Search the web
Welcome, Guest
[Sign Out, My Account]
EDGAR_Online

Quotes & Info
Enter Symbol(s):
e.g. YHOO, ^DJI
Symbol Lookup | Financial Search
PQ > SEC Filings for PQ > Form 10-K on 5-Mar-2014All Recent SEC Filings

Show all filings for PETROQUEST ENERGY INC

Form 10-K for PETROQUEST ENERGY INC


5-Mar-2014

Annual Report


Item 7.
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, 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 Texas through 2013, we have invested approximately $1.1 billion into growing our longer life assets. During the ten year period ended December 31, 2013, we have realized a 95% drilling success rate on 918 gross wells drilled. Comparing 2013 metrics with those in 2003, the year we implemented our diversification strategy, we have grown production by 294% and estimated proved reserves by 262%. At December 31, 2013, 81% of our estimated proved reserves and 63% of our 2013 production were derived from our longer life assets.
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 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 the Mississippian Lime. During 2013, we closed the Gulf of Mexico Acquisition. The aggregate purchase


Table of Contents

price of the Gulf of Mexico Acquisition was $188.8 million and it contributed
30.5 Bcfe to our estimated proved reserves at December 31, 2013 as well as 4.5 Bcfe of production during 2013. As a result of the JDA, the Gulf of Mexico Acquisition and the success of our drilling programs in each of our operating areas, we have grown our estimated proved reserves by 69% and production by 11% since year end 2009, including a 36% increase in our oil and natural gas liquids production during 2013. Gulf of Mexico Acquisition

On July 3, 2013, we closed the Gulf of Mexico Acquisition for an aggregate cash purchase price of $188.8 million, reflecting an effective date of January 1, 2013. The Gulf of Mexico Acquisition was financed with the issuance of an additional $200 million in aggregate principal amount of our 10% Senior Notes due 2017. The transaction included 16 gross wells located on seven platforms.

During 2013, the Acquired Assets contributed 4.5 Bcfe of total production, including 235,000 barrels of oil, and added 30.5 Bcfe of estimated proved reserves as of December 31, 2013. As a result of the Gulf of Mexico Acquisition, our acreage position in the Gulf Coast Basin increased 23% to 46,801 net acres. See "Note 2 - Acquisition" in Item 8. Financial Statements and Supplementary Data for additional details related to this transaction.

We believe the Gulf of Mexico Acquisition 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. As evidenced by the larger percentage of our production and estimated proved reserves now located in our longer lived basins, we have successfully leveraged our Gulf Coast free cash flow to help fund our substantial diversification efforts over the past several years. 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. In addition, based upon our experience and successful track record in exploiting reservoirs in the Gulf Coast Basin and Gulf of Mexico, we believe that we will be able to create value above the current estimated proved reserves associated with the Acquired Assets. 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.
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 is also 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


Table of Contents

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 depreciation, depletion and amortization ("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 estimated 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
We seek to reduce our exposure to commodity price volatility by hedging a portion of our production through commodity derivative instruments. The estimated fair values of our commodity derivative instruments are recorded in the consolidated balance sheet. The changes in fair value of those derivative instruments that qualify for hedge accounting treatment are recorded in other comprehensive income (loss) until the hedged oil or 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 December 31, 2013, our derivative instruments were designated effective cash flow hedges.


Table of Contents

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.

                                    Year Ended December 31,
                             2013             2012             2011
Production:
Oil (Bbls)                    680,980          520,590          572,096
Gas (Mcf)                  29,225,843       27,466,228       24,462,933
Ngl (Mcfe)                  4,754,223        3,366,774        2,287,846
Total Production (Mcfe)    38,065,946       33,956,542       30,183,355
Sales:
Total oil sales         $  70,476,065    $  56,635,786    $  60,064,426
Total gas sales            87,449,370       63,535,262       78,664,373
Total ngl sales            24,878,243       21,262,236       21,756,917
Total oil and gas sales $ 182,803,678    $ 141,433,284    $ 160,485,716
Average sales prices:
Oil (per Bbl)           $      103.49    $      108.79    $      104.99
Gas (per Mcf)                    2.99             2.31             3.22
Ngl (per Mcfe)                   5.23             6.32             9.51
Per Mcfe                         4.80             4.17             5.32

The above sales and average sales prices include increases (reductions) to revenue related to the settlement of gas hedges of $1,098,000, $6,846,000 and $2,609,000, oil hedges of ($232,000), $1,529,000 and ($192,000), and Ngl hedges of $61,000, $722,000 and zero for the twelve months ended December 31, 2013, 2012 and 2011, respectively.
Comparison of Results of Operations for the Years Ended December 31, 2013 and 2012
Net income (loss) available to common stockholders totaled $8,943,000 and ($137,218,000) for the years ended December 31, 2013 and 2012, respectively. The primary fluctuations were as follows:
Production Total production increased 12% during the year ended December 31, 2013 as compared to the 2012 period. Gas production during the year ended December 31, 2013 increased 6% from the 2012 period. The increase in gas production was primarily the result of added production from 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. As a result of a full year of production from the wells acquired in the Gulf of Mexico Acquisition and increased drilling activity planned for 2014, we expect our average daily gas production in 2014 to increase as compared to 2013.
Oil production during the year ended December 31, 2013 increased 31% as compared to the 2012 period due primarily to added production from 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 a full year of production from the wells acquired in the Gulf of Mexico Acquisition, we expect our average daily oil production to be significantly higher during 2014 as compared to 2013.
Ngl production during the year ended December 31, 2013 increased 41% from the 2012 period 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 Gulf of Mexico Acquisition. Partially offsetting these increases were decreases as a result of normal production declines at certain of our legacy Gulf of Mexico fields. As a result of the increase in drilling activity planned for 2014 as well as a full year of production from


Table of Contents

the wells acquired in the Gulf of Mexico Acquisition, we expect our daily Ngl production for 2014 to increase significantly compared to that of 2013. Prices Including the effects of our hedges, average gas prices per Mcf for the year ended December 31, 2013 were $2.99 as compared to $2.31 for the 2012 period. Average oil prices per Bbl for the year ended December 31, 2013 were $103.49 as compared to $108.79 for the 2012 period and average Ngl prices per Mcfe were $5.23 for the year ended December 31, 2013, as compared to $6.32 for the 2012 period. Stated on an Mcfe basis, unit prices received during the year ended December 31, 2013 were 15% higher than the prices received during the 2012 period.
Revenue Including the effects of hedges, oil and gas sales during the twelve months ended December 31, 2013 increased 29% to $182,804,000, as compared to oil and gas sales of $141,433,000 during the 2012 period. The increased revenue during 2013 was primarily the result of higher average realized prices for our production during 2013 as well as increased production as discussed above. Expenses Lease operating expenses for the year ended December 31, 2013 totaled $43,743,000 as compared to $38,890,000 during the 2012 period. Per unit lease operating expenses totaled $1.15 per Mcfe during both of the twelve month periods ended December 31, 2013 and 2012. We expect the absolute amount of lease operating expenses to increase during 2014 as compared to 2013 as a result of the Gulf of Mexico Acquisition but we expect per unit lease operating costs to approximate per unit amounts in 2013.
Production taxes for the year ended December 31, 2013 totaled $3,950,000 as compared to $885,000 during the 2012 period. The significant reduction during the 2012 period 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 are receiving incrementally through June, 2015. 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 during 2014 as compared to 2013.
General and administrative expenses during the year ended December 31, 2013 totaled $26,512,000 as compared to $22,957,000 during the 2012 period. Included in general and administrative expenses was non-cash, share-based compensation expense as follows (in thousands):

                                       Year Ended December 31,
                                           2013               2012
Stock options:
Incentive Stock Options           $        310              $   786
Non-Qualified Stock Options                222                  660
Restricted stock                         3,684                5,464
Non-cash share-based compensation $      4,216              $ 6,910

General and administrative expenses increased 15% during the year ended December 31, 2013 as compared to the 2012 period. Included in general and administrative expenses during the 2013 period is $4,018,000 of transaction-related costs related to the Gulf of Mexico Acquisition. In addition, during 2013, we recognized approximately $895,000 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 $13,514,000 of general and administrative costs during the year ended December 31, 2013 as compared to $11,925,000 during the comparable 2012 period. General and administrative expenses in 2014 are expected to be lower than 2013 due to these non-recurring items.
DD&A expense on oil and gas properties for the year ended December 31, 2013 totaled $69,357,000, or $1.82 per Mcfe, as compared to $59,496,000, or $1.75 per Mcfe, during the comparable 2012 period. The increase in the per unit DD&A rate is primarily the result of the Gulf of Mexico Acquisition, which had a higher cost per unit as compared to our overall amortization base. After taking into effect the Gulf of Mexico Acquisition, we expect our DD&A rate for 2014 to be higher than the full year rate during 2013.
At December 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 $2.21 per Mcf of natural gas, $102.81 per barrel of oil, and $6.07 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 $137,100,000 during the year ended December 31, 2012. No such ceiling test write-down occurred during 2013.
Interest expense, net of amounts capitalized on unevaluated properties, totaled $21,886,000 during the year ended December 31, 2013, as compared to $9,808,000 during 2012. During the year ended December 31, 2013, our capitalized interest totaled $6,570,000


Table of Contents

as compared to $7,036,000 during the 2012 period. The increase in interest expense was a result of the issuance of an additional $200 million of 10% senior notes, which were used to finance the Gulf of Mexico Acquisition in addition to increased borrowings outstanding under our bank credit facility during 2013 as compared to 2012. As a result, we expect interest expense for 2014 to be higher than that of 2013.
Income tax expense during the year ended December 31, 2013 totaled $320,000, as compared to $1,636,000 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 during 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 $45,531,000 as of December 31, 2013.
Comparison of Results of Operations for the Years Ended December 31, 2012 and 2011
Net income (loss) available to common stockholders totaled ($137,218,000) and $5,409,000 for the years ended December 31, 2012 and 2011, respectively. The primary fluctuations were as follows:
Production Total production increased 13% during the year ended December 31, 2012 as compared to the 2011 period. Gas production during the year ended December 31, 2012 increased 12% from the 2011 period. The increase in gas production was primarily the result of the success of our drilling programs 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. Partially offsetting these increases were normal production declines particularly in our Gulf Coast region.
Oil production during the year ended December 31, 2012 decreased 9% as compared to the 2011 period 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, our Eagle Ford Shale field where five new wells commenced production during the third and fourth quarters of 2012 and at our Mississippian Lime field where initial oil production from our first wells began during the second quarter of 2012 with four additional wells beginning production during the fourth quarter. Additionally, oil production increased at our Ship Shoal field as a result of three successful recompletions performed during the fourth quarter of 2012.
Ngl production during the year ended December 31, 2012 increased 47% from the 2011 period due to the inception of production from our La Cantera field, the liquids rich portion of our Oklahoma properties, and an increase in production at our Carthage field in East Texas. These increases were partially offset by the normal production declines particularly in our Gulf Coast region. Prices Including the effects of our hedges, average gas prices per Mcf for the year ended December 31, 2012 were $2.31 as compared to $3.22 for the 2011 period. Average oil prices per Bbl for the year ended December 31, 2012 were $108.79 as compared to $104.99 for the 2011 period and average Ngl prices per Mcfe were $6.32 for the year ended December 31, 2012, as compared to $9.51 for the 2011 period. Stated on an Mcfe basis, unit prices received during the year ended December 31, 2012 were 22% lower than the prices received during the 2011 period.
Revenue Including the effects of hedges, oil and gas sales during the twelve months ended December 31, 2012 decreased 12% to $141,433,000, as compared to oil and gas sales of $160,486,000 during the 2011 period. The decreased revenue . . .

  Add PQ to Portfolio     Set Alert         Email to a Friend  
Get SEC Filings for Another Symbol: Symbol Lookup
Quotes & Info for PQ - All Recent SEC Filings
Copyright © 2014 Yahoo! Inc. All rights reserved. Privacy Policy - Terms of Service
SEC Filing data and information provided by EDGAR Online, Inc. (1-800-416-6651). All information provided "as is" for informational purposes only, not intended for trading purposes or advice. Neither Yahoo! nor any of independent providers is liable for any informational errors, incompleteness, or delays, or for any actions taken in reliance on information contained herein. By accessing the Yahoo! site, you agree not to redistribute the information found therein.