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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
FORM 10-Q
(Mark One)
x
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended: September 30, 2012
¨
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 November 7, 2012 there were 64,057,711 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
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 


2


PETROQUEST ENERGY, INC.
Consolidated Balance Sheets
(Amounts in Thousands)
 
September 30,
2012
 
December 31,
2011
 
(unaudited)
 
(Note 1)
ASSETS
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
5,703

 
$
22,263

Revenue receivable
15,719

 
15,860

Joint interest billing receivable
26,641

 
47,445

Derivative asset
955

 
6,418

Prepaid drilling costs
2,482

 
2,900

Drilling pipe inventory
1,597

 
4,070

Other current assets
2,962

 
2,965

Total current assets
56,059

 
101,921

Property and equipment:
 
 
 
Oil and gas properties:
 
 
 
Oil and gas properties, full cost method
1,707,498

 
1,600,546

Unevaluated oil and gas properties
78,828

 
70,408

Accumulated depreciation, depletion and amortization
(1,420,630
)
 
(1,265,603
)
Oil and gas properties, net
365,696

 
405,351

Gas gathering assets
4,177

 
4,177

Accumulated depreciation and amortization of gas gathering assets
(2,017
)
 
(1,794
)
Total property and equipment
367,856

 
407,734

Other assets, net of accumulated depreciation and amortization of $9,259 and $8,066, respectively
8,133

 
6,511

Total assets
$
432,048

 
$
516,166

LIABILITIES AND STOCKHOLDERS’ EQUITY
 
 
 
Current liabilities:
 
 
 
Accounts payable to vendors
$
56,424

 
$
50,750

Advances from co-owners
25,065

 
33,867

Oil and gas revenue payable
14,533

 
13,764

Accrued interest and preferred stock dividend
2,417

 
6,167

Asset retirement obligation
1,034

 
3,110

Derivative liability
426

 

Other accrued liabilities
5,657

 
8,250

Total current liabilities
105,556

 
115,908

Bank debt
35,000

 

10% Senior Notes
150,000

 
150,000

Asset retirement obligation
29,241

 
27,317

Derivative liability
289

 

Deferred income taxes

 
551

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 62,720 and 62,148 shares, respectively
63

 
62

Paid-in capital
275,375

 
270,606

Accumulated other comprehensive income
600

 
4,031

Accumulated deficit
(164,077
)
 
(52,310
)
Total stockholders’ equity
111,962

 
222,390

Total liabilities and stockholders’ equity
$
432,048

 
$
516,166

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
 
Nine Months Ended
 
September 30,
 
September 30,
 
2012
 
2011
 
2012
 
2011
Revenues:
 
 
 
 
 
 
 
Oil and gas sales
$
33,913

 
$
38,980

 
$
103,286

 
$
122,446

Gas gathering revenue
38

 
49

 
119

 
161

 
33,951

 
39,029

 
103,405

 
122,607

Expenses:
 
 
 
 
 
 
 
Lease operating expenses
9,658

 
10,376

 
28,408

 
30,085

Production taxes
880

 
1,446

 
112

 
2,070

Depreciation, depletion and amortization
15,032

 
14,696

 
46,024

 
43,415

Ceiling test write-down
35,391

 

 
108,987

 
18,907

General and administrative
5,963

 
4,990

 
17,541

 
13,668

Accretion of asset retirement obligation
525

 
433

 
1,542

 
1,612

Interest expense
2,338

 
2,299

 
7,021

 
7,248

 
69,787

 
34,240

 
209,635

 
117,005

Other income (expense):
 
 
 
 
 
 
 
Other income (expense)
257

 
(40
)
 
529

 
237

Derivative expense
(340
)
 

 
(715
)
 

 
(83
)
 
(40
)
 
(186
)
 
237

Income (loss) from operations
(35,919
)
 
4,749

 
(106,416
)
 
5,839

Income tax expense (benefit)
1,435

 
(265
)
 
1,496

 
(594
)
Net income (loss)
(37,354
)
 
5,014

 
(107,912
)
 
6,433

Preferred stock dividend
1,285

 
1,287

 
3,855

 
3,854

Net income (loss) available to common stockholders
$
(38,639
)
 
$
3,727

 
$
(111,767
)
 
$
2,579

Earnings per common share:
 
 
 
 
 
 
 
Basic
 
 
 
 
 
 
 
Net income (loss) per share
$
(0.62
)
 
$
0.06

 
$
(1.79
)
 
$
0.04

Diluted
 
 
 
 
 
 
 
Net income (loss) per share
$
(0.62
)
 
$
0.06

 
$
(1.79
)
 
$
0.04

Weighted average number of common shares:
 
 
 
 
 
 
 
Basic
62,492

 
62,041

 
62,356

 
61,876

Diluted
62,492

 
62,415

 
62,356

 
62,278

See accompanying Notes to Consolidated Financial Statements.

2


PETROQUEST ENERGY, INC.
Consolidated Statements of Comprehensive Income
(unaudited)
(Amounts in Thousands)
 
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2012
 
2011
 
2012
 
2011
Net income (loss)
$
(37,354
)
 
$
5,014

 
$
(107,912
)
 
$
6,433

Change in fair value of derivative instruments,accounted for as hedges, net of income tax (expense) benefit of $1,435, ($1,423), $2,032 and ($1,753), respectively
(2,423
)
 
2,402

 
(3,431
)
 
4,048

Comprehensive income (loss)
$
(39,777
)
 
$
7,416

 
$
(111,343
)
 
$
10,481

See accompanying Notes to Consolidated Financial Statements.


3


PETROQUEST ENERGY, INC.
Consolidated Statements of Cash Flows
(unaudited)
(Amounts in Thousands)
 
 
Nine Months Ended
 
September 30,
 
2012
 
2011
Cash flows from operating activities:
 
 
 
Net income (loss)
$
(107,912
)
 
$
6,433

Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
 
Deferred tax expense (benefit)
1,496

 
(594
)
Depreciation, depletion and amortization
46,024

 
43,415

Ceiling test write-down
108,987

 
18,907

Accretion of asset retirement obligation
1,542

 
1,612

Share based compensation expense
5,609

 
2,985

Amortization costs and other
594

 
461

Non-cash derivative expense
715

 

Payments to settle asset retirement obligations
(2,519
)
 
(551
)
Changes in working capital accounts:
 
 
 
Revenue receivable
141

 
8,087

Prepaid drilling and pipe costs
2,891

 
3,164

Joint interest billing receivable
20,312

 
(34,646
)
Accounts payable and accrued liabilities
1,464

 
26,914

Advances from co-owners
(8,802
)
 
17,926

Other
(2,866
)
 
(3,000
)
Net cash provided by operating activities
67,676

 
91,113

Cash flows used in investing activities:
 
 
 
Investment in oil and gas properties
(121,428
)
 
(141,687
)
Sale of oil and gas properties
837

 

Sale of unevaluated oil and gas properties
6,083

 
14,461

Net cash used in investing activities
(114,508
)
 
(127,226
)
Cash flows used in financing activities:
 
 
 
Net payments for share based compensation
(840
)
 
(977
)
Deferred financing costs
(33
)
 
(24
)
Payment of preferred stock dividend
(3,855
)
 
(3,854
)
Proceeds from bank borrowings
72,500

 
22,000

Repayment of bank borrowings
(37,500
)
 
(22,000
)
Net cash provided by (used in) financing activities
30,272

 
(4,855
)
Net decrease in cash and cash equivalents
(16,560
)
 
(40,968
)
Cash and cash equivalents, beginning of period
22,263

 
63,237

Cash and cash equivalents, end of period
$
5,703

 
$
22,269

Supplemental disclosure of cash flow information:
 
 
 
Cash paid during the period for:
 
 
 
Interest
$
15,628

 
$
15,870

Income taxes
$
15

 
$
51

See accompanying Notes to Consolidated Financial Statements.

4


PETROQUEST ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
Note 1—Basis of Presentation
The consolidated financial information for the three and nine month periods ended September 30, 2012 and 2011, 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 September 30, 2012 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, 2011 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, 2011. Certain prior year amounts have been reclassified to conform to current year presentations.
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—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 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.


5


Note 3—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 September 30, 2012
Loss
(Numerator)
 
Shares
(Denominator)
 
Per
Share Amount
BASIC EPS
 
 
 
 
 
Net loss available to common stockholders
$
(38,639
)
 
62,492

 
$
(0.62
)
Effect of dilutive securities:
 
 
 
 
 
Stock options

 

 
 
Restricted stock

 

 
 
DILUTED EPS
$
(38,639
)
 
62,492

 
$
(0.62
)
 
 
 
 
 
 
For the Three Months Ended September 30, 2011
Income (Numerator)
 
Shares
(Denominator)
 
Per
Share Amount
Net income available to common stockholders
$
3,727

 
62,041

 
 
  Attributable to participating securities
(95
)
 

 
 
BASIC EPS
$
3,632

 
62,041

 
$
0.06

 
 
 
 
 
 
Net income available to common stockholders
$
3,727

 
62,041

 
 
Effect of dilutive securities:
 
 
 
 
 
  Stock options

 
374

 
 
  Restricted stock
(94
)
 

 
 
DILUTED EPS
$
3,633

 
62,415

 
$
0.06

 
 
 
 
 
 
For the Nine Months Ended September 30, 2012
Loss
(Numerator)
 
Shares
(Denominator)
 
Per
Share Amount
BASIC EPS
 
 
 
 
 
Net loss available to common stockholders
$
(111,767
)
 
62,356

 
$
(1.79
)
Effect of dilutive securities:
 
 
 
 
 
Stock options

 

 
 
Restricted stock

 

 
 
DILUTED EPS
$
(111,767
)
 
62,356

 
$
(1.79
)
 
 
 
 
 
 
For the Nine Months Ended September 30, 2011
Income (Numerator)
 
Shares
(Denominator)
 
Per
Share Amount
Net income available to common stockholders
$
2,579

 
61,876

 
 
Attributable to participating securities
(76
)
 

 
 
BASIC EPS
$
2,503

 
61,876

 
$
0.04

 
 
 
 
 
 
Net income available to common stockholders
2,579

 
61,876

 
 
Effect of dilutive securities:
 
 
 
 
 
Stock options

 
402

 
 
Attributable to participating securities
(76
)
 

 
 
DILUTED EPS
$
2,503

 
62,278

 
$
0.04

An aggregate of 1,104,000 and 943,000 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 5,148,000 shares were not included in the computation of diluted earnings per share for the three and nine month periods ended September 30, 2012, respectively, because the inclusion would have been anti-dilutive as a result of the net loss reported for the periods.

6


Common shares issuable upon the assumed conversion of the Series B preferred stock totaling 5,148,000 shares were not included in the computation of diluted earnings per share for the three and nine month periods ended September 30, 2011 because the inclusion would have been anti-dilutive. Options to purchase 127,000 and 21,000 shares of common stock were outstanding during the three and nine month periods ended September 30, 2011, respectively, 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 4—Long-Term Debt
On August 19, 2010, the Company issued $150 million in principal amount of 10% Senior Notes due 2017 (the “Notes”) in a public offering. 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 September 30, 2012, $1.3 million had been accrued in connection with the March 1, 2013 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 and Whitney Bank. The Credit Agreement provides the Company 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 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 September 30, 2012 the Company had $35.0 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 increased from $125 million to $130 million (subject to the aggregate commitments of the lenders then in effect) effective September 28, 2012. The aggregate commitments of the lenders is currently $100 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 borrowing base redetermination is scheduled to occur by March 31, 2013. The Company or the lenders may request two additional borrowing base redeterminations each year. Each time the borrowing base is to be re-determined, the administrative agent under the Credit Agreement will propose a new borrowing base as it deems appropriate in its sole discretion, which must be approved by all lenders if the borrowing base is to be increased, or by lenders holding two-thirds of the amounts outstanding under the Credit Agreement if the borrowing base remains the same or is reduced.
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 Company’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 debt to EBITDAX, determined on a rolling four quarter basis, of 3.0 to 1.0 and a minimum ratio of consolidated current assets to consolidated current liabilities of 1.0 to 1.0, 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 September 30, 2012, the Company was in compliance with all of the covenants contained in the Credit Agreement.


7


Note 5—Asset Retirement Obligation
The following table describes all changes to the Company’s asset retirement obligation liability (in thousands):
 
Nine Months Ended September 30,
 
2012
 
2011
Asset retirement obligation, beginning of period
$
30,427

 
$
24,592

Liabilities incurred
867

 
100

Liabilities settled
(2,519
)
 
(551
)
Accretion expense
1,542

 
1,612

Revisions in estimated cash flows
(42
)
 
1,597

Asset retirement obligation, end of period
30,275

 
27,350

Less: current portion of asset retirement obligation
(1,034
)
 
(2,483
)
Long-term asset retirement obligation
$
29,241

 
$
24,867

Note 6—Share-Based Compensation
Share-based compensation expense is reflected as a component of the Company’s general and administrative expense. A detail of share-based compensation expense for the periods ended September 30, 2012 and 2011 is as follows (in thousands):
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2012
 
2011
 
2012
 
2011
Stock options:
 
 
 
 
 
 
 
Incentive Stock Options
$
211

 
$
122

 
$
646

 
$
279

Non-Qualified Stock Options
181

 
192

 
509

 
526

Restricted stock
1,379

 
754

 
4,454

 
2,180

Share based compensation
$
1,771

 
$
1,068

 
$
5,609

 
$
2,985

Note 7—Ceiling Test
The Company uses the full cost method to account for its oil and gas operations. 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.
At September 30, 2012, 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 $2.22 per Mcf of natural gas, $104.83 per barrel of oil and $7.44 per Mcfe of Ngl. As a result of lower natural gas prices and their negative impact on certain of the Company’s longer-lived estimated proved reserves and estimated future net cash flows, the Company recognized ceiling test write-downs of $35.4 million and $109.0 million during the three and nine months ended September 30, 2012, respectively. The Company’s cash flow hedges in place at September 30, 2012 decreased the ceiling test write-down by approximately $2.1 million.
The Company recognized a ceiling test write-down of $18.9 million during the nine months ended September 30, 2011.


8


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, natural gas or natural gas liquids (Ngl) 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 other income (expense). At September 30, 2012, the Company designated all but one derivative instrument as effective cash flow hedges.
Oil and gas sales include additions related to the settlement of gas hedges of $1,482,000 and $478,000, Ngl hedges of $312,000 and zero, and oil hedges of $491,000 and $178,000, for the three months ended September 30, 2012 and 2011, respectively. For the nine months ended September 30, 2012 and 2011, oil and gas sales include additions (reductions) related to the settlement of gas hedges of $6,867,000 and $864,000, Ngl hedges of $544,000 and zero, and oil hedges of $853,000 and ($211,000), respectively.
As of September 30, 2012, the Company had entered into the following oil and gas contracts:
Production Period
Instrument
Type
 
Daily Volumes
 
Weighted
Average Price
Natural Gas:
 
 
 
 
 
October—December 2012
Costless Collar
 
10,000 Mmbtu
 
$5.00 - $5.29
October 2012
Swap
 
20,000 Mmbtu
 
$2.60
October—December 2012
Swap
 
20,000 Mmbtu
 
$2.73
January—December 2013
Three-Way Collar
 
10,000 Mmbtu
 
$2.00-$3.00-$4.09
 
 
 
 
 
 
Crude Oil:
 
 
 
 
 
October—December 2012
Swap
 
500 Bbls
 
$102.88
 
 
 
 
 
 
Natural Gasoline:
 
 
 
 
 
October—December 2012
Swap
 
100 Bbls
 
$100.13
 
 
 
 
 
 
Iso-Butane:
 
 
 
 
 
October—December 2012
Swap
 
50 Bbls
 
$84.27
 
 
 
 
 
 
Normal Butane:
 
 
 
 
 
October—December 2012
Swap
 
50 Bbls
 
$80.49
At September 30, 2012, the Company had accumulated other comprehensive income of approximately $0.6 million related to the estimated fair value of these derivative instruments. Based on estimated future commodity prices as of September 30, 2012, the Company would realize a $0.3 million gain, net of taxes, during the next 12 months. These gains are expected to be reclassified based on the schedule of oil, gas and Ngl volumes stipulated in the derivative contracts.
Derivatives designated as hedging instruments:
All of the Company’s 2012 derivative contracts are accounted for as effective cash flow hedges under ASC Topic 815-20-25. 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 September 30, 2012 and December 31, 2011:
 
Commodity Derivatives
Period
Balance Sheet
Location
Fair Value
September 30, 2012
Derivative asset
$
955

December 31, 2011
Derivative asset
$
6,418



9


Effect of Cash Flow Hedges on the Consolidated Statement of Operations for the three months ended September 30, 2012 and 2011:
Instrument
Amount of Gain (Loss)
Recognized in Other
Comprehensive Income
 
Location of
Gain Reclassified
into Income
 
Amount of Gain Reclassified into
Income
Commodity Derivatives at September 30, 2012
$
(2,423
)
 
Oil and gas sales
 
$
2,285

Commodity Derivatives at September 30, 2011
$
2,402

 
Oil and gas sales
 
$
656

Effect of Cash Flow Hedges on the Consolidated Statement of Operations for the nine months ended September 30, 2012 and 2011:
Instrument
Amount of Gain (Loss)
Recognized in Other
Comprehensive Income
 
Location of
Gain Reclassified
into Income
 
Amount of Gain 
Reclassified into
Income
Commodity Derivatives at September 30, 2012
$
(3,431
)
 
Oil and gas sales
 
$
8,264

Commodity Derivatives at September 30, 2011
$
4,048

 
Oil and gas sales
 
$
653

Derivatives not designated as hedging instruments:
The Company’s 2013 three-way collar derivative contract has not been designated as an effective cash flow hedge and therefore both realized and unrealized (mark-to-market) gains or losses on this derivative are recorded as derivative expense (income) on the statement of operations. The following tables reflect the fair value of the Company’s non-designated derivative instruments in the consolidated financial statements (in thousands):
Effect of Non-designated Derivative Instruments on the Consolidated Balance Sheet at September 30, 2012 and December 31, 2011:
 
Commodity Derivatives
Period
Balance Sheet Location
Fair Value
September 30, 2012
Derivative liability (current)
$
(426
)
September 30, 2012
Derivative liability (long-term)
$
(289
)
December 31, 2011
 
$

Effect of Non-designated Derivative Instruments on the Consolidated Statement of Operations for the three months ended September 30, 2012 and 2011:
Instrument
Amount of Unrealized Loss
Recognized in Derivative
Income (expense)
Commodity Derivatives at September 30, 2012
$
(340
)
Commodity Derivatives at September 30, 2011
$

Effect of Non-designated Derivative Instruments on the Consolidated Statement of Operations for the nine months ended September 30, 2012 and 2011:
Instrument
Amount of Unrealized Loss
Recognized in Derivative
Income (expense)
Commodity Derivatives at September 30, 2012
$
(715
)
Commodity Derivatives at September 30, 2011
$




10


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 September 30, 2012 were in the form of costless collars, three-way collars and swaps based on NYMEX pricing for oil and natural gas and OPIS Mt. Bellevue 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 September 30, 2012 and December 31, 2011 (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 September 30, 2012
$

 
$
240

 
$

At December 31, 2011
$

 
$
6,418

 
$

The estimated fair value of the Notes was $154.5 million and $151.5 million as of September 30, 2012 and December 31, 2011, respectively, as compared to the book value of $150 million as of each date. The estimated fair value of the Notes was provided by independent brokers using the actual period end quotes for the Notes, which represent Level 2 inputs.
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 the 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 $40.8 million as of September 30, 2012.

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 operations in Oklahoma, Texas, the Gulf Coast Basin, Arkansas and Wyoming. 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, Arkansas, Wyoming 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 2011, we have invested approximately $891 million into growing our longer life assets. During the eight year period ended December 31, 2011, we have realized a 95% drilling success rate on 771 gross wells drilled. Comparing 2011 metrics with those in 2003, the year we implemented our diversification strategy, we have grown production by 212% and estimated proved reserves by 219%. At September 30, 2012, 88% of our estimated proved reserves and 75% of our first nine months of 2012 production were derived from our longer life assets.
During late 2008, in response to declining commodity prices and the global financial crisis, we shifted our focus from increasing reserves and production to building liquidity and strengthening our balance sheet. Because of our significant operational control, we were able to reduce our capital expenditures from $358 million in 2008 to $59 million in 2009 thus allowing us to utilize our cash flow from operations, combined with proceeds from an equity offering, to repay $130 million of bank debt. While we achieved our goal of strengthening the financial position of the Company, because of the reduced capital investments during 2009, our production declined by 9% during 2010.
During 2010 and 2011, we refocused on the key elements of our business strategy with the goal of growing reserves and production in a fiscally prudent manner. In order to maintain our financial flexibility, we funded our 2011 capital expenditures budget with cash flow from operations, cash on hand and additional proceeds received under the Woodford joint development agreement (see “Liquidity and Capital Resources-Source of Capital: Joint Ventures”). As a result of our increased investments during 2010 and 2011, our estimated proved reserves as of December 31, 2011 increased 38% from 2010. Production in the first three quarters of 2012 was 13% higher than production in the first three quarters of 2011.
During February 2012, we amended our Woodford joint development agreement (“JDA”) to accelerate the entry into Phase 2 of the drilling program effective March 1, 2012 and modify the drilling carry ratio. Under the amended JDA, the Phase 2 drilling carry was expanded to provide for development in both the Mississippian Lime and the Woodford Shale plays whereby we will pay 25% of the cost to drill and complete wells and receive a 50% ownership interest. The Phase 2 drilling carry is subject to extensions in one-year intervals and as of September 30, 2012, approximately $78 million remained available. See “Liquidity and Capital Resources-Source of Capital: Joint Ventures”.
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

12


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.
At September 30, 2012, 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 $2.22 per Mcf of natural gas, $104.83 per barrel of oil, and $7.44 per Mcfe of Ngl. As a result of lower natural gas prices and their negative impact on certain of our longer-lived estimated proved reserves and estimated future net cash flows, we recognized ceiling test write-downs of $35.4 million and $109.0 million during the three and nine months ended September 30, 2012, respectively. Our cash flow hedges in place at September 30, 2012 decreased the ceiling test write-down by approximately $2.1 million.


13


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 further 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
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, natural gas or Ngl 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. Bellevue prices for Ngls. 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 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 or OPIS prices at which the hedges will be settled. At September 30, 2012, our derivative instruments, with the exception of our 2013 three-way collar, were designated effective cash flow hedges.
Estimating the fair value of derivative instruments requires valuation calculations incorporating estimates of future NYMEX or OPIS 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.

14


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 September 30,
 
Nine Months Ended September 30,
 
2012
 
2011
 
2012
 
2011
Production:
 
 
 
 
 
 
 
Oil (Bbls)
122,645

 
130,144

 
379,958

 
445,457

Gas (Mcf)
6,888,569

 
6,073,776

 
20,563,350

 
17,847,061

Ngl (Mcfe)
894,138

 
584,786

 
2,250,569

 
1,658,323

Total Production (Mcfe)
8,518,577

 
7,439,426

 
25,093,667

 
22,178,126

Sales:
 
 
 
 
 
 
 
Total oil sales
$
13,287,548

 
$
13,508,377

 
$
41,627,602

 
$
46,403,861

Total gas sales
15,583,994

 
19,865,595

 
46,321,605

 
60,481,702

Total ngl sales
5,041,274

 
5,606,335

 
15,336,515

 
15,560,225

Total oil and gas sales
$
33,912,816

 
$
38,980,307

 
$
103,285,722

 
$
122,445,788

Average sales prices:
 
 
 
 
 
 
 
Oil (per Bbl)
$
108.34

 
$
103.80

 
$
109.56

 
$
104.17

Gas (per Mcf)
2.26

 
3.27

 
2.25

 
3.39

Ngl (per Mcfe)
5.64

 
9.59

 
6.81

 
9.38

Per Mcfe
3.98

 
5.24

 
4.12

 
5.52

The above sales and average sales prices include increases to revenue related to the settlement of gas hedges of $1,482,000 and $478,000, oil hedges of $491,000 and $178,000 and Ngl hedges of $312,000 and zero for the three months ended September 30, 2012 and 2011, respectively. The above sales and average sales prices include increases (reductions) to revenue related to the settlement of gas hedges of $6,867,000 and $864,000, oil hedges of $853,000 and ($211,000) and Ngl hedges of $544,000 and zero for the nine months ended September 30, 2012 and 2011, respectively.
Net income (loss) available to common stockholders totaled ($38,639,000) and $3,727,000 for the quarters ended September 30, 2012 and 2011, respectively, while net income (loss) available to common stockholders totaled ($111,767,000) and $2,579,000 for the nine months ended September 30, 2012 and 2011, respectively. The primary fluctuations were as follows:
Production Total production increased 15% and 13%, respectively, during the three and nine month periods ended September 30, 2012 as compared to the 2011 periods. Gas production during the three and nine month periods ended September 30, 2012 increased 13% and 15%, respectively, from the comparable periods in 2011. The increase in gas production was primarily the result of the success of our drilling program in the Woodford Shale in Oklahoma, the Carthage field in East Texas, and the La Cantera field in South Louisiana. Gas production also increased at our West Cameron Block 402 well due to a successful recompletion during the fourth quarter of 2011. As a result of continued drilling in our longer-life basins, we expect our average daily gas production in 2012 to increase as compared to 2011.
Oil production during the three and nine month periods ended September 30, 2012 decreased 6% and 15%, respectively, from the 2011 periods due primarily to continued normal production declines in our onshore Louisiana and offshore Gulf of Mexico fields. Partially offsetting these decreases were increases from the inception of production from our La Cantera field during March 2012 and our Eagle Ford Shale wells during the second quarter of 2011. Although we expect to increase oil production from drilling operations in the Mississippian Lime, the Eagle Ford Shale and our La Cantera field, such increase is not expected to completely offset normal declines in the Gulf Coast area. As a result, we expect our average daily oil production during 2012 to decrease as compared to 2011.
Ngl production during the three and nine month periods ended September 30, 2012 increased 53% and 36%, respectively, from the 2011 periods due to the inception of production from our La Cantera field and the liquids rich portion of our Oklahoma properties as well as an increase in production at our Carthage field in East Texas. As a result of ongoing drilling in our Texas, Oklahoma and Gulf Coast assets, we expect our daily Ngl production in 2012 to increase significantly as compared to 2011.
Prices Including the effects of our hedges, average gas prices per Mcf for the three and nine month periods ended September 30, 2012 were $2.26 and $2.25, respectively, as compared to $3.27 and $3.39, respectively, for the 2011 periods. Average oil prices per Bbl for the three and nine months ended September 30, 2012 were $108.34 and $109.56, respectively, as compared to $103.80 and $104.17, respectively, for the 2011 periods and average Ngl prices per Mcfe were $5.64 and $6.81, respectively, for the three

15


and nine months ended September 30, 2012, as compared to $9.59 and $9.38, respectively, for the 2011 periods. Stated on an Mcfe basis, unit prices received during the three and nine months ended September 30, 2012 were 24% and 25% lower, respectively, than the prices received during the comparable 2011 periods.
Revenue Including the effects of hedges, oil and gas sales during the three months ended September 30, 2012 decreased 13% to $33,913,000, as compared to oil and gas sales of $38,980,000 during the 2011 period. Including the effects of hedges, oil and gas sales during the nine months ended September 30, 2012 decreased 16% to $103,286,000, as compared to oil and gas sales of $122,446,000 during the 2011 period. The decreased revenue during 2012 was primarily the result of lower natural gas prices as well as reduced oil production during the period.
Expenses Lease operating expenses for the three and nine months ended September 30, 2012 totaled $9,658,000 and $28,408,000, respectively, as compared to $10,376,000 and $30,085,000 during the 2011 periods. Per unit lease operating expenses totaled $1.13 per Mcfe during each of the three and nine month periods ended September 30, 2012 as compared to $1.39 and $1.36 per Mcfe during the 2011 periods. Per unit lease operating expenses decreased primarily due to the increase in overall produced volumes during the period as well as lower absolute costs due to cost savings primarily associated with our Woodford saltwater disposal systems.
Production taxes for the three and nine months ended September 30, 2012 totaled $880,000 and $112,000, respectively, as compared to $1,446,000 and $2,070,000 during the 2011 periods. The decrease during during the nine month period of 2012 was the result of recording a receivable of $2,717,000 during June 2012 for refunds relative to severance tax previously paid on our Oklahoma horizontal wells that we expect to receive over the next three years.
General and administrative expenses during the three and nine months ended September 30, 2012 totaled $5,963,000 and $17,541,000, respectively, as compared to $4,990,000 and $13,668,000 during the 2011 periods. Included in general and administrative expenses was share-based compensation expense as follows (in thousands):
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2012
 
2011
 
2012
 
2011
Stock options:
 
 
 
 
 
 
 
Incentive Stock Options
$
211

 
$
122

 
$
646

 
$
279

Non-Qualified Stock Options
181

 
192

 
509

 
526

Restricted stock
1,379

 
754

 
4,454

 
2,180

Share based compensation
$
1,771

 
$
1,068

 
$
5,609

 
$
2,985

General and administrative expenses increased 19% and 28% during the three and nine months ended September 30, 2012 as compared to the comparable periods of 2011 primarily due to increased non-cash share-based compensation expense during the 2012 periods. We capitalized $3,276,000 and $9,582,000 of general and administrative costs during the three and nine month periods ended September 30, 2012, respectively, and we capitalized $2,670,000 and $8,179,000 during the comparable 2011 periods. General and administrative expenses in 2012 are expected to be higher than in 2011 as a result of increased non-cash share based compensation expense and expansion of staffing as we develop the Mississippian Lime assets.
Depreciation, depletion and amortization (“DD&A”) expense on oil and gas properties for the three and nine months ended September 30, 2012 totaled $14,736,000, or $1.73 per Mcfe, and $45,203,000, or $1.80 per Mcfe, respectively, as compared to $14,412,000, or $1.94 per Mcfe, and $42,616,000, or $1.92 per Mcfe, during the comparable 2011 periods. The decrease in the per unit DD&A rate is primarily the result of positive drilling results in our La Cantera field, Woodford Shale and East Texas drilling programs as well as the write-down of a portion of our evaluated oil and gas properties during the first half of 2012.
At September 30, 2012, 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 $2.22 per Mcf of natural gas, $104.83 per barrel of oil, and $7.44 per Mcfe of Ngl. As a result of lower natural gas prices and their negative impact on certain of our longer-lived estimated proved reserves and estimated future net cash flows, we recognized ceiling test write-downs of $35,391,000 and $108,987,000 during the three and nine months ended September 30, 2012, respectively. Our cash flow hedges in place at September 30, 2012 decreased the ceiling test write-down by approximately $2.1 million.
We also recognized a ceiling test write-down of $18,907,000 during the nine months ended September 30, 2011.
Interest expense, net of amounts capitalized on unevaluated properties, totaled $2,338,000 and $7,021,000 during the three and nine months ended September 30, 2012, respectively, as compared to $2,299,000 and $7,248,000 during the 2011 periods. During

16


the three and nine months periods ended September 30, 2012, our capitalized interest totaled $1,869,000 and $5,452,000, respectively, as compared to $1,851,000 and $5,111,000 during the 2011 periods.
Income tax expense (benefit) during the three and nine months ended September 30, 2012 totaled $1,435,000 and $1,496,000, respectively, as compared to ($265,000) and ($594,000) during the 2011 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 the ceiling test write-downs recognized, 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 $40,843,000 as of September 30, 2012.
Liquidity and Capital Resources
We have financed our acquisition, exploration and development activities to date principally through cash flow from operations, bank borrowings, second lien term credit facilities, issuances of equity and debt securities, joint ventures and sales of assets. At September 30, 2012, we had a working capital deficit of $49 million compared to a deficit of $14 million at December 31, 2011. The increase in our working capital deficit is primarily the result of our increased operational activities as our capital expenditures during the first nine months of 2012 exceeded our cash flow from operations. 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. To the extent our capital expenditures during the fourth quarter of 2012 exceed our cash flow and cash on hand, we plan to utilize available borrowings under the bank credit facility or proceeds from the potential sale of assets to fund a portion of our drilling budget.
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 $91.1 million during the nine months ended September 30, 2011 to $67.7 million during the 2012 period. The decrease in operating cash flow during 2012 as compared to 2011 was primarily attributable to the decrease in oil and gas revenues during the period due to lower natural gas prices and lower oil production.
Source of Capital: Debt
On August 19, 2010, we issued $150 million in principal amount of 10% Senior Notes due 2017 (the “Notes”) in a public offering. At September 30, 2012, the estimated fair value of the Notes was $154.5 million, based upon a market quote provided by an independent broker. 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 September 30, 2012, $1.3 million had been accrued in connection with the March 1, 2013 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 and Whitney Bank. 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. The credit facility matures on October 3, 2016. As of September 30, 2012 we had $35 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. The current borrowing base is $130 million (subject to the aggregate commitments of the lenders then in effect). The aggregate commitments of the lenders is currently $100 million and can be increased to up to

17


$300 million by either adding new lenders or increasing the commitments of existing lenders, subject to certain conditions. The next borrowing base redetermination is scheduled to occur by March 31, 2013. We or the lenders may request two additional borrowing base redeterminations each year. Each time the borrowing base is to be re-determined, the administrative agent under the Credit Agreement will propose a new borrowing base as it deems appropriate in its sole discretion, which must be approved by all lenders if the borrowing base is to be increased, or by lenders holding two-thirds of the amounts outstanding under the Credit Agreement if the borrowing base remains the same or is reduced.
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.
We are subject to certain restrictive financial covenants under the Credit Agreement, including a maximum ratio of total debt to EBITDAX, determined on a rolling four quarter basis, of 3.0 to 1.0 and a minimum ratio of consolidated current assets to consolidated current liabilities of 1.0 to 1.0, 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 us to repurchase up to $10 million of our common stock during the term of the Credit Agreement, so long as after giving effect to such repurchase our Liquidity (as defined therein) is greater than 20% of the total commitments of the lenders at such time. As of September 30, 2012, we were in compliance with all of the covenants contained in the Credit Agreement.
Source of Capital: Issuance of Securities
During October 2010, our shelf registration statement was declared effective, which allows us to publicly offer and sell up to $250 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, net of $2.6 million in transaction fees, and an additional $14 million on November 30, 2011. In addition, since May 2010, WSGP has funded a share of our drilling costs under a drilling program. We achieved certain production performance metrics, as outlined in the joint development agreement, relative to the first 18 wells drilled under the drilling program. As a result, we received an additional $14 million during December 2011.
During February 2012, we amended the joint development agreement with WSGP to provide additional funding for a share of our drilling costs relative to our 2012 drilling programs in both our Woodford Shale and Mississippian Lime project areas. WSGP will continue to earn 50% of our undeveloped Woodford Shale acreage as they continue to fund a share of our drilling costs. As of September 30, 2012, approximately $78 million of drilling carry remained available.

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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 non-strategic 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 our Wyoming and Arkansas assets. We cannot assure you that we will be able to sell any of our assets in the future.
Use of Capital: Exploration and Development
Our 2012 capital budget, which includes capitalized interest and general and administrative costs, is expected to range between $130 million and $135 million, of which $115 million was incurred during the first nine months of 2012. 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 nine months ended September 30, 2012, we funded our capital expenditures with cash flow from operations, cash on hand and borrowings under our bank credit facility. To the extent our capital expenditures during the fourth quarter of 2012 exceed our cash flow and cash on hand, we plan to utilize available borrowings under the bank credit facility or proceeds from the potential sale of assets to fund a portion of our drilling budget.
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. In September 2011, we acquired approximately 28,000 acres in Pawnee County, Oklahoma targeting the Mississippian Lime, and subsequently sold a 50% interest in this acreage position for approximately $14.5 million. We recently sold a 50% working interest in additional Mississippian Lime acreage for approximately $6.1 million. After completing the sell downs, we have invested approximately $14.7 million as of September 30, 2012 acquiring Mississippian Lime acreage.
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 our ability to find oil and natural gas reserves that are economically recoverable, the volatility of oil and natural gas prices and significantly depressed natural gas prices since the middle of 2008, the uncertain economic conditions in the United States and globally, the declines in the values of our properties that have resulted and may in the future result in additional ceiling test write-downs, our ability to replace reserves and sustain production, our estimate of the sufficiency of our existing capital sources, our ability to raise additional capital to fund cash requirements for future operations, the uncertainties involved in prospect development and property acquisitions or dispositions and in projecting future rates of production or future reserves, the timing of development expenditures and drilling of wells, hurricanes and other natural disasters, changes in laws and regulations as they relate to our operations, including our fracing operations in shale plays or our operations in the Gulf of Mexico, and the operating hazards attendant to the oil and gas business. 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.


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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 and natural gas production. Based on projected sales volumes for the remainder of 2012, a 10% change in the prices we receive for our crude oil and natural gas production would have an approximate $2.1 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 and nine months ended September 30, 2012, we received $2,285,000 and $8,264,000, respectively, 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 September 30, 2012, we had entered into the following oil and gas contracts:
Production Period
Instrument
Type
Daily Volumes
Weighted
Average Price
Natural Gas:
 
 
 
October—December 2012
Costless Collar
10,000 Mmbtu
$5.00 - $5.29
October 2012
Swap
20,000 Mmbtu
$2.60
October—December 2012
Swap
20,000 Mmbtu
$2.73
January—December 2013
Three-Way Collar
10,000 Mmbtu
$2.00-$3.00-$4.09
 
 
 
 
Crude Oil:
 
 
 
October—December 2012
Swap
500 Bbls
$102.88
 
 
 
 
Natural Gasoline:
 
 
 
October—December 2012
Swap
100 Bbls
$100.13
 
 
 
 
Iso-Butane:
 
 
 
October—December 2012
Swap
50 Bbls
$84.27
 
 
 
 
Normal Butane:
 
 
 
October—December 2012
Swap
50 Bbls
$80.49
At September 30, 2012, we had accumulated other comprehensive income of approximately $0.6 million related to the estimated fair value of these derivative instruments. Based on estimated future commodity prices as of September 30, 2012, we would realize a $0.3 million gain, net of taxes, during the next 12 months. This gain is expected to be reclassified based on the schedule of oil, gas and Ngl volumes stipulated in the derivative contracts.


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Item 4. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
As of the end of the period covered by this report, the Company’s management, including its Chief Executive Officer and Chief Financial Officer, completed an evaluation of the effectiveness of the Company’s disclosure controls and procedures pursuant to Rule 13a-15 of the Securities and Exchange Act of 1934, as amended (the “Exchange Act”). Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded:
i.
that the Company’s disclosure controls and procedures are designed to ensure (a) that information required to be disclosed by the Company in the reports it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms, and (b) that such information is accumulated and communicated to the Company’s management, including the Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure; and
ii.
that the Company's disclosure controls and procedures are effective.
Notwithstanding the foregoing, there can be no assurance that the Company’s disclosure controls and procedures will detect or uncover all failures of persons within the Company and its consolidated subsidiaries to disclose material information otherwise required to be set forth in the Company’s periodic reports. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures.
Changes in Internal Control Over Financial Reporting
There have been no changes in the Company’s internal control over financial reporting during the period covered by this report that have materially affected, or that are reasonably likely to materially affect, the Company’s internal control over financial reporting.
Part II
Item 1. LEGAL PROCEEDINGS
NONE.

Item 1A. RISK FACTORS
Oil and natural gas prices are volatile, and natural gas prices have been significantly depressed since the middle of 2008. 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. Prices for natural gas have been significantly depressed since the middle of 2008 and future oil and natural gas prices are subject to large fluctuations in response to a variety of factors beyond our control.
These factors include:
relatively minor changes in the supply of or the demand for oil and natural gas;
the condition of the United States and worldwide economies;
market uncertainty;
the level of consumer product demand;
weather conditions in the United States, such as hurricanes;
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;

21


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, 2012 to decline compared to our estimated proved reserves at December 31, 2011. 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.
We have a substantial amount of indebtedness, which 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 September 30, 2012, the aggregate amount of our outstanding indebtedness, net of cash on hand, was $179.3 million, which 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 10% senior notes due 2017, which we refer to as 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, $15 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
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.



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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 unproved 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 unproved properties periodically to determine whether impairment has occurred. The risk that we will be required to further write down 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 unproved property values, or if estimated future development costs increase. As a result of the decline in commodity prices, we recognized ceiling test write-downs totaling $109.0 million and $18.9 million during the first nine months of 2012 and 2011, respectively. We may experience further ceiling test write-downs or other impairments in the future. In addition, any future ceiling test cushion would be subject to fluctuation as a result of acquisition or divestiture activity.
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 September 30, 2012.
 
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
July 1 - July 31, 2012
1,904

 
$
5.61

 

 

August 1 - August 31, 2012
4,509

 
6.32

 

 

September 1 - September 30, 2012
101,032

 
6.61

 

 

Total
107,445

 
$
6.58

 

 

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

Item 3. DEFAULTS UPON SENIOR SECURITIES
NONE.

Item 4. MINE SAFETY DISCLOSURES
NONE.

Item 5. OTHER INFORMATION
NONE.


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Item 6. EXHIBITS
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

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SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
 
 
 
PETROQUEST ENERGY, INC.
 
 
 
Date:
November 9, 2012
/s/ J. Bond Clement
 
 
J. Bond Clement
Executive Vice President, Chief
(Authorized Officer and Principal
Financial Officer)

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