|
|
Other comprehensive income before reclassifications:
|
|
|
|
|
|
Change in fair value of derivatives
|
(595
|
)
|
|
—
|
|
|
(595
|
)
|
Income tax effect
|
221
|
|
|
(176
|
)
|
|
45
|
|
Net of tax
|
(374
|
)
|
|
(176
|
)
|
|
(550
|
)
|
Amounts reclassified from accumulated other comprehensive income:
|
|
|
|
|
|
Oil and gas sales
|
(1,155
|
)
|
|
—
|
|
|
(1,155
|
)
|
Income tax effect
|
430
|
|
|
—
|
|
|
430
|
|
Net of tax
|
(725
|
)
|
|
—
|
|
|
(725
|
)
|
Net other comprehensive loss
|
(1,099
|
)
|
|
(176
|
)
|
|
(1,275
|
)
|
Balance as of June 30, 2016
|
$
|
(297
|
)
|
|
$
|
(176
|
)
|
|
$
|
(473
|
)
|
The following table represents the changes in accumulated other comprehensive income (loss), net of tax, for the six month period ended
June 30, 2016
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gains and Losses on Cash Flow Hedges
|
|
Change in Valuation Allowance
|
|
Total
|
Balance as of December 31, 2015
|
$
|
947
|
|
|
$
|
—
|
|
|
$
|
947
|
|
Other comprehensive income before reclassifications:
|
|
|
|
|
|
Change in fair value of derivatives
|
206
|
|
|
—
|
|
|
206
|
|
Income tax effect
|
(77
|
)
|
|
(176
|
)
|
|
(253
|
)
|
Net of tax
|
129
|
|
|
(176
|
)
|
|
(47
|
)
|
Amounts reclassified from accumulated other comprehensive income:
|
|
|
|
|
|
Oil and gas sales
|
(2,187
|
)
|
|
—
|
|
|
(2,187
|
)
|
Income tax effect
|
814
|
|
|
—
|
|
|
814
|
|
Net of tax
|
(1,373
|
)
|
|
—
|
|
|
(1,373
|
)
|
Net other comprehensive loss
|
(1,244
|
)
|
|
(176
|
)
|
|
(1,420
|
)
|
Balance as of June 30, 2016
|
$
|
(297
|
)
|
|
$
|
(176
|
)
|
|
$
|
(473
|
)
|
Note 12 - Recently Issued Accounting Standards
In May 2014, the 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. We expect to apply the modified retrospective approach upon adoption of this standard. The Company is currently evaluating the effect that this new standard will have on its consolidated financial statements and related disclosures, however, the Company does not expect the adoption of the standard will have a material impact on its consolidated financial statements.
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 March 2016, the FASB issued ASU 2016-09, "Compensation - Stock Compensation (Topic 718)" to simplify several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and forfeitures, as well as classification in the statement of cash flows. ASU 2016-09 became effective on January 1, 2017. The standard did not have a material impact on the Company's consolidated financial statements.
Item 2.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Overview
PetroQuest Energy, Inc. is an independent oil and gas company incorporated in the State of Delaware with primary operations in Texas, Louisiana and the shallow waters of the Gulf of Mexico. We seek to grow our production, proved reserves, cash flow and earnings at low finding and development costs through a balanced mix of exploration, development and acquisition activities. From the commencement of our operations through 2002, we were focused exclusively in the Gulf Coast Basin with onshore properties principally in southern Louisiana and offshore properties in the shallow waters of the Gulf of Mexico shelf. During 2003, we began the implementation of our strategic goal of diversifying our reserves and production into longer life and lower risk onshore properties with our acquisition of the Carthage Field in East Texas. From 2005 through 2015, we were focused primarily in the Woodford Shale play in Oklahoma. We divested all of our acreage and producing wells in Oklahoma in three transactions that closed in June 2015, April 2016 and October 2016 (the "Oklahoma Divestitures"). See Note 2 - Acquisitions and Divestitures.
Our liquidity position has been negatively impacted by the prolonged decline in commodity prices that began in late 2014. In response, we executed the following actions aimed at preserving liquidity, reducing overall debt levels and extending debt maturities:
|
|
•
|
Completed the Oklahoma Divestitures for
$292.6 million
;
|
|
|
•
|
Reduced our 2016 capital expenditures by 75% as compared to 2015 spending of approximately $65 million;
|
|
|
•
|
Completed two debt exchanges to extend maturities on a significant portion of debt;
|
|
|
•
|
Reduced total debt
30%
from $425 million at December 31, 2014 to
$296 million
at
June 30, 2017
;
|
|
|
•
|
Entered into a new
$50 million
Multidraw Term Loan Agreement (as defined below) maturing in 2020, and
|
|
|
•
|
Secured a new drilling joint venture in East Texas facilitating the restart of drilling operations.
|
In addition to extending the maturity on approximately
$113 million
of debt due in 2017 to 2021, our September 2016 debt exchange permits us to reduce our cash interest expense on our 2021 PIK Notes (as defined below) from 10% cash to 1% cash and 9% payment-in-kind for the first three semi-annual interest payments, which is expected to provide us with more than $30 million of cash interest savings during 2017 and 2018. To enhance our liquidity and provide capital to address the remaining 2017 Notes (as defined below), in October 2016, we entered into a new
$50 million
Multidraw Term Loan Agreement maturing in 2020, replacing our prior bank credit facility which had no borrowing base on the date of termination. During March 2017, we utilized borrowings under this Multidraw Term Loan Agreement and cash on hand to redeem the remaining 2017 Notes.
We have a more favorable outlook on oil and gas prices for 2017 than what we experienced in 2016. Stated on an Mcfe basis, unit prices received during the three and six month periods ended
June 30, 2017
were
45%
and
60%
higher than the prices received during the respective 2016 periods. We recently recompleted our Thunder Bayou well in South Louisiana into a larger sand package and commenced the East Texas joint venture drilling program at the end of 2016 where we expect to drill and complete nine gross wells during 2017. As a result, we expect to grow production significantly during 2017 as compared to the fourth quarter of 2016. Our average daily production during the second quarter of 2017 increased
38%
over average daily production during the fourth quarter of 2016.
Critical Accounting Policies
Reserve Estimates
Our estimates of proved oil and gas reserves constitute those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. At the end of each year, our proved reserves are estimated by independent petroleum engineers in accordance with guidelines established by the SEC. These estimates, however, represent projections based on geologic and engineering data. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that are difficult to measure. The accuracy of any reserve estimate is a function of the quantity and quality of available data, engineering and geological interpretation and professional judgment. Estimates of economically recoverable oil and gas reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effect of regulations by governmental agencies, and assumptions governing future oil and gas prices, future operating costs, severance taxes,
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.
Future Abandonment Costs
Future abandonment costs include costs to dismantle and relocate or dispose of our production platforms, gathering systems, wells and related structures and restoration costs of land and seabed. We develop estimates of these costs for each of our properties based upon the type of production structure, depth of water, reservoir characteristics, depth of the reservoir, market demand for equipment, currently available procedures and consultations with construction and engineering consultants. Because these costs typically extend many years into the future, estimating these future costs is difficult and requires management to make estimates and judgments that are subject to future revisions based upon numerous factors, including changing technology, the timing of estimated costs, the impact of future inflation on current cost estimates and the political and regulatory environment.
Derivative Instruments
We seek to reduce our exposure to commodity price volatility by hedging a portion of our production through commodity derivative instruments. The estimated fair values of our commodity derivative instruments are recorded in the consolidated balance sheet. The changes in fair value of those derivative instruments that qualify for hedge accounting treatment are recorded in other comprehensive income (loss) until the hedged oil and natural gas quantities are produced. If a hedge becomes ineffective because the hedged production does not occur, or the hedge otherwise does not qualify for hedge accounting treatment, the changes in the fair value of the derivative are recorded in the income statement as derivative income (expense).
Our hedges are specifically referenced to NYMEX prices for natural gas. We evaluate the effectiveness of our hedges at the time we enter the contracts, and periodically over the life of the contracts, by analyzing the correlation between NYMEX prices and the posted prices we receive from our designated production. Through this analysis, we are able to determine if a high correlation exists between the prices received for the designated production and the NYMEX prices at which the hedges will be settled. At
June 30, 2017
, our derivative instruments were designated as effective cash flow hedges.
Estimating the fair value of derivative instruments requires valuation calculations incorporating estimates of future NYMEX prices, discount rates and price movements. As a result, we calculate the fair value of our commodity derivatives using an independent third-party’s valuation model that utilizes market-corroborated inputs that are observable over the term of the derivative contract. Our fair value calculations also incorporate an estimate of the counterparties’ default risk for derivative assets and an estimate of our credit risk for derivative liabilities.
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,
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
Production:
|
|
|
|
|
|
|
|
Oil (Bbls)
|
147,723
|
|
|
114,319
|
|
|
280,401
|
|
|
254,308
|
|
Gas (Mcf)
|
4,357,390
|
|
|
4,272,820
|
|
|
7,882,356
|
|
|
9,820,297
|
|
Ngl (Mcfe)
|
1,080,100
|
|
|
1,045,858
|
|
|
1,984,306
|
|
|
2,292,490
|
|
Total Production (Mcfe)
|
6,323,828
|
|
|
6,004,592
|
|
|
11,549,068
|
|
|
13,638,635
|
|
Sales:
|
|
|
|
|
|
|
|
Total oil sales
|
$
|
7,299,518
|
|
|
$
|
4,936,757
|
|
|
$
|
14,170,927
|
|
|
$
|
9,295,501
|
|
Total gas sales
|
13,750,945
|
|
|
8,853,527
|
|
|
24,413,287
|
|
|
19,571,735
|
|
Total ngl sales
|
3,200,165
|
|
|
2,034,342
|
|
|
6,438,711
|
|
|
4,277,104
|
|
Total oil, gas, and ngl sales
|
$
|
24,250,628
|
|
|
$
|
15,824,626
|
|
|
$
|
45,022,925
|
|
|
$
|
33,144,340
|
|
Average sales prices:
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
$
|
49.41
|
|
|
$
|
43.18
|
|
|
$
|
50.54
|
|
|
$
|
36.55
|
|
Gas (per Mcf)
|
3.16
|
|
|
2.07
|
|
|
3.10
|
|
|
1.99
|
|
Ngl (per Mcfe)
|
2.96
|
|
|
1.95
|
|
|
3.24
|
|
|
1.87
|
|
Per Mcfe
|
3.83
|
|
|
2.64
|
|
|
3.90
|
|
|
2.43
|
|
The above sales and average sales prices include increases to revenue related to the settlement of gas hedges of
$108,000
and
$1,155,000
for the
three months ended
June 30, 2017 and 2016
, respectively. The above sales and average sales prices include (decreases) increases to revenue related to the settlement of gas hedges of
($214,000)
and
$2,187,000
for the
six months ended
June 30, 2017 and 2016
, respectively. Please see Item 3. Quantitative and Qualitative Disclosures About Market Risk in this Form 10-Q for further details on our hedging program and our current hedging arrangements.
Net loss available to common stockholders totaled
$3,385,000
and
$24,143,000
for the three months ended
June 30, 2017 and 2016
, respectively, while net loss available to common stockholders totaled
$8,303,000
and
$63,280,000
for the
six months ended
June 30, 2017 and 2016
, respectively. The primary fluctuations were as follows:
Production
Total production
increased
5%
and
decreased
15%
during the
three and six
month periods ended
June 30, 2017
, respectively, as compared to the
2016
periods. The increased production in the three months ended June 30, 2017 as compared to the three months ended June 30, 2016 is primarily the result of the successful recompletion of our Thunder Bayou well and production from five new Cotton Valley wells in East Texas. The decrease in production for the six months ended
June 30, 2017
as compared to the six months ended June 30, 2016 was due primarily to the 2016 Oklahoma divestitures and normal production
declines at our Gulf of Mexico and East Texas fields as a result of the reduction in capital expenditures during 2016 partially offset by the above mentioned second quarter 2017 increases. As a result of the successful recompletion of Thunder Bayou and our ongoing drilling program in East Texas, we expect our total production for the remainder of
2017
to continue to increase as compared to the same period in
2016
. Our total average daily production during the second quarter of 2017 increased
38%
from total average daily production during the fourth quarter of 2016.
Gas production during the
three and six
month periods ended
June 30, 2017
increased
2%
and
decreased
20%
, respectively, from the comparable periods in
2016
. The decrease during the six months ended
June 30, 2017
was primarily the result of the 2016 Oklahoma divestitures and normal production declines at our Gulf Coast and East Texas fields. As a result of the successful recompletion of our Thunder Bayou well during the first quarter of 2017 and our ongoing drilling program in East Texas, we expect our average daily gas production to increase during the remainder of
2017
as compared to the same period in
2016
, however, production from certain of our Gulf of Mexico fields will be shut-in for a portion of the third quarter of 2017 due to third party pipeline repairs.
Oil production during the
three and six
month periods ended
June 30, 2017
increased
29%
and
10%
, respectively, from the comparable
2016
periods due primarily to the successful recompletion of our Thunder Bayou well and various other recompletions at our Gulf of Mexico properties during the second half of 2016. As a result of these successful recompletions, we expect our average daily oil production to continue to increase during the remainder of
2017
as compared to the
2016
periods.
Ngl production during the
three and six
month periods ended
June 30, 2017
increased
3%
and
decreased
13%
, respectively, from the comparable
2016
periods. The decrease during the six months ended
June 30, 2017
was primarily due to normal production declines at certain of our Gulf Coast and East Texas fields partially offset by increased production as a result of the successful recompletion of our Thunder Bayou well during the first quarter of 2017 and our drilling program in East Texas. We expect our average daily Ngl production to continue to increase during the remainder of
2017
as compared to the
2016
periods.
Prices
Including the effects of our hedges, average gas prices per Mcf for the
three and six
month periods ended
June 30, 2017
were
$3.16
and
$3.10
, respectively, as compared to
$2.07
and
$1.99
for the
2016
periods. Average oil prices per Bbl for the
three and six
months ended
June 30, 2017
were
$49.41
and
$50.54
, respectively, as compared to
$43.18
and
$36.55
for the
2016
periods and average Ngl prices per Mcfe for the
three and six
month periods ended
June 30, 2017
were
$2.96
and
$3.24
, respectively, as compared to
$1.95
and
$1.87
for the
2016
periods. Stated on an Mcfe basis, unit prices received during the
three and six
months ended
June 30, 2017
were
45%
and
60%
higher
than the prices received during the comparable
2016
periods.
Revenue
Including the effects of hedges, oil and gas sales during the
three months ended
June 30, 2017
increased
53%
to
$24,251,000
, as compared to oil and gas sales of
$15,824,000
during the
2016
period. Including the effects of hedges, oil and gas sales during the
six months ended
June 30, 2017
increased
36%
to
$45,023,000
, as compared to oil and gas sales of
$33,144,000
during the
2016
period. These increases were primarily the result of
higher
average realized prices for our production during
2017
.
Expenses
Lease operating expenses for the
three and six
months ended
June 30, 2017
totaled
$7,113,000
and
$14,189,000
, respectively, as compared to
$6,864,000
and
$15,041,000
during the
2016
periods. Per unit lease operating expenses totaled
$1.12
and
$1.23
per Mcfe, respectively, during the
three and six
month periods ended
June 30, 2017
as compared to
$1.14
and
$1.10
per Mcfe during the
2016
periods. Total lease operating expenses decreased during the six months ended
June 30, 2017
primarily as result of the 2016 Oklahoma divestitures, but increased on a per unit basis due to these wells having a much lower per unit rate compared to our Gulf of Mexico and East Texas wells. Lease operating expenses decreased overall at our Gulf Coast and East Texas fields as a result of certain cost saving measures initiated during 2016. Additionally, lease operating expenses decreased as a result of transportation deductions related to certain offshore Gulf of Mexico fields. These transportation deductions reduced lease operating expenses per Mcfe by $0.17 and $0.10, respectively, for the
three and six
months ended
June 30, 2017
. We expect total lease operating expenses to generally approximate
2016
expenses on an absolute value basis and to decrease on a per unit basis during the remainder of 2017.
Production taxes for the
three and six
months ended
June 30, 2017
totaled
$570,000
and
$878,000
, respectively, as compared to
($48,000)
and
$290,000
during the
2016
periods. Per unit production taxes totaled
$0.09
and
$0.08
per Mcfe, respectively, during the
three and six
month periods ended
June 30, 2017
as compared to
($0.01)
and
$0.02
per Mcfe during the comparable
2016
periods. Severance taxes for the majority of our properties that are subject to severance taxes are assessed on the value of oil and gas sales. As a result of the expected increases in production and expiration of the two-year severance tax exemption on our Thunder Bayou well in June 2017, we expect an increase in our total and per unit production taxes during the remainder of
2017
as compared to the same period in
2016
.
General and administrative expenses during the
three and six
months ended
June 30, 2017
totaled
$4,314,000
and
$7,467,000
, respectively, as compared to
$3,871,000
and
$12,470,000
during the respective
2016
periods. General and administrative expenses during the
six
months ended
June 30, 2016
included $4,808,000 of costs related to the issuance of the 2021 Notes (as defined below). ASC Topic 470-60 "Troubled Debt Restructurings by Debtors" requires financing costs related to a troubled debt transaction
to be expensed in the period incurred. Share-based compensation costs totaled
$402,000
and
$822,000
, respectively, during the
three and six
months ended
June 30, 2017
as compared to
$582,000
and
$1,095,000
during the respective
2016
periods. We capitalized
$2,010,000
and
$3,344,000
, respectively, of general and administrative expenses during the
three and six
month periods ended
June 30, 2017
compared to
$1,634,000
and
$3,188,000
, respectively, during the
2016
periods. Excluding the non-recurring debt restructuring fees incurred in 2016, we expect general and administrative expenses during the remainder of
2017
to be lower than
2016
due to an approximate 50% reduction in staff levels during 2016.
Depreciation, depletion and amortization (“DD&A”) expense on oil and gas properties for the
three and six
months ended
June 30, 2017
totaled
$6,746,000
, or
$1.07
per Mcfe, and
$12,761,000
, or
$1.10
per Mcfe, respectively, as compared to
$7,014,000
, or
$1.17
per Mcfe, and
$16,964,000
, or
$1.24
per Mcfe, during the comparable
2016
periods. The decreases in the per unit DD&A rate are primarily the result of recent ceiling test write-downs as well as the success of our East Texas drilling program. We expect our DD&A rate to approximate the second quarter rate during the remainder of
2017
.
At
June 30, 2016
, the prices used in computing the estimated future net cash flows from our estimated proved reserves, including the effect of hedges in place at that date, averaged
$2.15
per Mcf of natural gas,
$42.12
per barrel of oil and
$1.71
per Mcfe of Ngl. As a result of lower commodity prices and their negative impact on our estimated proved reserves and estimated future net cash flows, we recognized ceiling test write-downs of
$12,782,000
and
$31,639,000
, respectively, during the
three and six
months ended
June 30, 2016
. See Note 7, “Ceiling Test” for further discussion of the ceiling test write-downs. We recognized no such ceiling test write-downs during the
three and six
months ended
June 30, 2017
. Utilizing current strip prices for oil and gas prices for the third quarter of 2017 and projecting the effect on the estimated future net cash flows from our estimated proved reserves as of
June 30, 2017
, we do not expect to recognize a ceiling test write-down in the third quarter of 2017.
Interest expense, net of amounts capitalized on unevaluated properties, totaled
$7,147,000
and
$14,405,000
during the
three and six
months ended
June 30, 2017
, respectively, as compared to
$6,503,000
and
$14,760,000
, respectively, during the
2016
periods. During the
three and six
month periods ended
June 30, 2017
, our capitalized interest totaled
$403,000
and
$708,000
, respectively, as compared to
$247,000
and
$555,000
, respectively, during the
2016
periods. The decrease in interest expense during the six month 2017 period was the result of the February 2016 debt exchange in which the total amount of debt outstanding was reduced by approximately
$53.6 million
.
Income tax benefit during both of the
three and six
month periods ended
June 30, 2017
was
$189,000
as compared to an income tax expense of
$475,000
and
$561,000
during the respective
2016
periods. We typically provide for income taxes at a statutory rate of 35% adjusted for permanent differences expected to be realized, primarily statutory depletion, non-deductible stock compensation expenses and state income taxes.
As a result of ceiling test write-downs, we have incurred a cumulative three-year loss. Because of the impact the cumulative loss has on the determination of the recoverability of deferred tax assets through future earnings, we assessed the realizability of our deferred tax assets based on the future reversals of existing deferred tax liabilities. Accordingly, we established a valuation allowance for a portion of our deferred tax asset. The valuation allowance was
$182,088,000
as of
June 30, 2017
.
Liquidity and Capital Resources
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 the prolonged decline in commodity prices that began in late 2014. In response to lower commodity prices we executed a number of transactions aimed at preserving liquidity, reducing overall debt levels and extending debt maturities. Through these transactions, which included two debt exchanges, we have eliminated all debt maturing in 2017 and have reduced total debt
30%
from
$425 million
at December 31, 2014 to
$296 million
at
June 30, 2017
. In addition to extending the maturity on the majority of our debt that was due in 2017, our September 2016 debt exchange permits us to reduce our cash interest expense on our 2021 PIK Notes from 10% cash to 1% cash and 9% payment-in-kind for the first three semi-annual interest payments, which is expected to provide us with more than $30 million of cash interest savings during 2017 and 2018. Finally, in October 2016, we entered into a new
$50 million
Multidraw Term Loan Agreement maturing in 2020, replacing our prior bank credit facility. For additional information, see "Source of Capital: Debt" below.
At
June 30, 2017
, we had a working capital
deficit
of approximately $
18.9 million
as compared to a working capital
deficit
of approximately
$37.8 million
as of
December 31, 2016
. The increase in working capital is primarily due to the redemption on March 31, 2017 of our remaining 2017 Notes as discussed in "Source of Capital: Debt" below.
Our liquidity may be negatively impacted by federal bonding requirements related to our properties located on the Outer Continental Shelf (the "OCS"). To cover the various obligations of lessees on the OCS, the Bureau of Ocean Energy Management (the"BOEM") and the Bureau of Safety and Environmental Enforcement (the "BSEE") generally require that lessees have substantial net worth or post bonds or other acceptable assurances that such obligations will be satisfied. Because we are not exempt from the BOEM's supplemental bonding requirements, we engage surety companies to post the requisite bonds. Pursuant to the terms of our surety agreements, we may be required to post collateral at the surety companies' discretion. One of our surety companies requested collateral be posted to support certain of the bonds issued on our behalf and to date, we have provided cash deposits totaling
$7.3 million
to satisfy this request. The surety companies may request additional collateral which could have a material adverse effect on our liquidity position. If we fail to satisfy future requests for collateral, we may be in default under our agreements with the surety companies, which could cause a cross-default under the Multidraw Term Loan Agreement and potentially the indentures governing the 2021 Notes and 2021 PIK Notes. In addition, recently updated BOEM financial assurance and risk management requirements may increase the amount of surety bonds or other security required to be provided by us. For additional information, see "Item 1A Risk Factors - We may be required to post additional collateral to satisfy the collateral requirements related to the surety bonds that secure our offshore decommissioning obligations or to increase the amount of surety bonds or other security required pursuant to updated BOEM financial assurance and risk management requirements".
Source of Capital: Operations
Net cash flow provided by (used in) operations
increased
from $
(26.1) million
during the
six
months ended
June 30, 2016
to
$13.7 million
during the
2017
period. The
increase
in operating cash flow during
2017
as compared to
2016
is primarily attributable to increases in oil and gas revenues as well as the timing of payment of payables based on operational activity.
Source of Capital: Divestitures
We do not budget for property divestitures; however, we are continuously evaluating our property base to determine if there are assets in our portfolio that no longer meet our strategic objectives. From time to time we may divest certain assets in order to provide liquidity to strengthen our balance sheet or capital to be reinvested in higher rate of return projects. We are currently exploring divestment opportunities for certain of our assets. We cannot assure you that we will be able to sell any of our assets in the future.
In 2016, we sold our remaining assets in Oklahoma for approximately
$18.5 million
and in 2017 we sold our remaining interest in the East Lake Verret field in Louisiana for approximately
$2.2 million
.
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 100% of the principal amount thereof, plus accrued interest to the redemption date, in the amount of
$22.8 million
. The redemption was funded by cash on hand and $20 million borrowed under the Multidraw Term Loan Agreement described below.
Unless we exercise our payable in kind ("PIK") interest option, 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 may, at our option, for one or more of the first three interest payment dates of the 2021 PIK Notes, 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 payment due in February 15, 2017. 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
was reflected as part of the carrying value of the 2021 PIK Notes. Such shortfall will be amortized under the effective interest method as an addition of interest expense over the term of the 2021 PIK Notes. At
June 30, 2017
,
$0.6 million
of the shortfall remained as part of the carrying value of the 2021 PIK Notes and we recognized
$37 thousand
of amortization expense as an increase to interest expense during the
six
months ended
June 30, 2017
.
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, 2017
,
$1.0 million
of the excess remained as part of the carrying value of the 2021 Notes and the Company recognized
$0.1 million
of amortization expense as a reduction to interest expense during the
six
months ended
June 30, 2017
.
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 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 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 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, we entered into the Multidraw Term Loan Agreement (the “Multidraw Term Loan Agreement”) with Franklin Custodian Funds - Franklin Income Fund ("Franklin"), as a lender, and Wells Fargo Bank, National Association, as administrative agent, replacing the prior credit agreement with JPMorgan Chase Bank, N.A. The Multidraw Term Loan Agreement provides a multi-advance term loan facility, with borrowing availability for three years, in a principal amount of up to
$50 million
. The loans drawn under the Multidraw Term Loan Agreement (collectively, the “Term Loans”) may be used to repay existing debt, including the 2017 Notes, to pay transaction fees and expenses, to provide working capital for exploration and production operations and for general corporate purposes. The Term Loans mature on October 17, 2020. As of the date hereof, we had
$30 million
of borrowings outstanding under the Term Loans.
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 financial 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 June 30, 2017, and the last day of each calendar quarter thereafter (the "Coverage Ratio").
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. 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, including the Coverage Ratio.
The following table reconciles the face value of the 2017 Notes, 2021 Notes, 2021 PIK Notes and Term Loans to the carrying value included in our Consolidated Balance Sheet as of
June 30, 2017
and
December 31, 2016
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2017
|
|
December 31, 2016
|
|
2017 Notes
|
2021 Notes
|
2021 PIK Notes
|
Term Loans
|
|
2017 Notes
|
2021 Notes
|
2021 PIK Notes
|
Term Loans
|
Face Value
|
$
|
—
|
|
$
|
14,177
|
|
$
|
251,868
|
|
$
|
30,000
|
|
|
$
|
22,650
|
|
$
|
14,177
|
|
$
|
243,468
|
|
$
|
10,000
|
|
Unamortized Deferred Financing Costs
|
—
|
|
(206
|
)
|
—
|
|
(2,395
|
)
|
|
(82
|
)
|
(108
|
)
|
—
|
|
(2,751
|
)
|
Excess (shortfall) Carrying Value
|
—
|
|
1,037
|
|
(553
|
)
|
—
|
|
|
—
|
|
1,159
|
|
(590
|
)
|
—
|
|
Accrued PIK Interest
|
—
|
|
—
|
|
8,501
|
|
—
|
|
|
—
|
|
—
|
|
5,722
|
|
—
|
|
Carrying Value
|
$
|
—
|
|
$
|
15,008
|
|
$
|
259,816
|
|
$
|
27,605
|
|
|
$
|
22,568
|
|
$
|
15,228
|
|
$
|
248,600
|
|
$
|
7,249
|
|
Use of Capital: Exploration and Development
Our
2017
capital expenditure budget, which includes capitalized interest and general and administrative costs, is expected to range between
$40 million
and
$48 million
(which from the midpoint of such range, represents a 176% increase from our 2016 capital expenditures), of which
$27.2 million
was incurred during the first
six
months of
2017
. During the
six
months ended
June 30, 2017
, we funded our capital expenditures with cash on hand and cash flow from operations. We plan to fund our capital expenditures during the remainder of
2017
with cash flow from operations and cash on hand. To the extent additional capital is required, we may utilize borrowings under our Multidraw Term Loan Agreement, sales of equity securities or the sales of properties or assets or we may reduce our capital expenditures to manage our liquidity position.
Use of Capital: Acquisitions
We do not budget for acquisitions; however, we are continuously evaluating opportunities to expand our existing asset base or establish positions in new core areas.
We expect to finance our future acquisition activities, if consummated, through cash on hand. We may also utilize sales of equity securities, borrowings under our Multidraw Term Loan Agreement, sales of properties or assets or joint venture arrangements with industry partners, if necessary. We cannot assure you that such additional financings will be available on acceptable terms, if at all.
Disclosure Regarding Forward Looking Statements
This Quarterly Report on Form 10-Q contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements other than statements of historical facts included in and incorporated by reference into this Form 10-Q are forward looking statements. These forward-looking statements are subject to certain risks, trends and uncertainties that could cause actual results to differ materially from those projected.
Among those risks, trends and uncertainties are: the volatility of oil and natural gas prices and significantly depressed oil prices since the end of 2014; our indebtedness and the significant amount of cash required to service our indebtedness; our estimate of the sufficiency of our existing capital sources, including availability under the Multidraw Term Loan Agreement; our ability to post additional collateral to satisfy our offshore decommissioning obligations; our ability to execute our 2017 drilling and recompletion program as planned and to increase our production; our ability to hedge future production to reduce our exposure to price volatility in the current commodity pricing market; our ability to find, develop and produce oil and natural gas reserves that are economically recoverable and to replace reserves and sustain and/or increase production; ceiling test write-downs resulting, and that could result in the future, from lower oil and natural gas prices; our ability to raise additional capital to fund cash requirements for future operations; limits on our growth and our ability to finance our operations, fund our capital needs and respond to changing conditions imposed by the Multidraw Term Loan Agreement and restrictive debt covenants; more than 50% of our production being exposed to the additional risk of severe weather, including hurricanes, tropical storms and flooding, and natural disasters; losses and liabilities from uninsured or underinsured drilling and operating activities; changes in laws and governmental regulations as they relate to our operations; the operating hazards attendant to the oil and gas business; the volatility of our stock price; and our ability to meet the continued listing standards of the New York Stock Exchange with respect to our common stock or to cure any deficiency with respect thereto.
Although we believe that the expectations reflected in these forward-looking statements are reasonable, we cannot assure you that such expectations reflected in these forward looking statements will prove to have been correct.
When used in this Quarterly Report on Form 10-Q, the words “expect,” “anticipate,” “intend,” “plan,” “believe,” “seek,” “estimate” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain these identifying words. Because these forward-looking statements involve risks and uncertainties, actual results could differ materially from those expressed or implied by these forward-looking statements for a number of important reasons, including those discussed under “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Risk Factors” and elsewhere in this Quarterly Report on Form 10-Q.
You should read these statements carefully because they discuss our expectations about our future performance, contain projections of our future operating results or our future financial condition, or state other “forward-looking” information. You should be aware that the occurrence of any of the events described under “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Risk Factors” and elsewhere in this Quarterly Report on Form 10-Q could substantially harm our business, results of operations and financial condition and that upon the occurrence of any of these events, the trading price of our common stock could decline, and you could lose all or part of your investment.
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.