Current PQ Stock Info

PetroQuest Energy, Inc. (PQ) announced today that the Company recorded net income available to common stockholders for the quarter ended March 31, 2013 of $2,607,000, or $0.04 per share, compared to first quarter 2012 net loss to common stockholders of $18,608,000, or $0.30 per share. The 2012 period included a non-cash ceiling test impairment of $20,111,000.

Discretionary cash flow for the first quarter of 2013 was $18,632,000, as compared to $19,648,000 for the comparable 2012 period.  See the attached schedule for a reconciliation of net cash flow provided by operating activities to discretionary cash flow.

Oil and gas sales during the first quarter of 2013 were $35,976,000, as compared to $35,997,000 in the first quarter of 2012. Production for the first quarter of 2013 was 8,255,580 Mcfe, as compared to 8,170,100 Mcfe in the first quarter of 2012. Pro forma for the Fayetteville asset divestiture in December 2012, production during the first quarter of 2013 was 7% higher than the comparable 2012 period.

Oil and NGL volumes comprised approximately 22% of the Company’s total production during the first quarter of 2013 as compared to 18% in the 2012 period.  The increased percentage of liquids production was due to a 79% increase in NGL production since the first quarter of 2012.  Stated on an Mcfe basis, unit prices received during the first quarter of 2013 were 1% lower than the comparable 2012 period.

Lease operating expenses (“LOE”) for the first quarter of 2013 totaled $9,719,000, as compared to $9,665,000 in the first quarter of 2012. LOE per Mcfe was $1.18 in each of the first quarters of 2013 and 2012.

Depreciation, depletion and amortization (“DD&A”) on oil and gas properties for the first quarter of 2013 was $1.53 per Mcfe as compared to $1.83 per Mcfe in the first quarter of 2012.  The decline in the DD&A rate was primarily the result of non-cash ceiling test impairments recorded during 2012.

General and administrative expenses during the first quarter of 2013 totaled $4,716,000, as compared to $5,579,000 during the 2012 period. Included in first quarter 2013 and 2012 general and administrative expenses were non-cash stock compensation costs totaling $556,000 and $1,923,000, respectively.

Interest expense for the first quarter of 2013 increased to $2,864,000, as compared to $2,270,000 in the first quarter of 2012. The increase in interest expense was the result of increased borrowings outstanding under the Company’s credit facility.  During March 2013, the Company’s bank group completed its semi-annual redetermination of the borrowing base under the credit facility and increased the borrowing base from $130,000,000 to $150,000,000. The Company had $60,000,000 of borrowings outstanding at March 31, 2013.

Capital expenditures during the first quarter of 2013 totaled $32,043,000 and consisted of leasing and seismic costs of $5,649,000, drilling capital of $21,831,000 and capitalized overhead and interest of $4,563,000.  The Company expects its capital expenditures in the second quarter of 2013 to be substantially less than the first quarter and reaffirms its full year 2013 capital expenditures guidance within a range of $80,000,000 to $100,000,000.

The following table sets forth certain information with respect to the oil and gas operations of the Company for the three-month periods ended March 31, 2013 and 2012:


Three Months Ended March 31,
2013 2012
Oil (Bbls) 125,723 141,275
Gas (Mcf) (1) 6,436,595 6,729,315
Ngl (Mcfe) 1,064,647 593,135
Total Production (Mcfe) (1) 8,255,580 8,170,100
Total Daily Production  (Mcfe) (1) 91,729 89,781
Total oil sales $                  13,144,310 $                  15,508,957
Total gas sales 16,723,032 15,279,953
Total ngl sales 6,108,946 5,208,105
Total oil and gas sales $                  35,976,288 $                  35,997,015
Average sales prices:
Oil (per Bbl) $                          104.55 $                          109.78
Gas (per Mcf) 2.60 2.27
Ngl (per Mcfe) 5.74 8.78
Per Mcfe 4.36 4.41
(1) First quarter 2012 production includes 462,500 Mcf (5.1 MMcfe/d) from Fayetteville Shale assets divested in December 2012

The above sales and average sales prices include increases (reductions) to revenue related to the settlement of gas hedges of $532,000 and $2,155,000 and oil hedges of ($145,000) and ($53,000) for the three months ended March 31, 2013 and 2012, respectively.

The following initiates guidance for the second quarter of 2013:


Guidance for
Description 2nd Quarter 2013
Production volumes (MMcfe/d) 92 – 97
Percent Gas 77%
Percent Oil 8%
Percent NGL 15%
  Lease operating expenses (per Mcfe) $1.15 – $1.25
  Production taxes (per Mcfe) $0.10 – $0.15
  Depreciation, depletion and amortization (per Mcfe) $1.50 – $1.60
  General and administrative (in millions) (1) $5.5 – $6.0
  Interest expense (in millions) $2.8 – $3.0
(1) Includes non-cash stock compensation estimate of $1.2 mm

Operations Update
In the Gulf Coast, the Company’s third well at its La Cantera field, the Broussard Estates #3 (NRI -17%), has reached total depth of 18,035 feet.  The well has been completed in the upper section of the Cris R-2 (Lobe A) and is in the process of being tied back to the Company’s production facilities. The Company’s mid-stream partner is currently installing a four mile pipeline to the north, which is expected to be in service by late May.  Once the pipeline is operational, production is planned to commence from the Broussard Estates #3 well at a gross daily rate of 35,000 Mcfe per day (21% liquids) increasing the total La Cantera gross production from the three wells to approximately 110,000 – 120,000 Mcfe per day (21 % liquids). The Company is planning additional processing capacity to be in service during the fourth quarter which is expected to increase natural gas liquids recovery efficiencies and bring the total La Cantera gross daily production to 120,000 – 130,000 Mcfe per day (28% liquids).

The Company has received a 70 square mile 3D seismic survey, which includes coverage over its Thunder Bayou prospect, located approximately two miles north of the La Cantera discovery.  In addition to enhancing the interpretation of the Thunder Bayou prospect, the 3-D seismic shoot has also identified multiple potential prospects that the Company is beginning to evaluate.  The unitization process for the Company’s Thunder Bayou prospect has commenced and the Company expects to spud this well during the second half of 2013.

The Company’s near term oil focused prospects, Sawgrass and Tokay, are expected to spud in early June and the fourth quarter of 2013, respectively. The Company’s Overlake prospect was recently logged and determined to be commercially non-productive.

In East Texas, the Company recently completed its PQ#9 horizontal Cotton Valley well.  The 4,273 foot lateral well (NRI – 76%) established a 24 hour max rate of 6,353 Mcf of gas and 458 barrels of natural gas liquids from 11 of the 14 stages.  The Company expects to complete the remaining three stages in approximately two weeks. The Company continues to identify future drilling locations and currently has numerous 100% and 50% working interest wells available for future development.

In the Woodford, the Company recently commenced production from two additional liquids rich Woodford wells (NRI –35%) at an average max 24 hour rate of 3,331 Mcf of gas and 351 barrels of natural gas liquids. These wells were part of an eight well pad that established a total max 24 hour rate of 29,072 Mcf of gas and 1,911 barrels of natural gas liquids.  The Company has three wells in the early stages of flowback with one operated rig running in the trend. The Company continues to realize cost savings and estimates that its current well cost is approximately $4.0 – $4.2 million. In addition, the Company continues to acquire additional acreage in the liquids portion of the trend and estimates that its total JV Woodford acreage position is in excess of 60,000 acres.

In northern Oklahoma, the Company’s PQML #13 well in Grant County established a max 24 hour rate of 95 Boe (84 % oil).  The well is in the initial production stage and is exhibiting inconsistent flow rates that the Company is attempting to resolve by optimizing the artificial lift system.  In addition, the Company’s PQML #14 well in Grant County was recently completed and is in the early stages of flowback.  The Company has commenced 3D seismic surveys in Kay and Pawnee Counties and expects to receive the data from these areas in June and September, respectively.  Once the seismic data has been interpreted and integrated with well results drilled to date, the Company expects to resume drilling activities utilizing a significantly enhanced geologic model in this oil focused area.

Hedging Update
The Company recently initiated the following commodity hedging transaction:

Production Period Type Daily Volumes Price
July 2013 – Dec 2013 Costless Collar 5,000 Mmbtu $4.00 – $4.75

The Company has approximately 14 Bcf of gas hedged for 2013.  Based on the mid-point of 2013 production guidance, the Company estimates it has hedged 52% of its 2013 estimated gas production at an average floor price of $3.60/Mcf and an average ceiling price of $3.93/Mcf.

Management Statement
“We are excited about our near term Gulf Coast inventory where, in addition to our high impact Thunder Bayou prospect, we have identified several new potential targets in this prolific mini-basin,” said Charles T. Goodson, Chairman, Chief Executive Officer and President. “Our Woodford liquids rich asset, with its advantageous joint venture cost structure, provides us a vehicle to deliver outstanding rates of return on a repeatable basis. The combination of high-impact Gulf Coast projects and our deep inventory of repeatable resource potential from our Woodford and East Texas assets provide us a balanced platform to replicate recent growth.  Excluding the Fayetteville assets sold in December 2012, we have now grown production six consecutive quarters and expect further growth in the second quarter of 2013.”

About the Company
PetroQuest Energy, Inc. is an independent energy company engaged in the exploration, development, acquisition and production of oil and natural gas reserves in the Arkoma Basin, Wyoming, Texas, South Louisiana and the shallow waters of the Gulf of Mexico.  PetroQuest’s common stock trades on the New York Stock Exchange under the ticker PQ.

Forward-Looking Statements
This news release contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended.  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 in 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 PetroQuest has filed with the Securities and Exchange Commission. PetroQuest undertakes no duty to update or revise these forward-looking statements.

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Consolidated Balance Sheets
(Amounts in Thousands)
March 31, 2013 December 31, 2012
Current assets:
Cash and cash equivalents $                       20,963 $                     14,904
Revenue receivable 15,150 17,742
Joint interest billing receivable 36,264 42,595
Other receivable 9,208
Derivative asset 830
Prepaid drilling costs 874 1,698
Drilling pipe inventory 753 707
Other current assets 4,549 1,900
Total current assets 78,553 89,584
Property and equipment:
Oil and gas properties:
Oil and gas properties, full cost method 1,768,031 1,734,477
Unevaluated oil and gas properties 70,203 71,713
Accumulated depreciation, depletion and amortization (1,495,299) (1,472,244)
Oil and gas properties, net 342,935 333,946
Other property and equipment 12,419 12,370
Accumulated depreciation of other property and equipment (7,867) (7,607)
Total property and equipment 347,487 338,709
Other assets, net of accumulated depreciation and amortization of $4,441 and $4,240, respectively 4,761 5,110
Total assets $                     430,801 $                   433,403
Current liabilities:
Accounts payable to vendors $                       38,947 $                     58,960
Advances from co-owners 31,201 20,459
Oil and gas revenue payable 23,195 26,175
Accrued interest and preferred stock dividend 2,456 6,190
Asset retirement obligation 3,845 2,351
Derivative liability 3,807 233
Other accrued liabilities 5,678 6,535
Total current liabilities 109,129 120,903
Bank debt 60,000 50,000
10% Senior Notes 150,000 150,000
Asset retirement obligation 24,661 24,909
Derivative liability 251
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 62,907 and 62,768 shares, respectively 63 63
Paid-in capital 277,006 276,534
Accumulated other comprehensive income (loss) (3,389) 521
Accumulated deficit (186,921) (189,528)
Total stockholders’ equity 86,760 87,591
Total liabilities and stockholders’ equity $                     430,801 $                   433,403


Consolidated Statements of Operations
(Amounts in Thousands, Except Per Share Data)
Three Months Ended,
March 31, 2013 March 31, 2012
Oil and gas sales $            35,976 $            35,997
Gas gathering revenue 33 44
36,009 36,041
Lease operating expenses 9,719 9,665
Production taxes 1,028 1,149
Depreciation, depletion and amortization 12,871 15,230
Ceiling test write-down 20,111
General and administrative 4,716 5,579
Accretion of asset retirement obligation 332 500
Interest expense 2,864 2,270
31,530 54,504
Other income (expense):
Other income 194 149
Derivative expense (437)
(243) 149
Income (loss) from operations 4,236 (18,314)
Income tax expense (benefit) 349 (988)
Net income (loss) 3,887 (17,326)
Preferred stock dividend 1,280 1,282
Net income (loss) available to common stockholders $              2,607 $           (18,608)
Earnings per common share:
Net income (loss) per share $                0.04 $               (0.30)
Net income (loss) per share $                0.04 $               (0.30)
Weighted average number of common shares:
Basic 62,834 62,216
Diluted 63,029 62,216


Consolidated Statements of Cash Flows
(Amounts in Thousands)
Three Months Ended,
March 31, 2013 March 31, 2012
Cash flows from operating activities:
Net income (loss) $              3,887 $           (17,326)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Deferred tax expense (benefit) 349 (988)
Depreciation, depletion and amortization 12,871 15,230
Ceiling test writedown 20,111
Accretion of asset retirement obligation 332 500
Share based compensation expense 556 1,923
Amortization costs and other 200 198
Non-cash derivative expense 437
Payments to settle asset retirement obligations (72) (782)
Changes in working capital accounts:
Revenue receivable 2,592 734
Prepaid drilling and pipe costs 778 2,317
Joint interest billing receivable 6,331 (6,121)
Accounts payable and accrued liabilities (27,344) 10,502
Advances from co-owners 10,742 (12,619)
Other (2,539) 272
Net cash provided by operating activities 9,120 13,951
Cash flows used in investing activities:
Investment in oil and gas properties (31,275) (33,396)
Investment in other property and equipment (49)
Sale of oil and gas properties 19,652
Net cash used in investing activities (11,672) (33,396)
Cash flows used in financing activities:
Net payments for share based compensation (234) (390)
Issuance of common stock under ESPP 150
Deferred financing costs (21) (1)
Payment of preferred stock dividend (1,284) (1,284)
Proceeds from bank borrowings 25,000 30,000
Repayment of bank borrowings (15,000) (20,000)
Net cash provided by financing activities 8,611 8,325
Net increase (decrease) in cash and cash equivalents 6,059 (11,120)
Cash and cash equivalents, beginning of period 14,904 22,263
Cash and cash equivalents, end of period $            20,963 $            11,143
Supplemental disclosure of cash flow information:
Cash paid during the period for:
Interest $              7,845 $              7,619
Income taxes $                   41 $                   15


Non-GAAP Disclosure Reconciliation
(Amounts In Thousands)
Three Months Ended
March 31,
2013 2012
Net income (loss) $          3,887 $     (17,326)
Reconciling items:
      Deferred tax expense (benefit) 349 (988)
      Depreciation, depletion and amortization 12,871 15,230
      Ceiling test writedown 20,111
      Accretion of asset retirement obligation 332 500
      Share based compensation expense 556 1,923
      Non-cash derivative expense 437
      Amortization costs and other 200 198
Discretionary cash flow 18,632 19,648
      Changes in working capital accounts (9,440) (4,915)
      Settlement of asset retirement obligations (72) (782)
Net cash flow provided by operating activities $          9,120 $      13,951


Note: Management believes that discretionary cash flow is relevant and useful information, which is commonly used by analysts, investors and other interested parties in the oil and gas industry as a financial indicator of an oil and gas company’s ability to generate cash used to internally fund exploration and development activities and to service debt.  Discretionary cash flow is not a measure of financial performance prepared in accordance with generally accepted accounting principles (“GAAP”) and should not be considered in isolation or as an alternative to net cash flow provided by operating activities.  In addition, since discretionary cash flow is not a term defined by GAAP, it might not be comparable to similarly titled measures used by other companies.


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