PETROQUEST ENERGY INC - FORM 10-Q - May 6, 2015

Attached files

file filename
EXCEL - IDEA: XBRL DOCUMENT - PETROQUEST ENERGY INCFinancial_Report.xls
EX-31.1 - EXHIBIT 31.1 - PETROQUEST ENERGY INCpq3311510qex311.htm
EX-32.2 - EXHIBIT 32.2 - PETROQUEST ENERGY INCpq3311510qex322.htm
EX-32.1 - EXHIBIT 32.1 - PETROQUEST ENERGY INCpq3311510qex321.htm
EX-31.2 - EXHIBIT 31.2 - PETROQUEST ENERGY INCpq3311510qex312.htm

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
FORM 10-Q
(Mark One)
x
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended: March 31, 2015
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from:                    to:                    
Commission file number: 001-32681
_________________________________________________________________
PETROQUEST ENERGY, INC.
(Exact name of registrant as specified in its charter)
––––––––––––––––––––––––––––––––––––––––––––––––––––––––––––––––––
DELAWARE
 
72-1440714
(State of Incorporation)
 
(I.R.S. Employer
Identification No.)
400 E. Kaliste Saloom Rd., Suite 6000
Lafayette, Louisiana
 
70508
(Address of principal executive offices)
 
(Zip code)
Registrant’s telephone number, including area code: (337) 232-7028
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  x    No  ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
 
Large accelerated filer
¨
Accelerated filer
x
Non-accelerated filer
¨
Smaller reporting company
¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  x
As of May 1, 2015 there were 65,850,916 shares of the registrant’s common stock, par value $.001 per share, outstanding.

 
 
 

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



PETROQUEST ENERGY, INC.
Consolidated Balance Sheets
(Amounts in Thousands)
 
March 31,
2015
 
December 31,
2014
 
(unaudited)
 
(Note 1)
ASSETS
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
14,209

 
$
18,243

Revenue receivable
13,691

 
16,485

Joint interest billing receivable
32,202

 
46,778

Derivative asset
11,121

 
8,631

Prepaid drilling costs
1,033

 
847

Other current assets
6,684

 
5,566

Total current assets
78,940

 
96,550

Property and equipment:
 
 
 
Oil and gas properties:
 
 
 
Oil and gas properties, full cost method
2,270,360

 
2,222,753

Unevaluated oil and gas properties
88,762

 
109,119

Accumulated depreciation, depletion and amortization
(1,777,246
)
 
(1,648,060
)
Oil and gas properties, net
581,876

 
683,812

Other property and equipment
15,033

 
14,953

Accumulated depreciation of other property and equipment
(10,649
)
 
(10,313
)
Total property and equipment
586,260

 
688,452

Derivative asset
192

 
—

Other assets, net of accumulated depreciation and amortization of $8,426 and $7,847, respectively
5,563

 
5,893

Total assets
$
670,955

 
$
790,895

LIABILITIES AND STOCKHOLDERS’ EQUITY
 
 
 
Current liabilities:
 
 
 
Accounts payable to vendors
$
88,057

 
$
102,954

Advances from co-owners
35,001

 
12,819

Oil and gas revenue payable
20,849

 
22,333

Accrued interest and preferred stock dividend
4,113

 
12,764

Asset retirement obligation
1,910

 
2,756

Derivative liability
138

 
—

Accrued acquisition costs
8,238

 
17,690

Other accrued liabilities
5,990

 
5,394

Total current liabilities
164,296

 
176,710

Bank debt
85,000

 
75,000

10% Senior Notes
350,000

 
350,000

Asset retirement obligation
53,448

 
52,214

Other long-term liability
447

 
62

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 64,815 and 64,721 shares, respectively
65

 
65

Paid-in capital
287,454

 
285,957

Accumulated other comprehensive income
7,018

 
5,420

Accumulated deficit
(276,774
)
 
(154,534
)
Total stockholders’ equity
17,764

 
136,909

Total liabilities and stockholders’ equity
$
670,955

 
$
790,895

See accompanying Notes to Consolidated Financial Statements.

1

PETROQUEST ENERGY, INC.
Consolidated Statements of Operations
(unaudited)
(Amounts in Thousands, Except Per Share Data)
 
    
 
Three Months Ended
 
March 31,
 
2015
 
2014
Revenues:
 
 
 
Oil and gas sales
$
33,451

 
$
59,966

Expenses:
 
 
 
Lease operating expenses
10,902

 
12,258

Production taxes
956

 
1,477

Depreciation, depletion and amortization
20,654

 
20,428

Ceiling test write-down
108,911

 
—

General and administrative
5,339

 
6,242

Accretion of asset retirement obligation
859

 
791

Interest expense
7,874

 
7,636

 
155,495

 
48,832

Other income:
 
 
 
Other income
157

 
189

Income (loss) from operations
(121,887
)
 
11,323

Income tax benefit
(927
)
 
—

Net income (loss)
(120,960
)
 
11,323

Preferred stock dividend
1,280

 
1,280

Income (loss) available to common stockholders
$
(122,240
)
 
$
10,043

Earnings per common share:
 
 
 
Basic
 
 
 
Net income (loss) per share
$
(1.89
)
 
$
0.15

Diluted
 
 
 
Net income (loss) per share
$
(1.89
)
 
$
0.15

Weighted average number of common shares:
 
 
 
Basic
64,774

 
63,846

Diluted
64,774

 
63,902

See accompanying Notes to Consolidated Financial Statements.

2

PETROQUEST ENERGY, INC.
Consolidated Statements of Comprehensive Income
(unaudited)
(Amounts in Thousands)
 
 
Three Months Ended
 
March 31,
 
2015
 
2014
Net income (loss)
$
(120,960
)
 
$
11,323

Change in fair value of derivative instruments, accounted for as hedges, net of income tax expense of $947 and $0, respectively
1,598

 
(3,418
)
Comprehensive income (loss)
$
(119,362
)
 
$
7,905

See accompanying Notes to Consolidated Financial Statements.


3

PETROQUEST ENERGY, INC.
Consolidated Statements of Cash Flows
(unaudited)
(Amounts in Thousands)
 
 
Three Months Ended
 
March 31,
 
2015
 
2014
Cash flows from operating activities:
 
 
 
Net income (loss)
$
(120,960
)
 
$
11,323

Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
 
Deferred tax benefit
(927
)
 
—

Depreciation, depletion and amortization
20,654

 
20,428

Ceiling test writedown
108,911

 
—

Accretion of asset retirement obligation
859

 
791

Share-based compensation expense
1,478

 
1,389

Amortization costs and other
591

 
557

Payments to settle asset retirement obligations
(894
)
 
(718
)
Changes in working capital accounts:
 
 
 
Revenue receivable
2,794

 
2,464

Prepaid drilling and pipe costs
(186
)
 
(43
)
Joint interest billing receivable
14,439

 
2,684

Accounts payable and accrued liabilities
(24,561
)
 
246

Advances from co-owners
22,182

 
6,033

Other
(1,149
)
 
135

Net cash provided by operating activities
23,231

 
45,289

Cash flows used in investing activities:
 
 
 
Investment in oil and gas properties
(36,033
)
 
(41,792
)
Investment in other property and equipment
(80
)
 
(205
)
Net cash used in investing activities
(36,113
)
 
(41,997
)
Cash flows provided by (used in) financing activities:
 
 
 
Net proceeds for share based compensation
405

 
911

Deferred financing costs
(273
)
 
(81
)
Payment of preferred stock dividend
(1,284
)
 
(1,284
)
Proceeds from bank borrowings
15,000

 
5,000

Repayment of bank borrowings
(5,000
)
 
(5,000
)
Net cash provided by (used in) financing activities
8,848

 
(454
)
Net increase (decrease) in cash and cash equivalents
(4,034
)
 
2,838

Cash and cash equivalents, beginning of period
18,243

 
9,153

Cash and cash equivalents, end of period
$
14,209

 
$
11,991

Supplemental disclosure of cash flow information:
 
 
 
Cash paid during the period for:
 
 
 
Interest
$
17,943

 
$
18,131

Income taxes
$
20

 
$
—

See accompanying Notes to Consolidated Financial Statements.

4

PETROQUEST ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
Note 1—Basis of Presentation
The consolidated financial information for the three month periods ended March 31, 2015 and 2014, has been prepared by the Company and was not audited by its independent registered public accountants. In the opinion of management, all normal and recurring adjustments have been made to present fairly the financial position, results of operations, and cash flows of the Company at March 31, 2015 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, 2014 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, 2014.
Unless the context otherwise indicates, any references in this Quarterly Report on Form 10-Q to “PetroQuest” or the “Company” refer to PetroQuest Energy, Inc. (Delaware) 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—Acquisition
In June 2014, the Company entered into a joint venture for an aggregate purchase price of $24 million. The assets acquired under the joint venture include an average 37% working interest in an approximately 30,000 acre leasehold position in Louisiana and exclusive rights, along with our joint venture partner, to a 200 square mile proprietary 3D survey which has generated several conventional and shallow non-conventional oil focused prospects.
The purchase price was comprised of $10 million in cash and $14 million in cash funding for future drilling, completion and lease acquisition costs. If the $14 million in drilling, completion and lease acquisition costs is not fully funded by December 31, 2015, any remaining balance becomes payable at the election of our joint venture partner. At March 31, 2015, $8.2 million of the cash funding for future drilling, completion and lease acquisition costs remained outstanding. The liability is reflected as accrued acquisition costs in the Consolidated Balance Sheet.
Note 3—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.
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 3.4433 shares of the Company’s common stock (which is based on an initial conversion price of approximately $14.52 per share of common stock, subject to 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

5

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 follows:
For the Three Months Ended March 31, 2015
Loss (Numerator)
 
Shares
(Denominator)
 
Per
Share Amount
BASIC EPS
 
 
 
 
 
Net loss available to common stockholders
$
(122,240
)
 
64,774

 
$
(1.89
)
  Stock options
—

 
—

 
 
  Attributable to participating securities
—

 
—

 
 
DILUTED EPS
$
(122,240
)
 
64,774

 
$
(1.89
)
 
 
 
 
 
 
For the Three Months Ended March 31, 2014
Income (Numerator)
 
Shares
(Denominator)
 
Per
Share Amount
Net income available to common stockholders
$
10,043

 
63,846

 
 
Attributable to participating securities
(289
)
 
—

 
 
BASIC EPS
$
9,754

 
63,846

 
$
0.15

 
 
 
 
 
 
Net income available to common stockholders
10,043

 
63,846

 
 
Effect of dilutive securities:
 
 
 
 
 
Stock options
—

 
56

 
 
Attributable to participating securities
(289
)
 
—

 
 
DILUTED EPS
$
9,754

 
63,902

 
$
0.15

An aggregate of 0.5 million shares of common stock representing unvested shares of restricted common stock and common shares issuable upon the assumed conversion of the Series B preferred stock totaling 5.1 million shares were not included in the computation of diluted earnings per share for the three month period ended March 31, 2015 because the inclusion would have been anti-dilutive as a result of the net loss reported for the period. Options to purchase 1.5 million of common stock were outstanding during the three month period ended March 31, 2015 and were not included in the computation of diluted earnings per share because the options' exercise prices were in excess of the average market price of the common shares.
Common shares issuable upon the assumed conversion of the Series B Preferred Stock totaling 5.1 million shares were not included in the computation of diluted earnings per share for the three month periods ended March 31, 2014 because the inclusion would have been anti-dilutive. Options to purchase 1.2 million shares of common stock were outstanding during the three month period ended March 31, 2014 and were not included in the computation of diluted earnings per share because the options' exercise prices were in excess of the average market price of the common shares.

Note 5—Long-Term Debt
On August 19, 2010, the Company issued $150 million in principal amount of its 10% Senior Notes due 2017 (the “Existing Notes”). On July 3, 2013, the Company issued an additional $200 million in principal amount of its 10% Senior Notes due 2017 (the "New Notes" and together with the Existing Notes, the "Notes").  The New Notes were issued at a price equal to 100% of face value plus accrued interest from March 1, 2013 and are substantially identical to the Existing Notes. The Notes are guaranteed by certain of PetroQuest's subsidiaries. The subsidiary guarantors are 100% owned by PetroQuest and all guarantees are full and unconditional and joint and several. PetroQuest has no independent assets or operations and the subsidiaries not providing guarantees are minor, as defined by the rules of the Securities and Exchange Commission.
The Notes have numerous covenants including restrictions on liens, incurrence of indebtedness, asset sales, dividend payments and other restricted payments. Interest is payable semi-annually on March 1 and September 1. At March 31, 2015, $2.9 million had been accrued in connection with the September 1, 2015 interest payment and the Company was in compliance with all of the covenants contained in the Notes.
The Company and PetroQuest Energy, L.L.C. (the “Borrower”) have a Credit Agreement (as amended, the “Credit Agreement”) with JPMorgan Chase Bank, N.A., Wells Fargo Bank, N.A., Capital One, N.A., IberiaBank, Bank of America, N.A. and The Bank of Nova Scotia. The Credit Agreement provides the Company with a $300 million revolving credit facility that

6

permits borrowings based on the commitments of the lenders and the available borrowing base as determined in accordance with the Credit Agreement. The Credit Agreement also allows the Company to use up to $25 million of the borrowing base for letters of credit. The credit facility matures on October 3, 2016. As of March 31, 2015, the Company had $85.0 million of borrowings outstanding under (and no letters of credit issued pursuant to) the Credit Agreement.
The borrowing base under the Credit Agreement is based upon the valuation of the reserves attributable to the Company’s oil and gas properties as of January 1 and July 1 of each year. In connection with the most recent redetermination, the borrowing base was revised to $190 million (subject to the aggregate commitments of the lenders then in effect) effective March 31, 2015. The aggregate commitments of the lenders is currently $170 million and can be increased to up to $300 million by either adding new lenders or increasing the commitments of existing lenders, subject to certain conditions. The next regularly scheduled borrowing base redetermination is scheduled to occur by September 30, 2015. However, the Company or the lenders may request two additional borrowing base re-determinations each year and the Company has requested an interim re-determination on or around July 1, 2015. Each time the borrowing base is to be re-determined, the administrative agent under the Credit Agreement will propose a new borrowing base as it deems appropriate in its sole discretion, which must be approved by all lenders if the borrowing base is to be increased, or by lenders holding two-thirds of the amounts outstanding under the Credit Agreement if the borrowing base remains the same or is reduced.
The Credit Agreement is secured by a first priority lien on substantially all of the assets of the Company and its subsidiaries, including a lien on all equipment and at least 80% of the aggregate total value of the Borrower’s oil and gas properties. Outstanding balances under the Credit Agreement bear interest at the alternate base rate (“ABR”) plus a margin (based on a sliding scale of 0.5% to 1.5% depending on total commitments) or the adjusted LIBO rate (“Eurodollar”) plus a margin (based on a sliding scale of 1.5% to 2.5% depending on total commitments). The alternate base rate is equal to the highest of (i) the JPMorgan Chase prime rate, (ii) the Federal Funds Effective Rate plus 0.5% or (iii) the adjusted LIBO rate plus 1%. For the purposes of the definition of alternative base rate only, the adjusted LIBO rate is equal to the rate at which dollar deposits of $5,000,000 with a one month maturity are offered by the principal London office of JPMorgan Chase Bank, N.A. in immediately available funds in the London interbank market. For all other purposes, the adjusted LIBO rate is equal to the rate at which Eurodollar deposits in the London interbank market for one, two, three or six months (as selected by the Company) are quoted, as adjusted for statutory reserve requirements for Eurocurrency liabilities. Outstanding letters of credit are charged a participation fee at a per annum rate equal to the margin applicable to Eurodollar loans, a fronting fee and customary administrative fees. In addition, the Company pays commitment fees based on a sliding scale of 0.375% to 0.5% depending on total commitments.
The Company and its subsidiaries are subject to certain restrictive financial covenants under the Credit Agreement, including a maximum ratio of total senior secured debt to EBITDAX, determined on a rolling four quarter basis of  2.25 to 1.0, a minimum ratio of EBITDAX to total cash interest expense, determined on a rolling four quarter basis, of 2.0 to 1.0 and a minimum ratio of consolidated current assets to consolidated current liabilities of 0.75 to 1.0 as of the last day of the fiscal quarters ending March 31, 2015 and June 30, 2015, and 1.0 to 1.0 as the last day of any fiscal quarter ending thereafter, all as defined in the Credit Agreement. The Credit Agreement also includes customary restrictions with respect to debt, liens, dividends, distributions and redemptions, investments, loans and advances, nature of business, international operations and foreign subsidiaries, leases, sale or discount of receivables, mergers or consolidations, sales of properties, transactions with affiliates, negative pledge agreements, gas imbalances and swap agreements. However, the Credit Agreement permits the Company to repurchase up to $10 million of the Company’s common stock during the term of the Credit Agreement, so long as after giving effect to such repurchase the Borrower’s Liquidity (as defined therein) is greater than 20% of the total commitments of the lenders at such time. As of March 31, 2015, the Company was in compliance with all such covenants contained in the Credit Agreement.



7

Note 6—Asset Retirement Obligation
The following table describes the changes to the Company’s asset retirement obligation liability (in thousands):
 
Three Months Ended March 31,
 
2015
 
2014
Asset retirement obligation, beginning of period
$
54,970

 
$
48,536

Liabilities incurred
380

 
—

Liabilities settled
(894
)
 
(718
)
Accretion expense
859

 
791

Revisions in estimated cash flows
43

 
561

Asset retirement obligation, end of period
55,358

 
49,170

Less: current portion of asset retirement obligation
(1,910
)
 
(3,390
)
Long-term asset retirement obligation
$
53,448

 
$
45,780


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 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 ceiling test write-down of oil and gas properties in the quarter in which the excess occurs.

In accordance with SEC requirements, the estimated future net cash flows from estimated proved reserves are based on an average of the first day of the month spot price for a historical 12-month period, adjusted for quality, transportation fees and market differentials. At March 31, 2015, the prices used in computing the estimated future net cash flows from the Company’s estimated proved reserves, including the effect of hedges in place at that date, averaged $3.31 per Mcf of natural gas, $81.33 per barrel of oil and $3.52 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 a ceiling test write-down of approximately $108.9 million during the three months ended March 31, 2015. The Company’s cash flow hedges in place at March 31, 2015 increased the ceiling test write-down by approximately $14 million.

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 statement of operations as derivative income (expense). At March 31, 2015, all of the Company's derivative instruments were designated as effective cash flow hedges.
Oil and gas sales included additions (reductions) related to the settlement of gas hedges of $2,324,000 and ($2,969,000), Ngl hedges of $21,000 and zero, and oil hedges of $27,000 and ($434,000) for the three months ended March 31, 2015 and 2014, respectively.    

8

As of March 31, 2015, the Company had entered into the following commodity derivative instruments:
Production Period
Instrument
Type
 
Daily Volumes
 
Weighted
Average Price
Natural Gas:

 
 
 
 
April 2015 - December 2015
Swap
 
55,000 Mmbtu
 
$3.43
July 2015 - June 2016
Swap
 
10,000 Mmbtu
 
$3.22
April 2015 - September 2015
Swap
 
5,000 Mmbtu
 
$2.89
Crude Oil:

 

 
 
April 2015 - December 2015
Swap (LLS)
 
500 Bbls
 
$56.68
Propane:
 
 
 
 
 
April 2015 - December 2015
Swap
 
250 Bbls
 
$25.62
LLS - Louisiana Light Sweet
At March 31, 2015, the Company had recognized accumulated other comprehensive income of approximately $7.0 million related to the estimated fair value of its effective cash flow hedges. Based on estimated future commodity prices as of March 31, 2015, the Company would reclassify approximately $6.9 million, net of taxes, of accumulated other comprehensive income into earnings during the next 12 months. These gains are expected to be reclassified to oil and gas sales based on the schedule of oil and gas volumes stipulated in the derivative contracts.
Derivatives designated as hedging instruments:
The following tables reflect the fair value of the Company’s effective cash flow hedges in the consolidated financial statements (in thousands):
Effect of Cash Flow Hedges on the Consolidated Balance Sheet at March 31, 2015 and December 31, 2014:    
 
Commodity Derivatives
Period
Balance Sheet
Location
Fair Value
March 31, 2015
Derivative asset, current
$
11,121

March 31, 2015
Derivative asset, long term
$
192

March 31, 2015
Derivative liability, current
$
(138
)
December 31, 2014
Derivative asset, current
$
8,631


Effect of Cash Flow Hedges on the Consolidated Statement of Operations for the three months ended March 31, 2015 and 2014:
Instrument
Amount of Income (Loss)
Recognized in Other
Comprehensive Income
 
Location of
Gain (Loss) Reclassified
into Income
 
Amount of Gain (Loss) Reclassified into
Income
Commodity Derivatives at March 31, 2015
$
4,917

 
Oil and gas sales
 
$
2,372

Commodity Derivatives at March 31, 2014
$
(6,821
)
 
Oil and gas sales
 
$
(3,403
)



9

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 March 31, 2015 were in the form of swaps based on NYMEX pricing for oil and natural gas and OPIS Mt. Belvieu pricing for natural gas liquids. The fair value of these derivatives is derived using an independent third-party’s valuation model that utilizes market-corroborated inputs that are observable over the term of the derivative contract. The Company’s fair value calculations also incorporate an estimate of the counterparties’ default risk for derivative assets and an estimate of the Company’s default risk for derivative liabilities. As a result, the Company designates its commodity derivatives as Level 2 in the fair value hierarchy.
The following table summarizes the net valuation of the Company’s derivatives subject to fair value measurement on a recurring basis as of March 31, 2015 and December 31, 2014 (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:
 
 
 
 
 
At March 31, 2015
$
—

 
$
11,175

 
$
—

At December 31, 2014
$
—

 
$
8,631

 
$
—

The fair value of the Company's cash and cash equivalents and variable-rate bank debt approximated book value at March 31, 2015 and December 31, 2014. The fair value of the Notes was approximately $296 million and $301 million as of March 31, 2015 and December 31, 2014, respectively, as compared to the book value of $350 million as of each date. The fair value of the Notes was determined based upon a market quote provided by an independent broker, which represents a Level 2 input.
Note 10—Income Taxes
The Company typically provides for income taxes at a statutory rate of 35% adjusted for permanent differences expected to be realized, primarily statutory depletion, non-deductible stock compensation expenses and state income taxes. As a result of ceiling test write-downs, 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 $77.7 million as of March 31, 2015.


10

Note 11 - Accumulated Other Comprehensive Income (Loss)

The following tables represent the changes in accumulated other comprehensive income (loss), net of tax, for the three-month periods ended March 31, 2015 and 2014 (in thousands):

 
Gains and Losses on Cash Flow Hedges
 
Change in Valuation Allowance
 
Total
Balance as of December 31, 2014
$
5,420

 
$
—

 
$
5,420

Other comprehensive income before reclassifications:
 
 
 
 
 
 Change in fair value of derivatives
4,917

 
—

 
4,917

 Income tax effect
(1,829
)
 
—

 
(1,829
)
 Net of tax
3,088

 
—

 
3,088

Amounts reclassified from accumulated other comprehensive income:
 
 
 
 
 
 Oil and gas sales
(2,372
)
 
—

 
(2,372
)
 Income tax effect
882

 
—

 
882

 Net of tax
(1,490
)
 
—

 
(1,490
)
Net other comprehensive income
1,598

 
—

 
1,598

Balance as of March 31, 2015
$
7,018

 
$
—

 
$
7,018


 
Gains and Losses on Cash Flow Hedges
 
Change in Valuation Allowance
 
Total
Balance as of December 31, 2013
$
(688
)
 
$
(408
)
 
$
(1,096
)
Other comprehensive loss before reclassifications:
 
 
 
 
 
 Change in fair value of derivatives
(6,821
)
 
—

 
(6,821
)
 Income tax effect
2,538

 
(2,538
)
 
—

 Net of tax
(4,283
)
 
(2,538
)
 
(6,821
)
Amounts reclassified from accumulated other comprehensive income (loss):
 
 
 
 
 
 Oil and gas sales
3,403

 
—

 
3,403

 Income tax effect
(1,266
)
 
1,266

 
—

 Net of tax
2,137

 
1,266

 
3,403

Net other comprehensive loss
(2,146
)
 
(1,272
)
 
(3,418
)
Balance as of March 31, 2014
$
(2,834
)
 
$
(1,680
)
 
$
(4,514
)

Note 12 - Recently Issued Accounting Standards

In April 2015, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update No. 2015-03, "Simplifying the Presentation of Debt Issuance Costs" ("ASU 2015-03") which changes the presentation of debt issuance costs in financial statements to present such costs as a direct deduction from the related debt liability rather than as an asset. ASU 2015-03 will become effective for public companies during interim and annual reporting periods beginning after December 15, 2015. Early adoption is permitted. We do not expect the adoption of ASU 2015-03 will have a material impact on our consolidated financial statements.


11

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 Oklahoma, East Texas, and the Gulf Coast Basin. 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 in 1985 through 2002, we were focused exclusively in the Gulf Coast Basin with onshore properties principally in southern Louisiana and offshore properties in the shallow waters of the Gulf of Mexico shelf. During 2003, we began the implementation of our strategic goal of diversifying our reserves and production into longer life and lower risk onshore properties. As part of the strategic shift to diversify our asset portfolio and lower our geographic and geologic risk profile, we refocused our opportunity selection processes to reduce our average working interest in higher risk projects, shift capital to higher probability of success onshore wells and mitigate the risks associated with individual wells by expanding our drilling program across multiple basins.
We have successfully diversified into onshore, longer life basins in Oklahoma and Texas through a combination of selective acquisitions and drilling activity. Beginning in 2003 with our acquisition of the Carthage Field in East Texas through 2014, we have invested a majority of our capital into growing our longer life assets. During the eleven year period ended December 31, 2014, we have realized a 94% drilling success rate on 976 gross wells drilled. Comparing 2014 metrics with those in 2003, the year we implemented our diversification strategy, we have grown production by 348% and estimated proved reserves by 377%. At March 31, 2015, 86% of our estimated proved reserves and 69% of our first quarter 2015 production were derived from our longer life assets.
During 2013, we closed on the acquisition of certain shallow water Gulf of Mexico shelf oil and gas properties which significantly enhanced our oil production. Utilizing the free cash flow provided by these acquired assets, we launched expanded drilling programs during 2014 in East Texas and the liquids rich portion of the Woodford Shale. The success of these two drilling programs, combined with a significant discovery at our Thunder Bayou prospect in the Gulf Coast Basin, were key components enabling us to achieve record annual production and record year end reserves during 2014.
In response to the impact that the decline in commodity prices has had, and is expected to continue to have, on our cash flow, our 2015 capital expenditures are significantly reduced as compared to 2014. To the extent our capital expenditures during 2015 exceed our cash flow from operations and cash on hand, we plan to utilize available borrowings under the bank credit facility. We also plan to maintain our commodity hedging program, and as in prior years, we may opportunistically dispose of certain assets to provide additional liquidity.

Fleetwood Joint Venture
In June 2014, we entered into a joint venture for an aggregate purchase price of $24 million. The assets acquired under the joint venture include an average 37% working interest in an approximately 30,000 acre leasehold position in Louisiana and exclusive rights, along with our joint venture partner, to a 200 square mile proprietary 3D survey which has generated several conventional and shallow non-conventional oil focused prospects.
The purchase price was comprised of $10 million in cash and $14 million in cash funding for future drilling, completion and lease acquisition costs. If the $14 million in drilling, completion and lease acquisition costs is not fully funded by December 31, 2015, any remaining balance becomes payable at the election of our joint venture partner. At March 31, 2015, $8.2 million of the cash funding for future drilling, completion and lease acquisition costs remained outstanding. The liability is reflected as accrued acquisition costs in the Consolidated Balance Sheet.
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

12

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 average price using beginning of the month pricing during the 12-month period prior to the ending date of the balance sheet to report oil and natural gas reserves. In addition, the 12-month average will also be used to measure ceiling test impairments and to compute depreciation, depletion and amortization.
Full Cost Method of Accounting
We use the full cost method of accounting for our investments in oil and gas properties. Under this method, all acquisition, exploration and development costs, including certain related employee costs, incurred for the purpose of exploring for and developing oil and natural gas are capitalized. Acquisition costs include costs incurred to purchase, lease or otherwise acquire property. Exploration costs include the costs of drilling exploratory wells, including those in progress and geological and geophysical service costs in exploration activities. Development costs include the costs of drilling development wells and costs of completions, platforms, facilities and pipelines. Costs associated with production and general corporate activities are expensed in the period incurred. Sales of oil and gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas.
The costs associated with unevaluated properties are not initially included in the amortization base and primarily relate to ongoing exploration activities, unevaluated leasehold acreage and delay rentals, seismic data and capitalized interest. These costs are either transferred to the amortization base with the costs of drilling the related well or are assessed quarterly for possible impairment or reduction in value.
We compute the provision for depletion of oil and gas properties using the unit-of-production method based upon production and estimates of proved reserve quantities. Unevaluated costs and related carrying costs are excluded from the amortization base until the properties associated with these costs are evaluated. In addition to costs associated with evaluated properties, the amortization base includes estimated future development costs related to non-producing reserves. Our depletion expense is affected by the estimates of future development costs, unevaluated costs and proved reserves, and changes in these estimates could have an impact on our future earnings.
We capitalize certain internal costs that are directly identified with acquisition, exploration and development activities. The capitalized internal costs include salaries, employee benefits, costs of consulting services and other related expenses and do not include costs related to production, general corporate overhead or similar activities. We also capitalize a portion of the interest costs incurred on our debt. Capitalized interest is calculated using the amount of our unevaluated property and our effective borrowing rate.
Capitalized costs of oil and gas properties, net of accumulated DD&A and related deferred taxes, are limited to the estimated future net cash flows from proved oil and gas reserves, including the effect of cash flow hedges in place, discounted at 10 percent, plus the lower of cost or fair value of unproved properties, as adjusted for related income tax effects (the full cost ceiling). If capitalized costs exceed the full cost ceiling, the excess is charged to write-down of oil and gas properties in the quarter in which the excess occurs.
Given the volatility of oil and gas prices, it is probable that our estimate of discounted future net cash flows from proved oil and gas reserves will change in the near term. If oil or gas prices remain at current levels or decline further, even for only a short period of time, or if we have downward revisions to our estimated proved reserves, it is possible that write-downs of oil and gas properties could occur in the future.

13

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 oil and natural gas and OPIS Mt. Belvieu pricing for natural gas liquids. 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 and OPIS Mt. Belvieu 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 and OPIS Mt. Belvieu prices at which the hedges will be settled. At March 31, 2015, 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 and OPIS Mt. Belvieu prices, discount rates and price movements. As a result, we calculate the fair value of our commodity derivatives using an independent third-party’s valuation model that utilizes market-corroborated inputs that are observable over the term of the derivative contract. Our fair value calculations also incorporate an estimate of the counterparties’ default risk for derivative assets and an estimate of our default risk for derivative liabilities.
Results of Operations
The following table sets forth certain information with respect to our oil and gas operations for the periods noted. These historical results are not necessarily indicative of results to be expected in future periods.
    
 
Three Months Ended March 31,
 
2015
 
2014
Production:
 
 
 
Oil (Bbls)
147,214

 
242,283

Gas (Mcf)
7,915,504

 
7,184,130

Ngl (Mcfe)
1,576,540

 
1,131,282

Total Production (Mcfe)
10,375,330

 
9,769,110

Sales:
 
 
 
Total oil sales
$
6,952,900

 
$
24,140,656

Total gas sales
21,650,095

 
29,557,335

Total ngl sales
4,848,046

 
6,268,406

Total oil and gas sales
$
33,451,041

 
$
59,966,397

Average sales prices:
 
 
 
Oil (per Bbl)
$
47.23

 
$
99.64

Gas (per Mcf)
2.74

 
4.11

Ngl (per Mcfe)
3.08

 
5.54

Per Mcfe
3.22

 
6.14

The above sales and average sales prices include increases (decreases) to revenue related to the settlement of gas hedges of $2,324,000 and ($2,969,000), Ngl hedges of $21,000 and zero and oil hedges of $27,000 and ($434,000) for the three months ended March 31, 2015 and 2014, respectively.

14

Net income (loss) available to common stockholders totaled ($122,240,000) and $10,043,000 for the quarters ended March 31, 2015 and 2014, respectively. The primary fluctuations were as follows:
Production Total production increased 6% during the three month period ended March 31, 2015 as compared to the 2014 period. The increase in total production was primarily the result of our successful drilling programs in our Carthage and Oklahoma fields, partially offset by a decrease in production due to normal production declines at our Gulf Coast fields. As a result of the current low commodity price environment and our plan to fund our 2015 drilling activities with cash flows from operations, our 2015 capital expenditures budget is significantly lower as compared to 2014. Despite the substantial decrease in capital spending, we expect our total production in 2015 to increase as compared to 2014 as a result of our continued drilling programs in our Oklahoma and Carthage fields, as well as anticipated initial production from our Thunder Bayou discovery in the second quarter of 2015.
Gas production during the three month period ended March 31, 2015 increased 10% from the comparable period in 2014. The increase in gas production was primarily due to the successful drilling programs in our Carthage and Oklahoma fields. Partially offsetting this increase was a decrease in gas production due to normal production declines at our Gulf Coast fields. As a result of continued drilling efforts in our Oklahoma and Carthage fields, as well as anticipated initial production from our Thunder Bayou discovery, we expect our average daily gas production to increase during 2015 as compared to 2014.
Oil production during the three month period ended March 31, 2015 decreased 39% from the 2014 period due primarily to normal production declines at our Gulf Coast fields, downtime at certain of our Gulf of Mexico properties and the divestment of our Eagle Ford properties in September 2014. As a result of normal production declines at certain of our legacy Gulf Coast fields, we expect our average daily oil production to decrease during  2015 as compared to 2014.
Ngl production during the three month period ended March 31, 2015 increased 39% from the 2014 period due to the successful drilling programs in our Carthage field and the liquids rich portion of our Oklahoma acreage position. Partially offsetting this increase was a decrease in Ngl production due to normal production declines at our Gulf Coast fields. As a result of the decrease in drilling activity planned for our liquids rich Oklahoma and Carthage acreage in 2015, as well as our expectation that we will not be recovering ethane volumes in Oklahoma due to the low ethane pricing environment, we expect our daily Ngl production for 2015 to decrease compared to that of 2014.
Prices Including the effects of our hedges, average gas prices per Mcf for the three month period ended March 31, 2015 were $2.74 as compared to $4.11 for the 2014 period. Average oil prices per Bbl for the three months ended March 31, 2015 were $47.23 as compared to $99.64 for the 2014 period and average Ngl prices per Mcfe were $3.08 for the three months ended March 31, 2015, as compared to $5.54 for the 2014 period. Stated on an Mcfe basis, unit prices received during the three months ended March 31, 2015 were 48% lower than the prices received during the comparable 2014 period.
Revenue Including the effects of hedges, oil and gas sales during the three months ended March 31, 2015 decreased 44% to $33,451,000, as compared to oil and gas sales of $59,966,000 during the 2014 period. The decreased revenue was primarily the result of lower average realized prices for our production during 2015.
Expenses Lease operating expenses for the three months ended March 31, 2015 totaled $10,902,000 as compared to $12,258,000 during the 2014 period. Per unit lease operating expenses totaled $1.05 per Mcfe during the three months ended March 31, 2015 as compared to $1.25 per Mcfe during the 2014 period. The decrease in total and per unit lease operating expenses is primarily the result of increased production from our onshore properties which typically incur lower per unit lease operating expenses as well as the divestment of our Eagle Ford properties. We expect lease operating expenses during 2015 to approximate 2014 expenses, both on an absolute and on a per unit basis.
Production taxes for the three months ended March 31, 2015 totaled $956,000, or $0.09 per Mcfe, as compared to $1,477,000, or $0.15 per Mcfe, during the 2014 period. The decrease was primarily due to lower commodity prices for our production during the first quarter of 2015 as compared to the 2014 period. 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 current commodity pricing environment, we expect a decrease in our total and per unit production taxes during 2015 as compared to 2014.
General and administrative expenses during the three months ended March 31, 2015 totaled $5,339,000 as compared to $6,242,000 during the 2014 period. The 14% decrease during the three months ended March 31, 2015 as compared to the comparable period of 2014 is primarily due to lower employee related costs including share-based compensation during the 2015 period. Included in first quarter 2015 and 2014 general and administrative expenses were share-based compensation costs of $1,519,000 and $1,762,000, respectively. We capitalized $2,240,000 of general and administrative costs during the three month period ended March 31, 2015 compared to $4,379,000 during the 2014 period. We expect general and administrative expenses in 2015 to decrease as compared to 2014.

15

Depreciation, depletion and amortization (“DD&A”) expense on oil and gas properties for the three months ended March 31, 2015 totaled $20,317,000, or $1.96 per Mcfe, as compared to $20,103,000, or $2.06 per Mcfe, during the comparable 2014 period. The decrease in the per unit DD&A rate is primarily the result of our successful drilling programs in our Carthage and Oklahoma fields, which have a lower cost per unit as compared to our overall amortization base. As a result of the current quarter ceiling test write-down, we expect our DD&A rate to be significantly lower than the 2015 first quarter rate for the remainder of 2015.
At March 31, 2015 and 2014, the prices used in computing the estimated future net cash flows from the Company’s estimated proved reserves, including the effect of hedges in place at that date, averaged $3.31 and $3.43 per Mcf of natural gas, $81.33 and $104.00 per barrel of oil and $3.52 and $4.78 per Mcfe of Ngl, respectively. As a result of lower commodity prices and their negative impact on our estimated proved reserves and estimated future net cash flows, we recognized a ceiling test write-down of approximately $108.9 million during the three months ended March 31, 2015.  See Note 7, “Ceiling Test” for further discussion of the ceiling test write-down. We expect that the current commodity price environment will likely result in additional ceiling test write-downs during 2015.
Interest expense, net of amounts capitalized on unevaluated properties, totaled $7,874,000 during the three months ended March 31, 2015 as compared to $7,636,000 during the comparable 2014 period. During the three month period ended March 31, 2015, our capitalized interest totaled $1,998,000 as compared to $2,167,000 during the comparable 2014 period. The increase in interest expense was a result of increased credit facility borrowings during the first quarter of 2015. As a result, we expect interest expense for 2015 to be higher than that of 2014.
Income tax benefit during the three months ended March 31, 2015 was $927,000 as compared to no income tax expense or benefit during the comparable 2014 period. 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 $77,662,000 as of March 31, 2015.
Liquidity and Capital Resources
We have financed our acquisition, exploration and development activities principally through cash flow from operations, bank borrowings, other credit facilities, issuances of equity and debt securities, joint ventures and sales of assets. At March 31, 2015 we had a working capital deficit of approximately $85.4 million as compared to a working capital deficit of approximately $80.2 million as of December 31, 2014. Since we operate the majority of our drilling activities, we have the ability to reduce our capital expenditures to manage our working capital deficit and liquidity position. In response to the impact that the decline in commodity prices has had, and is expected to continue to have, on our cash flow, our 2015 capital expenditures are significantly reduced as compared to 2014. During the three months ended March 31, 2015, we funded our capital expenditures with cash flow from operations, cash on hand, and bank borrowings. To the extent our capital expenditures during 2015 exceed our cash flow from operations and cash on hand, we plan to utilize available borrowings under our bank credit facility or proceeds from the potential sale of certain assets. To the extent additional capital is required, we may issue equity or debt securities or we may reduce our capital expenditures to manage our liquidity position.
Prices for oil and natural gas are subject to many factors beyond our control such as weather, the overall condition of the global financial markets and economies, relatively minor changes in the outlook of supply and demand, and the actions of OPEC. Oil and natural gas prices have a significant impact on our cash flows available for capital expenditures and our ability to borrow and raise additional capital. The amount we can borrow under our bank credit facility is subject to periodic re-determination based in part on changing expectations of future prices. Lower prices may also reduce the amount of oil and natural gas that we can economically produce. Lower prices and/or lower production may decrease revenues, cash flows and the borrowing base under the bank credit facility, thus reducing the amount of financial resources available to meet our capital requirements. Lower prices and reduced cash flow may also make it difficult to incur debt, including under our bank credit facility, because of the restrictive covenants in the indenture governing the Notes. See “Source of Capital: Debt” below. Our ability to comply with the covenants in our debt agreements is dependent upon the success of our exploration and development program and upon factors beyond our control, such as oil and natural gas prices.
Source of Capital: Operations
Net cash flow from operations decreased from $45.3 million during the three months ended March 31, 2014 to $23.2 million during the 2015 period. The decrease in operating cash flow during 2015 as compared to 2014 was primarily attributable to the decrease in oil and gas revenues.

16

Source of Capital: Debt
On August 19, 2010, we issued $150 million in principal amount of 10% Senior Notes due 2017 (the “Existing Notes”). On July 3, 2013, we issued an additional $200 million in principal amount of 10% Senior Notes due 2017 (the "New Notes" and together with the Existing Notes, the "Notes"). The New Notes were issued at a price equal to 100% of face value plus accrued interest from March 1, 2013 and are substantially identical to the Existing Notes. The net proceeds from the offering of the New Notes were used to finance the $188.8 million aggregate cash purchase price of the acquisition of certain shallow water Gulf of Mexico shelf oil and gas properties, which also closed on July 3, 2013.
The Notes have numerous covenants including restrictions on liens, incurrence of indebtedness, asset sales, dividend payments and other restricted payments. Interest is payable semi-annually on March 1 and September 1. At March 31, 2015, $2.9 million had been accrued in connection with the September 1, 2015 interest payment and we were in compliance with all of the covenants contained in the Notes.
We have a Credit Agreement (as amended, the “Credit Agreement”) with JPMorgan Chase Bank, N.A., Wells Fargo Bank, N.A., Capital One, N.A., IberiaBank, Bank of America, N.A. and The Bank of Nova Scotia. The Credit Agreement provides us with a $300 million revolving credit facility that permits borrowings based on the commitments of the lenders and the available borrowing base as determined in accordance with the Credit Agreement. The Credit Agreement also allows us to use up to $25 million of the borrowing base for letters of credit. Our bank credit facility matures on October 3, 2016. As of March 31, 2015, we had $85.0 million of borrowings outstanding under (and no letters of credit issued pursuant to) the Credit Agreement.
The borrowing base under the Credit Agreement is based upon the valuation of the reserves attributable to our oil and gas properties as of January 1 and July 1 of each year. In connection with the most recent redetermination, the borrowing base was revised to $190 million (subject to the aggregate commitments of the lenders then in effect) effective March 31, 2015. The aggregate commitments of the lenders is currently $170 million and can be increased to up to $300 million by either adding new lenders or increasing the commitments of existing lenders, subject to certain conditions. The next regularly scheduled borrowing base redetermination is scheduled to occur by September 30, 2015. However, we or the lenders may request two additional borrowing base re-determinations each year and we have requested an interim re-determination on or around July 1, 2015. Each time the borrowing base is to be re-determined, the administrative agent under the Credit Agreement will propose a new borrowing base as it deems appropriate in its sole discretion, which must be approved by all lenders if the borrowing base is to be increased, or by lenders holding two-thirds of the amounts outstanding under the Credit Agreement if the borrowing base remains the same or is reduced.
The Credit Agreement is secured by a first priority lien on substantially all of our assets, including a lien on all equipment and at least 80% of the aggregate total value of our oil and gas properties. Outstanding balances under the Credit Agreement bear interest at the alternate base rate (“ABR”) plus a margin (based on a sliding scale of 0.5% to 1.5% depending on total commitments) or the adjusted LIBO rate (“Eurodollar”) plus a margin (based on a sliding scale of 1.5% to 2.5% depending on total commitments). The alternate base rate is equal to the highest of (i) the JPMorgan Chase prime rate, (ii) the Federal Funds Effective Rate plus 0.5% or (iii) the adjusted LIBO rate plus 1%. For the purposes of the definition of alternative base rate only, the adjusted LIBO rate is equal to the rate at which dollar deposits of $5,000,000 with a one month maturity are offered by the principal London office of JPMorgan Chase Bank, N.A. in immediately available funds in the London interbank market. For all other purposes, the adjusted LIBO rate is equal to the rate at which Eurodollar deposits in the London interbank market for one, two, three or six months (as selected by us) are quoted, as adjusted for statutory reserve requirements for Eurocurrency liabilities. Outstanding letters of credit are charged a participation fee at a per annum rate equal to the margin applicable to Eurodollar loans, a fronting fee and customary administrative fees. In addition, we pay commitment fees based on a sliding scale of 0.375% to 0.5% depending on total commitments.
The Company and its subsidiaries are subject to certain restrictive financial covenants under the Credit Agreement, including a maximum ratio of total senior secured debt to EBITDAX, determined on a rolling four quarter basis of 2.25 to 1.0, a minimum ratio of EBITDAX to total cash interest expense, determined on a rolling four quarter basis, of 2.0 to 1.0 and a minimum ratio of consolidated current assets to consolidated current liabilities of 0.75 to 1.0 as of the last day of the fiscal quarters ending March 31, 2015 and June 30, 2015, and 1.0 to 1.0 as of the last day of any fiscal quarter ending thereafter, all as defined in the Credit Agreement. The Credit Agreement also includes customary restrictions with respect to debt, liens, dividends, distributions and redemptions, investments, loans and advances, nature of business, international operations and foreign subsidiaries, leases, sale or discount of receivables, mergers or consolidations, sales of properties, transactions with affiliates, negative pledge agreements, gas imbalances and swap agreements. However, the Credit Agreement permits the Company to repurchase up to $10 million of the Company’s common stock during the term of the Credit Agreement, so long as after giving effect to such repurchase the Borrower’s Liquidity (as defined therein) is greater than 20% of the total commitments of the lenders at such time. As of March 31, 2015, the Company was in compliance with all such covenants contained in the Credit Agreement.

17

Source of Capital: Divestitures
We do not budget 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 provide 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 September 2014, we sold our Eagle Ford assets for net proceeds of approximately $9.8 million.
Source of Capital: Issuance of Securities
Our shelf registration statement allows us to publicly offer and sell up to $350 million of any combination of debt securities, shares of common and preferred stock, depositary shares and warrants. The registration statement does not provide any assurance that we will or could sell any such securities.
Source of Capital: Joint Ventures
In May 2010, we entered into a joint development agreement with WSGP Gas Producing, LLC (WSGP), a subsidiary of NextEra Energy Resources, LLC, whereby WSGP acquired approximately 29 Bcfe of our Woodford proved undeveloped reserves as well as the right to earn 50% of our undeveloped Woodford acreage position through a two phase drilling program. We received approximately $57.4 million in cash at closing and an additional $14 million in each of 2011 and 2012. In addition, since May 2010, WSGP has funded a share of our drilling costs under a drilling program, which we refer to as the drilling carry. As of March 31, 2015, approximately $18.4 million of drilling carry remained available.
Use of Capital: Exploration and Development
Our 2015 capital budget, which includes capitalized interest and general and administrative costs, is expected to range between $60 million and $70 million, of which $27.3 million was incurred during the first three months of 2015. Because we operate the majority of our drilling activities, we expect to be able to control the timing of a substantial portion of our capital investments. During the three months ended March 31, 2015, we funded our capital expenditures with cash flow from operations, cash on hand, bank borrowings and an increase in our working capital deficit. To the extent our capital expenditures during 2015 exceed our cash flow from operations and cash on hand, we plan to utilize available borrowings under the bank credit facility or proceeds from the potential sale of certain assets. To the extent additional capital is required, we may utilize sales of equity or debt securities or we may reduce our capital expenditures to manage our liquidity position.
Use of Capital: Acquisitions
We do not budget 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 or available borrowings under our bank credit facility. We may also utilize sales of equity or debt securities, sales of properties or assets or joint venture arrangements with industry partners, if necessary. We cannot assure you that such additional financings will be available on acceptable terms, if at all.
Disclosure Regarding Forward Looking Statements
This 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 estimate of the sufficiency of our existing capital sources, including availability under our senior secured bank credit facility and the result of any borrowing base redetermination, our ability to raise additional capital to fund cash requirements for future operations, the effects of a financial downturn or negative credit market conditions on our liquidity, business and financial condition, the declines in the values of our properties that have resulted in and may in the future result in additional ceiling test write-downs, our ability to replace reserves and sustain production, our ability to find oil and natural gas reserves that are economically recoverable, the uncertainties involved in prospect development and property acquisitions or dispositions and in projecting future rates of production or future reserves, our ability to realize the anticipated benefits from our joint ventures, the timing of development expenditures and drilling of wells, hurricanes, tropical storms and other natural disasters, changes in laws and regulations as they relate to our operations, including our fracking operations or our operations in the Gulf of Mexico, and the operating hazards attendant to the oil and gas business.

18

In particular, careful consideration should be given to cautionary statements made in the various reports the Company has filed with the Securities and Exchange Commission. The Company undertakes no duty to update or revise these forward-looking statements.
When used in this 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” and elsewhere in this Form 10-Q.
Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We experience market risks primarily in two areas: commodity prices and interest rates. Because our properties are located within the United States, we do not believe that our business operations are exposed to significant foreign currency exchange risks.
Our revenues are derived from the sale of our crude oil, natural gas and natural gas liquids production. Based on projected sales volumes for the remainder of 2015, a 10% change in the prices we receive for our crude oil, natural gas and natural gas liquids production would have an approximate $3.9 million impact on our revenues.
We seek to reduce our exposure to commodity price volatility by hedging a portion of production through commodity derivative instruments. In the settlement of a typical hedge transaction, we will have the right to receive from the counterparties to the hedge the excess of the fixed price specified in the hedge over a floating price based on a market index multiplied by the quantity hedged. If the floating price exceeds the fixed price, we are required to pay the counterparties this difference multiplied by the quantity hedged. During the three months ended March 31, 2015, we received $2.4 million from the counterparties to our derivative instruments in connection with net hedge settlements.
We are required to pay the difference between the floating price and the fixed price (when the floating price exceeds the fixed price) regardless of whether we have sufficient production to cover the quantities specified in the hedge. Significant reductions in production at times when the floating price exceeds the fixed price could require us to make payments under the hedge agreements even though such payments are not offset by sales of production. Hedging will also prevent us from receiving the full advantage of increases in oil or gas prices above the fixed amount specified in the hedge.
Our Credit Agreement requires that the counterparties to our hedge contracts be lenders under the Credit Agreement or, if not a lender under the Credit Agreement, rated A/A2 or higher by S&P or Moody’s. Currently, the counterparties to our existing hedge contracts are lenders under the Credit Agreement. To the extent we enter into additional hedge contracts, we would expect that certain of the lenders under the Credit Agreement would serve as counterparties.

As of March 31, 2015, we had entered into the following commodity derivative instruments:
Production Period
Instrument
Type
Daily Volumes
Weighted
Average Price
Natural Gas:
 
 
 
April 2015 - December 2015
Swap
55,000 Mmbtu
$3.43
July 2015 - June 2016
Swap
10,000 Mmbtu
$3.22
April 2015 - September 2015
Swap
5,000 Mmbtu
$2.89
Crude Oil:
 
 
 
April 2015 - December 2015
Swap (LLS)
500 Bbls
$56.68
Propane:
 
 
 
April 2015 - December 2015
Swap
250 Bbls
$25.62
LLS - Louisiana Light Sweet
At March 31, 2015, we had accumulated other comprehensive income of approximately $7.0 million related to the estimated to the estimated fair value of our effective cash flow hedges. Based on estimated future commodity prices as of March 31, 2015, we would reclassify approximately $6.9 million, net of taxes, during the next 12 months. This gain is expected to be reclassified based on the schedule of oil and gas volumes stipulated in the derivative contracts.

19

As of March 31, 2015, the Company has approximately 17.9 Bcf of gas volumes, at an average price of $3.38 per Mcf, 68,750 barrels of propane volumes at an average price of $25.62 per barrel and 137,500 barrels of oil volumes at $56.68 per barrel hedged for the remainder of 2015.
Debt outstanding under our bank credit facility is subject to a floating interest rate and represents 20% of our total debt as of March 31, 2015. Based upon an analysis utilizing the actual interest rate in effect and balances outstanding as of March 31, 2015, and assuming a 10% increase in interest rates and no change in the amount of debt outstanding, the potential effect on interest expense for 2015 is $0.1 million.
Item 4. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
As of the end of the period covered by this report, the Company’s management, including its Chief Executive Officer and Chief Financial Officer, completed an evaluation of the effectiveness of the Company’s disclosure controls and procedures pursuant to Rule 13a-15 of the Securities and Exchange Act of 1934, as amended (the “Exchange Act”). Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded:
i.
that the Company’s disclosure controls and procedures are designed to ensure (a) that information required to be disclosed by the Company in the reports it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms, and (b) that such information is accumulated and communicated to the Company’s management, including the Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure; and
ii.
that the Company's disclosure controls and procedures are effective.
Notwithstanding the foregoing, there can be no assurance that the Company’s disclosure controls and procedures will detect or uncover all failures of persons within the Company and its consolidated subsidiaries to disclose material information otherwise required to be set forth in the Company’s periodic reports. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures.
Changes in Internal Control Over Financial Reporting
There have been no changes in the Company’s internal control over financial reporting during the period covered by this report that have materially affected, or that are reasonably likely to materially affect, the Company’s internal control over financial reporting.
Part II
Item 1. LEGAL PROCEEDINGS
NONE.

Item 1A. RISK FACTORS

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

Our future financial condition, revenues, results of operations, profitability and future growth, and the carrying value of our oil and natural gas properties depend primarily on the prices we receive for our oil and natural gas production. Our ability to maintain or increase our borrowing capacity and to obtain additional capital on attractive terms also substantially depends upon oil and natural gas prices. Historically, the markets for oil and natural gas have been volatile and oil prices have been significantly depressed since the end of 2014. For example, for the five years ended December 31, 2014, the NYMEX-WTI oil price ranged from a high of $113.93 per Bbl to a low of $53.27 per Bbl, while the NYMEX-Henry Hub natural gas price ranged from a high of $6.15 per MMBtu to a low of $1.91 per MMBtu. These markets will likely continue to be volatile in the future. The prices we will receive for our production, and the levels of our production, will depend on numerous factors beyond our control.
These factors include:
•
relatively minor changes in the supply of or the demand for oil and natural gas;

20

•
the condition of the United States and worldwide economies;
•
market uncertainty;
•
the level of consumer product demand;
•
weather conditions in the United States, such as hurricanes;
•
the actions of the Organization of Petroleum Exporting Countries;
•
domestic and foreign governmental regulation and taxes, including price controls adopted by the Federal Energy Regulatory Commission;
•
political conditions or hostilities in oil and natural gas producing regions, including the Middle East and South America;
•
the price and level of foreign imports of oil and natural gas; and
•
the price and availability of alternate fuel sources.
We cannot predict future oil and natural gas prices and such prices may decline further. An extended decline in oil and natural gas prices may adversely affect our financial condition, liquidity, ability to meet our financial obligations and results of operations. Lower prices have reduced and may further reduce the amount of oil and natural gas that we can produce economically and has required and may require us to record additional ceiling test write-downs and may cause our estimated proved reserves at December 31, 2015 to decline compared to our estimated proved reserves at December 31, 2014. Substantially all of our oil and natural gas sales are made in the spot market or pursuant to contracts based on spot market prices. Our sales are not made pursuant to long-term fixed price contracts.
To attempt to reduce our price risk, we periodically enter into hedging transactions with respect to a portion of our expected future production. We cannot assure you that such transactions will reduce the risk or minimize the effect of any decline in oil or natural gas prices. Any substantial or extended decline in the prices of or demand for oil or natural gas would have a material adverse effect on our financial condition, liquidity, ability to meet our financial obligations and results of operations.
Our outstanding indebtedness may adversely affect our cash flow and our ability to operate our business, remain in compliance with debt covenants and make payments on our debt.
As of March 31, 2015, the aggregate amount of our outstanding indebtedness, net of cash on hand, was $420.8 million. Based upon the current commitment level of our bank group, we have $85.0 million of additional availability under our bank credit facility, subject, however, to limitations on incurrence of indebtedness under the indenture governing our 10% senior notes due 2017, which we refer to as our 10% notes. In addition, we may also incur additional indebtedness in the future. Specifically, our high level of debt could have important consequences for you, including the following:
•
it may be more difficult for us to satisfy our obligations with respect to our outstanding indebtedness, including our 10% notes, and any failure to comply with the obligations of any of our debt agreements, including financial and other restrictive covenants, could result in an event of default under the agreements governing such indebtedness;
•
the covenants contained in our debt agreements limit our ability to borrow money in the future for acquisitions, capital expenditures or to meet our operating expenses or other general corporate obligations and may limit our flexibility in operating our business;
•
we will need to use a substantial portion of our cash flows to pay interest on our debt, approximately $35 million per year for interest on our 10% notes alone, and to pay quarterly dividends, if declared by our Board of Directors, on our Series B Preferred Stock of approximately $5.1 million per year, which will reduce the amount of money we have for operations, capital expenditures, expansion, acquisitions or general corporate or other business activities;
•
the amount of our interest expense may increase because certain of our borrowings in the future may be at variable rates of interest, which, if interest rates increase, could result in higher interest expense;
•
we may have a higher level of debt than some of our competitors, which may put us at a competitive disadvantage;
•
we may be more vulnerable to economic downturns and adverse developments in our industry or the economy in general, especially extended or further declines in oil and natural gas prices; and

21

•
our debt level could limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate.
Our ability to meet our expenses and debt obligations will depend on our future performance, which will be affected by financial, business, economic, regulatory and other factors. We will not be able to control many of these factors, such as economic conditions and governmental regulation. We cannot be certain that our cash flow from operations will be sufficient to allow us to pay the principal and interest on our debt, including our 10% notes, and meet our other obligations. If we do not have enough cash to service our debt, we may be required to refinance all or part of our existing debt, including our 10% notes, sell assets, borrow more money or raise equity. We may not be able to refinance our debt, sell assets, borrow more money or raise equity on terms acceptable to us, if at all.
Lower oil and natural gas prices may cause us to record ceiling test write-downs, which could negatively impact our results of operations.
We use the full cost method of accounting to account for our oil and natural gas operations. Accordingly, we capitalize the cost to acquire, explore for and develop oil and natural gas properties. Under full cost accounting rules, the net capitalized costs of oil and natural gas properties may not exceed a “full cost ceiling” which is based upon the present value of estimated future net cash flows from proved reserves, including the effect of hedges in place, discounted at 10%, plus the lower of cost or fair market value of unevaluated properties. If at the end of any fiscal period we determine that the net capitalized costs of oil and natural gas properties exceed the full cost ceiling, we must charge the amount of the excess to earnings in the period then ended. This is called a “ceiling test write-down.” This charge does not impact cash flow from operating activities, but does reduce our net income and stockholders' equity. Once incurred, a write-down of oil and natural gas properties is not reversible at a later date.
We review the net capitalized costs of our properties quarterly, using a single price based on the beginning of the month average of oil and natural gas prices for the prior 12 months. We also assess investments in unevaluated properties periodically to determine whether impairment has occurred. The risk that we will be required to recognize further write-downs of the carrying value of our oil and gas properties increases when oil and natural gas prices are low or volatile. In addition, write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves or our unevaluated property values, or if estimated future development costs increase. As a result of the decline in commodity prices, we recognized a ceiling test write-down totaling $108.9 million during the quarter ended March 31, 2015. We expect that the current commodity price environment will likely result in additional ceiling test write-downs during 2015.
Item 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
The following table sets forth certain information with respect to repurchases of our common stock during the quarter ended March 31, 2015.
 
Total Number of
Shares Purchased (1)
 
Average Price
Paid Per Share
 
Total Number of
Shares
Purchased as
Part of Publicly
Announced Plan
or Program
 
Maximum Number (or
Approximate Dollar
Value) of Shares that
May be Purchased
Under the Plans or
Programs
January 1 - January 31, 2015
2,282

 
$
3.20

 
—

 
—

February 1 - February 28, 2015
31,987

 
3.22

 
—

 
—

March 1 - March 31, 2015
387

 
2.88

 
—

 
—

Total
34,656

 
$
3.22

 
—

 
—

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

We have not paid dividends on our common stock, in cash or otherwise, and intend to retain our cash flow from operations for the future operation and development of our business. We are currently restricted from paying dividends on our common stock by our bank credit facility, the indenture governing the 10% senior notes and, in some circumstances, by the terms of our Series B Preferred Stock. Any future dividends also may be restricted by our then-existing debt agreements.

Item 3. DEFAULTS UPON SENIOR SECURITIES
NONE.


22

Item 4. MINE SAFETY DISCLOSURES
NONE.

Item 5. OTHER INFORMATION
NONE.

Item 6. EXHIBITS
10.1 Ninth Amendment to Credit Agreement dated as of February 26, 2015, among PetroQuest Energy, Inc., PetroQuest Energy, L.L.C., JPMorgan Chase Bank, N.A., Wells Fargo Bank, N.A., Capital One, N.A., Iberiabank, Bank of America, N.A. and The Bank of Nova Scotia (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on February 26, 2015).

 
10.2 Tenth Amendment to Credit Agreement dated as of March 27, 2015, among PetroQuest Energy, Inc., PetroQuest Energy, L.L.C., JPMorgan Chase Bank, N.A., Wells Fargo Bank, N.A., Capital One, N.A., Iberiabank, Bank of America, N.A. and The Bank of Nova Scotia (incorporated herein by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the SEC on March 30, 2015).


 
Exhibit 31.1, Certification of Chief Executive Officer pursuant to Rule 13-a-14(a)/Rule 15d-14(a), promulgated under the Securities Exchange Act of 1934, as amended.
 
Exhibit 31.2, Certification of Chief Financial Officer pursuant to Rule 13-a-14(a)/Rule 15d-14(a), promulgated under the Securities Exchange Act of 1934, as amended.
 
Exhibit 32.1, Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
 
Exhibit 32.2, Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
 
Exhibit 101.INS, XBRL Instance Document
 
Exhibit 101.SCH, XBRL Taxonomy Extension Schema Document.
 
Exhibit 101.CAL, XBRL Taxonomy Extension Calculation Linkbase Document.
 
Exhibit 101.DEF, XBRL Taxonomy Definitions Linkbase Document
 
Exhibit 101.LAB, XBRL Taxonomy Extension Label Linkbase Document.
 
Exhibit 101.PRE, XBRL Taxonomy Extension Presentation Linkbase Document


23

SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
 
 
 
PETROQUEST ENERGY, INC.
 
 
 
Date:
May 6, 2015
/s/ J. Bond Clement
 
 
J. Bond Clement
Executive Vice President,
Chief Financial Officer
(Authorized Officer and Principal
Financial Officer)

24

Stock widget

Investing forum

PETROQUEST ENERGY INC Reports