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PQ > SEC Filings for PQ > Form 10-Q on 6-Nov-2013All Recent SEC Filings

Show all filings for PETROQUEST ENERGY INC

Form 10-Q for PETROQUEST ENERGY INC


6-Nov-2013

Quarterly Report


MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Overview
PetroQuest Energy, Inc. is an independent oil and gas company incorporated in the State of Delaware with primary operations in Oklahoma, Texas and the Gulf Coast Basin. We seek to grow our production, proved reserves, cash flow and earnings at low finding and development costs through a balanced mix of exploration, development and acquisition activities. From the commencement of our operations in 1985 through 2002, we were focused exclusively in the Gulf Coast Basin with onshore properties principally in southern Louisiana and offshore properties in the shallow waters of the Gulf of Mexico shelf. During 2003, we began the implementation of our strategic goal of diversifying our reserves and production into longer life and lower risk onshore properties. As part of the strategic shift to diversify our asset portfolio and lower our geographic and geologic risk profile, we refocused our opportunity selection processes to reduce our average working interest in higher risk projects, shift capital to higher probability of success onshore wells and mitigate the risks associated with individual wells by expanding our drilling program across multiple basins.
We have successfully diversified into onshore, longer life basins in Oklahoma and Texas through a combination of selective acquisitions and drilling activity. Beginning in 2003 with our acquisition of the Carthage Field in East Texas through 2012, we have invested approximately $998 million into growing our longer life assets. During the nine year period ended December 31, 2012, we have realized a 95% drilling success rate on 878 gross wells drilled. Comparing 2012 metrics with those in 2003, the year we implemented our diversification strategy, we have grown production by 252% and estimated proved reserves by 174%. At September 30, 2013, 80% of our estimated proved reserves and 66% of our first nine months 2013 production were derived from our longer life assets. Gas prices have remained weak since late-2008. As a result of the impact of low natural gas prices on our revenues and cash flow, we have focused on growing our reserves and production through a balanced drilling budget with an increased emphasis on growing our oil and natural gas liquids production. In May 2010, we entered into the Woodford joint development agreement ("JDA"), which provided us with $85 million in cash during 2010 and 2011, along with a drilling carry that we have utilized since May 2010 to enhance economic returns by reducing our share of capital expenditures in the Woodford Shale and Mississippian Lime. As a result of the JDA and the success of our drilling programs, as of December 31, 2012 we grew our estimated proved reserves by 18% and production by 10% since 2010, while maintaining our long-term debt 28% below 2008 levels.
On July 3, 2013, we acquired certain shallow water Gulf of Mexico shelf oil and gas properties (the "Acquired Assets"), for an aggregate cash purchase price of $188.2 million, subject to customary adjustments to reflect an effective date of January 1, 2013, (collectively, the "Gulf of Mexico Acquisition"). The Acquired Assets include 16 wells located on 7 platforms. We believe the acquisition of the Acquired Assets represents both a strategic and transformative transaction for us. This transaction builds upon our existing strategy of utilizing free cash flow from our shorter life, Gulf Coast Basin assets to develop our longer life resource assets. We plan to utilize a portion of the free cash flow generated from these acquired properties to accelerate the development of our Woodford Shale and Cotton Valley resource plays. Critical Accounting Policies
Reserve Estimates
Our estimates of proved oil and gas reserves constitute those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. At the end of each year, our proved reserves are estimated by independent petroleum engineers in accordance with guidelines established by the SEC. These estimates, however, represent projections based on geologic and engineering data. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that are difficult to measure. The accuracy of any reserve estimate is a function of the quantity and quality of available data, engineering and geological interpretation and professional judgment. Estimates of economically recoverable oil and gas reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effect of regulations by governmental agencies, and assumptions governing future oil and gas prices, future operating costs, severance taxes, development costs and workover costs. The future drilling costs associated with reserves assigned to proved undeveloped locations may ultimately increase to the extent that these reserves may be later determined to be uneconomic. Any significant variance in the assumptions could materially affect the estimated quantity and value of the reserves, which could affect the carrying value of our oil and gas properties and/or the rate of depletion of such oil and gas properties.


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Disclosure requirements under Staff Accounting Bulletin 113 ("SAB 113") include provisions that permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes. The rules also allow companies the option to disclose probable and possible reserves in addition to the existing requirement to disclose proved reserves. The disclosure requirements also require companies to report the independence and qualifications of third party preparers of reserves and file reports when a third party is relied upon to prepare reserves estimates. Pricing is based on a 12-month average price using beginning of the month pricing during the 12-month period prior to the ending date of the balance sheet to report oil and natural gas reserves. In addition, the 12-month average will also be used to measure ceiling test impairments and to compute depreciation, depletion and amortization. Full Cost Method of Accounting
We use the full cost method of accounting for our investments in oil and gas properties. Under this method, all acquisition, exploration and development costs, including certain related employee costs, incurred for the purpose of exploring for and developing oil and natural gas are capitalized. Acquisition costs include costs incurred to purchase, lease or otherwise acquire property. Exploration costs include the costs of drilling exploratory wells, including those in progress and geological and geophysical service costs in exploration activities. Development costs include the costs of drilling development wells and costs of completions, platforms, facilities and pipelines. Costs associated with production and general corporate activities are expensed in the period incurred. Sales of oil and gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas. The costs associated with unevaluated properties are not initially included in the amortization base and primarily relate to ongoing exploration activities, unevaluated leasehold acreage and delay rentals, seismic data and capitalized interest. These costs are either transferred to the amortization base with the costs of drilling the related well or are assessed quarterly for possible impairment or reduction in value.
We compute the provision for depletion of oil and gas properties using the unit-of-production method based upon production and estimates of proved reserve quantities. Unevaluated costs and related carrying costs are excluded from the amortization base until the properties associated with these costs are evaluated. In addition to costs associated with evaluated properties, the amortization base includes estimated future development costs related to non-producing reserves. Our depletion expense is affected by the estimates of future development costs, unevaluated costs and proved reserves, and changes in these estimates could have an impact on our future earnings. We capitalize certain internal costs that are directly identified with acquisition, exploration and development activities. The capitalized internal costs include salaries, employee benefits, costs of consulting services and other related expenses and do not include costs related to production, general corporate overhead or similar activities. We also capitalize a portion of the interest costs incurred on our debt. Capitalized interest is calculated using the amount of our unevaluated property and our effective borrowing rate. Capitalized costs of oil and gas properties, net of accumulated DD&A and related deferred taxes, are limited to the estimated future net cash flows from proved oil and gas reserves, including the effect of cash flow hedges in place, discounted at 10 percent, plus the lower of cost or fair value of unproved properties, as adjusted for related income tax effects (the full cost ceiling). If capitalized costs exceed the full cost ceiling, the excess is charged to write-down of oil and gas properties in the quarter in which the excess occurs. Given the volatility of oil and gas prices, it is probable that our estimate of discounted future net cash flows from proved oil and gas reserves will change in the near term. If oil or gas prices 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.


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Derivative Instruments
The estimated fair values of our commodity derivative instruments are recorded in the consolidated balance sheet. The changes in fair value of those derivative instruments that qualify for hedge accounting treatment are recorded in other comprehensive income (loss) until the hedged oil and natural gas quantities are produced. If a hedge becomes ineffective because the hedged production does not occur, or the hedge otherwise does not qualify for hedge accounting treatment, the changes in the fair value of the derivative are recorded in the income statement as derivative income (expense).
Our hedges are specifically referenced to NYMEX prices for oil and natural gas and OPIS Mt. Belvieu for natural gas liquids. We evaluate the effectiveness of our hedges at the time we enter the contracts, and periodically over the life of the contracts, by analyzing the correlation between NYMEX and OPIS Mt. Belvieu prices and the posted prices we receive from our designated production. Through this analysis, we are able to determine if a high correlation exists between the prices received for the designated production and the NYMEX and OPIS Mt. Belvieu prices at which the hedges will be settled. At September 30, 2013, our derivative instruments, with the exception of our three-way collar and two of our oil swaps, were designated as effective cash flow hedges. Estimating the fair value of derivative instruments requires valuation calculations incorporating estimates of future NYMEX and OPIS Mt. Belvieu prices, discount rates and price movements. As a result, we calculate the fair value of our commodity derivatives using an independent third-party's valuation model that utilizes market-corroborated inputs that are observable over the term of the derivative contract. Our fair value calculations also incorporate an estimate of the counterparties' default risk for derivative assets and an estimate of our default risk for derivative liabilities. Results of Operations
The following table sets forth certain information with respect to our oil and gas operations for the periods noted. These historical results are not necessarily indicative of results to be expected in future periods.

                                         Three Months Ended September 30,          Nine Months Ended September 30,
                                              2013                2012                  2013                  2012
Production:
Oil (Bbls)                                       219,402          122,645               460,822                379,958
Gas (Mcf)                                      8,351,200        6,888,569            21,519,550             20,563,350
Ngl (Mcfe)                                     1,238,719          894,138             3,560,179              2,250,569
Total Production (Mcfe)                       10,906,331        8,518,577            27,844,661             25,093,667
Sales:
Total oil sales                        $      23,663,415     $ 13,287,548     $      48,831,937          $  41,627,602
Total gas sales                               25,009,383       15,583,994            61,980,015             46,321,605
Total ngl sales                                6,905,048        5,041,274            18,818,166             15,336,515
Total oil and gas sales                $      55,577,846     $ 33,912,816     $     129,630,118          $ 103,285,722
Average sales prices:
Oil (per Bbl)                          $          107.85     $     108.34     $          105.97          $      109.56
Gas (per Mcf)                                       2.99             2.26                  2.88                   2.25
Ngl (per Mcfe)                                      5.57             5.64                  5.29                   6.81
Per Mcfe                                            5.10             3.98                  4.66                   4.12

The above sales and average sales prices include increases (decreases) to revenue related to the settlement of gas hedges of $767,000 and $1,482,000, Ngl hedges of $5,000 and $312,000 and oil hedges of ($538,000) and $491,000 for the three months ended September 30, 2013 and 2012, respectively. The above sales and average sales prices include increases (reductions) to revenue related to the settlement of gas hedges of $422,000 and $6,867,000, Ngl hedges of $5,000 and $544,000, and oil hedges of ($684,000) and $853,000 for the nine months ended September 30, 2013 and 2012, respectively.
Net income (loss) available to common stockholders totaled $383,000 and ($38,639,000) for the quarters ended September 30, 2013 and 2012, respectively, while net income (loss) available to common stockholders totaled $6,652,000 and ($111,767,000) for the nine months ended September 30, 2013 and 2012, respectively. The primary fluctuations were as follows:
Production Total production increased 28% and 11% during the three and nine month periods ended September 30, 2013 as compared to the respective 2012 periods. Gas production during the three and nine month periods ended September 30, 2013 increased 21% and 5% from the comparable periods in 2012. The increases in gas production were primarily the result of added


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production from the wells acquired in the Gulf of Mexico Acquisition which closed on July 3, 2013. Additionally, gas production increased as a result of the successful drilling programs in our La Cantera field and our liquids rich Woodford acreage. Partially offsetting these increases were decreases in gas production due to normal production declines at our dry gas Oklahoma fields as well as certain of our legacy Gulf of Mexico fields in addition to the loss of production resulting from the sale of our Fayetteville assets in December 2012. For the remainder of 2013, we expect our average daily gas production to continue to increase as compared to 2012.
Oil production during the three and nine month periods ended September 30, 2013 increased 79% and 21%, respectively, from the 2012 periods due primarily to added production from the wells acquired in the Gulf of Mexico Acquisition as well as the continued success of our La Cantera field. Partially offsetting these increases were decreases as a result of continued normal production declines in certain of our legacy Gulf of Mexico and East Texas fields. As a result of added production from the wells acquired in the Gulf of Mexico Acquisition, we expect our average daily oil production during the remainder of 2013 to continue to increase significantly as compared to 2012.
Ngl production during the three and nine month periods ended September 30, 2013 increased 39% and 58% from the respective 2012 periods due to the success experienced in our La Cantera field and the liquids rich portion of our Oklahoma properties, as well as added production from the wells acquired in the Gulf of Mexico Acquisition. Partially offsetting these increases were decreases as a result of normal production declines at certain of our offshore Gulf of Mexico fields. As a result of the above, we expect our daily Ngl production for the remainder of 2013 to continue to increase as compared to 2012.
Prices Including the effects of our hedges, average gas prices per Mcf for the three and nine month periods ended September 30, 2013 were $2.99 and $2.88 as compared to $2.26 and $2.25 for the respective 2012 periods. Average oil prices per Bbl for the three and nine months ended September 30, 2013 were $107.85 and $105.97 as compared to $108.34 and $109.56 for the 2012 periods and average Ngl prices per Mcfe were $5.57 and $5.29 for the three and nine months ended September 30, 2013, as compared to $5.64 and $6.81 for the 2012 periods. Stated on an Mcfe basis, unit prices received during the three and nine months ended September 30, 2013 were 28% and 13% higher, respectively, than prices received during the comparable 2012 periods.
Revenue Including the effects of hedges, oil and gas sales during the three months ended September 30, 2013 increased 64% to $55,578,000, as compared to oil and gas sales of $33,913,000 during the 2012 period. Including the effects of hedges, oil and gas sales during the nine months ended September 30, 2013 increased 26% to $129,630,000, as compared to oil and gas sales of $103,286,000 during the 2012 period. These increases were primarily the result of higher average realized prices for our production during the 2013 periods and increased production as discussed above.
Expenses Lease operating expenses for the three and nine months ended September 30, 2013 totaled $12,652,000 and $31,208,000, respectively, as compared to $9,658,000 and $28,408,000 during the 2012 periods. Per unit lease operating expenses totaled $1.16 and $1.12 per Mcfe, respectively, during the three and nine month periods ended September 30, 2013 as compared to $1.13 per Mcfe during the respective 2012 periods. We expect the absolute amount of lease operating expenses to increase during the remainder of 2013 as a result of the Gulf of Mexico Acquisition, but we expect per unit lease operating costs to approximate per unit amounts in 2012.
Production taxes for the three and nine months ended September 30, 2013 totaled $1,248,000 and $3,757,000, respectively, as compared to $880,000 and $112,000, respectively, during the 2012 periods. Production taxes during 2012 were lowered as a result of recording a receivable of $2,717,000 during the second quarter of 2012 for refunds relative to production taxes previously paid on our Oklahoma horizontal wells that we expect to receive over three years. Because the majority of the assets purchased in the Gulf of Mexico Acquisition are located in Federal waters and are therefore not subject to production taxes, we do not expect a meaningful change to our production taxes as a result of the Gulf of Mexico Acquisition.
General and administrative expenses during the three and nine months ended September 30, 2013 totaled $9,132,000 and $20,199,000, respectively, as compared to $5,963,000 and $17,541,000 during the 2012 periods. Included in general and administrative expenses was non-cash share-based compensation expense as follows (in thousands):

                                      Three Months Ended September 30,     Nine Months Ended September 30,
                                            2013               2012              2013              2012
Stock options:
Incentive Stock Options              $              86     $      211     $            175     $      646
Non-Qualified Stock Options                         41            181                  176            509
Restricted stock                                 1,182          1,379                2,754          4,454
Non-cash share based compensation    $           1,309     $    1,771     $          3,105     $    5,609


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General and administrative expenses increased 15% during the nine months ended September 30, 2013 as compared to the comparable period of 2012. Included in general and administrative expenses for the three and nine months ended September 30, 2013 is $2,872,000 and $3,878,000, respectively, of transaction-related costs related to the Gulf of Mexico Acquisition. In addition, during the third quarter of 2013, we recognized approximately $1,009,000 in general and administrative expenses associated with benefits due under the compensation agreements of the Company's Executive Vice-President and General Counsel, who passed away unexpectedly in September 2013. We capitalized $3,526,000 and $9,682,000, respectively, of general and administrative costs during the three and nine month periods ended September 30, 2013 compared to $3,276,000 and $9,582,000, respectively, during the 2012 periods. We expect our general and administrative expenses in the fourth quarter of 2013 to decrease from third quarter amounts.
Depreciation, depletion and amortization ("DD&A") expense on oil and gas properties for the three and nine months ended September 30, 2013 totaled $22,107,000, or $2.03 per Mcfe, and $48,978,000, or $1.76 per Mcfe, respectively, as compared to $14,736,000, or $1.73 per Mcfe, and $45,203,000, or $1.80 per Mcfe, respectively, during the comparable 2012 periods. The increase in the per unit DD&A rate for the three month 2013 period is primarily the result of the purchase price of the assets acquired in the Gulf of Mexico Acquisition. As a result of the impact of the Gulf of Mexico Acquisition, we expect our DD&A rate to increase during the remainder of 2013.
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 $2,100,000. Interest expense, net of amounts capitalized on unevaluated properties, totaled $8,071,000 and $14,051,000 during the three and nine months ended September 30, 2013, respectively, as compared to $2,338,000 and $7,021,000, respectively, during the 2012 periods. During the three and nine month periods ended September 30, 2013, our capitalized interest totaled $1,757,000 and $4,525,000, respectively, as compared to $1,869,000 and $5,452,000, respectively, during the 2012 periods. The increases in interest expense were a result of the issuance of $200 million of 10% senior notes due 2017, which were used to finance the Gulf of Mexico Acquisition in addition to increased borrowings outstanding under our bank credit facility during the 2013 periods as compared to the prior year periods. As a result, we expect interest expense to remain higher than 2012 levels.
Income tax expense (benefit) during the three and nine months ended September 30, 2013 totaled $17,000 and ($474,000), respectively, as compared to $1,435,000 and $1,496,000, respectively, during the 2012 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 in 2012, 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 $47,183,000 as of September 30, 2013. Liquidity and Capital Resources
We have financed our acquisition, exploration and development activities principally through cash flow from operations, bank borrowings, issuances of equity and debt securities, joint ventures and sales of assets. At September 30, 2013 we had a working capital deficit of approximately $11 million as compared to a working capital deficit of approximately $31 million as of December 31, 2012. 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 remainder of 2013 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, . . .

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