Item 1 for a discussion of these regulations.
Restrictive Covenants. Our ability to incur debt and to make certain types of investments is subject to certain restrictive covenants in our various debt instruments. Among other requirements, our revolving credit agreement and our senior notes specify a minimum annual coverage ratio of operating cash flow to interest expense for the trailing four quarters of 2.8 to 1.0 and an asset coverage ratio of the present value of proved reserves plus working capital to debt of 1.75 to 1.0. Our revolving credit agreement also requires us to maintain a current ratio of 1.0 to 1.0. At December 31, 2011, we were in compliance in all material respects with all restrictive covenants on both the revolving credit agreement and senior notes. In the unforeseen event that we fail to comply with these covenants, we may apply for a temporary waiver with the lender, which, if granted, would allow us a period of time to remedy the situation.
Operating Risks and Insurance Coverage. Our business involves a variety of operating risks. See "Risk Factors-We face a variety of hazards and risks that could cause substantial financial losses" in Item 1A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Market Risk
Our primary market risk is exposure to oil and natural gas prices. Realized prices are mainly driven by worldwide prices for oil and market prices for North American natural gas production. Commodity prices can be volatile and unpredictable.
Derivative Instruments and Hedging Activity
Our hedging strategy is designed to reduce the risk of price volatility for our production in the natural gas and crude oil markets. A hedging committee that consists of members of senior management oversees our hedging activity. Our hedging arrangements apply to only a portion of our production and provide only partial price protection. These hedging arrangements limit the benefit to
us of increases in prices, but offer protection in the event of price declines. Further, if our counterparties defaulted, this protection might be limited as we might not receive the benefits of the hedges. Please read the discussion below as well as Note 12 of the Notes to the Consolidated Financial Statements for a more detailed discussion of our hedging arrangements.
Periodically, we enter into derivative commodity instruments to hedge our exposure to price fluctuations on natural gas and crude oil production. Our credit agreement restricts our ability to enter into commodity hedges other than to hedge or mitigate risks to which we have actual or projected exposure or as permitted under our risk management policies and not subjecting us to material speculative risks. All of our derivatives are used for risk management purposes and are not held for trading purposes. As of December 31, 2011, we had 37 derivative contracts open: 23 natural gas price swap arrangements, six natural gas basis swaps arrangements, three crude oil price swap arrangements and five natural gas collar arrangements. During 2011, we entered into 31 new derivative contracts covering anticipated natural gas and crude oil production for 2011, 2012, and 2013.
As of December 31, 2011, we had the following outstanding commodity derivatives:
The amounts set forth under the net unrealized gain / (loss) column in the tables above represent our total unrealized derivative position at December 31, 2011 and exclude the impact of nonperformance risk of $1.4 million. Nonperformance risk was primarily evaluated by reviewing credit default swap spreads for the various financial institutions in which we have derivative transactions, while our non-performance risk is evaluated using a market credit spread provided by our bank.
From time to time, we enter into natural gas and crude oil swap and collar agreements with counterparties to hedge price risk associated with a portion of our production. These cash flow hedges are not held for trading purposes. Under these price swaps, we receive a fixed price on a notional quantity of natural gas or crude oil in exchange for paying a variable price based on a market-based index, such as the NYMEX gas and crude oil futures. Under the collar agreements, if the index price rises above the ceiling price, we pay the counterparty. If the index price falls below the floor price, the counterparty pays us.
We had natural gas price swaps covering 74.9 Bcf, or 42%, of our 2011 natural gas production at an average price of $5.30 per Mcf.
We had one crude oil swap covering 275 Mbbl, or 20%, of our 2011 crude oil production, at an average price of $106.20 per Bbl.
During 2011, crude oil collars covered 365 Mbbl, or 26% of total crude oil production, at an average price of $90.88 per Bbl.
We are exposed to market risk on derivative instruments to the extent of changes in market prices of natural gas and crude oil. However, the market risk exposure on these derivative contracts is
generally offset by the gain or loss recognized upon the ultimate sale of the commodity. Although notional contract amounts are used to express the volume of natural gas agreements, the amounts that can be subject to credit risk in the event of non-performance by third parties are substantially smaller. We do not anticipate any material impact on our financial results due to non-performance by third parties. Our primary derivative contract counterparties are Bank of America, Bank of Montreal, BNP Paribas, Goldman Sachs and JPMorgan.
The preceding paragraphs contain forward-looking information concerning future production and projected gains and losses, which may be impacted both by production and by changes in the future market prices of energy commodities. See "Forward-Looking Information" for further details.
Fair Market Value of Financial Instruments
The estimated fair value of financial instruments is the amount at which the instrument could be exchanged currently between willing parties. The carrying amounts reported in the Consolidated Balance Sheet for cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the short-term maturities of these instruments.
The fair value of long-term debt is the estimated cost to acquire the debt, including a credit spread for the difference between the issue rate and the period end market rate. The credit spread is our default or repayment risk. The credit spread (premium or discount) is determined by comparing our fixed-rate notes and credit facility to new issuances (secured and unsecured) and secondary trades of similar size and credit statistics for both public and private debt. The fair value of all of the fixed-rate notes and the credit facility is based on interest rates currently available to us.
We use available market data and valuation methodologies to estimate the fair value of debt. The carrying amounts and fair values of long-term debt are as follows:
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of Cabot Oil & Gas Corporation:
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, stockholders' equity, comprehensive income and of cash flows present fairly, in all material respects, the financial position of Cabot Oil & Gas Corporation and its subsidiaries (the "Company") at December 31, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management's Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements and on the Company's internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers LLP
Houston, Texas
February 28, 2012
CABOT OIL & GAS CORPORATION
CONSOLIDATED STATEMENT OF OPERATIONS
The accompanying notes are an integral part of these consolidated financial statements.
CABOT OIL & GAS CORPORATION
CONSOLIDATED BALANCE SHEET
The accompanying notes are an integral part of these consolidated financial statements.
CABOT OIL & GAS CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
The accompanying notes are an integral part of these consolidated financial statements.
CABOT OIL & GAS CORPORATION
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
The accompanying notes are an integral part of these consolidated financial statements.
CABOT OIL & GAS CORPORATION
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
The accompanying notes are an integral part of these consolidated financial statements.
CABOT OIL & GAS CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
1. Summary of Significant Accounting Policies
Basis of Presentation and Nature of Operations
Cabot Oil & Gas Corporation and its subsidiaries are engaged in the development, exploitation, exploration, production and marketing of natural gas, crude oil and, to a lesser extent, natural gas liquids exclusively within the continental United States. The Company also transports, stores, gathers and purchases natural gas for resale. The Company's exploration and development activities are concentrated in areas with known hydrocarbon resources, which are conducive to multi-well, repeatable drilling programs.
The Company operates in one segment, natural gas and oil development, exploitation and exploration. The Company's oil and gas properties are managed as a whole rather than through discrete operating segments or business units. Operational information is tracked by geographic area; however, financial performance is assessed as a single enterprise and not on a geographic basis. Allocation of resources is made on a project basis across the Company's entire portfolio without regard to geographic areas.
The consolidated financial statements contain the accounts of the Company and its subsidiaries after eliminating all significant intercompany balances and transactions. Certain reclassifications have been made to prior year statements to conform with current year presentation. These reclassifications have no impact on net income.
On January 3, 2012, the Board of Directors declared a 2-for-1 split of the Company's common stock in the form of a stock dividend. The stock dividend was distributed on January 25, 2012 to shareholders of record as of January 17, 2012. All common stock accounts and per share data have been retroactively adjusted to give effect to the 2-for-1 split of the Company's common stock.
Recently Issued Accounting Pronouncements
In May 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2011-04, "Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs." The amendments in this update generally represent clarifications of Topic 820, but also include some instances where a particular principle or requirement for measuring fair value or disclosing information about fair value measurements has changed. This update results in common principles and requirements for measuring fair value and for disclosing information about fair value measurements in accordance with U.S. GAAP and IFRS. The amendments in this update are to be applied prospectively. The amendments are effective for interim and annual periods beginning after December 15, 2011. Early application is not permitted. The Company does not expect this guidance to have a significant impact on its consolidated financial position, results of operations or cash flows.
In June 2011, the FASB issued ASU No. 2011-05, "Presentation of Comprehensive Income." This update was amended in December 2011 by ASU No. 2011-12, "Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05." This update defers only those changes in update 2011-05 that relate to the presentation of reclassification adjustments. All other requirements in update 2011-05 are not affected by this update, including the requirement to report comprehensive income either in a single continuous financial statement or in two separate but consecutive financial statements. ASU No. 2011-05 and 2011-12 are effective for fiscal years (including
CABOT OIL & GAS CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
1. Summary of Significant Accounting Policies (Continued)
interim periods) beginning after December 15, 2011. The Company does not expect this guidance to have a significant impact on its consolidated financial position, results of operations or cash flows.
In December 2011, the FASB issued ASU No. 2011-11, "Disclosures about Offsetting Assets and Liabilities." The amendments in this update require enhanced disclosures around financial instruments and derivative instruments that are either (1) offset in accordance with either ASC 210-20-45 or ASC 815-10-45 or (2) subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset in accordance with either ASC 210-20-45 or ASC 815-10-45. An entity should provide the disclosures required by those amendments retrospectively for all comparative periods presented. The amendments are effective during interim and annual periods beginning on or after January 1, 2013. The Company does not expect this guidance to have any impact on its consolidated financial position, results of operations or cash flows.
Cash and Cash Equivalents
The Company considers all highly liquid short-term investments with original maturities of three months or less to be cash equivalents. Cash and cash equivalents were primarily concentrated in one financial institution at December 31, 2011 and 2010. The Company periodically assesses the financial condition of these institutions and considers any possible credit risk to be minimal.
Inventories
Inventories are comprised of natural gas in storage, tubular goods and well equipment and pipeline imbalances. All inventory balances are carried at the lower of average cost or market.
Natural gas gathering and pipeline operations normally include imbalance arrangements with the pipeline. The volumes of natural gas due to or from the Company under imbalance arrangements are recorded at actual selling or purchase prices, as the case may be, and are adjusted monthly to reflect market changes. The net pipeline imbalance is included in inventory in the Consolidated Balance Sheet.
Allowance for Doubtful Accounts
The Company records an allowance for doubtful accounts for receivables that the Company determines to be uncollectible based on the specific identification basis. The allowance for doubtful accounts, which is netted against Accounts Receivable in the Consolidated Balance Sheet, was $3.3 million and $4.1 million at December 31, 2011 and 2010, respectively.
Accounts Payable
This account may include credit balances from outstanding checks in zero balance cash accounts. These credit balances are referred to as book overdrafts and are included as a component of Accounts Payable on the Consolidated Balance Sheet. There were no credit balances from outstanding checks in zero balance cash accounts included in Accounts Payable at December 31, 2011 and 2010 as sufficient cash was available for offset.
Properties and Equipment
The Company uses the successful efforts method of accounting for oil and gas producing activities. Under this method, acquisition costs for proved and unproved properties are capitalized when incurred.
CABOT OIL & GAS CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
1. Summary of Significant Accounting Policies (Continued)
Exploration costs, including geological and geophysical costs, the costs of carrying and retaining unproved properties and exploratory dry hole drilling costs, are expensed. Development costs, including the costs to drill and equip development wells and successful exploratory drilling costs to locate proved reserves are capitalized.
Exploratory drilling costs are capitalized when incurred pending the determination of whether a well has found proved reserves. The determination is based on a process which relies on interpretations of available geologic, geophysical, and engineering data. If a well is determined to be successful, the capitalized drilling costs will be reclassified as part of the cost of the well. If a well is determined to be unsuccessful, the capitalized drilling costs will be charged to exploration expense in the period the determination is made. If an exploratory well requires a major capital expenditure before production can begin, the cost of drilling the exploratory well will continue to be carried as an asset pending determination of whether proved reserves have been found only as long as: i) the well has found a sufficient quantity of reserves to justify its completion as a producing well if the required capital expenditure is made and ii) drilling of the additional exploratory wells is under way or firmly planned for the near future. If drilling in the area is not under way or firmly planned, or if the well has not found a commercially producible quantity of reserves, the exploratory well is assumed to be impaired and its costs are charged to exploration expense.
Development costs of proved oil and gas properties, including estimated dismantlement, restoration and abandonment costs and acquisition costs, are depreciated and depleted on a field basis by the units-of-production method using proved developed and proved reserves, respectively. Properties related to gathering and pipeline systems and equipment are depreciated using the straight-line method based on estimated useful lives ranging from 10 to 25 years. Generally pipeline and transmission systems are depreciated over 12 to 25 years, gathering and compression equipment is depreciated over 10 years and storage equipment and facilities are depreciated over 10 to 16 years. Buildings are depreciated on a straight-line basis over 25 to 40 years. Certain other assets are depreciated on a straight-line basis over 3 to 10 years.
Costs of retired, sold or abandoned properties that make up a part of an amortization base (partial field) are charged to accumulated depreciation, depletion and amortization if the units-of-production rate is not significantly affected. Accordingly, a gain or loss, if any, is recognized only when a group of proved properties (entire field) that make up the amortization base has been retired, abandoned or sold.
The Company evaluates its oil and gas properties and other assets for impairment whenever events or changes in circumstances indicate an asset's carrying amount may not be recoverable. The Company compares expected undiscounted future cash flows to the net book value of the asset. If the future undiscounted expected cash flows, based on estimates of future crude oil and natural gas prices, operating costs and anticipated production from proved reserves are lower than the net book value of the asset, the capitalized cost is reduced to fair value. Commodity pricing is estimated by using a combination of assumptions management uses in its budgeting and forecasting process as well as historical and current prices adjusted for geographical location and quality differentials, as well as other factors that management believes will impact realizable prices. Fair value is calculated by discounting the future cash flows. The discount factor used is based on rates utilized by market participants that are commensurate with the risks inherent in the development and production of the underlying natural gas and crude oil.
CABOT OIL & GAS CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
1. Summary of Significant Accounting Policies (Continued)
Costs attributable to the Company's unproved properties are not subject to the impairment analysis described above; however, a portion of the costs associated with such properties is subject to amortization based on past drilling and exploration experience and average property lives. Average property lives are determined on a geographical basis and based on the estimated life of unproved property leasehold rights. During 2011, 2010 and 2009, amortization associated with the Company's unproved properties was $32.5 million, $47.6 million and $30.0 million, respectively, and is included in Depreciation, Depletion, and Amortization in the Consolidated Statement of Operations.
Asset Retirement Obligations
The Company records the fair value of a liability for an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated asset retirement cost is capitalized as part of the carrying amount of the long-lived asset. Subsequently, the asset retirement cost is allocated to expense using a systematic and rational method over the asset's useful life. The majority of the asset retirement obligations recorded by the Company relate to the plugging and abandonment of oil and gas wells. However, liabilities are also recorded for meter stations, pipelines, processing plants and compressors. At December 31, 2011, there were no assets legally restricted for purposes of settling asset retirement obligations.
Additional retirement obligations increase the liability associated with new oil and gas wells and other facilities as these obligations are incurred. Accretion expense is included in Depreciation, Depletion and Amortization expense on the Company's Consolidated Statement of Operations.
Risk Management Activities
From time to time, the Company enters into derivative contracts, such as natural gas and crude oil price swaps or zero-cost price collars, as a hedging strategy to manage commodity price risk associated with its production or other contractual commitments. All hedge transactions are subject to the Company's risk management policy which does not permit speculative trading activities. Gains or losses on these hedging activities are generally recognized over the period that its production or other underlying commitment is hedged as an offset to the specific hedged item. Cash flows related to any recognized gains or losses associated with these hedges are reported as cash flows from operations. If a hedge is terminated prior to expected maturity, gains or losses are deferred and included in income in the same period that the underlying production or other contractual commitment is delivered. Unrealized gains or losses associated with any derivative contract not considered a hedge are recognized currently in the results of operations.
When the designated item associated with a derivative instrument matures or is sold, extinguished or terminated, derivative gains or losses are recognized as part of the gain or loss on the sale or settlement of the underlying item. For example, in the case of natural gas price hedges, the gain or loss is reflected in natural gas revenue. When a derivative instrument is associated with an anticipated transaction that is no longer expected to occur or if the hedge is no longer effective, the gain or loss on the derivative is recognized currently in the results of operations to the extent the market value changes in the derivative have not been offset by the effects of the price changes on the hedged item since the inception of the hedge.
Effective January 1, 2009, the Company adopted the amended disclosure requirements prescribed in ASC 815, "Derivatives and Hedging."
CABOT OIL & GAS CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
1. Summary of Significant Accounting Policies (Continued)
Revenue Recognition
Gas Imbalances
The Company applies the sales method of accounting for natural gas revenue. Under this method, revenues are recognized based on the actual volume of natural gas sold to purchasers. Natural gas production operations may include joint owners who take more or less than the production volumes entitled to them on certain properties. Production volume is monitored to minimize these natural gas imbalances. A natural gas imbalance liability is recorded at the actual price realized upon the gas sale in Accounts Payable in the Consolidated Balance Sheet if the Company's excess takes of natural gas exceed its estimated remaining proved developed reserves for these properties.
Brokered Natural Gas Margin
The revenues and expenses related to brokering natural gas are reported gross as part of Operating Revenues and Operating Expenses in accordance with ASC 605-45, "Revenue Recognition: Principle Agent Considerations". The Company realizes brokered margin as a result of buying and selling natural gas utilizing separate purchase and sale transactions, typically with separate counterparties, whereby the Company and/or the counterparty takes title to the natural gas purchased or sold. The Company realized $7.4 million, $8.8 million and $8.3 million of brokered natural gas margin in 2011, 2010 and 2009, respectively.
Natural Gas Measurement
The Company records estimated amounts for natural gas revenues and natural gas purchase costs based on volumetric calculations under its natural gas sales and purchase contracts. Variances or imbalances resulting from such calculations are inherent in natural gas sales, production, operation, measurement, and administration. Management does not believe that differences between actual and estimated natural gas revenues or purchase costs attributable to the unresolved variances or imbalances are material.
Income Taxes
The Company follows the asset and liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are recorded for the estimated future tax consequences attributable to the differences between the financial carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using the tax rate in effect for the year in which those temporary differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the year of the enacted rate change. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.
The Company is required to make judgments, including estimating reserves for potential adverse outcomes regarding tax positions that the Company has taken. The Company accounts for uncertainty in income taxes using a recognition and measurement threshold for tax positions taken or expected to be taken in a tax return. The tax benefit from an uncertain tax position is recognized when it is more likely than not that the position will be sustained upon examination by taxing authorities based on technical merits of the position. The amount of the tax benefit recognized is the largest amount of the
CABOT OIL & GAS CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
1. Summary of Significant Accounting Policies (Continued)
benefit that has a greater than 50% likelihood of being realized upon ultimate settlement. The effective tax rate and the tax basis of assets and liabilities reflect management's estimates of the ultimate outcome of various tax uncertainties.
The Company recognizes accrued interest related to uncertain tax positions in Interest Expense and Other and accrued penalties related to such positions in General and Administrative expense in the Consolidated Statement of Operations.
Stock-Based Compensation
The Company accounts for stock-based compensation under a fair value based method of accounting prescribed under ASC 718. Under the fair value method, compensation cost is measured at the grant date and remeasured each reporting period for liability-classified awards based on the fair value of an award and is recognized over the service period, which is usually the vesting period. To calculate the fair value, either a binomial or Black-Scholes valuation model may be used. Stock-based compensation cost for all types of awards is included in General and Administrative expense in the Consolidated Statement of Operations.
The tax benefit for stock-based compensation is included as both a cash inflow from financing activities and a cash outflow from operating activities in the Consolidated Statement of Cash Flows. In accordance with ASC 718, the Company recognizes a tax benefit only to the extent it reduces the Company's income taxes payable. The Company did not recognize a tax benefit for stock-based compensation for the years ended December 31, 2011 and 2010. For the year ended December 31, 2009, the Company realized tax benefits of $13.8 million.
Environmental Matters
Environmental expenditures are expensed or capitalized, as appropriate, depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations, and that do not have future economic benefit are expensed. Liabilities related to future costs are recorded on an undiscounted basis when environmental assessments and/or remediation activities are probable and the costs can be reasonably estimated. Any insurance recoveries are recorded as assets when received.
Market Risk
The Company's primary market risk is exposure to oil and natural gas prices. Realized prices are mainly driven by worldwide prices for oil and spot market prices for North American natural gas production. Commodity prices are volatile and unpredictable.
Credit Risk
Although notional contract amounts are used to express the volume of natural gas price agreements, the amounts that can be subject to credit risk in the event of non-performance by third parties are substantially smaller. The Company does not anticipate any material impact on its financial results due to non-performance by the third parties.
In 2011, the Company did not have any one customer account for greater than 10% of the Company's total sales. In 2010, one customer accounted for approximately 11%, of the Company's total sales. In 2009, two customers accounted for approximately 13% and 11%, respectively of the Company's total sales.
CABOT OIL & GAS CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
1. Summary of Significant Accounting Policies (Continued)
Use of Estimates
In preparing financial statements, the Company follows generally accepted accounting principles. These principles require management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved natural gas, natural gas liquids and crude oil reserves and related cash flow estimates used in impairment tests of oil and gas properties, natural gas, natural gas liquids and crude oil revenues and expenses, current values of derivative instruments, as well as estimates of expenses related to legal, environmental and other contingencies, depreciation, depletion and amortization, asset retirement obligations, pension and postretirement obligations, stock-based compensation and deferred income taxes. Actual results could differ from those estimates.
2. Properties and Equipment, Net
Properties and equipment, net are comprised of the following:
Capitalized Exploratory Well Costs
The following table reflects the net changes in capitalized exploratory well costs during 2011, 2010 and 2009.
CABOT OIL & GAS CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
2. Properties and Equipment, Net (Continued)
The following table provides an aging of capitalized exploratory well costs based on the date the drilling was completed for which exploratory well costs have been capitalized for a period greater than one year since the completion of drilling:
Impairments
During 2010, the Company recorded $40.9 million of impairments of oil and gas properties and other assets. The Company recorded a $35.8 million impairment of oil and gas properties due to continued price declines and limited activity in two south Texas fields. These fields were reduced to a fair value of approximately $15.4 million. An impairment of $5.1 million was recorded related to drilling and service equipment that was primarily used for drilling in West Virginia. The impairment was a result of decreased activity in West Virginia and the decision to sell the underlying assets. These assets were reduced to fair value of approximately $4.0 million.
The Company also recorded an impairment loss of approximately $5.8 million during 2010 associated with the sale of certain properties in Colorado, which was recognized in the Gain / (Loss) on Sale of Assets in the Consolidated Statement of Operations. The fair value of the impaired properties was approximately $3.0 million and was determined using a market approach which considered the execution of a purchase and sale agreement the Company entered into on June 30, 2010. Accordingly, the inputs associated with the fair value of assets held for sale were considered Level 2 in the fair value hierarchy.
During 2009, the Company recorded $17.6 million of impairments of oil and gas properties. The Company recorded an impairment of $12.0 million and $5.6 million in the Fossil Federal field in San Miguel County, Colorado and the Beaurline field in Hildalgo County, Texas, respectively, due to lower well performance. These fields were reduced to fair value of approximately $8.9 million.
Fair value of oil and gas properties was determined using the income approach utilizing discounted future cash flows. The fair value of the impaired oil and gas properties and other assets was based on significant inputs that were not observable in the market and are considered to be Level 3 inputs as defined in ASC 820. Refer to Note 13 for more information and a description of fair value hierarchy. Key assumptions include (1) oil and natural gas prices (adjusted to quality and basis differentials), (2) projections of estimated quantities of oil and gas reserves and production, (3) estimates of future development and production costs and (4) risk adjusted discount rates (14% at September 30, 2010 and 16% at December 31, 2009, respectively). Fair value of drilling and service equipment was determined using the market approach which considered broker quotes from market participants in the oil field services sector.
CABOT OIL & GAS CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
2. Properties and Equipment, Net (Continued)
Natural gas prices have decreased from an average price of $4.39 per Mmbtu in 2010 to an average price of $4.04 per Mmbtu in 2011. Natural gas prices were $3.36 per Mmbtu in December 2011 and have continued to decline to $2.68 per Mmbtu in February 2012. Natural gas prices represent the first of the month Henry Hub index price per Mmbtu. Oil prices have increased from an average price of $77.32 per barrel in 2010 to an average price of $94.01 per barrel in 2011. Any further decline in natural gas prices or quantities could result in an impairment of proved oil and gas properties.
Divestitures
The Company recognized an aggregate gain on sale of assets of $63.4 million and $106.3 million for the years ended December 3, 2011 and 2010, respectively, and an aggregate loss of $3.3 million for the year ended December 31, 2009.
In October 2011, the Company sold certain proved oil and gas properties located in Colorado, Utah and Wyoming to Breitburn Operating L.P., a wholly owned subsidiary of Breitburn Energy Partners L.P. for $285.0 million. The Company received $283.2 million in cash proceeds, after closing adjustments, and recognized a $4.2 million gain on sale of assets.
In May 2011, the Company sold certain of its unproved Haynesville and Bossier Shale oil and gas properties in east Texas to a third party. The Company received approximately $47.0 million in cash proceeds and recognized a $34.2 million gain on sale of assets.
In February and April 2011, respectively, the Company entered into two participation agreements with third parties related to certain of its Haynesville and Bossier Shale leaseholds in east Texas. Under the terms of the participation agreements, the third parties will fund 100% of the cost to drill and complete certain Haynesville and Bossier Shale wells in the related leaseholds over a multi-year period in exchange for a 75% working interest in the leaseholds. During 2011, the Company received a reimbursement of drilling costs incurred of approximately $12.9 million associated with wells that had commenced drilling prior to the execution of the participation agreements.
In 2011, the Company also sold various other unproved properties and other assets for total proceeds of $73.5 million and recognized an aggregate gain of $25.0 million.
In December 2010, the Company sold its existing Pennsylvania gathering infrastructure of approximately 75 miles of pipeline and two compressor stations to Williams Field Services (Williams), a subsidiary of Williams Partners L.P., for $150 million. Under the terms of the purchase and sale agreement, the Company was obligated to construct pipelines to connect certain of its 2010 program wells, complete the construction of the Lathrop compressor station and complete taps into certain pipeline delivery points. These obligations were completed in 2011. As of December 31, 2010, the Company recognized a $49.3 million gain on sale of assets, which included the accrual of $17.9 million associated with the obligations described above. The Company also entered into a 25-year firm gathering contract with Williams that requires Williams to complete construction of approximately 32 miles of high pressure pipeline, 65 miles of trunklines and two compressor stations in Susquehanna County, Pennsylvania in the next two years. Additionally, Williams will connect all of the Company's drilling program wells, which will connect our production to five interstate pipeline delivery options.
In 2010, the Company also sold various other proved and unproved properties and other assets for total proceeds of $32.2 million and recognized an aggregate gain of $16.3 million.
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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
2. Properties and Equipment, Net (Continued)
In April 2009, the Company sold substantially all of its Canadian proved oil and gas properties to Tourmaline Oil Corporation (Tourmaline) for total consideration of $84.4 million ($63.8 million in cash and $20.6 million in common stock of Tourmaline) and recognized a loss of approximately $16.0 million. The common stock investment was accounted for using the cost method. In November 2010, the Company sold its investment in common stock of Tourmaline for $61.3 million and recognized a gain of $40.7 million which is included in Gain/(Loss) on Sale of Assets in the Consolidated Statement of Operations.
In 2009, the Company also sold certain oil and gas properties in West Virginia for cash proceeds of $11.4 million and recognized a gain of $12.7 million.
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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
3. Additional Balance Sheet Information
Certain balance sheet amounts are comprised of the following:
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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
4. Debt and Credit Agreements
The Company's debt consisted of the following as of:
The Company has debt maturities of $75 million due in 2013 and $20 million in 2016. In addition, the revolving credit facility (credit facility) matures in 2015. No other tranches of debt are due within the next five years.
In June 2010, the Company amended the agreements governing its senior notes to amend the required asset coverage ratio (the present value of the Company's proved reserves plus working capital to debt) contained in the agreements. The amendments revised the calculation of present value of proved reserves to reflect specified pricing assumptions based on quoted futures prices in lieu of historical realized prices, reduced the limit on proved undeveloped reserves included in the calculation from 35% to 30%, and increased the required ratio from 1.50:1 to 1.75:1. The amendments also provided that for so long as a borrowing base calculation is required under the Company's credit facility, the calculated indebtedness may not exceed 115% of such borrowing base for this ratio. If such a borrowing base calculation is not required under the credit facility, the Company would no longer be subject to the asset coverage ratio under the agreements, but would instead be required to maintain a ratio of debt to consolidated EBITDAX (as defined) not to exceed 3.0 to 1.0. In conjunction with the amendments, the Company incurred $2.0 million of debt issuance costs which were capitalized and are being amortized over the term of the respective amended agreements in accordance with ASC 470-50, "Debt Modifications and Extinguishments."
7.33% Weighted-Average Fixed Rate Notes
In July 2001, the Company issued $170 million of Notes to a group of seven institutional investors in a private placement. The Notes have bullet maturities and were issued in three separate tranches as follows:
The 7.33% weighted-average fixed rate notes contain restrictions on the merger of the Company or any subsidiary with a third party other than under certain limited conditions. There are also various other restrictive covenants customarily found in such debt instruments. Those covenants include a
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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
4. Debt and Credit Agreements (Continued)
required asset coverage ratio (present value of proved reserves to debt and other liabilities) of at least 1.75 to 1.0 (as amended) and a minimum annual coverage ratio of operating cash flow to interest expense for the trailing four quarters of 2.8 to 1.0.
In December 2010, the Company repaid the $75.0 million outstanding of Tranche 1 prior to the due date. In connection with the early payment the Company was required to pay a make-whole premium of $2.8 million which is included in Interest Expense and Other in the Consolidated Statement of Operations.
6.51% Weighted-Average Fixed Rate Notes
In July 2008, the Company issued $425 million of senior unsecured fixed-rate notes to a group of 41 institutional investors in a private placement. The Notes have bullet maturities and were issued in three separate tranches as follows:
Interest on each series of the 6.51% weighted-average fixed rate notes is payable semi-annually. The Company may prepay all or any portion of the Notes of each series on any date at a price equal to the principal amount thereof plus accrued and unpaid interest plus a make-whole premium. The Notes contain restrictions on the merger of the Company with a third party other than under certain limited conditions. There are also various other restrictive covenants customarily found in such debt instruments. These covenants include a required asset coverage ratio (present value of proved reserves plus adjusted cash (as defined in the note purchase agreement) to debt and other liabilities) of at least 1.75 to 1.0 (as amended) and a minimum annual coverage ratio of operating cash flow to interest expense for the trailing four quarters of 2.8 to 1.0. The Notes also are subject to customary events of default. The Company is required to offer to prepay the Notes upon specified change in control events accompanied by a ratings decline below investment grade.
9.78% Notes
In December 2008, the Company issued $67 million aggregate principal amount of its 10-year 9.78% Series G Senior Notes to a group of four institutional investors in a private placement. Interest on the Notes is payable semi-annually. The Company may prepay all or any portion of the Notes on any date at a price equal to the principal amount thereof plus accrued and unpaid interest plus a make-whole premium. The other terms of the Notes are substantially similar to the terms of the 6.51% Weighted-Average Fixed Rate Notes.
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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
4. Debt and Credit Agreements (Continued)
5.58% Weighted-Average Fixed Rate Notes
In December 2010, the Company issued $175 million of senior unsecured fixed-rate notes to a group of eight institutional investors in a private placement. The Notes have bullet maturities and were issued in three separate tranches as follows:
Interest on each series of the 5.58% weighted-average fixed rate notes is payable semi-annually. The Company may prepay all or any portion of the Notes of each series on any date at a price equal to the principal amount thereof plus accrued and unpaid interest plus a make-whole premium. The other terms of the Notes are substantially similar to the terms of the 6.51% Weighted-Average Fixed Rate Notes.
Revolving Credit Agreement
In September 2010, the Company amended and restated its revolving credit facility. The credit facility provides for an available credit line of $900 million and contains an accordion feature allowing the Company to increase the available credit line to $1.0 billion, if any one or more of the existing banks or new banks agree to provide such increased commitment amount. The amended facility provided for an initial $1.5 billion borrowing base and matures in September 2015. As of December 31, 2011, the Company's borrowing base was $1.7 billion.
In conjunction with entering into the September 2010 amended credit facility, the Company incurred $11.7 million of debt issuance costs, which were capitalized and will be amortized over the term of the amended credit facility. Approximately $6.3 million in unamortized costs associated with the original credit facility, as amended in June 2010, will be amortized over the term of the amended credit facility in accordance with ASC 470-50, "Debt Modifications and Extinguishments."
The credit facility is unsecured. The available credit line is subject to adjustment from time to time on the basis of (1) the projected present value (as determined by the banks based on the Company's reserve reports and engineering reports) of estimated future net cash flows from certain proved oil and gas reserves and certain other assets of the Company (the "Borrowing Base") and (2) the outstanding principal balance of the Company's senior notes. While the Company does not expect a reduction in the available credit line, in the event that it is adjusted below the outstanding level of borrowings in connection with scheduled redetermination or due to a termination of hedge positions, the Company has a period of six months to reduce its outstanding debt in equal monthly installments to the adjusted credit line available.
The Borrowing Base is redetermined annually under the terms of the credit facility on April 1. In addition, either the Company or the banks may request an interim redetermination twice a year in connection with certain acquisitions or sales of oil and gas properties. Effective April 1, 2011, the lenders under the Company's revolving credit facility approved an increase in the Company's borrowing base from $1.5 billion to $1.7 billion as part of the annual redetermination under the terms of the
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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
4. Debt and Credit Agreements (Continued)
credit facility. The Company's plan to sell certain oil and gas properties located in Colorado, Utah and Wyoming, triggered an interim redetermination of the Company's borrowing base, and the $1.7 billion borrowing base was reaffirmed by the lenders effective September 27, 2011.
Interest rates under the credit facility are based on Euro-Dollars (LIBOR) or Base Rate (Prime) indications, plus a margin. These associated margins increase if the total indebtedness under the credit facility and the Company's senior notes is greater than 25%, greater than 50%, greater than 75% or greater than 90% of the Borrowing Base, as shown below:
The credit facility provides for a commitment fee on the unused available balance at annual rates of 0.50%.
The credit facility contains various customary restrictions, which include the following (with all calculations based on definitions contained in the agreement):
(a)Maintenance of a minimum annual coverage ratio of operating cash flow to interest expense for the trailing four quarters of 2.8 to 1.0.
(b)Maintenance of an asset coverage ratio of the present value of proved reserves plus working capital to debt of 1.75 to 1.0.
(c)Maintenance of a current ratio of 1.0 to 1.0.
(d)Prohibition on the merger or sale of all or substantially all of the Company's or any subsidiary's assets to a third party, except under certain limited conditions.
In addition, the credit facility includes a customary condition to the Company's borrowings under the facility that a material adverse change has not occurred with respect to the Company.
At December 31, 2011 and 2010, borrowings outstanding under the Company's credit facilities were $188.0 million and $213.0 million, respectively. In addition, the Company had $1.0 million letters of credit outstanding and availability under the credit facility of $711.0 million at December 31, 2011.
The Company's weighted-average effective interest rates for the credit facilities during the years ended December 31, 2011, 2010 and 2009 were approximately 4.1%, 3.8% and 4.0%, respectively. As of December 31, 2011 and 2010, the weighted-average interest rate on the Company's credit facility was approximately 4.9% and 3.1%, respectively.
5. Employee Benefit Plans
Pension Plan
Prior to its termination in 2010, the Company had a non-contributory, defined benefit pension plan for all full-time employees, referred to as the tax qualified defined benefit pension plan (qualified pension plan). Plan benefits were based primarily on years of service and salary level near retirement. During the existence of the plan, the Company complied with the Employee Retirement Income
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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
5. Employee Benefit Plans (Continued)
Security Act (ERISA) of 1974 and Internal Revenue Code limitations when funding the plan. The Company also had an unfunded non-qualified supplemental pension plan to ensure payments to certain executive officers of amounts to which they would have been entitled under the provisions of the pension plan, but for limitations imposed by federal tax laws, referred to as the supplemental non-qualified pension arrangements (non-qualified pension plan).
Termination and Amendment of Qualified and Non-Qualified Pension Plans
On July 28, 2010, the Company notified its employees of its plan to terminate its qualified pension plan, with the plan and its related trust to be liquidated following appropriate filings with the Pension Benefit Guaranty Corporation and Internal Revenue Service, effective September 30, 2010. The Company then amended and restated the qualified pension plan to freeze benefit accruals, to provide for termination of the plan, to allow for an early retirement enhancement to be available to all active participants as of September 30, 2010 regardless of their age and years of service as of that date, and to make certain changes that were required or made desirable as a result of developments in the law. Because no further benefits will accrue under the qualified pension plan after September 30, 2010, the Company's related non-qualified pension plan was effectively frozen and no additional benefits were accrued under those arrangements after September 30, 2010.
Freezing the above plans resulted in a remeasurement of the pension obligations and plan assets as of July 28, 2010. In calculating the remeasurement at the time of the termination, management used a discount rate of 5.25% for the qualified pension plan and 4.5% for the non-qualified pension plan, which was consistent with the Company's methodology of determining the discount rate for these plans in prior periods. The discount rate was based on a yield curve based on high-quality corporate bonds that could be purchased to settle the pension obligation. Management determined the discount rate by matching this yield curve with the timing and amounts of the expected benefit payments for the Company's plans.
As a result of these changes to the Company's qualified and non-qualified pension plans, the Company revised its amortization period for prior service costs and actuarial losses based upon the anticipated final distribution of benefits from each plan. Prior service costs established in each plan prior to freeze were fully recognized in the third quarter of 2010 as a result of the plan freeze.
On December 15, 2011, the Company contributed $5.6 million to its non-qualified pension plan to fund the final distribution of benefits. As of December 31, 2011, the benefit obligations associated with the non-qualified pension plan were fully satisfied.
Obligations and Funded Status
The funded status represents the difference between the projected benefit obligation of the Company's qualified and non-qualified pension plans and the fair value of the qualified pension plan's assets at December 31.
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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
5. Employee Benefit Plans (Continued)
The change in the combined projected benefit obligation of the Company's qualified and non-qualified pension plans and the change in the Company's qualified pension plan assets at fair value are as follows:
(1)On December 15, 2011, the Company made a final distribution of benefits from the non-qualified pension plan.
Amounts Recognized in the Balance Sheet
Amounts recognized in the balance sheet consist of the following:
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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
5. Employee Benefit Plans (Continued)
Amounts Recognized in Accumulated Other Comprehensive Income
Amounts recognized in accumulated other comprehensive income consist of the following:
Information for Pension Plans with an Accumulated Benefit Obligation in Excess of Plan Assets
Components of Net Periodic Benefit Cost and Other Amounts Recognized in Other Comprehensive Income Combined Qualified and Non-Qualified Pension Plans
(1)On December 15, 2011, the Company made a final distribution of benefits from the non-qualified pension plan.
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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
5. Employee Benefit Plans (Continued)
The estimated prior service cost and net actuarial loss for the qualified pension plan that will be amortized from accumulated other comprehensive income into net periodic benefit cost over the next fiscal year are $0.2 million and $13.1 million, respectively.
Assumptions
Weighted-average assumptions used to determine projected pension benefit obligations were as follows:
Weighted-average assumptions used to determine net periodic pension costs are as follows:
(1)Represents the discount rate used to determine the projected benefit costs for qualified and non-qualified pension plans for 2009 and the non-qualified plan for 2011.
(2)Represents the discount rate used to determine the net periodic pension costs for the qualified plan for 2011 and 2010 and the non-qualified pension plan for 2010. For the qualified plan in 2011, a 5.25% discount rate was used from January 1, 2011 through July 31, 2011; due to a remeasurement triggered by settlements that occurred during the year, the discount rate was adjusted to 4.75% for the remainder of 2011. For both the qualified and non-qualified plans in 2010, a discount rate of 5.25% was used from January 1, 2010 through July 31, 2010. Due to the plan termination and amendments that were effective in July 2010, the discount rate was adjusted for determining the net periodic pension costs for the remainder of 2010 to 4.80%.
The Company establishes the long-term expected rate of return by developing a forward looking long-term expected rate of return assumption for each asset class, taking into account factors such as the expected real return for the specific asset class and inflation. One of the plan objectives is that performance of the equity portion of the pension plan exceeds the Standard and Poors' 500 Index over the long-term. The Company also seeks to achieve a minimum five percent annual real rate of return (above the rate of inflation) on the total portfolio over the long-term. In the Company's pension calculations, the Company has used 8% as the expected long-term return on plan assets for 2011, 2010 and 2009. In order to derive this return, a Monte Carlo simulation was run using 5,000 simulations based upon the Company's actual asset allocation. This model uses historical data for the period of
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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
5. Employee Benefit Plans (Continued)
1926-2007 for stocks, bonds and cash to determine the best estimate range of future returns. The median rate of return, or return that the Company expects to achieve over 50% of the time, is approximately 9%. The Company expects to achieve at a minimum approximately 7% annual real rate of return on the total portfolio over the long-term at least 75% of the time. The Company believes that the 8% chosen is a reasonable estimate based on its actual results.
Plan Assets
The Company's pension plan assets were accounted for at fair value and are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Each portfolio uses independent pricing services approved by the Trustee to value the Company's investments. All common/collective trust funds are managed by the Trustee. Refer to Note 13 for more information and a description of the fair value hierarchy.
The Company's investments in equity securities for which market quotations are readily available are valued at the last reported sale price or official closing price as reported by an independent pricing service on the primary market or exchange on which they are traded.
The Company's investment in debt securities are valued based on quotations received from dealers who transact in markets with such securities or by independent pricing services. For corporate bonds, bank notes, floating rate loans, foreign government and government agency obligations, municipal securities, preferred securities, supranational obligations, U.S. government and government agency obligations pricing services generally utilize matrix pricing which considers yield or price of bonds of comparable quality, coupon, maturity and type as well as dealer supplied prices.
The fair value of the plan assets of the Company's qualified pension plan at December 31, 2011 and 2010 by asset category are as follows:
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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
5. Employee Benefit Plans (Continued)
The Company's investment strategy for the pension benefit plan assets is to remain fully invested in the market until the final determination for the plan termination is complete. The Company will continue to target a portfolio of assets utilizing equity securities, debt securities and cash equivalents that are within a range of approximately 50% to 80% for equity securities and approximately 20% to 40% for fixed income securities.
Cash Flows
Employer Contributions / Estimated Future Benefit Payments
The funding levels of the pension and postretirement benefit plans (described below) are in compliance with standards set by applicable law or regulation. The Company did not have any required minimum funding obligations for its qualified pension plan in 2011; however, it chose to fund $7.0 million into the qualified pension plan. In 2012, the Company does not have any required minimum funding obligations for the qualified plan; however, the Company expects to make a final distribution of benefits from the qualified pension plan in the first half of 2012. During 2011, the Company contributed $7.3 million to its non-qualified pension plan.
Postretirement Benefits Other than Pensions
The Company provides certain health care benefits for retired employees, including their spouses, eligible dependents and surviving spouses (retirees). These benefits are commonly called postretirement benefits. The health care plans are contributory, with participants' contributions adjusted annually. Most employees become eligible for these benefits if they meet certain age and service requirements at retirement. The Company was providing postretirement benefits to 275 retirees and their dependents at the end of 2011 and 257 retirees and their dependents at the end of 2010.
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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
5. Employee Benefit Plans (Continued)
Obligations and Funded Status
The funded status represents the difference between the accumulated benefit obligation of the Company's postretirement plan and the fair value of plan assets at December 31. The postretirement plan does not have any plan assets; therefore, the funded status is equal to the amount of the December 31 accumulated benefit obligation.
The change in the Company's postretirement benefit obligation is as follows:
Amounts Recognized in the Balance Sheet
Amounts recognized in the balance sheet consist of the following:
Amounts Recognized in Accumulated Other Comprehensive Income
Amounts recognized in accumulated other comprehensive income consist of the following:
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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
5. Employee Benefit Plans (Continued)
The estimated net loss for the defined benefit postretirement plan that will be amortized from accumulated other comprehensive income into net periodic postretirement cost over the next fiscal year is $1.1 million.
Components of Net Periodic Benefit Cost and Other Amounts Recognized in Other Comprehensive Income
Assumptions
Assumptions used to determine projected postretirement benefit obligations and postretirement costs are as follows:
(1)Represents the year end rates used to determine the projected benefit obligation. To compute postretirement cost in 2011, 2010 and 2009, respectively, the beginning of year discount rates of 4.25%, 5.75% and 5.75% were used.
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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
5. Employee Benefit Plans (Continued)
Coverage provided to participants age 65 and older is under a fully-insured arrangement. The Company subsidy is limited to 60% of the expected annual fully-insured premium for participants age 65 and older. For all participants under age 65, the Company subsidy for all retiree medical and prescription drug benefits, beginning January 1, 2006, was limited to an aggregate annual amount not to exceed $648,000. This limit increases by 3.5% annually thereafter. The Company prepaid the life insurance premiums for all retirees retiring before January 1, 2006 eliminating all future premiums for retiree life insurance. A life insurance product is offered to employees allowing employees to continue coverage into retirement by paying the premiums directly to the life insurance provider.
Assumed health care cost trend rates may have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects:
Cash Flows
Contributions
The Company expects to contribute approximately $1.3 million to the postretirement benefit plan in 2012.
Estimated Future Benefit Payments
The following estimated benefit payments under the Company's postretirement plans, which reflect expected future service, as appropriate, are expected to be paid as follows:
Savings Investment Plan
The Company has a Savings Investment Plan (SIP), which is a defined contribution plan. The Company matches a portion of employees' contributions in cash. Participation in the SIP is voluntary, and all regular employees of the Company are eligible to participate. The Company made contributions of $2.0 million, $2.2 million and $2.2 million in 2011, 2010 and 2009, respectively, which are included in General and Administrative expense in the Consolidated Statement of Operations. The Company matches employee contributions dollar-for-dollar on the first six percent of an employee's pretax earnings. The Company's common stock is an investment option within the SIP.
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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
5. Employee Benefit Plans (Continued)
In July 2010, the Company amended the SIP to provide for discretionary profit sharing contributions upon termination of the qualified pension plan effective September 30, 2010. The Company presently makes a discretionary profit-sharing contribution to this plan in an amount equal to 9% of an eligible plan participant's salary and bonus. The Company charged to expense plan contributions of $3.6 million and $0.8 million in 2011 and 2010, respectively, which are included in General and Administrative expense in the Consolidated Statement of Operations.
Deferred Compensation Plan
In 1998, the Company established a Deferred Compensation Plan which was available to officers of the Company and acts as a supplement to the SIP. The Internal Revenue Code does not cap the amount of compensation that may be taken into account for purposes of determining contributions to the Deferred Compensation Plan and does not impose limitations on the amount of contributions to the Deferred Compensation Plan. Effective October 1, 2010, the Company amended the Deferred Compensation Plan to broaden the group of eligible employees who participate in the plan beyond the officers of the Company. Under this amendment, the Company may designate any member of the Company's management group as a participant in the Deferred Compensation Plan and may further designate whether such a participant is eligible to make deferral elections from their compensation. At the present time, the Company anticipates making such a contribution to the Deferred Compensation Plan on behalf of a participant in the event that Internal Revenue Code limitations cause a participant to receive less than the full Company matching contribution under the SIP. The Deferred Compensation Plan was also amended to provide that the Company would credit the accounts of participants who had entered into supplemental employee retirement plan agreements with the Company in an amount equal to which such participant would have been entitled under the terms of the supplemental employee retirement plan agreement in effect between the Company and the participant as of September 29, 2010, if the participant had terminated employment on September 30, 2010. This amendment also placed restrictions on the payment of these amounts in order to comply with Section 409A of the Internal Revenue Code. Effective January 1, 2011, the Company amended and restated the Deferred Compensation Plan to incorporate prior plan amendments and to provide for Company contributions that may not be made to the Company's tax-qualified Savings Investment Plan as a result of limitations imposed by the Internal Revenue Code.
The assets of the Deferred Compensation Plan are held in a rabbi trust and are subject to additional risk of loss in the event of bankruptcy or insolvency of the Company.
The participants direct the deemed investment of amounts credited to their accounts under the Deferred Compensation Plan. The trust assets are invested in either mutual funds that cover the investment spectrum from equity to money market, or may include holdings of the Company's common stock, which is funded by the issuance of shares to the trust. The mutual funds are publicly traded and have market prices that are readily available. Settlement payments are made to participants in cash, either in a lump sum or in periodic installments. The market value of the trust assets, excluding the Company's common stock, was $10.8 million and $15.8 million at December 31, 2011 and 2010, respectively, and is included in Other Assets in the Consolidated Balance Sheet. Related liabilities, including the Company's common stock, totaled $20.2 million and $21.6 million at December 31, 2011 and 2010, respectively, and are included in Other Liabilities in the Consolidated Balance Sheet. With the exception of the Company's common stock, there is no impact on earnings or earnings per share from the changes in market value of the deferred compensation plan assets because the changes in
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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
5. Employee Benefit Plans (Continued)
market value of the trust assets are offset completely by changes in the value of the liability, which represents trust assets belonging to plan participants.
The Company's common stock held in the rabbi trust is recorded at the market value on the date of deferral, which totaled $4.9 million and $6.6 million at December 31, 2011 and 2010, respectively and is included in Additional Paid-in Capital in Stockholders' Equity in the Consolidated Balance Sheet. As of December 31, 2011, 267,087 shares of the Company's stock representing vested performance share awards were deferred into the rabbi trust. During 2011, a decrease to the rabbi trust deferred compensation liability of $1.4 million was recognized, representing a decrease of $4.9 million related to a decrease in value of investments, excluding the Company's stock, coupled with a $0.8 million reduction in the liability due to shares that were sold out of the rabbi trust, partially offset by a $4.3 million increase based on the increase in the closing price of the Company's stock December 31, 2010 to December 31, 2011. The Company recognized $5.3 million in General and Administrative expense in the Consolidated Statement of Operations representing the increase in the closing price of the Company's shares held in the trust and also due to the sale of shares in the Company's stock. The Company's common stock issued to the trust is not considered outstanding for purposes of calculating basic earnings per share, but is considered a common stock equivalent in the calculation of diluted earnings per share.
The Company charged to expense plan contributions of $522,807, $109,196 and $0 in 2011, 2010 and 2009, respectively, which are included in General and Administrative expense in the Consolidated Statement of Operations.
6. Income Taxes
Income tax expense is summarized as follows:
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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
6. Income Taxes (Continued)
Total income taxes were different than the amounts computed by applying the statutory federal income tax rate as follows:
The tax effects of temporary differences that resulted in significant portions of the deferred tax liabilities and deferred tax assets were as follows:
As of December 31, 2011, the Company had alternative minimum tax credit carryforwards of $101.3 million which do not expire and can be used to offset regular income taxes in future years to the extent that regular income taxes exceed the alternative minimum tax in any such year. The Company also had net operating loss carryforwards of $291.8 million and $312.7 million for federal and state reporting purposes, respectively, the majority of which will expire between 2016 and 2031. It is expected that these deferred tax benefits will be utilized prior to their expiration.
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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
6. Income Taxes (Continued)
Uncertain Tax Positions
A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:
During 2010, unrecognized tax benefits were reduced by $0.5 million as a result of the completion of the Internal Revenue Service (IRS) Joint Committee on Taxation review of the 2005-2008 tax years that were under audit by the IRS. This reduction did not materially affect the effective tax rate. As of December 31, 2011 and 2010, the Company did not have any uncertain tax positions reported in the Consolidated Balance Sheet.
The Company files income tax returns in the U.S. federal jurisdiction, various states and other jurisdictions. The Company is no longer subject to examinations by state authorities before 2005. The Company is not currently under examination by the IRS.
7. Commitments and Contingencies
Gas Transportation Agreements
The Company has entered into gas transportation agreements with various pipelines with initial terms ranging from four to 25 years. Under certain of these agreements, the Company is obligated to transport minimum daily natural gas volumes, or pay for any deficiencies at a specified rate. The Company is also obligated under certain of these arrangements to pay a demand charge for firm capacity rights on pipeline systems regardless of the amount of pipeline capacity utilized by the Company. In most cases, the Company's production commitment to these pipelines is expected to exceed minimum daily volumes provided in the agreements. If the Company does not utilize the capacity, it can release it to others, thus reducing its potential liability.
Future obligations under gas transportation agreements as of December 31, 2011 are as follows:
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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
7. Commitments and Contingencies (Continued)
Drilling Rig Commitments
During 2011, the Company entered into two drilling rig commitments ranging from two to three years for its capital program in the Marcellus Shale in northeast Pennsylvania. The drilling rig commitments commenced in the fourth quarter of 2011. The future minimum commitments under these agreements as of December 31, 2011 are $19.8 million in 2012, $18.1 million in 2013 and $8.0 million in 2014.
Hydraulic Fracturing Services Commitments
During 2011, the Company entered into a thirteen month hydraulic fracturing services commitment in the Marcellus Shale in northeast Pennsylvania, which commenced in the fourth quarter of 2011. The future minimum commitments under the agreement as of December 31, 2011 are $82.2 million in 2012.
Lease Commitments
The Company leases certain transportation vehicles, warehouse facilities, office space, and machinery and equipment under cancelable and non-cancelable leases. Rent expense under these arrangements totaled $13.6 million, $18.3 million and $17.4 million for the years ended December 31, 2011, 2010 and 2009, respectively.
Future minimum rental commitments under non-cancelable leases in effect at December 31, 2011 are as follows:
Legal Matters
Preferential Purchase Right Litigation
In September 2005, the Company and Linn Energy, LLC were sued by Power Gas Marketing & Transmission, Inc. in the Court of Common Pleas of Indiana County, Pennsylvania. The lawsuit seeks unspecified damages arising out of the Company's 2003 sale of oil and gas properties located in Indiana County, Pennsylvania, to Linn Energy, LLC. The plaintiff alleges breach of a preferential purchase right regarding those properties contained in a 1969 joint operating agreement, to which the plaintiff was a party. The Company initially obtained judgment as a matter of law as to all claims in a decision by the trial court dated February 2007. Plaintiff appealed the ruling to the Pennsylvania Superior Court, where the ruling in favor of the Company was reversed and remanded to the trial court in March 2008. The Company appealed the Superior Court ruling to the Pennsylvania Supreme Court, but in December 2008 that Court declined to review. Effective July 2008, Linn Energy, LLC sold the subject properties
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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
7. Commitments and Contingencies (Continued)
to XTO Energy, Inc., giving rise to a second lawsuit for unspecified damages filed in September 2009 by EXCO-North Coast Energy, Inc., as successor in interest to Power Gas Marketing & Transmission, Inc., against the Company, Linn Energy, LLC and XTO Energy, Inc. The second lawsuit has been consolidated into the first lawsuit. A bench trial on the merits, should one be necessary, has been set for early March 2012.
The Company believes that the plaintiff's claims lack merit and does not consider a loss related to this matter to be probable; however, due to the inherent uncertainties of litigation a loss is possible. In the event that the Company is found liable, the potential loss is currently estimated to be less than $15 million.
Other
The Company is also a defendant in various other legal proceedings arising in the normal course of business. All known liabilities are accrued based on management's best estimate of the potential loss. While the outcome and impact of these legal proceedings on the Company cannot be predicted with certainty, management believes that the resolution of these proceedings will not have a material effect on the Company's financial position or cash flow; however, operating results could be significantly impacted in reporting periods in which such matters are resolved.
Contingency Reserves
When deemed necessary, the Company establishes reserves for certain legal proceedings. The establishment of a reserve is based on an estimation process that includes the advice of legal counsel and subjective judgment of management. While management believes these reserves to be adequate, it is reasonably possible that the Company could incur additional losses with respect to those matters in which reserves have been established. The Company believes that any such amount above the amounts accrued is not material to the Consolidated Financial Statements. Future changes in facts and circumstances could result in the actual liability exceeding the estimated ranges of loss and amounts accrued.
Environmental Matters
Pennsylvania Department of Environmental Protection
On November 4, 2009, the Company and the Pennsylvania Department of Environmental Protection (PaDEP) executed a consent order (Consent Order) addressing a number of environmental issues identified in 2008 and 2009, including alleged releases of drilling mud and other substances, alleged record keeping violations at various wells and alleged natural gas contamination of 13 water supplies in Susquehanna County, Pennsylvania. As part of the settlement, the Company paid an aggregate $120,000 civil penalty with respect to the matters addressed by the Consent Order, which were consolidated at the request of the PaDEP.
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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
7. Commitments and Contingencies (Continued)
On April 15, 2010, the Company and the PaDEP executed a modified Consent Order (First Modified Consent Order). The First Modified Consent Order provided that the Company would make available a permanent source of potable water to 14 households, most of which the Company had already been supplying with water. The First Modified Consent Order included the following conditions: (i) the Company would plug and abandon three vertical natural gas wells and would undertake certain remedial measures on a fourth well in a nine square mile area in Susquehanna County; (ii) the Company would complete these actions prior to new natural gas well drilling permits being issued for drilling in Pennsylvania, and prior to initiating hydraulic fracturing of seven wells already drilled in the area of concern; and (iii) the Company would also postpone drilling of new natural gas wells in the area of concern until certain terms of the consent orders were fulfilled. In addition, the First Modified Consent Order included a condition that the Company would take certain other actions if requested by the PaDEP and agreed to by the Company, which could include the plugging and abandonment of up to 10 additional wells. As part of the settlement, the Company paid a $240,000 civil penalty and the First Modified Consent Order included a provision that the Company would pay an additional $30,000 per month until certain terms under the First Modified Consent Order were satisfied.
On July 19, 2010, the Company and the PaDEP executed a Second Modification to Consent Order (Second Modified Consent Order) acknowledging that the Company plugged and abandoned the three vertical natural gas wells and completed work on the fourth natural gas well to the PaDEP's satisfaction. As a result, the PaDEP agreed to commence the processing and issuance of new well drilling permits outside the area of concern so long as the Company continued to provide temporary potable water and offered to provide gas/water separators to 14 households. No penalties were assessed under the Second Modified Consent Order.
As outlined in the Second Modified Consent Order, the Company made offers to provide whole-house water treatment systems to 14 households. On August 5, 2010 the Company filed with the PaDEP its report, prepared by its experts, finding that the Company's natural gas well drilling and development activities were not the source of methane gas reported to be in the groundwater and water wells in the area of concern.
In a September 14, 2010 letter to the Company, the PaDEP rejected the Company's expert report and stated its determination that the Company's drilling activities continue to cause the unpermitted discharge of natural gas into the groundwater and continue to affect residential water supplies in the area of concern. The PaDEP directed the Company to plug or take remedial actions at the remaining 10 natural gas wells and to contact the PaDEP to discuss connecting the impacted water supplies into community public water systems.
In a September 28, 2010 reply letter to the PaDEP, the Company disagreed with the PaDEP's rejection of the Company's expert report, disagreed that the remaining 10 natural gas wells continue to impact groundwater and affect residential water supplies and disagreed that a community public water system is necessary or feasible. The Company believed that offering installation of a whole-house water treatment system to the 14 households constituted compliance with the Company's obligations under these consent orders. The Company also asserted its belief that the Consent Order, First Modified Consent Order and Second Modified Consent Order were unlawful and not legally binding or enforceable.
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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
7. Commitments and Contingencies (Continued)
On December 15, 2010, the Company entered into a consent order and settlement agreement with the PaDEP (CO&SA), which according to its terms supersedes and/or replaces the Consent Order, the First Modified Consent Order and the Second Modified Consent Order. Under the CO&SA, among other things, the Company agreed to place a total of $4.2 million into escrow accounts for the benefit of each of the identified households, pay $500,000 to the PaDEP to reimburse the PaDEP for its costs, perform remedial measures for two natural gas wells in the area of concern, provide pressure, water quality and water well headspace data to the PaDEP and offer water treatment to the households. The CO&SA settled all outstanding issues and claims that are known and that could have been brought against the Company by the PaDEP relating to the natural gas wells in the affected area and the Consent Order, the First Modified Consent Order and the Second Modified Consent Order. It also allows the Company to seek to begin hydraulic fracturing and to commence drilling new wells in the affected areas after providing the PaDEP with certain data and information. Under the CO&SA, the Company has no obligation to connect the impacted water supplies to a community public water system.
On January 11, 2011, certain of the affected households appealed the CO&SA to the Pennsylvania Environmental Hearing Board (PEHB).
The Company is in continuing discussions with the PaDEP to address the results of the Company's natural gas well test data, water quality sampling and water well headspace screenings. The Company requested PaDEP approval to resume hydraulic fracturing and new natural gas well drilling operations in the affected area, along with a request to cease temporary water deliveries to the affected households. On October 18, 2011, the PaDEP concurred that temporary water deliveries to the property owners are no longer necessary.
On November 18, 2011, certain of the affected households appealed to the PEHB the PaDEP's October 18, 2011 determination that temporary water deliveries were no longer necessary to the property owners and on November 23, 2011 filed a Petition for Supersedeas in the appeal. On December 9, 2011, the PEHB denied the Petition for Supersedeas and consolidated the appeal of the CO&SA with the appeal of the October 18, 2011 determination. A hearing on the consolidated matter is expected to occur in 2012.
As of December 31, 2011, the Company has paid $1.3 million in settlement of fines and penalties sought or claimed by the PaDEP related to this matter, paid $2.0 million (through the escrow process) to seven of the affected households and accrued a $2.2 million settlement liability that represents the unpaid escrow balance, which is included in Other Liabilities in the Consolidated Balance Sheet.
United States Environmental Protection Agency
By letter dated January 6, 2012, the United States Environmental Protection Agency (EPA) sent a Required Submission of Information-Dimock Township Drinking Water Contamination letter to the Company pursuant to the Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended (CERCLA). The Required Submission of Information requests all documents, water sampling results and any other correspondence related to the Company's activities in the area of concern. The Company does not agree that the Submission of Information is required; however, the Company is providing information pursuant to the request.
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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
8. Asset Retirement Obligation
Activity related to the Company's asset retirement obligation during the year ended December 31, 2011 is as follows:
Accretion expense for the years ended December 31, 2011, 2010 and 2009 was $3.3 million, $1.9 million and $1.3 million, respectively.
9. Supplemental Cash Flow Information
Cash paid / (received) for interest and income taxes are as follows:
10. Capital Stock
Incentive Plans
Under the Company's 2004 Incentive Plan, incentive and non-statutory stock options, stock appreciation rights (SARs), stock awards, cash awards and performance awards may be granted to key employees, consultants and officers of the Company. Non-employee directors of the Company may be granted discretionary awards under the 2004 Incentive Plan consisting of stock options or stock awards. A total of 10,200,000 shares of common stock may be issued under the 2004 Incentive Plan. Under the 2004 Incentive Plan, no more than 3,600,000 shares may be used for stock awards that are not subject to the achievement of performance based goals, and no more than 6,000,000 shares may be issued pursuant to incentive stock options.
Stock Split
On January 3, 2012, the Board of Directors declared a 2-for-1 split of the Company's common stock in the form of a stock dividend. The stock dividend was distributed on January 25, 2012 to shareholders of record as of January 17, 2012. All common stock accounts and per share data have been retroactively adjusted to give effect to the 2-for-1 split of the Company's common stock.
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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
10. Capital Stock (Continued)
Treasury Stock
The Board of Directors has authorized a share repurchase program under which the Company may purchase shares of common stock in the open market or in negotiated transactions. The timing and amount of these stock purchases are determined at the discretion of management. The Company may use the repurchased shares to fund stock compensation programs presently in existence, or for other corporate purposes. All purchases executed to date have been through open market transactions. There is no expiration date associated with the authorization to repurchase securities of the Company.
During the year ended December 31, 2011, the Company did not repurchase any shares of common stock. Since the authorization date, the Company has repurchased 10,409,400 shares of the 20 million total shares authorized for a total cost of approximately $85.7 million. The repurchased shares were held as treasury stock with 10,005,000 shares having been subsequently retired. No treasury shares have been delivered or sold by the Company subsequent to the repurchase. As of December 31, 2011, 404,400 shares were held as treasury stock.
Dividend Restrictions
The Board of Directors of the Company determines the amount of future cash dividends, if any, to be declared and paid on the common stock depending on, among other things, the Company's financial condition, funds from operations, the level of its capital and exploration expenditures, and its future business prospects. None of the note or credit agreements in place have a restricted payment provision or other provision limiting dividends.
Expired Purchase Rights Plan
On January 21, 1991, the Board of Directors adopted the Preferred Stock Purchase Rights Plan and declared a dividend distribution of one right for each outstanding share of common stock. On December 8, 2000, the rights agreement for the plan was amended and restated to extend the term of the plan to 2010 and to make other changes. The rights plan expired on January 21, 2010. At December 31, 2010 there were no shares of Junior Preferred Stock issued or outstanding.
11. Stock-Based Compensation
Compensation expense charged against income for stock-based awards (including the supplemental employee incentive plan) for the years ended December 31, 2011, 2010 and 2009 was $39.5 million, $14.4 million and $25.1 million, respectively, and is included in General and Administrative expense in the Consolidated Statement of Operations.
For the year ended December 31, 2009, the Company realized a $13.8 million tax benefit related to the federal tax deduction in excess of book compensation cost for employee stock-based compensation for 2008. For regular federal income tax purposes, the Company was in a net operating loss position in 2008. As the Company carried back net operating losses concurrent with its 2008 tax return filing, the income tax benefit related to stock-based compensation was recorded in 2009. In accordance with ASC 718, the Company is able to recognize this tax benefit only to the extent it reduces the Company's income taxes payable.
There were no excess tax benefits recorded for the years ended December 31, 2011 and 2010 as the Company was in a net operating loss position for federal tax purposes. As of December 31, 2011,
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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
11. Stock-Based Compensation (Continued)
the Company had cumulative unrecorded excess tax benefits for employee stock-based compensation of $5.2 million.
Restricted Stock Awards
Most restricted stock awards vest either at the end of a three year service period or on a graded-vesting basis at each anniversary date over a three or four year service period. For awards that vest at the end of the three year service period, expense is recognized ratably using a straight-line expensing approach over three years. Under the graded-vesting approach, the Company recognizes compensation cost ratably over the three or four year requisite service period, as applicable, for each separately vesting tranche as though the awards are, in substance, multiple awards. For all restricted stock awards, vesting is dependent upon the employees' continued service with the Company, with the exception of employment termination due to death, disability or retirement.
The fair value of restricted stock grants is based on the average of the high and low stock price on the grant date. The maximum contractual term is four years. In accordance with ASC 718, the Company accelerated the vesting period for retirement-eligible employees for purposes of recognizing compensation expense in accordance with the vesting provisions of the Company's stock-based compensation programs for awards issued after the adoption of ASC 718. The Company used an annual forfeiture rate of 7.0% for purposes of recognizing stock-based compensation expense for restricted stock awards. The annual forfeiture rates were based on approximately ten years of the Company's history for this type of award to various employee groups.
The following table is a summary of restricted stock award activity for the year ended December 31, 2011:
(1)The aggregate intrinsic value of restricted stock awards is calculated by multiplying the closing market price of the Company's stock on December 30, 2011 by the number of non-vested restricted stock awards outstanding.
As shown in the table above, there were 19,600 shares of restricted stock granted to employees during 2011 with a weighted-average grant date fair value per share of $27.66. During the year ended December 31, 2010, 47,600 shares of restricted stock were granted to employees with a weighted-average grant date fair value per share of $17.44. During the year ended December 31, 2009, 290,120 shares of restricted stock were granted to employees with a weighted-average grant date fair value per
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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
11. Stock-Based Compensation (Continued)
share of $17.48. The total fair value of shares vested during 2011, 2010 and 2009 was $0.2 million, $1.5 million and $1.2 million, respectively.
Compensation expense recorded for all restricted stock awards for the years ended December 31, 2011, 2010 and 2009 was $1.2 million, $1.8 million and $1.2 million, respectively. Unamortized expense as of December 31, 2011 for all outstanding restricted stock awards was $1.3 million and will be recognized over the next 0.8 years.
Restricted Stock Units
Restricted stock units are granted from time to time to non-employee directors of the Company. The fair value of these units is measured at the average of the high and low stock price on grant date and compensation expense is recorded immediately. These units immediately vest and are issued when the director ceases to be a director of the Company.
The following table is a summary of restricted stock unit activity for the year ended December 31, 2011:
(1)The intrinsic value of restricted stock units is calculated by multiplying the closing market price of the Company's stock on December 30, 2011 by the number of outstanding restricted stock units.
(2)Due to the immediate vesting of the units and the unknown term of each director, the weighted-average remaining contractual term in years has been omitted from the table above.
As shown in the table above, 59,402 restricted stock units were granted with a weighted-average grant date fair value per share of $20.88 during 2011. During 2010, 53,922 restricted stock units were granted with a weighted-average grant date fair value per share of $20.04. During 2009, 66,300 restricted stock units were granted with a weighted-average grant date fair value per share of $11.32.
During the years ended December 31, 2011, 2010 and 2009, compensation cost recorded, which reflects the total fair value of these units, was $1.2 million, $1.1 million and $0.8 million, respectively.
Stock Options
Stock option awards are granted with an exercise price equal to the average of the high and low trading price of the Company's stock at the date of grant. During the years ended December 31, 2011, 2010 and 2009, there were no stock options granted. During 2011 and 2010 there was no compensation expense recorded. Compensation expense recorded for stock options for 2009 was less than $0.1 million. There was no unamortized expense as of December 31, 2011 for stock options.
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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
11. Stock-Based Compensation (Continued)
The following table is a summary of stock option activity for the years ended December 31, 2011, 2010 and 2009:
The total intrinsic value of options exercised during the years ended December 31, 2011, 2010 and 2009 was $0.2 million, $0.5 million and $0.1 million, respectively.
Stock Appreciation Rights
Stock appreciation rights (SARs) allow the employee to receive any intrinsic value over the grant date market price that may result from the price appreciation on a set number of common shares during the contractual term of seven years. All of these awards have graded-vesting features and will vest over a service period of three years, with one-third of the award becoming exercisable each year on the anniversary date of the grant. The Company calculates the fair value using a Black-Scholes model.
The assumptions used in the Black-Scholes fair value calculation on the date of grant for SARs are as follows:
The expected term was derived by reviewing minimum and maximum expected term outputs from the Black-Scholes model based on award type and employee type. This term represents the period of time that awards granted are expected to be outstanding. The stock price volatility was calculated using historical closing stock price data for the Company for the period associated with the expected term through the grant date of each award. The risk free rate of return percentages are based on the continuously compounded equivalent of the U.S. Treasury (Nominal 10) within the expected term as
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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
11. Stock-Based Compensation (Continued)
measured on the grant date. The expected dividend percentage assumes that the Company will continue to pay a consistent level of dividend each quarter.
The following table is a summary of SAR activity for the years ended December 31, 2011, 2010 and 2009:
(1)The intrinsic value of a SAR is the amount which the current market value of the underlying stock exceeds the exercise price of the SAR. The aggregate intrinsic value of SARs outstanding at December 31, 2011 was $28.2 million. The weighted-average remaining contractual term is 3.4 years.
(2)The aggregate intrinsic value of SARs exercisable at December 31, 2011 was $20.6 million. The weighted-average remaining contractual term is 2.5 years.
During 2011, the Compensation Committee granted 191,500 SARs to employees at a weighted-average exercise price equal to the grant date market price of $20.37. Compensation expense recorded during the years ended December 31, 2011, 2010 and 2009 for all outstanding SARs was $2.1 million, $1.6 million and $1.8 million, respectively. In 2011, 2010 and 2009 there was $0.1 million, $0 and $0.7 million, related to the immediate expensing of shares granted to retirement-eligible employees, respectively. Unamortized expense as of December 31, 2011 for all outstanding SARs was $0.3 million. The weighted-average period over which this compensation will be recognized is approximately 2.0 years.
Performance Share Awards
During 2011, three types of performance share awards were granted to employees for a total of 789,514 performance shares, which included 604,122 performance share awards based on performance conditions measured against the Company's internal performance metrics and 185,392 performance share awards based on market conditions. The Company used an annual forfeiture rate assumption ranging from 0% to 7% for purposes of recognizing stock-based compensation expense for all performance share awards. The performance period for the awards granted in 2011 commenced on January 1, 2011 and ends on December 31, 2013.
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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
11. Stock-Based Compensation (Continued)
The performance awards based on internal metrics had a grant date per share value of $20.37, which is based on the average of the high and low stock price on the grant date. These awards represent the right to receive up to 100% of the award in shares of common stock.
Of the 604,122 performance awards based on internal metrics, 185,392 shares have a three-year graded performance period. For these shares, one-third of the shares are issued on each anniversary date following the date of grant, provided that the Company has $100 million or more of operating cash flow for the year preceding the vesting date. If the Company does not meet this metric for the applicable period, then the portion of the performance shares that would have been issued on that date will be forfeited. As of December 31, 2011, it is considered probable that this performance metric will be met.
For the remaining 418,730 performance awards based on internal metrics, the actual number of shares issued at the end of the performance period will be determined based on the Company's performance against three performance criteria set by the Company's Compensation Committee. An employee will earn one-third of the award granted for each internal performance metric that the Company meets at the end of the performance period. These performance criteria measure the Company's average production, average finding costs and average reserve replacement over three years. Based on the Company's probability assessment at December 31, 2011, it is considered probable that these three criteria will be met for all outstanding awards.
The 185,392 performance shares based on market conditions are earned, or not earned, based on the comparative performance of the Company's common stock measured against sixteen other companies in the Company's peer group over a three-year performance period. The performance shares based on market conditions have both an equity and liability component. The equity portion of the 2011 awards was valued on the grant date (February 17, 2011) and was not marked to market. The liability portion of the awards was valued as of December 31, 2011 on a mark-to-market basis.
The following assumptions were used for the performance shares based on market conditions using a Monte Carlo model to value the liability and equity components of the awards. The four primary inputs for the Monte Carlo model are the risk-free rate, volatility of returns, correlation in movement of total shareholder return and the expected dividend. An interpolated risk-free rate was generated from the Federal Reserve website for constant maturity treasuries for two and three year bonds (as of the reporting date) set equal to the remaining duration of the performance period. Volatility was set equal to the annualized daily volatility for the remaining duration of the performance period ending on the reporting date. Correlation in movement of total shareholder return was determined based on a correlation matrix that was created which identifies total shareholder return correlations for each pair of companies in the peer group, including the Company. The paired returns in the correlation matrix ranged from 56.8% to 100.0% for the Company and its peer group. The expected dividend is calculated using the total Company annual dividends expected to be paid divided by the closing price of the Company's stock at the valuation date. Based on these inputs discussed above, a ranking was projected identifying the Company's rank relative to the peer group for each award period.
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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
11. Stock-Based Compensation (Continued)
The following assumptions were used for the Monte Carlo model to determine the grant date fair value of the equity component of the performance share awards based on market conditions for the respective periods:
The following assumptions were used in the Monte Carlo model to determine the fair value of the liability component of the performance share awards based on market conditions for the respective periods:
The long-term liability for market condition performance share awards, included in Other Liabilities in the Consolidated Balance Sheet, at December 31, 2011 and 2010 was $5.6 million and $0.6 million, respectively. The short-term liability, included in Accrued Liabilities in the Consolidated Balance Sheet, at December 31, 2011 and 2010 was $10.1 million and $2.4 million, respectively.
On December 31, 2011, the performance period ended for two types of performance shares awarded in 2009, including 594,960 shares measured based on internal performance metrics of the Company and 393,620 shares measured based on the Company's performance against a peer group. For the internal performance metric awards, the calculation of the average of the three years of the Company's three internal performance metrics was completed in the first quarter of 2012 and was certified by the Compensation Committee in February 2012. As the Company achieved the three internal performance metrics, 100% of the award, valued at $6.7 million based on the average of the high and low stock price on the grant date, was payable in 594,960 shares of common stock. For the peer group awards, due to the ranking of the Company compared to its peers in its predetermined peer group, 100% of the award, valued at $3.5 million based on the Monte Carlo value on the grant date, was payable in 393,620 shares of common stock and an additional 67%, equal to two-thirds of the total value of the award, calculated by using the average of the high and low stock price on December 30, 2011 multiplied by the number of performance shares earned, or $10.1 million, was payable in cash. The calculation of the award payout was certified by the Compensation Committee on January 3, 2012
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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
11. Stock-Based Compensation (Continued)
and payout occurred in January 2012. The vesting of both types of shares discussed above will be reported in the first quarter of 2012.
The following table is a summary of performance share award activity for the year ended December 31, 2011:
(1)The fair value figures in this table represent the fair value of the equity component of the performance share awards.
(2)The aggregate intrinsic value of performance share awards is calculated by multiplying the closing market price of the Company's stock on December 30, 2011 by the number of non-vested performance share awards outstanding.
Of the performance shares that vested during 2011 shown in the table above, 471,744 shares were granted in 2008. A total of 145,024 shares (valued at $2.7 million) were measured based on the Company's performance against a peer group and were issued. A total of 287,600 shares (valued at $5.9 million) measured based on internal performance metrics of the Company were also issued. During 2011, 187,516 shares vested (valued at $3.9 million) which represents one-third of the three-year graded vesting schedule performance share awards granted in 2010, 2009 and 2008 with a grant date per share value of $20.27, $11.32 and $24.24, respectively.
During the year ended December 31, 2010, 694,340 performance share awards were granted to employees with a weighted-average grant date fair value per share of $19.24. Of the 820,538 performance shares that vested during 2010, 184,800 shares were granted in 2007. These shares (valued at $2.8 million) were measured based on the Company's performance against a peer group and were issued in addition to cash of $1.3 million. A total of 300,200 shares (valued at $5.3 million) measured based on internal performance metrics of the Company were also issued. During 2010, 335,538 shares vested (valued at $5.1 million) which represents one-third of the three-year graded vesting schedule performance share awards granted in 2009, 2008, and 2007 with a grant date per share value of $11.32, 24.24 and $17.61, respectively.
During the year ended December 31, 2009, 1,570,700 performance share awards were granted to employees with a weighted-average grant date fair value per share of $10.65. Of the 665,284 performance shares that vested during 2009, 211,600 shares were granted in 2006. These shares (valued at $1.7 million) were measured based on the Company's performance against a peer group and were issued in addition to cash of $1.8 million. A total of 311,600 shares (valued at $3.8 million) measured based on internal performance metrics of the Company were also issued. During 2009, 121,480 shares vested (valued at $2.5 million) which represents one-third of the three-year graded vesting schedule
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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
11. Stock-Based Compensation (Continued)
performance share awards granted in 2008 and 2007 with a grant date per share value of $24.24 and $17.61, respectively. In addition, 20,604 performance shares vested as a result of early vesting schedules for certain employees. These awards met the performance criteria that the Company had positive operating income for 2008 and 2007.
During 2011, 2010 and 2009, 65,700, 80,360 and 240,180 performance shares, respectively, were forfeited.
Total unamortized compensation cost related to the equity component of performance shares at December 31, 2011 was $12.2 million and will be recognized over the next 1.9 years, computed by using the weighted-average of the time in years remaining to recognize unamortized expense. Total compensation cost recognized for both the equity and liability components of all performance share awards during the years ended December 31, 2011, 2010 and 2009 was $28.5 million, $12.4 million and $15.6 million, respectively.
Deferred Performance Shares
As of December 31, 2011, 267,086 shares of the Company's common stock representing vested performance share awards were deferred into the Rabbi Trust Deferred Compensation Plan. A total of 81,549 shares were sold out of the plan in 2011. During 2011, a decrease to the rabbi trust deferred compensation liability of $1.4 million was recognized, representing a decrease in the investment excluding the Company's common stock and the reduction in the liability due to shares that were sold out of the rabbi trust, partially offset by an increase in the closing price of the Company's common stock from December 31, 2010 to December 31, 2011. The increase in stock-based compensation expense was included in General and Administrative expense in the Consolidated Statement of Operations.
Supplemental Employee Incentive Plan
On July 24, 2008, the Company's Board of Directors adopted a Supplemental Employee Incentive Plan (the "Plan"). The Plan was intended to provide a compensation tool tied to stock market value creation to serve as an incentive and retention vehicle for full-time non-officer employees by providing for cash payments in the event the Company's common stock reaches a specified trading price.
The Plan provides for a final payout if, for any 20 trading days (which need not be consecutive) that fall within a period of 60 consecutive trading days ending on or before June 30, 2012, the closing price per share of the Company's common stock equals or exceeds the price goal of $52.50 per share. In such event, the 20th trading day on which such price condition is attained is the Final Trigger Date. The price goal is subject to adjustment by the Compensation Committee to reflect any stock splits, stock dividends or extraordinary cash distributions to stockholders. Under the Plan, each eligible employee may receive (upon approval by the Compensation Committee) a distribution of 50% of his or her base salary as of the Final Trigger Date. Payments under the final distribution will occur on the 15th business day following the Final Trigger Date. Payments are subject to certain other restrictions contained in the Plan.
The Plan also provided that a distribution of 20% of an eligible employee's base salary as of the Interim Trigger Date will be made (upon approval by the Compensation Committee) upon achieving
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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
11. Stock-Based Compensation (Continued)
the interim price goal of $85 per share on or before June 30, 2010. The Company did not meet this interim trigger and therefore no distribution was made as of the Interim Trigger Date.
These awards have been accounted for as liability awards under ASC 718. The Company recognized an expense of $1.2 million for 2011, a benefit of $0.9 million for 2010 and an expense of $1.2 million for 2009, which is included in General and Administrative expense in the Consolidated Statement of Operations.
12. Derivative Instruments and Hedging Activities
The Company periodically enters into commodity derivative instruments to hedge its exposure to price fluctuations on natural gas and crude oil production. The Company's credit agreement restricts the ability of the Company to enter into commodity hedges other than to hedge or mitigate risks to which the Company has actual or projected exposure or as permitted under the Company's risk management policies and not subjecting the Company to material speculative risks. All of the Company's derivatives are used for risk management purposes and are not held for trading purposes. As of December 31, 2011, the Company had 37 derivative contracts open: 23 natural gas price swap arrangements, six natural gas basis swaps arrangements, three crude oil price swap arrangements and five natural gas collar arrangements. During 2011, the Company entered into 31 new derivative contracts covering anticipated natural gas and crude oil production for 2011, 2012, and 2013.
As of December 31, 2011, the Company had the following outstanding commodity derivatives:
The change in fair value of derivatives designated as hedges that is effective is recorded to Accumulated Other Comprehensive Income in Stockholders' Equity in the Consolidated Balance Sheet. The ineffective portion of the change in the fair value of derivatives designated as hedges, and the change in fair value of derivatives not designated as hedges, are recorded currently in earnings as a component of Natural Gas revenue and Crude Oil and Condensate revenue in the Consolidated Statement of Operations.
CABOT OIL & GAS CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
12. Derivative Instruments and Hedging Activities (Continued)
The following tables reflect the fair value of derivative instruments on the Company's consolidated financial statements:
Effect of Derivative Instruments on the Consolidated Balance Sheet
At December 31, 2011 and 2010, unrealized gains of $198.3 million ($121.3 million, net of tax) and $16.9 million ($10.5 million, net of tax), respectively, were recorded in Accumulated Other Comprehensive Income in the Consolidated Balance Sheet. Based upon estimates at December 31, 2011, the Company expects to reclassify $108.3 million in after-tax income associated with its commodity hedges from Accumulated Other Comprehensive Income to the Consolidated Statement of Operations over the next 12 months.
Effect of Derivative Instruments on the Consolidated Statement of Operations
CABOT OIL & GAS CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
12. Derivative Instruments and Hedging Activities (Continued)
For the years ended December 31, 2011, 2010 and 2009, respectively, there was no ineffectiveness recorded in our Consolidated Statement of Operations related to our derivative instruments.
Additional Disclosures about Derivative Instruments and Hedging Activities
The use of derivative instruments involves the risk that the counterparties will be unable to meet their obligation under the agreement. The Company enters into derivative contracts with multiple counterparties in order to limit its exposure to individual counterparties. The Company also has netting arrangements with all of its counterparties that allow it to offset payables against receivables from separate derivative contracts with that counterparty.
The counterparties to the Company's derivative instruments are also lenders under its credit facility. The Company's credit facility and derivative instruments contain certain cross default and acceleration provisions that may require immediate payment of its derivative liability in certain situations.
13. Fair Value Measurements
ASC 820, "Fair Value Measurements and Disclosures," established a formal framework for measuring fair values of assets and liabilities in financial statements that are already required by GAAP to be measured at fair value. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The transaction is based on a hypothetical transaction in the principal or most advantageous market considered from the perspective of the market participant that holds the asset or owes the liability.
The Company utilizes market data or assumptions that market participants who are independent, knowledgeable and willing and able to transact would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. The Company attempts to utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The Company is able to classify fair value balances based on the observability of those inputs. ASC 820 establishes formal fair value hierarchy based on the inputs used to measure fair value. The hierarchy gives the highest priority to Level 1 measurements and the lowest priority to Level 3 measurements.
The three levels of the fair value hierarchy as defined by ASC 820 are as follows:
•Level 1: Valuations utilizing quoted, unadjusted prices for identical assets or liabilities in active markets that the Company has the ability to access. This is the most reliable evidence of fair value and does not require a significant degree of judgment. Examples include exchange-traded derivatives and listed equities that are actively traded.
CABOT OIL & GAS CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
13. Fair Value Measurements (Continued)
•Level 2: Valuations utilizing quoted prices in markets that are not considered to be active or financial instruments for which all significant inputs are observable, either directly or indirectly for substantially the full term of the asset or liability. Financial instruments that are valued using models or other valuation methodologies are included. Models used should primarily be industry-standard models that consider various assumptions and economic measures, such as interest rates, yield curves, time value, volatilities, contract terms, current market prices, credit risk or other market-corroborated inputs. Examples include most over-the-counter derivatives (non-exchange traded), physical commodities, most structured notes and municipal and corporate bonds.
•Level 3: Valuations utilizing significant, unobservable inputs. This provides the least objective evidence of fair value and requires a significant degree of judgment. Inputs may be used with internally developed methodologies and should reflect an entity's assumptions using the best information available about the assumptions that market participants would use in pricing an asset or liability. Examples include certain corporate loans, real-estate and private equity investments and long-dated or complex over-the-counter derivatives.
Depending on the particular asset or liability, input availability can vary depending on factors such as product type, longevity of a product in the market and other particular transaction conditions. In some cases, certain inputs used to measure fair value may be categorized into different levels of the fair value hierarchy. For disclosure purposes under ASC 820, the lowest level that contains significant inputs used in valuation should be chosen. In accordance with ASC 820, the Company has classified its assets and liabilities into these levels depending upon the data relied on to determine the fair values.
Non-Financial Assets and Liabilities
The Company discloses or recognizes its non-financial assets and liabilities, such as impairments of oil and gas properties and other assets, at fair value on a nonrecurring basis. During the years ended December 31, 2010 and 2009, the Company recorded impairment charges related to certain oil and gas properties and other assets. Refer to Note 2 for additional disclosures related to fair value associated with the impaired assets. As none of the Company's other non-financial assets and liabilities were impaired as of December 31, 2011, 2010 and 2009 and no other fair value measurements were required to be recognized on a non-recurring basis, additional disclosures were not provided.
CABOT OIL & GAS CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
13. Fair Value Measurements (Continued)
Financial Assets and Liabilities
Our financial assets and liabilities are measured at fair value on a recurring basis. The following fair value hierarchy table presents information about the Company's financial assets and liabilities measured at fair value on a recurring basis as of December 31, 2011 and 2010:
The Company's investments associated with its Rabbi Trust Deferred Compensation Plan consist of mutual funds and deferred shares of the Company's common stock that are publicly traded and for which market prices are readily available. The derivative contracts were measured based on quotes from the Company's counterparties. Such quotes have been derived using valuation models that consider various inputs including current market and contractual prices for the underlying instruments, quoted forward prices for natural gas and crude oil, volatility factors and interest rates, such as a LIBOR curve for a similar length of time as the derivative contract term as applicable. These estimates are verified using relevant NYMEX futures contracts or are compared to multiple quotes obtained
CABOT OIL & GAS CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
13. Fair Value Measurements (Continued)
from counterparties for reasonableness. The Company measured the nonperformance risk of its counterparties by reviewing credit default swap spreads for the various financial institutions in which it has derivative transactions. In times where the Company has net derivative contract liabilities, the nonperformance risk of the Company is evaluated using a market credit spread provided by the Company's bank. The impact of non-performance risk relative to the Company's derivative contracts was $1.4 million and $0.1 million at December 31, 2011 and 2010, respectively.
The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy:
(1)A loss of $1.0 million, $0.2 million and $2.0 million for the years ended December 31, 2011, 2010 and 2009, respectively, was unrealized and included in Natural Gas revenues in the Consolidated Statement of Operations.
There were no transfers between Level 1 and Level 2 measurements for the years ended December 31, 2011, 2010 and 2009.
Fair Value of Other Financial Instruments
The estimated fair value of financial instruments is the amount at which the instrument could be exchanged currently between willing parties. The carrying amounts reported in the Consolidated Balance Sheet for cash and cash equivalents, accounts receivable and accounts payable approximate fair value due to the short-term maturities of these instruments.
The fair value of long-term debt is the estimated cost to acquire the debt, including a credit spread for the difference between the issue rate and the period end market rate. The credit spread is the Company's default or repayment risk. The credit spread (premium or discount) is determined by comparing the Company's fixed-rate notes and credit facility to new issuances (secured and unsecured) and secondary trades of similar size and credit statistics for both public and private debt. The fair value of all of the fixed-rate notes and credit facility is based on interest rates currently available to the Company.
CABOT OIL & GAS CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
13. Fair Value Measurements (Continued)
The Company uses available market data and valuation methodologies to estimate the fair value of debt. The carrying amounts and fair values of long-term debt are as follows:
14. Earnings per Common Share
Basic EPS is computed by dividing net income (the numerator) by the weighted-average number of common shares outstanding for the period (the denominator). Diluted EPS is similarly calculated except that the denominator is increased using the treasury stock method to reflect the potential dilution that could occur if outstanding stock options and stock appreciation rights were exercised and stock awards were vested at the end of the applicable period.
The following is a calculation of basic and diluted weighted-average shares outstanding:
CABOT OIL & GAS CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
15. Accumulated Other Comprehensive Income / (Loss)
Changes in the components of accumulated other comprehensive income / (loss), net of taxes, were as follows:
CABOT OIL & GAS CORPORATION
SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)
Oil and Gas Reserves
Users of this information should be aware that the process of estimating quantities of "proved" and "proved developed" natural gas and crude oil reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures.
Estimates of total proved reserves at December 31, 2011, 2010 and 2009 were based on studies performed by the Company's petroleum engineering staff. The estimates were computed using the 12-month average oil and natural gas index prices, calculated as the unweighted arithmetic average for the first day of the month price for each month during the respective year, as prescribed under the revised rules codified in ASC 932, "Extractive Activities-Oil and Gas." The estimates were audited by Miller and Lents, Ltd., who indicated that based on their investigation and subject to the limitations described in their audit letter, they believe the results of those estimates and projections were reasonable in the aggregate.
No major discovery or other favorable or unfavorable event after December 31, 2011, is believed to have caused a material change in the estimates of proved or proved developed reserves as of that date.
As of December 31, 2009, the Company adopted the guidance in ASC 932 related to oil and gas reserve estimation and disclosures in conjunction with the year-end reserve reporting as a change in accounting principle that is inseparable from a change in accounting estimate. The impact of the adoption of this guidance on the Company's financial statements was not practicable to estimate due to the challenges associated with computing a cumulative effect of adoption by preparing reserve reports under both the old and new guidance.
The following tables illustrate the Company's net proved reserves, including changes, and proved developed and proved undeveloped reserves for the periods indicated, as estimated by the Company's engineering staff. All reserves are located within the continental United States in 2011, 2010 and 2009.
(1)Includes natural gas and natural gas equivalents determined by using the ratio of 6 Mcf of natural gas to 1 Bbl of crude oil, condensate or natural gas liquids.
(2)Prior to 2009, reserve estimates were based on year end prices.
(3)The net downward revision of 200.1 Bcfe was primarily due to (i) downward revisions of 101.6 Bcfe due to lower 2009 oil and natural gas prices compared to 2008 and (ii) downward revisions of 120.4 Bcfe due to the removal of proved undeveloped reserves scheduled for development beyond five years primarily due to the application of the SEC's oil and gas reserve calculation methodology effective beginning in 2009, partially offset by 21.9 Bcfe of positive performance revisions.
(4)Extensions, discoveries and other additions were primarily related to drilling activity in the Dimock field located in northeast Pennsylvania. The Company added 616.1 Bcfe, 536.6 Bcfe and 361.6 Bcfe of proved reserves in this field in 2011, 2010 and 2009, respectively.
(5)The net upward revision of 136.7 Bcfe was primarily due to (i) an upward performance revision of 284.4 Bcfe, primarily in the Dimock field in northeast Pennsylvania, and (ii) an upward revision of 35.0 Bcfe associated with increased reserve commodity pricing partially offset by a downward revision of 182.7 Bcfe of proved undeveloped reserves that are no longer in our five-year development plan.
(6)The net upward revision of 21.6 Bcfe was primarily due to an upward performance revision of 214.9 Bcfe, primarily in the Dimock field in northeast Pennsylvania, partially offset by (i) a downward revision of 189.8 Bcfe of proved undeveloped reserves that are no longer in our five-year development plan and (ii) a downward revision of 3.6 Bcfe associated with reduced reserve commodity pricing.
(7)Sales of reserves in place were primarily related to the divestiture of certain oil and gas properties in Colorado, Utah and Wyoming in October 2011 which represented 170.3 Bcfe.
Capitalized Costs Relating to Oil and Gas Producing Activities
The following table illustrates the total amount of capitalized costs relating to natural gas and crude oil producing activities and the total amount of related accumulated depreciation, depletion and amortization.
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities
Costs incurred in property acquisition, exploration and development activities were as follows:
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
The following information has been developed utilizing the guidance in ASC 932 and based on natural gas and crude oil reserve and production volumes estimated by the Company's engineering staff. It can be used for some comparisons, but should not be the only method used to evaluate the Company or its performance. Further, the information in the following table may not represent realistic
assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flows be viewed as representative of the current value of the Company.
The Company believes that the following factors should be taken into account when reviewing the following information:
•Future costs and selling prices will probably differ from those required to be used in these calculations.
•Due to future market conditions and governmental regulations, actual rates of production in future years may vary significantly from the rate of production assumed in the calculations.
•Selection of a 10% discount rate is arbitrary and may not be a reasonable measure of the relative risk that is part of realizing future net oil and gas revenues.
•Future net revenues may be subject to different rates of income taxation.
Under the Standardized Measure, future cash inflows for 2011, 2010 and 2009 were estimated by using the 12-month average oil and gas index prices, calculated as the unweighted arithmetic average for the first day of the month price for each month during the year, as prescribed under the revised rules codified in ASC 932 that the Company adopted on January 1, 2009, and by applying year end oil and gas prices to the estimated future production of year end proved reserves for 2008.
The average prices (adjusted for basis and quality differentials) related to proved reserves at December 31, 2011, 2010 and 2009 for natural gas ($ per Mcf) were $4.27, $4.33 and $3.84, respectively, and for oil ($ per Bbl) were $94.00, $74.25 and $55.41, respectively. Future cash inflows were reduced by estimated future development and production costs based on year end costs to arrive at net cash flow before tax. Future income tax expense was computed by applying year end statutory tax rates to future pretax net cash flows, less the tax basis of the properties involved and utilization of available tax carryforwards related to oil and gas operations. ASC 932 requires the use of a 10% discount rate.
Management does not solely use the following information when making investment and operating decisions. These decisions are based on a number of factors, including estimates of proved reserves, and varying price and cost assumptions considered more representative of a range of anticipated economic conditions.
Standardized Measure is as follows:
Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
The following is an analysis of the changes in the Standardized Measure:
CABOT OIL & GAS CORPORATION
SELECTED DATA (UNAUDITED)
QUARTERLY FINANCIAL INFORMATION
(1)Operating Income and Net Income in 2011 contain a $34.2 million gain on the disposition of certain Haynesville and Bossier Shale oil and gas properties in east Texas in the second quarter and an aggregate gain of $29.2 million from the sale of various other properties primarily in the fourth quarter of 2011.
(2)All Earnings per Share figures have been retroactively adjusted for the 2-for-1 split of the Company's common stock effective January 25, 2012.
(3)Operating Income and Net Income in 2010 contain an aggregate gain of $4.5 million from the sale of various oil and gas properties in the second quarter and a gain of $11.4 million related to the sale of certain oil and gas properties in Texas, a gain of $49.3 million associated with the sale of the Pennsylvania gathering infrastructure and a $40.7 million gain from the sale of the Company's investment in Tourmaline in the fourth quarter of 2010.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures and Changes in Internal Control over Financial Reporting
As of December 31, 2011, the Company carried out an evaluation, under the supervision and with the participation of the Company's management, including the Company's Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Company's disclosure controls and procedures pursuant to Rules 13a-15 and 15d-15 of the Securities Exchange Act of 1934 (the "Exchange Act"). Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company's disclosure controls and procedures are effective, in all material respects, with respect to the recording, processing, summarizing and reporting, within the time periods specified in the Commission's rules and forms, of information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act.
There were no changes in the Company's internal control over financial reporting that occurred during the fourth quarter that have materially affected, or are reasonably likely to materially effect, the Company's internal control over financial reporting.
Management's Report on Internal Control over Financial Reporting
The management of Cabot Oil & Gas Corporation is responsible for establishing and maintaining adequate internal control over financial reporting. Cabot Oil & Gas Corporation's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Cabot Oil & Gas Corporation's management assessed the effectiveness of the Company's internal control over financial reporting as of December 31, 2011. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Based on this assessment management has concluded that, as of December 31, 2011, the Company's internal control over financial reporting is effective at a reasonable assurance level based on those criteria.
The effectiveness of Cabot Oil & Gas Corporation's internal control over financial reporting as of December 31, 2011, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.
ITEM 9B.
ITEM 9B. OTHER INFORMATION
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The information required by this Item is incorporated by reference to the Company's definitive Proxy Statement in connection with the 2012 annual stockholders' meeting. In addition, the information set forth under the caption "Business-Other Business Matters-Corporate Governance Matters" in Item 1 regarding our Code of Business Conduct is incorporated by reference in response to this Item.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
The information required by this Item is incorporated by reference to the Company's definitive Proxy Statement in connection with the 2012 annual stockholders' meeting.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The information required by this Item is incorporated by reference to the Company's definitive Proxy Statement in connection with the 2012 annual stockholders' meeting.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The information required by this Item is incorporated by reference to the Company's definitive Proxy Statement in connection with the 2012 annual stockholders' meeting.
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information required by this Item is incorporated by reference to the Company's definitive Proxy Statement in connection with the 2012 annual stockholders' meeting.
PART IV
ITEM 15.
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
A. INDEX
1. Consolidated Financial Statements
See Index on page 55.
2. Financial Statement Schedules
Financial statement schedules listed under SEC rules but not included in this report are omitted because they are not applicable or the required information is provided in the notes to our consolidated financial statements.
3. Exhibits
The following instruments are included as exhibits to this report. Those exhibits below incorporated by reference herein are indicated as such by the information supplied in the parenthetical thereafter. If no parenthetical appears after an exhibit, copies of the instrument have been included herewith. Our Commission file number is 1-10447.
Exhibit
Number
Description
3.1
Restated Certificate of Incorporation of the Company (Form 8-K for January 21, 2010).
3.2
Amended and Restated Bylaws of the Company amended January 14, 2010 (Form 8-K for January 14, 2010).
4.1
Form of Certificate of Common Stock of the Company (Registration Statement No. 33-32553).
4.2
Note Purchase Agreement dated as of July 26, 2001 among Cabot Oil & Gas Corporation and the Purchasers listed therein (Form 8-K for August 30, 2001).
(a) Amendment No. 1 to Note Purchase Agreement, dated as of June 30, 2010 (Form 10-Q for the quarter ended June 30, 2010).
(b) Amendment No. 2 to Note Purchase Agreement, dated as of September 28, 2010 (Form 10-Q for the quarter ended September 30, 2010).
4.3
Note Purchase Agreement dated as of July 16, 2008 among Cabot Oil & Gas Corporation and the Purchasers named therein (Form 8-K for July 16, 2008).
(a) Amendment No. 1 to Note Purchase Agreement, dated as of June 30, 2010 (Form 10-Q for the quarter ended June 30, 2010).
4.4
Note Purchase Agreement dated as of December 1, 2008 among Cabot Oil & Gas Corporation and the Purchasers named therein (Form 10-K for 2008).
(a) Amendment No. 1 to Note Purchase Agreement, dated as of June 30, 2010 (Form 10-Q for the quarter ended June 30, 2010).
4.5
Note Purchase Agreement dated as of December 30, 2010 among Cabot Oil & Gas Corporation and the Purchasers named therein (Form 10-K for 2010).
4.6
Credit Agreement, dated as of September 22, 2010, among the Company, JPMorgan Chase Bank, N.A., as Administrative Agent, Banc of America Securities LLC, as Syndication Agent, Bank of Montreal, as Documentation Agent, and the Lenders party thereto (Form 10-Q for the quarter ended September 30, 2010).
*10.1
Form of Change in Control Agreement between the Company and Certain Officers (Form 10-K for 2008).
(a) Form of Change in Control Agreement between the Company and Certain Officers (Confirmation that Certain Benefits no Longer Apply).
*10.2
Form of Supplemental Executive Retirement Agreement (Form 10-K for 2008).
(a) Agreement Concerning SERP.
*10.3
Form of Indemnity Agreement between the Company and Certain Officers (Form 10-K for 1997).
Exhibit
Number
Description
*10.4
Deferred Compensation Plan of the Company, as Amended and Restated, Effective January 1, 2011 (Form 10-Q for the quarter ended June 30, 2011).
10.5
Trust Agreement dated September 2000 between Harris Trust and Savings Bank and the Company (Form 10-K for 2001).
*10.6
Employment Agreement between the Company and Dan O. Dinges dated August 29, 2001 (Form 10-K for 2001).
(a) Amendment to Employment Agreement between the Company and Dan O. Dinges, effective December 31, 2008 (Form 10-K for 2008).
*10.7
2004 Incentive Plan (Form 10-Q for the quarter ended June 30, 2004).
(a) First Amendment to the 2004 Incentive Plan effective February 23, 2007 (Form 10-Q for the quarter ended March 31, 2007).
(b) Second Amendment to the 2004 Incentive Plan Amendment, effective as of January 1, 2009 (Form 10-K for 2008).
*10.8
2004 Performance Award Agreement (Form 10-Q for the quarter ended June 30, 2004).
*10.9
2004 Annual Target Cash Incentive Plan Measurement Criteria for Cabot Oil & Gas Corporation (Form 8-K for February 10, 2005).
*10.10
Form of Restricted Stock Awards Terms and Conditions for Cabot Oil & Gas Corporation
(Form 8-K for February 10, 2005).
*10.11
2005 Form of Non-Employee Director Restricted Stock Unit Award Agreement (Form 8-K for May 24, 2005).
*10.12
Savings Investment Plan of the Company, as amended and restated effective January 1, 2001 (Form 10-K for 2005).
(a) First Amendment to the Savings Investment Plan effective January 1, 2002 (Form 10-K for 2005).
(b) Second Amendment to the Savings Investment Plan effective January 1, 2003 (Form 10-K for 2005).
(c) Third Amendment to the Savings Investment Plan effective January 1, 2005 (Form 10-K for 2005).
*10.13
Forms of Award Agreements for Executive Officers under 2004 Incentive Plan (Form 10-K for 2006).
(a) Form of Restricted Stock Award Agreement (Form 10-K for 2006).
(b) Form of Stock Appreciation Rights Award Agreement (Form 10-K for 2006).
(c) Form of Performance Share Award Agreement (Form 10-K for 2006).
10.14
Cabot Oil & Gas Corporation Mineral, Royalty and Overriding Royalty Interest Plan (Registration Statement No. 333-135365).
(a) Form of Conveyance of Mineral and/or Royalty Interest (Registration Statement No. 333-135365).
(b) Form of Conveyance of Overriding Royalty Interest (Registration Statement No. 333-135365).
Exhibit
Number
Description
*10.15
Form of Amendment of Employee Award Agreements (Form 8-K for December 19, 2006).
*10.16
Savings Investment Plan of the Company, as amended and restated effective January 1, 2006 (Form 10-K for 2006).
(a) First Amendment to the Savings Investment Plan of the Company effective January 1, 2006 (Form 10-K for 2007).
(b) Second Amendment to the Savings Investment Plan of the Company effective April 23, 2008 (Form 10-Q for the quarter ended March 31, 2008).
(c) Third Amendment to the Savings Investment Plan of the Company effective July 1, 2008 (Form 10-K for 2008).
(d) Fourth Amendment to the Savings Investment Plan of the Company effective January 1, 2008 (Form 10-K for 2008).
*10.17
Cabot Oil & Gas Corporation Pension Plan, as amended and restated effective September 30, 2010 (Form 10-K for 2010).
*10.18
Savings Investment Plan of the Company, as amended and restated effective January 1, 2009 (Form 10-K for 2009).
(a) First Amendment to the Savings Investment Plan of the Company effective January 1, 2009 (Form 10-K for 2010).
21.1
Subsidiaries of Cabot Oil & Gas Corporation.
23.1
Consent of PricewaterhouseCoopers LLP.
23.2
Consent of Miller and Lents, Ltd.
31.1
302 Certification-Chairman, President and Chief Executive Officer.
31.2
302 Certification-Vice President and Chief Financial Officer.
32.1
906 Certification.
99.1
Miller and Lents, Ltd. Audit Letter.
101.INS
XBRL Instance Document.
101.SCH
XBRL Taxonomy Extension Schema Document.
101.CAL
XBRL Taxonomy Extension Calculation Linkbase Document.
101.LAB
XBRL Taxonomy Extension Label Linkbase Document.
101.PRE
XBRL Taxonomy Extension Presentation Linkbase Document.
101.DEF
XBRL Taxonomy Extension Definition Linkbase Document.
*Compensatory plan, contract or arrangement.
SIGNATURES
Pursuant to the requirements of Section 13 and 15 (d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Houston, State of Texas, on the 28th of February 2012.
CABOT OIL & GAS CORPORATION
By:
/s/ DAN O. DINGES
Dan O. Dinges
Chairman, President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.