QUESTAR CORP
ITEM 1. BUSINESS.
Nature of Business
Questar Corporation (Questar or the Company) is a natural gas-focused energy company with five major lines of business - gas and oil exploration and production, midstream field services, energy marketing, interstate gas transportation, and retail gas distribution - which are conducted through its three principal subsidiaries:
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Questar Market Resources, Inc. (Market Resources) is a subholding company that operates through four principal subsidiaries. Questar Exploration and Production Company (Questar E&P) acquires, explores for, develops and produces natural gas, oil and NGL. Wexpro Company (Wexpro) manages, develops and produces cost-of-service reserves for gas utility affiliate Questar Gas. Questar Gas Management Company (Gas Management) provides midstream field services including natural gas-gathering and processing services for affiliates and third parties. Questar Energy Trading Company (Energy Trading) markets equity and third-party natural gas and oil, provides risk-management services and owns and operates an underground gas-storage reservoir.
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Questar Pipeline Company (Questar Pipeline) provides interstate natural gas transportation and storage and other energy services.
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Questar Gas Company (Questar Gas) provides retail natural gas distribution services in Utah, Wyoming and Idaho.
Questar operates in the Rocky Mountain and Midcontinent regions of the United States of America and is headquartered in Salt Lake City, Utah. Shares of Questar common stock trade on the New York Stock Exchange (NYSE:STR).
Questar is a holding company, as that term is defined in the Public Utility Holding Company Act of 2005 (PUHCA 2005), because its subsidiary Questar Gas is a natural gas utility company. Questar, however, has an exemption and waiver from provisions of the Act applicable to holding companies. Questar conducts all operations through subsidiaries. The parent holding company performs certain management, legal, tax, administrative and other services for its subsidiaries.
The corporate-organization structure and major subsidiaries are summarized below:
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See Note 15 to the consolidated financial statements included in Item 8 of Part II of this Annual Report for financial information by line of business including, but not limited to, revenues from unaffiliated customers, operating income and identifiable assets. A discussion of each of the Company's lines of business follows.
EXPLORATION AND PRODUCTION - Questar E&P and Wexpro
General: Questar's exploration and production business is conducted through Questar E&P and Wexpro. Questar E&P and Wexpro generated approximately 64% of the Company's operating income in 2009. Questar E&P operates in two core areas - the Rocky Mountain region of Wyoming, Utah, Colorado and North Dakota and the Midcontinent region of Oklahoma, Texas and Louisiana. Questar E&P has a large inventory of identified development drilling locations, primarily on the Pinedale Anticline in western Wyoming and in northwestern Louisiana. Questar E&P continues to conduct exploratory drilling to determine the commerciality of its inventory of undeveloped leaseholds. Questar E&P seeks to acquire, develop and produce natural gas and oil from so-called "resource plays" in its core areas. Resource plays are characterized by continuous, aerially extensive hydrocarbon accumulations in tight sand, shale and coal reservoirs. Since the existence and distribution of hydrocarbons in resource plays is well understood, development of these accumulations has lower exploration risk than conventional discrete hydrocarbon accumulations. Resource plays typically require many wells, drilled at high density, to fully develop and produce. Development of resource play accumulations requires expertise in drilling large numbers of complex, highly deviated or horizontal development wells to depths in excess of 13,000 feet and application of advanced well stimulation techniques including hydraulic fracture stimulation to achieve economic production. Questar E&P seeks to maintain geographical and geological diversity with its two core areas. Questar E&P has in the past and may in the future pursue acquisition of producing properties through the purchase of assets or corporate entities to expand its presence in its core areas or create a new core area.
Questar E&P reported 2,746.9 Bcfe of estimated proved reserves as of December 31, 2009. Approximately 60% of Questar E&P's proved reserves, or 1,646.4 Bcfe, were located in the Rocky Mountain region of the United States, while the remaining 40%, or 1,100.5 Bcfe, were located in the Midcontinent region. Approximately 1,342.8 Bcfe of the proved reserves reported by Questar E&P at year-end 2009 were developed, while 1,404.1 Bcfe were categorized as proved undeveloped. Natural gas comprised about 92% of Questar E&P's total proved reserves at year-end 2009. The SEC amended its definitions of oil and natural gas reserves effective December 31, 2009. Key revisions impacting the Company include a change in the pricing used in estimating reserves to a 12-month average of the first-day-of-the month prices, reserve category definitional changes and allowing the application of reliable technologies in determining proved reserves. See Item 2 of Part I and Note 17 to the consolidated financial statements included in Item 8 of Part II of this Annual Report for more information on the Company's proved reserves.
Wexpro manages, develops and produces cost-of-service reserves for gas utility affiliate Questar Gas under the terms of the Wexpro Agreement, a long-standing comprehensive agreement with the states of Utah and Wyoming. Pursuant to the Wexpro Agreement, Wexpro recovers its costs and receives an unlevered, after-tax return of approximately 19-20% on its investment base. Wexpro's investment base is its investment in commercial wells and related facilities adjusted for working capital and reduced for deferred income taxes and depreciation. The term of the Wexpro Agreement coincides with the productive life of the gas and oil properties covered therein. Wexpro's investment base totaled $431.9 million at December 31, 2009. See Note 11 to the consolidated financial statements included in Item 8 of Part II of this Annual Report for more information on the Wexpro Agreement.
Wexpro delivers natural gas production to Questar Gas at a price equal to Wexpro's cost-of-service. Cost-of-service gas satisfied 51% of Questar Gas supply requirements during 2009. Wexpro sells crude-oil production from certain oil-producing properties at market prices with the revenues used to recover operating expenses and to provide Wexpro a return on its investment. Any operating income remaining after recovery of expenses and Wexpro's return on investment is divided between Wexpro and Questar Gas, with Wexpro retaining 46%.
Wexpro's cost-of-service operations are contractually limited to a finite set of properties set forth in the Wexpro Agreement. Advances in technology (increased density drilling and multi-stage hydraulic fracture stimulation) have identified significant unexploited potential on many of the subject properties. Wexpro has identified over $1 billion of additional drilling opportunities that could support high single-digit to low double-digit growth in revenues and net income over the next five to ten years while delivering cost-of-service natural gas supplies to Questar Gas at prices competitive with alternative sources.
Competition and Customers: Questar E&P faces competition in every part of its business, including the acquisition of producing properties and leasehold acreage, the marketing of gas and oil, and obtaining goods, services and labor. Its longer-term growth strategy depends, in part, on its ability to purchase reasonably-priced reserves and develop them in a low-cost and efficient manner.
Questar E&P, both directly and through Energy Trading, sells natural gas production to a variety of customers, including gas-marketing firms, industrial users and local-distribution companies. However, Questar E&P and Energy Trading do not sell natural
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gas to Questar Gas. Questar E&P regularly evaluates counterparty credit and may require financial guarantees from parties that fail to meet its credit criteria.
In 2009, 93% of Wexpro's revenues were from affiliated companies, primarily Questar Gas.
Regulation: Questar E&P and Wexpro operations are subject to various government controls and regulation at the federal, state and local levels. Questar E&P must obtain permits to drill and produce; maintain bonding requirements to drill and operate wells; submit and implement spill-prevention plans; and file notices relating to the presence, use, and release of specified contaminants incidental to gas and oil production. Questar E&P is also subject to various conservation matters, including the regulation of the size of drilling and spacing units, the number of wells that may be drilled in a unit and the unitization or pooling of gas and oil properties. Wexpro gas- and oil-development and production activities are subject to the same type of regulation as Questar E&P. In addition, the Utah Division of Public Utilities has oversight responsibility and retains an outside reservoir-engineering consultant and a financial auditor to assess the prudence of Wexpro's activities.
Most Questar E&P leasehold acreage in the Rocky Mountain area is held under leases granted by the federal government and administered by federal agencies, principally the Bureau of Land Management (BLM). Current federal regulations restrict activities during certain times of the year on significant portions of Questar E&P leasehold due to wildlife activity and/or habitat. Questar E&P has worked with federal and state officials in Wyoming to obtain authorization for limited winter-drilling activities on the Pinedale Anticline and has developed measures, such as drilling multiple wells from a single pad location, to minimize the impact of its activities on wildlife and wildlife habitat. Various wildlife species inhabit Questar E&P leaseholds at Pinedale and in other areas. The presence of wildlife, including species that are protected under the federal Endangered Species Act could limit access to leases held by Questar E&P on public lands.
In September 2008, the BLM issued a Record of Decision (ROD) on the Final Supplemental Environmental Impact Statement (FSEIS) for long-term development of natural gas resources in the Pinedale Anticline Project Area (PAPA). Under the ROD, Questar E&P and Wexpro are allowed to drill and complete wells year-round in one of five Concentrated Development Areas defined in the PAPA. The ROD contains additional requirements and restrictions on development of the PAPA.
MIDSTREAM FIELD SERVICES - Questar Gas Management
General: Gas Management generated approximately 13% of the Company's operating income in 2009. Gas Management owns 78% of Rendezvous Gas Services, LLC, (Rendezvous), a partnership that operates gas-gathering facilities in western Wyoming. Rendezvous gathers natural gas for Pinedale Anticline and Jonah field producers for delivery to various interstate pipelines. Gas Management also owns 38% of Uintah Basin Field Services, LLC (Field Services) and 50% of Three Rivers Gathering, LLC (Three Rivers) partnerships that operate gas-gathering facilities in eastern Utah. The FERC-regulated Rendezvous Pipeline Co., LLC (Rendezvous Pipeline), a wholly owned subsidiary of Gas Management, operates a 21-mile 20-inch-diameter pipeline between Gas Management's Blacks Fork gas-processing plant and the Muddy Creek compressor station owned by Kern River Gas Transmission Co. (Kern River Pipeline).
Fee-based gathering and processing revenues were 81% of Gas Management's net operating revenues (revenues less plant shrink) during 2009. Approximately 42% of Gas Management's 2009 net gas-processing revenues (processing revenues less plant shrink) were derived from fee-based processing agreements. The remaining revenues were derived from keep-whole processing agreements. A keep-whole contract exposes Gas Management to frac-spread risk while a fee-based contract eliminates commodity price exposure. To further reduce volatility associated with keep-whole contracts, Gas Management may enter into forward-sales contracts for NGL or hedge NGL prices and equivalent gas volumes with the intent to lock in a processing margin. Under a contract with Questar Gas, Gas Management also gathers cost-of-service volumes produced from properties operated by Wexpro.
In 2009, 10% of Gas Management's revenues were from affiliated companies, primarily Questar Gas.
Competition and Customers: Gas Management provides natural gas-gathering and processing services to affiliates and third-party producers who have proved and/or producing gas fields in the Rocky Mountain region. Most of Gas Management's gas-gathering and processing services are provided under long-term agreements.
ENERGY MARKETING - Questar Energy Trading
General: Energy Trading markets natural gas, oil and NGL and generated approximately 1% of the Company's operating income in 2009. It includes Questar E&P production and gas volumes purchased from third parties to build a flexible and reliable portfolio. As a wholesale marketing entity, Energy Trading concentrates on markets in the Rocky Mountains, Pacific Northwest and Midcontinent that are either close to affiliate reserves and production or accessible by major pipelines. Energy Trading contracts for firm-transportation capacity on pipelines and firm-storage capacity at Clay Basin, a large baseload-storage facility owned by affiliate Questar Pipeline. Energy Trading, through its subsidiary Clear Creek Storage Company, LLC, operates an
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underground gas-storage reservoir in southwestern Wyoming. Energy Trading uses owned and leased-storage capacity together with firm-transportation capacity to take advantage of price differentials and arbitrage opportunities.
Competition and Customers: Energy Trading sells Questar E&P crude-oil production to refiners, remarketers and other companies, including some with pipeline facilities near company producing properties. In the event pipeline facilities are not available, Energy Trading transports crude oil by truck or rail to storage, refining or pipeline facilities. Energy Trading uses derivative instruments to manage commodity price risk. Energy Trading primarily uses fixed-price swaps to secure a known price for a specific volume of production. Energy Trading does not engage in speculative hedging transactions. See Item 7A and Notes 1 and 7 to the consolidated financial statements included in Item 8 of Part II of this Annual Report for additional information relating to hedging activities.
INTERSTATE GAS TRANSPORTATION - Questar Pipeline
General: Questar Pipeline provides natural gas-transportation and underground storage services in Utah, Wyoming and Colorado. Questar Pipeline and subsidiaries generated approximately 13% of the Company's operating income in 2009. As a "natural gas company" under the Natural Gas Act of 1938, Questar Pipeline and certain subsidiary pipeline companies are regulated by the FERC as to rates and charges for storage and transportation of natural gas in interstate commerce, construction of new facilities, and extensions or abandonments of service and facilities, accounting and other activities.
Questar Pipeline and its subsidiaries own 2,568 miles of interstate pipeline with total firm capacity commitments of 4,243 Mdth per day. Questar Pipeline's core-transportation system is strategically located near large reserves of natural gas in six major Rocky Mountain producing areas. Questar Pipeline transports natural gas from these producing areas to other major pipeline systems and to the Questar Gas distribution system. In addition to this core system, Questar Pipeline, through wholly owned subsidiaries, owns and operates the Overthrust Pipeline in southwestern Wyoming and the eastern segment of Southern Trails Pipeline, a 488-mile line that extends from the Blanco hub in the San Juan Basin to just inside the California state line. An additional 96 miles of Southern Trails Pipeline in California is not in service. Questar Pipeline owns 50% of the White River Hub in western Colorado, which was placed in service in the fourth quarter of 2008. These facilities connect with six interstate pipeline systems and a major processing plant near Meeker, Colorado.
Questar Pipeline owns and operates the Clay Basin storage facility, the largest underground-storage reservoir in the Rocky Mountain region. Through a subsidiary, Questar Pipeline also owns gathering lines and processing facilities near Price, Utah, which provide gas-processing services for third parties.
Customers, Growth and Competition: Questar Pipeline's transportation system is nearly fully subscribed. The weighted-average remaining life of firm contracts on Questar Pipeline was 12.4 years as of December 31, 2009. All of Questar Pipeline storage capacity is fully contracted with a weighted-average remaining life of 7.3 years as of December 31, 2009. Questar Pipeline faces the risk that it may not be able to recontract firm capacity when contract terms expire.
Questar Gas, an affiliated company, remains Questar Pipeline's largest transportation customer. During 2009, Questar Pipeline transported 112.9 MMdth for Questar Gas compared to 120.9 MMdth in 2008. Questar Gas has reserved firm-transportation capacity of 901 Mdth per day under long-term contracts. Questar Pipeline's primary transportation agreement with Questar Gas will expire on June 30, 2017.
Questar Pipeline also transported 614.8 MMdth during 2009, up 1% over 2008, for nonaffiliated customers to pipelines owned by Kern River Pipeline, Northwest Pipeline, Colorado Interstate Gas, TransColorado, Wyoming Interstate Company, Rockies Express Pipeline and other systems. Rocky Mountain producers, marketers and end-users seek capacity on interstate pipelines that move gas to California, the Pacific Northwest or Midwestern markets. Questar Pipeline provides access for many producers to these third-party pipelines.
Questar Pipeline competes for market growth with other natural gas transmission companies in the Rocky Mountain region and with other companies providing natural gas storage services. Some parties, including Gas Management, an affiliate of Questar, are building gathering lines that allow producers to make direct connections to competing pipeline systems.
Regulation: The FERC issued a final rule on Standards of Conduct in October 2008. The final rule, Order No. 717, eliminates the concept of energy affiliates and adopts a "functional approach" that applies standards of conduct to individual officers and employees based on their job functions, not on the company or division in which the individual works. The general principles of Standards of Conduct are: Non Discrimination, Independent Functioning, No Conduit and Transparency. These principles govern the relationship between transportation function employees and marketing function employees conducting transactions with affiliated pipeline and storage companies regulated by the FERC (transportation providers). Questar Pipeline maintains a rigorous compliance program to address all areas of FERC compliance including standards of conduct, market manipulation, shipper-
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must-have-title, bidding, capacity release, reporting, filings, postings and record retention. The Company annually trains Board members, executives, senior management and functional employees on standards of conduct rules.
Questar Pipeline is required to comply with the Pipeline Safety Improvement Act of 2002. This Act and the rules issued by the DOT require interstate pipelines and local distribution companies to implement a 10-year program of risk analysis, pipeline assessment and remedial repair for transportation pipelines located in high-consequence areas such as densely-populated locations. Questar Pipeline's annual cost to comply with the Act is approximately $1 million, not including costs of pipeline replacement, if necessary.
RETAIL GAS DISTRIBUTION - Questar Gas
General: Questar Gas distributes natural gas as a public utility in Utah, southwestern Wyoming and a small portion of southeastern Idaho. It generated approximately 9% of the Company's operating income in 2009. As of December 31, 2009, Questar Gas was serving 898,558 sales and transportation customers. Questar Gas is the only non-municipal gas-distribution utility in Utah, where 97% of its customers are located. The Public Service Commission of Utah (PSCU), the Public Service Commission of Wyoming (PSCW) and the Public Utility Commission of Idaho have granted Questar Gas the necessary regulatory approvals to serve these areas. Questar Gas also has long-term franchises granted by communities and counties within its service area.
Questar Gas growth is tied to the economic growth of Utah and southwestern Wyoming. It has over 90% of the load for residential space heating and water heating in its service area. During 2009, Questar Gas added 9,956 customers, a 1% increase. The rate of customer growth is the lowest in a number of years because of declines in housing construction.
Questar Gas faces the same risks as other local-distribution companies. These risks include revenue variations based on seasonal changes in demand, sufficient gas supplies, declining residential usage per customer, adequate distribution facilities and adverse regulatory decisions. Questar Gas's sales to residential and commercial customers are seasonal, with a substantial portion of such sales made during the heating season. The typical residential customer in Utah (defined as a customer using 80 dth per year) consumes over 77% of total gas requirements in the coldest six months of the year. Questar Gas, however, has a weather-normalization mechanism for its general-service customers. This mechanism adjusts the non-gas portion of a customer's monthly bill as the actual heating-degree days in the billing cycle are warmer or colder than normal. This mechanism reduces dramatic fluctuations in any given customer's monthly bill from year to year and reduces fluctuations in Questar Gas gross margin.
In October 2006 the PSCU approved a pilot program for a conservation enabling tariff (CET) effective January 1, 2006, to promote energy conservation. Under the Company's prior rate structure, non-gas revenues declined when average temperature-adjusted usage per customer declined while non-gas revenues increased when average temperature-adjusted usage per customer increased. Under the CET, Questar Gas non-gas revenues are decoupled from the temperature-adjusted usage per customer. The tariff specifies a margin per customer for each month with differences to be deferred and recovered from customers or refunded to customers through periodic rate adjustments. These adjustments are limited to five percent of distribution non-gas revenues. Under the CET, Questar Gas recorded a $4.0 million revenue decrease in 2009 compared with a $1.0 million increase in 2008. In late 2007, the PSCU ordered a continuation of the CET program for an additional two years.
In January 2007 the PSCU approved a demand-side management program (DSM) effective January 1, 2007. Under the DSM, Questar Gas encourages the conservation of natural gas through advertising, rebates for efficient homes and appliances, and energy audits. The costs related to the DSM are deferred and recovered from customers through periodic rate adjustments. Questar Gas received revenues for recovery of DSM costs amounting to $26.9 million in 2009 compared with $6.6 million in 2008. As of December 31, 2009, Questar Gas had a regulatory asset of $40.6 million for DSM costs to be recovered from customers.
Questar Gas reduces gas supply risk with cost-of-service natural gas reserves. During 2009 Questar Gas satisfied 51% of its supply requirements with cost-of-service gas volumes. Wexpro produces cost-of-service gas, which is then gathered by Gas Management and transported by Questar Pipeline. See Item 2 of Part I and Note 17 to the consolidated financial statements included in Item 8 of Part II of this Annual Report for more information on the Company's cost-of-service proved reserves. Questar Gas also has a balanced and diversified portfolio of gas-supply contracts for volumes produced in Wyoming, Colorado, and Utah. Questar Gas has regulatory approval to pass through in its balancing account the economic results associated with hedging activities.
Questar Gas has designed its distribution system and annual gas-supply plan to handle peak design-day demand, which is defined as the estimated volume of gas that firm customers could use when the weather is extremely cold. For the 2009-2010 heating season, Questar Gas had an estimated peak design-day demand of 1,256 MMdth.
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Questar Gas has long-term contracts with Questar Pipeline for transportation and storage capacity at Clay Basin and three peak-day storage facilities. Questar Gas also has transportation contracts to take deliveries at several locations on the Kern River Pipeline.
Competition, Customers and Growth: Questar Gas currently does not face direct competition from other distributors of natural gas for residential and commercial customers in its service territory. Natural gas has historically enjoyed a favorable price comparison with other energy sources used by residential and commercial customers with the notable exceptions of electricity from coal-fired power plants and occasionally fuel oil when oil prices are low. Questar Gas provides transportation service to industrial customers who buy gas directly from other suppliers. Questar Gas earns lower margins on this transportation service than firm-sales service and faces the risk that it could lose customers to competitor, Kern River Pipeline.
Regulation: As a public utility Questar Gas is subject to the jurisdiction of the PSCU and PSCW. Natural gas sales and transportation services are provided under rate schedules approved by the two regulatory commissions. Questar Gas is authorized to earn a return on equity of 10.0% in Utah and 10.5% in Wyoming. Both the PSCU and PSCW permit Questar Gas to recover gas costs through a balancing-account procedure and to reflect natural gas-price changes on a periodic basis, typically twice a year in the spring and the fall. Questar Gas has also received permission from the PSCU and PCSW to recover as part of its gas costs the specific costs associated with hedging activities.
Questar Gas filed a general rate case in Utah in December 2007. The PSCU allowed Questar Gas to increase its non-gas distribution revenues by an annualized $12.0 million beginning August 15, 2008 and authorized a 10.0% return on equity. Questar Gas filed a general rate case in Wyoming in August 2008. The PSCW authorized a 10.5% return on equity. Questar Gas filed a general rate case in Utah in December 2009, requesting an allowed return on equity of 10.6%, an increase in rates of $17.2 million, a mechanism to adjust rates for investment in feeder line replacement, and a continuation of the CET.
Questar Gas has significant relationships with affiliates that have allowed it to lower its costs and improve efficiency. Transactions between Questar Gas and its affiliates are subject to greater scrutiny by regulators.
Questar Gas is subject to the requirements of the Pipeline Safety Improvement Act. Questar Gas estimates that it will cost $4.0 to $5.0 million per year to comply with the Act, not including costs of pipeline replacement if necessary. The PSCU has allowed Questar Gas to recover these costs and to record a regulatory asset for costs incurred to comply with this Act.
Corporate
Corporate employees provide compliance, legal, finance, human resources, audit and insurance services for Questar's subsidiaries.
Employees
At December 31, 2009, the Company had 2,468 employees, including 905 in Market Resources, 301 in Questar Pipeline, 1,191 in Questar Gas and 71 in Corporate.
Executive Officers of the Registrant
Primary Positions Held with the Company
and Affiliates, Other Business Experience
Keith O. Rattie
Chairman (2003); President (2001); Chief Executive Officer (2002); Director (2001); Chief Operating Officer (2001 to 2002); Director, Questar affiliates (2001).
Charles B. Stanley
Chief Operating Officer, Questar (2008); Executive Vice President and Director, Questar (2002); President, Chief Executive Officer and Director, Market Resources and Market Resources subsidiaries (2002); Senior Vice President, Questar (2002); Executive Vice President and Chief Operating Officer, Market Resources and Market Resources subsidiaries (2002).
Richard J. Doleshek
Executive Vice President and Chief Financial Officer (2009). Prior to joining Questar; Mr. Doleshek was Executive Vice President and Chief Financial Officer, Hilcorp Energy Company (2001 to 2009).
R. Allan Bradley
Senior Vice President, Questar (2005); Chief Executive Officer, Questar Pipeline (2006); President, Chief Operating Officer and Director, Questar Pipeline (2005).
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Ronald W. Jibson
Senior Vice President, Questar (2008); President, Chief Executive Officer and Director, Questar Gas (2008); Executive Vice President, Questar Gas (2008); Vice President, Operations Questar Gas (2004).
Jay B. Neese
Senior Vice President, Questar (2005); Executive Vice President, Market Resources and Market Resources subsidiaries (2005); Vice President, Questar, Market Resources and Market Resources subsidiaries (2003); Assistant Vice President Questar and Assistant Vice President, Operations, Questar E&P (2001).
Thomas C. Jepperson
Vice President and General Counsel, Questar (2005); Division Counsel (2000 to 2004).
Abigail L. Jones
Vice President Compliance (2007) and Corporate Secretary (2005); Assistant Secretary (2004).
There is no "family relationship" between any of the listed officers or between any of them and the Company's directors. The executive officers serve at the pleasure of the Board of Directors. There is no arrangement or understanding under which the officers were selected.
ITEM 1A. RISK FACTORS.
Investors should read carefully the following factors as well as the cautionary statements referred to in "Forward-Looking Statements" herein. If any of the risks and uncertainties described below or elsewhere in this Annual Report actually occur, the Company's business, financial condition or results of operations could be materially adversely affected.
Risks Inherent in the Company's Business
The future prices for natural gas, oil and NGL are unpredictable. Historically natural gas, oil and NGL prices have been volatile and will likely continue to be volatile in the future. U.S. natural gas prices in particular are significantly influenced by weather. Any significant or extended decline in commodity prices would impact the Company's future financial condition, revenue, operating result, cash flow, return on invested capital, and rate of growth. Because approximately 92% of Market Resources' proved reserves at December 31, 2009, were natural gas, the Company's revenue, margin, cash flow, net income and return on invested capital are substantially more sensitive to changes in natural gas prices than to changes in oil prices.
Questar cannot predict the future price of natural gas, oil and NGL because of factors beyond its control, including but not limited to:
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changes in domestic and foreign supply of natural gas, oil and NGL;
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changes in local, regional, national and global demand for natural gas, oil, and NGL;
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regional price differences resulting from available pipeline transportation capacity or local demand;
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the level of imports of, and the price of, foreign natural gas, oil and NGL;
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domestic and global economic conditions;
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domestic political developments;
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weather conditions;
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domestic and foreign government regulations and taxes;
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technological advances affecting energy consumption and energy supply;
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political instability or armed conflict in oil and natural gas producing regions;
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conservation efforts;
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the price, availability and acceptance of alternative fuels;
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storage levels of natural gas, oil, and NGL; and
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the quality of gas and oil produced.
The Company may not be able to economically find and develop new reserves. The Company's profitability depends not only on prevailing prices for natural gas, oil and NGL, but also its ability to find, develop and acquire gas and oil reserves that are economically recoverable. Producing natural gas and oil reservoirs are generally characterized by declining production rates that vary depending on reservoir characteristics. Because of the high-rate production decline profile of several of the Company's producing areas, substantial capital expenditures are required to find, develop and acquire gas and oil reserves to replace those depleted by production.
Gas and oil reserve estimates are imprecise and subject to revision. Questar E&P's proved natural gas and oil reserve estimates are prepared annually by independent reservoir-engineering consultants. Gas and oil reserve estimates are subject to numerous uncertainties inherent in estimating quantities of proved reserves, projecting future rates of production and timing of development expenditures. The accuracy of these estimates depends on the quality of available data and on engineering and geological
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interpretation and judgment. Reserve estimates are imprecise and will change as additional information becomes available. Estimates of economically recoverable reserves and future net cash flows prepared by different engineers, or by the same engineers at different times, may vary significantly. Results of subsequent drilling, testing and production may cause either upward or downward revisions of previous estimates. In addition, the estimation process also involves economic assumptions relating to commodity prices, production costs, severance and other taxes, capital expenditures and remediation costs. Actual results most likely will vary from the estimates. Any significant variance from these assumptions could affect the recoverable quantities of reserves attributable to any particular properties, the classifications of reserves, the estimated future net cash flows from proved reserves and the present value of those reserves.
Investors should not assume that Questar E&P's presentation of the Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves in this Annual Report is the current market value of the estimated natural gas and oil reserves. In accordance with generally accepted accounting principles, the estimated discounted future net cash flows from Questar E&P's proved reserves is based on the first-of-the-month 12-month average prices and current costs on the date of the estimate, holding the prices and costs constant throughout the life of the properties and using a discount factor of 10 percent a year. Actual future prices and costs may differ materially from those used in the current estimate, and future determinations of the standardized measure of discounted future net cash flows using similarly determined prices and costs may be significantly different from the current estimate.
Shortages of oilfield equipment, services and qualified personnel could impact results of operations. The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and gas industry can fluctuate significantly, often in correlation with natural gas and oil prices, causing periodic shortages. There have also been regional shortages of drilling rigs and other equipment, as demand for specialized rigs and equipment has increased along with the number of wells being drilled. These factors also cause increases in costs for equipment, services and personnel. These cost increases could impact profit margin, cash flow and operating results or restrict the ability to drill wells and conduct operations, especially during periods of lower natural gas and oil prices.
Operations involve numerous risks that might result in accidents and other operating risks and costs. Drilling is a high-risk activity. Operating risks include: fire, explosions and blow-outs; unexpected drilling conditions such as abnormally pressured formations; abandonment costs; pipe, cement or casing failures; environmental accidents such as oil spills, natural gas leaks, ruptures or discharges of toxic gases, brine or well fluids (including groundwater contamination). The Company could incur substantial losses as a result of injury or loss of life; pollution or other environmental damage; damage to or destruction of property and equipment; regulatory investigation; fines or curtailment of operations; or attorney's fees and other expenses incurred in the prosecution or defense of litigation.
There are also inherent operating risks and hazards in the Company's gas and oil production, gas gathering, processing, transportation and distribution operations that could cause substantial financial losses. In addition, these risks could result in loss of human life, significant damage to property, environmental pollution, impairment of operations and substantial losses. The location of pipelines near populated areas, including residential areas, commercial business centers and industrial sites could increase the level of damages resulting from these risks. Certain segments of the Company's pipelines run through such areas. In spite of the Company's precautions, an event could cause considerable harm to people or property, and could have a material adverse effect on the financial position and results of operations, particularly if the event is not fully covered by insurance. Accidents or other operating risks could further result in loss of service available to the Company's customers. Such circumstances could adversely impact the Company's ability to meet contractual obligations and retain customers.
As is customary in the gas and oil industry, the Company maintains insurance against some, but not all, of these potential risks and losses. Questar cannot assure that insurance will be adequate to cover these losses or liabilities. Losses and liabilities arising from uninsured or underinsured events could have a material adverse effect on the Company's financial condition and operations.
Disruption of, capacity constraints in, or proximity to pipeline systems could impact results of operations. Questar E&P transports gas to market by utilizing pipelines owned by others. If pipelines do not exist near producing wells, if pipeline capacity is limited or if pipeline capacity is unexpectedly disrupted, gas sales could be reduced or shut in, reducing profitability. If pipeline quality tariffs change, the company might be required to install additional processing equipment which could increase costs.
Questar is dependent on bank credit facilities and continued access to capital markets to successfully execute its operating strategies. Questar also relies on access to short-term commercial paper markets. The Company is dependent on these capital sources to provide financing for certain projects. The availability and cost of these credit sources is cyclical, and these capital sources may not remain available or the Company may not be able to obtain money at a reasonable cost in the future. Liquidity in the global-credit markets has severely contracted, making terms for certain financings less attractive, and in certain cases, resulted in the unavailability of certain types of financing. In lieu of commercial paper issuance, the Company at times has utilized back-up lines of credit with banks to meet short-term funding needs. Banks may be unable or unwilling to extend back-up lines of credit in the
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future. All of Questar's bank loans are floating-rate debt. From time to time the Company may use interest-rate derivatives to fix the rate on a portion of its variable-rate debt. The interest rates on bank loans are tied to debt credit ratings of Questar and its subsidiaries published by Standard & Poor's and Moody's. A downgrade of credit ratings could increase the interest cost of debt and decrease future availability of money from banks and other sources. While management believes it is important to maintain investment grade credit ratings to conduct the Company's businesses, the Company may not be able to keep investment grade ratings.
The severe economic recession increases credit risk. Questar has significant credit exposure in outstanding accounts receivable from customers in all segments of its business. Questar is tightening its credit procedures such as requiring deposits or prepayments to help manage this risk. Questar also aggressively pursues collection of past-due accounts receivable.
Risks Related to Strategy
Questar uses derivative instruments to manage exposure to uncertain prices. Questar uses commodity-price derivative arrangements to reduce, or hedge, exposure to volatile natural gas, oil, and NGL prices and to protect cash flow, returns on capital, net income and credit ratings from downward commodity price movements. To the extent the Company hedges commodity price exposure, it forgoes the benefits of commodity price increases. Questar believes its regulated businesses - interstate natural gas transportation and retail gas distribution - and its Wexpro subsidiary generate revenues that are not significantly sensitive to short-term fluctuations in commodity prices.
Questar enters into commodity-price derivative arrangements with creditworthy counterparties (banks and energy-trading firms) that do not require collateral deposits. The amount of credit available may vary depending on the credit ratings assigned to the Company's debt securities. Questar is exposed to the risk of counterparties not performing.
Questar may be subject to risks in connection with acquisitions. The acquisition of gas and oil properties requires the assessment of recoverable reserves; future gas and oil sales prices and basis differentials; operating costs; and potential environmental and other liabilities. The accuracy of these assessments is inherently uncertain. In connection with these assessments, the Company performs a review of the subject properties and pursues contractual protection and indemnification generally consistent with industry practices.
Risks Related to Regulation
Questar is subject to complex regulations on many levels. The Company is subject to federal, state and local environmental, health and safety laws and regulations. Environmental laws and regulations are complex, change frequently and tend to become more onerous over time. In addition to the costs of compliance, substantial costs may be incurred to take corrective actions at both owned and previously-owned facilities. Accidental spills and leaks requiring cleanup may occur in the ordinary course of business. As standards change, the Company may incur significant costs in cases where past operations followed practices that were considered acceptable at the time but now require remedial work to meet current standards. Failure to comply with these laws and regulations may result in fines, significant costs for remedial activities, or injunctions.
Questar must comply with numerous and complex regulations federal and state regulations governing activities on federal and state lands, notably the National Environmental Policy Act, the Endangered Species Act, the Clean Air Act, and the National Historic Preservation Act and similar state laws. The United States Fish and Wildlife Service may designate critical habitat areas for certain listed threatened or endangered species. A critical habitat designation could result in further material restrictions to federal land use and private land use and could delay or prohibit land access or development. The listing of certain species, such as the sage grouse, as threatened and endangered, could have a material impact on the Company's operations in areas where such species are found. The Clean Water Act and similar state laws regulate discharges of storm water, wastewater, oil, and other pollutants to surface water bodies, such as lakes, rivers, wetlands, and streams. Failure to obtain permits for such discharges could result in civil and criminal penalties, orders to cease such discharges, and other costs and damages. These laws also require the preparation and implementation of Spill Prevention, Control, and Countermeasure Plans in connection with on-site storage of significant quantities of oil.
Federal and state agencies frequently impose conditions on the Company's activities. These restrictions have become more stringent over time and can limit or prevent exploration and production on the Company's leasehold. Certain environmental groups oppose drilling on some of Market Resources' federal and state leases. These groups sometimes sue federal and state agencies for alleged procedural violations in an attempt to stop, limit or delay natural gas and oil development on public lands.
All wells drilled in tight gas sand and shale reservoirs require hydraulic fracture stimulation to achieve economic production rates and recoverable reserves. A significant portion of the Company's current and future production and reserve potential is derived from reservoirs that require hydraulic fracture stimulation to be commercially viable. Currently, all well construction activities, including hydraulic fracture stimulation, are regulated by state agencies that review and approve all aspects of gas and oil well design and operation. New environmental initiatives, proposed federal and state legislation and rulemaking pertaining to
QUESTAR 2009 FORM 10-K
hydraulic fracture stimulation could include additional permitting and reporting requirements and potential restrictions on the use of hydraulic fracture stimulation that could materially affect the Company's ability to develop and produce gas and oil reserves.
In addition, the Company is subject to federal and state hazard communications and community right-to-know statutes and regulations such as the Emergency Planning and Community Right-to- Know Act that require certain record keeping and reporting of the use and release of hazardous substances.
Various federal agencies within the U.S. Department of the Interior, particularly the Minerals Management Service and the Bureau of Indian Affairs, along with each Native American tribe, promulgate and enforce regulations pertaining to gas and oil operations on Native American tribal lands. These regulations include such matters as lease provisions, drilling and production requirements, environmental standards and royalty considerations. In addition, each Native American tribe is a sovereign nation having the right to enforce laws and regulations independent from federal, state and local statutes and regulations. These tribal laws and regulations include various taxes, fees, requirements to employ Native American tribal members and other conditions that apply to lessees, operators and contractors conducting operations on Native American tribal lands. Lessees and operators
conducting operations on tribal lands are generally subject to the Native American tribal court system. One or more of these factors may increase the Company's costs of doing business on Native American tribal lands and have an impact on the viability of its gas and oil exploration, production, gathering, processing and transportation operations on such lands.
Regulatory authorities exercise considerable discretion in the timing and scope of permit issuance. Requirements imposed by these authorities may be costly and time consuming and may result in delays in the commencement or continuation of the Company's exploration and production and midstream field services operations. Further, the public may comment on and otherwise engage in the permitting process, including through intervention in the courts. Accordingly, needed permits may not be issued, or if issued, may not be issued in a timely fashion, or may involve requirements that restrict Questar's ability to conduct its operations or to do so profitably.
Both Questar Pipeline and Questar Gas incur significant costs to comply with federal pipeline-safety regulations.
Questar may be exposed to certain regulatory and financial risks related to climate change. Federal and state courts and administrative agencies are considering the scope and scale of climate-change regulation under various laws pertaining to the environment, energy use and development, and greenhouse gas emissions. Questar's ability to access and develop new natural gas reserves may be restricted by climate-change regulation. There are bills pending in Congress that would regulate greenhouse gas emissions through a cap-and-trade system under which emitters would be required to buy allowances for offsets of emissions of greenhouse gases. The Environmental Protection Agency (EPA) has adopted final regulations for the measurement and reporting of greenhouse gases emitted from certain large facilities (25,000 tons/year of CO2 equivalent) beginning with operations in 2010. The first report is to be filed with the EPA by March 31, 2011. In addition, several of the states in which Questar operates are considering various greenhouse gas registration and reduction programs. Carbon dioxide regulation could increase the price of natural gas, restrict access to or the use of natural gas, and/or reduce natural gas demand. Federal, state and local governments may also pass laws mandating the use of alternative energy sources, such as wind power and solar energy, which may reduce demand for natural gas. While future climate-change regulation is likely, it is too early to predict how this regulation will affect Questar's business, operations or financial results. It is uncertain whether Questar's operations and properties, located in the Rocky Mountain and Midcontinent regions of the United States, are exposed to possible physical risks, such as severe weather patterns, due to climate change as a result of man-made greenhouse gases. However, management does not believe such physical risks are reasonably likely to have a material effect on the company's financial condition or results of operations.
FERC regulates interstate natural gas transportation and oversees natural gas marketing. Questar Pipeline's natural gas transportation and storage operations are regulated by the FERC under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. The FERC has authority to: set rates for natural gas transportation, storage and related services; set rules governing business relationships between the pipeline subsidiary and its affiliates; approve new pipeline and storage-facility construction; and establish policies and procedures for accounting, purchase, sale, abandonment and other activities. FERC policies may adversely affect Questar Pipeline profitability.
During the fourth quarter of 2008, FERC issued a number of orders related to market transparency that extend FERC oversight to many Questar subsidiaries. Order No. 704 requires all natural gas companies to report gas purchases and sales and their relationship to price reporting indexes. Order No. 712 defines changes in capacity release and asset management. Order No. 717 establishes new Standards of Conduct Rules and Order No. 720 requires intrastate pipelines to report available transportation capacity. In addition to the new orders, FERC released a policy statement on compliance in which it states that companies must have a "rigorous" FERC compliance program that extends to all subsidiaries, not just interstate pipelines. Since the enactment of the Energy Policy Act of 2005, granting FERC increased penalty authority for non compliance, FERC has targeted various issues in the natural gas industry for compliance audits and investigations.
QUESTAR 2009 FORM 10-K
State agencies regulate the distribution of natural gas. Questar Gas natural gas-distribution business is regulated by the PSCU and the PSCW. These commissions set rates for distribution services and establish policies and procedures for services, accounting, purchase, sale and other activities. PSCU and PSCW policies and decisions may adversely affect Questar Gas profitability.
Other Risks
General economic and other conditions impact Questar's results. Questar's results may also be negatively affected by: changes in global economic conditions; changes in regulation; availability and economic viability of gas and oil properties for sale or exploration; creditworthiness of counterparties; rate of inflation and interest rates; assumptions used in business combinations; weather and natural disasters; changes in customers' credit ratings; competition from other forms of energy, other pipelines and storage facilities; effects of accounting policies issued periodically by accounting standard-setting bodies; terrorist attacks or acts of war; changes in business or financial condition; changes in credit ratings; and availability of financing for Questar.
ITEM 1B. UNRESOLVED STAFF COMMENTS.
None.
ITEM 2. PROPERTIES.
EXPLORATION AND PRODUCTION
Reserves - Questar E&P
Questar E&P's reserve estimates are prepared by Ryder Scott Company, L.P., independent reservoir-engineering consultants. The estimates of proved reserves at December 31, 2009, were made in accordance with amended reserves definitions included in the SEC's rules for the Modernization of Oil and Gas Reporting. The most significant amendments affecting the Company include, allowing the use of reliable technologies to estimate and categorize reserves and using the arithmetic average of the price on the first day of each month within the 12-month period prior to the end of the reporting period (unless contractual arrangements designate the price) to be used to calculate economic producibility of reserves and the discounted cash flows reported as the Standardized Measure of Future Net Cash Flows Relating to Proved Reserves. Refer to Note 17 to the consolidated financial statements included in Item 8 of Part II of this Annual Report for additional information regarding estimates of proved reserves and the preparation of such estimates.
Questar E&P does not have any long-term supply contracts with foreign governments or reserves of equity investees or reserves of subsidiaries with a significant minority interest. At December 31, 2009, approximately 90% of Questar E&P's estimated proved reserves were Company operated. All reported reserves are located in the United States. Questar E&P's estimated reserves are summarized as follows:
Questar E&P's reserve statistics for the years ended December 31, 2007 through 2009, are summarized below:
(a)Reserve life index is calculated by dividing year-end proved reserves by production for such year.
Questar E&P proved reserves by major operating areas at December 31, 2009 and 2008 follow:
QUESTAR 2009 FORM 10-K
Reserves - Cost-of-Service
Wexpro manages, develops and produces cost-of-service reserves for Questar Gas under the terms of the Wexpro Agreement. The following table sets forth estimated cost-of-service natural gas and oil reserves. The estimates of cost-of-service proved reserves were made by Wexpro's reservoir engineers as of December 31, 2009. All reported reserves are located in the United States.
Wexpro develops cost-of-service reserves and delivers the natural gas it produces to Questar Gas at cost of service. Wexpro sells crude oil production from certain oil-producing properties at market prices. Wexpro recovers its cost and return on investment from the proceeds of such sells. Any residual operating income after recovery of Wexpro costs and return is shared 54% Questar Gas, 46% Wexpro, Therefore, SEC guidelines with respect to standard economic assumptions do not apply to Wexpro. SEC guidelines provide for such exceptions. Accordingly, Wexpro reservoir engineers used a minimum producing rate or maximum well-life limit to determine the ultimate quantity of reserves attributable to each well.
Refer to Note 17 of the consolidated financial statements included in Item 8 of Part II of this Annual Report for additional information pertaining to both Questar E&P proved reserves and the Company's cost-of-service reserves as of the end of each of the last three years.
In addition to this filing, Questar E&P and Wexpro will each file reserves estimates as of December 31, 2009, with the Energy Information Administration of the Department of Energy on Form EIA-23. Although the companies use the same technical and economic assumptions when they prepare the EIA-23, they are obligated to report reserves for all wells they operate, not for all wells in which they have an interest, and to include the reserves attributable to other owners in such wells.
Production
The following table sets forth the net production volumes, the average sales prices per Mcf of natural gas, per bbl of oil and NGL produced, and the production costs per Mcfe for the years ended December 31, 2009, 2008 and 2007.
QUESTAR 2009 FORM 10-K
Productive Wells
The following table summarizes the Company's productive wells (including cost-of-service wells) as of December 31, 2009. All wells are located in the United States.
Although many wells produce both gas and oil, a well is categorized as either a gas or an oil well based upon the ratio of gas to oil produced. Each gross well completed in more than one producing zone is counted as a single well. At the end of 2009, the Company had 161 gross wells with multiple completions.
The Company also holds numerous overriding-royalty interests in gas and oil wells, a portion of which are convertible to working interests after recovery of certain costs by third parties. After converting to working interests, these overriding-royalty interests will be included in the gross and net-well count.
Leasehold Acres
The following table summarizes developed and undeveloped-leasehold acreage in which the Company owns a working interest as of December 31, 2009. "Undeveloped Acreage" includes leasehold interests that already may have been classified as containing proved undeveloped reserves and unleased mineral-interest acreage owned by the Company. Excluded from the table is acreage in which the Company's interest is limited to royalty, overriding-royalty and other similar interests. All leasehold acres are located in the United States.
(1)Developed acreage is acreage assigned to productive wells.
(2)Undeveloped acreage is leased acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas and oil regardless of whether such acreage contains proved reserves.
QUESTAR 2009 FORM 10-K
A portion of the leases summarized in the preceding table will expire at the end of their respective primary terms unless the existing leases are renewed or production has been obtained from the acreage subject to the lease prior to that date. Leases held by production remain in effect until production ceases. The following table sets forth the gross and net acres subject to leases summarized in the preceding table that will expire during the periods indicated:
Drilling Activity
The following table summarizes the number of development and exploratory wells drilled by Market Resources, including the cost-of-service wells drilled by Wexpro, during the years indicated.
MIDSTREAM FIELD SERVICES - Questar Gas Management
Gas Management owns 1,620 miles of gathering lines in Utah, Wyoming, and Colorado. Rendezvous Pipeline owns a 21-mile 20-inch-diameter line between Gas Management's Blacks Fork gas-processing plant and Kern River Pipeline's Muddy Creek compressor station that can deliver up to 300 MMcf of natural gas per day to markets in California and Nevada served by the Kern River Pipeline. In conjunction with these gathering facilities, Gas Management owns compression facilities, field-dehydration and measuring systems. Rendezvous owns an additional 329 miles of gathering lines and associated field equipment, Field Services owns 76 miles of gathering lines and associated field equipment and Three Rivers owns 57 miles of gathering lines. Gas Management owns processing plants that have an aggregate capacity of 654 MMcf of unprocessed natural gas per day.
ENERGY MARKETING - Questar Energy Trading
Energy Trading, through its wholly owned subsidiary Clear Creek Storage Company, LLC, owns and operates an underground gas-storage reservoir in southwestern Wyoming.
INTERSTATE GAS TRANSPORTATION - Questar Pipeline
Questar Pipeline has firm-capacity of 4,243 Mdth per day. These commitments include 1,991 Mdth per day for Questar Pipeline, 1,151 Mdth per day for Overthrust Pipeline, 81 Mdth per day for Southern Trails Pipeline and 1,020 Mdth per day for Questar Pipeline's 50% ownership of White River Hub. Questar Pipeline's transportation system includes 2,568 miles of natural gas transportation pipelines that interconnect with other pipelines. Its core system includes two segments, referred to as the northern system and southern system. The northern system extends from northwestern Colorado through southwestern Wyoming into northern Utah, while the southern system extends from western Colorado to Goshen, Utah. Questar Pipeline's 2,568 miles of natural gas transportation pipeline includes pipelines at storage fields and tap lines used to serve Questar Gas, 214 miles of Overthrust Pipeline, a wholly owned subsidiary and 487 miles of the Southern Trails Pipeline, a wholly owned subsidiary, but does not include 96 miles of Southern Trails Pipeline that is not in service in southern California,. Questar Pipeline's system ranges in size from lines that are less than four inches in diameter to the 36-inch Overthrust Pipeline. Questar Pipeline also owns large-scale compressor stations, which boost the pressure of natural gas transported on its pipelines for delivery to utility customers and third-party pipelines.
QUESTAR 2009 FORM 10-K
Questar Pipeline also owns the Clay Basin storage facility in northeastern Utah, which has a certificated capacity of 117.5 Bcf, including 51.3 Bcf of working gas. Questar Pipeline also owns three smaller storage aquifers in northeastern Utah and western Wyoming. Through a subsidiary, Questar Pipeline also owns gathering lines and processing facilities near Price, Utah, which provide gas-processing services for third parties.
RETAIL GAS DISTRIBUTION - Questar Gas
Questar Gas distributes gas to customers along the Wasatch Front, the major populated area of Utah, the metropolitan Salt Lake area, Provo, Park City, Ogden and Logan. It also serves customers throughout the state, including the cities of Price, Roosevelt, Vernal, Moab, Monticello, Fillmore, Cedar City and St. George. Questar Gas supplies natural gas to the southwestern Wyoming communities of Rock Springs, Green River, Evanston, Kemmerer and Diamondville and the southeastern Idaho community of Preston. To supply these communities Questar Gas owns and operates distribution systems and has a total of 27,034 miles of street mains, service lines and interconnecting pipelines. Questar Gas has a major operations center in Salt Lake City, and has operations centers, field offices and service-center facilities through other parts of its service area.
ITEM 3. LEGAL PROCEEDINGS.
Questar is involved in various commercial and regulatory claims and litigation and other legal proceedings that arise in the ordinary course of its business. Management does not believe any of them will have a material adverse effect on the Company's financial position, results of operations or cash flows. A liability is recorded for a loss contingency when its occurrence is probable and damages can be reasonably estimated based on the anticipated most likely outcome. Disclosures are provided for contingencies reasonably likely to occur which would have a material adverse effect on the Company's financial position, results of operations or cash flows. Some of the claims involve highly complex issues relating to liability, damages and other matters subject to substantial uncertainties and, therefore, the probability of liability or an estimate of loss cannot be reasonably determined.
Environmental Claims
In United States of America v. Questar Gas Management Co., Civil No. 208CV167, filed on February 29, 2008, in Utah Federal District Court, the EPA alleges that Gas Management violated the federal Clean Air Act (CAA) and seeks substantial penalties and a permanent injunction involving the manner of operation of five compressor stations located in the Uinta Basin of eastern Utah. EPA further alleges that the facilities are located within the original boundaries of the former Uncompahgre Indian Reservation and are therefore within "Indian Country." EPA asserts primary CAA jurisdiction over "Indian Country" where state CAA programs do not apply. EPA contends that the potential to emit, on a hypothetically uncontrolled basis, for Gas Management's facilities render them "major sources" of emissions for criteria and hazardous air pollutants. Categorization of the facilities as "major sources" affects the particular regulatory program applicable to those facilities. EPA claims that Gas Management failed to obtain the necessary major source pre-construction or modification permits, and failed to comply with hazardous air-pollutant regulations for testing and reporting, among other things. Gas Management contends that its facilities have pollution controls installed that reduce their actual air emissions below major source thresholds, rendering them subject to different regulatory requirements. Gas Management intends to vigorously defend against the EPA's claims, and believes that the major source permitting and regulatory requirements at issue can be legally avoided by applying Utah's CAA program or EPA's prior practice for similar facilities elsewhere in Indian Country, among other defenses. Because of the complexities and uncertainties of this legal dispute, it is difficult to predict all reasonably possible outcomes; however, management believes the Company has accrued a reasonable loss contingency that is an immaterial amount, for the anticipated most likely outcome.
On July 10, 2009 Questar E&P filed a petition with the U.S. Tenth Circuit Court of Appeals challenging an administrative compliance order dated May 12, 2009, (Order) issued by the EPA which asserts that Questar E&P's Flat Rock 14P Well and associated equipment is a major source of emissions of hazardous air pollutants and its operation fails to comply with certain regulations of the CAA. The Order required immediate compliance and threatened substantial penalties for failure to do so. Questar E&P denies that the drilling and operation of the 14P Well and associated equipment violates any provision of the CAA and intends to vigorously defend against this Order.
In October 2009, Questar E&P received a cease and desist order from the U.S. Army Corps of Engineers (COE) to refrain from further discharge of dredged and/or fill material into wetlands of the United States at three well sites without a permit under the Clean Water Act (CWA). The order specifically references prior construction activities at the sites located in Caddo and Red River Parishes, Louisiana. EPA Region 6 has now assumed lead responsibility for enforcement of the pending order and any possible future orders for the removal of unauthorized fills and/or civil penalties under Section 309 of the CWA. The company is working with the COE and EPA to resolve the matter.
QUESTAR 2009 FORM 10-K
Regulatory Proceedings
See Note 12 to the consolidated financial statements included in Item 8 of Part II of this Annual Report for information concerning various regulatory proceedings.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
The Company did not submit any matters to a vote of stockholders during the fourth quarter of 2009.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.
5-Year Cumulative Total Return to Shareholders
The following graph compares the cumulative total return of the Company's common stock with the cumulative total returns of a peer group of diversified natural gas companies selected by Questar, and of the S&P Composite-500 Stock Index.
The chart assumes $100 is invested at the close of trading on December 31, 2004 in the Company's common stock, an index of peer companies, and the S&P 500 Index. It also assumes all dividends are reinvested. For 2009 the Company had a total return of 29.1% compared to 39.7% for the peer group and 26.5% for the S&P 500 Index. For the five-year period, the Company had a compound annual total return of 11.6% compared to 7.1% for the peer group and 0.4% for the S&P 500 Index. The peer group is comprised of El Paso Corporation, Energen Corporation, EQT Corporation, MDU Resources Group, Inc., National Fuel Gas Company, and The Williams Companies, Inc.
The foregoing graph shall not be deemed to be filed as part of this Annual Report on Form 10-K and does not constitute soliciting material and should not be deemed filed or incorporated by reference into any other filing of Questar under the Securities Act of 1933 or the Securities Exchange Act of 1934, except to the extent the Company specifically incorporates the graph by reference.
Questar's common stock is listed on the New York Stock Exchange (NYSE:STR). As of January 31, 2010, Questar had 9,551 shareholders of record. Following is a summary of Questar's quarterly stock-price and dividend information:
QUESTAR 2009 FORM 10-K
Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities
Questar had no unregistered sales of equity during the fourth quarter of 2009. Questar repurchased shares in conjunction with tax-payment elections under the Company Long-term Stock Incentive Plan and rollover shares used in exercising stock options.
The following table sets forth the Company's purchases of common stock registered under Section 12 of the Exchange Act that occurred during the quarter ended December 31, 2009.
ITEM 6. SELECTED FINANCIAL DATA.
Selected financial data for the five years ending December 31, 2009, is provided in the table below. Refer to
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
RESULTS OF OPERATION
Following are comparisons of net income attributable to Questar by line of business:
EXPLORATION AND PRODUCTION
Questar E&P
Questar E&P reported net income of $134.9 million in 2009, down 67% from $408.0 million in 2008 and $285.5 million in 2007. Lower realized natural gas, crude oil and NGL prices and an 11% increase in 2009 average production costs more than offset an 11% increase in 2009 production. Unrealized mark-to-market losses on natural gas basis-only hedges decreased pre-tax income $164.0 million in 2009 compared to a net pre-tax loss of $79.2 million a year-earlier. Net gains from sales of assets at Questar E&P increased pre-tax income $1.6 million in 2009 compared to a net pre-tax gain of $60.4 million in the year-earlier period. Following is a summary of Questar E&P financial and operating results:
QUESTAR 2009 FORM 10-K
Questar E&P production volumes totaled 189.5 Bcfe in 2009 compared to 171.4 Bcfe in 2008 and 140.2 Bcfe in 2007. On an energy-equivalent basis, natural gas comprised approximately 89% of Questar E&P 2009 production. A comparison of natural gas-equivalent production by major operating area is shown in the following table:
Net production in the Midcontinent grew 29% or 20 Bcfe to 87.8 Bcfe in 2009 compared to 2008. Midcontinent production growth was driven by the first quarter 2008 acquisition of natural gas development properties in northwest Louisiana, ongoing infill-development drilling in the Cotton Valley and Haynesville formations in the Elm Grove, Thorn Lake and Woodardville fields in northwest Louisiana, continued development of the Granite Wash/Atoka/Morrow play in the Texas Panhandle, and production from new outside-operated Woodford Shale horizontal gas wells in the Anadarko Basin in central Oklahoma.
QUESTAR 2009 FORM 10-K
Questar E&P net production from the Pinedale Anticline in western Wyoming grew 9% to 61.8 Bcfe in 2009 as a result of ongoing development drilling. Historically, Pinedale seasonal access restrictions imposed by the Bureau of Land Management have limited the ability to drill and complete wells during the mid-November to early May period. In September 2008, the BLM issued a Record of Decision (ROD) on the Final Supplemental Environmental Impact Statement for long-term development of natural gas resources in the Pinedale Anticline Project Area (PAPA). Under the ROD, Questar E&P and Wexpro has been allowed to drill and complete wells year-round in one of the five Concentrated Development Areas defined in the PAPA. The ROD contains additional requirements and restrictions on development of the PAPA.
In the Uinta Basin, Questar E&P's net production decreased 14% to 23.2 Bcfe in 2009. Production volumes were adversely impacted by decreased drilling activity in response to low natural gas prices.
Rockies Legacy net production in 2009 decreased 16% to 16.7 Bcfe, 3.2 Bcfe lower than the year-ago period. Production volumes were adversely impacted by decreased drilling activity in response to low natural gas prices. Questar E&P Rockies Legacy properties include all Rocky Mountain region properties except the Pinedale Anticline and the Uinta Basin.
Realized prices for natural gas, oil and NGL at Questar E&P were lower when compared to the prior year. In 2009, the weighted-average realized natural gas price for Questar E&P (including the impact of hedging) was $6.54 per Mcf compared to $7.56 per Mcf in 2008, a 13% decrease. Realized oil and NGL prices in 2009 averaged $45.91 per bbl, compared with $72.96 per bbl during the prior year, a 37% decrease. A regional comparison of average realized prices, including the impact of hedges, is shown in the following table:
Questar E&P hedged approximately 77% of gas production in 2009 with fixed-price swaps. An additional 15% of gas production was subject to basis-only swaps. In 2008, approximately 82% of gas production was hedged with fixed-price swaps. An additional 3% of gas production was subject to basis-only swaps. Hedging increased Questar E&P gas revenues by $599.3 million in 2009 and increased revenues $125.8 million in 2008. Approximately 42% of 2009 and 50% of 2008 Questar E&P oil production was hedged with fixed-price swaps. Oil hedges increased oil revenues by $1.6 million in 2009 and reduced oil revenues $31.9 million in 2008. The net mark-to-market effect of gas-basis-only swaps is reported in the Consolidated Statements of Income below operating income. Derivative positions as of December 31, 2009, are summarized in Note 7 to the consolidated financial statements in Item 8 of Part II in this Annual Report on Form 10-K.
Questar E&P production costs (the sum of depreciation, depletion and amortization expense, lease operating expense, general and administrative expense, allocated-interest expense and production taxes) per Mcfe of production increased 11% to $4.39 per Mcfe in 2009 versus $3.94 per Mcfe in 2008. Questar E&P production costs are summarized in the following table:
QUESTAR 2009 FORM 10-K
Production volume-weighted per-unit depreciation, depletion and amortization (DD&A) expense increased compared to 2008 primarily due to price-related negative reserve revisions in certain fields and the growing proportion of total production from fields in the Midcontinent that have higher DD&A rates. Lease operating expense per Mcfe decreased primarily as a result of higher production volumes and reduced well-workover activity. General and administrative expense per Mcfe increased as a result of increased labor and outside services. Allocated interest expense per Mcfe of production was unchanged. Production taxes per Mcfe decreased in 2009 as the result lower natural gas and oil sales prices. In most states, the company pays production taxes based on a percentage of sales prices, excluding the impact of hedges.
Questar E&P exploration expense decreased $4.3 million or 15% in 2009 compared to 2008. Abandonment and impairment expense decreased $24.3 million or 54% in 2009 compared to 2008 primarily due to the impairment of certain gas and oil assets in 2008.
In the third quarter of 2008, Questar E&P sold certain outside-operated producing properties and leaseholds in the Gulf Coast region of south Texas and recognized a pre-tax gain of approximately $61.2 million. These properties contributed 2.8 Bcfe to Questar E&P net production in 2008.
Major Questar E&P Operating Areas
Midcontinent
Questar E&P Midcontinent properties are distributed over a large area, including the Anadarko Basin of Oklahoma and the Texas Panhandle, the Arkoma Basin of Oklahoma and western Arkansas, and the Ark-La-Tex region of Arkansas and Louisiana. With the exception of northwest Louisiana, the Granite Wash play in the Texas Panhandle and the Woodford Shale "Cana" play in western Oklahoma, Questar E&P Midcontinent leasehold interests are fragmented, with no significant concentration of property interests. In aggregate, Midcontinent properties comprised 1,100.5 Bcfe or 40% of Questar E&P total proved reserves at December 31, 2009.
Questar E&P has approximately 46,000 net acres of Haynesville Shale lease rights in northwest Louisiana. The true vertical depth to the top of the Haynesville Shale ranges from approximately 10,500 feet to 12,500 feet across Questar E&P's leasehold and is below the Hosston and Cotton Valley formations that Questar E&P has been developing in northwest Louisiana for over a decade. Questar E&P continues infill-development drilling in the Cotton Valley and Hosston formations in northwest Louisiana and intends to drill or participate in up to 48 (operated and non-operated) horizontal Haynesville Shale wells in 2010. As of December 31, 2009, Questar E&P had seven operated rigs drilling in the project area and operated or had working interests in 31 Haynesville formation wells and 610 total producing wells in northwest Louisiana compared to six Haynesville formation wells and 539 total producing wells at December 31, 2008.
Questar E&P has approximately 26,000 net acres of Woodford Shale lease rights in Blaine, Caddo and Canadian Counties in western Oklahoma. The true vertical depth to the top of the Woodford Shale ranges from approximately 11,000 feet to 14,000 feet across Questar E&P's leasehold. Questar E&P intends to drill or participate in up to 44 horizontal Woodford Shale wells in 2010. As of December 31, 2009, Questar E&P had one operated rig drilling in the project area and operated or had working interests in 49 producing Woodford Shale wells in western Oklahoma compared to 13 at December 31, 2008.
Questar E&P has over 25,000 net acres of Granite Wash lease rights in the Texas Panhandle and western Oklahoma and has been drilling vertical Granite Wash wells in the Texas Panhandle for over a decade. In the past year, other operators have drilled several successful horizontal wells in the Granite Wash Play. The true vertical depth to the top of the Granite Wash interval ranges from approximately 11,100 feet to 15,900 feet across Questar E&P's leasehold. As of December 31, 2009, Questar E&P had one rig drilling horizontal Granite Wash wells in the Texas Panhandle and had working interests in 10 producing horizontal Granite Wash wells in the Texas Panhandle or Washita County, Oklahoma compared to four wells at December 31, 2008. Questar E&P intends to drill or participate in up to 21 horizontal Granite Wash wells in 2010.
Pinedale Anticline
As of December 31, 2009, Market Resources (including both Questar E&P and Wexpro) operated and had working interests in 427 producing wells on the Pinedale Anticline compared to 331 at December 31, 2008. Of the 427 producing wells, Questar E&P has working interests in 405 wells, overriding royalty interests in an additional 21 Wexpro-operated wells, and no interest in one well operated by Wexpro. Wexpro has working interests in 126 of the 427 producing wells.
In 2005, the Wyoming Oil and Gas Conservation Commission (WOGCC) approved 10-acre-density drilling for Lance Pool wells on about 12,700 acres of Market Resources' 17,872-acre (gross) Pinedale leasehold. The area approved for increased density corresponds to the currently estimated productive limits of Market Resources core acreage in the field. In January 2008, the WOGCC approved five-acre-density drilling for Lance Pool wells on about 4,200 gross acres of Market Resources Pinedale
QUESTAR 2009 FORM 10-K
leasehold. The true vertical depth to the top of the Lance Pool tight gas sand reservoir interval ranges from 8,500 to 9,500 feet across Market Resources' acreage.
At December 31, 2009, Questar E&P had booked 432 proved undeveloped locations on a combination of 5-, 10- and 20-acre density and reported estimated net proved reserves at Pinedale of 1,300.7 Bcfe, or 47% of Questar E&P total proved reserves. The Company continues to evaluate development on five-acre density at Pinedale. If five-acre-density development is appropriate for a majority of its leasehold, the Company currently estimates that up to 1,400 additional wells will be required to fully develop the Lance Pool on its acreage.
Uinta Basin
As of December 31, 2009, Questar E&P had an operating interest in 2,334 gross producing wells in the Uinta Basin of eastern Utah, compared to 909 at December 31, 2008. The significant increase in well count was due to the inclusion of Questar E&P acreage within the outside-operated Greater Monument Butte enhanced recovery unit in 2009; resulting in Questar E&P having a very small interest in 1,313 wells. At December 31, 2009, Questar E&P had booked nine proved undeveloped locations and reported estimated net proved reserves in the Uinta Basin of 197.7 Bcfe or 7% of Questar E&P total proved reserves. Uinta Basin reserves declined 24% due to lower average 2009 gas and oil prices and a price-related slow down in development drilling. Uinta Basin proved reserves are found in a series of vertically stacked, laterally discontinuous reservoirs at depths of 5,000 feet to deeper than 18,000 feet. Questar E&P owns interests in over 244,000 net leasehold acres in the Uinta Basin.
Rockies Legacy
The remainder of Questar E&P Rocky Mountain region leasehold interests, productive wells and proved reserves are distributed over a number of fields and properties managed as the company's Rockies Legacy division. Most of the properties are located in the Greater Green River Basin of western Wyoming. In aggregate, Rockies Legacy properties comprised 148.0 Bcfe or 6% of Questar E&P total proved reserves at December 31, 2009. Exploration and development activity for 2010 includes wells in the San Juan, Paradox, Powder River, Green River, Vermillion and Williston Basins.
Questar E&P has approximately 80,000 net acres of Bakken formation lease rights in Mountrail, McLean and McKenzie counties in North Dakota. The true vertical depth to the top of the Bakken formation ranges from approximately 9,500 feet to 10,000 feet across Questar E&P's leasehold. The Three Forks Sanish formation lies approximately 60-70 feet below the middle Bakken formation and is also a target for horizontal drilling. Questar E&P intends to drill or participate in 20-25 horizontal Bakken or Three Forks Sanish wells in 2010. As of December 31, 2009, Questar E&P had one operated rig drilling in the project area and operated or had working interests in 26 producing Bakken or Three Forks Sanish wells in North Dakota compared to 15 at December 31, 2008.
Wexpro
Wexpro reported net income of $80.7 million in 2009 compared to $73.9 million in 2008, a 9% increase and $59.2 million in 2007. Wexpro 2009 results benefited from a higher average investment base compared to the prior-year period. Pursuant to the Wexpro Agreement, Wexpro recovers its costs and receives an unlevered after-tax return of approximately 19-20% on its investment base. Wexpro's investment base is its investment in commercial wells and related facilities adjusted for working capital and reduced for deferred income taxes and depreciation. Wexpro's investment base totaled $431.9 million at December 31, 2009, an increase of $21.3 million or 5% since December 31, 2008. Wexpro produced 48.2 Bcf of cost-of-service gas in 2009.
MIDSTREAM FIELD SERVICES - Questar Gas Management
Gas Management reported net income of $69.4 million in 2009 compared to $81.5 million in 2008, a 15% decrease and $55.3 million in 2007. Net income was impacted by lower processing margins. Following is a summary of Gas Management financial and operating results:
QUESTAR 2009 FORM 10-K
Processing margin (processing revenue minus plant operating and maintenance expense, which includes processing plant-shrink) in 2009 decreased 15% to $66.1 million compared to $78.1 million in 2008. Fee-based gas processing volumes were 210.0 million MMBtu in 2009, a 4% increase compared to 2008. In 2009, fee-based gas processing revenues increased 12% or $3.4 million, while the frac spread from keep-whole processing decreased 24% or $13.5 million. Approximately 81% of Gas Management's net operating revenue (revenue minus processing plant-shrink) in 2009 was derived from fee-based contracts, up from 75% in 2008. Gas Management may use forward sales contracts to reduce margin volatility associated with keep-whole contracts. Forward sales contracts had no impact in 2009 and reduced NGL revenues by $1.4 million in 2008.
Gathering margin (gathering revenue minus gathering operating and maintenance expense) in 2009 increased 5% to $123.5 million compared to $117.1 million in 2008. Expanding Pinedale production and new projects serving third parties in the Uinta Basin contributed to a 10% increase in third-party volumes in 2009. Gathering volumes increased 21.3 million MMBtu, or 5% to 413.8 million MMBtu in 2009. Rendezvous was consolidated with Gas Management beginning in 2008. Rendezvous provides gas gathering services for the Pinedale and Jonah producing areas of Wyoming.
ENERGY MARKETING - Questar Energy Trading
Energy Trading net income was $8.5 million in 2009, a decrease of 62% compared to 2008 net income of $22.1 million and 2007 net income of $20.8 million as a result of lower marketing and storage margins. Revenues from unaffiliated customers were $425.6 million in 2009 compared to $608.1 million in 2008, a 30% decrease, primarily the result of lower natural gas prices. The weighted-average natural gas sales price decreased 48% in 2009 to $3.29 per MMBtu, compared to $6.34 per MMBtu in 2008.
INTERSTATE GAS TRANSPORTATION - Questar Pipeline
Questar Pipeline reported 2009 net income of $58.2 million compared with $58.0 million in 2008, and $45.0 million in 2007. Operating income increased $2.3 million, or 2%, in 2009 compared to 2008 because of asset impairments recorded in 2008. Operating income increased $21.9 million, or 24%, in 2008 compared to 2007 due primarily to transportation-system expansions that were placed in service in late 2007. Following is a summary of Questar Pipeline financial and operating results:
QUESTAR 2009 FORM 10-K
Revenues
Following is a summary of major changes in Questar Pipeline revenues for 2009 compared with 2008 and 2008 compared with 2007:
QUESTAR 2009 FORM 10-K
As of December 31, 2009, Questar Pipeline had firm-transportation contracts of 4,243 Mdth per day, including 1,020 Mdth per day from Questar Pipeline's 50% ownership of White River Hub, compared with 4,155 Mdth per day as of December 31, 2008 and 3,112 Mdth per day as of December 31, 2007. Questar Pipeline has expanded its transportation system in response to growing regional natural gas production and transportation demand. In November 2007, Questar Pipeline placed an expansion of its southern system in service. The southern system expansion increased Questar Pipeline's 2008 firm-transport demand by 175 Mdth per day and revenues by $13.8 million compared to 2007. In December 2007, Questar Overthrust Pipeline placed the Wamsutter expansion project into service. The Wamsutter expansion increased Questar Overthrust Pipeline firm-transport demand by 750 Mdth per day and revenues by $31.2 million in 2008 compared to 2007. Questar Overthrust Pipeline completed a system expansion of its pipeline between Rock Springs and Wamsutter in December 2009 by adding a compressor at its existing Rocks Springs Station and constructing a new compressor station at Point of Rocks, midway between Rock Springs and Wamsutter. The Company has firm contracts for 300 Mdth per day that begins in the first quarter of 2010 and utilizes the expansion capacity.
Questar Gas is Questar Pipeline's largest transportation customers with contracts for 901 Mdth per day. The majority of the Questar Gas transportation contracts extend through mid 2017. The Rockies Express Pipeline has a lease on the Questar Overthrust Pipeline for 625 Mdth per day through 2027. Wyoming Interstate Company has contracts on the Questar Overthrust Pipeline for 125 Mdth per day through 2019 and for 380 Mdth per day through 2020. In addition, Wyoming Interstate Company has three contracts on Questar Overthrust Pipeline for transportation from Wamsutter to the proposed Ruby Pipeline near Opal that ramp up to 548.5 Mdth per day by 2015. Two of the contracts start in the first quarter of 2010 and one starts in early 2011 with terms ranging from 10 to 12 years. Questar Overthrust Pipeline has filed with the FERC for authorization to construct a 43 mile, 36-inch pipeline loop of its system from Rock Springs west to its Cabin 31 facility to support the Wyoming Interstate Company contracts.
Questar Pipeline owns and operates the Clay Basin underground storage complex in eastern Utah. This facility is 100% subscribed under long-term contracts. In addition to Clay Basin, Questar Pipeline also owns and operates three smaller aquifer gas storage facilities. Questar Gas has contracted for 26% of firm-storage capacity at Clay Basin for terms extending from three to eight years and 100% of the firm-storage capacity at the aquifer facilities for terms extending for eight years.
Questar Pipeline charges FERC-approved transportation and storage rates that are based on straight-fixed-variable rate design. Under this rate design, all fixed costs of providing service including depreciation and return on investment are recovered through the demand charge. About 95% of Questar Pipeline costs are fixed and recovered through these demand charges. Questar Pipeline's earnings are driven primarily by demand revenues from firm shippers. Since only about 5% of operating costs are recovered through volumetric charges, changes in transportation volumes do not have a significant impact on earnings.
NGL sales were 22% lower in 2009 compared to 2008 due to a 46% decrease in NGL prices offsetting a 42% increase in sales volume. NGL sales were 69% higher in 2008 over 2007 due primarily to a 43% increase in NGL prices and an 18% increase in sales volume.
Expenses
Operating and maintenance expenses increased by 8% to $40.1 million in 2009 compared to $37.1 million in 2008 and $33.0 million in 2007 as a result of system expansions and higher labor and service costs. General and administrative expenses decreased 2% to $36.1 million in 2009 compared with $36.8 million in 2008 and $36.0 million in 2007. Operating, maintenance, general and administrative expenses per dth transported declined to $0.10 in 2009 and 2008 compared with $0.14 in 2007. Operating, maintenance, general and administrative expenses include processing and storage costs.
QUESTAR 2009 FORM 10-K
Depreciation expense increased 4% in 2009 compared to 2008 and increased 22% in 2008 compared to 2007 due to investment in pipeline expansions.
Sale of processing plant and gathering lines
Questar Transportation Services, a subsidiary of Questar Pipeline, sold a carbon dioxide processing plant and some associated gathering facilities in the second quarter of 2008. The net investment in these facilities was $20.0 million. The transaction closed in April 2008 and resulted in a pre-tax gain of $3.9 million.
Impairment
There were no impairments in 2009. Charges for asset impairment amounted to $14.0 million in 2008. Questar Pipeline impaired the entire $10.6 million investment in a potential salt cavern storage project located in southwestern Wyoming in the second quarter of 2008 based on a technical and economic evaluation of the project. In the fourth quarter of 2008, Questar Pipeline also took a $3.4 million pre-tax charge for impairment of certain costs associated with the California segment of its Southern Trails Pipeline.
RETAIL GAS DISTRIBUTION - Questar Gas
Questar Gas reported net income of $41.6 million in 2009 compared with $40.2 million in 2008 and $37.4 million in 2007. Operating income increased $2.7 million in 2009 compared with 2008 and increased $8.1 million or 11% in 2008 compared with 2007 due primarily to higher revenues from new-customer growth and the outcome of a rate case that authorized higher recovery in rates of certain costs. Following is a summary of Questar Gas financial and operating results:
QUESTAR 2009 FORM 10-K
Margin Analysis
Questar Gas's margin (revenues less gas costs) increased $29.9 million in 2009 compared to 2008 and increased $18.1 million in 2008 compared to 2007. Following is a summary of major changes in Questar Gas's margin for 2009 compared to 2008 and 2008 compared to 2007:
At December 31, 2009, Questar Gas served 898,558 customers, up from 888,602 at December 31, 2008. New-customer growth increased the margin by $2.6 million in 2009 and $3.9 million in 2008.
Temperature-adjusted usage per customer decreased 1% in 2009 compared with 2008 and decreased 1% in 2008 compared with 2007. The impact on the company margin from changes in usage per customer has been mitigated by a conservation-enabling tariff (CET) that was approved by the PSCU beginning 2006. The CET resulted in a margin decrease of $4.0 million in 2009 and a margin increase of $1.0 million in 2008.
Weather, as measured in degree days, was 5% colder than normal in 2009 and 8% colder than normal in 2008. A weather-normalization adjustment on customer bills generally offsets financial impacts of moderate temperature variations.
In December 2007, Questar Gas filed a general rate case in Utah. In the second quarter of 2008, Questar Gas received an order from the PSCU increasing rates by $12.0 million. The PSCU reduced Questar Gas's allowed return on equity from 11.2% to 10%. The new rates went into effect in mid-August 2008 and increased the margin by $6.2 million in 2009 and $4.1 million in 2008.
In August 2008, Questar Gas filed a general rate case in Wyoming. In the second quarter of 2009, Questar Gas received an order from the PSCW increasing rates by $0.4 million effective July 2009. The PSCW allowed a return on equity of 10.5%.
Questar Gas filed a general rate case in Utah in December 2009, requesting an allowed return on equity of 10.6%, an increase in rates of $17.2 million, a mechanism to adjust rates for investment in feeder line replacement, and a continuation of the CET.
Expenses
Cost of natural gas sold decreased 15% in 2009 compared with 2008 due to a decrease in the cost of purchased gas. Cost of natural gas sold increased 7% in 2008 compared with 2007 due to a 6% increase in sales volumes and an increase in the cost of natural gas. Questar Gas accounts for purchased-gas costs in accordance with procedures authorized by the PSCU and the PSCW. Purchased-gas costs that are different from those provided for in present rates are accumulated and recovered or credited through future rate changes. As of December 31, 2009, Questar Gas had a $22.1 million over-collected balance in the purchased-gas adjustment account representing costs recovered from customers in excess of costs incurred.
QUESTAR 2009 FORM 10-K
Operating and maintenance expenses increased $19.3 million in 2009 compared to 2008 due to a $20.2 million increase in DSM costs recovered from customers. Bad debt costs decreased $3.0 million. Operating and maintenance expenses increased $13.7 million or 19% in 2008 compared to 2007 due primarily to $3.9 million higher bad-debt costs, $5.9 million higher demand-side management costs and $1.4 million higher labor costs. General and administrative costs increased $4.2 million in 2009 compared to 2008 due to higher labor costs. General and administrative expenses decreased $6.8 million or 15% in 2008 compared to 2007 due to $3.5 million lower labor costs and $1.4 million lower legal costs. The sum of operating, maintenance, general and administrative expenses per customer was $166 in 2009 compared to $142 in 2008 and $136 in 2007. DSM costs per customer amounted to $30 in 2009 compared to $7 in 2008 and $1 in 2007.
Depreciation expense increased 6% in 2009 compared to 2008 and increased 7% in 2008 compared to 2007 as a result of plant additions from customer growth and system expansion.
Consolidated Results below Operating Income
Interest and Other Income
Interest and other income decreased $10.7 million or 40% in 2009 compared with 2008 after increasing $12.4 million or 87% in 2008 compared with 2007. The details of interest and other income for 2009, 2008 and 2007 are shown in the table below:
Income from unconsolidated affiliates
Income from unconsolidated affiliates was $6.5 million in 2009 compared to $2.3 million in 2008 and $8.9 million in 2007. White River accounted for $3.2 million of the 2008 to 2009 increase. Rendezvous Gas Services, which represented the majority of income from unconsolidated affiliates in 2007, was consolidated beginning in 2008.
Realized and unrealized gain (loss) on basis-only swaps
The Company has used basis-only swaps to manage the risk of widening basis differentials. Basis-only swaps do not qualify for hedge accounting. As of December 31, 2009, all of the Company's basis-only swaps were paired with fixed-price swaps and re-designated as cash flow hedges. Changes in the fair value of the derivative instruments subsequent to the re-designation were recorded in accumulative other comprehensive income. Fair value changes occurring prior to re-designation were recorded in income. The Company recognized unrealized mark-to-market losses of $164.0 million in 2009, $79.2 million in 2008 and $5.7 million gain in 2007. The Company realized losses of $25.6 million on settlements of basis-only swaps in 2009.
Interest expense
Interest expense rose 8% in 2009 compared with 2008 and 66% in 2008 compared to 2007 due primarily to permanent financing activities associated with the purchase of natural gas development properties in northwest Louisiana and pipeline expansions. Interest rates on the Company's commercial-paper borrowings in 2009 averaged less than 1% per annum after reaching the highest level in recent years in September 2008. Capitalized interest charges on construction projects amounted to $1.2 million in 2009 compared to $6.1 million in 2008 and $8.0 million in 2007.
Income taxes
The effective combined federal and state income tax rate was 35.9% in 2009 compared with 35.3% in 2008 and 36.4% in 2007.
QUESTAR 2009 FORM 10-K
LIQUIDITY AND CAPITAL RESOURCES
Operating Activities
Net cash provided by operating activities increased 5% in 2009 compared to 2008 and 31% in 2008 compared to 2007. Noncash adjustments to net income consisted primarily of depreciation, depletion and amortization, and deferred income taxes. Cash sources from operating assets and liabilities were lower in 2009 primarily due to changes in the values of inventories and receivables. Receivables decreased at December 31, 2009, because of lower natural gas prices for gas distribution. Net cash provided by operating activities is presented below:
Investing Activities
Capital spending in 2009 amounted to $1,498.2 million. The details of capital expenditures in 2009 and 2008 and a forecast for 2010 are shown in the table below:
Questar E&P and Wexpro
Questar E&P capital expenditures decreased in 2009 compared to 2008 due to lower property acquisitions in 2009 and a commodity-price constrained drilling program in 2009. In February 2008, Questar E&P acquired natural gas development properties in northwest Louisiana for an aggregate purchase price of $652.1 million. During 2009, Questar E&P and Wexpro participated in 437 wells (197.6 net), resulting in 193.6 net successful gas and oil wells and 4.0 net dry or abandoned wells. The 2009 net drilling-success rate was 98.0%. There were 116 gross wells in progress at year-end.
Questar Gas Management
Market Resources also increased investment in its midstream gathering and processing-services business to expand capacity in both western Wyoming and eastern Utah in anticipation of growing production volumes.
Questar Pipeline
Questar Overthrust Pipeline completed a system expansion of its pipeline between Rock Springs and Wamsutter in December 2009 by adding a compressor at its Rock Springs Station and constructing the new Point of Rocks compressor station.
Questar Gas
During 2009, Questar Gas added 1,215 miles of main, feeder and service lines to provide service to additional customers and replaced high-pressure feeder lines.
QUESTAR 2009 FORM 10-K
Financing Activities
As a result of the recent economic downturn, the Company limited 2009 capital expenditures to internally generated cash flow. In 2009, net cash provided by operating activities of $1,578.2 million exceeded net cash used in investing activities of $1,484.1 million by $94.1 million reflecting the strategy. Long-term debt increased by a net change of $55.8 million and short-term debt decreased by a net change of $62.1 million. In 2008, the acquisition of natural gas development properties in northwest Louisiana resulted in net cash used in investing activities of $2,358.7 million exceeding net cash flow by operating activities by $862.5 million. In 2008, long-term debt increased by $990.4 million net and short-term debt decreased by $29.5 million.
In August 2009, Market Resources issued $300.0 million of notes due March 2020 with a 6.82% effective interest rate and used the net proceeds to reduce the balance outstanding under its long-term revolving-credit facility. In September 2009, Questar Pipeline issued $50.0 million of notes due February 2018 with a 5.40% effective interest rate and used the net proceeds to repay $42.0 million of long-term notes that matured in October 2009.
Questar's consolidated capital structure consisted of 40% combined short- and long-term debt and 60% common shareholders' equity at December 31, 2009, compared to 41% combined short- and long-term debt and 59% common shareholders' equity a year earlier. At December 31, 2009, Market Resources had unused capacity of $600.0 million on a revolving-credit facility with banks. The Company has no long-term debt maturing until 2011 and as of the end of the year, when commercial paper issuance typically peaks to buy gas at Questar Gas for the heating season; there was $866 million in unused availability under committed credit lines.
Questar issues commercial paper, rated A2 by Standard & Poor's Corporation and P2 by Moody's Investors Services, to meet short-term financing requirements. The Company maintains committed credit lines with banks to provide liquidity support. Credit commitments under the bank lines totaled $435.0 million at December 31, 2009, with no amounts borrowed. Commercial paper outstanding amounted to $169.0 million at December 31, 2009 compared with $231.1 million a year earlier. The table below sets forth credit ratings for Questar and its subsidiaries. The outlook associated with each rating is deemed stable by each rating agency:
Contractual Cash Obligations and Other Commitments
In the course of ordinary business activities, Questar enters into a variety of contractual cash obligations and other commitments. The following table summarizes the significant contractual cash obligations as of December 31, 2009:
The Company had $200.0 million of variable-rate long-term debt outstanding under Market Resources' revolving-credit facility with an interest rate of 0.73%. December 31, 2009.
Critical Accounting Policies, Estimates and Assumptions
Questar's significant accounting policies are described in Note 1 to the consolidated financial statements included in Item 8 of Part II of this Annual Report. The Company's consolidated financial statements are prepared in accordance with U.S. generally accepted accounting principles. The preparation of consolidated financial statements requires management to make assumptions
QUESTAR 2009 FORM 10-K
and estimates that affect the reported results of operations and financial position. The following accounting policies may involve a higher degree of complexity and judgment on the part of management.
Gas and Oil Reserves
Gas and oil reserve estimates require significant judgments in the evaluation of all available geological, geophysical, engineering and economic data. The data for a given field may change substantially over time as a result of numerous factors including, but not limited to, additional development activity, production history, and economic assumptions relating to commodity prices, production costs, severance and other taxes, capital expenditures and remediation costs. The subjective judgments and variances in data for various fields make these estimates less precise than other estimates included in the financial statement disclosures. See Note 17 to the consolidated financial statements included in Item 8 of Part II of this Annual Report for more information on the Company's estimated proved reserves.
Successful Efforts Accounting for Gas and Oil Operations
The Company follows the successful efforts method of accounting for gas- and oil-property acquisitions, exploration, development and production activities. Under this method, the acquisition costs of proved and unproved properties, successful exploratory wells and development wells are capitalized. Other exploration costs, including geological and geophysical costs, the delay rental and administrative costs associated with unproved property and unsuccessful exploratory well costs are expensed. Costs to operate and maintain wells and field equipment are expensed as incurred.
The capitalized costs of unproved properties are generally combined and amortized over the expected holding period for such properties. Individually significant unproved properties are periodically reviewed for impairment. Capitalized costs of unproved properties are reclassified as proved property when related proved reserves are determined or charged against the impairment allowance when abandoned.
Capitalized proved-property-acquisition costs are amortized by field using the unit-of-production method based on proved reserves. Capitalized exploratory-well and development costs are amortized similarly by field based on proved developed reserves. The calculation takes into consideration estimated future equipment dismantlement, surface restoration and property-abandonment costs, net of estimated equipment-salvage values. Other property and equipment are generally depreciated using the straight-line method over estimated useful lives or the unit-of-production method for certain processing plants. A gain or loss is generally recognized only when an entire field is sold or abandoned, or if the unit-of-production amortization rate would be significantly affected.
Questar E&P engages an independent reservoir-engineering consultant to prepare estimates of the proved gas and oil reserves. Reserve estimates are based on a complex and highly interpretive process that is subject to continuous revision as additional production and development-drilling information becomes available.
Long-lived assets are assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in the future cash flows expected to be generated on a field-by-field basis. Impairment is indicated when a triggering event occurs and the sum of estimated undiscounted future net cash flows of the evaluated asset is less than the asset's carrying value. The asset value is written down to estimated fair value, which is determined using discounted future net cash flows.
Accounting for Derivative Contracts
The Company uses derivative contracts, typically fixed-price swaps and costless collars, to hedge against a decline in the realized prices of its gas and oil production. Accounting rules for derivatives require marking these instruments to fair value at the balance-sheet reporting date. The change in fair value is reported either in net income or Accumulated Other Comprehensive Income (AOCI) depending on the structure of the derivative. The Company has historically structured substantially all energy-derivative instruments as cash flow hedges as defined in ASC 815 "Derivatives and Hedging." Changes in the fair value of cash flow hedges are recorded on the balance sheet and in AOCI or loss until the underlying gas or oil is produced. When a derivative is terminated before its contract expires, the associated gain or loss is recognized in income over the life of the previously hedged production.
Revenue Recognition
Revenues are recognized in the period that services are provided or products are delivered. Questar E&P uses the sales method of accounting whereby revenue is recognized for all gas, oil and NGL sold to purchasers. Revenues include estimates for the two most recent months using published commodity-price indexes and volumes supplied by field operators. A liability is recorded to the extent that Questar E&P has an imbalance in excess of its share of remaining reserves in an underlying property. Energy Trading presents revenues on a gross-revenue basis. Energy Trading does not engage in speculative hedging transactions, nor does it buy and sell energy contracts with the objective of generating profits on short-term differences in prices.
Questar Gas estimates revenues on a calendar basis even though bills are sent to customers on a cycle basis throughout the month.
QUESTAR 2009 FORM 10-K
The company estimates unbilled revenues for the period from the date meters are read to the end of the month, using usage history and weather information. Approximately one-half month of revenues is estimated in any period. The gas costs and other variable costs are recorded on the same basis to ensure proper matching of revenues and expenses.
Questar Gas tariff provides for monthly adjustments to customer bills to approximate the impact of normal temperatures on non-gas revenues. Questar Gas estimates the weather-normalization adjustment for the unbilled revenue each month. The weather-normalization adjustment is evaluated each month and reconciled on an annual basis in the summer to agree with the amount billed to customers. In 2006, the PSCU approved a three-year pilot program for a conservation enabling tariff effective January 1, 2006, to promote energy conservation. Under the CET, Questar Gas non-gas revenues are decoupled from the volume of gas used by customers. The tariff specifies a margin per customer for each month with differences to be deferred and recovered from customers or refunded to customers through periodic rate adjustments. These adjustments are limited to five percent of non-gas revenues.
Rate Regulation
Regulatory agencies establish rates for the storage, transportation, distribution and sale of natural gas. The regulatory agencies also regulate, among other things, the extension and enlargement or abandonment of jurisdictional natural gas facilities. Regulation is intended to permit the recovery, through rates, of the cost of service, including a return on investment. Questar Gas and Questar Pipeline follow ASC 980 "Regulated Operations," that requires the recording of regulatory assets and liabilities by companies subject to cost-based regulation. The FERC, PSCU and PSCW have accepted the recording of regulatory assets and liabilities.
Employee Benefit Plans
The Company has defined-benefit pension and life insurance plans covering a majority of its employees and a postretirement medical plan providing coverage to less than half of its current employees. The calculation of the Company's expense and liability associated with its benefit plans requires the use of assumptions that the Company deems to be critical. Changes in these assumptions can result in different expenses and liabilities and actual experience can differ from these assumptions.
Independent consultants hired by the Company use actuarial models to calculate estimates of pension and postretirement benefits expense. The models use key factors such as mortality estimations, liability discount rates, long-term rates of return on investments, rates of compensation increases, amortized gain or loss from investments and medical-cost trend rates. Management formulates assumptions based on market indicators and advice from consultants. The Company believes that the liability discount rate and the expected long-term rate of return on benefit plan assets are critical assumptions.
The assumed liability discount rate reflects the current rate at which the pension benefit obligations could effectively be settled. Management considers the rates of return on high-quality, fixed-income investments and compares those results with a bond-defeasance technique. The Company discounted its future pension liabilities using rates of 6.50% as of December 31, 2009 and 2008. A 0.25% decrease in the discount rate would increase the Company's 2010 estimated annual pension expense by about $1.7 million.
The expected long-term rate of return on benefit-plan assets reflects the average rate of earnings expected on funds invested or to be invested for purposes of paying pension benefits. The Company establishes the expected long-term rate of return at the beginning of each fiscal year giving consideration to the benefit plan's investment mix and historical and forecasted rates of return on these types of securities. The expected long-term rate of return determined by the Company was 7.5% as of January 1, 2009 and 8.0% as of January 1,2008. The rate as of January 1, 2010, is 7.25%. Benefit plan expense typically increases as the expected long-term rate of return on plan assets decreases. A 0.25% decrease in the expected long-term rate of return causes an approximate $0.7 million increase in the 2010 qualified pension expense.
Recent Accounting Developments
Refer to Note 1 to the consolidated financial statements included in Item 8 of Part II of this Annual Report for a discussion of recent accounting developments.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
Questar's primary market-risk exposure arises from changes in the market price for natural gas, oil and NGL, and volatility in interest rates. Energy Trading has long-term contracts for pipeline capacity and is obligated to pay for transportation services with no guarantee that it will be able to fully utilize the contractual capacity of these transportation commitments.
QUESTAR 2009 FORM 10-K
Commodity-Price Risk Management
Market Resources' subsidiaries use commodity-price derivative instruments in the normal course of business to reduce the risk of adverse commodity-price movements. However, these same arrangements typically limit future gains from favorable price movements. Derivative contracts are currently in place for a significant share of Questar E&P-owned gas and oil production and a portion of Energy Trading gas-marketing transactions.
As of December 31, 2009, Market Resources held commodity-price derivative contracts for 409.6 million MMBtu of natural gas and 2.7 million barrels of oil. A year earlier Market Resources held derivative contracts for 234.4 million MMBtu of natural gas, 0.7 million barrels of oil and natural gas basis-only swaps on an additional 204.9 Bcf. A table of the Market Resources derivative positions for equity production as of December 31, 2009, is shown below:
A table of the net fair value of gas- and oil-derivative contracts as of December 31, 2009, is shown below. Cash flow hedges representing 72% of the net fair value will settle in the next 12 months and will be reclassified from AOCI:
The following table shows the sensitivity of fair value of gas- and oil-derivative contracts and basis-only swaps to changes in the market price of gas and oil and basis differentials:
Credit Risk
Market Resources requests credit support and, in some cases, prepayment from companies that pose unfavorable credit risks. Market Resources' five largest customers are Sempra Energy Trading Corp., Chevron USA Inc., Enterprise Products Operating, Texla Energy Management Inc. and BP Energy Company. Sales to these companies accounted for 23% of Market resources revenues before elimination of intercompany transactions in 2009, and their accounts were current at December 31, 2009.
QUESTAR 2009 FORM 10-K
Questar Pipeline requests credit support, such as letters of credit and cash deposits, from companies that pose unfavorable credit risks. All companies posing such concerns were current on their accounts at December 31, 2009. Questar Pipeline's largest customers include Questar Gas, Rockies Express Pipeline, EOG Resources, XTO Energy, Wyoming Interstate Pipeline, EnCana Marketing and PacifiCorp.
Questar Gas requires deposits from customers that pose unacceptable credit risks. No single customer accounted for a significant portion of revenue in 2009.
Interest-Rate Risk
The fair value of fixed-rate debt is subject to change as interest rates fluctuate. The Company's ability to borrow and the rates quoted by lenders can be adversely affected by the illiquid credit markets as described in Item 1A. Risk Factors of Part I of this Annual Report on Form 10-K. The Company had $2,179.9 million of fixed-rate long-term debt with a fair value of $2,289.2 million at December 31, 2009. A year earlier the Company had $2,122.2 million of fixed-rate long-term debt with a fair value of $1,994.8 million. If interest rates had declined 10%, fair value would increase to $2,356.7 million in 2009 and $2,061.4 million in 2008. The fair value calculations do not represent the cost to retire the debt securities.
Climate-Change Risk
Federal and state courts and administrative agencies are considering the scope and scale of climate-change regulation under various laws pertaining to the environment, energy use and development, and greenhouse gas emissions. Questar's ability to access and develop new natural gas reserves may be restricted by climate-change regulation. There are bills pending in Congress that would regulate greenhouse gas emissions through a cap-and-trade system under which emitters would be required to buy allowances for offsets of emissions of greenhouse gases. The EPA has adopted final regulations for the measurement and reporting of greenhouse gases emitted from certain large facilities (25,000 tons/year of CO2 equivalent) beginning with operations in 2010. The first report is to be filed with the EPA by March 31, 2011. In addition, several of the states in which Questar operates are considering various greenhouse gas registration and reduction programs. Carbon dioxide regulation could increase the price of natural gas, restrict access to or the use of natural gas, and/or reduce natural gas demand. Federal, state and local governments may also pass laws mandating the use of alternative energy sources, such as wind power and solar energy, which may reduce demand for natural gas. While future climate-change regulation is likely, it is too early to predict how this regulation will affect Questar's business, operations or financial results. It is uncertain whether Questar's operations and properties, located in the Rocky Mountain and Midcontinent regions of the United States, are exposed to possible physical risks, such as severe weather patterns, due to climate change as a result of man-made greenhouse gases. However, management does not believe that such physical risks are reasonably likely to have a material effect on the company's financial condition or results of operations.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
Page No.
Financial Statements:
Report of Independent Registered Public Accounting Firm
Consolidated Statements of Income, three years ended December 31, 2009
Consolidated Balance Sheets at December 31, 2009 and 2008
Consolidated Statements of Equity, three years ended December 31, 2009
Consolidated Statements of Cash Flows, three years ended December 31, 2009
Notes Accompanying the Consolidated Financial Statements
Financial Statement Schedules:
Valuation and Qualifying Accounts, for the three years ended December 31, 2009
All other schedules are omitted because they are not applicable or the required information is shown in the consolidated financial statements or Notes thereto.
QUESTAR 2009 FORM 10-K
Report of Independent Registered Public Accounting Firm
The Board of Directors and Shareholders of
Questar Corporation
We have audited the accompanying consolidated balance sheets of Questar Corporation as of December 31, 2009 and 2008, and the related consolidated statements of income, common shareholders' 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 8. 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 Questar Corporation at December 31, 2009 and 2008, and the consolidated results of its operations and its 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 1 to the consolidated financial statements, during 2009, the Company adopted a new accounting standard relating to the presentation of noncontrolling interests in consolidated subsidiaries and the Company adopted new oil and gas reserve estimation and disclosure requirements.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Questar Corporation's 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 26, 2010, expressed an unqualified opinion thereon.
/s/Ernst & Young LLP
Ernst & Young LLP
Salt Lake City, Utah
February 26, 2010
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See notes accompanying the consolidated financial statements
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See notes accompanying the consolidated financial statements
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See notes accompanying the consolidated financial statements
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See notes accompanying the consolidated financial statements
QUESTAR 2009 FORM 10-K
QUESTAR CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1 - Summary of Significant Accounting Policies
Nature of Business
Questar Corporation (Questar or the Company) is a natural gas-focused energy company with five major lines of business - gas and oil exploration and production, midstream field services, energy marketing, interstate gas transportation, and retail gas distribution - which are conducted through its three principal subsidiaries:
·
Questar Market Resources, Inc. (Market Resources) is a subholding company that operates through four principal subsidiaries. Questar Exploration and Production Company (Questar E&P) acquires, explores for, develops and produces natural gas, oil and NGL. Wexpro Company (Wexpro) manages, develops and produces cost-of-service reserves for gas utility affiliate Questar Gas. Questar Gas Management Company (Gas Management) provides midstream field services including natural gas-gathering and processing services for affiliates and third parties. Questar Energy Trading Company (Energy Trading) markets equity and third-party natural gas and oil, provides risk-management services and owns and operates an underground gas-storage reservoir.
·
Questar Pipeline Company (Questar Pipeline) provides interstate natural gas transportation and storage and other energy services.
·
Questar Gas Company (Questar Gas) provides retail natural gas distribution services in Utah, Wyoming and Idaho.
Accounting Standards References
In July 2009 the Financial Accounting Standards Board (FASB) completed a revision of non-governmental U.S. generally accepted accounting principles (GAAP) into a single authoritative source and issued a codification of accounting rules and references. Authoritative standards included in the codification are designated by their Accounting Standards Codification (ASC) topical reference, and revised standards are designated as Accounting Standards Updates (ASU), with a year and assigned sequence number. The codification effort, while not creating or changing accounting rules, changed how users would cite accounting regulations. Citations in financial statements must identify the sections within the new codification. The codification is effective for interim and annual periods ending after September 15, 2009. The Company is complying with the new codification standards.
Principles of Consolidation
The consolidated financial statements contain the accounts of Questar and its majority-owned or controlled subsidiaries. The consolidated financial statements were prepared in accordance GAAP and with the instructions for annual reports on Form 10-K and Regulations S-X and S-K. Rendezvous Gas Services, an affiliate, was consolidated beginning in 2008 as a result of a step acquisition caused by disproportionate ownership. Gas Management's ownership interest increased from 50% to 78%. All significant intercompany accounts and transactions have been eliminated in consolidation.
On January 1, 2009, Questar adopted "Noncontrolling Interests in Consolidated Financial Statements" (ASC 810-10-65-1) for the accounting, reporting and disclosure of noncontrolling interests. The new guidance requires that noncontrolling interest, previously known as minority interest, be clearly identified, labeled, and presented in the consolidated financial statements separate from the parent's equity; the amount of consolidated net income attributable to the parent and to the noncontrolling interest be clearly identified and presented in the consolidated income statement; changes in a parent's ownership interest while the parent retains its controlling financial interest in its subsidiary be accounted for consistently; and any retained noncontrolling equity investment in a former subsidiary be initially measured at fair value. The new provisions are applied prospectively from the date of adoption, except for the presentation and disclosure requirements, which are applied retrospectively for all periods presented.
SEC's Modernization of Oil and Gas Reporting Requirements
In December 2008, the SEC issued Release No. 33-8995, "Modernization of Oil and Gas Reporting," which amends the oil and gas disclosures for oil and gas producers contained in Regulations S-K and S-X. The goal of Release No. 33-8995 is to provide investors with a more meaningful and comprehensive understanding of oil and gas reserves. The most significant amendments affecting the Company include the following: (i) economic producibility of reserves and discounted cash flows are to be based on the arithmetic average of the price on the first day of each month within the 12-month period prior to the end of the reporting period, unless contractual arrangements designate the price to be used; and (ii) reserves may be estimated and categorized through the use of reliable technologies. Release No. 33-8995 is effective for financial statements for fiscal years ending on or after December 31, 2009.
QUESTAR 2009 FORM 10-K
Investment in Unconsolidated Affiliates
Questar uses the equity method to account for investment in unconsolidated affiliates where it does not have control, but has significant influence. Generally, the investment in unconsolidated affiliates on the Company's consolidated balance sheets equals the Company's proportionate share of equity reported by the unconsolidated affiliates. Investment is assessed for possible impairment when events indicate that the fair value of the investment may be below the Company's carrying value. When such a condition is deemed to be other than temporary, the carrying value of the investment is written down to its fair value, and the amount of the write-down is included in the determination of net income.
The principal unconsolidated affiliates and the Company's ownership percentage as of December 31, 2009, were White River Hub, LLC, a limited liability company (50%) engaged in interstate natural gas transportation and Uintah Basin Field Services, LLC, (38%) and Three Rivers Gathering, LLC, (50%) both limited liability companies engaged in gathering and compressing natural gas.
Use of Estimates
The preparation of consolidated financial statements and notes in conformity with GAAP requires that management formulate estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. The Company also incorporates estimates of proved developed and proved gas and oil reserves in the calculation of depreciation, depletion and amortization rates of its gas and oil properties. Changes in estimated quantities of its reserves could impact the Company's reported financial results as well as disclosures regarding the quantities and value of proved gas and oil reserves. Actual results could differ from these estimates.
Revenue Recognition
Market Resources' subsidiaries recognize revenues in the period that services are provided or products are delivered. Revenues reflect the impact of price-hedging instruments. Revenues associated with the production of gas and oil are accounted for using the sales method, whereby revenue is recognized as gas and oil is sold to purchasers. A liability is recorded to the extent that the company has sold volumes in excess of its share of remaining gas and oil reserves in an underlying property. Market Resources imbalance obligations at December 31, was $4.2 million in 2009 and $3.1 million in 2008.
Energy Trading reports revenues on a gross basis because, in the judgment of management, the nature and circumstances of its marketing transactions are consistent with guidance for gross revenue reporting. Questar is primarily engaged in gas and oil exploration and production, midstream field services, interstate gas transportation and retail gas distribution. Energy Trading markets equity and third-party natural gas, oil and NGL volumes. Energy Trading uses derivatives to secure a known price for a specific volume over a specific time period. Energy Trading does not engage in speculative hedging transactions, nor does it buy and sell energy contracts with the objective of generating profits on short-term differences in price. Energy Trading has not engaged in buy/sell arrangements, as described in ASC 845-10-25-4 "Accounting for Purchases and Sales of Inventory with the Same Counterparty."
Questar Pipeline and subsidiaries recognize revenues in the period that services are provided. The straight fixed-variable rate design used by Questar Pipeline, which allows for recovery of substantially all fixed costs in the demand or reservation charge, reduces the earnings impact of volume changes on gas-transportation and storage operations. Rate-regulated companies may collect revenues subject to possible refunds and establish reserves pending final orders from regulatory agencies.
Questar Gas records revenues for gas delivered to residential and commercial customers but not billed as of the end of the accounting period. Unbilled gas deliveries are estimated for the period from the date meters are read to the end of the month. Approximately one-half month of revenue is estimated in any period. Gas costs and other variable costs are recorded on the same basis to ensure proper matching of revenues and expenses. Questar Gas tariff allows for monthly adjustments to customer bills to approximate the effect of abnormal weather on non-gas revenues. The weather-normalization adjustment significantly reduces the impact of weather on gas-distribution earnings. The Public Service Commission of Utah (PSCU) approved a "conservation enabling tariff" (CET), to promote energy conservation. Under the CET, Questar Gas non-gas revenues are decoupled from the volume of gas used by customers. The tariff specifies a margin per customer for each month with differences to be deferred and recovered from customers or refunded to customers through periodic rate adjustments. Rate adjustments occur every six months under the CET program. The adjustments amortize deferred CET amounts over a 12-month period. These adjustments are limited to five percent of non-gas revenues.
Regulation
Questar Gas is regulated by the PSCU and the Public Service Commission of Wyoming (PSCW). The Idaho Public Utilities Commission has contracted with the PSCU for rate oversight of Questar Gas operations in a small area of southeastern Idaho. Questar Pipeline is regulated by the Federal Energy Regulatory Commission (FERC). Market Resources, through its subsidiary Clear Creek Storage Company, LLC, operates a gas-storage facility under the jurisdiction of the FERC. These regulatory agencies establish rates for the storage, transportation and sale of natural gas. The regulatory agencies also regulate, among other things, the extension and enlargement or abandonment of jurisdictional natural gas facilities. Regulation is intended to permit the recovery, through rates, of the cost of service, including a return on investment.
QUESTAR 2009 FORM 10-K
The Company applies the regulatory accounting principles prescribed under ASC 980 "Regulated Operations" to the rate-regulated businesses. Under ASC 980, the Company records regulatory assets and liabilities that would not be recorded under GAAP for non-rate regulated entities. Regulatory assets and liabilities record probable future revenues or expenses associated with certain credits or charges that will be recovered from or refunded to customers through the rate-making process. See Note 12 for a description and comparison of regulatory assets and liabilities as of December 31, 2009 and 2008.
Cash and Cash Equivalents
Cash equivalents consist principally of repurchase agreements with maturities of three months or less. In almost all cases, the repurchase agreements are highly liquid investments in overnight securities made through commercial-bank accounts that result in available funds the next business day.
Purchased-Gas Adjustments
Questar Gas accounts for purchased-gas costs in accordance with procedures authorized by the PSCU and the PSCW. Purchased-gas costs that are different from those provided for in present rates are accumulated and recovered or credited through future rate changes. Questar Gas may hedge a portion of its natural gas supply to mitigate price fluctuations for gas-distribution customers. The regulatory commissions allow Questar Gas to record periodic mark-to-market adjustments for commodity-price derivatives in the purchased-gas-adjustment account.
Property, Plant and Equipment
Property, plant and equipment balances are stated at historical cost. Maintenance and repair costs are expensed as incurred with the exception of compressor maintenance costs, which are capitalized and depreciated based on hours of usage in accordance with ASC 360-10-25-5.
Gas and oil properties
Questar uses the successful efforts method to account for gas and oil properties. The costs of acquiring leaseholds, drilling development wells, drilling successful exploratory wells, purchasing related support equipment and facilities are capitalized. Geological and geophysical studies and other exploratory activities are expensed as incurred. Costs of production and general-corporate activities are expensed in the period incurred. A gain or loss is generally recognized only when an entire field is sold or abandoned, or if the unit-of-production depreciation, depletion and amortization rate would be significantly affected.
Capitalized costs of unproved properties are generally combined and amortized over the expected holding period for such properties. Capitalized costs of unproved properties are reclassified as proved property when related proved reserves are determined or charged against the impairment allowance when abandoned.
Capitalized exploratory well costs
The Company capitalizes exploratory-well costs until it determines whether an exploratory well is commercial or noncommercial. If the Company deems the well commercial, capitalized costs are depreciated on a field basis using the unit-of-production method and the estimated proved developed gas and oil reserves. If the Company concludes that the well is noncommercial, well costs are immediately charged to exploration expense. Exploratory-well costs capitalized for a period greater than one year since the completion of drilling are expensed unless the Company remains engaged in substantial activities to assess whether the well is commercial.
Cost-of-service gas and oil operations
The successful efforts method of accounting is used for "cost-of-service" reserves managed, developed and produced by Wexpro for gas utility affiliate Questar Gas. Cost-of-service reserves are properties for which the operations and return on investment are subject to the Wexpro Agreement (see Note 11). In accordance with the agreement, production from the gas properties operated by Wexpro is delivered to Questar Gas at Wexpro's cost of providing this service including a return on Wexpro's investment. Wexpro sells crude-oil production from certain oil-producing properties at market prices with the revenues used to recover operating expenses and to provide Wexpro a return on its investment. Any operating income remaining after recovery of expenses and Wexpro's return on investment is divided between Wexpro and Questar Gas, with Wexpro retaining 46%. Amounts received by Questar Gas from the sharing of Wexpro's oil income are used to reduce natural-gas costs to utility customers.
Contributions-in-aid-of construction
Customer contributions-in-aid-of construction reduce plant unless the amounts are refundable to customers. Contributions for main-line extensions may be refundable to customers if additional customers connect to the main-line segment within five years. Refundable contributions are recorded as liabilities until refunded or the five-year period expires without additional customer connections. Amounts not refunded reduce plant. Capital expenditures in the Consolidated Statements of Cash Flows are reported net of nonrefunded contributions.
QUESTAR 2009 FORM 10-K
Depreciation, depletion and amortization
Capitalized proved leasehold costs are depleted on a field-by-field basis using the unit-of-production method and the estimated proved gas and oil reserves. Oil and NGL volumes are converted to natural gas equivalents using the ratio of one barrel of crude oil, condensate or NGL to 6,000 cubic feet of natural gas. Capitalized costs of exploratory wells that have found proved gas and oil reserves and capitalized development costs are depreciated using the unit-of-production method based on estimated proved developed reserves on a field basis. The Company capitalizes an estimate of the fair value of future abandonment costs. Future abandonment costs, less estimated future salvage values, are depreciated over the life of the related asset using a unit-of-production method. The following rates per Mcfe represent the volume-weighted average depreciation, depletion and amortization rates of the Company's capitalized costs:
Depreciation, depletion and amortization for the remaining Company properties is based upon rates that will systematically charge the costs of assets against income over the estimated useful lives of those assets using either a straight-line or unit-of-production method. Investment in gas-gathering and processing fixed assets is charged to expense using either the straight-line or unit-of-production method depending upon the facility.
Major categories of fixed assets in gas-distribution, transportation and storage operations are grouped together and depreciated on a straight-line method. Under the group method, salvage value is not considered when determining depreciation rates. Gains and losses on asset disposals are recorded as adjustments in accumulated depreciation. The Company has not capitalized future-abandonment costs on a majority of its long-lived gas-distribution and transportation assets due to a lack of a legal obligation to restore the area surrounding abandoned assets. In these cases, the regulatory agencies have opted to leave retired facilities in the ground undisturbed rather than excavate and dispose of the assets. The following represent average depreciation and amortization rates of the Company's capitalized costs:
Impairment of Long-Lived Assets
Proved gas and oil properties are evaluated on a field-by-field basis for potential impairment. Other properties are evaluated on a specific-asset basis or in groups of similar assets, as applicable. Impairment is indicated when a triggering event occurs and the sum of the estimated undiscounted future net cash flows of an evaluated asset is less than the asset's carrying value. Triggering events could include, but are not limited to, an impairment of gas and oil reserves caused by mechanical problems, faster-than-expected decline of reserves, lease-ownership issues, other-than-temporary decline in gas and oil prices and changes in the utilization of pipeline assets. If impairment is indicated, fair value is calculated using a discounted-cash flow approach. Cash flow estimates require forecasts and assumptions for many years into the future for a variety of factors, including commodity prices and operating costs.
The Company also performs periodic assessments of individually significant unproved gas and oil properties for impairment and recognizes a loss at the time of impairment. In determining whether a significant unproved property is impaired the Company considers numerous factors including, but not limited to, current exploration plans, favorable or unfavorable exploration activity on adjacent leaseholds, in-house geologists' evaluations of the lease, and the remaining lease term.
Goodwill and Other Intangible Assets
Goodwill represents the excess of the amount paid over the fair value of net assets acquired in a business combination and is not subject to amortization. Goodwill and indefinite lived intangible assets are tested for impairment at a minimum of once a year or when a triggering event occurs. If a triggering event occurs, the undiscounted net cash flows of the intangible asset or entity to which the goodwill relates are evaluated. Impairment is indicated if undiscounted cash flows are less than the carrying value of the assets. The amount of the impairment is measured using a discounted cash flow model considering future revenues, operating costs, a risk-adjusted discount rate and other factors.
Capitalized Interest and Allowance for Funds Used During Construction (AFUDC)
The Company capitalizes interest costs when applicable. The FERC, PSCU and PSCW require the capitalization of AFUDC during the construction period of rate-regulated plant and equipment. The Wexpro Agreement requires capitalization of AFUDC
QUESTAR 2009 FORM 10-K
on cost-of-service construction projects, which is recorded in interest and other income. AFUDC on equity funds amounted to $2.6 million in 2009, $4.1 million in 2008 and $2.0 million in 2007 and increased interest and other income in the Consolidated Statements of Income. Interest expense was reduced by $1.2 million in 2009, $6.1 million in 2008 and $8.0 million in 2007.
Derivative Instruments
In November 2008, the Company adopted the updated disclosure provisions of ASC 815 "Derivatives and Hedging" and modified the disclosures accordingly. The Company may elect to designate a derivative instrument as a hedge of exposure to changes in fair value or cash flows. If the hedged exposure is a fair-value exposure, the gain or loss on the derivative instrument is recognized in earnings in the period of the change together with the offsetting gain or loss from the change in fair value of the hedged item. If the hedged exposure is a cash flow exposure, the effective portion of the gain or loss on the derivative instrument is reported initially as a component of AOCI and subsequently reclassified into earnings when the forecasted transaction affects earnings. Any amount excluded from the assessment of hedge effectiveness, as well as the ineffective portion of the gain or loss, is reported in the current period income statement. A derivative instrument qualifies as a cash flow hedge if all of the following tests are met:
·
The item to be hedged exposes the Company to price risk.
·
The derivative reduces the risk exposure and is designated as a hedge at the time the Company enters into the contract.
·
At the inception of the hedge and throughout the hedge period, there is a high correlation between changes in the market value of the derivative instrument and the fair value of the underlying hedged item.
When the designated item associated with a derivative instrument matures, is sold, extinguished or terminated, derivative gains or losses are included in income in the same period that the underlying production or other contractual commitment is delivered. When a derivative instrument is associated with an anticipated transaction that is no longer probable, the gain or loss on the derivative is reclassified from other comprehensive income and recognized currently in the results of operations. When a derivative is terminated before its contract expires, the associated gain or loss is recognized in income over the life of the previously hedged production.
Physical Contracts
Physical-hedge contracts have a nominal quantity and a fixed price. Contracts representing both purchases and sales settle monthly based on quantities valued at a fixed price. Purchase contracts fix the purchase price paid and are recorded as cost of sales in the month the contracts are settled. Sales contracts fix the sales price received and are recorded as revenues in the month they are settled. Due to the nature of the physical market, there is a one-month delay for the cash settlement. Market Resources accrues for the settlement of contracts in the current month's revenues and cost of sales.
Financial Contracts
Financial contracts are contracts that are net settled in cash without delivery of product. Financial contracts also have a nominal quantity and exchange an index price for a fixed price, and are net settled with the brokers as the price bulletins become available. Financial contracts are recorded in revenues or cost of sales in the month of settlement.
Basis-Only Swaps
Basis-only swaps are used to manage the risk of widening basis differentials. These contracts are marked-to-market monthly with any change in the valuation recognized in the determination of income.
Credit Risk
The Rocky Mountain and Midcontinent regions constitute the Company's primary market areas. Exposure to credit risk may be affected by the concentration of customers in these regions due to changes in economic or other conditions. Customers include individuals and numerous commercial and industrial enterprises that may react differently to changing conditions. Management believes that its credit-review procedures, loss reserves, customer deposits and collection procedures have adequately provided for usual and customary credit-related losses. Commodity-based hedging arrangements also expose the Company to credit risk. The Company monitors the creditworthiness of its counterparties, which generally are major financial institutions and energy companies. Loss reserves are periodically reviewed for adequacy and may be established on a specific-case basis. Market Resources requests credit support and, in some cases, fungible collateral from companies with unacceptable credit risks. The Company has master-netting agreements with some counterparties that allow the offsetting of receivables and payables in a default situation.
Bad-debt expense associated with accounts receivable for the year ended December 31, amounted to $3.8 million in 2009, $7.0 million in 2008 and $2.6 million in 2007. The allowance for bad-debt expenses was $8.4 million at December 31, 2009 and $8.5 million at December 31, 2008. Questar Gas's retail-gas operations account for a majority of the bad-debt expense. Questar Gas
QUESTAR 2009 FORM 10-K
estimates bad-debt expense as a percentage of general-service revenues with periodic adjustments. Uncollected accounts are generally written off six months after gas is delivered and interest is no longer accrued.
Income Taxes
Questar and its subsidiaries file a consolidated federal income tax return. Deferred income taxes are provided for the temporary differences arising between the book and tax-carrying amounts of assets and liabilities. These differences create taxable or tax-deductible amounts for future periods. Questar Gas and Questar Pipeline use the deferral method to account for investment tax credits as required by regulatory commissions. The Company records interest earned on income tax refunds in interest and other income and records penalties and interest charged on tax deficiencies in interest expense.
ASC 740 "Income Taxes" specifies the accounting for uncertainty in income taxes by prescribing a minimum recognition threshold for a tax position to be reflected in the financial statements. If recognized, the tax benefit is measured as the largest amount of tax benefit that is more-likely-than-not to be realized upon ultimate settlement. Management has considered the amounts and the probabilities of the outcomes that could be realized upon ultimate settlement and believes that it is more-likely-than-not that the Company's recorded income tax benefits will be fully realized. There were no unrecognized tax benefits at the beginning or at the end of the twelve-month periods ended December 31, 2009, 2008 and 2007. Income tax returns for 2006 and subsequent years are subject to examination.
Earnings Per Share (EPS)
Basic EPS is computed by dividing net income attributable to Questar by the weighted-average number of common shares outstanding during the reporting period. Diluted EPS includes the potential increase in the number of outstanding shares that could result from the exercise of in-the-money stock options. During the first quarter of 2009, the Company adopted the updated provisions of ASC 260, "Earnings Per Share." ASC 260 addresses whether instruments granted in share-based payment transactions are participating securities and therefore have a potential dilutive effect on EPS. The adoption was applied retrospectively and did not have a material effect on the Company's EPS calculations.
Share-Based Compensation
Questar issues stock options and restricted shares to certain officers, employees and non-employee directors under its Long-Term Stock Incentive Plan (LTSIP). Since January 1, 2006, the fair value of stock options is expensed during the vesting period. The Company uses the Black-Scholes-Merton mathematical model in estimating the fair value of stock options for accounting purposes. The granting of restricted shares results in recognition of compensation cost measured at the grant-date market price. Questar uses an accelerated method in recognizing share-based compensation costs with graded-vesting periods. See Note 13 for further discussion on share-based compensation.
Comprehensive Income
Comprehensive income is the sum of net income attributable to Questar as reported in the Consolidated Statements of Income and other comprehensive income (loss). As reported in the Consolidated Statements of Equity, other comprehensive income (loss) includes changes in the market value of commodity-based derivative instruments and recognition of the under-funded position of pension and other postretirement benefit plans. These transactions are not the culmination of the earnings process but result from periodically adjusting historical balances to fair value. Income or loss is realized when the physical gas, oil or NGL underlying the derivative instrument is sold or the pension or other postretirement benefit costs are accrued. Comprehensive income (loss) attributable to Questar is shown below:
Unrealized gain on derivatives is a component of AOCI on the Consolidated Balance Sheets. The following table sets forth the changes in unrealized gain on derivatives, net of income taxes, during 2009:
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Income taxes allocated to each component of other comprehensive income (loss) for the year are shown in the table below: Expenses are enclosed in parentheses.
Business Segments
Line of business information is presented according to senior management's basis for evaluating performance considering differences in the nature of products, services and regulation. Certain intersegment sales include intercompany profit.
Recent Accounting Developments
ASC 810 "Consolidation"
In June 2009, the FASB issued new guidance that was codified in ASC 810 "Consolidation," amending previous guidance by addressing the effects of eliminating the qualifying special-purpose entity (QSPE) concept and responding to concerns about the application of certain key provisions regarding consolidation of variable interest entities (VIEs), including concerns over the transparency of enterprises' involvement with VIEs. The new guidance is effective for interim and annual periods for calendar year-end companies beginning on January 1, 2010. The Company is evaluating if the new guidance will affect its income, financial position, or cash flow.
Reclassifications
Certain reclassifications were made to prior-year consolidated financial statements to conform with the 2009 presentation.
All dollar and share amounts in this annual report on Form 10-K are in millions, except per-share information and where otherwise noted.
Note 2 - Earnings Per Share
Earnings Per Share
Basic earnings per share (EPS) is computed by dividing net income attributable to Questar by the weighted-average number of common shares outstanding during the reporting period. Diluted EPS includes the potential increase in the number of outstanding shares that could result from the exercise of in-the-money stock options. During the first quarter of 2009, the Company adopted the updated provisions of ASC 260, "Earnings Per Share." ASC 260 addresses whether instruments granted in share-based payment transactions are participating securities and therefore have a potential dilutive effect on EPS. The adoption was applied retrospectively and did not have a material effect on the Company's EPS calculations. A reconciliation of the components of basic and diluted shares used in the EPS calculation follows:
QUESTAR 2009 FORM 10-K
In the past three years, Questar had the ability to issue shares under the terms of the Dividend Reinvestment and Stock Purchase Plan, Employee Investment Plan and Long-Term Stock Incentive Plan.
Dividend Reinvestment and Stock Purchase Plan (Reinvestment Plan)
The Reinvestment Plan allows parties interested in owning Questar common stock to reinvest dividends or invest additional funds in common stock. The Company can issue new shares or buy shares in the open market to meet shareholders' purchase requests. The Company issued 181,508 shares in 2009 and relied on open market purchases to meet 2008 and 2007 distributions. At December 31, 2009, 1,592,969 shares were reserved for future issuance.
Long-Term Stock Incentive Plan
Questar issues stock options and restricted shares to certain officers, directors, and employees under its LTSIP. Stock options for participants have terms ranging from five to ten years with a majority issued with a seven to ten-year term. Options held by employees generally vest in three or four equal, annual installments. Options granted to non-employee directors generally vest in one installment six months after grant. Restricted shares vest in equal installments over a specified number of years after the grant date with the majority vesting in three or four years. Nonvested restricted shares have voting and dividend rights; however, sale or transfer is restricted. Options and restricted shares issued prior to February 2006 vest on an accelerated basis in the event of a qualified termination, such as retirement, and have postretirement exercise periods. For a summary of LTSIP transactions see Note 13 - Share-Based Compensation.
Note 3 - Property, Plant and Equipment
The details of property, plant and equipment and accumulated depreciation, depletion and amortization follow:
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Questar E&P proved and unproved leaseholds had a net book value of $1,152.2 million at December 31, 2009, and $1,074.2 million in at December 31, 2008.
In February 2008, Questar E&P acquired natural gas development properties in northwest Louisiana for an aggregate purchase price of $652.1 million effective January 1, 2008. The acquisition was accounted for as a purchase and, accordingly, the results of operations of the properties were included in net income from the closing date of the acquisition. After recording deferred income taxes of $13.1 million, the purchase price allocated to proved properties was $570.9 million and to unproved properties was $81.2 million.
In conjunction with the acquisition of the Louisiana properties, the Company identified and subsequently sold certain outside-operated producing properties and leaseholds in the Gulf Coast region of south Texas. These properties contributed 2.8 Bcfe to Questar E&P net production in 2008. For income tax purposes, the Company structured a portion of the purchase of the Louisiana properties and the July 31, 2008, sale of the south Texas properties as a reverse like-kind exchange of property under Section 1031 of the Internal Revenue Code of 1986, as amended. The Company recognized a pre-tax gain on the sale of the Texas properties of approximately $61.2 million.
Abandonment and impairment expense decreased $24.3 million or 54% in 2009 compared to 2008 primarily due to the impairment of certain gas and oil assets in 2008.
Questar Pipeline impairment expense amounted to $14.0 million in 2008. Questar Pipeline impaired the entire $10.6 million investment in a potential salt cavern storage project located in southwestern Wyoming in the second quarter of 2008 based on a technical and economic evaluation of the project. In the fourth quarter of 2008, Questar Pipeline also took a $3.4 million pre-tax charge for impairment of certain costs associated with the California segment of its Southern Trails Pipeline. There were no impairments at Questar Pipeline in 2009.
Gas Management constructed a gathering pipeline for $203.5 million and contributed the asset to Rendezvous Gas Services LLC (Rendezvous). As a result, Gas Management's ownership interest in Rendezvous increased from 50% to 78%. Common stock was reduced by $31.6 million, and noncontrolling interest increased by $28.5 million. Rendezvous operates gas-gathering facilities for Pinedale Anticline and Jonah field producers for delivery to various interstate pipelines.
Note 4 - Asset Retirement Obligations
Questar records asset retirement obligations (ARO) when there are legal obligations associated with the retirement of tangible long-lived assets. At Questar, ARO apply primarily to abandonment costs associated with gas and oil wells, production facilities and certain other properties. The fair value of retirement costs are estimated by Company personnel based on abandonment costs of similar properties available to field operations and depreciated over the life of the related assets. Revisions to ARO estimates result from changes in expected cash flows or material changes in estimated retirement costs. Income or expense resulting from the settlement of ARO liabilities is included in net gain or (loss) from asset sales on the Consolidated Statements of Income. The ARO liability is adjusted to present value each period through an accretion calculation using a credit-adjusted risk-free interest rate. Changes in ARO were as follows:
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Wexpro collects from Questar Gas and deposits in trust certain funds related to estimated ARO costs. The funds are recorded in other noncurrent assets on the Consolidated Balance Sheets and used to satisfy retirement obligations as the properties are abandoned. The accounting treatment of reclamation activities associated with ARO for properties administered under the Wexpro Agreement is defined in a guideline letter between Wexpro and the Utah Division of Public Utilities and the staff of the PSCW.
Note 5 - Capitalized Exploratory Well Costs
Net changes in capitalized exploratory well costs are presented in the table below and exclude amounts that were capitalized and subsequently expensed in the period. All of these costs have been capitalized for less than one year.
Note 6 - Fair Value Measurements
Beginning in 2008, Questar adopted the effective provisions of ASC 820 "Fair Value Measurements and Disclosures." ASC 820 defines fair value in applying GAAP, establishes a framework for measuring fair value and expands disclosures about fair-value measurements. ASC 820 does not change existing guidance as to whether or not an instrument is carried at fair value. ASC 820 establishes a fair-value hierarchy. Level 1 inputs are quoted prices (unadjusted) for identical assets or liabilities in active markets that the Company has the ability to access at the measurement date. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for the asset or liability. The Level 2 fair value of derivative contracts (see Note 7) is based on market prices posted on the NYMEX on the last trading day of the reporting period and industry-standard discounted cash flow models. The Level 3 fair value of derivative contracts is based on NYMEX market prices in combination with unobservable volatility inputs and industry-standard option pricing models. Long-term investments consist of money market and short-term bond index mutual funds, and represent funds held in Wexpro's trust (see Note 4). The fair value of long-term investments is based on quoted prices for the underlying mutual funds, and is considered a Level 1 fair value.
Questar primarily applies the market approach for recurring fair value measurements and maximizes its use of observable inputs and minimizes its use of unobservable inputs. Questar considers bid and ask prices for valuing the majority of its assets and liabilities measured and reported at fair value. In addition to using market data, Questar makes assumptions in valuing its assets and liabilities, including assumptions about risk and the risks inherent in the inputs to the valuation technique.
Certain of Questar's derivative instruments, however, are valued using industry-standard models that consider various inputs, including quoted forward prices for commodities, time value, volatility, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable prices at which transactions are executed in the marketplace. The determination of fair value for derivative assets and liabilities also
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incorporates nonperformance risk for counterparties and for Questar. Derivative contract fair values are reported on a net basis to the extent a legal right of offset with a counterparty exists.
In February 2008, the FASB delayed the effective date of ASC 820 for one year for certain nonfinancial assets and nonfinancial liabilities, except those recognized or disclosed at fair value in the financial statements on a recurring basis. On January 1, 2009, Questar adopted, without material impact on the Consolidated Financial Statements, the delayed provisions of ASC 820 related to nonfinancial assets and nonfinancial liabilities that are not required or permitted to be measured at fair value on a recurring basis. Questar did not have any assets or liabilities measured at fair value on a non-recurring basis at December 31, 2009. The fair values of assets and liabilities at December 31, 2009, are shown in the table below:
The change in the fair value of Level 3 assets and liabilities is shown below:
Questar did not have any assets or liabilities measured at fair value on a non-recurring basis or Level 3 at December 2008. The fair values of assets and liabilities at December 31, 2008, are shown in the table below:
QUESTAR 2009 FORM 10-K
The following table discloses the fair value and related carrying amount of certain financial instruments not disclosed in other notes to the Consolidated Financial Statements in this annual report on Form 10-K:
The carrying amounts of cash and cash equivalents and short-term debt approximate fair value. The fair value of fixed-rate long-term debt is based on the discounted present value of future cash flows using the Company's current borrowing rates. The borrowing rates are credit-risk adjusted. The carrying amount of variable-rate long-term debt approximates fair value.
Note 7 - Derivative Contracts
Market Resources' subsidiaries use commodity-price derivative instruments in the normal course of business. Market Resources has established policies and procedures for managing commodity-price risks through the use of derivative instruments. On January 1, 2009, the Company adopted a revision to ASC 815 "Derivatives and Hedging", which requires more detailed information about hedging transactions including the location and effect on the primary consolidated financial statements.
Market Resources uses derivative instruments to support rate of return and cash flow targets and protect earnings from downward movements in commodity prices. However, these same instruments typically limit future gains from favorable price movements. Derivative contracts are currently in place for a significant share of Questar E&P-owned gas and oil production and a portion of Energy Trading gas marketing transactions. The volume of production with associated derivative instruments and the mix of the instruments are frequently evaluated and adjusted by management in response to changing market conditions. Market Resources may match derivative contracts with up to 100% of forecast production from proved reserves when prices meet earnings and cash flow objectives. Market Resources does not enter into derivative instruments for speculative purposes.
Market Resources uses derivative instruments known as fixed-price swaps and costless collars to realize a known price or range of prices for a specific volume of production delivered into a regional sales point. Swap agreements do not require the physical transfer of natural gas between the parties at settlement. Swap transactions are settled in cash with one party paying the other for the net difference in prices, multiplied by the relevant volume, for the settlement period. Collars are combinations of put and call options that have a floor price and a ceiling price and are only triggered if the settlement price is outside the range of the floor and ceiling prices. In the past, Questar E&P has also used natural gas basis-only swaps to protect cash flows and net income from widening natural gas-price basis differentials. However, natural gas basis-only swaps exposed the Company to losses from narrowing natural gas price-basis differentials.
Market Resources enters into derivative instruments that do not have margin requirements or collateral provisions that would require funding prior to the scheduled cash settlement dates. Derivative-arrangement counterparties are normally financial institutions and energy-trading firms with investment-grade credit ratings. The Company routinely monitors and manages its exposure to counterparty risk by requiring specific minimum credit standards for all counterparties and transacting with multiple counterparties.
All derivative instruments are required to be recorded on the balance sheet as either assets or a liabilities measured at their fair values. The designation of a derivative instrument as a hedge and its ability to meet hedge accounting criteria determines how the change in fair value of the derivative instrument is reflected in the consolidated financial statements. A derivative instrument qualifies for hedge accounting, if at inception, the derivative is expected to be highly effective in offsetting the underlying hedged cash flows. Generally, Market Resources' derivative instruments are matched to equity gas and oil production and are highly effective, thus qualifying as cash flow hedges. Changes in the fair value of effective cash flow hedges are recorded as a component of AOCI on the Condensed Consolidated Balance Sheets and reclassified to earnings as gas and oil sales when the underlying physical transactions occur. Gas hedges are typically structured as fixed-price swaps into regional pipelines, locking in basis and hedge effectiveness. Costless collars qualify for cash flow hedge accounting. A basis-only swap does not qualify for hedge accounting treatment. Market Resources regularly reviews the effectiveness of derivative instruments. The ineffective
QUESTAR 2009 FORM 10-K
portion of cash flow hedges and the mark to market adjustment of basis-only swaps are immediately recognized in the determination of net income. The ineffective portion of cash flow hedges was de minimis for the year ended December 31, 2009.
Contract settlements in 2009 resulted in a transfer of $271.0 million after-tax income from AOCI to the Consolidated Statements of Income. Effective portions of cash flow hedges resulted in the recognition of $16.5 million after-tax income in AOCI in 2009. In the next twelve months $63.6 million, based on year-end 2009 prices, will be settled and transferred from AOCI to the Consolidated Statements of Income. The following table discloses the fair value of derivative contracts on a gross-contract basis as opposed to the net-contract basis presentation in the Consolidated Balance Sheets.
Previously reported basis-only swaps have been combined with fixed-price NYMEX gas swaps for 2010 and 2011 and now qualify as cash flow hedges. The following table sets forth Market Resources' volumes and average net to the well prices for transactions with associated risk management derivative contracts as of December 31, 2009:
QUESTAR 2009 FORM 10-K
Questar E&P Production
Energy Trading Marketing Transactions
(a)
The fixed-price swap and collar prices are reduced by gathering costs and adjusted for product quality to determine the net-to-the-well price.
Note 8 - Debt
The Company has short-term line-of-credit commitments from several banks under which it may borrow up to $435.0 million at December 31, 2009. These credit lines have interest-rate options generally below the prime interest rate. Commercial-paper borrowings with initial maturities of less than one year are backed by these short-term line-of-credit arrangements. These credit arrangements carry annual facility or commitment fees on the unused balance. The details of short-term debt are as follows:
All short-term and long-term notes and the term-bank loan are unsecured obligations and rank equally with all other unsecured liabilities. Market Resources' $800.0 million revolving-credit facility had $200.0 million outstanding at a weighted-average interest rate of 0.73% at December 31, 2009. This credit agreement carries an annual commitment fee of 0.115% on the unused
QUESTAR 2009 FORM 10-K
balance. At December 31, 2009, Market Resources could pay dividends of $1.1 billion without violating its limitation of total outstanding debt to total capitalization debt covenant. The terms of the Questar Pipeline and Questar Gas debt obligations do not have dividend-payment restrictions.
In August 2009, Market Resources issued $300.0 million of notes due March 2020 with a 6.82% effective interest rate and used the net proceeds to reduce the balance outstanding under its long-term revolving-credit facility. In September 2009, Questar Pipeline issued $50.0 million of notes due February 2018 with a 5.40% effective interest rate and used the net proceeds to repay $42.0 million of long-term notes that matured in October 2009. The details of long-term debt are as follows:
Maturities of long-term debt for the five years following December 31, 2009, are $332.0 million in 2011, $91.5 million in 2012 and $242.0 million in 2013.
Note 9 - Income Taxes
Details of Questar's income tax expense and deferred income taxes are provided in the following tables. The components of income tax expense were as follows:
QUESTAR 2009 FORM 10-K
The difference between the statutory federal income tax rate and the Company's effective income tax rate is explained as follows:
Significant components of the Company's deferred income taxes were as follows:
Note 10 - Commitments and Contingencies
Questar is involved in various commercial and regulatory claims and litigation and other legal proceedings that arise in the ordinary course of its business. Management does not believe any of them will have a material adverse effect on the Company's financial position, results of operations or cash flows. A liability is recorded for a loss contingency when its occurrence is probable and damages can be reasonably estimated based on the anticipated most likely outcome. Disclosures are provided for contingencies reasonably likely to occur which would have a material adverse effect on the Company's financial position, results of operations or cash flows. Some of the claims involve highly complex issues relating to liability, damages and other matters subject to substantial uncertainties and, therefore, the probability of liability or an estimate of loss cannot be reasonably determined.
Environmental Claims
In United States of America v. Questar Gas Management Co., Civil No. 208CV167, filed on February 29, 2008, in Utah Federal District Court, the Environmental Protection Agency (EPA) alleges that Gas Management violated the federal Clean Air Act (CAA) and seeks substantial penalties and a permanent injunction involving the manner of operation of five compressor stations located in the Uinta Basin of eastern Utah. EPA further alleges that the facilities are located within the original boundaries of the former Uncompahgre Indian Reservation and are therefore within "Indian Country." EPA asserts primary CAA jurisdiction over "Indian Country" where state CAA programs do not apply. EPA contends that the potential to emit, on a hypothetically uncontrolled basis, for Gas Management's facilities render them "major sources" of emissions for criteria and hazardous air pollutants. Categorization of the facilities as "major sources" affects the particular regulatory program applicable to those facilities. EPA claims that Gas Management failed to obtain the necessary major source pre-construction or modification permits, and failed to comply with hazardous air-pollutant regulations for testing and reporting, among other things. Gas Management
QUESTAR 2009 FORM 10-K
contends that its facilities have pollution controls installed that reduce their actual air emissions below major source thresholds, rendering them subject to different regulatory requirements. Gas Management intends to vigorously defend against the EPA's claims, and believes that the major source permitting and regulatory requirements at issue can be legally avoided by applying Utah's CAA program or EPA's prior practice for similar facilities elsewhere in Indian Country, among other defenses. Because of the complexities and uncertainties of this legal dispute, it is difficult to predict all reasonably possible outcomes; however, management believes the Company has accrued a reasonable loss contingency for the anticipated most likely outcome, and that the amount of the accrual is not material.
On July 10, 2009, Questar E&P filed a petition with the U.S. Tenth Circuit Court of Appeals challenging an administrative compliance order dated May 12, 2009, (Order) issued by the EPA which asserts that Questar E&P's Flat Rock 14P Well and associated equipment is a major source of emissions of hazardous air pollutants and that its operation fails to comply with certain regulations of the CAA. The Order required immediate compliance and threatened substantial penalties for failure to do so. Questar E&P denies that the drilling and operation of the 14P Well and associated equipment violates any provision of the CAA and intends to vigorously defend against this Order.
In October 2009, Questar E&P received a cease and desist order from the U.S. Army Corps of Engineers (COE) to refrain from further discharge of dredged and/or fill material into wetlands of the United States at three well sites without a permit under the Clean Water Act (CWA). The order specifically references prior construction activities at the sites located in Caddo and Red River Parishes, Louisiana.EPA Region 6 has now assumed lead responsibility for enforcement of the pending order and any possible future orders for the removal of unauthorized fills and/or civil penalties under Section 309 of the CWA. The company is working with the COE and EPA to resolve the matter.
Commitments
Historically, 40 to 50% of Questar Gas gas-supply has been provided by cost-of-service reserves developed and produced by Wexrpo. In 2009, Questar Gas purchased the remainder of its gas supply from multiple third-parties under index-based or fixed-price contracts. Questar Gas has commitments to purchase gas for $81.1 million in 2010, $30.9 million in 2011, $26.6 million in 2012, $26.4 million in 2013 and $26.4 million in 2014 based on current prices. Generally, at the conclusion of the heating season and after a bid process, new agreements for the next heating season are put in place. Questar Gas bought natural gas under purchase agreements amounting to $225.3 million in 2009, $395.5 million in 2008 and $374.8 million in 2007. In addition, Questar Gas has contracted for underground storage. Questar Gas stores gas during off-peak periods (typically during the summer) and withdraws gas from storage to meet peak-gas demand (typically in the winter).
Questar Gas has third-party transportation commitments requiring yearly payments of $5.0 million through 2017 and $1.4 million in 2018.
Subsidiaries of Market Resources have contracted for firm-transportation services with various third-party pipelines through 2040. Market conditions and competition may prevent full utilization of the contractual capacity. Annual payments and the years covered are as follows:
The Company is committed to lease its headquarters building through January 12, 2012 and committed to a $3.9 million annual rent payment. Rental expense amounted to $7.5 million in 2009, $6.8 million in 2008 and $5.8 million in 2007. Minimum future payments under the terms of long-term operating leases for the Company's primary office locations are as follows:
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Note 11 - Wexpro Agreement
Wexpro's operations are subject to the terms of the Wexpro Agreement. The agreement was effective August 1, 1981, and sets forth the rights of Questar Gas to receive certain benefits from Wexpro's operations. The agreement was approved by the PSCU and PSCW in 1981 and affirmed by the Supreme Court of Utah in 1983. Major provisions of the agreement are as follows.
a. Wexpro conducts gas-development drilling on a finite group of productive gas properties, as defined in the agreement, and bears any costs of dry holes. Natural gas produced from successful drilling on these properties is delivered to Questar Gas. Wexpro is reimbursed for the costs of producing the natural gas plus a return on its investment in successful wells. The after-tax return allowed Wexpro is adjusted annually and is approximately 20.5%.
b. Wexpro operates certain natural gas properties for Questar Gas. Wexpro is reimbursed for its costs of operating these properties, including a rate of return on any investment it makes. This after-tax rate of return is adjusted annually and is approximately 12.5%.
c. Crude-oil production from certain oil-producing properties is sold at market prices with the revenues used to recover operating expenses and to provide Wexpro a return on its investment. The after-tax rate of return on investments in these properties is adjusted annually and is approximately 12.5%. Any operating income remaining after recovery of expenses and Wexpro's return on investment is divided between Wexpro and Questar Gas, with Wexpro retaining 46%.
d. Wexpro conducts developmental-oil drilling on productive oil properties and bears any costs of dry holes. Oil discovered from these properties is sold at market prices with the revenues used to recover operating expenses and to give Wexpro a return on its investment in successful wells. The after-tax rate of return is adjusted annually and is approximately 17.5%. Any operating income remaining after recovery of expenses and Wexpro's return on investment is divided between Wexpro and Questar Gas with Wexpro retaining 46%. Questar Gas received oil-income sharing of $1.0 million in 2009, $6.1 million in 2008 and $4.9 million in 2007.
e. Amounts received by Questar Gas from the sharing of Wexpro's oil income are used to reduce natural-gas costs to utility customers.
Wexpro's net investment base and the yearly average rate of return for 2009 and the previous two years are shown in the table below:
Note 12 - Rate Regulation
Questar Gas Rate Changes
Questar Gas filed a general rate case in Utah in December 2009, requesting an allowed return on equity of 10.6%, an increase in rates of $17.2 million, a mechanism to adjust rates for investment in feeder line replacement, and a continuation of the CET.
Questar Gas filed a general rate case in Utah in December 2007. The PSCU allowed Questar Gas to increase its non-gas distribution revenues by an annualized $12.0 million beginning August 15, 2008 and authorized a 10.0% return on equity. Questar Gas filed a general rate case in Wyoming in August 2008. The PSCW authorized a 10.5% return on equity.
In January 2007 the PSCU approved a demand-side management program (DSM) effective January 1, 2007. Under the DSM, Questar Gas encourages the conservation of natural gas through advertising, rebates for efficient homes and appliances, and energy audits. The costs related to the DSM are deferred and recovered from customers through periodic rate adjustments. Questar Gas received revenues for recovery of DSM costs amounting to $26.9 million in 2009 compared with $6.6 million in 2008. As of December 31, 2009, Questar Gas had a regulatory asset of $40.6 million for DSM costs to be recovered from customers.
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In October 2006, the PSCU approved a three-year pilot program for a conservation enabling tariff (CET) effective January 1, 2006, to promote energy conservation. Under the company's prior rate structure, non-gas revenues declined when average temperature-adjusted usage per customer declined while non-gas revenues increased when average temperature-adjusted usage per customer increased. Under the CET, Questar Gas non-gas revenues are decoupled from the temperature-adjusted usage per customer. The tariff specifies a margin per customer for each month with differences to be deferred and recovered from customers or refunded to customers through periodic rate adjustments. These adjustments are limited to five percent of distribution non-gas revenues. Under the CET, Questar Gas recorded a $4.0 million revenue decrease in 2009 compared with a $1.0 million increase in 2008. In late 2007, the PSCU ordered a continuation of the CET program for an additional two years.
Other Regulatory Assets and Liabilities
The Company has other regulatory assets and liabilities in addition to purchased-gas adjustments. The rate-regulated entities recover the costs of assets but do not generally receive a return on these assets.
Following is a description of the Company's regulatory assets:
·
Gains and losses on the reacquisition of debt by rate-regulated companies are deferred and amortized as interest expense over the would-be remaining life of the reacquired debt. The reacquired debt costs had a weighted-average life of approximately 10.0 years as of December 31, 2009.
·
The CET asset (liability) represents actual revenues received that are less than (in excess of) the allowed revenues. These amounts are recovered (refunded) through periodic rate adjustments.
·
The DSM program liability represents funds available for the program that exceed amounts expended to date. These amounts are refunded through periodic rate adjustments.
·
The costs of complying with pipeline-integrity regulations are recovered in rates subject to a PSCU order. Questar Gas is allowed to recover $5.1 million per year. Costs incurred in excess of this amount will be recovered in future rate changes.
·
Questar Gas has a regulatory asset that represents future expenses related to abandonment of Wexpro operated gas and oil wells. The regulatory asset will be reduced over an 18 year period following an amortization schedule that commenced January 1, 2003, or as cash is paid to plug and abandon wells.
·
Production taxes on cost-of-service gas production are recorded when the gas is produced and recovered from customers when taxes are paid, generally within 12 months.
·
The rate-regulated businesses are allowed to recover certain deferred taxes from customers over the life of the related property, plant and equipment.
·
Questar Pipeline has regulatory assets and liabilities for gas imbalances, fuel over or under recovery, and sharing of interruptible revenues with firm customers.
A list of regulatory assets follows:
A list of regulatory liabilities follows:
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Following is a description of the Company's regulatory liabilities:
·
A regulatory liability has been recorded for the collection of postretirement medical costs allowed in rates which exceed actual charges.
·
Income taxes refundable to customers arise from adjustments to deferred taxes.
Current regulatory liabilities are included with accounts payable and accrued expense in the Consolidated Balance Sheets. Long-term regulatory liabilities are included with other long-term liabilities in the Consolidated Balance Sheets. A list of long-term regulatory liabilities follows:
Note 13 - Share-Based Compensation
Questar issues stock options and restricted shares to certain officers, employees and non-employee directors under its LTSIP and recognizes expense over time as the stock options or restricted shares vest. Share-based compensation expense amounted to $22.7 million in 2009 compared to $16.7 million in 2008 and $12.9 million in 2007. Deferred share-based compensation, representing the nonvested value of restricted share awards, amounted to $13.7 million at December 31, 2009 and $17.7 million at December 31, 2008. Deferred share-based compensation is included in common stock on the Consolidated Balance Sheets. Cash flow from income tax benefits in excess of recognized compensation expense amounted to $3.6 million in 2009, $13.2 million in 2008 and $11.1 million in 2007. There were 8,253,083 shares available for future grant at December 31, 2009.
The Company uses the Black-Scholes-Merton mathematical model in estimating the fair value of stock options for accounting purposes. Fair-value calculations rely upon subjective assumptions used in the mathematical model and may not be representative of future results. The Black-Scholes-Merton model was intended for measuring the value of options traded on an exchange. The calculated fair value of options granted and major assumptions used in the model at the date of grant are listed below:
Unvested stock options increased by 819,827 shares to 1,677,327 in 2009. Stock-option transactions under the terms of the LTSIP for the three years ended December 31, 2009, are summarized below:
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Restricted shares are valued at the grant-date market price and amortized to expense over the vesting period. Most restricted share grants vest in equal installments over a three or four year period from the grant date. The weighted average vesting period of unvested restricted shares at December 31, 2009, was 14 months. Transactions involving restricted shares under the terms of the LTSIP for the three years ended December 31, 2009, are summarized below:
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Note 14 - Employee Benefits
Defined Benefit Pension Plan and Other Postretirement Benefits
The Company has defined-benefit pension and life insurance plans covering a majority of its employees and a postretirement medical plan providing coverage to less than half of its employees. The Company's Employee Benefits Committee (EBC) has oversight over investment of retirement-plan and postretirement-benefit assets. The EBC uses a third-party consultant to assist in setting targeted-policy ranges for the allocation of assets among various investment categories. The majority of retirement-benefit assets were invested as follows:
At the end of 2009, domestic equity assets were invested in a passive total stock market index fund that invests in a diversified portfolio of stocks representative of the whole U.S. stock market. Developed market foreign equity assets were invested in funds that hold a diversified portfolio of common stocks of corporations in developed countries outside the United States. These investments are benchmarked against the Morgan Stanley Capital International Europe Australasia and Far East (or MSCI EAFE) index. Emerging market foreign equity assets are invested in funds that hold a diversified portfolio of common stocks of corporations in emerging countries outside the United States. This investment is benchmarked against the MSCI EAFE Emerging Markets index. Investment grade intermediate-term debt assets are invested in funds holding a diversified portfolio of debt of governments, corporations and mortgage borrowers with average maturities of 5 to 10 years and investment grade credit ratings. The investments are benchmarked against the Barclay's Aggregate Bond index. Investment grade long-term debt assets are invested in a diversified portfolio of debt of governments, corporations and mortgage borrowers with an average maturity of more than 10 years and investment grade credit ratings. These assets are benchmarked against the Barclay's Government/Credit Bond index. Below-investment grade debt assets are invested in a fund holding a diversified portfolio of debt securities of corporations with an average maturity up to 10 years with below-investment grade credit ratings. This investment is benchmarked against the Merrill Lynch High Yield II Total Return Bond index. Cash and short-term investments are held in a fund that purchases investment grade quality short term debt issued by governments and corporations.
Questar funds a trust for Employee Retirement Income Security Act (ERISA) qualified retirement-benefit obligations to pay benefits currently due and to build asset balances over a reasonable time period to pay future obligations. Questar is subject to and complies with minimum-required and maximum-allowed annual contribution levels mandated by ERISA and by the Internal Revenue Code. Subject to the above limitations, the Company seeks to fund the qualified retirement plan in amounts approximately equal to the yearly expense. The Company also has a nonqualified pension plan that covers a group of management employees in addition to the qualified pension plan. The nonqualified pension plan provides for defined benefit payments upon retirement of the management employee, or to the spouse upon death of the management employee above the benefit limit defined by the Internal Revenue Service for the qualified plan. The nonqualified pension plan is unfunded. Claims are paid from the Company's general funds. The Company commingles postretirement-benefit obligation assets with those of the ERISA-qualified retirement plan as permitted by section 401(h) of the Internal Revenue Code. The EBC seeks investment returns consistent with reasonable and prudent levels of liquidity and risk.
The EBC allocates pension-plan and postretirement-medical-plan assets among broad asset categories and reviews the asset allocation at least annually. Asset-allocation decisions consider risk and return, future-benefit requirements, participant growth and other expected cash flows. These characteristics affect the level, risk and expected growth of postretirement-benefit assets.
QUESTAR 2009 FORM 10-K
The EBC uses asset-mix guidelines that include permissible ranges for each asset category, return objectives for each asset group and the desired level of diversification and liquidity. These guidelines change from time to time based on the committee's ongoing evaluation of each plan's risk tolerance. The EBC estimates an expected overall long-term rate of return on assets by weighting expected returns of each asset class by its targeted asset allocation percentage. Expected return estimates are developed from analysis of past performance and forecasts of long-term return expectations by third-parties.
Responsibility for individual security selection rests with each investment manager, who is subject to guidelines specified by the EBC. These guidelines are designed to ensure consistency with overall plan objectives.
The EBC sets performance objectives for each investment manager that are expected to be met over a three-year period or a complete market cycle, whichever is shorter. Performance and risk levels are regularly monitored to confirm policy compliance and that results are within expectations.
Pension-plan guidelines prohibit transactions between a fiduciary and parties in interest unless specifically provided for in ERISA. No restricted securities, such as letter stock or private placements, may be purchased for any investment fund. Questar securities may be considered for purchase at an investment manager's discretion, but within limitations prescribed by ERISA and other laws. There was no direct investment in Questar shares for the periods disclosed. Use of derivative securities by any investment managers is prohibited except where the committee has given specific approval or where commingled funds are utilized that have previously adopted permitting guidelines.
The fair value measurement provision of ASC 820 "Fair Value Measurements and Disclosures" defines fair value in applying generally accepted accounting principles as well as establishes a framework for measuring fair value and for making disclosures about fair-value measurements. Fair value measurement establishes a fair-value hierarchy. Level 1 inputs are unadjusted quoted prices in active markets for identical assets or liabilities that are accessible at the measurement date. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for an asset, either directly or indirectly. Level 3 inputs are unobservable inputs for an asset. Following is a description of the valuation methodologies used at December 31, 2009 used to value pension and post retirement assets at December 31, 2009.
Common Stocks: Common stocks are valued at the closing price reported on the active market on which each individual security is traded.
Bonds: Bonds are valued at the closing price reported on the active market on which each individual security is traded.
Mutual funds: Mutual funds are valued at the closing price reported on the active market on which each individual mutual fund is traded.
Bond trust fund: This investment is a public investment vehicle valued using the Net Asset Value (NAV) of the fund. The NAV is based on the value of the underlying assets owned by the fund excluding transaction costs, and minus liabilities.
Commingled funds: These investments are public investment vehicles valued using the NAV of the fund. The NAV is based on the value of the underlying assets owned by the fund excluding transaction costs, and minus liabilities.
The following table sets forth by level, within the fair value hierarchy, pension and postretirement benefit assets fair value.
QUESTAR 2009 FORM 10-K
Pension-plan benefits are based on the employee's age at retirement, years of service and highest earnings in a consecutive 72 semimonthly pay period during the 10 years preceding retirement. Postretirement health-care and life insurance benefits are provided only to employees hired before January 1, 1997. The Company pays a portion of the costs of health-care benefits determined by an employee's years of service and generally limited to 170% of the 1992 contribution for employees who retired after January 1, 1993. The Company is amortizing its transition obligation over a 20-year period, which began in 1992.
The pension projected-benefit obligation and postretirement benefit accumulated benefit obligation were measured using a 6.5% discount rate at December 31, 2009 and 2008. Plan assets reflect the fair value of assets at December 31. Questar does not expect any plan assets to be returned during 2010. The pension plan accumulated benefit obligation was $394.7 million at December 31, 2009. Plan obligations and fair value of plan assets are shown in the following table:
QUESTAR 2009 FORM 10-K
The projected 2010 pension funding is expected to be $22.0 million. Estimated benefit-plan payments for the five years following 2009 and the subsequent five years aggregated are as follows:
The components of pension and postretirement benefits expense are as follows. The pension expense includes costs of both qualified and nonqualified pension plans:
Assumptions at January 1, used to calculate pension and postretirement benefits expense for the years, were as follows:
QUESTAR 2009 FORM 10-K
The 2010 estimated pension expense is $24.8 million. In 2010, $7.1 million of estimated actuarial loss and $1.2 million of prior service cost for the pension plan will be amortized from AOCI. The 2010 estimated post-retirement expense is $5.6 million excluding amortization of a regulatory liability. In 2010, $1.9 million of net transition obligation and $0.7 million of estimated actuarial loss for the postretirement benefit plans will be amortized from AOCI.
Service costs and interest costs are sensitive to changes in the health-care inflation rate. A 1% increase in the health-care inflation rate would increase the yearly service and interest costs by $0.1 million and the accumulated postretirement-benefit obligation by $1.1 million. A 1% decrease in the health-care inflation rate would decrease the yearly service cost and interest cost by $0.1 million and the accumulated postretirement-benefit obligation by $1.0 million.
Employee Investment Plan (EIP)
The EIP allows eligible employees to purchase shares of Questar common stock or other investments through payroll deduction at the current fair market value on the transaction date. The Company currently contributes an overall match of either 80% or 100% of employees' pre-tax purchases up to a maximum of 6% of their qualifying earnings. In addition, the Company contributes $200 annually to the EIP for each eligible employee. The EIP trustee purchases Questar shares on the open market with cash received. The Company recognizes expense equal to its yearly contributions, which amounted to $9.4 million in 2009, $9.1 million in 2008, and $8.1 million in 2007.
Note 15 - Operations by Line of Business
Questar's major lines of business include gas and oil exploration and production (Questar E&P and Wexpro), midstream field services (Gas Management), energy marketing (Energy Trading), interstate gas transportation (Questar Pipeline), and retail gas distribution (Questar Gas). Line of business information is presented according to senior management's basis for evaluating performance including differences in the nature of products, services and regulation. Following is a summary of operations by line of business for the three years ended December 31, 2009:
QUESTAR 2009 FORM 10-K
QUESTAR 2009 FORM 10-K
Note 16 - Quarterly Financial Information (Unaudited)
A reclassification of first, second and third quarter 2009 revenues and realized loss on basis-only swaps increased both line items by $3.4 million, $4.6 million and $7.2 million, respectively. Following is a summary of unaudited quarterly financial information:
Note 17 - Supplemental Gas and Oil Information (Unaudited)
The Company is making the following supplemental disclosures of gas and oil producing activities, in accordance with ASC 932 "Extractive Activities - Oil and Gas" as amended by ASU 2010-03 "Oil and Gas Reserve Estimation and Disclosures" and SEC Regulation S-X.
The Company uses the successful efforts accounting method for its gas and oil exploration and development activities and for cost-of-service gas and oil properties.
Questar E&P Activities
The following information is provided with respect to Questar E&P's gas and oil exploration and production activities, which are all located in the United States.
QUESTAR 2009 FORM 10-K
Capitalized Costs
The aggregate amounts of costs capitalized for gas and oil exploration and development activities and the related amounts of accumulated depreciation, depletion and amortization are shown below:
Costs Incurred
The costs incurred in gas and oil exploration and development activities are displayed in the table below. The costs incurred to develop proved undeveloped reserves were $216.1 million in 2009, $219.9 million in 2008 and $125.8 million in 2007.
Results of Operation
Following are the results of operation of Questar E&P gas and oil exploration and development activities, before corporate overhead and interest expenses.
Estimated Quantities of Proved Gas and Oil Reserves
Estimates of proved gas and oil reserves have been completed in accordance with professional engineering standards and the Company's established internal controls, which includes the compliance oversight of a multi-functional reserves review committee responsible to the Company's board of directors. Questar E&P's estimated proved reserves have been prepared by Ryder Scott Company, L.P., independent reservoir engineering consultants, in accordance with the SEC's Regulation S-X and ASC 932 as amended. The individuals performing reserves estimates possess professional qualifications and demonstrate competency in reserves estimation and evaluation.
QUESTAR 2009 FORM 10-K
(a) Estimates of the quantity of proved reserves from the Company's Pinedale Anticline leasehold in western Wyoming have changed substantially over time as a result of numerous factors including, but not limited to, additional development drilling activity, producing well performance and the development and application of reliable technologies. The continued analysis of new data has led to progressive increases in estimates of original gas-in-place at Pinedale and to a better understanding of the appropriate well density to maximize the economic recovery of the in-place volumes. With the application of the amendments of ASC 932 in ASU 2010-03, reserves associated with Pinedale increased density drilling are included in extensions and discoveries for the year ended December 31, 2009, because each new well drilled recovers incremental reserves that would otherwise be unrecoverable.
QUESTAR 2009 FORM 10-K
(a)Revisions include price-related reductions of 220.4 Bcfe. Year-end 2009 proved reserve estimates were based on SEC-prescribed 12-month average prices of $3.06 per Mcf and $45.54 per barrel. Such price-related reductions would not have occurred under the SEC's prior end-of-year pricing rules.
(b)Extensions and discoveries include 578.1 Bcfe resulting from the application of the amendments of ASC 932 in ASU 2010-03 relative to booking proved undeveloped reserves for locations more than one location away from an existing producing well when reliable technology can be demonstrated. Such additions are based on empirical data including subsurface well control, long-term well performance, pressure testing and pressure studies, core data, and ongoing pilot programs of increased density development, which have confirmed with reasonable certainty the areal extent and continuity of the subject hydrocarbon accumulations. The Company routinely applies multi-stage hydraulic fracture stimulation technology and in some instances horizontal drilling combined with multi-stage fracture stimulation technology in development of its reserves. Empirical data has also been incorporated in detailed reservoir models supported by three dimensional seismic data and numerical simulation studies to further corroborate such conclusions.
(c)All of Questar E&P's proved undeveloped reserves at December 31, 2009 are scheduled to be developed within five years from the date such locations were initially disclosed as proved undeveloped reserves, except for 350 Bcfe located within the northernmost portion of the Company's Pinedale Anticline leasehold in western Wyoming. As discussed in Item 1of Part I of this Annual Report, long-term development of natural gas reserves in the PAPA is governed by the BLM's September 2008, ROD on the FSEIS. Under the ROD, Questar E&P and Wexpro are allowed to drill and complete wells year-round in designated concentrated development areas defined in the PAPA. The ROD contains additional requirements and restrictions on the sequence of development of the PAPA, which requires the Company to develop its leasehold from the south to the north. These restrictions result in protracted, phased development of the PAPA that is beyond the control of the Company. The Company has an ongoing development plan for the PAPA and the financial capability to continue development in the manner estimated.
Standardized Measure of Future Net Cash Flows Relating to Proved Reserves
Future net cash flows were calculated at December 31, 2009, by applying prices used in estimating 2009 reserves, which was the simple average of the first-of-the-month prices for the twelve months of 2009 with consideration of known contractual price changes. Future net cash flow calculations for years prior to 2009 used year-end prices and known contract-price changes. The prices used do not include any impact of hedging activities. The average price per Mcf used to calculate proved natural gas reserves was $3.06 in 2009, $4.62 in 2008 and $6.01 in 2007. The average price per barrel of proved oil and NGL reserves combined used to calculate reserves was $45.54 in 2009, $28.41 in 2008 and $80.86 in 2007. Year-end production costs, development costs and appropriate statutory income tax rates, with consideration of future tax rates already legislated, were used to compute the future net cash flows. All cash flows were discounted at 10% to reflect the time value of cash flows, without regard to the risk of specific properties. The estimated future costs to develop booked proved undeveloped reserves are $436.8 million in 2010, $467.9 million in 2011 and $389.1 million in 2012. At the end of five-year period ending in 2014, the Company expects to have evaluated 100% of the current booked proved undeveloped reserves.
The assumptions used to derive the standardized measure of future net cash flows are those required by accounting standards and do not necessarily reflect the Company's expectations. The usefulness of the standardized measure of future net cash flows is impaired because of the reliance on reserve estimates and production schedules that are inherently imprecise.
Management considers a number of factors when making investment and operating decisions. They include estimates of probable and proved reserves and varying price and cost assumptions considered more representative of a range of anticipated economic conditions. The standardized measure of future net cash flows relating to proved reserves is presented in the table below:
QUESTAR 2009 FORM 10-K
The principal sources of change in the standardized measure of future net cash flows relating to proved reserves is presented in the table below:
Cost-of-Service Activities
The following information is provided with respect to cost-of-service gas and oil properties managed and developed by Wexpro and governed by the Wexpro Agreement. Information on the standardized measure of future net cash flows has not been included for cost-of-service activities because the operations of and return on investment for such properties are regulated by the Wexpro Agreement.
Capitalized Costs of Cost-of-Service Activities
Capitalized costs for cost-of-service gas and oil properties net of the related accumulated depreciation and amortization are shown below.
Costs Incurred for Cost-of-Service Activities
Costs incurred by Wexpro for cost-of-service gas and oil-producing activities were $113.2 million in 2009, $148.0 million in 2008 and $110.7 million in 2007.
QUESTAR 2009 FORM 10-K
Results of Operation of Cost-of-Service Activities
Following are the results of operation of cost-of-service gas and oil-development activities, before corporate overhead and interest expenses:
(a) Primarily represents revenues including reimbursement of general and administrative expenses amounting to $16.7 million in 2009, $13.3 million in 2008 and $14.4 million in 2007 received from Questar Gas pursuant to the Wexpro Agreement.
Estimated Quantities of Cost-of-Service Proved Gas and Oil Reserves
Estimates of cost-of-service proved gas and oil reserves have been prepared in accordance with professional engineering standards and the Company's established internal controls, which includes the compliance oversight of a multi-functional reserves review committee that reports to the Company's board of directors. The estimates set forth below were prepared by Wexpro's reservoir engineers, individuals who possess professional qualifications and demonstrated competency in reserves estimation and evaluation.
Because gas reserves managed, developed and produced by Wexpro are delivered to Questar Gas at cost-of-service, SEC guidelines with respect to standard economic assumptions are not applicable. The SEC acknowledges this potential circumstance and provides that companies may give appropriate recognition to differences arising because of the effect of the ratemaking process. Accordingly, Wexpro uses a minimum-producing rate or maximum well-life limit to determine the ultimate quantity of reserves attributable to each well.
QUESTAR 2009 FORM 10-K
(a)Estimates of the quantity of proved reserves from the Company's Pinedale Anticline leasehold in western Wyoming have changed substantially over time as a result of numerous factors including, but not limited to, additional development drilling activity, producing well performance and the development and application of reliable technologies. The continued analysis of new data has led to progressive increases in estimates of original gas-in-place at Pinedale and to a better understanding of the appropriate well density to maximize the economic recovery of the in-place volumes. With the application of the amendments of ASC 932 in ASU 2010-03, reserves associated with Pinedale increased density drilling are included in extensions and discoveries for the year ended December 31, 2009 because each new well drilled recovers incremental reserves that would otherwise be unrecoverable.
Financial Statement Schedule:
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
The Company has not changed its independent auditors or had any disagreement with them concerning accounting matters and financial statement disclosures within the last 24 months.
QUESTAR 2009 FORM 10-K
ITEM 9A. CONTROLS AND PROCEDURES.
Evaluation of Disclosure Controls and Procedures
The Company's Chief Executive Officer and Chief Financial Officer have evaluated the effectiveness of the Company's disclosure controls and procedures (as such term is defined in Rules 13a-15(e) under the Securities Exchange Act of 1934, as amended, as of December 31, 2009. Based on such evaluation, such officers have concluded that, as of December 31, 2009, the Company's disclosure controls and procedures are effective in alerting them on a timely basis to material information relating to the Company, including its consolidated subsidiaries, required to be included in the Company's reports filed or submitted under the Exchange Act. The Company's Chief Executive Officer and Chief Financial Officer also concluded that the controls and procedures were effective in ensuring that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is accumulated and communicated to the Company's management including its principal executive and financial officers or persons performing similar functions as appropriate to allow timely decisions regarding required disclosure.
Changes in Internal Controls
There were no changes in the Company's internal controls over financial reporting that occurred during the quarter ended December 31, 2009, that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.
Management's Assessment of Internal Control Over Financial Reporting
Questar's management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Exchange Act Rule 13a-15(e). Questar's management assessed the effectiveness of the Company's internal control over financial reporting as of December 31, 2009. The criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control - Integrated Framework were used to make this assessment. We believe that the Company's internal control over financial reporting as of December 31, 2009, is effective based on those criteria.
The effectiveness of Questar's internal control over financial reporting as of December 31, 2009, has been audited by Ernst & Young LLP, an independent registered public accounting firm, as stated in their report as follows:
QUESTAR 2009 FORM 10-K
Report of Independent Registered Public Accounting Firm
The Board of Directors and Shareholders of
Questar Corporation
We have audited Questar Corporation's 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). Questar Corporation's 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 Assessment of 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, Questar Corporation 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 Questar Corporation as of December 31, 2009 and 2008, and the related consolidated statements of income, common shareholders' equity, and cash flows for each of the three years in the period ended December 31, 2009, of Questar Corporation and our report dated February 26, 2010, expressed an unqualified opinion thereon.
/s/Ernst & Young LLP
Ernst & Young LLP
Salt Lake City, Utah
February 26, 2010
QUESTAR 2009 FORM 10-K
ITEM 9B. OTHER INFORMATION.
There is no information to report in Item 9B.
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERANCE.
The information requested in Item 10 concerning Questar's directors is presented in the Company's definitive Proxy Statement under the section entitled "Election of Directors" and is incorporated herein by reference. A definitive Proxy Statement for Questar's 2010 annual meeting will be filed with the Securities and Exchange Commission on or about April 7, 2010.
Information about the Company's executive officers can be found in Item 1 of Part I in this Annual Report.
Information concerning compliance with Section 16(a) of the Exchange Act, is presented in the definitive Proxy Statement for Questar's 2010 annual meeting under the section entitled "Section 16(a) Compliance" and is incorporated herein by reference.
The Company has a Business Ethics and Compliance Policy (Ethics Policy) that applies to all of its directors, officers (including its Chief Executive Officer and Chief Financial Officer) and employees. Questar has posted the Ethics Policy on its Web site, www.questar.com. Any waiver of the Ethics Policy for executive officers must be approved only by the Company's Board of Directors. Questar will post on its Web site any amendments to or waivers of the Ethics Policy that apply to executive officers.
ITEM 11. EXECUTIVE COMPENSATION.
The information required to be furnished pursuant to Item 11 will be set forth under the caption "Executive Compensation" in the Proxy Statement, and is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.
The information requested in Item 12 for certain beneficial owners is presented in Questar's definitive Proxy Statement for the Company's 2010 annual meeting under the section entitled "Security Ownership, Principal Holders" and is incorporated herein by reference. Similar information concerning the securities ownership of directors and executive officers is presented in the definitive Proxy Statement for the Company's 2010 annual meeting under the section entitled "Security Ownership, Directors and Executive Officers" and is incorporated herein by reference.
Finally, information concerning securities authorized for issuance under the Company's equity compensation plans as of December 31, 2009, is presented in the definitive Proxy Statement for the Company's 2010 Annual Meeting of Shareholders under the section entitled "Equity Compensation Plan Information" and is incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE.
The information requested in Item 13 for related transactions involving the Company's directors and executive officers is presented in the definitive Proxy Statement for Questar's 2010 Annual Meeting of Shareholders under the sections entitled "Information Concerning the Board of Directors" and Certain Relationships - "Executive Officers."
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES.
The information requested in Item 14 for principal accountant fees and services is presented in the definitive Proxy Statement for Questar's 2010 Annual Meeting of Shareholders under the section entitled "Audit Committee Report" and is incorporated herein by reference.
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.
(a) and (c) Financial statements and financial statement schedules filed as part of this report are listed in the index included in Item 8 of this report.
(b) Exhibits. The following is a list of exhibits required to be filed as a part of this report in Item 15(b).
QUESTAR 2009 FORM 10-K
Exhibit No.
Description
3.1.*
Restated Articles of Incorporation as amended effective May 19, 1998. (Exhibit No. 3.1. to Form 10-Q Report for quarter ended June 30, 1998.)
3.2.*
Bylaws as amended effective May 19, 2009. (Exhibit No. 99.1. to Current Report on Form 8-K dated May 19, 2009.)
4.2.*
Questar Dividend Reinvestment and Stock Purchase Plan. (Exhibit No. 4. to Current Report on Form 8-K dated February 8, 2000.)
10.1.*
Stipulation and Agreement, dated October 14, 1981, executed by Mountain Fuel; Wexpro; the Utah Department of Business Regulations, Division of Public Utilities; the Utah Committee of Consumer Services; and the staff of the Public Service Commission of Wyoming. (Exhibit No. 10(a) to Mountain Fuel Supply Company's Form 10-K Annual Report for 1981.)
10.2.*1
Questar Corporation Annual Management Incentive Plan, as amended and restated effective October 28, 2008. (Exhibit No. 10.17. to Form 10-K Annual Report for 2008.)
10.3.* 1
Questar Corporation Executive Incentive Retirement Plan, as amended and restated effective January 1, 2005. (Exhibit No. 10.3. to Form 10-K Annual Report for 2004.)
10.4.*1
Questar Corporation Long-term Stock Incentive Plan, as amended and restated effective August 7, 2007. (Exhibit 10.4 to the Annual Report on Form 10-K for 2007.)
10.5. *1
Questar Corporation Executive Severance Compensation Plan, as amended and restated effective October 23, 2007. (Exhibit No. 99.1 to Current Report on Form 8-K dated October 24, 2007.)
10.6.*1
Questar Corporation Deferred Compensation Plan for Directors, as amended and restated effective January 1, 2005, adopted October 23, 2007. (Exhibit No. 99.2 to Current Report on Form 8-K dated October 24, 2007.)
10.7.*1
Questar Corporation Supplemental Executive Retirement Plan, as amended and restated effective January 1, 2005, adopted August 7, 2007. (Exhibit 10.7 to the Annual Report on Form 10-K for 2007.)
10.8.*1
Questar Corporation Stock Option Plan for Directors, as amended and restated effective October 29, 1998. (Exhibit No. 10.10. to Form 10-Q Report for quarter ended September 30, 1998.)
10.9.*1
Form of Individual Indemnification Agreement dated February 9, 1993, between Questar Corporation and Directors. (Exhibit No. 10.11. to Form 10-K Annual Report for 1992.)
10.10.*1
Questar Corporation Deferred Share Plan, as amended and restated effective January 1, 2003. (Exhibit No.10.10 to Form 10-K Annual Report for 2004.)
10.11.*1
Questar Corporation Deferred Compensation Plan, as amended and restated effective January 1, 2003. (Exhibit No. 10.11 to Form 10-K Annual Report for 2004.)
10.12.*1
Questar Corporation Directors' Stock Plan as approved May 21, 1996. (Exhibit No. 10.15. to Form 10-Q Report for quarter ended June 30, 1996.)
10.13.*1
Questar Corporation Deferred Share Make-Up Plan as amended and restated effective January 1, 2003. (Exhibit No. 10.13 to Form 10-K Annual Report for 2004.)
10.14.1
Questar Corporation Long-Term Cash Incentive Plan as amended and restated effective October 28, 2008.
10.15.*1
Employment Agreement between the Company and Keith O. Rattie effective February 1, 2004. (Exhibit No. 10.15. to Form 10-K Annual Report for 2003.)
10.16.*1
Employment Agreement between the Company and Charles B. Stanley effective February 1, 2004. (Exhibit No. 10.16. to Form 10-K Annual Report for 2003.)
QUESTAR 2009 FORM 10-K
10.17.*1
Questar Corporation Annual Management Incentive Plan II as amended and restated on October 28, 2008. (Exhibit No. 10.17. to Form 10-K Annual Report for 2008.)
10.18.*1
Form of Phantom Stock Agreement dated February 8, 2005, for phantom stock units granted to non-employee directors. (Exhibit No. 10.3 to Current Report on Form 8-K dated February 8, 2005.)
10.19.*1
First Amendment to Employment Agreement of Keith O. Rattie dated May 17, 2005. (Exhibit 10.23 to Current Report on Form 8-K dated May 18, 2005.)
10.20.*1
First Amendment to Employment Agreement of Charles B. Stanley dated May 17, 2005. (Exhibit 10.24 to Current Report on Form 8-K dated May 18, 2005.)
10.21.*1
Form of Option Agreement dated October 24, 2005, for shares granted to key officers. (Exhibit No. 99.1 to Current Report on Form 8-K dated October 27, 2005.)
10.22.*1
Questar Corporation Deferred Compensation Wrap Plan as amended and restated October 28, 2008. (Exhibit No. 10.24. to Form 10-K Annual Report for 2008.)
10.23.*1
Form of Restricted Stock Agreement dated February 14, 2006, for shares granted to certain key executives. (Exhibit No. 10.1 to Current Report on Form 8-K dated February 14, 2006.)
10.24.*1
Form of Restricted Stock Agreement dated February 14, 2006, for shares granted to other officers and key employees. (Exhibit No. 10.2 to Current Report on Form 8-K dated February 14, 2006.)
10.25.*1
Form of Restricted Stock Agreement dated February 14, 2006, for shares granted to non-employee directors. (Exhibit No. 10.3 to Current Report on Form 8-K dated February 14, 2006.)
10.26.*1
Form of Phantom Stock Agreement dated February 14, 2006, for shares granted to non-employee directors. (Exhibit No. 10.4 to Current Report on Form 8-K dated February 14, 2006.)
10.27*1
Form of Restricted Stock Agreement dated February 13, 2007, for shares granted to certain key executives. (Exhibit No. 10.1 to Current Report on Form 8-K dated February 13, 2007.)
10.28*1
Form of Restricted Stock Agreement dated February 13, 2007, for shares granted to other officers and key employees. (Exhibit No. 10.2 to Current Report on Form 8-K dated February 13, 2007.)
10.29*1
Form of Restricted Stock Agreement dated February 13, 2007, for shares granted to non-employee directors. (Exhibit No. 10.3 to Current Report on Form 8-K dated February 13, 2007.)
10.30*1
Form of Phantom Stock Agreement dated February 13, 2007, for shares granted to non-employee directors. (Exhibit No. 10.4 to Current Report on Form 8-K dated February 13, 2007.)
10.31*1
Form of option agreement dated February 13, 2007, for options granted to certain key executives. (Exhibit No. 10.5 to Current Report on Form 8-K dated February 13, 2007.)
10.32*1
Second Amendment to Employment Agreement of Keith O. Rattie dated February 28, 2007 (Exhibit 99.1 to current report on Form 8-K dated February 28, 2007.)
10.33*1
Form of Restricted Stock Agreement dated February 12, 2008 for shares granted to certain key executives. (Exhibit 10.1 to Current Report on Form 8-K dated February 13, 2008.)
10.34*1
Form of Restricted Stock Agreement dated February 12, 2008 for shares granted to other officers and key employees. (Exhibit 10.2 to Current Report on Form 8-K dated February 13, 2008.)
10.35*1
Form of Restricted Stock Agreement dated February 12, 2008 for shares granted to non-employee directors. (Exhibit 10.3 to Current Report on Form 8-K dated February 13, 2008.)
10.36*1
Form of Phantom Stock Agreement dated February 12, 2008 for shares granted to non-employee directors. (Exhibit 10.4 to Current Report on Form 8-K dated February 13, 2008.)
QUESTAR 2009 FORM 10-K
10.37*1
Form of Option Agreement dated February 12, 2008, for options granted to a key executives. (Exhibit 10.5 to Current Report on Form 8-K dated February 13, 2008.)
10.38*1
Second Amendment to Employment Agreement of Charles B. Stanley dated December 31, 2008 (Exhibit 99.2 to current report on Form 8-K dated December 31, 2008.)
10.39*1
Third Amendment to Employment Agreement of Keith O. Rattie dated December 31, 2008 (Exhibit 99.1 to Current Report on Form 8-K dated December 31, 2008.)
10.40*1
Form of Restricted Stock Agreement dated February 10, 2009, for shares granted to other officers. (Exhibit No. 99.2 to Current Report on Form 8-K dated February 10, 2009.)
10.41*1
Form of Restricted Stock Agreement dated February 10, 2009, for shares granted to non-employee directors. (Exhibit No. 99.3 to Current Report on Form 8-K dated February 10, 2009.)
10.42*1
Form of Phantom Stock Agreement dated February 10, 2009, for shares granted to non-employee directors. (Exhibit No. 99.4 to Current Report on Form 8-K dated February 10, 2009.)
10.43*1
Form of Option Agreement dated February 10, 2009, for options granted to certain key executives. (Exhibit No. 99.5 to Current Report on Form 8-K dated February 10, 2009.)
10.44*1
Form of Option Agreement dated February 10, 2009, for options granted to other officers. (Exhibit No. 99.6 to Current Report on Form 8-K dated February 10, 2009.)
10.45*1
Form of Employment Agreement of Richard J. Doleshek dated May 7, 2009 (Exhibit No. 99.1 to Current Report on Form 8-K dated May 7, 2009.)
12.
Ratio of earnings to fixed charges.
14.*
Business Ethics and Compliance Policy.
21.
Subsidiary Information.
23.1.
Consent of Independent Registered Public Accounting Firm.
23.2.
Consent of Independent Petroleum Engineers and Geologists.
23.3
Qualifications and report of Independent Petroleum Engineers and Geologists.
24.
Power of Attorney.
31.1.
Certification signed by Keith O. Rattie, Questar's Chairman, President and Chief Executive Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2.
Certification signed by Richard J. Doleshek, Questar's Executive Vice President and Chief Financial Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.
Certification signed by Keith O. Rattie, Chairman, President and Chief Executive Officer and Richard. J. Doleshek, Executive Vice President and Chief Financial Officer, respectively, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.SCH
XBRL Taxonomy Extension Schema.
101.CAL
XBRL Taxonomy Extension Calculation Linkbase.
101.LAB
XBRL Taxonomy Extension Label Linkbase.
101.PRE
XBRL Taxonomy Extension Presentation Linkbase.
101.INS
XBRL Instance Document.
QUESTAR 2009 FORM 10-K
101.DEF
XBRL Definition.
*Exhibits so marked have been filed with the Securities and Exchange Commission as part of the indicated filing and are incorporated herein by reference.
1Exhibit so marked is management contract or compensation plan or arrangement.
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, on the 26th day of February 2010.
QUESTAR CORPORATION
(Registrant)
By /s/Keith O. Rattie
Keith O. Rattie
Chairman, President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.
/s/Keith O. Rattie
Chairman, President and
Keith O. Rattie
Chief Executive Officer
(Principal Executive Officer)
/s/Richard J. Doleshek
Executive Vice President and
Richard J. Doleshek
Chief Financial Officer
(Principal Financial and Accounting Officer)
* P. S. Baker, Jr.
Director
*Teresa Beck
Director
*R. D. Cash
Director
*L. Richard Flury
Director
*J. A. Harmon
Director
*Robert E. McKee III
Director
*Gary G. Michael
Director
*Keith O. Rattie
Director
*M. W. Scoggins
Director
*Harris H. Simmons
Director
*C. B. Stanley
Director
*Bruce A. Williamson
Director
February 26, 2010
*/s/Keith O. Rattie
Keith O. Rattie, Attorney in Fact
EXHIBIT INDEX
Exhibit No.
Description
3.1.*
Restated Articles of Incorporation as amended effective May 19, 1998. (Exhibit No. 3.1. to Form 10-Q Report for quarter ended June 30, 1998.)
3.2.*
Bylaws as amended effective May 19, 2009. (Exhibit No. 99.1. to Current Report on Form 8-K dated May 19, 2009.)
QUESTAR 2009 FORM 10-K
4.2.*
Questar Dividend Reinvestment and Stock Purchase Plan. (Exhibit No. 4. to Current Report on Form 8-K dated February 8, 2000.)
10.1.*
Stipulation and Agreement, dated October 14, 1981, executed by Mountain Fuel; Wexpro; the Utah Department of Business Regulations, Division of Public Utilities; the Utah Committee of Consumer Services; and the staff of the Public Service Commission of Wyoming. (Exhibit No. 10(a) to Mountain Fuel Supply Company's Form 10-K Annual Report for 1981.)
10.2.*1
Questar Corporation Annual Management Incentive Plan, as amended and restated effective October 28, 2008. (Exhibit No. 10.17. to Form 10-K Annual Report for 2008.)
10.3.* 1
Questar Corporation Executive Incentive Retirement Plan, as amended and restated effective January 1, 2005. (Exhibit No. 10.3. to Form 10-K Annual Report for 2004.)
10.4.*1
Questar Corporation Long-term Stock Incentive Plan, as amended and restated effective August 7, 2007. (Exhibit 10.4 to the Annual Report on Form 10-K for 2007.)
10.5. *1
Questar Corporation Executive Severance Compensation Plan, as amended and restated effective October 23, 2007. (Exhibit No. 99.1 to Current Report on Form 8-K dated October 24, 2007.)
10.6.*1
Questar Corporation Deferred Compensation Plan for Directors, as amended and restated effective January 1, 2005, adopted October 23, 2007. (Exhibit No. 99.2 to Current Report on Form 8-K dated October 24, 2007.)
10.7.*1
Questar Corporation Supplemental Executive Retirement Plan, as amended and restated effective January 1, 2005, adopted August 7, 2007. (Exhibit 10.7 to the Annual Report on Form 10-K for 2007.)
10.8.*1
Questar Corporation Stock Option Plan for Directors, as amended and restated effective October 29, 1998. (Exhibit No. 10.10. to Form 10-Q Report for Quarter Ended September 30, 1998.)
10.9.*1
Form of Individual Indemnification Agreement dated February 9, 1993, between Questar Corporation and Directors. (Exhibit No. 10.11. to Form 10-K Annual Report for 1992.)
10.10.*1
Questar Corporation Deferred Share Plan, as amended and restated effective January 1, 2003. (Exhibit No.10.10 to Form 10-K Annual Report for 2004.)
10.11.*1
Questar Corporation Deferred Compensation Plan, as amended and restated effective January 1, 2003. (Exhibit No. 10.11 to Form 10-K Annual Report for 2004.)
10.12.*1
Questar Corporation Directors' Stock Plan as approved May 21, 1996. (Exhibit No. 10.15. to Form 10-Q Report for quarter ended June 30, 1996.)
10.13.*1
Questar Corporation Deferred Share Make-Up Plan as amended and restated effective January 1, 2003. (Exhibit No. 10.13 to Form 10-K Annual Report for 2004.)
10.14.1
Questar Corporation Long-Term Cash Incentive Plan as amended and restated effective October 28, 2008.
10.15.*1
Employment Agreement between the Company and Keith O. Rattie effective February 1, 2004. (Exhibit No. 10.15. to Form 10-K Annual Report for 2003.)
10.16.*1
Employment Agreement between the Company and Charles B. Stanley effective February 1, 2004. (Exhibit No. 10.16. to Form 10-K Annual Report for 2003.)
10.17.*1
Questar Corporation Annual Management Incentive Plan II as amended and restated on October 28, 2008. (Exhibit No. 10.17. to Form 10-K Annual Report for 2008.)
10.18.*1
Form of Phantom Stock Agreement dated February 8, 2005, for phantom stock units granted to non-employee directors. (Exhibit No. 10.3 to Current Report on Form 8-K dated February 8, 2005.)
10.19.*1
First Amendment to Employment Agreement of Keith O. Rattie dated May 17, 2005. (Exhibit 10.23 to Current Report on Form 8-K dated May 18, 2005.)
QUESTAR 2009 FORM 10-K
10.20.*1
First Amendment to Employment Agreement of Charles B. Stanley dated May 17, 2005. (Exhibit 10.24 to Current Report on Form 8-K dated May 18, 2005.)
10.21.*1
Form of Option Agreement dated October 24, 2005, for shares granted to key officers. (Exhibit No. 99.1 to Current Report on Form 8-K dated October 27, 2005.)
10.22.*1
Questar Corporation Deferred Compensation Wrap Plan as amended and restated October 28, 2008. (Exhibit No. 10.24. to Form 10-K Annual Report for 2008.)
10.23.*1
Form of Restricted Stock Agreement dated February 14, 2006, for shares granted to certain key executives. (Exhibit No. 10.1 to Current Report on Form 8-K dated February 14, 2006.)
10.24.*1
Form of Restricted Stock Agreement dated February 14, 2006, for shares granted to other officers and key employees. (Exhibit No. 10.2 to Current Report on Form 8-K dated February 14, 2006.)
10.25.*1
Form of Restricted Stock Agreement dated February 14, 2006, for shares granted to non-employee directors. (Exhibit No. 10.3 to Current Report on Form 8-K dated February 14, 2006.)
10.26.*1
Form of Phantom Stock Agreement dated February 14, 2006, for shares granted to non-employee directors. (Exhibit No. 10.4 to Current Report on Form 8-K dated February 14, 2006.)
10.27*1
Form of Restricted Stock Agreement dated February 13, 2007, for shares granted to certain key executives. (Exhibit No. 10.1 to Current Report on Form 8-K dated February 13, 2007.)
10.28*1
Form of Restricted Stock Agreement dated February 13, 2007, for shares granted to other officers and key employees. (Exhibit No. 10.2 to Current Report on Form 8-K dated February 13, 2007.)
10.29*1
Form of Restricted Stock Agreement dated February 13, 2007, for shares granted to non-employee directors. (Exhibit No. 10.3 to Current Report on Form 8-K dated February 13, 2007.)
10.30*1
Form of Phantom Stock Agreement dated February 13, 2007, for shares granted to non-employee directors. (Exhibit No. 10.4 to Current Report on Form 8-K dated February 13, 2007.)
10.31*1
Form of option agreement dated February 13, 2007, for options granted to certain key executives. (Exhibit No. 10.5 to Current Report on Form 8-K dated February 13, 2007.)
10.32*1
Second Amendment to Employment Agreement of Keith O. Rattie dated February 28, 2007 (Exhibit 99.1 to Current Report on Form 8-K dated February 28, 2007.)
10.33*1
Form of Restricted Stock Agreement dated February 12, 2008 for shares granted to certain key executives. (Exhibit 10.1 to Current Report on Form 8-K dated February 13, 2008.)
10.34*1
Form of Restricted Stock Agreement dated February 12, 2008 for shares granted to other officers and key employees. (Exhibit 10.2 to Current Report on Form 8-K dated February 13, 2008.)
10.35*1
Form of Restricted Stock Agreement dated February 12, 2008 for shares granted to non-employee directors. (Exhibit 10.3 to Current Report on Form 8-K dated February 13, 2008.)
10.36*1
Form of Phantom Stock Agreement dated February 12, 2008 for shares granted to non-employee directors. (Exhibit 10.4 to Current Report on Form 8-K dated February 13, 2008.)
10.37*1
Form of Option Agreement dated February 12, 2008, for options granted to a key executives. (Exhibit 10.5 to Current Report on Form 8-K dated February 13, 2008.)
10.38*1
Second Amendment to Employment Agreement of Charles B. Stanley dated December 31, 2008 (Exhibit 99.2 to Current Report on Form 8-K dated December 31, 2008.)
10.39*1
Third Amendment to Employment Agreement of Keith O. Rattie dated December 31, 2008 (Exhibit 99.1 to current report on Form 8-K dated December 31, 2008.)
QUESTAR 2009 FORM 10-K
10.40*1
Form of Restricted Stock Agreement dated February 10, 2009, for shares granted to other officers. (Exhibit No. 99.2 to Current Report on Form 8-K dated February 10, 2009.)
10.41*1
Form of Restricted Stock Agreement dated February 10, 2009, for shares granted to non-employee directors. (Exhibit No. 99.3 to Current Report on Form 8-K dated February 10, 2009.)
10.42*1
Form of Phantom Stock Agreement dated February 10, 2009, for shares granted to non-employee directors. (Exhibit No. 99.4 to Current Report on Form 8-K dated February 10, 2009.)
10.43*1
Form of Option Agreement dated February 10, 2009, for options granted to certain key executives. (Exhibit No. 99.5 to Current Report on Form 8-K dated February 10, 2009.)
10.44*1
Form of Option Agreement dated February 10, 2009, for options granted to other officers. (Exhibit No. 99.6 to Current Report on Form 8-K dated February 10, 2009.)
10.45*1
Form of Employment Agreement of Richard J. Doleshek dated May 7, 2009 (Exhibit No. 99.1 to Current Report on Form 8-K dated May 7, 2009.)
12.
Ratio of earnings to fixed charges.
14.*
Business Ethics and Compliance Policy.
21.
Subsidiary Information.
23.1.
Consent of Independent Registered Public Accounting Firm.
23.2.
Consent of Independent Petroleum Engineers and Geologists.
23.3
Qualifications and report of Independent Petroleum Engineers and Geologists.
24.
Power of Attorney.
31.1.
Certification signed by Keith O. Rattie, Questar's Chairman, President and Chief Executive Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2.
Certification signed by Richard J. Doleshek, Questar's Executive Vice President and Chief Financial Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.
Certification signed by Keith O. Rattie, Chairman, President and Chief Executive Officer and Richard. J. Doleshek, Executive Vice President and Chief Financial Officer, respectively, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.SCH
XBRL Taxonomy Extension Schema.
101.CAL
XBRL Taxonomy Extension Calculation Linkbase.
101.LAB
XBRL Taxonomy Extension Label Linkbase.
101.PRE
XBRL Taxonomy Extension Presentation Linkbase.
101.INS
XBRL Instance Document.
101.DEF
XBRL Definition.
*Exhibits so marked have been filed with the Securities and Exchange Commission as part of the indicated filing and are incorporated herein by reference.
1Exhibit so marked is management contract or compensation plan or arrangement.
QUESTAR 2009 FORM 10-K