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| UPL > SEC Filings for UPL > Form 10-K on 20-Feb-2013 | All Recent SEC Filings |
20-Feb-2013
Annual Report
The following discussion of the financial condition and operating results of the Company should be read in conjunction with the consolidated financial statements and related notes of the Company, which are included in this report in Item 8, and the information set forth in Risk Factors under Item 1A. Except as otherwise indicated, all amounts are expressed in U.S. dollars.
Overview
Ultra Petroleum Corp. is an independent exploration and production company focused on developing its long-life natural gas reserves in the Green River Basin of Wyoming-the Pinedale and Jonah fields-and is in the early exploration and development stages in the Appalachian Basin of Pennsylvania. The Company operates in one industry segment, natural gas and oil exploration and development, with one geographical segment, the United States.
The Company currently conducts operations exclusively in the United States. Substantially all of its oil and natural gas activities are conducted jointly with others and, accordingly, amounts presented reflect only the Company's proportionate interest in such activities. Inflation has not had a material impact on the Company's results of operations. The Company continues to focus on improving its drilling and production results through gaining efficiencies with the use of advanced technologies, detailed technical analysis of its properties and leveraging its experience into improved operational efficiencies. Inflation is not expected to have a material impact on the Company's results of operations in the future.
The Company currently generates its revenue, earnings and cash flow primarily from the production and sales of natural gas and condensate from its properties in southwest Wyoming with an increasing portion of the Company's revenues coming from gas sales from wells located in the Appalachian Basin in Pennsylvania.
Part of the Company's business strategy includes proactive and regular review of its portfolio of investment opportunities with a focus on investments that produce positive returns. Accordingly, in response to the current low natural gas price environment during 2012, the Company reduced its net capital investments from $1.5 billion in 2011 to $615.2 million in 2012 by releasing all but two of its operated drilling rigs in Wyoming and reducing drilling activity in Pennsylvania.
The price of natural gas is a critical factor to the Company's business and the price of natural gas has declined significantly since the beginning of 2011. During 2012, the Company limited the impact of these low prices on its results by entering into swap agreements and/or fixed price forward physical delivery contracts for natural gas. The average price realization for the Company's natural gas during 2012 was $4.01 per Mcf, including realized gains and losses on commodity derivatives. During the quarter ended December 31, 2012, the average price realization for the Company's natural gas was $4.08 per Mcf, including realized gains and losses on commodity derivatives. The Company's average price realization for natural gas, excluding realized gains and losses on commodity derivatives, was $2.79 per Mcf and $3.33 per Mcf for the year and quarter ended December 31, 2012, respectively. Because of the Company's belief that overall domestic natural gas supply will decline and natural gas forward prices will increase in response, the Company has not hedged any of its forecast 2013 natural gas production. (See Note 7).
Mission and Strategy
Ultra's mission is to profitably grow an upstream oil and gas company for the long-term benefit of its shareholders. Ultra's strategy includes building a robust portfolio of high return investment opportunities, maintaining a disciplined approach to capital investment, maximizing earnings and cash flows by controlling costs and maintaining financial flexibility. Consistent with this mission and strategy, the Company significantly reduced its activity during 2012 as a result of the low prevailing natural gas prices during 2012. As a result of this reduced activity, the number of wells drilled and completed by the Company was lower in 2012 than in some
prior years. In addition, as a result of the low gas prices, the Company was required to record a $2.9 billion non-cash, ceiling test write-down of the carrying value of its oil and gas properties, and the Company's proved reserves were reduced to 3.08 Tcfe at December 31, 2012 from 4.98 Tcfe at December 31, 2011. For additional information about steps the Company is taking to address low natural gas prices, see the "Marketing and Pricing" section of Item 1. Business.
Because dry natural gas drilling activities were significantly reduced by most oil and gas operators during 2012, the Company expects natural gas supply to decline. As a result, the Company believes the current low natural gas prices are unsustainable, and the Company expects natural gas prices to improve over the next two years. If natural gas prices recover as the Company expects, the Company should be able to restore its proved undeveloped reserves to at least prior prevailing levels. The reduction in proved reserves reflected in the year-end 2012 report is not the result of any change in the geologic prospectivity of the Company's properties.
As required by SEC regulations, the Company used a calculated weighted average natural gas sales price of $2.63 per Mcf and $4.04 per Mcf for estimating its proved reserves at December 31, 2012 and 2011, respectively. The lower gas price for the 2012 reserves negatively impacted the Company in two ways. First, some of its 2011 proved reserves are uneconomic at the 2012 SEC gas price. Second, some of its 2011 proved undeveloped reserves were reclassified as unproven properties in 2012 because the 2012 SEC gas price reduced capital available for the Company to drill its proved undeveloped properties.
High Return Portfolio. Ultra seeks to maintain a portfolio of properties that provide long-term, profitable growth through development in areas that support sustainable, lower-risk, repeatable, high return drilling projects. The Company continually evaluates opportunities for the acquisition, exploration and development of additional oil and natural gas properties that afford risk-adjusted returns in excess of or equal to its current set of investment alternatives.
Disciplined Capital Investment. Part of the Company's business strategy includes proactive and regular review of its portfolio of investment opportunities with a focus on investments that produce positive returns in order to optimize return to its shareholders. Accordingly, in response to the current low natural gas price environment, the Company reduced capital expenditures by reducing the number of drilling rigs operating in its Wyoming fields, and the Company is encouraging the parties operating projects on its behalf in Pennsylvania to reduce their activity as well. Reductions in the Company's activity resulted in reduced capital spending during the current year as compared to the prior year.
Low Cost Producer. Ultra strives to maintain one of the lowest cost structures in the industry in terms of both adding and producing oil and natural gas reserves. The Company continues to focus on improving its drilling and production results through the use of advanced technologies and detailed technical analysis of its properties.
Financial Flexibility. Preserving financial flexibility and a strong balance sheet are also strategic to Ultra's business philosophy. Maintaining financial discipline enables the Company to capitalize on the flexibility of its portfolio.
Critical Accounting Policies
The discussion and analysis of the Company's financial condition and results of operations is based upon consolidated financial statements, which have been prepared in accordance with U.S. GAAP. In addition, application of GAAP requires the use of estimates, judgments and assumptions that affect the reported amounts of assets and liabilities as of the date of the financial statements as well as the revenues and expenses reported during the period. Changes in these estimates related to judgments and assumptions will occur as a result of future events, and, accordingly, actual results could differ from amounts estimated. Set forth below is a discussion of the critical accounting policies used in the preparation of our financial statements which we believe involve the most complex or subjective decisions or assessments.
Oil and Gas Reserves. The reserve estimates presented herein were made in accordance with oil and gas reserve estimation and disclosure authoritative accounting guidance according to Financial Accounting Standards Board ("FASB") Accounting Standards Codification ("ASC") Topic 932, Extractive Activities - Oil and Gas ("FASB ASC 932") as updated in order to align the reserve calculation and disclosure requirements with those in SEC Release No. 33-8995.
The Company utilizes reliable technology such as seismic data and interpretation, wireline formation tests, geophysical logs and core data to assess its resources. However, none of these technologies have contributed to a material addition to the proved reserves in this report. The proved reserves estimates are prepared by Netherland, Sewell & Associates, Inc., an independent, third-party engineering firm.
Estimates of proved crude oil and natural gas reserves significantly affect the Company's depreciation, depletion and amortization ("DD&A") expense. For example, if estimates of proved reserves decline, the Company's DD&A rate will increase, resulting in a decrease in net income. A decline in estimates of proved reserves may result from a number of factors including lower prices, evaluation of additional operating history, mechanical problems on our wells and catastrophic events. Lower prices also make it uneconomical to drill wells or produce from fields with high operating costs.
The Company's proved reserves are a function of many assumptions, all of which could deviate materially from actual results. As a result, the estimates of proved reserves could vary over time, and could vary from actual results.
Full Cost Method of Accounting. The Company uses the full cost method of accounting for oil and gas exploration and development activities as defined by SEC Release No. 33-8995 and FASB ASC 932. Under the full cost method of accounting, all costs associated with the exploration for and development of oil and gas reserves are capitalized on a country-by-country basis. All costs incurred in the acquisition, exploration and development of properties (including costs of surrendered and abandoned leaseholds, delay lease rentals, dry holes and overhead related to exploration and development activities) are capitalized. The sum of net capitalized costs and estimated future development costs of oil and natural gas properties for each full cost center are depleted using the units-of-production method. Changes in estimates of proved reserves, future development costs or asset retirement obligations are accounted for prospectively in our depletion calculation.
Under the full cost method, costs of unevaluated properties and major development projects expected to require significant future costs may be excluded from capitalized costs being amortized. The Company excludes significant costs until proved reserves are found or until it is determined that the costs are impaired. Excluded costs, if any, are reviewed quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the capitalized costs being amortized in the appropriate full cost pool.
Write-down of Oil and Gas Properties. Companies that use the full cost method of accounting for oil and natural gas exploration and development activities are required to perform a ceiling test calculation each quarter. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is performed quarterly, on a country-by-country basis, utilizing the average of prices in effect on the first day of the month for the preceding twelve month period. The ceiling limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved crude oil and natural gas reserves discounted at 10% plus the lower of cost or market value of unproved properties less any associated tax effects. If such capitalized costs exceed the ceiling, the Company will record a write-down to the extent of such excess as a non-cash charge to earnings. Any such write-down will reduce earnings in the period of occurrence and result in a lower DD&A rate in future periods. A write-down may not be reversed in future periods even though higher oil and natural gas prices may subsequently increase the ceiling.
The calculation of the ceiling test is based upon estimates of proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves, in projecting the future rates of production and in the timing of development activities. The accuracy of any reserve estimate is a function of the quality of
available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered.
During 2012, the Company recorded a $2.9 billion non-cash write-down of the carrying value of the Company's proved oil and gas properties as a result of ceiling test limitations, which is reflected with ceiling test and other impairments in the accompanying Consolidated Statements of Operations. The ceiling test was calculated based upon the average of quoted market prices in effect on the first day of the month for the preceding twelve month period at December 31, 2012, September 30, 2012 and June 30, 2012 of $2.76 per MMBtu, $2.83 per MMBtu and $3.15 per MMBtu for Henry Hub natural gas, respectively, and $94.71 per barrel, $94.97 per barrel and $95.67 per barrel for West Texas Intermediate oil, respectively, adjusted for market differentials. The Company did not have any write-downs related to the full cost ceiling limitation in 2011 or 2010.
Asset Retirement Obligation. The Company's asset retirement obligations ("ARO") consist primarily of estimated costs of dismantlement, removal, site reclamation and similar activities associated with its oil and natural gas properties. FASB ASC Topic 410, Asset Retirement and Environmental Obligations ("FASB ASC 410") requires that the discounted fair value of a liability for an ARO be recognized in the period in which it is incurred with the associated asset retirement cost capitalized as part of the carrying cost of the oil and natural gas asset. The recognition of an ARO requires that management make numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an ARO, estimated probabilities, amounts and timing of settlements; the credit-adjusted, risk-free rate to be used; inflation rates, and future advances in technology. In periods subsequent to initial measurement of the ARO, the Company must recognize period-to-period changes in the liability resulting from the passage of time and revisions to either the timing or the amount of the original estimate of undiscounted cash flows. Increases in the ARO liability due to passage of time impact net income as accretion expense. The related capitalized costs, including revisions thereto, are charged to expense through DD&A.
Entitlements Method of Accounting for Oil and Natural Gas Sales. The Company generally sells natural gas and condensate under both long-term and short-term agreements at prevailing market prices and under multi-year contracts that provide for a fixed price of oil and natural gas. The Company recognizes revenues when the oil and natural gas is delivered, which occurs when the customer has taken title and has assumed the risks and rewards of ownership, prices are fixed or determinable and collectability is reasonably assured. The Company accounts for oil and natural gas sales using the "entitlements method." Under the entitlements method, revenue is recorded based upon the Company's ownership share of volumes sold, regardless of whether it has taken its ownership share of such volumes. The Company records a receivable or a liability to the extent it receives less or more than its share of the volumes and related revenue.
Make-up provisions and ultimate settlements of volume imbalances are generally governed by agreements between the Company and its partners with respect to specific properties or, in the absence of such agreements, through negotiation. The value of volumes over- or under-produced can change based on changes in commodity prices. The Company prefers the entitlements method of accounting for oil and natural gas sales because it allows for recognition of revenue based on its actual share of jointly owned production, results in better matching of revenue with related operating expenses, and provides balance sheet recognition of the estimated value of product imbalances.
Valuation of Deferred Tax Assets. The Company uses the asset and liability method of accounting for income taxes. Under this method, future income tax assets and liabilities are determined based on differences between the financial statement carrying values and their respective income tax basis (temporary differences).
To assess the realization of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences
become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment.
As a result of the tax effect of the ceiling test and other impairments recorded during the year ended December 31, 2012, the Company's previously recorded net deferred tax liability fully reversed into a net deferred tax asset. The Company has recorded a full valuation allowance against its net deferred tax asset balance of $449.8 million as of December 31, 2012. This valuation allowance may be reversed in future periods against future taxable income.
Derivative Instruments and Hedging Activities. The Company follows FASB ASC Topic 815, Derivatives and Hedging ("FASB ASC 815"). The Company records the fair value of its commodity derivatives as an asset or liability on the Consolidated Balance Sheets, and records the changes in the fair value of its commodity derivatives in the Consolidated Statements of Operations as an unrealized gain or loss on commodity derivatives.
Fair Value Measurements. The Company follows FASB ASC Topic 820, Fair Value Measurements and Disclosures ("FASB ASC 820"). Under FASB ASC 820, fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at measurement date and establishes a three level hierarchy for measuring fair value. The valuation assumptions the Company has used to measure the fair value of its commodity derivatives were observable inputs based on market data obtained from independent sources and are considered Level 2 inputs (quoted prices for similar assets, liabilities (adjusted) and market-corroborated inputs). At December 31, 2012, the Company did not have any open commodity derivative contracts. See Note 8 for additional information.
In consideration of counterparty credit risk, the Company assessed the possibility of whether each counterparty to the derivative would default by failing to make any contractually required payments as scheduled in the derivative instrument in determining the fair value. Additionally, the Company considers that it is of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions.
The Company recognized impairments of $92.5 million during the year ended December 31, 2012 related to the decline in fair value as defined in FASB ASC 820 as a result of forecast decreased throughput volumes on its gathering facilities in Pennsylvania due to the decline in commodity prices. These facilities are included in Property, Plant and Equipment in the Consolidated Balance Sheets and were impaired to a fair value of $82.6 million based on the income approach, estimated using Level 3 fair value inputs.
Legal, Environmental and Other Contingencies. A provision for legal, environmental and other contingencies is charged to expense when the loss is probable and the cost can be reasonably estimated. Determining when expenses should be recorded for these contingencies and the appropriate amounts for accrual is a complex estimation process that includes the subjective judgment of management. In many cases, management's judgment is based on interpretation of laws and regulations, which can be interpreted differently by regulators and/or courts of law. The Company's management closely monitors known and potential legal, environmental and other contingencies and periodically determines when the Company should record losses for these items based on information available to the Company.
Share-Based Payment Arrangements. The Company follows FASB ASC Topic 718, Compensation - Stock Compensation ("FASB ASC 718") which requires the measurement and recognition of compensation expense for all share-based payment awards made to employees and directors, including employee stock options, based on estimated fair values. Share-based compensation expense recognized under FASB ASC 718 for the years ended December 31, 2012, 2011 and 2010 was $10.8 million, $13.9 million and $12.9 million, respectively. See Note 6 for additional information.
Conversion of Barrels of Oil to Mcfe of Gas. The Company converts Bbls of oil and other liquid hydrocarbons to Mcfe at a ratio of one Bbl of oil or liquids to six Mcfe. This conversion ratio, which is typically used in the oil and gas industry, represents the approximate energy equivalent of a barrel of oil or other liquids to an Mcf of natural gas. The sales price of one Bbl of oil or liquids has been much higher than the sales price of six Mcf of natural gas over the last several years, so a six to one conversion ratio does not represent the economic equivalency of six Mcf of natural gas to a Bbl of oil or other liquids.
Recent Accounting Pronouncements. In May 2011, the FASB issued ASU No. 2011-04, which amends FASB ASC 820. The amended guidance clarifies many requirements in U.S. GAAP for measuring fair value and for disclosing information about fair value measurements. Additionally, the amendments clarify the FASB's intent about the application of existing fair value measurement requirements. The guidance provided in ASU No. 2011-04 is effective for interim and annual periods beginning after December 15, 2011. The adoption of this amendment did not have a material impact on the Company's consolidated financial statements.
Results of Operations - Year Ended December 31, 2012 vs. Year Ended December 31, 2011
During the year ended December 31, 2012, production increased on a gas equivalent basis to 257.0 Bcfe from 245.3 Bcfe for the same period in 2011 as a result of wells put on production in 2012. Realized natural gas prices, including realized gain and loss on commodity derivatives, decreased to $4.01 per Mcf during the year ended December 31, 2012 as compared to $5.05 per Mcf during 2011. During the year ended December 31, 2012, the Company's average price for natural gas was $2.79 per Mcf, excluding realized gains and losses on commodity derivatives as compared to $4.15 per Mcf for the same period in 2011. The decrease in average natural gas prices largely contributed to a 26% decrease in revenues for the year ended December 31, 2012 to $810.0 million as compared to $1.1 billion in 2011.
Lease operating expenses ("LOE") increased to $64.5 million for the year ended December 31, 2012 compared to $51.8 million during the same period in 2011 primarily due to increased well counts resulting from the Company's drilling program. On a unit of production basis, LOE costs increased to $0.25 per Mcfe at December 31, 2012 compared to $0.21 per Mcfe at December 31, 2011 as a result of higher lease operating expense on non-operated wells in Pennsylvania.
During the year ended December 31, 2012, production taxes were $60.8 million compared to $97.1 million during the same period in 2011, or $0.24 per Mcfe, compared to $0.40 per Mcfe. Production taxes are primarily calculated based on a percentage of revenue from production in Wyoming after certain deductions and were 7.5% of revenues for the year ended 2012 and 8.8% for the same period in 2011. In addition, the year ended December 31, 2012 includes charges related to Pennsylvania impact fees totaling $5.6 million while the period ended December 31, 2011 did not include any charges related to impact fees in Pennsylvania. The decrease in per unit taxes is primarily attributable to decreased sales revenues as a result of decreased natural gas prices, excluding the effects of commodity derivatives, during the year December 31, 2012 as compared to the same period in 2011.
Gathering fees increased to $59.0 million for the year ended December 31, 2012 compared to $56.5 million during the same period in 2011 largely due to increased production volumes. On a per unit basis, gathering fees remained flat at $0.23 per Mcfe for the year ended December 31, 2012 and 2011.
The Company incurred firm transportation charges totaling $84.5 million for the period ended December 31, 2012 as compared to $64.2 million for the same period in 2011 in association with REX pipeline charges. On a per unit basis, transportation charges increased to $0.33 per Mcfe (on total company volumes) for the period ended December 31, 2012 as compared to $0.26 for the same period in 2011 primarily due to demand charges associated with the additional capacity of 50 MMMBtu per day secured on the REX pipeline system beginning in January 2012.
DD&A expenses increased to $389.0 million during the period ended December 31, 2012 from $346.4 million for the same period in 2011, attributable primarily to increased production volumes and a higher depletion rate. On a unit of production basis, DD&A increased to $1.51 per Mcfe at December 31, 2012 from $1.41 at December 31, 2011 primarily as a result of increased costs in Pennsylvania.
The Company recorded a $2.9 billion non-cash write-down of the carrying value of its proved oil and natural gas properties for the period ended December 31, 2012 as a result of ceiling test limitations, which is reflected as ceiling test and other impairments in the accompanying Consolidated Statements of Operations. The ceiling test was calculated based upon the average of quoted market prices in effect on the first day of the month for the preceding twelve month period at December 31, 2012, September 30, 2012 and June 30, 2012 of $2.76 per MMBtu, $2.83 per MMBtu and $3.15 per MMBtu for Henry Hub natural gas, respectively, and $94.71 per barrel, $94.97 per barrel and $95.67 per barrel for West Texas Intermediate oil, respectively, adjusted for market differentials. The . . .
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