EQT Corp
Item 1. Business
General
EQT Corporation (EQT or the Company) conducts its business through three business segments: EQT Production, EQT Midstream and Distribution. EQT Production is one of the largest natural gas producers in the Appalachian Basin with 4.1 trillion cubic feet of proved reserves across 3.4 million acres as of December 31, 2009. EQT offers energy products (natural gas, NGLs and a limited amount of crude oil) and services to wholesale and retail customers in the United States via EQT Midstream and Distribution.
Overall, EQT’s increased production, increased reserves, low cost structure and record results for EQT Midstream and Distribution operations resulted in an outstanding 2009. Some highlights for the year included:
▪ Sales of produced natural gas of 100.1 Bcfe, a 19% increase over 2008;
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A 31% increase in proved reserves to 4.1 Tcfe;
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EQT drilled its 800th horizontal Huron/Berea well, and nearly one third of fourth quarter sales were produced from horizontal Huron/Berea wells;
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The Company drilled 702 gross wells during 2009 of which 403 were horizontal wells, 347 targeting the Huron/Berea play and 46 targeting the Marcellus play;
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The company was successful on more than 99% of the wells drilled in 2009;
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Achieved 14% decrease in unit lease operating expense (LOE), excluding production taxes, to $0.30 per Mcfe. Including production taxes, LOE was $0.59 per Mcfe, an industry leading result;
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Record EQT Midstream throughput and operating income; and
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Record Distribution operating income of $78.9 million, 32% higher than in 2008.
Production
EQT Production has 4.1 Tcfe of proved reserves across three major plays: Huron/Berea, Marcellus and CBM, all located in the Appalachian Basin. The Company’s strategy is to maximize value by profitably developing its extensive acreage position enabled by a low cost structure. EQT Production is focused on continuing its significant organic reserve and production growth through its drilling program and believes that it is a technological leader in drilling in low pressure shale. In particular, the use of air in horizontal drilling has proven to be a cost effective technology which the Company has efficiently deployed in its Huron/Berea play.
The Company’s well profile is generally low-risk wells with long lives, low development and production costs, high energy content natural gas and close proximity to natural gas markets. Many of these wells have been producing for decades, with several in production since early in the 20th century.
To date, EQT has focused its highly successful horizontal air drilling program in the Huron/Berea play where the Company has approximately 2.7 million acres and 2.8 Tcfe of proved reserves. This technology has been used in fractured horizontal single lateral wells, non-fractured horizontal multilateral wells, stacked horizontal wells and extended lateral wells. EQT is also employing horizontal drilling technology to its 450,000 acres and 1.1 Tcfe of proved reserves in the Marcellus play.
Horizontal wells drilled by the Company over the past five years are as follows:
EQT’s proved reserves increased by 31% in 2009 and by 72% over the past five years while the Company’s cost structure remained at an industry leading level. EQT’s 2009 3-year finding and development costs are among the lowest in the industry at $0.94 per Mcfe with 2009 costs at a low of $0.68 per Mcfe. As of December 31, 2009, the Company’s proved reserves, including proved developed and proved undeveloped reserves, and the resource plays to which the reserves relate are as follows:
* The Company includes the Lower Huron, Cleveland, Berea sandstone and other Devonian shales, except Marcellus, in its Huron/Berea play. Also included in the Huron/Berea play is 775 Bcfe of reserves from non-shale formations accessed through vertical wells.
Midstream
EQT Midstream provides gathering, processing, transmission and storage services to EQT Production and to independent third parties in the Appalachian Basin. The Company has approximately 10,650 miles of gathering lines and 970 miles of transmission lines. EQT also owns and operates Kentucky Hydrocarbon, a gas processing facility in Langley, Kentucky. Through Equitrans L.P. (Equitrans, EQT’s interstate pipeline affiliate), EQT’s transmission and storage system interconnects with five major interstate pipelines: Texas Eastern Transmission, Columbia Gas Transmission, National Fuel Gas Supply, Tennessee Gas Pipeline, and Dominion Transmission. EQT Midstream’s 14 natural gas storage reservoirs provide approximately 500 MMcf per day of peak delivery capability and 63 Bcf of storage capacity, of which 32 Bcf is working gas. EQT’s storage reservoirs are clustered in two geographic areas, with eight in northern West Virginia and six in southwestern Pennsylvania. As of December 31, 2009, EQT Midstream, through Equitrans and EQT Energy, LLC (EQT Energy, EQT’s gas marketing affiliate), leased an additional 8.2 Bcf of contractual storage capacity and 118,834 Dth per day of contractual pipeline capacity from third parties. In addition, in 2008, EQT Energy executed a binding precedent agreement with Tennessee Gas Pipeline Company (TGP), a wholly owned subsidiary of El Paso Corporation, for a 15-year term that awarded the Company capacity in TGP’s 300-Line expansion project. EQT Energy’s capacity in the project is expected to be 350,000 Dth per day, giving EQT access to consumer markets from the Gulf Coast to the Mid-Atlantic and the Northeast.
Distribution
EQT’s regulated natural gas distribution subsidiary, Equitable Gas Company, LLC (Equitable Gas, EQT’s local distribution affiliate), distributes and sells natural gas to residential, commercial and industrial customers in southwestern Pennsylvania, West Virginia and eastern Kentucky. Equitable Gas also operates a small gathering system in Pennsylvania and provides off-system sales activities which include the purchase and delivery of gas to customers at mutually agreed-upon points on facilities not owned by the Company.
The Distribution segment’s business strategy is to earn an appropriate return on its asset base through operational efficiency and innovative regulatory mechanisms. Distribution is focused on enhancing the value of its existing assets by establishing a reputation for excellent customer service, effectively managing capital spending, improving the efficiency of its workforce and continuing to leverage technology throughout its operations. In 2009, Equitable Gas received approval for a base rate increase in Pennsylvania to recover an increased return on assets placed in service since the previous rate case and to fully recover costs associated with customer assistance programs.
Markets and Customers
Natural Gas Sales: EQT Production’s produced natural gas is sold to marketers (including EQT Energy), utilities and industrial customers located mainly in the Appalachian area. No individual customers accounted for more than 10% of revenues in 2009 or 2007. Sales to one marketer accounted for approximately 13% of revenues for EQT Production for the year ended December 31, 2008. Natural gas is a commodity and therefore the Company receives market-based pricing. The market price for natural gas can be volatile as evidenced by the high natural gas prices in early through mid 2008 followed by dramatic decreases later in 2008 and in 2009. The market price for gas located in the Appalachian Basin is generally higher than the price for gas located in the Gulf Coast, largely due
to the differential in the cost to transport gas to customers in the northeastern United States. The Company hedges a portion of its forecasted natural gas production. The Company’s hedging strategy and information regarding its derivative instruments is outlined in Item 7A, “Quantitative and Qualitative Disclosures About Market Risk,” and in Notes 1 and 3 to the Consolidated Financial Statements.
Natural Gas Gathering: EQT Midstream derives gathering revenues from charges to customers for use of its gathering system in the Appalachian Basin. The gathering system volumes are transported to three major interstate pipelines: Columbia Gas Transmission, East Tennessee Natural Gas Company and Dominion Transmission. The gathering system also maintains interconnects with Equitrans. Maintaining these interconnects provides the Company with access to geographically diverse markets.
Gathering system transportation volumes for 2009 totaled 161,480 BBtu, of which approximately 60% related to gathering for EQT Production, 30% related to third party volumes and 3% related to volumes for other affiliates of the Company. The remainder related to volumes in which interests were sold by the Company but which the Company continued to operate for a fee. Revenues from affiliates accounted for almost 80% of 2009 gathering revenues.
Natural Gas Processing: The Company processes natural gas in order to extract heavier liquid hydrocarbons (propane, iso-butane, normal butane and natural gasoline) from the natural gas stream, primarily from EQT Production’s produced gas. NGLs are recovered at EQT’s Kentucky Hydrocarbon facility and transported to a fractionation plant owned by a third party for separation into commercial components. The third party markets these components and in exchange retains an agreed-upon percentage of NGLs delivered by the Company. The Company also has contractual processing arrangements whereby the Company sells gas to a third party processor at a weighted average liquids component price.
While natural gas processing produces independent revenues, the Company’s primary reason for these activities is to comply with the product quality specifications of the pipelines on which the Company’s produced natural gas is transported and sold. As a result, the Company typically engages in gas processing at locations where its produced gas would not satisfy the downstream interstate pipeline’s gas quality specifications. Without sufficient processing, the Company’s natural gas production could be interrupted as a result of an inability to achieve required interstate pipeline specifications. Thus, as the Company’s production continues to grow, access to gas processing capacity must also grow.
Natural Gas Transmission and Storage: Services offered by EQT Energy include commodity procurement, sales, delivery, risk management and other services. These operations are executed using Company owned and operated or contracted transmission and underground storage facilities as well as other contractual capacity arrangements with major pipeline and storage service providers in the eastern United States. EQT Energy uses leased storage capacity and firm transportation capacity, including the Company’s Big Sandy Pipeline capacity, to take advantage of price differentials and arbitrage opportunities. EQT Energy also engages in risk management and energy trading activities for the Company. The objective of these activities is to limit the Company’s exposure to shifts in market prices and to optimize the use of the Company’s assets.
Customers of EQT Midstream’s gas transportation, storage, risk management and related services are affiliates and third parties in the northeastern United States, including but not limited to, Dominion Resources, Inc., Keyspan Corporation, NiSource, Inc., PECO Energy Company and UGI Energy Services, Inc. EQT Energy’s commodity procurement, sales, delivery, risk management and other services are offered to natural gas producers and energy consumers including large industrial, utility, commercial and institutional end-users.
Equitrans’ firm transportation contracts expire between 2010 and 2018. The Company anticipates that the capacity associated with these expiring contracts will be remarketed or used by affiliates such that the capacity will remain fully subscribed. In 2009, approximately 80% of transportation volumes and approximately 87% of transportation revenues were from affiliates.
Natural Gas Distribution: The Company’s Distribution segment provides natural gas distribution services to approximately 275,900 customers, consisting of 257,300 residential customers and 18,600 commercial and
industrial customers in southwestern Pennsylvania, municipalities in northern West Virginia and field line sales, also referred to as farm tap service, in eastern Kentucky and West Virginia. These service areas have a rather static population and economy.
Equitable Gas purchases gas through contracts with various sources including major and independent producers in the Gulf Coast, local producers in the Appalachian area and gas marketers (including an affiliate). The gas purchase contracts contain various pricing mechanisms, ranging from fixed prices to several different index-related prices.
Because most of its customers use natural gas for heating purposes, Equitable Gas’ revenues are seasonal, with approximately 74% of calendar year 2009 revenues occurring during the winter heating season (the months of January, February, March, November and December). Significant quantities of purchased natural gas are placed in underground storage inventory during the off-peak season to accommodate higher demand during the winter heating season.
Competition
Natural gas producers compete in the acquisition of properties, the search for and development of reserves, the production and sale of natural gas and the securing of labor and equipment required to conduct operations. Competitors include major oil and gas companies, other independent oil and gas companies and individual producers and operators. Key competitors for new gathering and processing systems include independent gas gatherers and integrated energy companies. Natural gas marketing activities compete with numerous other companies offering the same services. Some of these competitors are affiliates of companies with extensive pipeline systems that are used for transportation from producers to end-users. The Company’s distribution operations face competition from other local distribution companies, alternative fuels and reduced usage among customers as a result of conservation.
Regulation
EQT Production’s natural gas operations are subject to various federal, state, and local laws and regulations, including regulations related to the location of wells; drilling, stimulating and casing of wells; water withdrawal and disbursement for well stimulation purposes; well production; spill prevention plans; the use, transportation, storage and disposal of fluids and materials incidental to oil and gas operations; surface usage and the reclamation of properties upon which wells or other facilities have been located; the calculation and disbursement of royalty payments and taxes; the plugging and abandoning of wells; and the gathering of production in certain circumstances. These regulations may increase the costs of drilling.
EQT Production’s operations are also subject to conservation regulations, including the regulation of the size of drilling and spacing units or field rule units; the number of wells that may be drilled in a unit; and the unitization or pooling of natural gas properties. EQT Production’s operating states allow in certain circumstances the forced pooling or integration of tracts to facilitate development and exploration, while in other circumstances it is necessary to rely on voluntary pooling of lands and leases which may make it more difficult to develop natural gas properties. In addition, state conservation laws generally limit the venting or flaring of natural gas. The effect of these regulations is to limit the amounts of natural gas we produce from our wells and to limit the number of wells or the locations at which we drill.
EQT Midstream has both regulated and non-regulated operations. The regulated activities consist of federally-regulated transmission and storage operations and certain state-regulated gathering operations. The non-regulated activities include certain gathering and transportation operations, processing of NGLs and risk management activities. Equitrans’ rates and operations are subject to regulation by the FERC. The 2006 FERC rate case settlement allowed Equitrans, among other things, to institute an annual surcharge for the tracking and recovery of all costs (operations, maintenance and return on invested capital) incurred on and after September 1, 2005, related to Equitrans’ Pipeline Safety Program under the Pipeline Safety Improvement Act of 2002. The Company has continued to utilize the surcharge mechanism each year to recover costs incurred in connection with its Pipeline Safety Program. Under the terms of the 2006 settlement, Equitrans was prohibited from seeking new base
transmission and storage rates prior to June 1, 2009 and is prohibited from seeking new gathering base rates prior to November 1, 2010. In 2008, the Big Sandy Pipeline was placed in service in eastern Kentucky.
Equitable Gas’ distribution rates, terms of service and contracts with affiliates are subject to comprehensive regulation by the PA PUC and the WV PSC. In addition, the issuance of securities by Equitable Gas is subject to regulation by the PA PUC. The field line sales rates in Kentucky are subject to rate regulation by the Kentucky Public Service Commission.
Equitable Gas must usually seek the approval of one or more of its regulators prior to changing its rates. Currently, Equitable Gas passes through to its regulated customers the cost of its purchased gas and transportation activities. Equitable Gas is allowed to recover a return in addition to the costs of its distribution and gathering delivery activities. However, Equitable Gas’ regulators do not guarantee recovery and may require that certain costs of operation be recovered over an extended term. On February 26, 2009, the PA PUC approved a settlement between Equitable Gas and the active parties to the filing for a base rate case increase in Pennsylvania. The Company implemented the new base rates upon approval of the settlement. On October 29, 2009, Equitable Gas filed a request with the WV PSC to increase the rates it charges its customers for delivery of natural gas in West Virginia. It is the first delivery rate increase that Equitable Gas has requested in West Virginia since 1991. The rate case proceedings are expected to be resolved no later than the third quarter of 2010.
Pennsylvania law requires that local distribution companies develop and implement programs to assist low-income customers with paying their gas bills. The costs of these programs are recovered through rates charged to other residential customers. Equitable Gas has several such programs, including the customer assistance program (CAP). Effective with the approval of the Pennsylvania rate case settlement, the Company received approval to implement an increased CAP surcharge, for recovery of its costs for assisting low-income customers with paying their gas bills and will receive an annual reconciliation of CAP costs to ensure complete recovery of these costs.
Equitable Gas continues to work with regulators to implement alternative cost recovery programs. Equitable Gas’ tariffs for commercial and industrial customers allow for negotiated rates in limited circumstances.
Regulators periodically audit the Company’s compliance with applicable regulatory requirements. The Company is not aware of any significant non-compliance as a result of any completed audits.
Employees
The Company and its subsidiaries had approximately 1,800 employees at the end of 2009.
Holding Company Reorganization
On June 30, 2008, the former Equitable Resources, Inc. (Old EQT) entered into and completed an Agreement and Plan of Merger (the Plan) under which Old EQT reorganized into a holding company structure such that a newly formed Pennsylvania corporation, also named Equitable Resources, Inc. (New EQT), became the publicly traded holding company of Old EQT and its subsidiaries. The primary purpose of this reorganization (the Reorganization) was to separate Old EQT’s state-regulated distribution operations into a new subsidiary in order to better segregate its regulated and unregulated businesses and improve overall financing flexibility. To effect the Reorganization, Old EQT formed New EQT, a wholly-owned subsidiary, and New EQT, in turn, formed EGC Merger Co., a Pennsylvania corporation owned solely by New EQT (MergerSub). Under the Plan, MergerSub merged with and into Old EQT with Old EQT surviving (the Merger). The Merger resulted in Old EQT becoming a direct, wholly-owned subsidiary of New EQT. New EQT changed its name to EQT Corporation effective February 9, 2009. Throughout this Annual Report, references to EQT, EQT Corporation and the Company refer collectively to New EQT and its consolidated subsidiaries.
Availability of Reports
The Company makes certain filings with the SEC, including its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments and exhibits to those reports, available free of charge through its website, http://www.eqt.com, as soon as reasonably practicable after the date they are filed with,
or furnished to, the SEC. The filings are also available at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549 or by calling 1-800-SEC-0330. Also, these filings are available on the internet at http://www.sec.gov. The Company’s annual reports to shareholders, press releases and recent analyst presentations are also available on the Company’s website.
Composition of Segment Operating Revenues
Presented below are operating revenues as a percentage of total operating revenues for each class of products and services representing greater than 10% of total operating revenues during the years 2009, 2008 and 2007.
Financial Information About Segments
In January 2008, the Company announced a change in organizational structure to better align the Company to execute its growth strategy for development and infrastructure expansion in the Appalachian Basin. These changes resulted in changes to the Company’s reporting segments effective for fiscal year 2008. The segment disclosures and discussions contained in this report have been reclassified to reflect all periods presented under the current organizational structure.
See Note 2 to the Consolidated Financial Statements for financial information by business segment including, but not limited to, revenues from external customers, operating income, and total assets.
Financial Information About Geographic Areas
Substantially all of the Company’s assets and operations are located in the continental United States.
Environmental
See Note 18 to the Consolidated Financial Statements for information regarding environmental matters.
Item 1A. Risk Factors
Risks Relating to Our Business
In addition to the other information contained in this Form 10-K, the following risk factors should be considered in evaluating our business and future prospects. Please note that additional risks not presently known to us or that are currently considered immaterial may also have a negative impact on our business and operations. If any of the events or circumstances described below actually occurs, our business, financial condition or results of operations could suffer and the trading price of our common stock could decline.
Natural gas price volatility may have an adverse effect on our revenue, profitability, future rate of growth and liquidity.
Our revenue, profitability, future rate of growth and liquidity depend upon the price for natural gas. The markets for natural gas are volatile and fluctuations in prices will affect our financial results. Natural gas prices are affected by a number of factors beyond our control, which include: weather conditions; the supply of and demand for natural gas; national and worldwide economic and political conditions; the price and availability of alternative fuels; the proximity to, and availability of capacity on, transportation facilities; and government regulations, such as regulation of natural gas transportation and price controls.
Lower natural gas prices may result in decreases in the revenue, margin and cash flow for each of our businesses, a reduction in the construction of new transportation capacity and downward adjustments to the value of our estimated proved reserves which may cause us to incur non-cash charges to earnings. A reduction in cash flow will reduce our funds available for capital expenditures and, correspondingly, our opportunities for growth. We are also exposed to the risk of non-performance by our hedge counterparties in the event that changes, positive or negative, in natural gas prices result in derivative contracts with a positive fair value.
Increases in natural gas prices may be accompanied by or result in increased well drilling costs, increased deferral of purchased gas costs for our distribution operations, increased production taxes, increased lease operating expenses, increased exposure to credit losses resulting from potential increases in uncollectible accounts receivable from our distribution customers, increased volatility in seasonal gas price spreads for our storage assets and increased customer conservation or conversion to alternative fuels. Significant price increases subject us to margin calls on our commodity price derivative contracts (hedging arrangements, including futures contracts, swap, collar and option agreements and exchange traded instruments) which would potentially require us to post significant amounts of cash collateral with our hedge counterparties. The cash collateral, which is interest-bearing, provided to our hedge counterparties is returned to us in whole or in part upon a reduction in forward market prices, depending on the amount of such reduction, or in whole upon settlement of the related hedged transaction. In addition, to the extent we have hedged our current production at prices below the current market price, we are unable to benefit fully from an increase in the price of natural gas.
Our need to comply with comprehensive, complex and sometimes unpredictable government regulations may increase our costs and limit our revenue growth, which may result in reduced earnings.
Our operations are regulated extensively at the federal, state and local levels. Laws, regulations and other legal requirements have increased the cost to plan, design, drill, install, operate and abandon wells, gathering systems, pipelines and distribution systems. Environment, health and safety legal requirements govern discharges of substances into the air and water, the management and disposal of hazardous substances and wastes, the clean-up of contaminated sites, groundwater quality and availability, plant and wildlife protection, restoration of drilling properties after drilling is completed, pipeline safety and work practices related to employee health and safety. Compliance with the laws, regulations and other legal requirements applicable to our businesses may be costly. These requirements could subject us to liability for personal injuries, property damage and other damages. Our failure to comply with the laws, regulations and other legal requirements applicable to our businesses, even if as a result of factors beyond our control, may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties and damages.
The rates charged to customers by our gathering, transportation, storage and distribution businesses are, in many cases, subject to state or federal regulation. The agencies that regulate our rates may prohibit us from realizing a level of return which we believe is appropriate. These restrictions may take the form of imputed revenue credits, cost disallowances (including purchased gas cost recoveries) and/or expense deferrals. Additionally, we may be required to provide additional assistance to low income residential customers to help pay their bills without the ability to recover some or all of the additional assistance in rates.
Laws, regulations and other legal requirements are constantly changing and implementation of compliant processes in response to such changes could be costly and time consuming. For instance, the U.S. Congress and various states have been evaluating climate-related legislation and other regulatory initiatives that would restrict emissions of greenhouse gases, including methane (a primary component of natural gas) and carbon dioxide (a byproduct of burning natural gas). Such restrictions may result in additional compliance obligations with respect to, or taxes on, and the release, capture and use of greenhouse gases that could have an adverse effect on our operations. Changes to well fracturing or waste water regulations or existing legal requirements could also have a significant effect on our costs of operations and competitive position.
The rates of federal, state and local taxes applicable to the industries in which we operate, including production taxes paid by EQT Production, which often fluctuate, could be increased by the various taxing authorities. In addition, the tax laws, rules and regulations that affect our business, such as the imposition of a new severance tax (a tax on the extraction of natural resources) in states in which we produce gas, could change. Any such increase or change could adversely impact our cash flows and profitability.
Strategic determinations regarding the allocation of capital and other resources in the current economic environment are challenging and our failure to appropriately allocate capital and resources among our businesses may adversely affect our financial condition and reduce our growth rate.
In developing our 2010 business plan, we considered allocating capital and other resources to various aspects of our businesses including well-development (primarily drilling), reserve acquisitions, exploratory activity, midstream infrastructure, distribution infrastructure, corporate items and other alternatives. We also considered our likely sources of capital. Notwithstanding the determinations made in the development of our 2010 plan, business opportunities not previously identified periodically come to our attention, including possible acquisitions and dispositions. If we don’t optimize our capital investment and capital raising opportunities and the use of our other resources, our financial condition and growth rate may be adversely affected.
Global financial challenges may adversely affect our business and financial condition in ways that we currently cannot predict. Downgrades to our credit ratings could increase our costs of borrowing adversely affecting our business, results of operations and liquidity.
We rely upon access to both short-term bank and money markets and longer-term capital markets as sources of liquidity for any capital requirements not satisfied by the cash flow from operations. Challenges in the global financial system, including the capital markets, may adversely affect our business and our financial condition and we may face challenges if conditions in the financial markets do not improve. Our ability to access the capital markets may be restricted at a time when we desire, or need, to raise capital, which could have an impact on our flexibility to react to changing economic and business conditions. The economic situation could adversely affect the collectability of our trade receivables. Market conditions could cause our commodity hedging counterparties to be unable to perform their obligations or to seek bankruptcy protection. Continuing challenges in the economy could lead to reduced demand for natural gas which could have a negative impact on our revenues and our credit ratings.
Any downgrade of our credit ratings may increase the cost of borrowing or adversely affect our ability to raise capital through the issuance of debt or equity securities or other borrowing arrangements, which could adversely affect our business, results of operations and liquidity. We cannot be sure that our current ratings will remain in effect for any given period of time or that our rating will not be lowered or withdrawn entirely by a rating agency. An increase in the level of our indebtedness in the future may result in a downgrade in the ratings that are assigned to our debt. Any downgrade in our ratings could result in an increase in our borrowing costs, which would diminish financial results.
Our failure to develop or obtain, and maintain, the necessary infrastructure to successfully deliver gas to market may adversely affect our earnings, cash flows and results of operations.
Our delivery of gas depends upon the availability of adequate transportation infrastructure. The Company’s investment in midstream infrastructure is intended to address a lack of capacity on, and access to, existing gathering and transportation pipelines as well as processing adjacent to and curtailments on such pipelines. The lack of midstream infrastructure is particularly acute in the geographic area in which the Marcellus shale is being developed. Our infrastructure development and maintenance programs can involve significant risks, including those related to timing, cost overruns and operational efficiency, and these risks can be affected by the availability of capital, materials, and qualified contractors and work force, as well as weather conditions, gas price volatility, government approvals, title problems, geology, compliance by third parties with their contractual obligations to us and other factors. We also deliver to and are served by third party gas gathering, transportation, processing and storage facilities which are limited in number and geographically concentrated. An extended interruption of access to or service from these facilities could result in adverse consequences to us. In addition, some of our third party contracts may involve significant financial commitments on our part and may make us dependent upon others to get our produced natural gas to market.
We are subject to risks associated with the operation of our wells, pipelines and facilities.
Our business operations are subject to all of the inherent hazards and risks normally incidental to the production, transportation, storage and distribution of natural gas. These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage. As a result, we are sometimes a defendant in legal proceedings and litigation arising in the ordinary course of business. There can be no assurance that the insurance policies we maintain to limit our liability for such losses will be adequate to protect us from all material expenses related to potential future claims for personal injury and property damage or that such levels of insurance will be available in the future at economical prices or to cover all risks.
The amount and timing of actual future gas production is difficult to predict and may vary significantly from our estimates which may reduce our earnings.
Our future success depends upon our ability to develop additional gas reserves that are economically recoverable and to optimize existing well production, and our failure to do so may reduce our earnings. Our drilling and subsequent maintenance of wells can involve significant risks, including those related to timing, cost overruns and operational efficiency, and these risks can be affected by the availability of capital, leases, rigs and a qualified work force, as well as weather conditions, gas price volatility, government approvals, title problems, geology and other factors. Drilling for natural gas can be unprofitable, not only from dry wells, but from productive wells that do not produce sufficient revenues to return a profit. Additionally, a failure to effectively and efficiently operate existing wells may cause production volumes to fall short of our projections. Without continued successful development or acquisition activities, together with effective operation of existing wells, our reserves and revenues will decline as a result of our current reserves being depleted by production.
Our failure to assess production opportunities based on market conditions could negatively impact our long-term growth prospects for our production business.
Our goal of sustaining long-term growth for our production business is contingent upon our ability to identify production opportunities based on market conditions. Our decision to drill a prospect is subject to a number of factors which may alter our drilling schedule or our plans to drill at all. We may have difficulty drilling all of the wells before the lease term expires which could result in the loss of certain leasehold rights or we could drill wells in locations where we do not have the necessary infrastructure to deliver the gas to market. Successfully identifying production opportunities involves a high degree of business experience, knowledge and careful evaluation of potential opportunities, along with subjective judgments and assumptions which may prove to be incorrect. Our recent addition of exploration projects increases the risks inherent in our natural gas activities. Specifically, seismic data is subject to interpretation and may not accurately identify the presence of natural gas, which could adversely affect the results of our operations. Because we have a limited operating history in certain exploratory areas, our
future operating results are difficult to forecast, and our failure to sustain high growth rates in the future could adversely affect the market price of our common stock.
See Item 7A, “Quantitative and Qualitative Disclosures About Market Risk,” for further discussion regarding the Company’s exposure to market risks, including the risks associated with our use of derivative contracts to hedge commodity prices.
Item 1B. Unresolved Staff Comments
None.
Item 2. Properties
Principal facilities are owned by the Company’s business segments, or in the case of certain office locations, warehouse buildings and equipment, leased. The majority of the Company’s properties are located on or under (1) private properties owned in fee, held by lease, or occupied under perpetual easements or other rights acquired for the most part without warranty of underlying land titles or (2) public highways under franchises or permits from various governmental authorities. The Company’s facilities are generally well maintained and, where appropriate, are replaced or expanded to meet operating requirements.
EQT Production. EQT Production’s properties are located primarily in Kentucky, West Virginia, Virginia and Pennsylvania. This segment currently has approximately 3.4 million gross acres (approximately 67% of which are considered undeveloped), which encompasses nearly all of the Company’s acreage of proved developed and undeveloped natural gas and oil production properties. Although most of its wells are drilled to relatively shallow depths (2,000 to 6,500 feet below the surface), the Company retains what are normally considered “deep rights” on the majority of its acreage. As of December 31, 2009, the Company estimated its total proved reserves to be 4,068 Bcfe, consisting of proved developed producing reserves of 1,912 Bcfe, proved developed non-producing reserves of 161 Bcfe and proved undeveloped reserves of 1,995 Bcfe. All of the Company’s reserves reside in continuous accumulations. The Company’s estimate of proved natural gas and oil reserves are prepared by Company engineers. The engineer primarily responsible for the technical aspects of the reserves audit has received a bachelor's degree in Engineering from the Pennsylvania State University and has ten years of experience in the oil and gas industry. To ensure that the reserves are materially accurate, management reviews the price, heat content conversion rate, and cost assumptions used in the economic model to determine the reserves. Additionally, production volumes are reconciled between the system used to calculate the reserves and other accounting/measurement systems, and the reserve roll forward between prior year reserves and current year reserves is reviewed by senior management. The estimates of proved natural gas and oil reserves are audited by the independent consulting firm of Ryder Scott Company L.P., who is hired by the Company’s management. Since 1937, Ryder Scott Company L.P. has evaluated oil and gas properties and independently certified petroleum reserves quantities in the United States and internationally. Ryder Scott Company L.P.’s audit report has been filed herewith as Exhibit 99.01. No report has been filed with any federal authority or agency reflecting a 5% or more difference from the Company’s estimated total reserves. Additional information relating to the Company’s estimates of natural gas and crude oil reserves and future net cash flows is provided in Note 22 (unaudited) to the Consolidated Financial Statements.
Natural Gas and Crude Oil Production:
Average per unit production cost, including severance taxes, of natural gas and crude oil during 2009, 2008 and 2007 was $0.585, $0.871 and $0.740 per Mcfe, respectively.
Certain lease acquisition agreements require the Company to drill 2 Marcellus or deeper wells and 6 wells drilled to 250’ above the top of the Tully formation or deeper in 2010, 5 wells drilled to 250’ above the top of the Tully formation or deeper plus 4 wells to any depth or formation in 2011, and 5 wells drilled to 250’ above the top of the Tully formation or deeper plus 2 wells to any depth or formation in 2012; each of these wells must be drilled within specified acreage. The Company intends to satisfy these requirements as part of its Marcellus development program. As of December 31, 2009, leases associated with 9,975 gross undeveloped acres expire in 2010 if they are not renewed; however, the Company has an active lease renewal program.
Number of net productive and dry exploratory and development wells drilled:
Selected data by state (at December 31, 2009 unless otherwise noted):
During 2009, the Company converted 65 Bcfe of proved undeveloped reserves to proved developed reserves and 315 Bcfe of non-proved undeveloped reserves to proved developed reserves. The Company anticipates spending $2.9 billion to convert proved undeveloped reserves to proved developed reserves over the next 5 years. Capital expenditures for drilling and development totaled $717 million during 2009. Proved reserves increased primarily in the Marcellus and Huron/Berea plays as a result of the Company’s 2009 drilling program. In addition, the application of new SEC oil and gas reporting rules permitted the booking of PUDs in locations more than one offset location away from existing wells. Partially offsetting these reserve additions, EQT also reported a reduction of CBM/other reserves as a result of removing previously booked vertical locations.
The Company’s 2009 extensions, discoveries and other additions, resulting from extensions of the proved acreage of previously discovered reservoirs through additional drilling in periods subsequent to discovery, of 1,159 Bcfe exceeded the 2009 production of 104.9 Bcfe. Of this increase, approximately 715 Bcfe was attributable to drilling in 2009 that would have qualified as reserve extensions, discoveries and other additions under the previous
rules, including approximately 400 Bcfe related to offset locations from wells drilled in 2009. The remaining additions are attributable to the SEC’s expanded definition of proved reserves to include reserves based on reasonable certainty, partially offset by removing reserves that were previously recorded for future vertical wells.
During 2009, the Company recorded downward revisions of 94.8 Bcfe to the December 31, 2008 estimate of proved reserves due to decreased prices and other revisions. The new SEC oil and gas reporting rules modified the definition of proved reserves as well as the price used in the calculation which resulted in approximately 55 Bcfe of revision of previous estimates. The reserves were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2009. Absent the effect of the new SEC oil and gas reporting rule, the price impact would have been minimal as prices as of December 31, 2009 only decreased approximately $0.06 from December 31, 2008.
Wells located in Kentucky are primarily in shale formations with depths ranging from 2,500 feet to 6,000 feet and average spacing of 100 acres. Wells located in West Virginia are primarily in tight sands and shale formations with depths ranging from 2,500 feet to 6,500 feet and average spacing of 40 acres in the northern part of the state and 60 acres in the southern part of the state. Horizontal wells in both northern and southern West Virginia are drilled on 100 acre spacing. Wells located in Virginia are primarily in coalbed methane formations with depths ranging from 2,000 feet to 3,000 feet and average spacing of 60 acres and in tight sands and shale formations at depths of 3,000 to 6,500 feet on 100 acre spacing. Wells located in Pennsylvania are primarily in shale formations with depths ranging from 7,000 feet to 8,000 feet and average spacing of 100 acres.
During 2008, the Company drilled its first exploratory vertical Utica well. During 2009, the Company made the decision to plug back the well and to convert the well to a horizontal Marcellus well in 2010. As a result, the Company wrote-off $2.9 million of incremental exploratory costs related to drilling down to the Utica formation. As of December 31, 2009, $5.0 million of well costs remain capitalized for the future horizontal Marcellus well, pending successful completion.
EQT Production owns and leases office space in Pennsylvania, West Virginia, Virginia and Kentucky.
EQT Midstream. EQT Midstream owns or operates approximately 10,650 miles of gathering line and 243 compressor units comprising 121 compressor stations with approximately 249,000 horsepower of installed capacity, as well as other general property and equipment.
Substantially all of the gathering operations’ sales volumes are delivered to several large interstate pipelines on which the Company and other customers lease capacity. These pipelines are subject to periodic curtailments for maintenance and repairs.
The Midstream business also owns a hydrocarbon processing plant and gas compression facilities located in Langley, Kentucky.
EQT Midstream also owns and operates regulated underground storage and transmission facilities in Pennsylvania, West Virginia and Kentucky. These operations consist of approximately 970 miles of regulated transmission and storage lines with approximately 35,000 horsepower of installed capacity and interconnections with five major interstate pipelines. The interstate pipeline system stretches throughout north central West Virginia and southwestern Pennsylvania. The completion of the Big Sandy Pipeline in 2008 added 68 miles of transmission line and 9,000 horsepower of installed capacity in Kentucky. Equitrans has 14 natural gas storage reservoirs with approximately 496 MMcf per day of peak delivery capability and 63 Bcf of storage capacity, of which 32 Bcf is working gas. These storage reservoirs are geographically clustered, with eight in northern West Virginia and six in southwestern Pennsylvania.
EQT Midstream owns and leases office space in Pennsylvania, West Virginia, Virginia and Kentucky.
Equitable Distribution. This segment owns and operates natural gas distribution and gathering facilities as well as other general property and equipment in western Pennsylvania, West Virginia and Kentucky. The distribution operations consist of approximately 4,000 miles of pipe in Pennsylvania, West Virginia and Kentucky.
Headquarters. The corporate headquarters and other operations are located in leased office space in Pittsburgh, Pennsylvania. In 2008, the Company entered into an agreement with Liberty Avenue Holdings, LLC to lease office space in Pittsburgh, Pennsylvania for the Company’s new corporate headquarters. During the third quarter of 2009, the Company completed the relocation of its corporate headquarters and certain other operations to downtown Pittsburgh.
Item 3. Legal Proceedings
Kay Company, LLC et al v. EQT Production Company et al, U.S. District Court, Southern District of West Virginia
Several West Virginia lessors claimed in a suit filed on July 31, 2006 that EQT Production Company had underpaid royalties on gas produced and marketed from leases. The suit sought compensatory and punitive damages, an accounting and other relief. The plaintiffs later amended their complaint to name EQT as an additional defendant. The Company has settled the litigation. The settlement covers all of the Company’s lessors in West Virginia who have not opted out of the settlement class. The Court has entered an order preliminarily approving the settlement. A Formal Fairness Hearing was held on January 20, 2010. The Company is waiting for entry of an order giving final approval of the settlement. The Company believes the reserve established for this litigation is sufficient.
In addition to the claim disclosed above, in the ordinary course of business various other legal and regulatory claims and proceedings are pending or threatened against the Company. While the amounts claimed may be substantial, the Company is unable to predict with certainty the ultimate outcome of such claims and proceedings. The Company has established reserves it believes to be appropriate for other pending matters and after consultation with counsel and giving appropriate consideration to available insurance, the Company believes that the ultimate outcome of any other matter currently pending against the Company will not materially affect the financial position, results of operations or liquidity of the Company.
Item 4. Submission of Matters to a Vote of Security Holders
No matters were submitted to a vote of the Company’s security holders during the last quarter of its fiscal year ended December 31, 2009.
Executive Officers of the Registrant (as of February 18, 2010)
____________________
All executive officers have executed agreements with the Company and serve at the pleasure of the Company’s Board of Directors. Officers are elected annually to serve during the ensuing year or until their successors are chosen and qualified.
As previously announced, Murry S. Gerber, Chairman and Chief Executive Officer, will step aside from his duties as Chief Executive Officer following the Company’s annual meeting of shareholders on April 21, 2010. David L. Porges, currently EQT’s President and Chief Operating Officer, will become Chief Executive Officer. To insure a smooth transition, Mr. Gerber will remain with EQT as Executive Chairman through EQT’s 2011 annual meeting of shareholders.
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
The Company’s common stock is listed on the New York Stock Exchange. The high and low sales prices reflected in the New York Stock Exchange Composite Transactions, and the dividends declared and paid per share, are summarized as follows (in U.S. dollars per share):
As of February 10, 2010, there were 3,519 shareholders of record of the Company’s common stock.
The amount and timing of dividends is subject to the discretion of the Board of Directors and depends on certain business conditions, such as the Company’s lines of business, results of operations and financial condition and other factors. Based on currently foreseeable conditions, the Company anticipates that comparable dividends will be paid on a regular quarterly basis.
The following table sets forth the Company’s repurchases of equity securities registered under Section 12 of the Exchange Act that have occurred in the three months ended December 31, 2009:
(a) Comprised solely of Company-directed purchases made by the Company’s 401(k) plans.
Stock Performance Graph
The following graph compares the most recent five-year cumulative total return attained by shareholders on EQT Corporation’s common stock with the cumulative total returns of the S&P 500 index and a customized peer group of twenty companies (the “Self-Constructed Peer Group”) whose individual companies are listed in footnote (1) below. An investment of $100 (with reinvestment of all dividends) is assumed to have been made at the close of business on December 31, 2004 in the Company’s common stock, in the S&P 500 index, and in the peer group. Relative performance is tracked through December 31, 2009.
(1) The twenty companies included in the self constructed peer group are: Atlas Energy Resources, LLC, Cabot Oil & Gas Corporation, Chesapeake Energy Corporation, CNX Gas Corporation, El Paso Corporation, Enbridge Inc., Energen Corporation, MarkWest Energy Partners, L.P., MDU Resources Group, Inc, National Fuel Gas Company, ONEOK, Inc, Penn Virginia Corporation, Questar Corporation, Range Resources Corporation, Sempra Energy, Southern Union Company, Southwestern Energy Company, Spectra Energy Corp., Transcanada Corp. and The Williams Companies, Inc. Atlas Energy Resources LLC was acquired during 2009 and is included in the calculation from December 31, 2004 through December 31, 2008, at which time it is removed from the peer group calculation.
See Item 12, “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters” for information relating to compensation plans under which the Company’s securities are authorized for issuance.
Item 6. Selected Financial Data
(a) All 2005 per share amounts have been adjusted for the two-for-one stock split affected on September 1, 2005.
See Item 1A, “Risk Factors” and Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Notes 5 and 6 to the Consolidated Financial Statements for other matters that affect the comparability of the selected financial data as well as uncertainties that might affect the Company’s future financial condition.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Consolidated Results of Operations
In 2009 EQT achieved record results. Highlights for 2009 included:
· Record annual sales of produced natural gas of 100.1 Bcfe, more than 19 % higher than 2008;
· Drilled 800th horizontal Huron/Berea well, approximately 27% of sales were from horizontal Huron/Berea wells;
· Drilled 46 horizontal Marcellus wells;
· Record EQT Midstream throughput and operating income; and
· Record Distribution operating income of $78.9 million, 32% higher than 2008.
EQT’s consolidated income from continuing operations for 2009 was $156.9 million, $1.19 per diluted share, compared with $255.6 million, $2.00 per diluted share, for 2008 and $257.5 million, $2.10 per diluted share, for 2007.
The $98.7 million decrease in income from continuing operations from 2008 to 2009 was primarily attributable to a lower average well-head sales price, increased incentive compensation expense, increased depletion expense, and higher interest expense partially offset by increased gas sales volumes at EQT Production, increased gathering volumes and rate, Big Sandy pipeline activity and NGLs sold at EQT Midstream and an increase in base rates in the Distribution segment.
Incentive compensation expense increased from 2008 to 2009 as a result of expenses related to the Company’s 2009 Shareholder Value Plan recorded in 2009 and a reversal of previously recorded expense on the Company’s 2005 Executive Performance Incentive Program in 2008 primarily as a result of the decline in the Company’s stock price in 2008. Incentive compensation is primarily reported in selling, general and administrative expenses in the Statements of Consolidated Income. A significant portion of the 2009 expense and 2008 reversal are reported as unallocated expenses in the information by business segment in Note 2 of the Company’s Consolidated Financial Statements.
Interest expense increased from 2008 to 2009 primarily due to the Company’s continued investment in drilling and midstream infrastructure during 2009. This investment was partially funded by the issuance of $700 million of 8.125% notes in May 2009.
The $1.9 million decrease in income from continuing operations from 2007 to 2008 reflects an increase in operating income of $153.1 million which was more than offset by the absence of a 2007 pre-tax gain of $126.1 million on the sale of assets in the Nora area, higher 2008 interest and income taxes and a 2008 other than temporary impairment loss on available for sale securities.
Operating income for 2008 was impacted by decreased incentive compensation expense, increased production revenues due to higher average well-head sales prices and significantly higher volumes, increased gathering and transmission revenues due to higher rates and volumes, and the absence of 2007 transaction costs associated with the terminated Peoples and Hope acquisition. The decreased incentive compensation expense was the result of the reversal of previously recorded expense on the Company’s 2005 Executive Performance Incentive Program partially offset by increased short-term incentive compensation. These items were partially offset by increased depletion, depreciation and amortization, increased operating and administrative expenses and the impact of the May 2007 asset sales.
Business Segment Results
Business segment operating results are presented in the segment discussions and financial tables on the following pages. Operating segments are evaluated on their contribution to the Company’s consolidated results based on operating income, equity in earnings of nonconsolidated investments and other income. Interest expense and income taxes are managed on a consolidated basis. Headquarters’ costs are billed to the operating segments based upon a fixed allocation of the headquarters’ annual operating budget. Differences between budget and actual headquarters expenses are not allocated to the operating segments. Certain performance-related incentive expenses (income) and administrative expenses totaling $62.2 million, ($17.4) million and $65.3 million in 2009, 2008 and 2007, respectively, were not allocated to business segments. The unallocated expense in 2009 and 2007 primarily relates to performance-related incentive expenses, while the unallocated income in 2008 primarily relates to the reversal of previously recorded performance-related incentive expenses.
The Company has reconciled each segment’s operating income, equity in earnings of nonconsolidated investments and other income to the Company’s consolidated operating income, equity in earnings of nonconsolidated investments and other income totals in Note 2 to the Consolidated Financial Statements. Additionally, these subtotals are reconciled to the Company’s consolidated net income in Note 2. The Company has also reported the components of each segment’s operating income and various operational measures in the sections below, and where appropriate, has provided information describing how a measure was derived. EQT’s management believes that presentation of this information is useful to management and investors in assessing the financial condition, operations and trends of each of EQT’s segments without being obscured by these items for the other segments or by the effects of corporate allocations. In addition, management uses these measures for budget planning purposes.
EQT Production
Overview
Driven by aggressive horizontal air drilling in the Huron/Berea play, EQT Production achieved sales of produced natural gas of 100.1 Bcfe in 2009, representing a more than 19% increase. Also, unit LOE, excluding production taxes, decreased 14% in 2009 to $0.30 per Mcfe.
EQT Production’s strategy is to maximize value by profitably developing the Company’s extensive acreage position through organic growth enabled by a low cost structure. The Company is focused on continuing its significant organic reserve and production growth through its drilling program and believes that it is a technological leader in drilling in low pressure shale. In particular, the use of air in horizontal drilling has proven to be a cost effective technology which the Company has efficiently deployed to various geological formations in the
Appalachian Basin mountain terrain and which may be deployed to other Company assets in the Appalachian Basin to maximize production. In 2009, extended laterals utilizing this technology produced a 6,700 foot lateral with 6,000 feet of pay, essentially doubling the typical horizontal well which is a 3,700 foot with 3,000 feet of pay. Based on these favorable preliminary results, the Company is in the process of incorporating extended lateral wells into its preferred standard operating procedures for the Huron/Berea play. The Company expects to access significantly more reserves through the extended lateral drilling procedures for less than a proportional amount of the development costs.
In 2009, the Company drilled 434 gross wells in the Huron/Berea play. Total proved reserves in the Huron/Berea play (including vertical non-shale formations) are 2.8 Tcfe. In the Marcellus play, the Company drilled 50 gross wells during 2009. Total proved reserves in the Marcellus play increased 1,278% to 1.1 Tcfe. Proved reserves increased in the Marcellus and Huron/Berea plays as a result of the Company’s 2009 drilling program. In addition, the application of new SEC oil and gas reporting rules permitted the booking of PUDs in locations more than one offset location away from existing wells. The Company drilled 218 gross CBM wells in 2009. The CBM play had total proved reserves of 0.2 Tcfe at December 31, 2009, down 6% from 2008 as a result of the implementation of the new SEC oil and gas reporting rules. See Item 2 “Properties” for additional discussion of the Company’s proved reserves and the impact of the new SEC oil and gas reporting rules. Sales of produced natural gas in 2009 from the Huron/Berea, Marcellus and CBM plays were 84.9 Bcfe, 2.9 Bcfe and 12.3 Bcfe, respectively.
EQT Production’s revenues for 2009 decreased approximately 16% compared to 2008 revenues. The average well-head sales price decreased approximately 30%, as a result of decreased commodity market prices offset by slightly higher hedge prices year-over-year. Gas sales volumes increased more than 19% from 2008 primarily as a result of increased production from the 2008 and 2009 drilling programs partially offset by the normal production decline in the Company’s producing wells.
Operating expenses at EQT Production included an $8.8 million increase in the Company’s exploration program. The increase in exploration expense is primarily a result of the Company’s initiative to explore additional reserve opportunities in various exploration plays on its legacy acreage position with the purchase and interpretation of seismic data for unproved properties. In addition, in 2009, EQT Production recorded a $2.9 million impairment charge associated with the write-off of the Utica exploratory well when the Company made the decision to abandon the Utica formation and plug back the well to the Marcellus formation. Excluding exploration expenses, 2009 operating expenses increased 10% primarily due to higher depletion resulting from increased drilling investments.
See Investing Activities in Capital Resources and Liquidity for a discussion of capital expenditures.
Results of Operations
(a) Natural gas and oil production represents the Company’s interest in gas and oil production measured at the well-head. It is equal to the sum of total sales volumes, Company usage and line loss.
(b) Average well-head sales price is calculated as market price adjusted for hedging activities less deductions for gathering, processing and transmission included in EQT Midstream revenues. These deductions totaled $1.69/Mcfe, $1.50/Mcfe and $1.23/Mcfe for 2009, 2008 and 2007, respectively.
(c) Capital expenditures in 2009 and 2008 include $31.0 million and $85.5 million, respectively, for undeveloped property acquisitions. Capital expenditures in 2007 include $24.4 million for the acquisition of working interests in wells in the Roaring Fork area.
(d) Production taxes include severance and production-related ad valorem and other property taxes.
Fiscal Year Ended December 31, 2009 vs. December 31, 2008
EQT Production’s operating income totaled $151.1 million for 2009 compared to $252.8 million for 2008, a decrease of $101.7 million between years, primarily due to a lower average well-head sales price and an increase in depletion expenses partially offset by increased gas sales volumes.
Total operating revenues were $384.6 million for 2009 compared to $457.1 million for 2008. The decrease in operating revenues was due to lower realized prices which more than offset increased sales volumes. The average well-head sales price decreased by $1.57 per Mcfe, primarily as a result of a decrease in NYMEX natural gas prices and a lower percentage of hedged gas sales, partially offset by a higher realized hedge price. The decrease in prices was partially offset by increased sales volumes of more than 19% as a result of the 2008 and 2009 drilling programs, net of the normal production decline in the Company’s wells and a decrease in Company usage and line loss.
Operating expenses totaled $233.5 million for 2009 compared to $204.4 million for 2008. The $29.1 million increase in operating expenses was a result of increases of $39.2 million in DD&A partially offset by decreases of $17.0 million in production taxes, $1.4 million in SG&A, and $0.5 million in LOE. In addition, 2009 includes an $8.8 million increase in exploration expense due to the purchase and interpretation of seismic data in support of the Company’s examination of emerging plays and the impairment charge on the exploratory Utica well. The increase in DD&A was primarily due to increased depletion expense resulting from both increases in the unit rate ($26.3 million) and volume ($11.0 million). The $0.25 per Mcfe increase in the depletion rate is primarily attributable to the increased investment in oil and gas producing properties. The decrease in production taxes was primarily due to an $18.4 million decrease in severance taxes partially offset by a $1.4 million increase in property taxes. The decrease in severance taxes (a production tax imposed on the value of gas extracted) was primarily due to lower gas commodity prices partially offset by higher sales volumes in the various taxing jurisdictions that impose such taxes. The increase in property taxes was a direct result of increased prices and sales volumes in prior years, as property taxes in several of the taxing jurisdictions where the Company’s wells are located are calculated based on historical gas commodity prices and sales volumes. The decrease in SG&A was primarily due to the reversal of reserves for certain legal disputes partially offset by higher overhead costs associated with the growth of the Company, increased franchise and gross receipts taxes attributable to increased receipts and costs associated with the amendment of a contract to secure capacity for the processing and disposal of salt water. The decrease in LOE was primarily attributable to the 2008 program to test the re-fracturing of existing wells.
Fiscal Year Ended December 31, 2008 vs. December 31, 2007
EQT Production’s operating income totaled $252.8 million for 2008 compared to $331.2 million for 2007, a decrease of $78.4 million between years, primarily due to the absence of a 2007 gain on the sale of a portion of the Company’s interests in certain gas properties in the Nora area compared to 2008 results which included higher average well-head sales price and increased gas sales volumes, partially offset by an increase in operating expenses.
Total operating revenues were $457.1 million for 2008 compared to $364.4 million for 2007. The $92.7 million increase in operating revenues was due to higher realized prices and increased sales volumes. The average well-head sales price increased by $0.73 per Mcfe, primarily as a result of an increase in NYMEX natural gas prices and a higher percentage of unhedged gas sales, partially offset by a lower realized hedge price. Additionally, sales volumes increased 12% excluding the 2007 sale of interests which provided sales of 1,966 MMcfe during 2007, as a result of the 2008 and 2007 drilling programs net of the normal production decline in the Company’s wells.
Operating expenses totaled $204.4 million for 2008 compared to $162.4 million for 2007. The $42.0 million increase in operating expenses was a result of increases of $16.2 million in DD&A, $11.0 million in production taxes, $6.4 million in LOE, and $0.2 million in SG&A. In addition, the 2008 period included an $8.2 million increase in exploration expense due to the purchase and interpretation of seismic data in support of the Company’s examination of emerging plays. The increase in DD&A was primarily due to increased depletion expense resulting from both increases in the unit rate ($9.9 million) and volume ($5.0 million). The $0.11 increase in the depletion rate was primarily attributable to the increased investment in oil and gas producing properties. The increase in production taxes was primarily due to a $9.8 million increase in severance taxes and a $1.2 million increase in property taxes. The increase in severance taxes (a production tax imposed on the value of gas extracted) was
primarily due to higher gas commodity prices and higher sales volumes in the various taxing jurisdictions that impose such taxes. The increase in property taxes was a direct result of increased prices and sales volumes in prior years, as property taxes in several of the taxing jurisdictions where the Company’s wells are located are calculated based on historical gas commodity prices and sales volumes. The increase in LOE was attributable to personnel costs, the 2008 program to test the re-fracturing of existing wells, salt water and waste disposal, environmental costs and road and location maintenance. The increase in SG&A was primarily due to higher overhead costs associated with the growth of the Company partially offset by lower charges for certain legal disputes in 2008 compared to 2007.
On April 13, 2007, the Company and Range Resources Corporation (Range) agreed to a development plan for the Nora area in southwestern Virginia. The Company entered into a Purchase and Sale Agreement (Purchase Agreement) with Pine Mountain Oil and Gas, Inc. (PMOG), a subsidiary of Range, pursuant to which the Company agreed to sell to PMOG a portion of the Company’s interests in certain gas properties in the Nora area. As a result of this transaction, EQT Production recognized a net gain of $129.2 million in earnings in 2007. The net gain includes a gain on the sale of working interest in oil and gas properties under the Purchase Agreement of $157.6 million offset by a hedge loss of $28.4 million resulting from a 7.3 Bcf reduction in the Company’s hedge position due to the sale of properties. See Note 5 of the Consolidated Financial Statements for further discussion related to this transaction.
Outlook
EQT Production’s business strategy is focused on organic growth of the Company’s natural gas reserves and sales volumes. Key elements of EQT Production’s strategy include:
· Expanding production and developed reserves through horizontal drilling in Kentucky, West Virginia, and Pennsylvania. The Company is committed to expanding its production and developed reserves through horizontal drilling in its existing plays. The Company will seek to maximize the value of its existing asset base by developing its large acreage position, which the Company believes holds significant production and reserve growth potential. A substantial portion of the Company’s 2010 drilling efforts will be focused on drilling horizontal wells in shale formations in Kentucky, West Virginia and Pennsylvania. Additionally, based on favorable preliminary results, the Company is in the process of incorporating extended lateral wells into its preferred standard operating procedures for the Huron/Berea play. The Company expects to access significantly more reserves through the extended lateral drilling procedures for less than a proportional amount of the development costs. Sales of produced natural gas in 2010 are projected to be 20% higher than the 2009 produced gas sales.
· Maintaining flexibility in a low price environment - The pace at which the Company is able to grow production and reserves is impacted by drilling success and the price for natural gas. The Company has mitigated some of the commodity price risk by hedging a portion of its production. The Company believes that its position as a low cost operator allows for the development of reserves and production in a low price environment.
· Geological and geophysical expenditures - In 2010, the Company plans to spend $10.5 million on seismic data to determine optimal placement for future Marcellus wells and $1.5 million on 2D and 3D seismic data over properties in which the Company holds deeper exploration and drilling rights.
· Growing acreage position - The Company is focused on expanding production, primarily through organic development of its large acreage position. The Company may also take advantage of property acquisition opportunities as economic conditions warrant.
EQT Midstream
Overview
In 2009 EQT Midstream achieved record throughput and operating income primarily due to revenues generated by new infrastructure projects exceeding the increased costs required to operate these assets. Projects completed in 2008 that positively impacted 2009 earnings include: the Kentucky hydrocarbon processing plant and gas compression facilities (Kentucky Hydrocarbon) which have the capacity to process 170 MMcfe of natural gas per day; the Mayking Corridor project (Mayking) which consists of three compressor units and 38 miles of pipe; and the Big Sandy Pipeline which currently provides 130,000 Dth per day of firm transportation capacity. In 2009, EQT Midstream continued optimizing existing capacity by building gathering lines to tie in wells in Kentucky, West Virginia and Pennsylvania. The combination of these 2009 investments with the Kentucky Hydrocarbon, Mayking and the Big Sandy Pipeline provided the platform for sales growth and will help to mitigate curtailments and increase the flexibility and reliability of the Company’s gathering systems in transporting gas to market.
EQT Midstream’s net operating revenues increased by 27% from 2008 to 2009. This increase was primarily due to increases in gathered volumes due to our infrastructure expansion, increased processing volumes as a result of the Kentucky Hydrocarbon processing plant being operational for a full year in 2009 and transmission revenues from the Big Sandy Pipeline. Increases in net operating revenues were partially offset by an increase in operating expenses.
EQT Energy, the Company’s gas marketing affiliate, executed a binding precedent agreement with Tennessee Gas Pipeline Company (TGP), a wholly owned subsidiary of El Paso Corporation, for a 15-year term that awarded the Company 300,000 Dth per day of capacity in TGP’s 300-Line expansion project. In July 2009, the parties amended the binding precedent agreement and EQT Energy’s capacity in the project was increased to 350,000 Dth per day beginning in November 2011. The awarded capacity will provide EQT access to consumer markets from the Gulf Coast to the Mid-Atlantic and the Northeast.
See Investing Activities in Capital Resources and Liquidity for a discussion of capital expenditures.
Results of Operations
(a) The calculation of gathering and compression expense ($/MMBtu) for 2008 excludes a $9.5 million charge for pension and other post-retirement benefits.
(b) NGLs sold includes NGLs recovered at the Company’s processing plant and transported to a fractionation plant owned by a third party for separation into commercial components, net of volumes retained, as well as equivalent volumes sold at liquid component prices under the Company’s contractual processing arrangements with third parties.
Fiscal Year Ended December 31, 2009 vs. December 31, 2008
EQT Midstream’s operating income totaled $189.0 million for 2009 compared to $134.8 million for 2008. The $54.2 million increase in operating income was primarily the result of increased gathering and processing volumes, gathering rates and increased Big Sandy pipeline activity, partially offset by increases in O&M and D&A expense.
Total net operating revenues were $386.2 million for 2009 compared to $303.3 million for 2008. The $82.9 million increase in total net operating revenues was due to a $25.4 million increase in gathering net operating revenues, a $22.2 million increase in processing net operating revenues, a $25.2 million increase in transmission net operating revenues, and a $10.1 million increase in storage, marketing and other net operating revenues.
Gathering net operating revenues increased due to an 11% increase in gathered volumes as well as a 6% increase in the average gathering fee. This increase was driven by more volumes gathered for EQT Production, as well as increased third party customer volume due to increased available capacity with Mayking and the Big Sandy Pipeline being operational for a full year in 2009. Processing net revenues increased primarily due to a 55% increase in NGLs sold. This resulted from increased production volumes from both EQT Production and third party customers and the expansion of the Kentucky Hydrocarbon processing plant and gas compression facilities in the second half of 2008. Although the average NGL sales price decreased more than 35% from 2008, the impact on processing net operating revenues was not significant due to a decrease in the related cost of natural gas processed.
Transmission net revenues in 2009 increased from the prior year primarily due to increased capacity from the Big Sandy pipeline, which came on-line in the second quarter of 2008. The increase in storage and marketing net revenues was primarily due to increased third party marketing that utilized Big Sandy Pipeline capacity.
Total operating revenues decreased by $137.9 million, or 20%, primarily as a result of lower sales prices on decreased commercial activity related to contractual transmission and storage assets and lower NGL sales prices partially offset by an increase in gathering and processing volumes, gathering rates and increased transmission revenues from the Big Sandy Pipeline. Total purchased gas costs decreased 58% as a result of lower gas costs on
decreased commercial activity related to contractual transmission and storage assets and lower gas costs related to processing activities.
Operating expenses totaled $197.2 million for 2009 compared to $168.6 million for 2008. The increase in operating expenses was due to increases of $12.2 million in O&M and $18.5 million in D&A, offset by a decrease of $2.1 million in SG&A. The increase in O&M resulted mainly from higher electricity, labor, non-income taxes and compressor maintenance expenses for the gathering and processing business due to new compressors and processing facilities put in operation in the second half of 2008, partially offset by a decrease of $9.5 million relating to pension and other post-retirement benefit charges recorded in 2008. The increase in D&A was primarily due to the increased investment in infrastructure during 2008 and 2009. The decrease in SG&A was primarily due to expenses in 2008 which were not incurred in 2009, including a $5.2 million reserve against Lehman Brothers receivables and $1.2 million for legal and actuarial services associated with the pension and other post-retirement benefit charges, partially offset by an increase in labor and services to support the growth in the Midstream business during 2009.
Other income represents allowance for equity funds used during construction. The $4.3 million decrease from 2008 to 2009 was primarily caused by AFUDC recorded on the construction of the Big Sandy Pipeline in 2008. AFUDC was no longer recorded once Big Sandy was placed into service in the second quarter of 2008.
Equity in earnings of nonconsolidated investments totaled $6.4 million for 2009 compared to $5.1 million for 2008. This increase is related to equity earnings recorded for EQT Midstream’s investment in Nora Gathering, LLC, which was formed in May 2007. Earnings increased in 2009 as a result of higher net income for Nora Gathering, LLC in 2009 compared to 2008. The higher net income was driven by increases in the average gathering fee and gathered volumes partially offset by increased operating expenses for the Nora operations in 2009.
Fiscal Year Ended December 31, 2008 vs. December 31, 2007
EQT Midstream’s operating income totaled $134.8 million for 2008 compared to $137.3 million for 2007, a decrease of $2.5 million. An increase in net operating revenues was more than offset by increased operating expenses, including a $10.7 million settlement charge for pension and post-retirement benefits including related severance and legal fees and $5.2 million bad debt expense as a result of the Lehman Brothers bankruptcy. This was partially offset by a loss of $3.1 resulting from the contribution of gathering assets to Nora LLC, an entity formed in 2007 that is equally owned by the Company and Pine Mountain Oil and Gas, Inc. See Note 5 of the Consolidated Financial Statements for further discussion of this transaction. Excluding these items, operating income increased 7%.
Total net operating revenues were $303.3 million for 2008 compared to $261.9 million for 2007. The $41.4 million increase in total net operating revenues was due to a $20.7 million increase in gathering net operating revenues, a $15.1 million increase in transmission net operating revenues, a $5.3 million increase in processing net operating revenues and a $0.3 million increase in storage, marketing and other net operating revenues.
The increase in gathering net operating revenues was due to a 17% increase in the average gathering fee and a small increase in gathered volumes. The increase in the average gathering fee is reflective of the Company’s commitment to ensuring that this fee is sufficient to cover costs associated with infrastructure expansion. Gathered volumes increased 1% due to the increase in 2008 Company production and third party volumes which were partially offset by the elimination in 2008 of volumes gathered on assets contributed to Nora Gathering, LLC. The increase in processing net operating revenues was due to an increase in NGLs sold as well as increased commodity prices for propane and other NGLs. The volume of NGLs sold increased in 2008 as a result of the Company’s infrastructure investments. The increase in transmission net operating revenues was due to new transmission revenues from the Big Sandy Pipeline, which came on-line in the second quarter of 2008 while storage, marketing and other net operating revenues increased mainly from third party marketing that utilized Big Sandy Pipeline capacity.
Total operating revenues increased by $89.9 million, or 15%, primarily as a result of higher sales prices on increased commercial activity related to contractual transmission and storage assets, an increase in processing volumes and commodity prices, higher gathering rates and new transmission revenues from the Big Sandy Pipeline.
Total purchased gas costs increased due to the higher gas costs on increased commercial activity related to contractual transmission and storage assets as well as higher gas costs related to processing activities.
Operating expenses totaled $168.6 million for 2008 compared to $121.5 million for 2007. The $47.1 million increase in operating expenses was due to increases of $20.2 million in SG&A, $18.4 million in O&M, and $8.5 million in D&A. The increase in SG&A was primarily due to labor and services to support the growth in the Midstream business, a $5.2 million reserve against Lehman Brothers receivables, and $1.2 million for legal and actuarial services associated with the pension and other post-retirement charge, partially offset by decreased SG&A for the gathering assets contributed to Nora Gathering, LLC. The increase in O&M resulted mainly from the $9.5 million pension and other post-retirement charge as well as increased electricity charges, compressor maintenance, labor and non-income taxes for the gathering and processing business due to new compressors and processing facilities, partially offset by the expenses associated with gathering asset contributed to Nora Gathering, LLC. The increase in D&A was primarily due to the increased investment in infrastructure during 2008, partially offset by decreased depreciation relating to the gathering asset contribution to Nora Gathering, LLC.
Other income represents allowance for equity funds used during construction. The $1.6 million decrease from 2007 to 2008 was primarily caused by a full year of AFUDC on Big Sandy recorded in 2007, as compared to only a partial year in 2008 as Big Sandy was placed on-line in the second quarter of 2008.
Equity in earnings of nonconsolidated investments totaled $5.1 million for 2008 compared to $2.6 million for 2007. This increase is related to equity earnings recorded for EQT Midstream’s investment in Nora Gathering, LLC, which was formed in May 2007.
Outlook
EQT Midstream’s long-term focus is to take advantage of its infrastructure asset position in the heart of the Marcellus shale play in southwestern Pennsylvania and northern West Virginia. The Equitrans Marcellus Expansion Project is expected to provide Appalachian producers with timely, cost effective options to reach Northeastern and Mid-Atlantic markets as well as storage by expanding Equitrans existing asset base. Equitrans plans to create new firm transportation capacity through the addition of pipeline looping, new high pressure laterals and compression facilities on Equitrans’ existing pipeline network. EQT Midstream successfully completed an open season for a proposed expansion of the Equitrans pipeline with total capacity demand indicated in the open season in excess of 1,100,000 Dth per day. The next steps are to secure firm precedent agreements with shippers and obtain FERC approval.
Gathering, processing and transmission revenues are expected to increase as EQT Midstream expands its infrastructure to support EQT Production growth in the Huron/Berea and Marcellus plays.
Equitable Distribution
Overview
Distribution’s business strategy is to earn a competitive return on its asset base through operational efficiency and innovative regulatory mechanisms. Distribution is focused on enhancing the value of its existing assets by establishing a reputation for excellent customer service, effectively managing its capital spending, improving the efficiency of its workforce and continuing to leverage technology throughout its operations.
Equitable Gas continues to focus on improved customer service. In 2009, Equitable Gas launched a new website giving customers the ability to view and pay bills on-line and providing customers with a Home Energy Analyzer that enables them to easily examine their energy use factoring in weather, appliance and electronics usage and the type of construction used in their home. These and other efforts, including improved operating performance at Equitable Gas’s customer call center, have resulted in increased overall customer satisfaction.
On February 26, 2009, the PA PUC approved a settlement between Equitable Gas and the active parties to the filing for a base rate case increase in Pennsylvania. The Company implemented the new base rates upon approval of the settlement.
Pennsylvania law requires that local distribution companies develop and implement programs to assist low-income customers with paying their gas bills. The costs of these programs are recovered through rates charged to other residential customers. Equitable Gas has several such programs, including the customer assistance program (CAP). As part of the rate case settlement, the Company received approval to increase the CAP surcharge in order to recover its costs for assisting low-income customers with paying their gas bills. In addition, the CAP costs will be reconciled annually to ensure complete recovery of these costs in the future.
Distribution’s net operating revenues increased 5% from 2008 to 2009 due to the increase in base rates. The weather in Equitable Gas’ service territory in 2009 was 3% warmer than 2008 and 6% warmer than the 30-year National Oceanic and Atmospheric Administration average. The weather in 2008 was 4% warmer than the 30-year average. Total operating expenses decreased 9% from 2008, primarily due to lower bad debt expense and lower overhead costs in 2009.
See Investing Activities in Capital Resources and Liquidity for a discussion of capital expenditures.
Results of Operations
Fiscal Year Ended December 31, 2009 vs. December 31, 2008
Distribution’s operating income totaled $78.9 million for 2009 compared to $59.9 million for 2008. The increase in operating income was primarily due to an increase in base rates and lower operating expenses.
Net operating revenues were $180.0 million for 2009 compared to $170.9 million for 2008. The $9.1 million increase in net operating revenues was primarily the result of the approval of the Company’s base rate increase in 2009. Net revenues from residential customers increased $5.9 million as a result of an increase in base rates which was partially offset by the absence of a 2008 non-recurring increase in customer assistance program activities, as well as customer conservation and slightly warmer weather. Off-system and energy services net operating revenues increased $2.1 million due to higher revenues from gathering activities resulting primarily from increased rates. Commercial and industrial net revenues increased $1.0 million due to higher base rates and an increase in usage by one industrial customer, partially offset by lower performance-based revenues. The high volume sales from the industrial customer have low unit margins and did not significantly impact total net operating revenues. A decrease in gas costs associated with asset optimization transactions and a decrease in the commodity component of residential tariff rates resulted in a decrease in both total operating revenues and purchased gas costs.
Operating expenses totaled $101.1 million for 2009 compared to $111.0 million for 2008. The $9.9 million decrease in operating expenses was primarily the result of lower bad debt, general overhead and labor and fringe benefit expenses in 2009 and the absence of the holding company reorganization costs that were incurred in 2008. The reduction in bad debt expense from 2008 to 2009 was the result of favorable adjustments in the allowance for uncollectible accounts in 2009 due to increased customer participation in programs assisting low-income customers in paying their bills, the recovery of CAP costs associated with the approval of the rate case settlement and a decrease in the commodity component of residential tariff rates. These decreases were partially offset by an increase in accruals for certain non-income tax reserves and an increase in incentive compensation costs.
Fiscal Year Ended December 31, 2008 vs. December 31, 2007
Distribution’s operating income totaled $59.9 million for 2008 compared to $34.5 million for 2007. The $25.4 million increase in operating income was primarily due to a non-recurring increase in customer assistance program activities, colder weather and lower SG&A expenses due to the absence in 2008 of costs associated with the now terminated Peoples and Hope acquisition.
Net operating revenues were $170.9 million for 2008 compared to $160.6 million for 2007. The $10.3 million increase in net operating revenues was primarily a result of an increase in both residential and commercial and industrial net operating revenues. The $6.0 million increase in residential net operating revenues was primarily the result of an increase in customer assistance program activities. Additionally, 2008 weather was 5% colder than the prior year. Commercial and industrial revenues increased $3.8 million due to an increase in performance-based revenues as well as increased volumes of 1,532 MMcf from 2007 to 2008 primarily due to an increase in usage by one industrial customer. The high volume sales from the industrial customer have low unit margins and did not significantly impact total net operating revenues. Off-system and energy services net operating revenues increased due to increased gathering revenue as a result of increased volumes and rates, partially offset by lower volumes and margins in asset optimization activities. Additionally, an increase in the commodity component of residential tariff rates resulted in an increase in both total operating revenues and purchased gas costs.
Operating expenses totaled $111.0 million for 2008 compared to $126.1 million for 2007. This $15.1 million decrease was primarily due to the impact of $21.0 million in 2007 costs related to the now terminated Peoples and Hope acquisition, a decrease in incentive compensation expenses and a reduction in insurance reserves due to increased safety measures. Partially offsetting these decreases were an increase in customer assistance expenses resulting from a significant increase in customer participation in the CAP and an increase in operating expenses primarily related to increased leak repair and maintenance activities for gathering operations, service line maintenance and line location requests and higher gas prices. Additionally, there was a $2.1 million increase in depreciation due to an adjustment in asset estimated useful lives resulting from the PA PUC-mandated asset service life study as well as increased capital expenditures. See Note 6 of the Consolidated Financial Statements for further discussion of the Peoples and Hope transaction.
Outlook
Distribution will continue to execute its strategy of earning a competitive return on its asset base through operational efficiency and regulatory mechanisms. Distribution is focused on enhancing the value of its existing assets by improving the efficiency of its workforce, establishing a reputation for excellent customer service, effectively managing its capital spending and continuing to leverage technology throughout its operations. Distribution will also seek out growth opportunities for the sale of natural gas through new outlets such as natural gas vehicles while promoting customer conservation and efficiency.
On October 29, 2009, Equitable Gas filed a request with the WV PSC to increase the rates it charges its approximately 13,000 customers for delivery of natural gas in West Virginia. It is the first delivery rate increase that Equitable Gas has requested in West Virginia since 1991. The proposed increase, which totals approximately $3 million annually, is subject to WV PSC review and is expected to increase residential gas bills by approximately 18% per month. Equitable Gas expects the rate case proceeding to be resolved no later than the third quarter of 2010.
Other Income Statement Items
In 2009, 2008 and 2007, other income primarily relates to the equity portion of AFUDC on various projects. In 2007, the Company made a substantial investment in the construction of the Big Sandy Pipeline, which was completed in the second quarter of 2008. Completion of the project reduced AFUDC in 2008 as a full year of AFUDC on Big Sandy was recorded in 2007, only a partial year in 2008. The substantial decrease in other income in 2009 reflects reduced value of projects subject to AFUDC.
As discussed in Note 9 to the Company’s Consolidated Financial Statements, the Company’s available-for-sale investments consist of equity and bond funds intended to fund plugging and abandonment and other liabilities for which the Company self-insures. At December 31, 2008, these investments had a fair market value which was $7.8 million below cost. The Company analyzed the decline in these investments based on the extent and duration of the impairment and the nature of the underlying assets. Although the Company holds these investments to fund long-term liabilities, based on the extent and duration of the impairment, combined with then current market conditions, the Company concluded that the decline was other-than-temporary. As such, the Company recognized a $7.8 million impairment in earnings in 2008.
In 2007, the Company reviewed its investment portfolio (including its investment allocation) and sold equity funds with a cost basis of $6.3 million for total proceeds of $7.3 million, resulting in the Company recognizing a gain of $1.0 million.
Interest Expense
Interest expense increased by $53.4 million from 2008 to 2009 primarily due to the Company’s continued investment in drilling and midstream infrastructure during 2009. This investment was partially funded by the issuance of $700 million of 8.125% notes in May 2009. The interest expense associated with these notes was partially offset by a 2.8% decrease in the average short-term interest rate during 2009.
Interest expense increased by $10.7 million from 2007 to 2008 primarily due to the Company’s investment in drilling and midstream infrastructure during 2007 and 2008. This investment was partially funded by the issuance of $500 million of 6.5% notes in March 2008. The interest expense associated with these notes was partially offset by a 2.3% decrease in the average short-term interest rate during 2008.
Weighted average annual interest rates on the Company’s long-term debt were 6.5%, 6.1% and 5.9% for 2009, 2008 and 2007, respectively. Weighted average annual interest rates on the Company’s short-term debt were 0.7%, 3.5% and 5.8% for 2009, 2008 and 2007, respectively.
Income Taxes
Income tax expense decreased by $58.3 million from 2008 to 2009 despite a higher effective tax rate as a result of lower pre-tax income. During 2009, the Company’s effective income tax rate increased from 37.7% to 38.1%. The higher tax rate in 2009 is primarily the result of nondeductible compensation expense partially offset by a regulatory asset recorded to recover deferred taxes caused by an accounting method change that deducts as repairs certain costs capitalized for financial accounting purposes. The Company recorded a tax benefit in 2008 for a change in the West Virginia state tax law that primarily provides for a reduction in future corporate income tax rates which was partially offset by additional tax expense recorded as a result of the completion of the IRS audit through the 2005 tax year.
Income tax expense increased by $10.5 million from 2007 to 2008 primarily due to the increase in the Company’s effective tax rate. The effective tax rate for 2008 was 37.7% compared to 35.9% in 2007. The higher effective tax rate in 2008 is the result of several factors including the Company being in a net operating loss position for tax purposes in 2008 which resulted in the loss of certain deductions for 2008 and for prior years as a result of carrying losses back to receive a cash refund of taxes paid. In addition, state taxes increased as a result of limitations imposed on certain state tax losses generated in 2008. The Company recorded a net increase to tax expense in 2008 as a result of the completion of its IRS audit through the 2005 tax year, partially offset by a beneficial change in the West Virginia state tax law.
The Company was in an overall federal tax net operating loss position for 2008 and 2009 and expects to pay minimal federal income taxes for as long as the Company’s drilling program in Appalachia continues, unless tax laws change. For federal income tax purposes, the Company currently deducts approximately 75% of drilling costs as intangible drilling costs (IDC) in the year incurred. The primary reasons for the Company’s net operating loss are the IDC deduction resulting from the Company’s drilling program and the accelerated tax deprecation for expansion of gathering infrastructure which provide tax deductions in excess of book deductions.
Capital Resources and Liquidity
Overview
The Company’s primary sources of cash during 2009 were cash flows from operating activities and proceeds from a public offering of Senior Notes. The Company used the proceeds from the public offering primarily to fund its capital spending program and repay short-term borrowings.
Operating Activities
The Company’s net cash provided by operating activities during 2009 was $725.7 million compared to $509.2 million for the same period of 2008. EQT received an income tax refund of $115.2 million from the IRS in 2009 relating to the 2008 net operating loss carryback claims that were filed with the IRS in 2009. The remaining increase in cash flows provided by operating activities is primarily the result of lower inventory, accounts receivable, unbilled revenues and margin deposits. These were partially offset by a corresponding decrease in accounts payable at December 31, 2009 as compared to December 31, 2008.
Cash flows provided by operating activities increased to $509.2 million in 2008 from $426.7 million in 2007. The increase in cash flows provided by operating activities was primarily attributable to a net cash refund related to income taxes of $14.0 million in 2008 compared to a net cash payment of $63.4 million in 2007. For federal income tax purposes the Company currently deducts approximately 75% of drilling costs as intangible drilling costs (IDC) in the year incurred. The IDC deduction resulting from its drilling program coupled with accelerated tax depreciation for expansion of the gathering infrastructure put the Company into an overall federal tax net operating
loss position in 2008. Unless the IDC related tax law changes, this tax position is likely to continue so long as the Company’s drilling program in Appalachia continues. As such, the Company expects minimal federal cash taxes for the foreseeable future.
Investing Activities
Cash flows used in investing activities totaled $985.5 million for 2009 as compared to $1,376.0 million for 2008, a net decrease of $390.5 million in cash flows used in investing activities between years. The decrease in cash flows used in investing activities was primarily attributable to the following:
· a decrease in capital expenditures to $963.9 million in 2009 from $1,344.0 million in 2008. See discussion of capital expenditures below;
· a decrease in capital contributions to Nora Gathering, LLC for use in midstream infrastructure projects to $6.4 million in 2009 from $29.0 million in 2008;
Cash flows used in investing activities totaled $1,376.0 million for 2008 as compared to $590.1 million for 2007, a net increase of $785.9 million in cash flows used in investing activities between years. The increase in cash flows used in investing activities was attributable to the following:
· an increase in capital expenditures to $1,344.0 million in 2008 from $776.7 million in 2007. See discussion of capital expenditures below;
· capital contributions of $29.0 million to Nora Gathering, LLC in 2008 for use in midstream infrastructure projects;
· the absence in 2008 of proceeds of $217.0 million received in 2007 from the sale and contribution of assets. See Note 5 to the Company’s Consolidated Financial Statements.
Capital Expenditures
* Includes $24.4 million and $3.7 million, in the well development and Midstream infrastructure categories, respectively, for the acquisition of additional working interest and related gathering assets in the Roaring Fork area. See Note 6 to the Company’s Consolidated Financial Statements.
The Company is committed to profitably expanding its production and reserves through horizontal drilling, exploiting additional reserve potential through key emerging development plays and expanding its infrastructure in the Appalachian Basin with the Equitrans Marcellus Expansion Project. Capital expenditures for 2010 will be concentrated on drilling in areas that already benefit from the Company’s substantial Appalachian midstream infrastructure in the Huron/Berea play. The Company’s planned 2010 capital expenditures are designed to achieve annual gas sales volume growth of 20% in 2010, without requiring access to the capital markets. The Company believes it has sufficient liquidity to finance its planned capital expenditures with cash generated from operating activities as well as a portion of the Company’s $1.5 billion revolving credit facility.
Capital expenditures for drilling and development totaled $717 million and $701 million during 2009 and 2008, respectively. The Company drilled 702 gross wells (536 net wells) in 2009, 434 Huron/Berea wells, 50 Marcellus wells and 218 CBM wells, compared to 668 gross wells (533 net wells) in 2008, including 484 Huron/Berea wells, 23 Marcellus wells and 161 CBM wells. Capital expenditures for 2009 also included $31.0 million for undeveloped property acquisitions, primarily within the Marcellus play. Capital expenditures for 2008 included $85.5 million for undeveloped property acquisitions.
Capital expenditures for the midstream operations totaled $201 million for 2009. EQT Midstream turned in-line 274 miles of pipeline and 21,850 horse power of compression primarily within the Huron/Berea play. During 2008, Midstream capital expenditures were $594 million and included costs associated with gathering pipeline and compression, including the Mayking corridor, and the construction of the Big Sandy Pipeline and Kentucky Hydrocarbon processing plant upgrade, both of which were completed in 2008.
Capital expenditures at Distribution totaled $34 million and $46 million during 2009 and 2008, respectively, principally for pipeline replacement and metering. The decrease in capital expenditures was due to reduced gathering-related infrastructure spending in 2009 as compared to 2008.
Financing Activities
Cash flows provided by financing activities totaled $259.8 million for 2009 as compared to $785.1 million for 2008. During 2009, the Company received $700 million from the public sale of 8.125% Senior Notes due June 1, 2019. By comparison, during 2008, the Company received $560.7 million from the public sale of 8.625 million shares of common stock and $500 million from the public sale of 6.50% Senior Notes due April 1, 2018. A portion of the 2009 and 2008 debt offerings were used to repay short-term borrowings under the Company’s revolving credit facility during the periods. The Company repaid $314.9 million in short-term borrowing during 2009 and $130.1 million in short-term borrowings during the same period in 2008. The Company also repaid $4.3 million in long-term debt during 2009.
Cash flows provided by financing activities totaled $785.1 million for 2008 as compared to $245.1 million for 2007. The increase was attributable largely to the 2008 equity and debt offerings.
Short-term Borrowings
Cash required for operations is affected primarily by the seasonal nature of the Company's natural gas distribution operations and the volatility of oil and natural gas commodity prices. In addition to funding working capital requirements, which are significantly impacted by seasonality, the Company utilizes short-term borrowings to fund any required margin deposit until the underlying transactions are settled or the deposits are returned and to finance capital expenditures until they can be permanently financed.
The Company has a $1.5 billion revolving credit facility that matures on October 26, 2011. The facility may be used for working capital, capital expenditures, share repurchases and other purposes including support of a commercial paper program. The credit facility is underwritten by a syndicate of 15 financial institutions, each of which is obligated to fund its pro-rata portion of any borrowings by the Company. Lehman Brothers Bank, FSB (Lehman) is one of the 15 financial institutions in the syndicate and has committed to make loans not exceeding $95 million under the facility. Lehman failed to fund its portion of all recent borrowings by the Company which effectively reduces the total amount available under the facility to $1,405 million. Otherwise, the Company’s large syndicate group and relatively low percentage of participation by each lender is expected to limit the Company’s exposure if further problems or consolidation occur in the banking industry.
As of December 31, 2009, the Company had outstanding under the revolving credit facility loans of $5.0 million in support of corporate purposes and an irrevocable standby letter of credit of $24.4 million. The weighted average interest rate on the Company’s short-term borrowings was 0.7% for 2009. The interest rate on the revolving credit facility fluctuates with the LIBOR rate.
The Company’s short-term borrowings generally have original maturities of three months or less.
Security Ratings and Financing Triggers
The table below reflects the credit ratings for the outstanding debt instruments of the Company at December 31, 2009. Changes in credit ratings may affect the Company’s cost of short-term and long-term debt and its access to the credit markets.
On February 17, 2010, Standard & Poor’s Ratings services (S&P) affirmed its ratings on EQT. At the same time, S&P revised its outlook to negative and lowered the short-term rating to A-3 citing the Company’s growth in its exploration and production and midstream businesses.
On March 9, 2009, Moody’s reaffirmed its ratings on EQT. The Outlook is negative. Moody’s stated that the “ratings reflect the diversification and vertical integration among its three business segments as well as the Baa stand-alone quality of both its E&P and LDC operations.”
On March 20, 2009, Fitch announced initial ratings for EQT stating that the “ratings are supported by the stability and predictability of cash flows from its midstream and gas distribution businesses and the quality of its exploration and production (E&P) segment, which focuses on natural gas production in the Appalachian Basin.”
The Company’s credit ratings may be subject to revision or withdrawal at any time by the assigning rating organization and each rating should be evaluated independently of any other rating. The Company cannot ensure that a rating will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a credit rating agency if, in its judgment, circumstances so warrant. If the credit rating agencies downgrade the Company’s ratings, particularly below investment grade, the Company’s access to the capital markets may be limited, borrowing costs and margin deposits on derivative contracts could increase, counterparties may request additional assurances and the potential pool of investors and funding sources may decrease. The required margin is subject to significant change as a result of other factors besides credit rating such as gas prices and credit thresholds set forth in agreements between the hedging counterparties and the Company.
The Company’s debt instruments and other financial obligations include provisions that, if not complied with, could require early payment, additional collateral support or similar actions. The most significant default events include maintaining covenants with respect to maximum leverage ratio, insolvency events, nonpayment of scheduled principal or interest payments, acceleration of other financial obligations and change of control provisions. The Company’s current credit facility’s financial covenants require a total debt-to-total capitalization ratio of no greater than 65%. The calculation of this ratio excludes the effects of accumulated other comprehensive income (loss). As of December 31, 2009, the Company is in compliance with all existing debt provisions and covenants.
Commodity Risk Management
The Company’s overall objective in its hedging program is to protect earnings from undue exposure to the risk of changing commodity prices. The Company’s risk management program includes the use of exchange-traded natural gas futures contracts and options and OTC natural gas swap agreements and options (collectively, derivative commodity instruments) to hedge exposures to fluctuations in natural gas prices and for trading purposes. The derivative commodity instruments currently utilized by the Company are primarily fixed price swaps, collars and options.
The approximate volumes and prices of the Company’s total hedge position for 2010 through 2012 production are:
* The above price is based on a conversion rate of 1.05 MMBtu/Mcf
The Company’s current hedge position extends through 2015 and provides price protection for approximately 40%, 30% and 10% of expected natural gas production sales volumes in 2010, 2011 and 2012, respectively. The Company’s exposure to a $0.10 change in average NYMEX natural gas price is approximately $0.05, $0.06 and $0.10 per diluted share for 2010, 2011 and 2012, respectively. The Company also engages in a limited number of basis swaps to protect earnings from undue exposure to the risk of geographic disparities in commodity prices.
See the “Quantitative and Qualitative Disclosures About Market Risk,” in
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Derivative Commodity Instruments
The Company’s primary market risk exposure is the volatility of future prices for natural gas and natural gas liquids, which can affect the operating results of the Company primarily through the EQT Production and EQT Midstream segments. The Company’s use of derivatives to reduce the effect of this volatility is described in Notes 1 and 3 to the Consolidated Financial Statements and under the caption “Commodity Risk Management” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” (Item 7) of this Form 10-K. The Company uses non-leveraged derivative commodity instruments that are placed with major financial institutions whose credit worthiness is continually monitored. The Company also enters into energy trading contracts to leverage its assets and limit its exposure to shifts in market prices. The Company’s use of these derivative financial instruments is implemented under a set of policies approved by the Company’s Corporate Risk Committee and Board of Directors.
Commodity Price Risk
The following sensitivity analysis estimates the potential effect on fair value or future earnings from derivative commodity instruments due to a 10% increase or a 10% decrease in commodity prices.
For the derivative commodity instruments used to hedge the Company’s forecasted production, the Company sets policy limits relative to the expected production and sales levels which are exposed to price risk. For the derivative commodity instruments used to hedge forecasted natural gas purchases and sales which are exposed to price risk, the Company sets limits related to acceptable exposure levels.
The financial instruments currently utilized by the Company include futures contracts, swap agreements, collar agreements and option contracts, which may require payments to or receipt of payments from counterparties based on the differential between a fixed and variable price for the commodity. The Company also considers options and other contractual agreements in implementing its commodity hedging strategy.
Management monitors price and production levels on a continuous basis and will make adjustments to quantities hedged as warranted. The Company’s overall objective in its hedging program is to ensure an adequate level of return for the well development and infrastructure investment at EQT Production and EQT Midstream.
With respect to the derivative commodity instruments held by the Company for purposes other than trading as of December 31, 2009, the Company hedged portions of expected equity production through 2015 and portions of forecasted purchases and sales by utilizing futures contracts, swap agreements and collar agreements covering approximately 142.9 Bcf of natural gas. See the “Commodity Risk Management” in the “Capital Resources and Liquidity” sections of “Management’s Discussion and Analysis of Financial Condition and Results of Operations” (Item 7) of this Form 10-K for further discussion. A hypothetical decrease of 10% in the market price of natural gas from the December 31, 2009 levels would increase the fair value of non-trading natural gas derivative instruments by approximately $66.9 million. A hypothetical increase of 10% in the market price of natural gas from the December 31, 2009 levels would decrease the fair value of non-trading natural gas derivative instruments by approximately $64.2 million.
The Company determined the change in the fair value of the derivative commodity instruments using a model similar to its normal determination of fair value as described in Note 1 to the Consolidated Financial Statements. The Company assumed a 10% change in the price of natural gas from its levels at December 31, 2009. The price change was then applied to the derivative commodity instruments recorded on the Company’s balance sheet, resulting in the change in fair value.
The above analysis of the derivative commodity instruments held by the Company for purposes other than trading does not include the offsetting impact that the same hypothetical price movement may have on the Company and its subsidiaries’ physical sales of natural gas. The portfolio of derivative commodity instruments held for risk management purposes approximates the notional quantity of a portion of the expected or committed transaction volume of physical commodities with commodity price risk for the same time periods. Furthermore, the derivative
commodity instrument portfolio is managed to complement the physical transaction portfolio, reducing overall risks within limits. Therefore, an adverse impact to the fair value of the portfolio of derivative commodity instruments held for risk management purposes associated with the hypothetical changes in commodity prices referenced above would be offset by a favorable impact on the underlying hedged physical transactions, assuming the derivative commodity instruments are not closed out in advance of their expected term, the derivative commodity instruments continue to function effectively as hedges of the underlying risk and the anticipated transactions occur as expected.
If the underlying physical transactions or positions are liquidated prior to the maturity of the derivative commodity instruments, a loss on the financial instruments may occur, or the derivative commodity instruments might be worthless as determined by the prevailing market value on their termination or maturity date, whichever comes first.
Other Market Risks
The Company is exposed to credit loss in the event of nonperformance by counterparties to derivative contracts. This credit exposure is limited to derivative contracts with a positive fair value. The Company believes that NYMEX-traded futures contracts have minimal credit risk because the Commodity Futures Trading Commission regulations are in place to protect exchange participants, including the Company, from any potential financial instability of the exchange members. The Company’s swap, collar and option derivative instruments are primarily with financial institutions and thus are subject to events that would impact those companies individually as well as that industry as a whole.
The Company utilizes various processes and analysis to monitor and evaluate its credit risk exposures. This includes closely monitoring current market conditions, counterparty credit spreads and credit default swap rates. Credit exposure is controlled through credit approvals and limits. To manage the level of credit risk, the Company deals with financial counterparties that are of investment grade or better, enters into netting agreements whenever possible and may obtain collateral or other security.
Approximately 54%, or $144.5 million, of OTC derivative contracts outstanding at December 31, 2009 have a positive fair value. All derivative contracts outstanding as of December 31, 2009 are with counterparties having an S&P rating of A- or above at that date.
In September 2008, the credit support provider of one counterparty (Lehman Brothers Holding, Inc.) declared bankruptcy resulting in a default under various derivative contracts with the Company. As a result, those contracts were terminated and a reserve of approximately $5 million was recorded against the entire balance due to the Company. There is no additional income statement exposure to this counterparty beyond the reserve recorded in 2008. As of December 31, 2009, the Company was not in default under any derivative contracts and has no knowledge of default by any other counterparty to derivative contracts. The Company made no adjustments to the fair value of derivative contracts due to credit related concerns outside of the normal non-performance risk adjustment included in the Company’s established fair value procedure. The Company will continue to monitor market conditions that may impact the fair value of derivative contracts reported in the Consolidated Balance Sheet.
The Company is also exposed to the risk of nonperformance by credit customers on physical sales of natural gas. A significant amount of revenues and related accounts receivable from EQT Production are generated from the sale of produced natural gas to certain marketers, including the Company’s wholly owned marketing subsidiary EQT Energy, and utility and industrial customers located mainly in the Appalachian area. Additionally, a significant amount of revenues and related accounts receivable from EQT Midstream is generated from the sale of produced natural gas liquids to a gas processor in Kentucky and gathering of natural gas in Kentucky, Virginia, Pennsylvania and West Virginia.
The Company has a $1.5 billion revolving credit facility that matures on October 26, 2011. The credit facility is underwritten by a syndicate of 15 financial institutions each of which is obligated to fund its pro-rata portion of any borrowings by the Company. Lehman is one of the 15 financial institutions in the syndicate and has committed to make loans not exceeding $95 million under the facility. Lehman failed to fund its portion of all recent borrowings by the Company which effectively reduces the total amount available under the facility to $1,405
million. As of December 31, 2009, the Company had outstanding under the facility $5.0 million of loans in support of corporate activities and an irrevocable standby letter of credit of $24.4 million.
No one lender in the syndicate holds more than 10% of the facility. The Company’s large syndicate group and relatively low percentage of participation by each lender is expected to otherwise limit the Company’s exposure if further problems or consolidation occur in the banking industry.
Item 8. Financial Statements and Supplementary Data
Page Reference
Reports of Independent Registered Public Accounting Firm
Statements of Consolidated Income for each of the three years in the period ended December 31, 2009
Statements of Consolidated Cash Flows for each of the three years in the period ended December 31, 2009
Consolidated Balance Sheets as of December 31, 2009 and 2008
Statements of Consolidated Common Stockholders’ Equity for each of the three years in the period ended December 31, 2009
Notes to Consolidated Financial Statements
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders
EQT Corporation
We have audited the accompanying consolidated balance sheets of EQT Corporation and Subsidiaries (formerly Equitable Resources, Inc.) as of December 31, 2009 and 2008, and the related statements of consolidated income, common stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2009. Our audits also included the financial statement schedule listed in the Index at Item 15(a). These financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our 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 audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of EQT Corporation and Subsidiaries (formerly Equitable Resources, Inc.) at December 31, 2009 and 2008, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2009 in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
As discussed in Note 7 to the consolidated financial statements, the Company has changed its accounting for uncertain tax position during the year ended December 31, 2007. As discussed in Note 22 to the consolidated financial statements, the Company has changed its reserve estimates and related disclosures as a result of adopting new oil and gas reserve estimation and disclosure requirements during the year ended December 31, 2009.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of EQT Corporation and Subsidiaries’ (formerly Equitable Resources, Inc.) internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 18, 2010, expressed an unqualified opinion thereon.
Pittsburgh, Pennsylvania
February 18, 2010
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders
EQT Corporation
We have audited EQT Corporation and Subsidiaries’ (formerly Equitable Resources, Inc.) internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). EQT Corporation and Subsidiaries’ (formerly Equitable Resources, Inc.) management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
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 (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) 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 (3) 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.
In our opinion, EQT Corporation and Subsidiaries (formerly Equitable Resources, Inc.) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of EQT Corporation and Subsidiaries (formerly Equitable Resources, Inc.) as of December 31, 2009 and 2008, and the related statements of consolidated income, common stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2009 and our report dated February 18, 2010 expressed an unqualified opinion thereon.
Pittsburgh, Pennsylvania
February 18, 2010
EQT CORPORATION AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED INCOME
YEARS ENDED DECEMBER 31,
See notes to consolidated financial statements.
EQT CORPORATION AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CASH FLOWS
YEARS ENDED DECEMBER 31,
See notes to consolidated financial statements.
EQT CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
DECEMBER 31,
See notes to consolidated financial statements.
EQT CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
DECEMBER 31,
See notes to consolidated financial statements.
EQT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY
YEARS ENDED DECEMBER 31, 2009, 2008 and 2007
Common shares authorized: 320,000,000 shares. Preferred shares authorized: 3,000,000 shares. There are no preferred shares issued or outstanding.
See notes to consolidated financial statements.
EQT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2009
1. Summary of Significant Accounting Policies
Principles of Consolidation: The Consolidated Financial Statements include the accounts of EQT Corporation and all subsidiaries, ventures and partnerships in which a controlling equity interest is held (EQT or the Company). All significant intercompany accounts and transactions have been eliminated in consolidation. EQT utilizes the equity method of accounting for companies where its ownership is less than or equal to 50% and significant influence exists.
On June 30, 2008, the former Equitable Resources, Inc. (Old EQT) entered into and completed an Agreement and Plan of Merger (the Plan) under which Old EQT reorganized into a holding company structure such that a newly formed Pennsylvania corporation, also named Equitable Resources, Inc. (New EQT), became the publicly traded holding company of Old EQT and its subsidiaries. The primary purpose of this reorganization (the Reorganization) was to separate Old EQT’s state-regulated distribution operations into a new subsidiary in order to better segregate its regulated and unregulated businesses and improve overall financing flexibility. New EQT changed its name to EQT Corporation effective February 9, 2009. Throughout these statements, references to EQT, EQT Corporation and the Company refer collectively to New EQT and its consolidated subsidiaries.
Reclassification: Certain previously reported amounts have been reclassified to conform to the current year presentation.
Use of Estimates: The preparation of financial statements in conformity with United States generally accepted accounting principles requires management to make estimates and assumptions that affect the amounts reported in the Consolidated Financial Statements and accompanying notes. Actual results could differ from those estimates.
Cash Equivalents: The Company considers all highly liquid investments with an original maturity of three months or less when purchased to be cash equivalents. These investments are accounted for at cost. Interest earned on cash equivalents is included as a reduction of interest expense.
Inventories: Generally, the Company’s inventory balance consists of natural gas stored underground and materials and supplies recorded at the lower of average cost or market. Included in the inventory balance at December 31, 2009 and 2008 is $10.9 million and $53.8 million, respectively, of lower of cost or market adjustments due to market natural gas prices being lower than the carrying value of natural gas stored underground. For hedged inventory the Company reclassifies unrealized hedge gains deferred in accumulated other comprehensive income into earnings in the same period as the lower of cost or market adjustment. As such, the recording of the lower of cost or market adjustment had an immaterial impact to the Company's 2009 and 2008 earnings.
EQT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2009
Property, Plant and Equipment: The Company’s property, plant and equipment consists of the following:
Oil and gas producing properties use the successful efforts method of accounting for production activities. Under this method, the cost of productive wells, including mineral interests, wells and related equipment, development dry holes, as well as productive acreage, are capitalized and depleted on the unit-of-production method. These capitalized costs include salaries, benefits and other internal costs directly attributable to these activities. The Company capitalized internal costs of $46.5 million, $35.6 million and $14.4 million in 2009, 2008 and 2007, respectively. Depletion expense is calculated based on the actual production multiplied by the depletion rate per unit. The depletion rates are derived by dividing the total costs capitalized over the number of units expected to be produced over the life of the reserves. Costs of exploratory dry holes, geological and geophysical activities, delay rentals and other property carrying costs are charged to expense. The majority of the Company’s oil and natural gas producing properties consist of gas producing properties which were depleted at a composite rate of $1.06/Mcf, $0.81/Mcf and $0.70/Mcf produced for the years ended December 31, 2009, 2008 and 2007, respectively.
The carrying values of the Company’s proved oil and gas properties are reviewed for indications of impairment whenever events or circumstances indicate that the remaining carrying value may not be recoverable. In order to determine whether impairment has occurred, the Company estimates the expected future cash flows (on an undiscounted basis) from its proved oil and gas properties and compares these estimates to their respective carrying values. The estimated future cash flows used to test those properties for recoverability are based on proved reserves, utilizing assumptions about the use of the asset, market prices for oil and gas and future operating costs. Proved oil and gas properties that have carrying amounts in excess of estimated future cash flows would be deemed unrecoverable. Those properties would be written down to fair value, which would be estimated by discounting the estimated future cash flows using discount rate assumptions that marketplace participants would use in their estimates of fair value. For the years ended December 31, 2009, 2008 and 2007, the Company did not recognize impairment charges on proved oil and gas properties.
Capitalized costs of unproved properties are evaluated at least annually for recoverability on an aggregated prospect basis. Indicators of potential impairment included changes brought about by economic factors, potential shifts in business strategy employed by management and historical experience. If it is determined that the properties will not yield proved reserves, the related costs are expensed in the period in which that determination is made. Unproved properties had a net book value of $105.9 million and $81.9 million at December 31, 2009 and December 31, 2008, respectively.
The Company had capitalized exploratory well costs pending the determination of proved reserves of $6.9 million on the exploratory Utica well at December 31, 2008. During 2009, the Company incurred $1.0 million on
EQT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2009
this well. During 2009, the Company made the decision to plug back the well and convert it to a horizontal Marcellus well in 2010. As a result, the Company wrote-off $2.9 million of incremental costs related to drilling down to the Utica formation thereby leaving no capitalized exploratory well costs at December 31, 2009. There were no significant unproved properties balances at December 31, 2007. For additional information on oil and gas properties see Note 22 (unaudited).
Midstream property, plant and equipment is carried at cost. Depreciation is calculated using the straight-line method based on estimated service lives. Midstream property consists largely of gathering and transmission systems (25-60 year estimated service life), buildings (35 year estimated service life), office equipment (3-7 year estimated service life), vehicles (5 year estimated service life), and computer and telecommunications equipment and systems (3-7 year estimated service life).
Distribution property, plant and equipment, principally regulated property, is carried at cost. Depreciation is recorded using composite rates on a straight-line basis. The overall rate of depreciation for the years ended December 31, 2009 and December 31, 2008, was approximately 4% of net properties in both years.
Major maintenance projects that do not increase the overall life of the related assets are expensed. When the major maintenance materially increases the life or value of the underlying asset, the cost is capitalized.
Sales and Retirements Policies: No gain or loss is recognized on the partial sale of oil and gas reserves unless non-recognition would significantly alter the relationship between capitalized costs and remaining proved reserves for the affected amortization base. When gain or loss is not recognized, the amortization base is reduced by the amount of the proceeds. Due to the significance of the transaction, a gain was recognized on the sale and contribution of Nora assets in 2007. See Note 5.
Regulatory Accounting: EQT Midstream’s regulated operations consist of interstate pipeline operations subject to regulation by the Federal Energy Regulatory Commission (FERC) and certain state-regulated gathering operations. The Distribution segment’s rates, terms of service, and contracts with affiliates are subject to comprehensive regulation by the Pennsylvania Public Utility Commission (PA PUC) and the West Virginia Public Service Commission (WV PSC). The issuance of securities by Equitable Gas Company, LLC, the Company’s gas distribution subsidiary, is subject to regulation by the PA PUC and WV PSC. Distribution also provides field line service, also referred to as “farm tap” service, in Kentucky which is subject only to rate regulation by the Kentucky Public Service Commission. The application of regulatory accounting allows the Company to defer expenses and income on its Consolidated Balance Sheets as regulatory assets and liabilities when it is probable that those expenses and income will be allowed in the rate setting process in a period different from the period in which they would have been reflected in the Statements of Consolidated Income for a non-regulated company. The deferred regulatory assets and liabilities are then recognized in the Statements of Consolidated Income in the period in which the same amounts are reflected in rates.
Where permitted by regulatory authority under purchased natural gas adjustment clauses or similar tariff provisions, Equitable Distribution defers the difference between its purchased natural gas cost, less refunds, and the billing of such cost and amortizes the deferral over subsequent periods in which billings either recover or repay such amounts. Such amounts are reflected on the Company’s Consolidated Balance Sheets as other current assets or liabilities. For further information regarding regulatory assets, see Note 10.
When any portion of Distribution’s or EQT Midstream’s regulated operations ceases to meet the criteria for application of regulatory accounting treatment for all or part of their operations, the regulatory assets and liabilities related to those portions are eliminated from the Consolidated Balance Sheets and are included in the Statements of Consolidated Income in the period in which the discontinuance of regulatory accounting treatment occurs.
EQT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2009
The following table presents the total regulated net revenues and operating expenses of the Company:
The following table presents the regulated net property, plant and equipment of the Company:
Derivative Instruments: Derivatives are held as part of a formally documented risk management program. The Company’s risk management activities are subject to the management, direction and control of the Company’s Corporate Risk Committee (CRC). The CRC reports to the Audit Committee of the Board of Directors and is comprised of the chief executive officer, the president and chief operating officer, the chief financial officer, the chief risk officer and other officers and employees.
The Company’s risk management program includes the consideration and, when appropriate, the use of (i) exchange-traded natural gas futures contracts and options and over the counter (OTC) natural gas swap agreements and options (collectively, derivative commodity instruments) to hedge exposures to fluctuations in natural gas prices and for trading purposes and (ii) interest rate swap agreements to hedge exposures to fluctuations in interest rates. At contract inception, the Company designates its derivative instruments as hedging or trading activities.
The Company recognizes all derivative instruments as either current assets or current liabilities at fair value due to their highly liquid nature. The Company can net settle its derivative instruments at any time. The measurement of fair value is based upon actively quoted market prices when available. In the absence of actively
EQT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2009
quoted market prices, the Company seeks indicative price information from external sources, including broker quotes and industry publications. If pricing information from external sources is not available, measurement involves judgment and estimates. These estimates are based upon valuation methodologies deemed appropriate by the Company’s CRC.
The accounting for the changes in fair value of the Company’s derivative instruments depends on the use of the derivative instruments. To the extent that a derivative instrument has been designated and qualifies as a cash flow hedge, the effective portion of the change in fair value of the derivative instrument is reported as a component of accumulated other comprehensive income (loss), net of tax, and is subsequently reclassified into earnings in the same period or periods during which the hedged forecasted transaction affects earnings. The Company assesses the effectiveness of hedging relationships, as determined by the degree that the gain (loss) for the hedging instrument offsets the loss (gain) on the hedged item, both at the inception of the hedge and on an on-going basis. If the gain (loss) for the hedging instrument is greater than the loss (gain) on the hedged item, the ineffective portion of the cash flow hedge is immediately recognized in operating revenues in the Statements of Consolidated Income.
If a cash flow hedge is terminated or de-designated as a hedge before the settlement date of the hedged item, the amount of accumulated other comprehensive income (loss) recorded up to that date remains accrued provided that the forecasted transaction remains probable of occurring, and going forward, the change in fair value of the derivative instrument is recorded in earnings. The derivative instruments that comprise the amount recorded in accumulated other comprehensive income (loss) are primarily instruments which are designated and qualify as cash flow hedges. During 2008, the Company entered into derivative transactions which had the effect of offsetting existing cash flow hedges, resulting in an effective reduction in the hedge position for years 2010 through 2013. The Company concurrently de-designated the original transactions. The fair value of these derivative instruments was a net $19.1 million liability at December 31, 2009. In addition, during the first quarter of 2009, the Company terminated certain collar agreements scheduled to mature during the period 2010 through 2012. As of the date of termination of these hedges the Company had recorded a gain, net of tax, in accumulated other comprehensive income of approximately $5.1 million. These amounts will be recognized as part of the realized sales price in the Consolidated Statement of Income when the underlying physical transactions occur. The Company does not treat these derivatives as hedging instruments. These amounts are included in the Consolidated Balance Sheet as derivative instruments, at fair value.
The Company reports all gains and losses on its energy trading contracts net on its Statements of Consolidated Income.
Allowance for Funds Used During Construction: The Company capitalizes the carrying costs for the construction of certain regulated long-term assets and amortizes the costs over the life of the related assets. The calculated allowance for funds used during construction (AFUDC) includes capitalization of the cost of financing construction of assets subject to regulation by the PA PUC, the WV PSC or the FERC. A computed interest cost and a designated cost of equity for financing the construction of these regulated assets are recorded in the Company’s income statement. The debt portion is calculated based on the average cost of debt and is included as a reduction of interest expense in the Statements of Consolidated Income. AFUDC interest costs were $0.4 million, $2.1 million and $2.6 million for the years ended December 31, 2009, 2008 and 2007, respectively.
The equity portion of AFUDC is calculated using the most recent equity rate of return approved by the applicable regulator. Equity amounts capitalized are included in other income in the Statements of Consolidated Income. The AFUDC equity amounts capitalized were $1.2 million, $6.2 million and $7.6 million for the years ended December 31, 2009, 2008 and 2007, respectively.
Capitalized Interest: Interest costs for the construction of certain long-term assets in unregulated Company businesses are capitalized and amortized over the related assets’ estimated useful lives. The Company capitalized interest costs of $3.8 million, $14.9 million and $4.2 million, during 2009, 2008 and 2007 respectively, as a portion of the cost of the related long-term assets.
Impairment of Long-Lived Assets: Whenever events or changes in circumstances indicate that the carrying
EQT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2009
amount of long-lived assets may not be recoverable, the Company reviews its long-lived assets for impairment by first comparing the carrying value of the assets to the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the assets. If the carrying value exceeds the sum of the assets’ undiscounted cash flows, the Company estimates an impairment loss by taking the difference between the carrying value and fair value of the assets.
Other Current Liabilities: Included in current liabilities in the Company’s Consolidated Balance Sheet is approximately $70 million of incentive compensation at December 31, 2009.
Revenue Recognition: Revenue is recognized for production and gathering activities when deliveries of natural gas, crude oil and natural gas liquids (NGL) are made. Revenues from natural gas transportation and storage activities are recognized in the period service is provided. Sales of natural gas to distribution customers are billed on a monthly cycle basis; however, the billing cycle periods for certain customers do not necessarily coincide with accounting periods used for financial reporting purposes. The Company follows the revenue accrual method of accounting for Distribution segment revenue whereby revenues applicable to gas delivered to customers but not yet billed under the cycle billing method are estimated and accrued and the related costs are charged to expense. The Company reports revenue from all energy trading contracts net in the income statement, regardless of whether the contracts are physically or financially settled. Contracts which result in physical delivery of a commodity expected to be used or sold by the Company in the normal course of business are considered normal purchases and sales and are not subject to mark-to-market accounting. Revenues from these contracts are recognized at contract value when delivered. Revenues associated with energy trading contracts that do not result in physical delivery of an energy commodity are classified as derivative instruments and are recorded using mark-to-market accounting. Revenues associated with the Company’s natural gas advance sales contracts are recognized as natural gas is gathered and delivered. The Company accounts for gas-balancing arrangements under the entitlement method. The Company uses the gross method to account for overhead cost reimbursements from joint operating partners. During periods in which rates are subject to refund as a result of a pending rate case, the Company records revenue at the rates which are pending approval but reserves these revenues to the level of previously approved rates until the final settlement of the rate case.
Investments: Investments in companies in which the Company has the ability to exert significant influence over operating and financial policies (generally 20% to 50% ownership) are accounted for using the equity method. Under the equity method, investments are initially recorded at cost and adjusted for dividends and undistributed earnings and losses. These investments are classified as equity in nonconsolidated investments on the Consolidated Balance Sheets. The Company recognizes a loss in the value of an equity method investment that is other than a temporary decline. The Company analyzes its equity method investments based on its share of estimated future cash flows from the investment to determine whether the carrying amount will be recoverable.
Other investments in equity securities which are generally under 20% ownership and where the Company does not exert significant influence over operating and financial polices are accounted for as available-for-sale and are classified as investments, available-for-sale on the Consolidated Balance Sheets. Available-for-sale securities are required to be carried at fair value, with any unrealized gains and losses reported on the Consolidated Balance Sheets within a separate component of equity, accumulated other comprehensive income (loss). The Company utilizes the average cost method to determine the cost of the securities sold. The Company continually reviews its available-for-sale investments to determine whether a decline in fair value below the cost basis is other than temporary. If the decline in fair value is judged to be other than temporary, the cost basis of the security is written down to fair value and the amount of the write-down is included in the Statements of Consolidated Income. The Company recorded an other than temporary impairment of $7.8 million in 2008. See Note 9. No other than temporary decline in fair value was recorded in 2009 or 2007.
Purchased Gas Costs: Purchased gas costs in the Statements of Consolidated Income include natural gas wellhead purchases, natural gas field line purchases, natural gas transmission line purchases, purchased gas cost adjustments, natural gas withdrawn from storage, gas used for product extraction and other gas supply expenses, including pipeline demand charges and related transportation costs of purchased gas.
EQT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2009
Income Taxes: The Company files a consolidated federal income tax return and utilizes the asset and liability method to account for income taxes. The provision for income taxes represents amounts paid or estimated to be payable, net of amounts refunded or estimated to be refunded, for the current year and the change in deferred taxes, exclusive of amounts recorded in other comprehensive income. Any refinements to prior years’ taxes made due to subsequent information are reflected as adjustments in the current period. Separate income taxes are calculated for income from continuing operations, discontinued operations and items charged or credited directly to stockholders’ equity.
Deferred income tax assets and liabilities are determined based on temporary differences between the financial reporting and tax bases of assets and liabilities and are recognized using enacted tax rates for the effect of such temporary differences. Deferred tax assets are reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax asset will not be realized. Where deferred tax liabilities will be passed through to customers in regulated rates, the Company establishes a corresponding regulatory asset for the increase in future revenues that will result when the temporary differences reverse.
Investment tax credits realized in prior years were deferred and are being amortized over the estimated service lives of the related properties where required by ratemaking rules.
In accounting for uncertainty in income taxes, the Company utilizes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The recognition threshold requires the Company to determine whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position in order to record any financial statement benefit. If it is more likely than not that a tax position will be sustained, then the Company must measure the tax position to determine the amount of benefit to recognize in financial statements. The tax position is measured at the largest amount of benefit that is greater than 50 percent likely of being realized upon ultimate settlement. The Company recognizes interest and penalties accrued related to unrecognized tax benefits in income tax expense.
Provision for Doubtful Accounts: Judgment is required to assess the ultimate realization of the Company’s accounts receivable, including assessing the probability of collection and the credit worthiness of certain customers. Reserves for uncollectible accounts are recorded as part of selling, general and administrative expense on the Statements of Consolidated Income. The reserves are based on historical experience, current and expected economic trends and specific information about customer accounts. Accordingly, actual results may differ from these estimates under different assumptions or conditions.
Earnings Per Share (EPS): Basic EPS were computed by dividing net income by the weighted average number of common shares outstanding during the period, without considering any dilutive items. Diluted EPS were computed by dividing net income by the weighted average number of common shares and potentially dilutive securities, net of shares assumed to be repurchased using the treasury stock method. Purchases of treasury shares are calculated using the average share price for the Company’s common stock during the period. Potentially dilutive securities arise from the assumed conversion of outstanding stock options and other share-based awards. See Note 14.
Asset Retirement Obligations: The Company accrues a liability for legal asset retirement obligations based on an estimate of the timing and amount of their settlement. For oil and gas wells, the fair value of the Company’s plugging and abandonment obligations is required to be recorded at the time the obligations are incurred, which is typically at the time the wells are drilled. Upon initial recognition of an asset retirement obligation, the Company increases the carrying amount of the long-lived asset by the same amount as the liability. Over time, the liabilities are accreted for the change in their present value, through charges to depreciation, depletion and amortization, and the initial capitalized costs are depleted over the useful lives of the related assets.
The Company is required to operate and maintain its natural gas pipeline and storage systems, and intends to do so as long as supply and demand for natural gas exists, which the Company expects for the foreseeable future. Therefore, the Company believes that the substantial majority of its natural gas pipeline and storage system assets have indeterminate lives.
EQT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2009
The following table presents a reconciliation of the beginning and ending carrying amounts of the Company’s asset retirement obligations which is included in other credits in the Consolidated Balance Sheet. The Company does not have any assets that are legally restricted for purposes of settling these obligations.
Self-Insurance: The Company is self-insured for certain losses related to workers’ compensation and maintains a self-insured retention for general liability, automobile liability, environmental liability and other casualty coverages. The Company maintains stop loss coverage with third party insurers to limit the total exposure for general liability, automobile liability, environmental liability and workers’ compensation. The recorded reserves represent estimates of the ultimate cost of claims incurred as of the balance sheet date. The estimated liabilities are based on analyses of historical data and actuarial estimates and are not discounted. The liabilities are reviewed by management quarterly and by independent actuaries annually to ensure that they are appropriate. While the Company believes these estimates are reasonable based on the information available, financial results could be impacted if actual trends, including the severity or frequency of claims or fluctuations in premiums, differ from estimates.
Recently Issued Accounting Standards:
Accounting for Variable Interest Entities
In June 2009, the FASB issued amendments to improve financial reporting by enterprises involved with variable interest entities. The amendments are effective as of the beginning of the first annual reporting period after November 15, 2009, which for the Company is January 1, 2010. These amendments will not have a material impact on the Company’s future consolidated financial statements.
Disclosures about Fair Value Measurements
In January 2010, the FASB issued an amendment intended to improve the transparency of the inputs and assumptions used to measure the fair value of assets and liabilities reported at fair value by requiring enhanced disclosures. This amendment is effective for financial statements issued for fiscal years and interim periods beginning after December 15, 2009. However, certain disclosures included in the amendment are effective for fiscal years beginning after December 15, 2010. The Company is currently evaluating the affect that this amendment will have on its consolidated financial statement disclosures.
Subsequent Events: The Company has evaluated subsequent events through February 18, 2010.
EQT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2009
2. Financial Information by Business Segment
Operating segments are revenue-producing components of the enterprise for which separate financial information is produced internally and are subject to evaluation by the Company’s chief operating decision maker in deciding how to allocate resources.
In January 2008, the Company announced a change in organizational structure to better align the Company to execute its growth strategy for development and infrastructure expansion in the Appalachian Basin. These changes resulted in changes to the Company’s reporting segments effective for fiscal year 2008.
The Company reports its operations in three segments, which reflect its lines of business. The EQT Production segment includes the Company’s exploration for, and development and production of, natural gas and a limited amount of crude oil in the Appalachian Basin. EQT Midstream’s operations include the natural gas gathering, processing, transportation and storage activities of the Company as well as sales of NGLs. Distribution’s operations primarily comprise the state-regulated distribution activities of the Company.
Operating segments are evaluated on their contribution to the Company’s consolidated results based on operating income, equity in earnings of nonconsolidated investments, and other income. Interest expense and income taxes are managed on a consolidated basis. Headquarters’ costs are billed to the operating segments based upon a fixed allocation of the headquarters’ annual operating budget. Differences between budget and actual headquarters’ expenses are not allocated to the operating segments.
Substantially all of the Company’s operating revenues, income from continuing operations and assets are generated or located in the United States.
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(a) Intersegment revenues primarily represent natural gas sales from EQT Production to EQT Midstream and transportation activities between EQT Midstream and Distribution.
(b) Unallocated (expenses) income consists primarily of incentive compensation and administrative costs that are not allocated to the operating segments.
(c) Expenditures for segment assets in the EQT Production segment include $31.0 million and $85.5 million for undeveloped property acquisitions in 2009 and 2008, respectively. Expenditures for segment assets for 2007 include $24.4 million and $3.7 million, in the EQT Production and EQT Midstream segments, respectively, for the acquisition of additional working interest and related gathering assets in the Roaring Fork area.
3. Derivative Instruments
The Company’s primary market risk exposure is the volatility of future prices for natural gas and natural gas liquids, which can affect the operating results of the Company primarily through the EQT Production and EQT Midstream segments. The Company’s overall objective in its commodity hedging program is to ensure an adequate level of return for the well development and infrastructure investments at these segments.
The Company uses non-leveraged derivative commodity instruments that are placed with major financial institutions whose creditworthiness is continually monitored to reduce the effect of this volatility. Futures contracts obligate the Company to buy or sell a designated commodity at a future date for a specified price and quantity at a specified location. Swap agreements involve payments to or receipts from counterparties based on the differential between a fixed and variable price for the commodity. Collar agreements require the counterparty to pay the Company if the index price falls below the floor price and the Company to pay the counterparty if the index price rises above the cap price. Put option contracts provide protection from dropping prices and require the counterparty to pay the Company if the index price falls below the contract price. The Company also engages in a limited number of basis swaps to protect earnings from undue exposure to the risk of geographic disparities in commodity prices and interest rate swaps to hedge exposure to interest rate fluctuations on short or long-term debt.
The Company recognizes all derivative instruments as either assets or liabilities at fair value. The accounting for the changes in fair value of the Company’s derivative instruments depends on the use of the derivative instruments. At contract inception, the Company designates its derivative instruments as hedging or trading activities. To the extent that a derivative instrument has been designated and qualifies as a cash flow hedge, the effective portion of the change in fair value of the derivative instrument is reported as a component of accumulated other comprehensive loss, net of tax, and is subsequently reclassified into earnings, in the same caption associated with the forecasted transaction, in the same period or periods during which the hedged forecasted transaction affects earnings. For derivative instruments that have not been designated as cash flow hedges, the change in fair value for the instrument is recognized in the Statements of Consolidated Income as operating revenues each period.
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DECEMBER 31, 2009
Exchange-traded instruments are generally settled with offsetting positions. Over the counter (OTC) arrangements require settlement in cash. Settlements of derivative commodity instruments are reported as a component of cash flows from operations in the accompanying Statements of Consolidated Cash Flows.
The various derivative commodity instruments used by the Company to hedge its exposure to variability in expected future cash flows associated with the fluctuations in the price of natural gas related to the Company’s forecasted sale of equity production and forecasted natural gas purchases and sales have been designated and qualify as cash flow hedges.
The Company assesses the effectiveness of hedging relationships, determined by the degree that the gain (loss) for the hedging instrument offsets the loss (gain) on the hedged item, both at the inception of the hedge and on an on-going basis. If the gain (loss) for the hedging instrument is greater than the loss (gain) on the hedged item, the ineffective portion of the cash flow hedge is immediately recognized in operating revenues in the Statements of Consolidated Income.
The Company also enters into a limited amount of energy trading contracts to leverage its assets and limit its exposure to shifts in market prices and has a limited amount of other derivative instruments not designated as hedges.
During 2008, the Company effectively settled certain derivative commodity hedges scheduled to mature during the period 2010 through 2013 by de-designating the hedges and entering into directly counteractive economic hedges. As of the date of de-designation of these hedges, the Company had recorded a loss, net of tax, in accumulated other comprehensive loss of approximately $11.4 million which will be recognized as part of the realized sales price in the Statements of Consolidated Income when the underlying physical transactions occur. The fair value of the offsetting positions not designated as hedges as of December 31, 2009 was a $68.4 million derivative liability and a $49.3 million derivative asset. During the first quarter of 2009, the Company terminated certain collar agreements scheduled to mature during the period 2010 through 2012. As of the date of termination of these hedges the Company had recorded a gain, net of tax, in accumulated other comprehensive income of approximately $5.1 million which will be recognized as part of the realized sales price in the Statements of Consolidated Income when the underlying physical transactions occur.
The current hedge position extends through 2015 and provides price protection for approximately 40%, 30% and 10% of expected natural gas production sales volumes in 2010, 2011 and 2012, respectively. See “Commodity Risk Management” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Form 10-K for further details of the Company’s hedged position.
All derivatives recognized in the balance sheet and used in cash flow hedging relationships are commodity contracts. All gains (losses) recognized in income or reclassified from accumulated other comprehensive income (OCI) into income are reported in operating revenues. All derivative instrument assets and liabilities are reported in the balance sheet as derivative instruments, at fair value. These derivative instruments are reported as either current assets or current liabilities due to their highly liquid nature. The Company can net settle its derivative instruments at any time.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2009
(a) Includes $5.1 million and $32.8 million for the years ended December 31, 2009 and 2008, respectively, of unrealized hedge gains reclassified into earnings to offset lower of cost or market adjustments on hedged items. The Company also had an immaterial amount of OCI reclassified to interest expense related to an interest rate swap on long-term debt.
(b) No amounts have been excluded from effectiveness testing.
The net fair value of derivative instruments changed during 2009 primarily as a result of the settlement of hedged transactions and a decrease in natural gas prices. The absolute quantities of the Company’s derivative commodity instruments that have been designated and qualify as cash flow hedges totaled 172 Bcf and 243 Bcf as of December 31, 2009 and December 31, 2008, respectively, and are primarily related to natural gas swaps and collars.
The Company deferred net gains (losses) of $15.6 million and ($28.8) million in accumulated other comprehensive income (loss), net of tax, as of December 31, 2009 and December 31, 2008, respectively, associated with the effective portion of the change in fair value of its derivative instruments designated as cash flow hedges. Assuming no change in price or new transactions, the Company estimates that approximately $4.2 million of net unrealized gains on its derivative commodity instruments reflected in accumulated other comprehensive income, net of tax, as of December 31, 2009 will be recognized in earnings during the next twelve months due to the settlement of hedged transactions. This recognition occurs through an increase in the Company’s net operating revenues resulting in the average hedged price becoming the realized sales price.
The Company is exposed to credit loss in the event of nonperformance by counterparties to derivative contracts. This credit exposure is limited to derivative contracts with a positive fair value. The Company believes that NYMEX-traded futures contracts have minimal credit risk because Commodity Futures Trading Commission regulations are in place to protect exchange participants, including the Company, from potential financial instability of the exchange members. The Company’s swap, collar and option derivative instruments are primarily with
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2009
financial institutions and thus are subject to events that would impact those companies individually as well as that industry as a whole.
The Company utilizes various processes and analysis to monitor and evaluate its credit risk exposures. This includes closely monitoring current market conditions, counterparty credit spreads and credit default swap rates. Credit exposure is controlled through credit approvals and limits. To manage the level of credit risk, the Company deals with financial counterparties that are of investment grade or better, enters into netting agreements whenever possible and may obtain collateral or other security.
When the net fair value of any of the Company’s swap agreements represents a liability to the Company which is in excess of the agreed-upon threshold between the Company and the financial institution acting as counterparty, the counterparty requires the Company to remit funds to the counterparty as a margin deposit for the derivative liability which is in excess of the threshold amount. The Company records these deposits as a current asset in the consolidated balance sheet. When the net fair value of any of the Company’s swap agreements represents an asset to the Company which is in excess of the agreed-upon threshold between the Company and the financial institution acting as counterparty, the Company requires the counterparty to remit funds as margin deposits in an amount equal to the portion of the derivative asset which is in excess of the threshold amount. The Company records a current liability for such amounts received. The Company had no such deposits in its Consolidated Balance Sheets as of December 31, 2009 and December 31, 2008.
When the Company enters into exchange-traded natural gas contracts, exchanges may require the Company to remit funds to the corresponding broker as good-faith deposits to guard against the risks associated with changing market conditions. Participants must make such deposits based on an established initial margin requirement as well as the net liability position, if any, of the fair value of the associated contracts. In the case where the fair value of such contracts is in a net asset position, the broker may remit funds to the Company, in which case the Company records a current liability for such amounts received. The initial margin requirements are established by the exchanges based on the price, volatility and time to expiration of the related contract and are subject to change at the exchanges’ discretion. The Company recorded a current liability of $6.9 million as of December 31, 2009 and a current asset of $4.4 million at December 31, 2008 for such deposits with brokers in its Consolidated Balance Sheets.
Certain of the Company's derivative instrument contracts provide that if the Company's credit ratings are lowered below investment grade, additional collateral must be deposited with the counterparty. This additional collateral can be up to 100% of the derivative liability. As of December 31, 2009, the aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a net liability position was $58.6 million, for which the Company had no collateral posted on December 31, 2009. If the Company’s credit rating had been downgraded below investment grade on December 31, 2009, the Company would have been required to post additional collateral of $30.0 million in respect of the liability position. Investment grade refers to the quality of the Company’s credit as assessed by one or more credit rating agencies. The Company’s unsecured medium-term debt was rated BBB by Standard & Poor’s Rating Services (S&P), Baa1 by Moody’s Investor Services (Moody’s) and BBB+ by Fitch Ratings Service (Fitch) at December 31, 2009. In order to be considered investment grade, the Company must be rated BBB- or higher by S&P and Fitch and Baa3 or higher by Moody’s. Anything below these ratings is considered non-investment grade.
4. Fair Value Measurements
The Company has an established process for determining fair value for its financial instruments, principally derivative commodity instruments and available-for-sale investments. Fair value is based on quoted market prices, where available. If quoted market prices are not available, fair value is based upon models that use as inputs market-based parameters, including but not limited to forward curves, discount rates, broker quotes, volatilities, and nonperformance risk. Nonperformance risk considers the effect of the Company’s credit standing on the fair value of liabilities and the effect of the counterparty’s credit standing on the fair value of assets. The Company estimates nonperformance risk by analyzing publicly available market information, including a comparison of the yield on debt instruments with credit ratings similar to the Company’s or counterparty’s credit rating and the yield of a risk free instrument and credit default swaps rates where applicable.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2009
The Company has categorized its financial instruments into a three-level fair value hierarchy, based on the priority of the inputs to the valuation technique. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets and liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Financial instruments included in Level 1 include the Company’s futures contracts and available-for-sale investments, while instruments included in Level 2 include the majority of the Company’s swap agreements, and instruments included in Level 3 include the Company’s collar and option agreements and a portion of the Company’s swap agreements. Since the adoption of fair value accounting, the Company has not made any changes to its classification of financial instruments in any category.
The fair value of financial instruments included in Level 2 is based on industry models that use significant observable inputs, including NYMEX forward curves and LIBOR-based discount rates. Swaps included in Level 3 are valued using internal models; these internal models are validated each period with non-binding broker price quotes. The Company has not experienced significant differences between internally calculated values and broker price quotes. Collars and options included in Level 3 are valued using internal models calculated with market derived volatilities. The Company uses NYMEX forward curves to value futures, NYMEX swaps, collars and options. The NYMEX forward curves are validated to external sources at least monthly.
The following assets and liabilities were measured at fair value on a recurring basis during the period:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2009
Gains and losses related to derivative commodity instruments included in earnings for the period are reported in operating revenues in the Statements of Consolidated Income. Any gains or losses related to available-for-sale securities are included as a separate component of income.
The estimated fair value of long-term debt on the Consolidated Balance Sheets at December 31, 2009 and December 31, 2008 was approximately $2 billion and $1 billion, respectively. The fair value was estimated based on the Company’s established fair value methodology based discounted values using a current discount rate reflective of the remaining maturity.
5. Sale of Properties
On April 13, 2007, the Company and Range Resources Corporation (Range) agreed to a development plan for the Nora area in Southwestern Virginia. The Company entered into a Purchase and Sale Agreement (Purchase Agreement) with Pine Mountain Oil and Gas, Inc. (PMOG), a subsidiary of Range, pursuant to which the Company agreed to sell to PMOG a portion of the Company’s interests in certain gas properties in the Nora area. During the remainder of 2007, the Company completed a majority of the transactions contemplated by the Purchase Agreement by selling proved reserves of approximately 74 Bcf, including proved developed reserves of approximately 67 Bcf, to PMOG for proceeds of $193.5 million after purchase price adjustments.
Additionally in 2007, the Company entered into a Contribution Agreement (Contribution Agreement) with PMOG relating to the contribution of certain Nora area gathering facilities and pipelines to Nora Gathering, LLC (Nora LLC), a newly formed entity that is equally owned by the Company and PMOG. This gathering system services production of the Company and Range. The Company contributed Nora area gathering property to Nora LLC in exchange for a 50% interest in Nora LLC and cash of $23.6 million. The Company accounts for its interest in and contribution to Nora LLC under the equity method of accounting, as the Company determined that it has the ability to exert significant influence over the operating and financial policies of Nora LLC through its 50%, non-controlling interest. The net book value of properties contributed to Nora LLC exceeded the value of cash and the interest received in Nora LLC by $3.1 million which the Company recorded as a loss on the contribution.
As a result of these transactions the Company recorded a net gain on the sale of assets of $126.1 million in the Statements of Consolidated Income for 2007. This net gain includes a gain on the sale of working interest in oil and gas properties under the Purchase Agreement of $157.6 million, a hedge loss of $28.4 million resulting from a
EQT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2009
7.3 Bcf reduction in the Company’s hedge position due to the sale of properties, and a loss of $3.1 million resulting from the contribution of gathering assets to Nora LLC under the Contribution Agreement.
The Company and Nora LLC also entered into a demand note agreement whereby Nora LLC loaned to the Company $69.8 million on the initial closing date. At December 31, 2008, the note was fully paid and cancelled.
6. Acquisitions
In September 2007, the Company purchased an additional working interest of approximately 13.5% in the Roaring Fork area in Virginia and certain gathering assets from a minority interest holder for $28.5 million subject to post-closing adjustments, which increased the Company’s working interest to approximately 97.0%. The additional working interest of 13.5% represented approximately 12.3 Bcf of reserves, consisting of approximately 10.1 Bcf of proved developed reserves and approximately 2.2 Bcf of proved undeveloped reserves. The purchase price was funded using a portion of the proceeds received from the sale described in Note 5, as this transaction qualified as a like-kind exchange under the Internal Revenue Code of 1986, as amended (IRC). The like-kind exchange did not impact the accounting for this transaction or the sale described in Note 5.
On March 1, 2006, the Company entered into an agreement to acquire Dominion Resources, Inc.’s (Dominion) natural gas distribution assets in Pennsylvania and in West Virginia for approximately $970 million, subject to adjustments, in a cash transaction for the stock of The Peoples Natural Gas Company and Hope Gas, Inc. In light of the continued delay in achieving the final legal approvals for this transaction, the Company and Dominion agreed to terminate the agreement pursuant to a mutual termination agreement entered into on January 15, 2008. As a result of this previously proposed transaction and its termination, the Company recognized a total of $21 million in expense, including $9.8 million of deferred acquisition costs and $0.3 million of impairment charges in the 2007 Statements of Consolidated Income.
7. Income Taxes
Income tax (benefit) expense is summarized as follows:
The current federal tax benefit results in prepaid income taxes of approximately $111.1 million which is included in prepaid expenses and other assets in the Consolidated Balance Sheet at December 31, 2009.
During the second quarter of 2009 EQT received a refund of $99.5 million from the Internal Revenue Service (IRS) relating to the 2008 net operating loss (NOL) carryback claim that was filed with the IRS on March 3, 2009. During the third quarter of 2009, the Company filed a superseding tax return for the 2008 tax year in which the Company requested an additional refund of $15.7 million relating to the carryback of its 2008 net operating tax loss. The Company received this refund in November of 2009.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2009
On November 6, 2009, the Worker, Homeownership, and Business Assistance Act of 2009 was signed into law. This law extended the applicability of the tax net operating loss carryback provision from 2 years to 5 years for either the 2008 or 2009 tax year. The Company will elect to carryback its 2009 tax net operating loss under this new law and estimates that it will receive a tax refund of approximately $115 million in the second quarter of 2010.
The Company was in an overall federal tax net operating loss position for 2008 and 2009 and expects to pay minimal federal income taxes for as long as the Company’s drilling program in Appalachia continues, unless tax laws change. For federal income tax purposes, the Company currently deducts approximately 75% of drilling costs as intangible drilling costs (IDC) in the year incurred. The primary reasons for the Company’s net operating loss are the IDC deduction resulting from the Company’s drilling program and the accelerated tax deprecation for expansion of the gathering infrastructure which provide tax deductions in excess of book deductions.
The qualified production activities deduction under Section 199 of the IRC, which provides for a phased-in deduction related to qualifying production activities, was provided for the first time under the American Jobs Creation Act of 2004. The Company recorded an income tax benefit for certain qualifying production activities of approximately $4.5 million in 2007. Due to the Company’s taxable loss position in 2008 and 2009 and the resulting net operating loss carryback, no Section 199 benefit was recorded for 2009 or 2008 and the prior years’ benefits were reversed. The reversal of the prior years’ Section 199 deduction was a detriment to the 2009 and 2008 effective tax rates in the amount of $2.1 million and $2.6 million, respectively.
Income tax expense differs from amounts computed at the federal statutory rate of 35% on pre-tax income from continuing operations as follows:
The Company’s effective tax rate for its continuing operations for the year ended December 31, 2009 was 38.1% compared to 37.7% for the year ended December 31, 2008. The higher tax rate in 2009 is primarily the result of nondeductible compensation expense partially offset by a regulatory asset recorded to recover deferred taxes caused by an accounting method change that deducts as repairs certain costs capitalized for financial accounting purposes. In addition, the Company recorded a tax benefit in 2008 for a change in the West Virginia state tax law that primarily provides for a reduction in the future corporate income tax rates which was partially offset by additional tax expense as a result of the completion of the IRS audit through the 2005 tax year.
Section 162(m) of the IRC disallows, with certain exceptions such as performance based compensation paid pursuant to a shareholder approved plan, a federal income tax deduction for annual compensation over $1 million paid to any covered employee. The covered employees are the principal executive officer and the three most highly-compensated officers other than the principal executive officer and the principal financial officer. During 2009, payments awarded under the 2009 Shareholder Value Plan were subject to this limitation which resulted in $8.9 million of tax expense.
During 2008, the Company applied for a change in accounting method that would allow current income tax deductions for certain repair costs that are capitalized for book purposes. However, the method request was a non-automatic change and required the consent of the IRS. During the fourth quarter of 2009 the Company received
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2009
consent from the IRS to change and reflected the change in the quarterly results. As a result of the tax treatment of certain accelerated deductions for regulatory purposes, the tax benefit of this deduction is passed along to the Company’s customers and will be collected in the future when the deferred taxes become current. Thus, the Company is required to record a regulatory asset to reflect the future recovery of these deferred taxes when the temporary differences reverse. Due to the establishment of the regulatory asset the overall tax expense decreased by $9.8 million in 2009 partially offset by other regulatory basis differences of approximately $0.5 million.
The effective tax rate for 2008 was 37.7% compared to 35.9% in 2007. The higher effective tax rate in 2008 is the result of several factors including the Company being in a net operating loss position for tax purposes in 2008 which resulted in the loss of certain deductions for 2008 and for prior years as a result of carrying losses back to receive a cash refund of taxes paid. In addition, state taxes increased due to limitations imposed on certain state tax losses generated in 2008 and the Company recorded a net increase to tax expense as a result of the completion of its IRS audit through the 2005 tax year, slightly offset by a beneficial change in the West Virginia state tax law that primarily provides for a reduction in the future corporate income tax rates.
During 2007, state income taxes increased as a result of a West Virginia law change enacted on April 4, 2007 that was slated to be effective for the Company’s tax year beginning January 1, 2009. This new law mandated unitary combined reporting, changed certain apportionment provisions for tax partnerships, changed certain definitions for financial organizations and made miscellaneous changes to other corporate net income tax statutes. As a result of this law change, the Company recorded additional tax expense of $3.3 million to reflect an overall increase in the Company’s expected deferred tax liability as of the effective date.
The other category does not include any items that are individually significant.
On January 1, 2007, the Company recognized a $4.1 million increase in the liability for unrecognized tax benefits which was accounted for as a reduction to the balance of retained earnings upon adoption of amendments to rules regarding accounting for unrecognized tax positions. Additionally, the Company recorded $29.7 million of unrecognized tax benefits related to a balance sheet reclassification that did not impact retained earnings. A total of $16.9 million of this reclassification related to the gross up of certain tax positions that were previously recorded net of tax benefit, tax positions which relate to temporary differences that were previously part of deferred taxes and tax positions that were previously offset against deferred tax assets. The remaining $12.8 million related to tax positions previously categorized as current liabilities. After the recognition of these items, the total liability for unrecognized tax benefits, inclusive of interest and penalties, at January 1, 2007 was $33.8 million.
The following table reconciles the beginning and ending amount of unrecognized tax benefits (excluding interest and penalties):
Included in the tabular reconciliation above at December 31, 2009, December 31, 2008 and December 31, 2007 are $29.5 million, $20.2 million and $18.1 million, respectively, for tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. Because of the impact of deferred tax accounting, other than interest and penalties, the disallowance of the shorter deductibility period would not affect the annual effective tax rate but would accelerate the payment of cash to the taxing authority to an earlier period.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2009
The Company recognizes interest and penalties accrued related to unrecognized tax benefits in income tax expense. During the year ended December 31, 2009, the Company recognized approximately $2.5 million of interest expense and for the year ended December 31, 2008, the Company reversed approximately $6.1 million of previously recorded interest expense. The Company recognized approximately $8.5 million of interest expense in 2007. Interest and penalty of $15.9 million, $13.4 million and $19.5 million is included in the balance sheet reserve at December 31, 2009, 2008 and 2007, respectively.
The total amount of unrecognized tax benefits, inclusive of interest and penalties, was $56.6 million, $47.6 million and $50.8 million as of December 31, 2009, 2008 and 2007, respectively. The total amount of unrecognized tax benefits (excluding interest and penalties) that, if recognized, would affect the effective tax rate was $8.9 million, $10.7 million and $11.1 million as of December 31, 2009, 2008 and 2007, respectively.
As of December 31, 2009, it is reasonably possible that the total amount of unrecognized tax benefits could decrease by up to $29.0 million within the next 12 months due to potential settlements with taxing authorities, legal or administrative guidance by relevant taxing authorities or the lapse of an applicable statute of limitation.
There were no material changes to the Company’s methodology for unrecognized tax benefits during 2009. Increases to the unrecognized tax benefit balance during 2009 were primarily attributable to certain changes in the Company’s accounting for repairs expenditures for tax purposes.
The consolidated federal income tax liability of the Company has been settled with the IRS through 2000. In December 2008, the Joint Committee on Taxation (JCT) approved the settlement of all issues related to the 1998 through 2000 audit. The Company received a final net tax refund of $4.6 million, including interest, for these years.
The IRS has completed its audit and review of the Company’s federal income tax filings for the 2001 through 2005 years and the Company has received approximately $3.0 million of the total expected $3.4 million refund relating to the agreed upon audit adjustments for these years. In September of 2009, the JCT approved the settlement of all issues related to the 2001 through 2005 audit excluding the Company’s research and experimentation (R&E) tax credits claimed for such years. The R&E credits have been referred to the Appeals Division of the IRS. The Company also is the subject of various state income tax examinations. The Company believes that it is appropriately reserved for any uncertain tax positions claimed during these periods.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2009
The following table summarizes the source and tax effects of temporary differences between financial reporting and tax bases of assets and liabilities.
The net deferred tax asset relating to the Company’s accumulated other comprehensive loss balance as of December 31, 2009 was comprised of a $9.6 million deferred liability related to the Company’s net unrealized gain from hedging transactions, a $2.2 million deferred tax liability related to the unrealized gain on available-for-sale securities, a $7.7 million deferred tax asset related to other post-retirement benefits and a $14.7 million deferred tax asset related to the Company’s pension plans. The net deferred tax asset relating to the Company’s accumulated other comprehensive loss balance as of December 31, 2008 was comprised of a $17.6 million deferred tax asset related to the Company’s net unrealized loss from hedging transactions, a $8.7 million deferred tax asset related to other post-retirement benefits, and a $17.4 million deferred tax asset related to the Company’s pension plans.
The Company expects a 2009 taxable loss that can be carried back to recover income taxes paid in the prior five tax years under the Worker, Homeownership, and Business Assistance Act of 2009. The Company anticipates that it will fully utilize its 2009 net operating loss generated in such carryback claim to obtain a refund of approximately $115 million. The Company also has a deferred tax asset related to the net operating loss carryforward created in 2008 that was not utilized in its net operating loss carryback for $2.2 million. The federal net operating loss carryforward period is 20 years and, if unused, the loss carryforward for 2008 will expire in 2028. The Company is subject to alternative minimum tax (AMT) primarily due to limitations on deductions for intangible drilling costs. AMT taxes may be carried forward indefinitely and are creditable against regular income tax. As a result of certain AMT preference items related to intangible drilling costs, the Company anticipates that it will generate an AMT credit in connection with its 2009 net operating loss carryback and recorded a deferred tax asset for AMT credits of $26.0 million.
The Company has recorded a deferred tax asset of $31.8 million, which is net of valuation allowances of $3.6 million, related to tax benefits from state net operating loss carryforwards with various expiration dates ranging from 2010 to 2029.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2009
An income tax benefit of approximately $1 million, $1 million and $18 million for the years ended December 31, 2009, 2008 and 2007, respectively, triggered by the exercise of nonqualified employee stock options and vesting of restricted share awards is reflected as an addition to common stockholders’ equity.
8. Equity in Nonconsolidated Investments
The Company has ownership interests in nonconsolidated investments that are accounted for under the equity method of accounting. The following table summarizes the equity in the nonconsolidated investments:
The Company’s ownership share of the earnings for 2009, 2008 and 2007 related to the total investments was $6.5 million, $5.7 million and $3.1 million, respectively.
EQT Midstream’s equity investment in Nora LLC represents a 50% ownership interest which was obtained through a series of transactions with PMOG by contributing Nora area gathering property in exchange for the ownership interest, as discussed in Note 5. EQT Midstream’s investment in Nora LLC totaled $143.8 million and $131.0 million as of December 31, 2009 and 2008, respectively. EQT Midstream made additional equity investments in Nora LLC of $6.4 million in 2009 and $29.0 million in 2008.
EQT Production’s equity investment in ANGT represents an ownership interest in natural gas producing properties located in the Appalachian Basin region of the United States. As of December 31, 2009, EQT Production’s investment in ANGT totaled $25.3 million while the Company’s total investment was $38.1 million. As of December 31, 2008, EQT Production’s investment in ANGT totaled $25.4 million, while the Company’s total investment was $38.2 million. The portion of the investment not held by EQT Production is intended to fund plugging and abandonment and other liabilities for which the Company self-insures. The Company did not make any additional equity investments in ANGT during 2009 or 2008. Despite the 1% ownership percentage in ANGT, the Company determined it is appropriate to use the equity method of accounting to account for ANGT’s activities because of the Company’s ability to exert significant influence over the operating and financial decisions of ANGT.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2009
The following tables summarize the unaudited condensed financial statements for nonconsolidated investments accounted for under the equity method of accounting for the periods noted:
Summarized Balance Sheets
Summarized Statements of Income
9. Investments, Available-For-Sale
As of December 31, 2009, the investments classified by the Company as available-for-sale consist of approximately $36.2 million of equity and bond funds intended to fund plugging and abandonment and other liabilities for which the Company self-insures.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2009
The fair market value of debt and equity securities was $7.8 million below cost as of December 31, 2008. The Company analyzed the decline in these investments based on the extent and duration of the impairment, nature of the underlying assets and the Company’s intent and ability to hold the investments. Based on this analysis, the Company concluded that the decline in the securities values was other than temporary and recorded the decline in value as other than temporary impairment of available-for-sale securities within the Statements of Consolidated Income. This impaired value is the new (adjusted) cost of these investments for purposes of future impairment and unrealized gain or loss determinations.
During 2009 and 2008, the Company purchased additional equity and bond funds with a cost basis totaling $3.0 million and $3.0 million, respectively. These investments are classified as available-for-sale in the Consolidated Balance Sheet.
10. Regulatory Assets
The following table summarizes the Company’s regulatory assets, net of amortization, as of December 31, 2009 and 2008. The Company believes that it will continue to be subject to rate regulation that will provide for the recovery of its regulatory assets.
The regulatory asset associated with deferred taxes primarily represents deferred income taxes recoverable through future rates once the taxes become current. The Company expects to recover the amortization of this asset through rates. At December 31, 2008, the deferred purchased gas costs regulatory asset was reduced by $10.3 million of unrealized gains on derivative contracts designated as cash flow hedges that would have been classified as other comprehensive income absent the probability of recovery through rates. There was no such reduction in the deferred purchased gas cost regulatory asset at December 31, 2009. Deferred purchased gas cost is included in prepaid expenses and other in the Consolidated Balance Sheets.
The Company amortizes post-retirement benefits other than pensions previously deferred as well as recognizing expenses for on-going post-retirement benefits other than pensions, which are subject to recovery in approved rates. The reduction in the Company’s regulatory asset for amortization of post-retirement benefits other
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DECEMBER 31, 2009
than pensions previously deferred was approximately $1.4 million for each of the years ended December 31, 2009 and 2008.
The Company recorded a regulatory asset of $7.3 million at December 31, 2009 and $8.9 million at December 31, 2008 for Equitrans, L.P.’s (Equitrans, the Company’s interstate pipeline affiliate) other post-retirement benefits. The Company believes the future recovery of the unfunded status of the Equitrans other post-retirement benefits is probable.
The following regulatory assets do not earn a return on investment: deferred taxes and other post-retirement benefits.
11. Short-Term Loans
On October 27, 2006, the Company entered into a $1.5 billion, five-year revolving credit agreement, which replaced the Company’s previous $1 billion, five-year revolving credit agreement. On December 15, 2006, the maturity date was extended to October 26, 2011 pursuant to its terms. Additionally, the Company may request two one-year extensions of the stated maturity date; however, these extensions require the approval of 51% of the lenders underwriting the credit facility. The revolving credit agreement may be used for working capital, capital expenditures, share repurchases and other purposes including support of a commercial paper program. Subject to certain terms and conditions, the Company may, on a one time basis, request that the lenders’ commitments be increased to an aggregate amount of up to $2.0 billion. Each lender in the facility may decide if it will increase its commitment.
The credit facility is underwritten by a syndicate of 15 financial institutions each of which is obligated to fund its pro-rata portion of any borrowings by the Company. Lehman Brothers Bank, FSB (Lehman) is one of the 15 financial institutions in the syndicate and had committed to make loans not exceeding $95 million under the facility. Lehman failed to fund its portion of all recent borrowings by the Company which effectively reduces the total amount available under the facility to $1,405 million.
The Company is not required to maintain compensating bank balances. The Company’s debt issuer credit ratings, as determined by S&P, Moody’s or Fitch on its non-credit-enhanced, senior unsecured long-term debt, determine the level of fees associated with its lines of credit in addition to the interest rate charged by the counterparties on any amounts borrowed against the lines of credit; the lower the Company’s debt credit rating, the higher the level of fees and borrowing rate.
As of December 31, 2009, the Company had outstanding under the revolving credit facility loans of $5.0 million and an irrevocable standby letter of credit of $24.4 million. As of December 31, 2008, the Company had outstanding short-term loans under the revolving credit facility of $319.9 million and an irrevocable standby letter of credit of $25.8 million. Commitment fees averaging approximately one-twelfth of one percent in 2009 and 2008 were paid to maintain credit availability under the revolving credit facility.
The weighted average interest rates for short-term loans outstanding as of December 31, 2009 and 2008 were 0.51% and 0.84%, respectively. The maximum amount of outstanding short-term loans at any time during the year was $448.9 million in 2009 and $620.0 million in 2008. The average daily balance of short-term loans outstanding over the course of the year was approximately $116.8 million and $199.6 million at weighted average annual interest rates of 0.73% and 3.47% during 2009 and 2008, respectively.
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DECEMBER 31, 2009
12. Long-Term Debt
The indentures and other agreements governing the Company’s indebtedness contain certain restrictive financial and operating covenants including covenants that restrict the Company’s ability to incur indebtedness, incur liens, enter into sale and leaseback transactions, complete acquisitions, merge, sell assets and perform certain other corporate actions. The covenants do not contain a rating trigger. Therefore, a change in Company’s debt rating would not trigger a default under the indentures and other agreements governing the Company’s indebtedness.
Aggregate maturities of long-term debt are zero in 2010, $6.0 million in 2011, $200.0 million in 2012, $10.0 million in 2013 and $5.0 million in 2014.
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DECEMBER 31, 2009
13. Pension and Other Post-retirement Benefit Plans
The following table sets forth the defined benefit pension and other post-retirement benefit plans’ funded status and amounts recognized for those plans in the Company’s Consolidated Balance Sheets:
The accumulated benefit obligation for all defined benefit pension plans was $63.8 million and $72.3 million at December 31, 2009 and 2008, respectively. The Company uses a December 31 measurement date for its defined benefit pension and other post-retirement plans.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2009
The Company’s costs related to its defined benefit pension and other post-retirement benefit plans were as follows:
Under the current Equitrans rate case settlement, the Company began amortization of post-retirement benefits other than pensions previously deferred as well as recognizing expenses for on-going post-retirement benefits other than pensions, which are now subject to recovery in the approved rates. Expenses recognized by the Company for amortization of post-retirement benefits other than pensions previously deferred and on-going post-retirement benefits other than pensions were approximately $1.4 million and $1.2 million, respectively, for the years ended December 31, 2009, 2008 and 2007.
The estimated net loss for the defined benefit pension plans that will be amortized from accumulated other comprehensive loss, net of tax, into net periodic benefit cost over the next fiscal year is $0.8 million. The estimated net loss and net prior service credit for the other post-retirement benefit plans that will be amortized from accumulated other comprehensive loss, net of tax, into net periodic benefit cost over the next fiscal year are $1.0 million and $(0.5) million.
The following weighted average assumptions were used to determine the benefit obligations for the Company’s defined benefit pension and other post-retirement benefit plans at December 31:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2009
The following weighted average assumptions were used to determine the net periodic benefit cost for the Company’s defined benefit pension and other post-retirement benefit plans for the years ended December 31:
The expected rate of return is established at the beginning of the fiscal year to which it relates based upon information available to the Company at that time, including the plans’ investment mix and the forecasted rates of return on the types of securities held. The Company considered the historical rates of return earned on plan assets, an expected return percentage by asset class based upon a survey of investment managers and the Company’s actual and targeted investment mix. Any differences between actual experience and assumed experience are deferred as an unrecognized actuarial gain or loss. The unrecognized actuarial gains or losses are amortized into the Company’s net periodic benefit cost. The expected rate of return determined as of January 1, 2010 is 8.0%. This assumption will be used to derive the Company’s 2010 net periodic benefit cost. The rate of compensation increase is not applicable in determining future benefit obligations as a result of plan design. Pension expense increases as the expected rate of return decreases or if the discount rate is lowered.
For measurement purposes, the annual rate of increase in the per capita cost of covered health care benefits in 2010 is 9.0% for both the Pre-65 and Post-65 medical charges. The rates were assumed to decrease gradually to ultimate rates of 5.0% in 2018.
Assumed health care cost trend rates have an 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:
The Company’s pension asset allocation at December 31, 2009 and 2008 and target allocation for 2010 by asset category are as follows:
The investment activities of the Company’s pension plan are supervised and monitored by the Benefits Investment Committee (BIC). The BIC reports to the Compensation Committee of the Board of Directors and is comprised of the Chief Financial Officer and other officers and employees of the Company. The BIC has developed
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2009
an investment strategy that focuses on asset allocation, diversification and quality guidelines. The investment goals of the BIC are to minimize high levels of risk at the total pension investment fund level. The BIC monitors the actual asset allocation on a quarterly basis and adjustments are made, as needed, to rebalance the assets within the prescribed target ranges. Comparative market and peer group benchmarks are utilized to ensure that each of the firm’s investment managers is performing satisfactorily.
The Company made cash contributions of approximately $11.6 million and $3.4 million to its pension plan during 2009 and 2008, respectively, as a result of the Kentucky West Virginia Gas Company LLC settlements described below as well as additional contributions to meet certain funding targets. The Company expects to make cash payments of at least $1.2 million related to its pensions during 2010, which will meet the 80% funding obligations on its remaining plans. Pension plan cash contributions are designed to at least meet requirements of the 80% funding level. The dollar amount of a cash contribution made in any particular year will vary as a result of gains or losses sustained by the Plan during the year due to market conditions. The Company does not expect these variations to have a significant affect on the financial position, results of operations or liquidity of the Company.
The following pension benefit payments, which reflect expected future service, are expected to be paid by the plan during each of the next five years and the five years thereafter: $6.9 million in 2010; $7.1 million in 2011; $6.6 million in 2012; $6.3 million in 2013; $6.4 million in 2014; and $26.2 million in the five years thereafter.
The following benefit payments for post-retirement benefits other than pensions, which reflect expected future service, are expected to be paid by the Company during each of the next five years and the five years thereafter: $4.4 million in 2010; $4.3 million in 2011; $4.1 million in 2012; $4.0 million in 2013; $3.9 million in 2014; and $17.0 million in the five years thereafter.
Expense recognized by the Company related to its 401(k) employee savings plans totaled $10.1 million in 2009, $8.8 million in 2008 and $6.5 million in 2007.
During 2008, the Company settled its pension obligations under a plan covering employees of the former Kentucky West Virginia Gas Company LLC (Kentucky West Virginia), an EQT subsidiary which merged into EQT Gathering LLC. The former Kentucky West Virginia employees transferred to EQT Gathering LLC or EQT Production Company. As a result of the settlement, the Company recognized settlement expense of approximately $9.0 million, comprised of $8.0 million for pension benefits and $1.0 for other post-retirement benefits, for an early retirement program. Under this settlement, the affected employees were provided the option either to roll over to the Company’s defined contribution plan the lump-sum value of their pension benefit or to receive an insured annuity benefit. The $9.0 million settlement expense was recorded as operating and maintenance expense included within operating expenses of the EQT Midstream business segment. As a result of this settlement, the Company’s projected benefit obligation decreased by approximately $3.9 million.
The Company adopted amendments to Financial Accounting Standards Board Accounting Standards Codification (FASB ASC) Topic 715, Compensation - Retirement Benefits effective December 31, 2009. The disclosures required by this guidance are intended to enhance the transparency surrounding the types of assets and associated risks in an employer’s defined benefit pension or other post-retirement plan. The new disclosures define fair value as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. The disclosure fair value hierarchy requires assets and liabilities measured at fair value to be categorized into one of three levels used in the valuation. Assets and liabilities are classified in their entirety based on the lowest level of input significant to the fair value measurement. The three levels are defined as follows:
Level 1 - Observable inputs based on quoted prices (unadjusted) in active markets for identical assets or liabilities.
Level 2 - Observable inputs, other than those included in Level 1, based on quoted prices for similar assets or liabilities in active markets or quoted prices for identical assets and liabilities in inactive markets.
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DECEMBER 31, 2009
Level 3 - Unobservable inputs that reflect an entity’s own assumptions about what inputs a market participant would use in pricing the asset or liability based on the best information available in the circumstances.
Investments in the plan assets include mutual funds totaling $19.9 million and $18.3 million, which are stated at fair value as of December 31, 2009 and December 31, 2008, respectively. These investments are based upon daily unadjusted quoted prices and therefore are considered Level 1.
Investments in the plan assets include common/collective trusts totaling $29.1 million and $22.5 million, which are stated at fair value as of December 31, 2009 and December 31, 2008, respectively. These investments are valued at current market value of the underlying assets of the fund and therefore are considered Level 2.
14. Common Stock and Earnings Per Share
At December 31, 2009, shares of EQT’s authorized and unissued common stock were reserved as follows:
Earnings Per Share
The computation of basic and diluted earnings per common share is shown in the table below:
(a)
Options to purchase 955,107, 6,480 and 7,298 shares of common stock were not included in the computation of diluted earnings per common share for 2009, 2008 and 2007, respectively, because the options’ exercise prices were greater than the average market prices of the common shares.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2009
15. Accumulated Other Comprehensive Loss
The components of accumulated other comprehensive loss, net of tax, are as follows:
16. Share-Based Compensation Plans
Share-based compensation expense (income) recorded by the Company was as follows:
The Company typically uses treasury stock to fund awards that are paid in stock. When an award has graduated vesting, the Company records the expense equal to the vesting percentage on the vesting date. A portion of the expense related to share-based compensation plans is included as an unallocated expense in deriving total operating income for segment reporting purposes. See Note 2.
Cash received from exercises under all share-based payment arrangements for employees and directors for the years ended December 31, 2009, 2008 and 2007, was $0.8 million, $0.9 million, and $3.2 million, respectively. The actual tax benefits realized for tax deductions, including excess tax benefits, from share-based payment arrangements which were paid in stock for the years ended December 31, 2009, 2008 and 2007, was $2.2 million, $2.2 million, and $19.4 million, respectively. For share-based payment arrangements paid in cash, the Company recognizes tax benefits at the effective tax rate, except as limited by Section 162(m) of the IRC as discussed in Note 7.
Executive Performance Incentive Programs
In February 2005, the Compensation Committee of the Board of Directors adopted the 2005 Executive Performance Incentive Program (2005 Program) under the 1999 Long-Term Incentive Plan. The 2005 Program was established to provide additional incentive benefits to retain executive officers and certain other employees of the Company in order to further align the interests of the persons primarily responsible for the success of the Company with the interests of the shareholders. The vesting of the stock units granted under the 2005 Program occurred on December 31, 2008, after the ordinary close of the performance period. The vesting resulted in approximately 1.9 million units (175% of the award) with a value of approximately $64 million being distributed in cash and stock on December 31, 2008. Greater than 90% of the award was distributed in cash. The Company accounted for these awards as liability awards and as such recorded compensation expense for the remeasurement of the fair value of the awards at the end of each
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2009
reporting period. The Company recorded a reversal of previously recorded compensation expense in 2008 primarily due to the reduction in the Company’s stock price during the year.
In 2008, the Compensation Committee of the Board of Directors adopted the 2008 Executive Performance Incentive Program (2008 Program) under the 1999 Long-Term Incentive Plan. The 2008 Program was established to provide additional long-term incentive opportunities to key executives to further align their interests with those of the Company’s shareholders and with the strategic objectives of the Company. A total of 68,860 units were granted and no additional units may be granted. The vesting of these units will occur upon payment after the end of the performance period at a payout multiple dependent upon the level of total shareholder return relative to a predefined peer group’s total shareholder return during the 3.5 year performance period. As a result, zero to approximately 210,000 units (reflecting a 300% payout multiple) may be distributed upon vesting. The Compensation Committee of the Board of Directors retained the discretion to reduce the payout multiple by a specified amount if the Company does not attain a specified revenue target. However, if the Company’s total shareholder return ranking is median or above, the payout multiple may not be decreased below 100%. Payment of awards is expected to be made in cash based on the price of the Company’s common stock at the end of the performance period, December 31, 2011. The Company accounts for these awards as liability awards and as such records compensation expense for the remeasurement of the fair value of the awards at the end of each reporting period. The Company continually monitors its stock price and performance in order to assess the impact on the ultimate payout under the 2008 Program. The Company’s current assumptions for the ultimate share price and payout multiple are $50 and 100% of the units awarded, respectively. As of December 31, 2009, approximately 59,000 units were outstanding under the 2008 Program. The 2008 Program expense is classified as selling, general and administrative expense in the Statements of Consolidated Income.
The peer companies for the 2008 Program are as follows:
Atlas Energy Resources, LLC
Markwest Energy Partners, L.P.
Sempra Energy
Cabot Oil & Gas Corp.
MDU Resources Group Inc.
Southern Union Co.
Chesapeake Energy Corp.
National Fuel Gas Co.
Southwestern Energy Co.
CNX Gas Corp.
ONEOK, Inc.
Spectra Energy Corp.
El Paso Corp.
Penn Virginia Corp.
TransCanada Corp.
Enbridge Inc.
Questar Corp.
The Williams Companies, Inc.
Energen Corp.
Range Resources Corp.
2009 Shareholder Value Plan
In December 2008, the Compensation Committee of the Board of Directors adopted the 2009 Shareholder Value Plan (SVP) under the 1999 Long-Term Incentive Plan. The SVP was established to ensure continued alignment with shareholders, to recognize the Company’s evolution from a diversified utility to an integrated energy company and to continue to encourage sustained high performance and shareholder return. The effective date of the SVP was January 1, 2009. The vesting of the stock units granted under the 2009 SVP occurred on December 31, 2009, after the ordinary close of the performance period. The vesting resulted in approximately 2.2 million units (225% of the award) with a value of approximately $45 million being distributed in cash on December 31, 2009. The Company accounted for these awards as liability awards and as such recorded compensation expense for the fair value of the awards at the end of each reporting period.
2007 Supply Long-Term Incentive Program
On July 1, 2007, the Compensation Committee of the Board of Directors established the 2007 Supply Long-Term Incentive Program (2007 Supply Program) to provide a long-term incentive compensation opportunity to key employees in the EQT Production and EQT Midstream segments. Awards granted may be earned by achieving pre-determined total sales and efficiency targets and by satisfying certain applicable employment requirements. The awards earned may be increased to a maximum of three times the initial award or reduced to zero based upon achievement of the predetermined performance levels. Payment of awards will be made in cash based on the price of the Company’s common stock at the end of the performance period, December 31, 2010. The Company accounts for these awards as liability awards and as
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2009
such records compensation expense for the remeasurement of the fair value of the awards at the end of each reporting period. In the first quarter of 2009, the Company granted approximately 116,000 of additional awards to key employees in the EQT Production and EQT Midstream segments. As of December 31, 2009 approximately 270,000 awards were outstanding under this program. In the fourth quarter of 2009, the Company increased its assumption for the payout multiple to approximately 290% of the units awarded. The assumption for the ultimate share price at the vesting date for the 2007 Supply Program is $45.00. Total compensation cost recorded for the 2007 Supply Program was $15.5 million for the year ended December 31, 2009, which included $6.8 million of cost capitalized as part of oil and gas-producing properties and $8.7 million recorded as expense in the Company’s Consolidated Statement of Income.
Restricted Stock Awards
The Company granted 62,340, 157,730 and 77,540 restricted stock awards during the years ended December 31, 2009, 2008 and 2007, respectively, to key employees of the Company. The majority of the shares granted will be fully vested at the end of the three-year period commencing with the date of grant. The weighted average fair value of these restricted stock grants, based on the grant date fair value of the Company’s stock, was approximately $33, $59, and $44 for the years ended December 31, 2009, 2008 and 2007, respectively. The total fair value of restricted stock awards vested during the years ended December 31, 2009, 2008, and 2007 was $6.0 million, $3.7 million, and $6.7 million, respectively.
As of December 31, 2009, there was $3.9 million of total unrecognized compensation cost related to nonvested restricted stock awards. That cost is expected to be recognized over a remaining weighted average vesting term of approximately 19 months.
A summary of restricted stock activity as of December 31, 2009, and changes during the year then ended, is presented below:
Non-Qualified Stock Options
The fair value of the Company’s option grants was estimated at the dates of grant using a Black-Scholes option-pricing model with the assumptions indicated in the table below for the years ended December 31, 2009, 2008 and 2007. The risk-free rate for periods within the contractual life of the option is based on the U.S. Treasury yield curve in effect at the time of grant. The dividend yield is based on the historical dividend yield of the Company’s stock. Expected volatilities are based on historical volatility of the Company’s stock. The expected term of options granted represents the period of time that options granted are expected to be outstanding based on historical option exercise experience.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2009
The Company granted 905,700 and 27,421 stock options during the years ended December 31, 2008 and 2007, respectively. All of the 2007 stock option grants were options granted for reload rights associated with previously-awarded options. The weighted average grant date fair value of the options was $10.32 and $7.33 for the years ended December 31, 2008 and 2007, respectively. The total intrinsic value of options exercised during the years ended December 31, 2009, 2008 and 2007 was $1.6 million, $2.3 million, and $47.6 million, respectively. No options were granted in 2009.
As of December 31, 2009, there was $4.4 million of total unrecognized compensation cost related to outstanding nonvested stock options.
A summary of option activity as of December 31, 2009, and changes during the year then ended, is presented below:
Non-employee Directors’ Share-Based Awards
At December 31, 2009, 78,800 options were outstanding and included in the table above under the 1999 Non-employee Directors’ Stock Incentive Plan at prices ranging from $7.66 to $19.56 per share. The exercise price for each award is equal to the market price of the Company’s common stock on the date of grant. Each option is subject to time-based vesting provisions and expires 5 to 10 years after date of grant. No options have been granted to non-employee directors since 2002 and all previously granted options are vested.
The Company has also historically granted to non-employee directors share-based awards which vest upon award. The value of the share-based awards will be paid in cash on the earlier of the director’s death or retirement from the Company’s Board of Directors. The Company accounts for these awards as liability awards and as such records compensation expense for the remeasurement of the fair value of the awards at the end of each reporting period. A total of 109,292 non-employee director share based awards were outstanding as of December 31, 2009. A total of 23,760, 12,800, and 15,570 share based awards were granted to non-employee directors during the years ended December 31, 2009, 2008 and 2007, respectively. The weighted average fair value of these grants, based on the grant date fair value of the Company’s stock, was $41.68, $68.22, and $49.88 for the years ended December 31, 2009, 2008 and 2007, respectively.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2009
Executive Performance Incentive Plan and 2010 Stock Incentive Award program
Effective January 1, 2010, the Compensation Committee of the Board of Directors adopted the 2010 Executive Performance Incentive Plan (2010 EPIP) and the 2010 Stock Incentive Award program (2010 SIA) under the 2009 Long-Term Incentive Plan. The 2010 EPIP and 2010 SIA were established to provide additional long-term incentive opportunities to key employees to further align their interests with those of the Company’s shareholders and with the strategic objectives of the Company. The effective date of the 2010 EPIP and 2010 SIA was January 1, 2010 and as such no compensation expense was recorded in 2009. A total of 142,440 units were granted under the 2010 EPIP and 155,850 awards were granted under the 2010 SIA.
The vesting of the units under the 2010 EPIP will occur upon payment after the end of the 3-year performance period. The payment will vary between zero and 300% of the number of units granted contingent upon a combination of the level of total shareholder return relative to a predefined peer group over the period January 1, 2010 through December 31, 2012 and the level of production sales revenues over the period January 1, 2010 through September 30, 2012. If earned, the 2010 EPIP units are expected to be distributed in Company common stock.
The vesting of the awards under the 2010 SIA will occur on the third anniversary of the grant date. The payment will vary between zero and 300% of the number of awards granted contingent upon adjusted 2010 earnings before interest, taxes, depreciation and amortization (EBITDA) performance as compared to plan and individual, business unit and Company value driver performance over the period January 1, 2010 through December 31, 2010. If earned, the 2010 SIA awards are expected to be distributed in Company common stock.
The Company has not recorded an obligation or expense related to the 2010 Executive Performance Incentive Program or the 2010 Stock Incentive Award program at December 31, 2009.
2010 Stock Options
In the first quarter of 2010, the Compensation Committee of the Board of Directors approved the grant of 332,300 non-qualified stock options to key employees of the Company. The 2010 options are seven-year options, with an exercise price of $43.92, and a vesting schedule as follows: 50% vest on December 31, 2010, 25% vest on December 31, 2011 and 25% vest on December 31, 2012, contingent upon continued employment with the Company on such dates. The Company has not recorded any obligation or expense related to 2010 Stock Options as of December 31, 2009.
17. Concentrations of Credit Risk
Revenues and related accounts receivable from the EQT Production segment’s operations are generated primarily from the sale of produced natural gas and limited amounts of crude oil to certain marketers, EQT Energy, LLC (an affiliate), other Appalachian Basin purchasers and utility and industrial customers located mainly in the Appalachian area. No customers accounted for more than 10% of revenues in 2009 or 2007. As of December 31, 2008, sales to one marketer accounted for approximately 13% of revenues for EQT Production. EQT Midstream’s gathering and processing revenues include the sale of produced NGLs to a gas processor in Kentucky and the gathering of natural gas in Kentucky, Virginia, Pennsylvania and West Virginia.
The transmission and storage operations of EQT Midstream include FERC regulated interstate pipeline transportation and storage service for the Distribution segment, as well as other utility and end user customers located in the northeastern United States. These operations also provide commodity procurement and delivery, physical natural gas management operations and control and customer support services to energy consumers including large industrial, utility, commercial, institutional and certain marketers primarily in the Appalachian and mid-Atlantic regions.
Distribution’s operating revenues and related accounts receivable are generated primarily from state-regulated distribution natural gas sales and transportation to approximately 275,900 residential, commercial and industrial
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2009
customers located in southwestern Pennsylvania, northern West Virginia and eastern Kentucky. Distribution continues to aggressively monitor and analyze various customer-related metrics and their impact on accounts receivable. The Company employs a firm collections strategy which is comprised of various collections tactics, including termination of service if necessary, as well as outreach to low income customers to provide information regarding energy assistance programs. The outreach to low income customers includes enrolling customers into the Customer Assistance Program which is an affordable payment plan for low income customers based on a percentage of total household income. This program is managed by the Company and recovered through rates charged to other residential customers.
Approximately 60% and 68% of the Company’s accounts receivable balance as of December 31, 2009 and 2008, respectively, represent amounts due from marketers. The Company manages the credit risk of sales to marketers by limiting its dealings to those marketers who meet the Company’s criteria for credit and liquidity strength and by proactively monitoring these accounts. The Company may require letters of credit, guarantees, performance bonds or other credit enhancements from a marketer in order for that marketer to meet the Company’s credit criteria. As a result, the Company did not experience any significant defaults on sales of natural gas to marketers during the years ended December 31, 2009, 2008 and 2007.
The Company is exposed to credit loss in the event of nonperformance by counterparties to derivative contracts. This credit exposure is limited to derivative contracts with a positive fair value. The Company believes that NYMEX-traded future contracts have minimal credit risk because Commodity Futures Trading Commission regulations are in place to protect exchange participants, including the Company, from any potential financial instability of the exchange members. The Company’s swap, collar and option derivative instruments are primarily with financial institutions and thus are subject to events that would impact those companies individually as well as that industry as a whole.
The Company utilizes various processes and analysis to monitor and evaluate its credit risk exposures. This includes closely monitoring current market conditions, counterparty credit spreads and credit default swap rates. Credit exposure is controlled through credit approvals and limits. To manage the level of credit risk, the Company deals with financial counterparties that are of investment grade or better, enters into netting agreements whenever possible and may obtain collateral or other security.
In September 2008, the credit support provider of one counterparty (Lehman Brothers) declared bankruptcy resulting in the default under various derivative contracts with the Company. As a result, those contracts were terminated and a reserve of approximately $5.0 million was recorded against the entire balance due to the Company. There is no additional income statement exposure to Lehman Brothers beyond the reserve recorded in 2008. As of December 31, 2009, the Company is not in default under any derivative contracts and has no knowledge of default by any other counterparty to derivative contracts. The Company will continue to monitor market conditions that may impact the fair value of derivative contracts reported in the Consolidated Balance Sheets.
18. Commitments and Contingencies
The Company has commitments for demand charges under existing long-term contracts and binding precedent agreements with various pipelines. Future payments for these items as of December 31, 2009 totaled $2,006.6 million (2010 - $49.9 million, 2011 - $66.6 million, 2012 - $158.2 million, 2013 - $139.8 million, 2014 - $138.7 million and thereafter - $1,453.4 million). The Company believes that approximately $19.5 million of the demand charges are recoverable in customer rates.
The Company has agreements with Highlands Drilling, LLC, Patterson UTI Drilling Company, LLC and other drilling contractors to provide drilling equipment and services to the Company. These obligations totaled approximately $35.3 million as of December 31, 2009. Operating lease rentals for drilling contractors, office locations (including the new corporate headquarters) and warehouse buildings, as well as a limited amount of equipment, amounted to approximately $62.3 million in 2009, $40.4 million in 2008 and $12.0 million in 2007. Future lease payments under non-cancelable operating leases as of December 31, 2009 totaled $171.6 million (2010 - $40.2 million, 2011 - $20.0 million, 2012 - $12.5 million, 2013 - $8.4 million, 2014 - $7.9 million and thereafter -
EQT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2009
$82.6 million). The Company has subleased two floors of its previous corporate headquarters building. The Company will receive future lease payments under the non-cancelable sublease totaling approximately $21.3 million (2010 - $1.0 million, 2011 - $1.4 million, 2012 - $1.4 million, 2013 - $1.4 million, 2014 - $1.4 million and thereafter - $14.7 million) as of December 31, 2009.
Several West Virginia lessors claimed in a suit filed on July 31, 2006 that EQT Production Company had underpaid royalties on gas produced and marketed from leases. The suit sought compensatory and punitive damages, an accounting and other relief. The plaintiffs later amended their complaint to name EQT as an additional defendant. The Company has settled the litigation. The settlement covers all of the Company’s lessors in West Virginia who have not opted out of the settlement class. The Court has entered an order preliminarily approving the settlement. A Formal Fairness Hearing was held on January 20, 2010. The Company is waiting for entry of an order giving final approval of the settlement. The Company believes the reserve established for this litigation is sufficient.
The Company is subject to various federal, state and local environmental and environmentally related laws and regulations. These laws and regulations, which are constantly changing, can require expenditures for remediation and may in certain instances result in assessment of fines. The Company has established procedures for ongoing evaluation of its operations to identify potential environmental exposures and to assure compliance with regulatory policies and procedures. The estimated costs associated with identified situations that require remedial action are accrued. However, certain costs are deferred as regulatory assets when recoverable through regulated rates. Ongoing expenditures for compliance with environmental laws and regulations, including investments in plant and facilities to meet environmental requirements, have not been material. Management believes that any such required expenditures will not be significantly different in either their nature or amount in the future and does not know of any environmental liabilities that will have a material affect on the Company’s financial position, results of operations or liquidity. The Company has identified situations that require remedial action for which approximately $1.3 million is included in other credits in the Consolidated Balance Sheet as of December 31, 2009.
In the ordinary course of business, various legal and regulatory claims and proceedings are pending or threatened against the Company. While the amounts claimed may be substantial, the Company is unable to predict with certainty the ultimate outcome of such claims and proceedings. The Company has established reserves it believes to be appropriate for pending matters and after consultation with counsel and giving appropriate consideration to available insurance, the Company believes that the ultimate outcome of any other matter currently pending against the Company will not materially affect the financial position, results of operations or liquidity of the Company.
19. Guarantees
NORESCO Guarantees
In connection with the sale of its NORESCO domestic operations in December 2005, the Company agreed to maintain in place guarantees of certain warranty obligations of NORESCO. The savings guarantees provided that once the energy-efficiency construction was completed by NORESCO, the customer would experience a certain dollar amount of energy savings over a period of years. The undiscounted maximum aggregate payments that may be due related to these guarantees is approximately $274 million as of December 31, 2009, extending at a decreasing amount for approximately 20 years. In addition, the Company agreed to maintain in place certain outstanding payment and performance bonds, letters of credit and other guarantee obligations supporting NORESCO’s obligations under certain customer contracts, existing leases and other items with an undiscounted maximum exposure to the Company as of December 31, 2009 of approximately $42 million, of which approximately $34 million relates to work already completed under the associated contracts. In addition, approximately $35 million of these guarantee obligations will end or be terminated not later than December 31, 2010.
In exchange for the Company’s agreement to maintain these guarantee obligations, the purchaser of the NORESCO business and NORESCO agreed, among other things, that NORESCO would fully perform its obligations under each underlying agreement and agreed to reimburse the Company for any loss under the guarantee
EQT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2009
obligations, provided that the purchaser’s reimbursement obligation will not exceed $6 million in the aggregate and will expire on November 18, 2014. In 2008, the original purchaser of NORESCO sold its interest in NORESCO and transferred its obligations to a third party. In connection with that event, the new owner delivered to the Company a $1 million letter of credit supporting its obligations.
The NORESCO guarantees are exempt from FASB ASC Topic 460, Guarantees. The Company has determined that the likelihood it will be required to perform on these arrangements is remote and any potential payments are expected to be immaterial to the Company’s financial position, results of operations and liquidity. As such, the Company has not recorded any liabilities in its Consolidated Balance Sheets related to these guarantees.
Other Guarantees
In November 1995, EQT, through a subsidiary, guaranteed a tax indemnification to the limited partners of Appalachian Basin Partners, LP (ABP) for any tax losses resulting from a disallowance of the nonconventional fuels tax credits, if certain representations and warranties of the Company were not true. The Company guaranteed the tax indemnification until the tax statute of limitations closes. The Company does not have any recourse provisions with third parties or any collateral held by third parties associated with this guarantee that could be liquidated to recover amounts paid, if any, under the guarantee. As of December 31, 2009, the maximum potential amount of future payments the Company could be required to make is estimated to be approximately $12 million. The Company has not recorded a liability for this guarantee and has not modified it subsequent to issuance. Additionally, based on the status of the Company’s IRS examinations, the Company has determined that the likelihood of loss from this guarantee is remote.
In December 2000, the Company entered into a transaction with ANGT by which an interest in natural gas producing properties located in the Appalachian Basin region of the United States was sold. ANGT manages the assets and produces, markets, and sells the related natural gas from the properties. Appalachian NPI, LLC (ANPI) contributed cash to ANGT. The assets of ANPI, including its interest in ANGT, collateralize ANPI’s debt.
The Company has a non-equity interest in a variable interest entity, Appalachian NPI, LLC (ANPI), in which EQT was not deemed to be the primary beneficiary. Thus, ANPI is not consolidated within the Company’s Consolidated Financial Statements. In determining the primary beneficiary, the Company estimated the expected losses and expected residual returns of ANPI under various scenarios in order to identify the party that would absorb the majority of the losses or benefit from the majority of the returns. The primary assumptions utilized in the scenarios included commodity price and production volumes. In June 2009, the FASB issued amendments to improve financial reporting by enterprises involved with variable interest entities. The amendments are effective as of the beginning of the first annual reporting period after November 15, 2009. These amendments will not have a material impact on the Company’s future consolidated financial statements. As of December 31, 2009, ANPI had $154 million of total assets and $144 million of total liabilities (including $85 million of long-term debt, including current maturities), excluding minority interest. ANPI is financed primarily through cash provided by operating activities.
The Company provided ANPI with a liquidity reserve guarantee secured by the fair market value of the assets purchased by ANGT. This guarantee is subject to certain restrictions that limit the amount of the guarantee to the calculated present value of the project’s future cash flows from the preceding year-end until the termination date of the agreement. The agreement also defines events of default, use of proceeds and demand procedures. The Company receives a market-based fee for providing the guarantee. As of December 31, 2009, the maximum amount of future payments the Company could be required to make under the liquidity reserve guarantee is estimated to be approximately $30 million. The Company has not recorded a liability for this guarantee and has not modified it subsequent to issuance. The terms of this guarantee require the Company to provide a letter of credit in favor of ANPI as security for its obligations under the liquidity reserve guarantee. The amount of the letter of credit outstanding at December 31, 2009 was approximately $24.4 million and is expected to decline over time under the terms of the liquidity reserve guarantee.
EQT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2009
20. Office Consolidation / Impairment Charges
In the third quarter of 2009, the Company completed the relocation of its corporate headquarters and other operations to downtown Pittsburgh. As a result of the relocation, the Company recorded an impairment charge of $5.2 million in selling, general and administrative expense in the Statements of Consolidated Income for 2009. This impairment related to the reduced usage of the operating lease for, and certain assets at, the Company’s previous headquarters facility located on Pittsburgh’s North Shore.
21. Interim Financial Information (Unaudited)
The following quarterly summary of operating results reflects variations due primarily to the seasonal nature of the Company’s distribution and storage businesses and volatility of natural commodity prices.
(a) The sum of the quarterly data in some cases may not equal the yearly total due to rounding.
EQT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2009
22. Natural Gas Producing Activities (Unaudited)
On December 31, 2009, the Company adopted the revisions to FASB ASC Topic 932, Extractive Activities - Oil and Gas (ASC 932) which aligned the reserve calculation and disclosure requirements of ASC 932 with the requirements of Securities and Exchange Commission (SEC) rule, Modernization of Oil and Gas Reporting, which the Company also adopted. The key revisions to ASC 932 include a change in the definition of proved undeveloped reserves to allow undeveloped locations to be recorded beyond one offset location where reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. The new rules also suggest that five years is a reasonable timeframe to develop existing proved undeveloped locations. In addition, the new rules require that year end proved reserve volumes be computed using an unweighted average price for sales of oil and gas on the first calendar day of each month during the year.
The supplementary information summarized below presents the results of natural gas and oil activities for the EQT Production segment in accordance with the successful efforts method of accounting for production activities.
Production Costs
The following table presents the costs incurred relating to natural gas and oil production activities (a):
(a)
Amounts exclude capital expenditures for facilities and information technology.
(b)
Amounts include capitalizable exploratory costs and exploration expense.
Results of Operations for Producing Activities
The following table presents the results of operations related to natural gas and oil production for the years ended December 31:
EQT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2009
Reserve Information
The information presented below represents estimates of proved natural gas and oil reserves prepared by Company engineers. The engineer primarily responsible for the technical aspects of the reserves audit received a bachelor’s degree in Engineering from the Pennsylvania State University and has ten years of experience in the oil and gas industry. To ensure that the reserves are materially accurate, management reviews the price, heat content conversion rate and cost assumptions used in the economic model to determine the reserves; production volumes are reconciled between the system used to calculate the reserves and other accounting/measurement systems; the reserve roll forward between prior year reserves and current year reserves is reviewed by senior management; and the estimates of proved natural gas and oil reserves are audited by the independent consulting firm of Ryder Scott Company L.P., who is hired by the Company’s management. Since 1937, Ryder Scott Company L.P. has evaluated oil and gas properties and independently certified petroleum reserves quantities in the United States and internationally.
Proved developed reserves represent only those reserves expected to be recovered from existing wells and support equipment. There were no differences between the internally prepared and externally audited estimates. Proved undeveloped reserves represent proved reserves expected to be recovered from new wells after substantial development costs are incurred. Ryder Scott Company L.P. reviewed 100 percent of the total net gas and liquid hydrocarbon reserves attributable to the Company’s interests as of December 31, 2009. Ryder Scott conducted a detailed, well by well, audit of the Company’s largest properties. This audit covered 80 percent of the Company’s proved reserves. Ryder Scott’s audit of the remaining 20% of the Company’s properties consisted of an audit of aggregated groups not exceeding 200 wells per group. The audit utilized the performance method and the analogy method. Where historical reserve or production data was definitive the performance method, which extrapolates historical data, was utilized. In other cases the analogy method, which calculates reserves based on correlations to comparable surrounding wells, was utilized. All of the Company’s proved reserves are in the United States.
EQT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2009
(a) One thousand Bbl equals approximately 6 MMcf.
The Company holds a 1% equity interest in Appalachian Natural Gas Trust (ANGT) which is accounted for under the equity method. The Company’s share of these reserves and the impact on the standard measure of discounted future cash flow is not considered material and therefore was excluded from the results presented herein. The Company’s 1% share of ANGT for 2009 is 101 MMcfe of produced volumes and 455 MMcfe of proved developed reserves.
The Company’s 2009 extensions, discoveries and other additions, resulting from extensions of the proved acreage of previously discovered reservoirs through additional drilling in periods subsequent to discovery, of 1,159 Bcfe exceeded the 2009 production of 104.9 Bcfe. Of this increase, approximately 715 Bcfe was attributable to drilling in 2009 that would have qualified as reserve extensions, discoveries and other additions under the previous SEC rules, including approximately 400 Bcfe related to offset locations from wells drilled in 2009. The remaining additions are attributable to the SEC’s expanded definition of proved reserves to include reserves based on reasonable certainty, partially offset by removing reserves that were previously recorded for future vertical wells.
During 2009, the Company recorded downward revisions of 94.8 Bcfe to the December 31, 2008 estimates of its reserves due to decreased prices and other revisions. The new SEC oil and gas reporting rule modified the definition of proved reserves as well as the price used in the calculation which resulted in approximately 55 Bcfe of the 94.8 Bcfe revision of previous estimates. The reserves were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2009 of $58.43 per Bbl, $4.046 per Dth for Columbia Gas Transmission Corp., $4.128 per Dth for Dominion Transmission, Inc., $3.909 per Dth for the East Tennessee Natural Gas Pipeline and $3.920 per Dth for the Tennessee LA 500 leg of Transcontinental Gas Pipe Line Corp. Absent the affect of the new SEC oil and gas reporting rule, the price impact would have been minimal as year end prices only decreased approximately $0.06 per Dth from 2008.
During 2008, the Company recorded downward revisions of 65.5 Bcfe to the December 31, 2007 estimates of its reserves due to decreased prices and other revisions. The reserves were computed using a $41.85 per Bbl price at December 31, 2008, the Columbia Gas Transmission Corp. 2008 year-end price of $6.095 per Dth, and the Dominion Transmission, Inc. 2008 year-end price of $6.225 per Dth. The Company’s 2008 extensions, discoveries and other additions, resulting from extensions of the proved acreage of previously discovered reservoirs through additional drilling in periods subsequent to discovery, of 584.9 Bcfe exceeded the 2008 production of 90.6 Bcfe.
During 2007, the Company sold to Pine Mountain Oil and Gas, Inc., a portion of the Company’s interests in certain gas properties in the Nora area totaling approximately 74 Bcf of proved reserves. Also during 2007, the Company purchased an additional working interest of approximately 13.5% in certain gas properties in the Roaring Fork area totaling 12.3 Bcf of proved reserves. During 2007, the Company recorded upward revisions of 9.1 Bcfe to the December 31, 2006 estimates of its reserves due to increased prices and other revisions. The reserves were
EQT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2009
computed using a $93.28 per Bbl price at December 31, 2007, the Columbia Gas Transmission Corp. 2007 year-end price of $7.030 per Dth, and the Dominion Transmission, Inc. 2007 year-end price of $7.200 per Dth. The Company’s 2007 extensions, discoveries and other additions, resulting from extensions of the proved acreage of previously discovered reservoirs through additional drilling in periods subsequent to discovery, of 321.0 Bcfe exceeded the 2007 production of 83.1 Bcfe.
As of December 31, 2009, the Company did not have any reserves that have been classified as proved undeveloped reserves for more than five years. As a result of the adoption of the new SEC oil and gas reporting rule, previously recorded reserves from vertical well locations were removed and replaced with new reserves from horizontal well locations. This aligns with the Company’s five-year drilling plan. Increases in proved undeveloped reserves were primarily due to the ability to add horizontal proved undeveloped location more than one offset location away from existing horizontals.
Standard Measure of Discounted Future Cash Flow
Management cautions that the standard measure of discounted future cash flows should not be viewed as an indication of the fair market value of natural gas and oil producing properties, nor of the future cash flows expected to be generated therefrom. The information presented does not give recognition to future changes in estimated reserves, selling prices or costs and has been discounted at a rate of 10%.
Estimated future net cash flows from natural gas and oil reserves are as follows at December 31:
(a) The majority of the Company’s production is sold through liquid trading points on interstate pipelines.
Accordingly, the price of gas on these pipelines was determined using the unweighted arithmetic average of the closing prices on the first day of each month during 2009 published in the applicable editions of Platts Gas Daily (Columbia Gas Transmission Corp.’s unweighted arithmetic average of the closing prices on the first day of each month during 2009 was $4.046 per Dth; Dominion Transmission, Inc.’s unweighted arithmetic average of the closing prices on the first day of each month during 2009 was $4.128 per Dth; East Tennessee Natural Gas Pipeline’s unweighted arithmetic average of the closing prices on the first day of each month during 2009 was $3.909 per Dth; and the Tennessee LA 500 leg of Transcontinental Gas Pipe Line Corp.’s unweighted arithmetic average of the closing prices on the first day of each month during 2009 was $3.920 per Dth ).
(b) The price of gas for 2008 and 2007 was determined using the year-end prices published in the December 31, 2008 and December 31, 2007 edition of Platts Gas Daily (Columbia Gas Transmission Corp. 2008 and 2007 year-end price was $6.095 per Dth and $7.030 per Dth, respectively; Dominion Transmission, Inc. 2008 and 2007 year-end price was $6.225 per Dth and $7.200 per Dth, respectively ).
Holding production and development costs constant, a change in price of $1 per Dth for natural gas and $10 per barrel for oil would result in a change in the December 31, 2009 discounted future net cash flows before income taxes of the Company’s proved reserves of approximately $1.3 billion and $6 million, respectively.
EQT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2009
Summary of changes in the standardized measure of discounted future net cash flows for the years ended December 31:
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Not Applicable.
Item 9A. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
Under the supervision and with the participation of management, including the Company’s Principal Executive Officer and Principal Financial Officer, an evaluation of the Company’s disclosure controls and procedures, as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (Exchange Act), was conducted as of the end of the period covered by this report. Based on that evaluation, the Principal Executive Officer and Principal Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of the end of the period covered by this report.
Changes in Internal Control over Financial Reporting
There were no changes in internal control over financial reporting (as such term is defined in Rule 13a-15(f) under the Exchange Act) that occurred during the fourth quarter of 2009 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
Management’s Report on Internal Control over Financial Reporting
The management of EQT is responsible for establishing and maintaining adequate internal control over financial reporting (as such term is defined in Exchange Act Rule 13a-15(f)). EQT’s internal control system is designed to provide reasonable assurance to the Company’s management and Board of Directors regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. All internal control systems, no matter how well designed, have inherent limitations. Accordingly, even effective controls can provide only reasonable assurance with respect to financial statement preparation and presentation.
EQT’s management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2009. In making this assessment, management 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 concluded that the Company maintained effective internal control over financial reporting as of December 31, 2009.
Ernst & Young LLP, the independent registered public accounting firm that audited the Company’s Consolidated Financial Statements, has issued an attestation report on the Company’s internal control over financial reporting. Ernst & Young’s attestation report on the Company’s internal control over financial reporting appears in Part II, Item 8 of this Annual report on Form 10-K and is incorporated by reference herein.
Item 9B. Other Information
Not Applicable.
PART III
Item 10. Directors, Executive Officers and Corporate Governance
The following information is incorporated herein by reference from the Company’s definitive proxy statement relating to the annual meeting of the shareholders to be held on April 21, 2010, which will be filed with the Commission within 120 days after the close of the Company’s fiscal year ended December 31, 2009:
· Information required by Item 401 of Regulation S-K with respect to directors is incorporated herein by reference from the sections captioned “Item No. 1 - Election of Directors,” “Nominees to Serve for a Three-Year Term Expiring in 2013”, “Directors Whose Terms Expire in 2012,” “Directors Whose Terms Expire in 2011” and “Corporate Governance and Board Matters” in the Company’s definitive proxy statement;
· Information required by Item 405 of Regulation S-K with respect to compliance with Section 16(a) of the Exchange Act is incorporated herein by reference from the section captioned “Stock Ownership - Section 16(a) Beneficial Ownership Reporting Compliance” in the Company’s definitive proxy statement;
· Information required by Item 407(d)(4) of Regulation S-K with respect to disclosure of the existence of the Company’s separately designated standing Audit Committee and the identification of the members of the Audit Committee is incorporated herein by reference from the section captioned “Corporate Governance and Board Matters - Meetings of the Board of Directors and Committee Membership-Audit Committee” in the Company’s definitive proxy statement; and
· Information required by Item 407(d)(5) of Regulation S-K with respect to disclosure of audit committee financial expert is incorporated herein by reference from the section captioned “Corporate Governance and Board Matters - Meetings of the Board of Directors and Committee Membership-Audit Committee” in the Company’s definitive proxy statement.
Information required by Item 401 of Regulation S-K with respect to executive officers is included after Item 4 at the end of Part I of this Form 10-K under the heading “Executive Officers of the Registrant (as of February 18, 2010),” and is incorporated herein by reference.
The Company has adopted a code of ethics applicable to all directors and employees, including the principal executive officer, principal financial officer and principal accounting officer. The code of ethics is posted on the Company’s website, http://www.eqt.com (accessible under the “Corporate Governance” caption of the Investor page) and a printed copy will be delivered free of charge on request by writing to the corporate secretary at EQT Corporation, c/o Corporate Secretary, 625 Liberty Avenue, Pittsburgh, Pennsylvania 15222. The Company intends to satisfy the disclosure requirement regarding certain amendments to, or waivers from, provisions of its code of ethics by posting such information on the Company’s website.
Item 11. Executive Compensation
The following information is incorporated herein by reference from the Company’s definitive proxy statement relating to the annual meeting of the shareholders to be held on April 21, 2010, which will be filed with the Commission within 120 days after the close of the Company’s fiscal year ended December 31, 2009:
· Information required by Item 402 of Regulation S-K with respect to executive and director compensation is incorporated herein by reference from the sections captioned “Corporate Governance and Board Matters - Compensation Programs and Risk Management,” “Executive Compensation” and “Directors’ Compensation” in the Company’s definitive proxy statement; and
· Information required by paragraphs (e)(4) and (e)(5) of Item 407 of Regulation S-K with respect to certain matters related to the Compensation Committee is incorporated herein by reference from the sections captioned “Corporate Governance and Board Matters - Compensation Committee Interlocks and Insider Participation” and “Report of the Compensation Committee” in the Company’s definitive proxy statement.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Information required by Item 403 of Regulation S-K with respect to stock ownership of significant shareholders, directors and executive officers is incorporated herein by reference to the section captioned “Stock Ownership - Significant Shareholders” and “Stock Ownership - Stock Ownership of Directors and Executive Officers” in the Company’s definitive proxy statement relating to the annual meeting of shareholders to be held on April 21, 2010, which will be filed with the Commission within 120 days after the close of the Company’s fiscal year ended December 31, 2009.
The following table provides information as of December 31, 2009 with respect to shares of the company’s common stock that may be issued under the company’s existing equity compensation plans, including the 2009 Long-Term Incentive Plan (2009 LTIP), the 1999 Long-Term Incentive Plan (1999 LTIP), the 1999 Non-Employee Directors’ Stock Incentive Plan (1999 NEDSIP), the Directors’ Deferred Compensation Plan, the 2005 Directors’ Deferred Compensation Plan and the 2008 Employee Stock Purchase Plan (2008 ESPP).
(1) Includes the 2009 LTIP including deferred stock units and dividends reinvestments thereon; the 1999 LTIP including performance share awards under the 2008 Executive Performance Incentive Program, and dividend reinvestments thereon; the 1999 NEDSIP including the deferred stock units and dividend reinvestments thereon; and the 2008 ESPP. The 1999 LTIP was originally approved by shareholders on May 26, 1999 and was reapproved by shareholders on April 14, 2004. A May 17, 2001 amendment to the 1999 LTIP increased the shares available for awards by 5,000,000 without shareholder approval as then permitted by the rules of the New York Stock Exchange; as a consequence those shares may not be used for incentive stock options.
(2) Includes shares issuable under the Directors’ Deferred Compensation Plan and the 2005 Directors Deferred Compensation Plan (collectively, the Director Deferral Plans). The Director Deferral Plans are described below.
(3) Does not include shares subject to purchase at December 31, 2009 under the 2008 ESPP.
(4) The weighted-average exercise price is calculated solely based upon outstanding stock options and excludes deferred stock units under the 1999 NEDSIP and 2009 LTIP and performance awards under the 2008 EPIP.
(5) 933,913 shares remain available for issuance under the 2008 ESPP and no shares were subject to purchase at December 31, 2009.
(6) Shares issuable under the Director Deferral Plans consist of: (a) 40,624 shares issuable in connection with a 1999 deferred stock grant payable in common stock of EQT Corporation and including dividends thereon, and (b) 25,671 shares representing fees deferred by directors and including dividends thereon.
2005 Directors’ Deferred Compensation Plan
The 2005 Directors’ Deferred Compensation Plan was adopted by the Compensation Committee of the Board of Directors, effective January 1, 2005. The plan has been amended to allow the plan to continue into 2006 and thereafter and to comply with the documentation requirements of Section 409A of the Internal Revenue Code. Neither the original adoption of the plan nor its amendments required approval by shareholders. The plan allows non-employee directors to defer all or a portion of their directors’ fees and retainer. Amounts deferred are payable upon retirement from the Board unless an early payment is authorized after the director suffers an unforeseeable financial emergency. In addition to deferred directors’ fees and retainers, the deferred stock units granted to directors on or after January 1, 2005 under the 1999 Non-Employee Directors’ Stock Incentive Plan and the 2009 Long-Term Incentive Plan are administered under this plan.
Directors’ Deferred Compensation Plan
The Directors’ Deferred Compensation Plan was suspended as of December 31, 2004. After December 31, 2004, the Directors’ Deferred Compensation Plan continues to operate for the sole purpose of administering vested amounts deferred under the plan on or prior to December 31, 2004. Deferred amounts are generally payable upon retirement from the Board, but may be payable earlier if an early payment is authorized after a director suffers an unforeseeable financial emergency. In addition to deferred directors’ fees and retainers and the one-time grant of deferred shares in 1999, the deferred stock units granted to directors and vested prior to January 1, 2005 under the 1999 Non-Employee Directors’ Stock Incentive Plan are administered under this plan.
Item 13. Certain Relationships and Related Transactions, and Director Independence
Information required by Items 404 and 407(a) of Regulation S-K is incorporated herein by reference to the sections captioned “Corporate Governance and Board Matters - Director Independence” and “Corporate Governance and Board Matters - Certain Relationships and Related Transactions” in the Company’s definitive proxy statement relating to the annual meeting of shareholders to be held on April 21, 2010, which will be filed with the Commission within 120 days after the close of the Company’s fiscal year ended December 31, 2009.
Item 14. Principal Accounting Fees and Services
Information required by Item 9(e) of Schedule 14A is incorporated herein by reference to the section captioned “Item No. 2 - Ratification of Appointment of Independent Registered Public Accounting Firm” in the Company’s definitive proxy statement relating to the annual meeting of stockholders to be held on April 21, 2010, which will be filed with the Commission within 120 days after the close of the Company’s fiscal year ended December 31, 2009.
PART IV
Item 15. Exhibits and Financial Statement Schedules
(a)
1.
Financial Statements
The financial statements listed in the accompanying index to financial statements are filed as part of this Annual Report on Form 10-K.
2.
Financial Statement Schedule
The financial statement schedule listed in the accompanying index to financial statements and financial schedule is filed as part of this Annual Report on Form 10-K.
3.
Exhibits
The exhibits listed on the accompanying index to exhibits (pages 114 through 121) are filed as part of this Annual Report on Form 10-K.
EQT CORPORATION
INDEX TO FINANCIAL STATEMENTS COVERED
BY REPORT OF INDEPENDENT REGISTERED
PUBLIC ACCOUNTING FIRM
Item 15 (a)
1. The following Consolidated Financial Statements of EQT Corporation and Subsidiaries are included in Item 8:
Page Reference
Statements of Consolidated Income for each of the three years in the period ended
December 31, 2009
Statements of Consolidated Cash Flows for each of the three years in the period ended
December 31, 2009
Consolidated Balance Sheets as of December 31, 2009 and 2008
Statements of Consolidated Common Stockholders’ Equity for each of the three years in the period ended
December 31, 2009
Notes to Consolidated Financial Statements
2. Schedule for the Years Ended December 31, 2009, 2008 and 2007 included in Part IV:
II - Valuation and Qualifying Accounts and Reserves
All other schedules are omitted since the subject matter thereof is either not present or is not present in amounts sufficient to require submission of the schedules.
EQT CORPORATION AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE THREE YEARS ENDED DECEMBER 31, 2009
Note:
(a) For allowance for doubtful accounts, amount represents CAP surcharge included in residential rates. The inventory valuation allowance represents a lower of cost or market adjustment. For hedged inventory the Company reclassifies unrealized hedge gains deferred in accumulated other comprehensive income into earnings in the same period as the lower of cost or market adjustment. As such, the recording of the inventory valuation allowance had an immaterial impact to the Company’s 2009, 2008 and 2007 earnings.
(b) For allowance for doubtful accounts, amount represents customer accounts written off, less recoveries. For inventory valuation allowance, amount represents a reversal of lower of cost or market adjustments previously recorded on inventory sold in the period.
INDEX TO EXHIBITS
Exhibits
Description
Method of Filing
2.01
Stock Purchase Agreement dated as of March 1, 2006 between the Company and Dominion Resources, Inc. (as successor by merger to Consolidated Natural Gas Company). Schedules (or similar attachments) to the Stock Purchase Agreement are not filed. The Registrant will furnish supplementally a copy of any omitted schedule to the Commission upon request.
Filed as Exhibit 2.1 to Form 8-K filed on March 3, 2006
2.02
Letter agreement dated as of July 3, 2007 between the Company and Dominion Resources, Inc. (as successor by merger to Consolidated Natural Gas Company)
Filed as Exhibit 2.1 to Form 10-Q for the quarter ended June 30, 2007
2.03
Mutual Termination Agreement dated as of January 15, 2008 between the Company and Dominion Resources, Inc. (as successor by merger to Consolidated Natural Gas Company)
Filed as Exhibit 10.1 to Form 8-K filed on January 17, 2008
3.01
Restated Articles of Incorporation of EQT Corporation (amended through February 9, 2009)
Filed as Exhibit 3.1 to Form 8-K filed on February 9, 2009
3.02
By-Laws of EQT Corporation (amended through February 9, 2009)
Filed as Exhibit 3.2 to Form 8-K filed on February 9, 2009
4.01(a)
Indenture dated as of April 1, 1983 between the Company and Pittsburgh National Bank
Filed as Exhibit 4.1(a) to Form 10-K for the year ended December 31, 2009
4.01(b)
Instrument appointing Bankers Trust Company as successor trustee to Pittsburgh National Bank
Filed as Exhibit 4.01(b) to Form 10-K for the year ended December 31, 1998
4.01(c)
Supplemental Indenture dated as of March 15, 1991 with Bankers Trust Company eliminating limitations on liens and additional funded debt
Filed as Exhibit 4.01(f) to Form 10-K for the year ended December 31, 1996
4.01(d)
Resolution adopted August 19, 1991 by the Ad Hoc Finance Committee of the Board of Directors of the Company Addenda Nos. 1 through 27, establishing the terms and provisions of the Series A Medium-Term Notes
Filed as Exhibit 4.01(g) to Form 10-K for the year ended December 31, 1996
4.01(e)
Resolutions adopted July 6, 1992 and February 19, 1993 by the Ad Hoc Finance Committee of the Board of Directors of the Company and Addenda Nos. 1 through 8, establishing the terms and provisions of the Series B Medium-Term Notes
Filed as Exhibit 4.01(h) to Form 10-K for the year ended December 31, 1997
Each management contract and compensatory arrangement in which any director or any named executive officer participates has been marked with an asterisk (*)
INDEX TO EXHIBITS
Exhibits
Description
Method of Filing
4.01(f)
Resolution adopted July 14, 1994 by the Ad Hoc Finance Committee of the Board of Directors of the Company and Addenda Nos. 1 and 2, establishing the terms and provisions of the Series C Medium-Term Notes
Filed as Exhibit 4.01(i) to Form 10-K for the year ended December 31, 1995
4.01(g)
Supplemental Indenture dated as of June 30, 2008 between the Company and Deutsche Bank Trust Company Americas
Field as Exhibit 4.01(g) to Form 8-K filed on July 1, 2008
4.02(a)
Indenture with The Bank of New York, as successor to Bank of Montreal Trust Company, as Trustee, dated as of July 1, 1996
Filed as Exhibit 4.01(a) to Form S-4 Registration Statement (#333-103178) filed on February 13, 2003
4.02(b)
Resolution adopted January 18 and July 18, 1996 by the Board of Directors of the Company and Resolutions adopted July 18, 1996 by the Executive Committee of the Board of Directors of the Company, establishing the terms and provisions of the 7.75% Debentures issued July 29, 1996
Filed as Exhibit 4.01(j) to Form 10-K for the year ended December 31, 1996
4.02(c)
Officer’s Declaration dated as of February 20, 2003 establishing the terms of the issuance and sale of the Notes of the Company in an aggregate amount of up to $200,000,000
Filed as Exhibit 4.01(c) to Form S-4 Registration Statement (#333-104392) filed on April 8, 2003
4.02(d)
Officer’s Declaration dated as of November 7, 2002 establishing the terms of the issuance and sale of the Notes of the Company in an aggregate amount of up to $200,000,000
Filed as Exhibit 4.01(c) to Form S-4/A Registration Statement (#333-103178) filed on March 12, 2003
4.02(e)
Officer’s Declaration dated as of September 27, 2005 establishing the terms of the issuance and sale of the Notes of the Company in an aggregate amount of $150,000,000
Filed as Exhibit 4.01(b) to Form S-4 Registration Statement (#333-104392) filed on October 28, 2005
4.02(f)
Supplemental Indenture dated as of June 30, 2008 between the Company and The Bank of New York
Filed as Exhibit 4.02(f) to Form 8-K filed on July 1, 2008
4.03(a)
Indenture dated as of March 18, 2008 between the Company and The Bank of New York
Filed as Exhibit 4.1 to Form 8-K filed on March 18, 2008
4.03(b)
First Supplemental Indenture (including the form of senior note) dated as of March 18, 2008 between the Company and The Bank of New York, as Trustee, pursuant to which the 6.5% Senior Notes due 2018 were issued
Filed as Exhibit 4.2 to Form 8-K filed on March 18, 2008
4.03(c)
Second Supplemental Indenture dated as of June 30, 2008 between the Company and The Bank of New York
Filed as Exhibit 4.03(c) to Form 8-K filed on July 1, 2008
Each management contract and compensatory arrangement in which any director or any named executive officer participates has been marked with an asterisk (*)
INDEX TO EXHIBITS
Exhibits
Description
Method of Filing
4.03(d)
Third Supplemental Indenture dated as of May 15, 2009 between the Company and The Bank of New York
Filed as Exhibit 4.1 to Form 8-K filed on May 15, 2009
* 10.01(a)
1999 Long-Term Incentive Plan (amended and restated December 2, 2009)
Filed herewith as Exhibit 10.01(a)
* 10.01(b)
Form of Participant Award Agreement (Restricted Stock) under 1999 Long-Term Incentive Plan (Pre 2007)
Filed as Exhibit 10.05 to Form 10-K for the year ended December 31,
* 10.01(c)
Form of Participant Award Agreement (Restricted Stock) under 1999 Long-Term Incentive Plan (2007 and later)
Filed as Exhibit 10.01(b) to Form 10-K for the year ended December 31, 2006
* 10.01(d)
Form of Participant Award Agreement (Stock Option) under 1999 Long-Term Incentive Plan (Pre-2007)
Filed as Exhibit 10.3 to Form 10-Q for the quarter ended September 30, 2004
* 10.01(e)
Form of Participant Award Agreement (Stock Option) under the 1999 Long-Term Incentive Plan (post 2007)
Filed as Exhibit 10.3 to Form 10-Q for the quarter ended September 30, 2008
* 10.01(f)
2005 Executive Performance Incentive Program
Filed as Exhibit 10.5 to Form 10-Q for the quarter ended March 31,
* 10.01(g)
Form of Participant Award Agreement under the 2005 Executive Performance Incentive Program
Filed as Exhibit 10.02 to Form 8-K filed on March 1, 2005
* 10.01(h)
Supply Long-Term Incentive Program (as amended and restated March 5, 2009)
Filed as Exhibit 10.4 to Form 10-Q for the quarter ended March 31,
* 10.01(i)
Form of Participant Award Agreement under the 2007 Supply Long-Term Incentive Program
Filed as Exhibit 10.01(i) to Form 10-K for the year ended December 31, 2008
* 10.01(j)
Executive Performance Incentive Program
Filed as Exhibit 10.6 to Form 10-Q for the quarter ended March 31,
* 10.01(k)
Form of Participant Award Agreement under the 2008 Executive Performance Incentive Program
Filed as Exhibit 10.2 to Form 10-Q for the quarter ended September 30, 2008
* 10.01(l)
Shareholder Value Plan
Filed as Exhibit 10.7 to Form 10-Q for the quarter ended March 31,
* 10.01(m)
Form of Participant Award Agreement under the 2009 Shareholder Value Plan
Filed as Exhibit 10.01(m) to Form 10-K for the year ended December 31, 2008
* 10.01(n)
Long-Term Incentive Plan (as amended and restated December 2, 2009)
Filed herewith as Exhibit 10.01(n)
* 10.01(o)
Form of Participant Award Agreement (Phantom Stock Unit Awards) under 2009 Long-Term Incentive Plan
Filed as Exhibit 10.1 to Form 10-Q for the quarter ended September 30, 2009
Each management contract and compensatory arrangement in which any director or any named executive officer participates has been marked with an asterisk (*)
INDEX TO EXHIBITS
Exhibits
Description
Method of Filing
* 10.01(p)
Form of Participant Award Agreement (Restricted Stock) under 2009 Long-Term Incentive Plan
Filed as Exhibit 10.3 to Form 10-Q for the quarter ended June 30,
* 10.01(q)
Form of Participant Award Agreement (Stock Option) under 2009 Long-Term Incentive Plan
Filed as Exhibit 10.3 to Form 8-K filed on April 28, 2009
* 10.01(r)
2010 Executive Performance Incentive Program
Filed herewith as Exhibit 10.01(r)
* 10.01(s)
Form of Participant Award Agreement under the 2010 Executive Performance Incentive Program
Filed herewith as Exhibit 10.01(s)
* 10.01(t)
Form of 2010 Stock Incentive Award Agreement
Filed herewith as Exhibit 10.01(t)
* 10.02(a)
Non-Employee Directors’ Stock Incentive Plan (as amended and restated December 3, 2008)
Filed as Exhibit 10.02(a) to Form 10-K for the year ended December 31, 2008
* 10.02(b)
Form of Participant Award Agreement (Stock Option) under 1999 Non-Employee Directors’ Stock Incentive Plan
Filed as Exhibit 10.04(b) to Form 10-K for the year ended December 31, 2006
* 10.02(c)
Form of Participant Award Agreement (Phantom Units Award) under 1999 Non-Employee Directors’ Stock Incentive Plan
Filed as Exhibit 10.04(c) to Form 10-K for the year ended December 31, 2006
* 10.03
Executive Short-Term Incentive Plan (as amended and restated December 3, 2008)
Filed as Exhibit 10.03 to Form 10-K for the year ended December 31,
* 10.04
Payroll Deduction and Contribution Program (as amended and restated December 3, 2008)
Filed as Exhibit 10.9 to Form 10-Q for the quarter ended March 31,
* 10.05
Directors’ Deferred Compensation Plan (as amended and restated May 15, 2003)
Filed as Exhibit 10.10 to Form 10-Q for the quarter ended June 30,
* 10.06
Directors’ Deferred Compensation Plan (as amended and restated December 2, 2009)
Filed herewith as Exhibit 10.06
* 10.7(a)
Agreement dated as of September 23, 2008 with Murry S. Gerber
Filed as Exhibit 10.4 to Form 10-Q for the quarter ended September 30, 2008
* 10.7(b)
Confidentiality, Non-Solicitation and Non-Competition Agreement dated as of September 8, 2008 between the Company and Murry S. Gerber
Filed as Exhibit 10.5 to Form 10-Q for the quarter ended September 30, 2008
* 10.7(c)
Change of Control Agreement dated as of September 8, 2008 between the Company and Murry S. Gerber
Filed as Exhibit 10.6 to Form 10-Q for the quarter ended September 30, 2008
Each management contract and compensatory arrangement in which any director or any named executive officer participates has been marked with an asterisk (*)
INDEX TO EXHIBITS
Exhibits
Description
Method of Filing
* 10.8(a)
Agreement dated as of September 23, 2008 with David L. Porges
Filed as Exhibit 10.7 to Form 10-Q for the quarter ended September 30, 2008
* 10.8(b)
Confidentiality, Non-Solicitation and Non-Competition Agreement dated as of September 8, 2008 between the Company and David L. Porges
Filed as Exhibit 10.8 to Form 10-Q for the quarter ended September 30, 2008
* 10.8(c)
Change of Control Agreement dated as of September 8, 2008 between the Company and David L. Porges
Filed as Exhibit 10.9 to Form 10-Q for the quarter ended September 30, 2008
* 10.9(a)
Confidentiality, Non-Solicitation and Non-Competition Agreement dated as of September 8, 2008 between the Company and Philip P. Conti
Filed as Exhibit 10.10 to Form 10-Q for the quarter ended September 30, 2008
* 10.9(b)
Change of Control Agreement dated as of September 8, 2008 between the Company and Philip P. Conti
Filed as Exhibit 10.11 to Form 10-Q for the quarter ended September 30, 2008
* 10.10(a)
Confidentiality, Non-Solicitation and Non-Competition Agreement dated as of September 8, 2008 between the Company and Theresa Z. Bone
Filed as Exhibit 10.11(a) to Form 10-K for the year ended December 31, 2008
* 10.10(b)
Change of Control Agreement dated as of September 8, 2008 between the Company and Theresa Z. Bone
Filed as Exhibit 10.11(b) to Form 10-K for the year ended December 31, 2008
* 10.11(a)
Confidentiality, Non-Solicitation and Non-Competition Agreement dated as of September 8, 2008 between the Company and Randall L. Crawford
Filed as Exhibit 10.12 to Form 10-Q for the quarter ended September 30, 2008
* 10.11(b)
Change of Control Agreement dated as of September 8, 2008 between the Company and Randall L. Crawford
Filed as Exhibit 10.13 to Form 10-Q for the quarter ended September 30, 2008
* 10.11(c)
Form of Randall L. Crawford Participant Award Agreement under 2007 Supply Long-Term Incentive Program.
Filed herewith as Exhibit 10.11(c)
* 10.12(a)
Confidentiality, Non-Solicitation and Non-Competition Agreement dated as of September 8, 2008 between the Company and Lewis B. Gardner
Filed as Exhibit 10.13(a) to Form 10-K for the year ended December 31, 2008
* 10.12(b)
Change of Control Agreement dated as of September 8, 2008 between the Company and Lewis B. Gardner
Filed as Exhibit 10.13(b) to Form 10-K for the year ended December 31, 2008
Each management contract and compensatory arrangement in which any director or any named executive officer participates has been marked with an asterisk (*)
INDEX TO EXHIBITS
Exhibits
Description
Method of Filing
* 10.13
Employment Agreement dated as of October 31, 2008 between the Company and Joseph E. O’Brien.
Filed as Exhibit 10.1 to Form 8-K filed on November 6, 2008
* 10.14
Employment Agreement dated as of March 14, 2008 between the Company and Johanna G. O’Loughlin
Filed as Exhibit 10.1 to Form 8-K filed on March 20, 2008
* 10.15(a)
Confidentiality, Non-Solicitation and Non-Competition Agreement dated as of September 8, 2008 between the Company and Steven T. Schlotterbeck
Filed as Exhibit 10.16(a) to Form 10-K for the year ended December 31, 2008
* 10.15(b)
Change of Control Agreement dated as of September 8, 2008 between the Company and Steven T. Schlotterbeck
Filed as Exhibit 10.16(b) to Form 10-K for the year ended December 31, 2008
* 10.15(c)
Horizontal Drilling Special Grant Award Letters dated as of May 17, 2006 and August 22, 2008 between the Company and Steven T. Schlotterbeck
Filed as Exhibit 10.13 for Form 10-Q for the quarter ended March 31,
* 10.16(a)
Agreement dated as of May 24, 1996 with Phyllis A. Domm for deferred payment of 1996 director fees beginning May 24, 1996
Filed as Exhibit 10.14(a) to Form 10-K for the year ended December 31, 1996
* 10.16(b)
Agreement dated as of November 27, 1996 with Phyllis A. Domm for deferred payment of 1997 director fees
Filed as Exhibit 10.14(b) to Form 10-K for the year ended December 31, 1996
* 10.16(c)
Agreement dated as of November 30, 1997 with Phyllis A. Domm for deferred payment of 1998 director fees
Filed as Exhibit 10.14(c) to Form 10-K for the year ended December 31, 1997
* 10.16(d)
Agreement dated as of December 5, 1998 with Phyllis A. Domm for deferred payment of 1999 director fees
Filed as Exhibit 10.20(d) to Form 10-K for the year ended December 31, 1998
* 10.17
Form of Indemnification Agreement between the Company and all executive officers and outside directors
Filed as Exhibit 10.18 to Form 10-K for the year ended December 31,
* 10.18
Directors’ Compensation
Filed herewith as Exhibit 10.18
10.19(a)
Revolving Credit Agreement, dated as of October 27, 2006, among the Company, Bank of America, N.A., as Administrative Agent, Swing Line Lender and a Letter of Credit Issuer, JPMorgan Chase Bank, N.A., as Syndication Agent and a Letter of Credit Issuer, The Bank of Tokyo-Mitsubishi UFJ, Ltd., Houston Agency, Citibank, N.A., and PNC Bank, National Association, as Co-Documentation Agents, and other lender parties thereto.
Filed as Exhibit 10.15 to Form 10-Q for the quarter ended March 31,
Each management contract and compensatory arrangement in which any director or any named executive officer participates has been marked with an asterisk (*)
INDEX TO EXHIBITS
Exhibits
Description
Method of Filing
10.19(b)
Assignment and Assumption Agreement and Amendment to Credit Agreement, among Equitable Resources, Inc., a Pennsylvania corporation formed in 1926, Equitable Resources, Inc., a Pennsylvania corporation formed in 2008 and Bank of America, N.A.
Filed as Exhibit 10.23(b) to Form 8-K filed on July 1, 2008
10.20
Purchase and Sale Agreement dated as of April 13, 2007 between EQT Production Company and Pine Mountain Oil and Gas, Inc.
Filed as Exhibit 10.1 to Form 10-Q for the quarter ended June 30,
10.21
Contribution Agreement dated as of April 13, 2007 between EQT Production Company and Pine Mountain Oil and Gas, Inc.
Filed as Exhibit 10.2 to Form 10-Q for the quarter ended June 30,
10.22
Agreement and Plan of Merger
Filed as Exhibit 10.24(a) to Form 8-K filed on July 1, 2008
10.23
Assignment and Assumption Agreement (for Benefit Plans)
Filed as Exhibit 10.24(b) to Form 8-K filed on July 1, 2008
10.24
Master Assignment, Assumption and Acknowledgment Agreement
Filed as Exhibit 10.24(c) to Form 8-K filed on July 1, 2008
Schedule of Subsidiaries
Filed herewith as Exhibit 21
23.01
Consent of Independent Registered Public Accounting Firm
Filed herewith as Exhibit 23.01
23.02
Consent of Independent Petroleum Engineers
Filed herewith as Exhibit 23.02
31.1
Rule 13(a)-14(a) Certification of Principal Executive Officer
Filed herewith as Exhibit 31.1
31.2
Rule 13(a)-14(a) Certification of Principal Financial Officer
Filed herewith as Exhibit 31.2
Section 1350 Certification of Principal Executive Officer and Principal Financial Officer
Filed herewith as Exhibit 32
99.01
Independent Petroleum Engineers’ Audit Report
Filed herewith as Exhibit 99.01
**101
Interactive Data File
Filed herewith as Exhibit 101
The Company agrees to furnish to the Commission, upon request, copies of instruments with respect to long-term debt, which have not previously been filed.
Each management contract and compensatory arrangement in which any director or any named executive officer participates has been marked with an asterisk (*)
In accordance with Rule 406T of Regulation S-T promulgated by the Securities and Exchange Commission, Exhibit 101 is deemed not filed or part of a registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act of 1933, is deemed not filed for purposes of section 18 of the Securities Exchange Act of 1934, and otherwise is not subject to liability under these sections. (**)
SIGNATURES
Pursuant to the requirements of Section 13 or 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.
EQT CORPORATION
By:
/s/ MURRY S. GERBER
Murry S. Gerber
Chairman and Chief Executive Officer
February 17,
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.
/s/ MURRY S. GERBER
Chairman and
February 17,
Murry S. Gerber
Chief Executive Officer
(Principal Executive Officer)
/s/ PHILIP P. CONTI
Senior Vice President
February 17,
Philip P. Conti
and Chief Financial Officer
(Principal Financial Officer)
/s/ THERESA Z. BONE
Vice President
February 17,
Theresa Z. Bone
and Corporate Controller
(Principal Accounting Officer)
/s/ VICKY A. BAILEY
Director
February 17,
Vicky A. Bailey
/s/ PHILIP G. BEHRMAN
Director
February 17,
Philip G. Behrman
/s/ A. BRAY CARY, JR.
Director
February 17,
A. Bray Cary, Jr.
/s/ BARBARA S. JEREMIAH
Director
February 17,
Barbara S. Jeremiah
/s/ GEORGE L. MILES, JR.
Director
February 17,
George L. Miles, Jr.
/s/ DAVID L. PORGES
President,
February 17,
David L. Porges
Chief Operating Officer
and Director
/s/ JAMES E. ROHR
Director
February 17,
James E. Rohr
/s/ DAVID S. SHAPIRA
Director
February 17,
David S. Shapira
/s/ LEE T. TODD, JR.
Director
February 17,
Lee T. Todd, Jr.
/s/ JAMES W. WHALEN
Director
February 17,
James W. Whalen