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PQ > SEC Filings for PQ > Form 10-Q on 8-May-2013All Recent SEC Filings

Show all filings for PETROQUEST ENERGY INC | Request a Trial to NEW EDGAR Online Pro



Quarterly Report

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 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, 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 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 March 31, 2013, 88% of our estimated proved reserves and 71% of our first quarter 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.
During February 2012, we amended our 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 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 March 31, 2013, approximately $60.4 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 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. We evaluate the effectiveness of our hedges at the time we enter the contracts, and periodically over the life of the contracts, by analyzing the correlation between NYMEX prices and the posted prices we receive from our designated production. Through this analysis, we are able to determine if a high correlation exists between the prices received for the designated production and the NYMEX prices at which the hedges will be settled. At March 31, 2013, our derivative instruments, with the exception of our three-way collar, were designated as effective cash flow hedges.
Estimating the fair value of derivative instruments requires valuation calculations incorporating estimates of future NYMEX prices, discount rates and price movements. As a result, we calculate the fair value of our commodity derivatives using an independent third-party's valuation model that utilizes market-corroborated inputs that are observable over the term of the derivative contract. Our fair value calculations also incorporate an estimate of the counterparties' default risk for derivative assets and an estimate of our default risk for derivative liabilities. Results of Operations
The following table sets forth certain information with respect to our oil and gas operations for the periods noted. These historical results are not necessarily indicative of results to be expected in future periods.

                             Three Months Ended March 31,
                                 2013                2012
Oil (Bbls)                       125,723              141,275
Gas (Mcf)                      6,436,595            6,729,315
Ngl (Mcfe)                     1,064,647              593,135
Total Production (Mcfe)        8,255,580            8,170,100
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

The above sales and average sales prices include increases (decreases) 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.
Net income (loss) available to common stockholders totaled $2,607,000 and ($18,608,000) for the quarters ended March 31, 2013 and 2012, respectively. The primary fluctuations were as follows:
Production Total production increased 1% during the three month period ended March 31, 2013 as compared to the 2012 period. Gas production during the three month period ended March 31, 2013 decreased 4% from the comparable period in 2012. The decrease in gas production was primarily the result of the sale of our Fayetteville Shale assets in Arkansas in December 2012. Partially offsetting the impact of the sale were increases in gas production as a result of the successful drilling programs ongoing in our La Cantera field and our Woodford acreage. As a result of continued drilling in our longer-life basins, offset by the loss of production resulting from the sale of our Fayetteville assets, we expect our average daily gas production in 2013 to approximate that of 2012.

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Oil production during the three month period ended March 31, 2013 decreased 11% from the 2012 period due primarily to continued normal production declines in our offshore Gulf of Mexico and East Texas fields. Partially offsetting these decreases were increases from the continued success of our La Cantera field as well as our Carthage and Mississippian Lime drilling programs. Due to the planned reduction in our capital spending in these areas for the remainder of 2013, we expect our average daily oil production during 2013 to decrease as compared to 2012.
Ngl production during the three month period ended March 31, 2013 increased 79% from the 2012 period due to the success experienced in our La Cantera field and the liquids rich portion of our Oklahoma properties. Partially offsetting these increases were decreases as a result of normal production declines at our offshore Gulf of Mexico fields as well as our East Texas fields. As a result of ongoing drilling in our liquids rich Oklahoma assets and increased production from La Cantera, we expect our daily Ngl production in 2013 to increase as compared to 2012.
Prices Including the effects of our hedges, average gas prices per Mcf for the three month period ended March 31, 2013 were $2.60 as compared to $2.27 for the 2012 period. Average oil prices per Bbl for the three months ended March 31, 2013 were $104.55 as compared to $109.78 for the 2012 period and average Ngl prices per Mcfe were $5.74 for the three months ended March 31, 2013, as compared to $8.78 for the 2012 period. Stated on an Mcfe basis, unit prices received during the three months ended March 31, 2013 were 1% lower than the prices received during the comparable 2012 period.
Revenue Including the effects of hedges, oil and gas sales of $35,976,000 during the three months ended March 31, 2013 were comparable to oil and gas sales of $35,997,000 during the 2012 period.
Expenses Lease operating expenses for the three months ended March 31, 2013 totaled $9,719,000 as compared to $9,665,000 during the 2012 period. Per unit lease operating expenses totaled $1.18 per Mcfe during each of the three month periods ended March 31, 2013 and 2012.
Production taxes for the three months ended March 31, 2013 totaled $1,028,000 as compared to $1,149,000 during the 2012 period. The decrease was due to the overall reduction in produced oil, gas and Ngl volumes at our East Texas fields during the period as compared to the first quarter of 2012.
General and administrative expenses during the three months ended March 31, 2013 totaled $4,716,000 as compared to $5,579,000 during the 2012 period. Included in general and administrative expenses was non-cash share-based compensation expense as follows (in thousands):

                                      Three Months Ended March 31,
                                       2013                 2012
Stock options:
Incentive Stock Options           $        (4 )       $            223
Non-Qualified Stock Options                69                      164
Restricted stock                          491                    1,536
Non-cash share based compensation $       556         $          1,923

General and administrative expenses decreased 15% during the three months ended March 31, 2013 as compared to the comparable period of 2012 primarily due to decreased non-cash share-based compensation expense during the 2013 period. We capitalized $3,111,000 of general and administrative costs during the three month period ended March 31, 2013 compared to $3,056,000 during the 2012 period. General and administrative expenses in 2013 are expected to be lower than in 2012 as a result of this decrease in non-cash share based compensation expense. Depreciation, depletion and amortization ("DD&A") expense on oil and gas properties for the three months ended March 31, 2013 totaled $12,611,000, or $1.53 per Mcfe, as compared to $14,979,000, or $1.83 per Mcfe, during the comparable 2012 period. The decrease in the per unit DD&A rate is primarily the result of the write-down of a portion of our evaluated oil and gas properties during 2012 in connection with ceiling test impairments.
At March 31, 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 $2.97 per Mcf of natural gas, $107.99 per barrel of oil, and $8.74 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 a ceiling test write-down of $20,111,000 during the three months ended March 31, 2012. Our cash flow hedges in place at March 31, 2012 increased the ceiling test write-down by approximately $1.2 million. No such ceiling test write-down occurred during 2013.

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Interest expense, net of amounts capitalized on unevaluated properties, totaled $2,864,000 during the three months ended March 31, 2013 as compared to $2,270,000 during the 2012 period. During the three month period ended March 31, 2013, our capitalized interest totaled $1,452,000 as compared to $1,850,000 during the 2012 period. The increase in interest expense was due to increased borrowings outstanding under our bank credit facility during the three month period ended March 31, 2013 as compared to the prior year period. Income tax expense (benefit) during the three months ended March 31, 2013 totaled $349,000 as compared to ($988,000) during the 2012 period. We typically provide for income taxes at a statutory rate of 35% adjusted for permanent differences expected to be realized, primarily statutory depletion, non-deductible stock compensation expenses and state income taxes.
As a result of 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 $50,860,000 as of March 31, 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 both March 31, 2013 and December 31, 2012, we had a working capital deficit of approximately $31 million. 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, 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 $14.0 million during the three months ended March 31, 2012 to $9.1 million during the 2013 period. The decrease in operating cash flow during 2013 as compared to 2012 was primarily attributable to the decrease in our accounts payable to vendors offset by the reduction in accounts receivable from our joint partners. 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 March 31, 2013, the estimated fair value of the Notes was $160.9 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 March 31, 2013, $1.3 million had been accrued in connection with the September 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 March 31, 2013 we had $60 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 $150 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 $300 million by either adding new lenders or increasing the commitments of existing lenders, subject to certain conditions. The

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next borrowing base redetermination is scheduled to occur by September 30, 2013. We or the lenders may request two additional borrowing base re-determinations 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 . . .

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