UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the Year Ended December 31, 2006
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QUESTAR CORPORATION
(Exact name of registrant as specified in charter)
STATE OF UTAH 1-8796 87-0407509
(State or other jurisdiction of (Commission File No.) (I.R.S. Employer
incorporation or organization) Identification No.)
180 East 100 South, P.O. Box 45433, Salt Lake City, Utah 84145-0433
(Address of principal executive offices)
Registrant’s telephone number: (801) 324-5000
Securities registered pursuant to Section 12(b) of the Act:
Common stock without par value
The above Securities are listed on the New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes [X]
No [ ]
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Yes [ ]
No [X]
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ ]
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):
QUESTAR 2006 FORM 10-K 1
Large accelerated filer [X] Accelerated filer [ ] Non-accelerated filer [ ]
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes [ ]
No [X]
Aggregate market value of the voting common equity held by non-affiliates of the registrant as of the last business day of the registrant’s most recently completed second quarter (June 30, 2006): $6.9 billion.*
On January 31, 2007, 85,946,432 shares of the registrant’s common stock, without par value, were outstanding.
Documents Incorporated by Reference. Portions of the Registrant’s Definitive Proxy Statement (the “Proxy Statement”) to be filed with respect to its annual meeting of shareholders scheduled to be held on May 15, 2007.
*Calculated by excluding all shares held by directors and executive officers of registrant and three nonprofit foundations established by registrant without conceding that all such persons are affiliates for purposes of federal securities laws.
QUESTAR 2006 FORM 10-K 2
TABLE OF CONTENTS
Page No.
Where You Can Find More Information
4
4
Glossary of Commonly Used Terms
5
Nature of Business
7
Market Resources
8
Questar E&P
8
Wexpro
9
Gas Management
10
Energy Trading
10
Questar Pipeline
10
Questar Gas
12
Corporate and Other Operations
13
Environmental Matters
13
Employees
13
Executive Officers
13
14
17
Questar E&P
17
Wexpro
17
Gas Management
21
Energy Trading
21
Questar Pipeline
22
Questar Gas
22
22
SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
23
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER
MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
24
25
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATION
26
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
42
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
48
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE
85
85
87
DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
87
87
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
87
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS,
AND DIRECTOR INDEPENDENCE
87
PRINCIPAL ACCOUNTING FEES AND SERVICES
88
EXHIBITS, FINANCIAL STATEMENT SCHEDULES
88
91
Where You Can Find More Information
Questar Corporation (Questar) and its principal subsidiaries, Questar Market Resources, Inc., Questar Pipeline Company and Questar Gas Company, each file annual, quarterly, and current reports with the Securities and Exchange Commission (SEC). Questar also regularly files proxy statements and other documents with the SEC. The public may read and copy these reports and any other materials filed with the SEC at its Public Reference Room at 450 Fifth Street, N.W., Washington, D.C. 20549-0213. Please call the SEC at 1-800-SEC-0330 for further information on the operation of the Public Reference Room. The SEC also maintains a web site that contains information filed electronically that can be accessed over the Internet at www.sec.gov.
Investors can also access financial and other information via Questar’s web site at www.questar.com. Questar and each of its reporting subsidiaries make available, free of charge through the web site copies of Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and any amendments to such reports and all reports filed by executive officers and directors under Section 16 of the Exchange Act reporting transactions in Questar securities. Access to these reports is provided as soon as reasonably practical after such reports are electronically filed with the SEC. Questar’s web site also contains Statements of Responsibility for Board Committees, Corporate Governance Guidelines and its Business Ethics and Compliance Policy.
Finally, you may request a copy of filings other than an exhibit to a filing unless that exhibit is specifically incorporated by reference into that filing, at no cost by writing or calling Questar, 180 East 100 South Street, P.O. Box 45433, Salt Lake City, Utah 84145-0433 (telephone number (801) 324-5000).
Forward-Looking Statements
This Annual Report may contain or incorporate by reference information that includes or is based upon “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements give expectations or forecasts of future events. You can identify these statements by the fact that they do not relate strictly to historical or current facts. They use words such as “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe,” and other words and terms of similar meaning in connection with a discussion of future operating or financial performance. In particular, these include statements relating to future actions,
QUESTAR 2006 FORM 10-K 4
prospective services or products, future performance or results of current and anticipated services or products, exploration efforts, expenses, the outcome of contingencies such as legal proceedings, trends in operations and financial results.
Any or all forward-looking statements may turn out to be wrong. They can be affected by inaccurate assumptions or by known or unknown risks and uncertainties. Many such factors will be important in determining actual future results. These statements are based on current expectations and the current economic environment. They involve a number of risks and uncertainties that are difficult to predict. These statements are not guarantees of future performance. Actual results could differ materially from those expressed or implied in the forward-looking statements. Among factors that could cause actual results to differ materially are:
·
the risk factors discussed in Part I, Item 1A of this Annual Report;
·
general economic conditions, including the performance of financial markets and interest rates;
·
changes in industry trends;
·
changes in laws or regulations; and
·
other factors, most of which are beyond control.
Questar undertakes no obligation to publicly correct or update the forward-looking statements in this Annual Report, in other documents, or on the web site to reflect future events or circumstances. All such statements are expressly qualified by this cautionary statement.
Glossary of Commonly Used Terms
B
Billion.
bbl
Barrel, which is equal to 42 U.S. gallons and is a common measure of volume of crude oil and other liquid hydrocarbons.
basis
The difference between a reference or benchmark commodity price and the corresponding sales price at various regional sales points.
Btu
One British thermal unit – a measure of the amount of energy required to raise the temperature of a one-pound mass of water one degree Fahrenheit at sea level.
cash flow hedge
A derivative instrument that complies with Statement of Financial Accounting Standards (SFAS) 133, as amended, and is used to reduce the exposure to variability in cash flows from the forecasted physical sale of gas and oil production whereby the gains (losses) on the derivative transaction are anticipated to offset the losses (gains) on the forecasted physical sale.
cf
Cubic foot is a common unit of gas measurement. One standard cubic foot equals the volume of gas in one cubic foot measured at standard conditions – a temperature of 60 degrees Fahrenheit and a pressure of 30 inches of mercury (approximately 14.7 pounds per square inch).
cfe
Cubic feet of natural gas equivalents.
development well
A well drilled into a known producing formation in a previously discovered field.
dewpoint
A specific temperature and pressure at which hydrocarbons condense to form a liquid.
dry hole
A well drilled and found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of production exceed expenses and taxes.
dth
Decatherms or ten therms. One dth equals one million Btu or approximately one Mcf.
dthe
Decatherms of natural gas equivalents.
equity production
Production at the wellhead attributed to Questar ownership.
exploratory well
QUESTAR 2006 FORM 10-K 5
A well drilled into a previously untested geologic prospect to determine the presence of gas or oil.
finding costs
The sum of costs incurred for gas and oil exploration and development activities; including purchases of reserves in place, leasehold acquisitions, seismic, geological and geophysical, development and exploration drilling and asset retirement obligations for a given period, divided by the total amount of estimated net proved reserves added through discoveries, positive and negative revisions and purchases in place for the same period. The Company expresses finding costs in dollars per Mcfe averaged over a five-year period.
frac spread
The difference between the market value for NGL extracted from the gas stream and the market value of the Btu-equivalent volume of natural gas required to replace the extracted liquids.
futures contract
An exchange-traded contract to buy or sell a standard quantity and quality of a commodity at a specified future date and price.
gal
U.S. gallon.
gas
All references to “gas” in this report refer to natural gas.
gross
“Gross” natural gas and oil wells or “gross” acres are the total number of wells or acres in which the Company has a working interest.
heating degree days
A measure of the number of degrees the average daily outside temperature is below 65 degrees Fahrenheit.
hedging
The use of derivative commodity and interest-rate instruments to reduce financial exposure to commodity price and interest-rate volatility.
infill development drilling
Drilling wells between established producing wells; a drilling program to reduce the spacing between wells in order to increase production and/or recovery of in-place hydrocarbons.
lease operating expenses
The expenses, usually recurring, which are incurred to operate the wells and equipment on a producing lease.
M
Thousand.
MM
Million.
natural gas equivalents
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.
natural gas liquids (NGL)
Liquid hydrocarbons that are extracted and separated from the natural gas stream. NGL products include ethane, propane, butane, natural gasoline and heavier hydrocarbons.
net
“Net” gas and oil wells or “net” acres are determined by the sum of the fractional ownership working interest the Company has in those gross wells or acres.
net revenue interest
A share of production after all burdens, such as royalties and overriding royalties, have been deducted from the working interest. It is the percentage of production that each owner actually receives.
production replacement ratio
The production replacement ratio is calculated by dividing the net proved reserves added through discoveries, positive and negative revisions and purchases and sales in-place for a given period by the production for the same period, expressed as a percentage. The production replacement ratio is typically reported on an annual basis.
proved reserves
Those quantities of natural gas, crude oil, condensate and NGL on a net revenue interest basis, which geological and engineering data demonstrate with reasonable certainty to be recoverable under existing economic and operating conditions. See 17 C.F.R. Section 4-10(a)(2) for a complete definition.
proved developed reserves
Reserves that include proved developed producing reserves and proved developed nonproducing reserves. See 17 C.F.R. Section 4-10(a)(3).
QUESTAR 2006 FORM 10-K 6
proved developed producing reserves
Reserves expected to be recovered from existing completion intervals in existing wells.
proved undeveloped reserves
Reserves expected to be recovered from new wells on proved undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. See 17 C.F.R. Section 4-10(a)(4).
reservoir
A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
royalty
An interest in an oil and gas lease that gives the owner the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.
seismic
An exploration method of sending energy waves or sound waves into the earth and recording the wave reflections to indicate the type, size, shape and depth of a subsurface rock formation. (2-D seismic provides two-dimensional information and 3-D seismic provides three-dimensional views.)
wet gas
Unprocessed natural gas that contains a mixture of heavier hydrocarbons including ethane, propane, butane and natural gasoline.
working interest
An interest in an oil and gas lease that gives the owner the right to drill, produce and conduct operating activities on the leased acreage and receive a share of any production.
workover
Operations on a producing well to restore or increase production.
FORM 10-K
ANNUAL REPORT, 2006
PART I
ITEM 1. BUSINESS.
Nature of Business
Questar Corporation (Questar or the Company) is a natural gas-focused energy company with four major lines of business – gas and oil exploration and production, midstream field services, 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 services.
·
Questar Gas Company (Questar Gas) provides retail natural gas distribution.
See Note 15 to the consolidated financial statements included in Item 8 of Part II of this Annual Report for financial information concerning Questar’s lines of business that contribute 10% or more of consolidated revenues.
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 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.
QUESTAR 2006 FORM 10-K 7
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 under the symbol STR.
The corporate-organization structure and major subsidiaries are summarized below:
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Market Resources
Market Resources is a natural gas-focused energy company, a wholly owned subsidiary of Questar and Questar’s primary growth driver. Market Resources is a subholding company with four principal subsidiaries: Questar E&P acquires, explores for, develops and produces natural gas, oil, and NGL; Wexpro manages, develops and produces cost-of-service reserves for affiliate Questar Gas; Gas Management provides midstream field services including natural gas-gathering and processing services for affiliates and third parties; and Energy Trading markets equity and third-party gas and oil, provides risk-management services, and through its wholly owned limited liability company, Clear Creek Storage Company, LLC, owns and operates an underground natural gas-storage reservoir.
Questar E&P
Questar E&P operates in two core areas – the Rocky Mountain region of Wyoming, Utah and Colorado 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, in the Uinta Basin of Utah and in the Elm Grove area of northwestern Louisiana. Questar E&P continues to conduct exploratory drilling to determine the commerciality of its inventory of undeveloped leaseholds located primarily in the Rocky Mountain region. 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 1,631.4 Bcfe of estimated proved reserves as of December 31, 2006. Approximately 81% of Questar E&P’s proved reserves, or 1,322.5 Bcfe, were located in the Rocky Mountain region of the United States, while the remaining 19%, or 308.9 Bcfe, were located in the Midcontinent region. Approximately 990.7 Bcfe of the proved reserves reported by Questar E&P at year-end 2006 were developed, while 640.7 Bcfe were proved undeveloped. The majority of the proved undeveloped reserves were
QUESTAR 2006 FORM 10-K 8
associated with the Company’s Pinedale Anticline leasehold. Natural gas comprised about 90% of Questar E&P’s total proved reserves at year-end 2006. 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 Questar E&P’s proved reserves.
Questar E&P – Competition and Customers
Questar E&P faces competition in every part of its business, including the acquisition of reserves and leases. 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. Competition is particularly intense when prices are high, as has been the case in recent years.
Questar E&P, through Energy Trading, sells natural gas production to a variety of customers, including gas-marketing firms, industrial users and local-distribution companies. It regularly evaluates counterparty credit and may require financial guarantees from parties that fail to meet its credit criteria. Energy Trading sells equity 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 to storage, refining or pipeline facilities.
Questar E&P – Regulation
Questar E&P 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.
Most Questar E&P leases in the Rocky Mountain area are granted by the federal government and administered by federal agencies. Development of Pinedale leasehold acreage is subject to the terms of certain winter-drilling restrictions. In 2004, Market Resources worked with federal and state officials in Wyoming to obtain authorization for limited winter-drilling activities and has developed innovative measures, such as drilling multiple wells from a single location, to minimize the impact of its activities on wildlife and wildlife habitat. A Supplemental Environmental Impact Statement is currently being prepared by the Bureau of Land Management, (BLM) to consider expanded winter-drilling and completion operations on the Pinedale Anticline. The presence of wildlife and potential endangered species could limit access to public lands. Various wildlife species inhabit Market Resources leaseholds at Pinedale and in other areas. Current federal regulations restrict activities during certain times of the year on portions of Market Resources leaseholds due to wildlife activity and/or habitat.
Wexpro
Wexpro develops and produces gas and oil on certain properties for affiliate Questar Gas under the terms of a comprehensive agreement, the Wexpro Agreement. Pursuant to the Wexpro Agreement, Wexpro recovers its costs and receives an unlevered after-tax return of approximately 19-20% on its investment in commercial wells and related facilities – adjusted for working capital and reduced for deferred income taxes and depreciation – its investment base. The term of the Wexpro Agreement coincides with the productive life of the gas and oil properties covered therein. Wexpro’s investment base totaled $260.6 million at December 31, 2006. See Note 14 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 43% of Questar Gas supply requirements during 2006 at prices that were significantly lower than Questar Gas cost for purchased gas.
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.
Wexpro owns oil-producing properties. Under terms of the Wexpro Agreement, revenues from crude-oil sales offset operating expenses and provide Wexpro with a return on its investment. Any remaining revenues, after recovery of expenses and Wexpro’s return on investment, are divided between Wexpro (46%) and Questar Gas (54%).
Wexpro 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 unlocked 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
QUESTAR 2006 FORM 10-K 9
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.
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.
Gas Management
Gas Management provides natural gas-gathering and processing services to affiliates and third-party producers in the Rocky Mountain region. Gas Management owns 50% 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), a partnership that operates gas-gathering facilities in eastern Utah. Under a contract with Questar Gas, Gas Management also gathers cost-of-service volumes produced from properties operated by Wexpro.
Approximately 58% of Gas Management’s 2006 revenues were derived from fee-based gathering and processing agreements. The remaining revenues were derived from natural gas processing margins that are in part exposed to the frac spread. To reduce processing margin risk, Gas Management has restructured many of its processing agreements with producers from “keep-whole” contracts to “fee-based” contracts. A keep-whole contract insulates producers from frac spread risk while a fee-based contract eliminates commodity price risk for the processing plant owner. To further reduce processing margin volatility associated with keep-whole contracts, Gas Management may also attempt to reduce processing margin risk with forward-sales contracts for NGL or hedge NGL prices and equivalent gas volumes with the intent to lock in a processing margin.
Energy Trading
Energy Trading markets natural gas, oil and NGL. It combines gas volumes purchased from third parties and equity production 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 close to reserves owned by affiliates or accessible by major pipelines. It 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 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.
Energy Trading uses derivatives 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 Notes 1 and 9 to the consolidated financial statements included in Item 8 and in Item 7A of Part II of this Annual Report for additional information relating to hedging activities.
Questar Pipeline
Questar Pipeline is an interstate pipeline company that provides natural gas-transportation and underground storage services in Utah, Wyoming and Colorado. As a “natural gas company” under the Natural Gas Act of 1938, Questar Pipeline and certain subsidiary pipeline companies are regulated by the Federal Energy Regulatory Commission (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 2,503 miles of interstate pipeline with total daily capacity of 3,442 Mdth. Questar Pipeline’s core-transmission system is strategically located in the Rocky Mountain area 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 a subsidiary, owns and operates the 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.
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 plants near Price, Utah, which provides heat-content-management services for Questar Gas and carbon-dioxide extraction and gas-processing services for third parties.
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Questar Pipeline – Customers, Growth and Competition
Questar Pipeline faces risk of recontracting firm capacity as contract terms expire. Questar Pipeline’s transportation system is nearly fully subscribed, and firm contracts had a weighted-average remaining life of 9.2 years as of December 31, 2006. All of Questar Pipeline storage capacity is fully contracted with a weighted-average remaining life of 7.5 years as of December 31, 2006.
Questar Gas remains Questar Pipeline’s largest transportation customer. During 2006, Questar Pipeline transported 116.7 MMdth for Questar Gas compared to 116.3 MMdth in 2005. Questar Gas has reserved firm-transportation capacity of 951 Mdth per day under long-term contracts, or about 50% of Questar Pipeline’s reserved capacity, during the three coldest months of the year. Questar Pipeline’s primary transportation agreement with Questar Gas will expire on June 30, 2017.
Questar Pipeline also transported 320.4 MMdth for nonaffiliated customers to pipelines owned by Kern River Pipeline, Northwest Pipeline, Colorado Interstate Gas, TransColorado, Wyoming Interstate Company and other systems. Questar Pipeline’s tariff does not contain an explicit hydrocarbon dewpoint limit for gas delivered into its system. Questar Pipeline is able to transport gas with a higher hydrocarbon dewpoint specification than most other systems through use of enhanced liquid handling and processing facilities on its system and agreements with third-party processors. As a consequence, Questar Pipeline must incur higher costs to meet the hydrocarbon dewpoint specifications of these downstream interconnecting pipelines. In effect, Questar Pipeline currently provides a bundled gas-transportation and dewpoint-management service for shippers at certain delivery points consistent with FERC’s policy statement on gas quality and interchangeability standards issued in June 2006. Questar Pipeline proposes to amend its tariff to enable it to manage hydrocarbon dewpoint levels on its system, in a fair and efficient manner, to meet downstream interconnecting pipeline gas quality specifications and maximize system throughput for its shipper.
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. Some parties, including Gas Management, an affiliate of Questar Pipeline, are building gathering lines that allow producers to make direct connections to competing pipeline systems.
During 2006, Questar Pipeline completed a 27.2-mile expansion of its Overthrust Pipeline to connect with Kern River at Opal, Wyoming. The expansion went into service on January 1, 2007, and is supported with long-term contracts.
Questar Pipeline has two planned expansions during 2007. Overthrust Pipeline plans to extend 78 miles from Rock Springs to Wamsutter, Wyoming. This expansion will complete the western segment of the Rockies Express Pipeline project and is supported with a long-term capacity lease. Questar Pipeline plans to expand the capacity on its southern system with 58 miles of pipe looping its current system and additional compression. This project is supported with long-term contracts.
Southern Trails Pipeline
In mid-2002, Questar Southern Trails Pipeline, a Questar Pipeline subsidiary, placed the eastern segment of the Southern Trails pipeline into service. The eastern segment extends from the San Juan Basin to inside the California state line. Capacity on this segment is fully committed under contracts that expire in mid-2008 and mid-2015.
The California segment of the Southern Trails Pipeline, which extends from near the California-Arizona state line to Long Beach, California, is currently not in service. Questar Pipeline is pursuing several options to sell or place this line in service.
See Note 4 to the consolidated financial statements included in Item 8 of Part II of this Annual Report for discussion of an impairment of the California segment of Southern Trails.
Questar Pipeline – Regulation
On January 18, 2007, the FERC proposed permanent standards of conduct regulation in a Notice of Proposed Rulemaking (NOPR) that will replace an Interim Rule governing the relationship between transmission providers and their energy affiliates. The Interim Rule was put forth January 9, 2007, by the FERC in response to Order No. 2004 being vacated November 17, 2006, by the U.S. Court of Appeals for the District of Columbia Circuit. The Court of Appeals found that the FERC had not adequately supported the application of the standards of conduct to a broader definition of energy affiliates in Order No. 2004. In its NOPR the FERC proposed that the standards of conduct apply only to marketing affiliates. The proposed definition of marketing affiliate is similar to the definition found in Order No. 497 (pre-Order No. 2004).
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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.
Clay Basin Storage Gas
See Results of Operation included in Item 7 of Part II of this Annual Report for discussion of Clay Basin storage gas loss.
Questar Gas
Questar Gas distributes natural gas as a public utility in Utah, southwestern Wyoming and a small portion of southeastern Idaho. As of December 31, 2006, Questar Gas was serving 850,542 sales and transportation customers. Questar Gas is the only non-municipal gas-distribution utility in Utah, where over 96% 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 2006, Questar Gas added 26,095 customers, a 3.2% increase.
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 115 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. The Company’s prior rate structure penalized the Company for declining usage per customer and rewarded the Company for increasing usage per customer. 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 will be limited to one percent of total revenues for the first year. The program will be reviewed after one year. Questar Gas recorded a $1.7 million revenue reduction in 2006 to recognize the impact of the CET.
In January 2007, the PSCU approved a demand-side management program (DSM) effective January 1, 2007. Under the DSM, Questar Gas will encourage the conservation of natural gas through advertising, rebates for efficient homes and appliances, and energy audits. The costs of the DSM will be deferred and recovered from customers through periodic rate adjustments.
Questar Gas minimizes gas supply risk with cost-of-service natural gas reserves. During 2006, Questar Gas satisfied 43% of its supply requirements with cost-of-service gas and associated royalty-interest 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 include costs associated with hedging activities in its balancing account for pass-through treatment.
Questar Gas has designed its distribution system and annual gas-supply plan to handle design-day demand requirements. It periodically updates its design-day demand, the volume of gas that firm customers could use during extremely cold weather. For the 2006-07 heating season, Questar Gas used a design-day demand of 1.2 MMdth for firm customers.
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 contracts to take deliveries at several locations on the Kern River Pipeline.
QUESTAR 2006 FORM 10-K 12
Questar Gas – Regulation
As a public utility, Questar Gas is subject to the jurisdiction of the PSCU and PSCW. Natural gas sales and transportation services are made under rate schedules approved by the two regulatory commissions. Questar Gas is authorized to earn a return on equity of 11.2% in Utah and 11.83% 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, generally semi-annual basis. Questar Gas has also received permission from the PSCU and PCSW to reflect in its gas costs specified costs associated with hedging contracts.
See Note 11 of the consolidated financial statements included in Item 8 of Part II in this Annual Report for a discussion of gas-processing cost coverage.
Questar Gas has significant relationships with affiliates that have allowed it to lower its costs and improve efficiency. These affiliate relationships, however, are subject to oversight by regulatory commissions for evidence of subsidization and above-market payments.
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 $2.0 million per year of these costs beginning June 2006 and to record a regulatory asset for additional incremental operating costs incurred to comply with this Act.
Questar Gas – Competition
Questar Gas is a public utility and currently has no direct competition from other distributors of natural gas for residential and commercial customers. It has historically enjoyed a favorable price comparison with other energy sources used by residential and commercial customers except coal and occasionally fuel oil. It provides transportation service to industrial customers that can buy volumes of gas directly from others. Questar Gas earns lower margins on this transportation service than firm-sales service and could lose customers to Kern River.
Corporate and Other Operations
Questar’s Other Operations include commercial real-estate management; wellhead gas analysis and automation, field compression and engine maintenance.
Environmental Matters
A discussion of Questar’s environmental matters is included in Item 3 of Part I of this Annual Report.
Employees
At December 31, 2006, the Company had 2,188 employees, including 679 in Market Resources, 265 in Questar Pipeline, 1,175 in Questar Gas and 69 in Corporate and Other Operations.
Executive Officers
The following individuals are serving as executive officers of the Company:
Primary Positions Held with the Company
and Affiliates, Other Business Experience
Name
Keith O. Rattie
53
Chairman (2003); President (2001); Chief Executive Officer (2002); Director (2001); Chief Operating Officer (2001 to 2002); Director, Questar affiliates (2001). Prior to coming to Questar, Mr. Rattie served successively as Vice President and Senior Vice President of the Coastal Corporation (1996 to 2001).
Charles B. Stanley
48
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 to 2002); Executive Vice President and Chief Operating Officer, Market Resources and Market Resources subsidiaries (2002 to 2002). Prior to joining Questar, Mr. Stanley was President, Chief Executive Officer and Director, Coastal Gas
QUESTAR 2006 FORM 10-K 13
International Co. (1995 to 2000); President and Chief Executive Officer, El Paso Oil and Gas Canada, Inc. (2000 to January 2002).
Alan K. Allred
56
Executive Vice President, Questar (2003); President and Chief Executive Officer and Director, Questar Regulated Services and Questar Gas (2003); Chief Executive Officer and Director, Questar Pipeline (2003 to 2006); President, Questar Pipeline (2003 to 2005); Executive Vice President and Chief Operating Officer, Questar Regulated Services, Questar Gas and Questar Pipeline (2002 to 2003); Senior Vice President, Questar Regulated Services, Questar Gas and Questar Pipeline (2002 to 2002); Vice President, Business Development, Questar Regulated Services, Questar Gas and Questar Pipeline (2000 to 2002); Manager, Regulatory Affairs, Questar Gas and Questar Pipeline (1997 to 2000).
R. Allan Bradley
55
Senior Vice President, Questar (2005); Chief Executive Officer, Questar Pipeline (2006); President, Chief Operating Officer and Director, Questar Pipeline (2005); Prior to joining Questar, Mr. Bradley was Managing Director and founding member, Ventura Energy LLC (2002 to 2004) and Senior Vice President, Coastal Corporation and El Paso Corporation affiliates (1990-2002).
Stephen E. Parks
55
Senior Vice President and Chief Financial Officer (2001); Chief Financial Officer (1996); Treasurer (1984 to 2004); Vice President (1990 to 2001); Vice President and Chief Financial Officer of all affiliates (at various dates beginning 1984); and Director Market Resources subsidiaries (at various dates beginning in 1996).
Thomas C. Jepperson
52
Vice President and General Counsel, Questar (2005); Division Counsel (2000 to 2004) Managing Attorney (1990 to 1999) and Senior Attorney (1988 to 1989) for Market Resources.
Brent L. Adamson
55
Vice President Ethics, Compliance and Audit (2002); Director, Audit (1982 to 2002); Compliance Officer (1995 to 2002). Mr. Adamson announced his retirement effective March 1, 2007.
Abigail L. Jones
46
Vice President Compliance (2007) and Corporate Secretary (2005); Assistant Secretary (2004 to 2005); Senior Attorney (2002 to 2007) for Questar Regulated Services.
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.
The future price of natural gas, oil and NGL is unpredictable. Historically the price of natural gas, oil and NGL has been volatile and is likely to continue to be volatile in the future. Any significant or extended decline in commodity prices would impact the Company’s future financial condition, revenues, results of operations, cash flows and rate of growth. Because approximately 90% of Questar’s proved reserves at December 31, 2006, were natural gas, the Company is 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:
•
changes in domestic and foreign supply of natural gas, oil and NGL;
•
changes in local, regional, national and global demand for natural gas, oil, and NGL;
•
regional price differences resulting from available pipeline transportation capacity or local demand;
•
the level of imports of, and the price of, foreign natural gas, oil and NGL;
QUESTAR 2006 FORM 10-K 14
•
domestic and global economic conditions;
•
domestic political developments;
•
weather conditions;
•
domestic and foreign government regulations and taxes;
•
political instability or armed conflict in oil and natural gas producing regions;
•
conservation efforts;
•
the price, availability and acceptance of alternative fuels;
•
U.S. storage levels of natural gas, oil, and NGL;
•
differing Btu content of gas produced and quality of oil produced.
Questar uses derivative instruments to manage exposure to uncertain prices. Questar uses financial contracts to 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 otherwise experienced if commodity prices increase. 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 hedging arrangements with creditworthy counterparties (banks and industry participants) with a variety of credit requirements. Some contracts do not require the Company to post cash collateral, while others allow some amount of credit before requiring deposits of collateral for out-of-the-money hedges. The amount of credit available may vary depending on the credit ratings assigned to the Company’s debt securities. A substantial increase in the price of natural gas, oil and/or NGL could result in the requirement to deposit large amounts of collateral with counterparties that could seriously impact the Company’s cash liquidity. Additionally, a downgrade in the Company’s credit ratings to sub-investment grade could result in the acceleration of obligations to hedge counterparties.
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 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 remedial costs. Actual results most likely will vary from the estimates. Any significant variance could reduce the estimated future net revenues from proved reserves and the present value of those reserves.
Investors should not assume that the “standardized measure of discounted future net cash flows” from Questar E&P’s proved reserves referred to in this Annual Report is the current market value of the estimated natural gas and oil reserves. In accordance with SEC requirements, the estimated discounted future net cash flows from Questar E&P’s proved reserves is based on prices and costs in effect on the date of the estimate, holding the prices constant throughout the life of the properties. 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 then current prices and costs may be significantly less than the current estimate.
Questar faces many operating risks to develop and produce its reserves. 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;
QUESTAR 2006 FORM 10-K 15
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.
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 can not assure that insurance will be adequate to cover these losses or liabilities. Losses and liabilities arising from uninsured or underinsured events could have an adverse effect on the Company’s financial condition and operations.
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 oil and natural gas prices, causing periodic shortages. There have also been shortages of drilling rigs and other equipment, as demand for rigs and equipment has increased along with the number of wells being drilled. These factors also cause significant increases in costs for equipment, services and personnel. Higher oil and natural gas prices generally stimulate increased demand and result in increased costs for drilling rigs, crews and associated supplies, equipment and services. These shortages or cost increases could impact profit margin, cash flow and operating results or restrict the ability to drill wells and conduct operations.
A significant portion of Market Resources production, revenue and cash flow are derived from assets that are concentrated in a geographical area. While geographic concentration of assets provides scope and scale that can reduce operating costs and provide other operating synergies, asset concentration does increase exposure to certain risks. Market Resources has extensive operations on the Pinedale Anticline and in the Greater Green River Basin of southwestern Wyoming. Any circumstance or event that negatively impacts the operations of Questar E&P, Wexpro or Gas Management in that area could materially reduce earnings and cash flow.
Gas and oil operations involve numerous risks that might result in accidents and other operating risks and costs. There are inherent operating risks and hazards in the Company’s exploration and production, gas gathering, processing, transportation and distribution operations, such as fires, earthquakes, leaks, explosions and mechanical problems 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. In accordance with customary industry practice, the Company maintains insurance against some, but not all, of these risks and 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.
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 that 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 governing activities on federal and state lands in the Rocky Mountain region, notably the National Environmental Policy Act, the Endangered Species Act, and the National Historic Preservation Act. 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 exploring for, finding and producing natural gas and oil on the Company’s Rockies leasehold. Certain environmental groups oppose drilling on some of Market Resources’ federal and state leases.
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
QUESTAR 2006 FORM 10-K 16
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. Finally, 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, oil and transportation operations on such lands.
Both Questar Pipeline and Questar Gas incur significant costs to comply with federal pipeline-safety regulations. Questar may also be affected by possible future regulations requiring the tracking, reporting and reduction of greenhouse-gas emissions pertaining to its operations.
FERC regulates interstate transportation of natural gas. 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. The FERC also has various affiliate rules that may cause the Company to incur additional costs of compliance.
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 may adversely affect Questar Gas profitability.
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. All 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. Management believes it is important to maintain investment grade credit ratings to conduct the Company’s businesses, but may not be able to keep investment grade ratings.
General economic and other conditions impact Questar’s results. Questar’s results may also be negatively affected by: changes in general 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.
Questar E&P and Cost-of-Service
Reserves – Questar E&P
The following table sets forth Questar E&P’s estimated proved reserves, the estimated future net revenues from the reserves and the standardized measure of discounted net cash flows as of December 31, 2006. The estimates were collectively prepared by Ryder Scott Company, H. J. Gruy and Associates, Inc. and Netherland, Sewell & Associates, Inc., independent reservoir-engineering consultants. Questar E&P does not have any long-term supply contracts with foreign governments or reserves of equity investees or of subsidiaries with a significant minority interest. At December 31, 2006, Questar E&P was the operator of approximately 82% of its estimated proved reserves. All reported reserves are located in the United States.
QUESTAR 2006 FORM 10-K 17
Estimated proved reserves |
|
Natural gas (Bcf) | 1,461.2 |
Oil and NGL (MMbbl) | 28.4 |
Total proved reserves (Bcfe) | 1,631.4 |
Proved developed reserves (Bcfe) | 990.7 |
Estimated future net revenues before future |
|
income taxes (in millions) (1) | $4,825.2 |
Standardized measure of discounted net cash |
|
flows (in millions) (2) | $1,567.8 |
(1)
Estimated future net revenue represents estimated future gross revenue to be generated from the production of proved reserves, using average year-end 2006 prices of $4.47 per Mcf for natural gas and $51.49 per bbl for oil and NGL combined, net of estimated production and development costs (but excluding the effects of general and administrative expenses; debt service; depreciation, depletion and amortization; and income tax expense).
(2)
The standardized measure of discounted future net cash flows prepared by the Company represents the present value of estimated future net revenues after income taxes, discounted at 10%.
Estimates of proved reserves and future net revenues are made at year-end, using sales prices estimated to be in effect as of the date of such reserve estimates and are held constant throughout the remaining life of the properties (except to the extent a contract specifically provides for escalation). Year-end prices do not include the effect of hedging. Estimated quantities of proved reserves and future net revenues are affected by natural gas and oil prices, which have fluctuated widely in recent years. There are numerous uncertainties inherent in estimating natural gas and oil reserves and their estimated values, including many factors beyond the control of the Company.
Questar E&P’s reserve statistics for the years ended December 31, 2004 through 2006, are summarized below:
Year | Year End Reserves (Bcfe) | Proved Gas and Oil Reserves Annual Production (Bcfe) | Reserve Life (Years) |
2004 | 1,434.0 | 103.5 | 13.9 |
2005 | 1,480.4 | 114.2 | 13.0 |
2006 | 1,631.4 | 129.6 | 12.6 |
In 2006, gas and oil reserves increased 10%, after production and sales of producing properties, to 1,631.4 Bcfe versus a 3% increase in 2005 to 1,480.4 Bcfe. Questar E&P’s production replacement ratio was 217% in 2006 and 141% in 2005. Net reserve additions, revisions, purchases and sales in place totaled 280.7 Bcfe in 2006 and 160.6 Bcfe in 2005. Questar E&P’s five-year average finding cost of proved reserves per Mcfe was $1.53 in 2006, $1.08 in 2005 and $0.83 in 2004.
Finding costs measure the costs of finding, developing and acquiring new proved reserves. The production replacement ratio measures company success at replacing production during a specific period. If the production replacement ratio is greater than 100%, the Company added or replaced more reserves than it produced for the same period.
Questar E&P proved reserves by major operating areas at December 31, 2006 and 2005 follow:
| 2006 | 2005 | ||
| (Bcfe) | (% of total) | (Bcfe) | (% of total) |
Pinedale Anticline | 931.9 | 57% | 780.0 | 53% |
Uinta Basin | 248.3 | 15% | 254.9 | 17% |
Rockies Legacy | 142.3 | 9% | 144.4 | 10% |
Rocky Mountains Total | 1,322.5 | 81% | 1,179.3 | 80% |
Midcontinent | 308.9 | 19% | 301.1 | 20% |
Questar E&P Total | 1,631.4 | 100% | 1,480.4 | 100% |
QUESTAR 2006 FORM 10-K 18
Reserves – Cost-of-Service
The following table sets forth estimated cost-of-service proved natural gas reserves, which Wexpro develops and produces for Questar Gas under the terms of the Wexpro Agreement; and Wexpro proved oil reserves. The estimates of cost-of-service proved reserves were made by Wexpro reservoir engineers as of December 31, 2006. All reported reserves are located in the United States.
Estimated cost-of-service proved reserves |
|
Natural gas (Bcf) | 620.6 |
Oil (MMbbl) | 4.4 |
Total proved reserves (Bcfe) | 647.0 |
Proved developed reserves (Bcfe) | 458.2 |
The gas reserves operated by Wexpro are delivered to Questar Gas at cost of service. Net income from oil properties remaining after recovery of expenses and Wexpro contractual return on investment under the settlement agreement is divided between Wexpro and Questar Gas. Therefore, SEC guidelines with respect to standard economic assumptions are not applicable. The SEC anticipated such potential difficulty and provides that companies may give appropriate recognition to differences arising because of the effect of the ratemaking process. 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.
Reference should be made 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 estimated reserves as of December 31, 2006, with the Energy Information Administration in 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 lifting cost per Mcfe for the years ended December 31, 2006, 2005 and 2004. Lifting costs include labor, repairs, maintenance, materials, supplies and workovers, administrative costs of production offices, insurance and property and severance taxes.
| Year Ended December 31, | ||
| 2006 | 2005 | 2004 |
Questar E&P Volumes produced and sold Natural gas (Bcf) Oil and NGL (MMbbl) | 113.9 2.6 | 100.0 2.4 | 89.8 2.3 |
Total production (Bcfe) Average realized price (including hedges) Natural gas (per Mcf) Oil and NGL (per bbl) | 129.6 $ 6.00 49.12 | 114.2 $ 5.18 41.54 | 103.5 $ 4.18 30.97 |
Lifting costs (per Mcfe) Lease operating expense Production taxes | $ 0.57 0.45 | $ 0.54 0.60 | $ 0.50 0.46 |
Total lifting costs | $ 1.02 | $ 1.14 | $ 0.96 |
Cost-of-Service Volumes produced Natural gas (Bcf) Oil and NGL (MMbbl) | 38.8 0.4 | 40.0 0.4 | 38.8 0.4 |
QUESTAR 2006 FORM 10-K 19
Productive Wells
The following table summarizes Market Resources productive wells (including cost-of-service wells) as of December 31, 2006. All of these wells are located in the United States.
| Gas | Oil | Total |
Gross | 4,633 | 966 | 5,599 |
Net | 2,065.6 | 456.2 | 2,521.8 |
Although many Market Resources 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 2006, there were 88 gross wells with multiple completions.
Market Resources also holds numerous overriding-royalty interests in gas and oil wells, a portion of which is 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 Market Resources gross and net-well count.
Leasehold Acres
The following table summarizes developed and undeveloped-leasehold acreage in which Market Resources owns a working interest as of December 31, 2006. “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 Market Resources interest is limited to royalty, overriding-royalty and other similar interests. All leasehold acres are located in the U.S.
Leasehold Acreage – December 31, 2006
Developed (1)
Undeveloped (2)
Total
Gross
Net
Gross
Net
Gross
Net
(in acres)
Arizona |
|
| 480 | 450 | 480 | 450 |
Arkansas | 32,049 | 10,310 | 3 | 1 | 32,052 | 10,311 |
California | 25 | 2 | 1,293 | 192 | 1,318 | 194 |
Colorado | 143,967 | 99,540 | 169,367 | 81,470 | 313,334 | 181,010 |
Idaho |
|
| 44,175 | 10,643 | 44,175 | 10,643 |
Illinois | 172 | 39 | 14,207 | 3,949 | 14,379 | 3,988 |
Indiana |
|
| 1,890 | 702 | 1,890 | 702 |
Kansas | 30,302 | 13,396 | 16,880 | 3,963 | 47,182 | 17,359 |
Kentucky |
|
| 17,323 | 6,669 | 17,323 | 6,669 |
Louisiana | 13,242 | 12,065 | 1,553 | 999 | 14,795 | 13,064 |
Michigan | 89 | 8 | 6,240 | 1,262 | 6,329 | 1,270 |
Minnesota |
|
| 313 | 104 | 313 | 104 |
Mississippi | 2,904 | 1,798 | 965 | 398 | 3,869 | 2,196 |
Montana | 19,829 | 8,374 | 299,847 | 51,507 | 319,676 | 59,881 |
Nevada | 320 | 280 | 680 | 543 | 1,000 | 823 |
New Mexico | 97,531 | 68,858 | 25,333 | 5,315 | 122,864 | 74,173 |
North Dakota | 4,635 | 546 | 146,364 | 21,757 | 150,999 | 22,303 |
Ohio |
|
| 202 | 43 | 202 | 43 |
Oklahoma | 1,519,727 | 271,962 | 98,956 | 54,345 | 1,618,683 | 326,307 |
Oregon |
|
| 43,869 | 7,671 | 43,869 | 7,671 |
South Dakota |
|
| 204,398 | 107,829 | 204,398 | 107,829 |
Texas | 147,467 | 61,167 | 70,761 | 53,977 | 218,228 | 115,144 |
QUESTAR 2006 FORM 10-K 20
Utah | 128,173 | 104,340 | 288,313 | 148,611 | 416,486 | 252,951 |
Washington |
|
| 26,631 | 10,149 | 26,631 | 10,149 |
West Virginia | 969 | 115 |
|
| 969 | 115 |
Wyoming | 260,030 | 161,295 | 345,692 | 227,857 | 605,722 | 389,152 |
Grand Total | 2,401,431 | 814,095 | 1,825,735 | 800,406 | 4,227,166 | 1,614,501 |
(1)
Developed acreage is acreage spaced or assignable 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.
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. In that event, the lease will 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:
Leaseholds Expiring | Acres Expiring | |
| Gross | Net |
12 months ending December 31, | (in Acres) | |
2007 | 70,574 | 53,248 |
2008 | 80,408 | 49,310 |
2009 | 67,956 | 43,227 |
2010 | 36,599 | 17,008 |
2011 and later | 175,963 | 159,381 |
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.
| Year Ended December 31, | |||||
| Productive | Dry | ||||
| 2006 | 2005 | 2004 | 2006 | 2005 | 2004 |
Net Wells Completed |
|
|
|
|
|
|
Exploratory | 0.9 | 6.1 | 4.7 | 5.2 | 1.5 |
|
Development | 185.6 | 165.2 | 156.0 | 4.6 | 7.4 | 6.6 |
|
|
|
|
|
|
|
Gross Wells Completed |
|
|
|
|
|
|
Exploratory | 2 | 9 | 9 | 11 | 4 |
|
Development | 408 | 370 | 322 | 18 | 15 | 13 |
Gas Management
Gas Management owns 1,474 miles of gathering lines in Utah, Wyoming, and Colorado. In conjunction with these gathering facilities, Gas Management owns compression facilities, field-dehydration and measuring systems. Gas Management is a 50% partner in Rendezvous, which owns an additional 229 miles of gathering lines and associated field equipment and is a 38% partner in Field Services which owns 65 miles of gathering lines and associated field equipment.
Gas Management owns processing plants that have an aggregate capacity of 440 MMcf of unprocessed natural gas per day.
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.
QUESTAR 2006 FORM 10-K 21
Questar Pipeline
Questar Pipeline has a maximum capacity of 3,442 Mdth per day and firm-capacity commitments of 2,152 Mdth per day. Questar Pipeline’s transmission system includes 2,503 miles of transmission lines that interconnect with other pipelines. Its core system includes two segments, often 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. The transmission mileage includes lines at storage fields and tap lines used to serve Questar Gas, the 488 miles of the Southern Trails system in service that is owned by a subsidiary, and the 88 miles of Overthrust Pipeline that is owned by a subsidiary. The maximum-daily-capacity figures included above for Southern Trails is 85 Mdth and Overthrust is 1,119 Mdth. Questar Pipeline’s system ranges in size from lines that are less than four inches in diameter to the Overthrust line that is 36 inches in diameter. Southern Trails also owns 210 miles of pipeline comprising the California segment of the Southern Trails system, although this segment has not been placed in service. Questar Pipeline has major compression sites, including a complex near Rock Springs, Wyoming, that compress gas volumes from the transmission system for delivery to other pipelines, including systems that move gas volumes east.
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, and several smaller storage aquifers in northeastern Utah and western Wyoming. Through a subsidiary, Questar Pipeline owns processing plants near Price, Utah, and related gathering lines.
Questar Gas
Questar Gas distributes gas to customers in the major populated area of Utah, commonly referred to as the Wasatch Front, including 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 25,527 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 Questar’s financial position. An accrual is recorded for a loss contingency when its occurrence is probable and damages can be reasonably estimated based on the anticipated most likely outcome. 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.
Pinedale Unit Net Profits Interest Litigation
In March 2006, Doyle Hartman and other alleged stakeholders (collectively the “Hartman Group”) filed a declaratory judgment action against Questar E&P, Wexpro and others in Sublette County District Court, Wyoming (Case No. 2006-6843) claiming a 5% net profits interest (NPI) in Pinedale leasehold interests. The Hartman Group seeks a declaratory judgment that the NPI burdens leases committed to the original Pinedale Unit regardless of whether the leases and lands have been eliminated from the Pinedale Unit by contraction and termination of that Unit. The defendants have denied the allegations and filed counterclaims for declaratory judgment and quiet title. In January 2007, the court dismissed a declaratory judgment action previously filed by Questar E&P and Wexpro in order to have all claims and counterclaims consolidated in a single case (Case No. 2006-6843). The court also granted the Hartman Group leave to amend its complaint which amended complaint alleges claims for declaratory judgment, accounting, damages for breach of contract, breach of royalty payment obligations, slander of title, breach of the duty of good faith and fair dealing, rescission, constructive trust and conversion. The Hartman Group has also filed motions for partial summary judgment which are pending with the court. The defendants will be filing a response to the amended complaint and motions for summary judgment.
Grynberg Cases
Questar affiliates are involved in various pending lawsuits filed by Jack Grynberg, an independent producer. In United States ex rel. Grynberg v. Questar Corp., Civil No. 99-MD-1604, consolidated as In re Natural Gas Royalties Qui Tam Litigation, Consolidated Case MDL No. 1293 (D. Wyo.), Grynberg filed qui tam claims against Questar under the federal False Claims Act that were substantially similar to other cases filed against other industry pipelines and their affiliates. The cases were consolidated
QUESTAR 2006 FORM 10-K 22
for discovery and pre-trial motions in Wyoming’s federal district court. The cases involve allegations of industry-wide mismeasurement of natural gas quantities on which royalty payments are due the federal government.
The defendants filed a motion contending that the court has no jurisdiction over the case because Grynberg cannot satisfy the statutory requirements for jurisdiction. The defendants argued that Grynberg’s allegations were publicly disclosed prior to the filing of his complaint and that Grynberg is not the “original source” of the information on which the allegations are based. By order dated October 20, 2006, the district court granted defendants motion and dismissed all of Grynberg’s claims against all the defendants for lack of jurisdiction. The judge found that Grynberg was not the “original source” and therefore could not bring the action. Grynberg has appealed the case to the U.S. Tenth Circuit Court of Appeals.
In Grynberg and L & R Exploration Venture v. Questar Pipeline Co., Civil No. 97CV0471 (D. Wyo.), Grynberg brought breach of contract claims, statutory claims and fraud claims against Questar entities related to a certain gas purchase contract for the purchase of gas produced from wells located in Wyoming. In December, 1998, the federal district court granted Questar’s motion for partial summary judgment on a contract termination issue and in June 2001, the court granted partial summary judgment dismissing the antitrust claims from the case. By order dated September 12, 2006, the judge also dismissed the fraud claims and ratable-take claims. The breach of contract claims are the only issues remaining to be decided. Grynberg has appealed the case to the U.S. Tenth Circuit Court of Appeals.
Kansas Cases
Energy Trading is a named defendant in cases pending in a Kansas state district court, Price v. Gas Pipelines, No. 99 C 30 (Dist. Ct. Kan.) and Price v. El Paso Entities, No. 03 C 23 (Dist. Ct. Kan.). These cases are similar to the cases filed by Grynberg, but the allegations of a conspiracy by the pipeline industry to set standards that result in the systematic undermeasurement of natural gas volumes and resulting underpayment of royalties are made on behalf of private lessors rather than on behalf of the federal government. The purported class involves all royalty owners of production from private land in Kansas, Wyoming and Colorado. Energy Trading opposes certification of the class and contends that it is not engaged in any gas measurement activities in Kansas. A hearing on plaintiffs’ motion to certify the class was held on April 1, 2005. The court has not issued a ruling in the case.
Environmental Claims
Questar Pipeline received a Notice of Violation from the Colorado Department of Public Health and Environment, Air Pollution Control Division (APCD) dated December 20, 2006, concerning its operation of the Powder Wash dew point plant and compressor station in Moffat County, Colorado. Specifically, APCD alleged that Questar Pipeline violated applicable air permitting regulations by failing to obtain the necessary permits and complying with best available control technology. Questar Pipeline has been working with the APCD to obtain these permits and resolve these allegations. This potential violation may result in civil penalties of an unknown and undetermined amount in excess of $100,000.
In 2004, the Environmental Protection Agency (EPA) issued two separate compliance orders alleging that Gas Management did not comply with regulatory requirements adopted to enforce the federal Clean Air Act. Both orders involved facilities in the Uinta Basin of eastern Utah that were purchased by Questar E&P in mid-2001. Gas Management believes it is operating the facilities and filing necessary reports in compliance with regulatory requirements; however, the EPA contends such facilities are located within Indian Country and are subject to additional Clean Air Act requirements not applicable to non-Indian Country lands administered by the state of Utah. As a consequence, EPA has broadened its allegations to include additional potential ongoing violations of the Clean Air Act for the referenced facilities. Other Gas Management facilities in the Uinta Basin have been added to the civil penalty discussions with the EPA, with similar allegations of Clean Air Act violations. These potential violations will likely result in civil penalties of an unknown and undetermined amount in excess of $100,000.
Regulatory Proceedings
See Note 11 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 last quarter of 2006.
QUESTAR 2006 FORM 10-K 23
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 an industry group of six diversified natural gas companies selected by Questar, and of the S&P 500 Composite Stock Price Index.
![[str10k4q2006005.gif]](str10k4q2006005.gif)
The chart assumes $100 is invested at the close of trading on December 31, 2001, in the Company’s common stock, the indices of an industry peer group and the S&P 500 Composite Stock Price Index. It also assumes all dividends are reinvested. For 2006, the Company had a total return of 11.0% compared to 15.8% for the S&P 500 Index and 20.5% for the industry group. For the five-year period, the Company had a compound annual total of 29.7% compared to 6.2% for the S&P 500 Index and 22.2% for the industry group. The industry group is comprised of Energen Corporation, Equitable Resources, Inc., Kinder Morgan Inc., National Fuel Gas Company, Oneok Inc. and Southwestern Energy Company.
Information concerning the market for the common equity of the Company and the dividends paid on such stock is located in Note 16 to the consolidated financial statements included in Item 8 of Part II of this Annual Report. As of January 31, 2007, Questar had 9,432 shareholders of record.
Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities
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, 2006.
QUESTAR 2006 FORM 10-K 24
Total Number of Shares Purchased* | Average Price per Share | Total Number of Shares Purchased as Part of Publicly Announced Plans | Maximum Number of Shares that May Yet Be Purchased Under the Plans | |
October 1, 2006 to October 31, 2006 | 259 | $81.41 |
|
|
November 1, 2006 to November 30, 2006 | 10,937 | 86.25 |
|
|
December 1, 2006 to December 31, 2006 | 3,485 | 86.98 |
|
|
Total | 14,681 | $86.34 |
|
|
*The numbers include shares purchased in conjunction with tax-payment elections under the Company’s Long-term Stock Incentive Plan. They exclude any fractional shares purchased from terminating participants in Questar’s Dividend Reinvestment and Stock Purchase Plan and any shares of restricted stock forfeited when failing to satisfy vesting conditions.
ITEM 6. SELECTED FINANCIAL DATA.
| Year Ended December 31, | |||||
| 2006 | 2005 | 2004 | 2003 | 2002 | |
| (in millions, except per-share amounts) | |||||
Revenues | $2,835.6 | $2,724.9 | $1,901.4 | $1,463.2 | $1,200.7 | |
Operating expenses |
|
|
|
|
| |
Cost of natural gas and other products sold | 1,223.6 | 1,371.3 | 821.8 | 527.4 | 391.4 | |
Operating and maintenance | 286.8 | 262.8 | 213.6 | 205.0 | 179.8 | |
General and administrative | 135.0 | 123.1 | 114.2 | 94.3 | 108.8 | |
Production and other taxes | 108.7 | 120.2 | 90.9 | 70.7 | 44.2 | |
Depreciation, depletion and amortization | 308.4 | 250.3 | 216.2 | 192.4 | 185.0 | |
Other expenses | 42.0 | 35.4 | 29.1 | 33.6 | 17.3 | |
Total operating expenses | 2,104.5 | 2,163.1 | 1,485.8 | 1,123.4 | 926.5 | |
Net gain (loss) on asset sales | 25.3 | 4.7 | 0.3 | (0.3) | 23.9 | |
Operating income | 756.4 | 566.5 | 415.9 | 339.5 | 298.1 | |
Interest and other income | 9.3 | 9.0 | 6.3 | 8.0 | 33.2 | |
Income from unconsolidated affiliates | 7.5 | 7.5 | 5.1 | 5.0 | 11.8 | |
Interest expense | (73.6) | (69.4) | (68.4) | (70.7) | (81.1) | |
Income taxes | (255.5) | (187.9) | (129.6) | (102.6) | (91.1) | |
Income before accounting changes | 444.1 | 325.7 | 229.3 | 179.2 | 170.9 | |
Cumulative effects of accounting changes |
|
|
| (5.6) | (15.3) | |
Net income | $ 444.1 | $ 325.7 | $ 229.3 | $ 173.6 | $ 155.6 | |
Basic earnings per common share |
|
|
|
|
| |
Income before accounting changes | $5.20 | $3.84 | $2.74 | $2.17 | $2.09 | |
Cumulative effect of accounting changes |
|
|
| (0.07) | (0.19) | |
Net income | $5.20 | $3.84 | $2.74 | $2.10 | $1.90 | |
Diluted earnings per common share |
|
|
|
|
| |
QUESTAR 2006 FORM 10-K 25
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION.
SUMMARY
Questar reported net income of $444.1 million, or $5.07 diluted per share, in 2006 compared to $325.7 million, or $3.74 per diluted share, in 2005 and to $229.3 million, or $2.67 for 2004. Following is a comparison of net income by lines of business:
| Year Ended December 31, | Change | Change | ||||||
| 2006 | 2005 | 2004 | 2006 v. 2005 | 2005 v. 2004 | ||||
| (in millions, except per-share amounts) | ||||||||
NET INCOME |
|
|
|
|
| ||||
Questar E&P | $253.9 | $172.8 | $108.2 | $81.1 | $64.6 | ||||
Wexpro | 50.0 | 43.7 | 35.3 | 6.3 | 8.4 | ||||
Gas Management | 42.6 | 35.7 | 21.0 | 6.9 | 14.7 | ||||
Energy Trading and other | 9.6 | 6.0 | 0.9 | 3.6 | 5.1 | ||||
Market Resources total | 356.1 | 258.2 | 165.4 | 97.9 | 92.8 | ||||
Questar Pipeline | 42.4 | 24.4 | 27.6 | 18.0 | (3.2) | ||||
Questar Gas | 37.0 | 36.0 | 31.5 | 1.0 | 4.5 | ||||
Corporate and other operations | 8.6 | 7.1 | 4.8 | 1.5 | 2.3 | ||||
| $444.1 | $325.7 | $229.3 | $118.4 | $96.4 | ||||
|
|
|
|
|
| ||||
Earnings per share – diluted | $5.07 | $3.74 | $2.67 | $1.33 | $1.07 | ||||
Market Resources net income increased 38% in 2006 compared to 2005 and 56% in 2005 over 2004. Primary factors for the higher income were increases in natural gas production, higher realized natural gas, oil and NGL prices, higher gas processing and gas gathering margins, and increases in the Wexpro investment base.
QUESTAR 2006 FORM 10-K 26
Questar Pipeline reported net income of $42.4 million in 2006 compared to $24.4 million in 2005 and $27.6 million in 2004. The increase in net income was the result of increased firm-transportation contracts supporting recent system expansions and higher NGL revenues. In 2005, Questar Pipeline recorded a $10.4 million after-tax asset impairment for the California segment of the company’s Southern Trails Pipeline. The 2004 results were lower by $3.0 million after tax as a result of an order to credit to transportation customers certain revenues from the sale of liquids recovered from gas processing.
Questar Gas net income increased 3% in 2006 versus 2005 and 14% in 2005 versus 2004. The 2006 results reflect continued customer growth and lower bad debt and depreciation expense. Higher 2005 revenues resulted from a record addition of 30,330 customers.
RESULTS OF OPERATION
Market Resources
Market Resources, which conducts natural gas and oil exploration, development and production, gas gathering and processing, wholesale gas and oil marketing and gas storage, reported $356.1 million of net income for 2006 compared with $258.2 million in 2005, a 38% increase, and $165.4 million in 2004. Operating income increased $160.8 million, or 38%, in the 2006 to 2005 comparison due primarily to increased natural gas production and higher realized prices at Questar E&P, an increased investment base at Wexpro, increased gas-processing plant margins at Gas Management and a net gain from asset sales. Following is a summary of Market Resources financial and operating results:
| Year Ended December 31, | ||
| 2006 | 2005 | 2004 |
| (in millions) | ||
OPERATING INCOME |
|
|
|
Revenues |
|
|
|
Natural gas sales | $ 684.0 | $ 517.6 | $ 375.2 |
Oil and NGL sales | 149.6 | 118.6 | 86.4 |
Cost-of-service gas operations | 148.6 | 133.2 | 116.7 |
Energy marketing | 668.7 | 902.8 | 506.6 |
Gas gathering, processing and other | 184.9 | 156.0 | 100.4 |
Total revenues | 1,835.8 | 1,828.2 | 1,185.3 |
Operating expenses |
|
|
|
Energy purchases | 652.6 | 888.3 | 499.7 |
Operating and maintenance | 180.4 | 158.6 | 113.8 |
General and administrative | 69.2 | 54.6 | 49.6 |
Production and other taxes | 89.4 | 102.2 | 73.2 |
Depreciation, depletion and amortization | 235.0 | 173.8 | 142.7 |
Exploration | 34.4 | 11.5 | 9.2 |
Abandonment and impairment | 7.6 | 7.9 | 15.8 |
Wexpro Agreement – oil-income sharing | 5.5 | 6.1 | 4.7 |
Total operating expenses | 1,274.1 | 1,403.0 | 908.7 |
Net gain from asset sales | 25.2 | 0.9 | 0.3 |
Operating income | $ 586.9 | $ 426.1 | $ 276.9 |
|
| ||
OPERATING STATISTICS |
|
|
|
Questar E&P production volumes |
|
|
|
Natural gas (Bcf) | 113.9 | 100.0 | 89.8 |
Oil and NGL (MMbbl) | 2.6 | 2.4 | 2.3 |
QUESTAR 2006 FORM 10-K 27
Total production (Bcfe) | 129.6 | 114.2 | 103.5 |
Average daily production (MMcfe) | 355.2 | 312.9 | 282.8 |
Questar E&P average realized price, net to the well (including hedges) |
|
|
|
Natural gas (per Mcf) | $6.00 | $5.18 | $4.18 |
Oil and NGL (per bbl) | $49.12 | $41.54 | $30.97 |
Wexpro investment base at December 31, net |
|
|
|
of depreciation and deferred income taxes (millions) | $260.6 | $206.3 | $182.8 |
Natural gas processing volumes |
|
|
|
NGL sales volumes (MMgal) | 88.1 | 88.4 | 55.5 |
Processing fee based (in millions of MMBtu) | 120.4 | 75.5 | 29.8 |
Natural gas processing revenues |
|
|
|
NGL sales price (per gal) | $0.88 | $0.77 | $0.65 |
Processing fee based (per MMBtu) | $0.14 | $0.15 | $0.13 |
Natural gas gathering volumes (in millions of MMBtu) |
|
|
|
For unaffiliated customers | 153.9 | 145.0 | 128.7 |
For Questar Gas | 42.2 | 43.1 | 39.0 |
For other affiliated customers | 78.0 | 68.9 | 57.0 |
Total gathering | 274.1 | 257.0 | 224.7 |
Gathering revenue (per MMBtu) | $0.29 | $0.25 | $0.22 |
Natural gas and oil marketing volumes (MMdthe) |
|
|
|
For unaffiliated customers | 118.3 | 118.5 | 91.2 |
For affiliated customers | 102.0 | 91.8 | 82.5 |
Total marketing | 220.3 | 210.3 | 173.7 |
|
|
|
|
Questar E&P
Questar E&P, a Market Resources subsidiary that conducts natural gas and oil exploration, development and production, reported net income of $253.9 million in 2006, up 47% from $172.8 million in 2005 and $108.2 million in 2003. The increase was driven by a combination of higher realized natural gas, oil and NGL prices and increased gas, oil and NGL production volumes.
Questar E&P reported production volumes increased to 129.6 Bcfe in 2006, a 13% increase compared to 2005. Natural gas is Questar E&P’s primary focus. On an energy equivalent basis, natural gas comprised approximately 88% of Questar E&P 2006 production. A comparison of natural gas-equivalent production by region is shown in the following table:
| Year Ended December 31, | Change | Change | ||
| 2006 | 2005 | 2004 | 2006 vs. 2005 | 2005 vs. 2004 |
| (in Bcfe) | ||||
Pinedale Anticline | 39.5 | 33.2 | 23.5 | 6.3 | 9.7 |
Uinta Basin | 25.1 | 25.6 | 24.8 | (0.5) | 0.8 |
Rockies Legacy | 18.3 | 16.7 | 18.0 | 1.6 | (1.3) |
Rocky Mountain total | 82.9 | 75.5 | 66.3 | 7.4 | 9.2 |
Midcontinent | 46.7 | 38.7 | 37.2 | 8.0 | 1.5 |
Total Questar E&P | 129.6 | 114.2 | 103.5 | 15.4 | 10.7 |
QUESTAR 2006 FORM 10-K 28
Questar E&P production from the Pinedale Anticline in western Wyoming grew 19% to 39.5 Bcfe in 2006 and comprised 30% of Questar E&P total production in the 2006 period compared to 33.2 Bcfe and 29% of 2005 production. Questar E&P completed 51 new wells during 2006 and 40 new wells at Pinedale during 2005.
In the Uinta Basin of eastern Utah, Questar E&P production decreased 2% to 25.1 Bcfe in 2006 compared to a year ago. Production increased 3% to 25.6 Bcfe in 2005 compared to 24.8 Bcfe in 2004 despite production constraints related to third quarter construction and maintenance on an interstate pipeline.
Production from Questar E&P Rocky Mountain “Legacy” properties increased 10% to 18.3 Bcfe in 2006 compared to a year ago. Excluding a one-time adjustment of 0.7 Bcfe, Legacy 2006 production was 17.6 Bcfe, an increase of 5% over the 2005 period driven by the company’s emerging gas play in the Vermillion Basin. Legacy assets include all Questar E&P Rocky Mountain region properties except the Pinedale Anticline and the Uinta Basin. Production during the 2005 period was negatively impacted by normal field decline, seasonal restrictions that limit access to leases and wells during the winter months, payout of a high-volume well that reduced the company’s working interest and mechanical problems that delayed completion of a new well in the Vermillion Basin.
In the Midcontinent, production grew 21% to 46.7 Bcfe in 2006, driven by ongoing infill-development drilling in the Elm Grove field in northwestern Louisiana.
Questar E&P also benefited from higher realized prices for natural gas, oil and NGL. In 2006, the weighted average realized natural gas price for Questar E&P (including the impact of hedging) was $6.00 per Mcf compared to $5.18 per Mcf for the same period in 2005, a 16% increase. Realized oil and NGL prices in 2006 averaged $49.12 per bbl, compared with $41.54 per bbl during the prior year period, an 18% increase. A regional comparison of average realized prices including hedges is shown in the following table:
| Year Ended December 31, | Change | Change | ||
| 2006 | 2005 | 2004 | 2006 vs. 2005 | 2005 vs. 2004 |
Natural gas (per Mcf) |
|
|
|
|
|
Rocky Mountains | $5.73 | $5.01 | $3.95 | $0.72 | $1.06 |
Midcontinent | 6.47 | 5.49 | 4.57 | 0.98 | 0.92 |
Volume-weighted average | 6.00 | 5.18 | 4.18 | 0.82 | 1.00 |
Oil and NGL (per bbl) |
|
|
|
|
|
Rocky Mountains | $46.62 | $42.08 | $30.10 | $4.54 | $11.98 |
Midcontinent | 54.93 | 40.25 | 32.98 | 14.68 | 7.27 |
Volume-weighted average | 49.12 | 41.54 | 30.97 | 7.58 | 10.57 |
Approximately 70% in 2006 and 83% in 2005 of Questar E&P gas production was hedged or pre-sold. Hedging increased 2006 gas revenues by $53.7 million and reduced 2005 gas revenues by $173.9 million. Approximately 78% in 2006 and 70% in 2005 of Questar E&P oil production was hedged or pre-sold. Oil hedges reduced revenues $19.6 million in 2006 and $24.8 million in 2005.
Questar may hedge up to 100 percent of forecasted production from proved reserves to lock in acceptable returns on invested capital and to protect returns, cash flow and net income from a decline in commodity prices. During 2006, Questar E&P continued to take advantage of high natural gas and oil prices to hedge additional production through 2008. In 2006, the company began using basis-only swaps to protect cash flows and net income from widening natural gas-price basis differentials that may result from capacity constraints on regional gas pipelines. Derivative positions as of December 31, 2006, are summarized in Part II of Item 7A of this Annual Report.
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 6% to $2.99 per Mcfe in 2006 versus $2.83 per Mcfe in 2005 and $2.51 in 2004. Questar E&P production costs are summarized in the following table:
QUESTAR 2006 FORM 10-K 29
| Year Ended December 31, | Change | Change | ||
| 2006 | 2005 | 2004 | 2006 vs. 2005 | 2005 vs. 2004 |
| (per Mcfe) | ||||
Depreciation, depletion and amortization | $1.43 | $1.18 | $1.04 | $0.25 | $0.14 |
Lease operating expense | 0.57 | 0.54 | 0.50 | 0.03 | 0.04 |
General and administrative expense | 0.33 | 0.30 | 0.30 | 0.03 |
|
Allocated interest expense | 0.21 | 0.21 | 0.21 |
|
|
Production taxes | 0.45 | 0.60 | 0.46 | (0.15) | 0.14 |
Total production costs | $2.99 | $2.83 | $2.51 | $0.16 | $0.32 |
Depreciation, depletion and amortization expense rose due to higher costs for drilling, completion and related services, increased cost of steel casing, other tubulars and wellhead equipment, and the ongoing depletion of older, lower-cost reserves. Per unit lease operating expense increased due to increased costs of materials and consumables and higher well workover costs. General and administrative expenses increased due to higher labor costs and an increase in the allowance for doubtful accounts.
Production taxes per unit decreased with lower sales prices on natural gas, increased incentive tax credits related to well drilling and production enhancement projects, and adjustments to prior estimates. Most production taxes are based on a fixed percentage of commodity sales prices.
Questar E&P exploration expense increased $23.3 million in 2006 compared to 2005. The increase was primarily due to expenses for unsuccessful exploratory wells. Questar E&P plugged and abandoned the deep exploratory portion of the Stewart Point 15-29 well on the Pinedale Anticline after failing to establish commercial production in the Hilliard and Rock Springs formations. The company recorded a $10.0 million charge related to abandonment of the deep portion of the well, which was subsequently re-completed as a commercial well in the Lance Pool. Exploration expense increased $1.9 million in 2005 compared to 2004. The expense increase was due to increased exploratory seismic acquisition expenditures in the Midcontinent and Uinta Basin. Abandonment and impairment expense decreased $0.1 million in 2006 compared to 2005 and declined $5.3 million in 2005 compared to 2004. The 2004 amount included $2.3 million of expense due to a well with collapsed casing and $3.3 million for an abandoned coal bed methane project.
In 2006, Questar E&P sold certain proved reserves and undeveloped leasehold interests in western Colorado and recognized a pre-tax gain of $22.7 million. For income tax purposes, the company structured the sale of the Colorado properties and the 2006 acquisition of certain Louisiana properties to qualify as a reverse like-kind exchange of property under Section 1031 of the Internal Revenue Code of 1986, as amended.
Pinedale Anticline Drilling Activity
As of December 31, 2006, Market Resources (including both Questar E&P and Wexpro) operated and had working interest in 195 producing wells on the Pinedale Anticline compared to 144 and 104 at year-end 2005 and 2004, respectively. Of the 195 producing wells, Questar E&P has working interests in 173 wells, overriding royalty interests only in an additional 21 Wexpro-operated wells, and no interest in one well operated by Wexpro. Wexpro has working interests in 66 of the 195 producing wells.
In 2005, the Wyoming Oil and Gas Conservation Commission approved 10-acre-density drilling for Lance Pool wells on about 12,700 acres of Market Resources 18,208 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. With 10-acre-density drilling, the company currently believes that up to 932 wells will be required to fully develop the Lance Pool on its acreage.
Uinta Basin
During 2006, the company drilled or participated in 65 Wasatch and Upper Mesaverde gas wells, four horizontal and one vertical Green River Formation oil wells, and four deeper Blackhawk, Mancos and Dakota formations gas wells on its core acreage block.
As of December 31, 2006, Questar E&P had drilled five wells in the Flat Rock and Wolf Flat areas in the southern portion of the Uinta Basin, including two wells on its 12,577 gross acre Ute Tribe Exploration and Development Agreement lands and three wells on its State of Utah leasehold, and was drilling another well at year end.
QUESTAR 2006 FORM 10-K 30
Rockies Legacy
In the Vermillion Basin on the southwestern Wyoming-northwestern Colorado state line, Market Resources continues to evaluate the potential of several formations under the company’s 146,000 net leasehold acres. As of December 31, 2006, the company had recompleted two older wells, drilled and completed 13 new wells, and two were waiting on completion. The targets are the Baxter Shale, which extends across a 3,000-3,500 foot gross interval from about 9,500 feet deep to about 13,000 feet deep on most of the company’s leasehold in the basin, and the deeper Frontier and Dakota tight-sand formations at depths down to 14,000 feet.
Midcontinent
Questar E&P continued a two-rig infill-development project in the Elm Grove field in northwest Louisiana as it operated or participated in eight new wells that were completed in the fourth quarter of 2006. The company participated in the completion of 36 wells in Elm Grove field in 2006. In 2006, Questar E&P also acquired interests in 48 producing wells in nine spacing units in the Elm Grove field. The acquisition provides Questar E&P initial or additional working interest in approximately 75 undrilled locations.
Wexpro
Wexpro, a Market Resources subsidiary that develops and produces cost-of-service reserves for Questar Gas, reported net income of $50.0 million, in 2006 compared to $43.7 in 2005, a 14% increase and $35.3 million in 2004. Pursuant to the Wexpro Agreement, Wexpro recovers its costs and receives an unlevered after-tax return of approximately 19% to 20% on its investment in commercial wells and related facilities – adjusted for working capital and reduced for deferred income taxes and depreciation (investment base). Wexpro investment base at December 31, 2006, was $260.6 million, an increase of $54.3 million or 26%.
Gas Management
Gas Management, Market Resources gas-gathering and processing-services business, grew net income 19% to $42.6 million in 2006 from $35.7 million in 2005 and $21.0 million in 2004. Gas processing plant margin grew 72% from $24.3 million in 2005 to $41.7 million in 2006. Gathering volumes increased 17.1 million MMBtu to 274.1 million MMBtu in 2006 due primarily to expanding Pinedale production and new projects serving third parties in the Uinta Basin. Total gathering margins increased 9% despite increased start-up costs associated with the Pinedale liquids-gathering and transportation facilities.
To reduce processing margin risk, Gas Management has restructured a number of its processing agreements with producers from “keep-whole” contracts to “fee-based” contracts. A keep-whole contract protects producers from frac spread risk while fee-based contracts eliminate commodity-price risk for the plant owner. In 2006, revenues from keep-whole contracts benefited from a 13% increase in realized NGL sales prices versus the prior-year period. Revenues from fee-based contracts were impacted by a 59% increase in processing volumes offset by a $0.01 decrease in the average rate charged per MMBtu processed compared with 2005. To further reduce margin volatility associated with keep-whole contracts, Gas Management began managing NGL price risk in 2004 by using forward-sales contracts. Forward sales contracts increased NGL revenues by $0.7 million in 2006 and decreased NGL revenues $1.0 million in 2005.
Income before income tax from Gas Management’s 50% interest in Rendezvous was $7.0 million for 2006 compared to $7.2 million in 2005 and $5.0 million in 2004. Rendezvous provides gas gathering services for the Pinedale and Jonah producing areas. Gas Management continues to invest in additional gas gathering and processing and liquids-handling facilities to serve growing equity and third-party production in its core areas of the Pinedale and Jonah fields in western Wyoming and the Uinta Basin in eastern Utah.
Gas Management completed its condensate and produced-water gathering and transportation facilities on Market Resources Pinedale Anticline leasehold in November 2005 in time to satisfy BLM conditions for expanded winter access.
Gas Management entered into an agreement with a third party producer to gather, compress and process gas in the Uinta Basin. Under terms of the fee-based agreement, the company constructed gas compression facilities and expanded its existing Red Wash gas plant to process an additional 70 MMcf per day of raw gas. The processed gas and liquids are redelivered to the producer. The new facilities were in service at the end of the third quarter 2005. Gas Management has formed a joint venture with the Ute Indian Tribe and another industry participant to build a gas gathering system for the Flat Rock area in southern Uinta Basin.
Energy Trading and Other
Energy Trading sells Market Resources equity gas and oil, provides risk-management services and operates a natural-gas storage facility, reported net income for 2006 of $9.6 million compared to $6.0 million in 2005 and $0.9 million in 2005. Service fee revenues from affiliates were $0.8 million higher in 2006 relative to 2005. Gross margins for gas and oil marketing (gross
QUESTAR 2006 FORM 10-K 31
revenues less costs for gas and oil purchases, transportation and gas storage), increased to $16.0 million for 2006 versus $14.5 million a year ago, a 10% increase. The increase in gross margin was due primarily to a 5% increase in volumes and increased storage activity over the same period last year.
Questar Pipeline
Questar Pipeline, which provides interstate natural gas-transportation and storage services, reported net income for 2006 of $42.4 million for 2006 compared with $24.4 million in 2005, a 74% increase, and $27.6 million in 2004. Operating income increased $31.6 million, or 53%, in the 2006 to 2005 comparison due primarily to increased transportation revenues and a 2005 impairment. The 2005 results were reduced by $10.4 million after tax for an impairment of the California segment of Southern Trails. Following is a summary of Questar Pipeline financial and operating results:
|
|
| Year Ended December 31, | |||||||
|
|
| 2006 | 2005 | 2004 | |||||
|
|
| (in millions) | |||||||
OPERATING INCOME |
|
|
| |||||||
Revenues |
|
|
| |||||||
Transportation | $ 119.9 | $108.2 | $105.5 | |||||||
Storage | 37.6 | 37.4 | 37.7 | |||||||
Gas processing | 6.3 | 5.6 | 7.3 | |||||||
NGL revenues | 11.0 | 9.2 | 1.2 | |||||||
Other | 6.6 | 5.6 | 4.8 | |||||||
Total revenues | 181.4 | 166.0 | 156.5 | |||||||
Operating expenses |
|
|
| |||||||
Operating and maintenance | 33.1 | 30.7 | 26.3 | |||||||
General and administrative | 19.3 | 25.2 | 29.4 | |||||||
Depreciation and amortization | 31.5 | 29.4 | 28.2 | |||||||
Impairment of the California segment of Southern Trails Pipeline |
| 16.0 |
| |||||||
Other taxes | 6.6 | 5.8 | 6.6 | |||||||
Operating expenses | 90.5 | 107.1 | 90.5 | |||||||
Net gain from assets sale |
| 0.4 |
| |||||||
Operating income | $ 90.9 | $ 59.3 | $ 66.0 | |||||||
|
|
|
| |||||||
OPERATING STATISTICS |
|
|
| |||||||
Natural gas-transportation volumes (MMdth) | ||||||||||
For unaffiliated customers | 320.4 | 259.3 | 220.5 | |||||||
For Questar Gas | 116.7 | 116.3 | 116.5 | |||||||
For other affiliated customers | 26.3 | 25.7 | 18.8 | |||||||
Total transportation | 463.4 | 401.3 | 355.8 | |||||||
Transportation revenue (per dth) | $0.26 | $0.27 | $0.30 | |||||||
Firm daily transportation demand at December 31, (MMdth) | 2.2 | 1.9 | 1.6 | |||||||
Revenues
Following is a summary of major changes in Questar Pipeline revenues for 2006 compared with 2005 and 2005 compared with 2004:
QUESTAR 2006 FORM 10-K 32
| Change in Revenues | |
| 2005 to 2006 | 2004 to 2005 |
| (in millions) | |
Transportation |
|
|
New transportation contracts | $14.4 | $ 4.7 |
Expiration of transportation contracts | (2.7) | (2.0) |
Storage | 0.2 | (0.3) |
Gas processing | 0.7 | (1.7) |
NGL revenues |
|
|
Change in NGL prices and volumes | 4.2 | 5.6 |
Adjustment to credit of NGL revenues in 2005 | (2.4) | 2.4 |
Other | 1.0 | 0.8 |
Increase | $15.4 | $ 9.5 |
As of December 31, 2006, Questar Pipeline had firm-transportation contracts of 2,152 Mdth per day compared with 1,920 Mdth per day as of December 31, 2005, and 1,643 Mdth per day as of December 31, 2004. Questar Pipeline has expanded its transportation system in response to growing regional natural gas production and transportation demand. In the second quarter of 2005, Questar Pipeline began operating a lateral to an electric generation power plant with a capacity of 190 Mdth per day. In the fourth quarter of 2005, Questar Pipeline completed an expansion of its southern system, which added capacity of 102 Mdth per day. On January 1, 2006, Questar Pipeline subsidiary, Questar Overthrust Pipeline, placed in service an interconnection with Kern River Gas Transmission Company that added capacity of 220 Mdth per day. Each of these expansion projects was fully subscribed with long-term contracts.
Questar Gas is Questar Pipeline’s largest transportation customer with contracts for 951 Mdth per day, including 50 Mdth per day for winter-peaking service. The majority of Questar Gas transportation contracts extend through mid 2017.
Questar Pipeline primary storage facility is Clay Basin 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 one to 12 years and 100% of the firm-storage capacity at the aquifer facilities for terms extending for 11 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 revenues increased 20% in 2006 over 2005 due to 21% higher prices and 33% higher volumes offset by a 2005 $2.4 million adjustment due to a resolution of a liquid sharing arrangement in a fuel-gas reimbursement proceeding. The 2005 NGL revenues were $5.6 million higher than 2004 due to higher prices and volumes and $2.4 million because of the adjustment.
During the third quarter of 2005, Questar Pipeline received approval of a settlement with customers that resolved outstanding issues in the 2004 and 2005 fuel gas reimbursement percentage (FGRP) filings. Included in this settlement was a resolution of the amount of liquid revenues at the Kastler plant to be retained by Questar Pipeline. Questar Pipeline recorded the impact of the settlement in third quarter 2005 increasing liquid revenues by $2.4 million and net income by $1.5 million. See Note 11 to the consolidated financial statements included in Item 8 of Part II of this Annual Report for a discussion of Questar Pipeline’s FGRP proceedings.
Expenses
Operating, maintenance, general and administrative expenses decreased by 6% to $52.4 million in 2006 compared to $55.9 million in 2005 and $55.7 million in 2004. Beginning in July 2005 customers at the company’s carbon dioxide processing plant
QUESTAR 2006 FORM 10-K 33
began supplying their own fuel gas, which accounted for $1.0 million of the decrease. Operating, maintenance, general and administrative expenses per dth transported were $0.11 in 2006 compared with $0.14 in 2005 and $0.16 in 2004. Operating, maintenance, general and administrative expenses include processing and storage costs.
Depreciation expense increased 7% in 2006 compared to 2005 and 4% in 2005 compared to 2004 due to investment in pipeline expansions.
Clay Basin Storage
Questar Pipeline conducts periodic pressure tests on its Clay Basin storage facility. Beginning with a test in April 2002, the company noted a discrepancy between the book volumes of cushion gas at Clay Basin and the volumes implied by pressure data. Questar Pipeline retained a reservoir consultant to model the reservoir and determine the size and cause of the discrepancy. The company conducted six additional pressure tests from April 2004 to October 2006 to validate the model.
The reservoir model indicates from 0 to 3.8 Bcf of gas may be missing from Clay Basin, with the most likely amount of 3.2 Bcf. The cumulative gas loss is due to imprecision inherent in measurement of large injection and withdrawal volumes as well as reservoir heterogeneity that impacts storage reservoir performance. The cushion gas loss represents 0.25% of the volume of gas cycled in and out of the reservoir over the past 30 years. There is no indication that the reservoir is leaking. The Clay Basin reservoir is functioning as expected to meet customer requirements.
Questar Pipeline is discussing with its firm-storage customers the recording of the loss of gas as a reduction of native gas remaining in the reservoir and various tariff changes. This accounting treatment would not impact Questar Pipeline net income. Alternatively, the FERC may require Questar Pipeline to adjust recoverable cushion gas, and reduce earnings by about $3 million after tax.
Southern Trails Pipeline
See Note 4 to the consolidated financial statements included in Item 8 of Part II of this Annual Report for discussion of the impairment of the California segment of Southern Trails and potential impairment of the eastern segment.
Questar Gas
Questar Gas, which provides natural gas distribution services in Utah, Wyoming and Idaho, reported net income of $37.0 million for 2006 compared with $36.0 million in 2005, a 3% increase, and $31.5 million in 2004. Operating income increased $2.4 million, or 3%, in the 2006 to 2005 comparison due primarily to higher margins from customer growth and lower bad debt and depreciation expenses. Following is a summary of Questar Gas’s financial and operating results:
| Year Ended December 31, | ||||
| 2006 | 2005 | 2004 | ||
| (in millions) | ||||
OPERATING INCOME |
|
|
| ||
Revenues |
|
|
| ||
Residential and commercial sales | $ 988.4 | $867.8 | $680.7 | ||
Industrial sales | 23.5 | 40.1 | 49.1 | ||
Transportation for industrial customers | 6.7 | 5.9 | 6.4 | ||
Service | 7.1 | 6.6 | 5.3 | ||
Other | 38.9 | 42.1 | 22.7 | ||
Total revenues | 1,064.6 | 962.5 | 764.2 | ||
Cost of natural gas sold | 821.8 | 720.2 | 536.1 | ||
Margin | 242.8 | 242.3 | 228.1 | ||
Operating expenses |
|
|
| ||
Operating and maintenance | 73.2 | 73.7 | 69.2 | ||
General and administrative | 41.9 | 39.3 | 35.6 | ||
Rate-refund obligation |
|
| 4.1 | ||
QUESTAR 2006 FORM 10-K 34
Depreciation and amortization | 40.9 | 45.8 | 42.0 | ||
Other taxes | 11.6 | 11.0 | 9.8 | ||
Total operating expenses | 167.6 | 169.8 | 160.7 | ||
Net loss from asset sales | (0.3) |
| (0.2) | ||
Operating income | $ 74.9 | $ 72.5 | $ 67.2 | ||
|
|
|
| ||
OPERATING STATISTICS |
|
|
| ||
Natural gas volumes (MMdth) |
|
|
| ||
Residential and commercial sales | 102.2 | 96.3 | 93.0 | ||
Industrial sales | 3.1 | 5.7 | 8.8 | ||
Transportation for industrial customers | 35.5 | 31.2 | 34.3 | ||
Total industrial | 38.6 | 36.9 | 43.1 | ||
Total deliveries | 140.8 | 133.2 | 136.1 | ||
|
|
|
| ||
Natural gas revenue (per dth) |
|
|
| ||
Residential and commercial | $9.67 | $9.01 | $7.32 | ||
Industrial sales | 7.64 | 7.06 | 5.56 | ||
Transportation for industrial customers | 0.19 | 0.19 | 0.19 | ||
System natural gas cost (per dth) | $ 6.54 | $6.46 | $5.20 | ||
Temperatures – colder (warmer) than normal | (2%) | (3%) | 3% | ||
Temperature-adjusted usage per customer (dth) | 113.6 | 113.3 | 114.9 | ||
Customers at December 31, (in thousands) | 850.5 | 824.4 | 794.1 | ||
Margin Analysis
Questar Gas’s margin (revenues less gas costs) increased $0.5 million in 2006 compared to 2005, and $14.2 million in 2005 compared with 2004. Following is a summary of major changes in Questar Gas’s margin for 2006 compared to 2005 and 2005 compared to 2004:
| Change in Margin | |
| 2005 to 2006 | 2004 to 2005 |
| (in millions) | |
New customers | $ 6.9 | $ 6.6 |
Conservation enabling tariff | (1.7) |
|
Change in usage per customer | 0.5 | (1.6) |
Interest on past-due receivables | 0.6 | 1.2 |
Change in rates | (4.9) |
|
Gas-processing revenues collected from customers | 0.7 | 0.9 |
Recovery of gas-cost portion of bad-debt costs | (2.8) | 2.1 |
Other, including shifting between rate classes | 1.2 | 5.0 |
Increase | $ 0.5 | $14.2 |
Temperature-adjusted usage per customer increased less than 1% in 2006 compared to 2005 and decreased 1% in 2005 compared to 2004. The impact on the company’s margin from changes in usage per customer has been mitigated by a conservation enabling tariff that was approved by the PSCU in October 2006, effective back to the beginning of 2006. Questar Gas recorded a reduction in margin of $1.7 million in 2006 to reflect the impact of changes in usage per customer. See Note 11 to the consolidated financial statements included in Item 8 of Part II of this Annual Report for a discussion of the conservation enabling tariff.
QUESTAR 2006 FORM 10-K 35
Effective June 1, 2006, Utah customer rates were reduced by $9.7 million per year, primarily to reflect changes in the company’s depreciation rates. Questar Gas realized $4.9 million in reduced revenues from this rate change during the last seven months of 2006. Depreciation expense was approximately $5.3 million lower for this seven-month period as a result of the depreciation rate change. See Note 11 to the consolidated financial statements included in Item 8 of Part II of this Annual Report for a discussion of the rate changes.
Weather, as measured in degree days, was 2% and 3% warmer than normal in 2006 and 2005, respectively compared with 3% colder than normal in 2004. A weather-normalization adjustment on customer bills generally offsets financial impacts of moderate temperature variations. At December 31, 2006, Questar Gas was serving 850,542 customers, up from 824,447 at December 31, 2005.
Industrial deliveries (including sales and transportation) increased 5% in 2006 compared to 2005. Industrial deliveries declined 14% in 2005 compared with 2004 primarily driven by lower power-generation requirements and customers changing to the residential and commercial rate schedules.
Expenses
Cost of natural gas sold increased 14% in 2006 compared to 2005 due primarily to higher gas purchase expenses per dth and a 3% increase in volumes sold. Cost of natural gas sold increased 34% in 2005 compared with 2004. 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, 2006, Questar Gas had a $34.3 million over-collection balance in the purchased-gas adjustment account representing costs recovered from customers in excess of costs incurred. In November 2005, rates were increased significantly to recover increased gas costs caused by the Gulf Coast hurricanes. Questar Gas reduced rates in Utah and Wyoming effective November 1, 2006, by more than the prior year increases.
Operating, maintenance, general and administrative expenses increased 2% in 2006 compared to 2005 due primarily to higher labor costs offset by lower bad debt costs. These expenses increased 8% in 2005 compared to 2004 due to higher labor costs and bad debt costs. Operating, maintenance, general and administrative expenses per customer were $135 in 2006 compared to $137 in 2005 and $132 in 2004.
Depreciation expense decreased 11% in 2006 compared to 2005 primarily as a result of reduced depreciation rates effective June 1, 2006, in accordance with a PSCU order as discussed above. This offsets the depreciation impact of plant additions from customer growth, which caused depreciation expense to increase 9% in 2005 compared with 2004.
Rate Matters
See Note 11 to the consolidated financial statements included in Item 8 of Part II of this Annual Report for a discussion of the Conservation Enabling Tariff, a rate reduction in Utah and recovery of gas processing costs. 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 $2.0 million per year of these costs beginning June 2006 and to record a regulatory asset for additional incremental operating costs incurred to comply with this Act.
Corporate and Other Operations
Corporate and Other Operations includes sales to affiliates and from gas measurement activities.
|
|
| Year Ended December 31, | ||||
|
|
| 2006 | 2005 | 2004 | ||
|
|
| (in millions) | ||||
OPERATING INCOME |
|
|
| ||||
Revenues | $17.0 | $ 19.1 | $35.6 | ||||
Operating expenses |
|
|
| ||||
Cost of products sold | 4.8 | 5.4 | 5.9 | ||||
Operating and maintenance | 1.2 | 0.8 | 11.0 | ||||
QUESTAR 2006 FORM 10-K 36
General and administrative | 5.6 | 5.2 | 8.5 | ||||
Depreciation and amortization | 1.1 | 1.3 | 3.3 | ||||
Other taxes | 1.0 | 1.2 | 1.3 | ||||
Total operating expenses | 13.7 | 13.9 | 30.0 | ||||
Net gain from asset sales | 0.4 | 3.4 | 0.2 | ||||
Operating income | $ 3.7 | $ 8.6 | $ 5.8 | ||||
Revenues and total operating expenses decreased in 2005 compared with 2004 due to the 2004 reorganization of information-technology-related businesses and the May 2005 sale of data-hosting assets.
Consolidated Operating Results After Operating Income
Interest and Other Income
The details of interest and other income for 2006, 2005 and 2004 are shown in the table below:
| Year Ended December 31, | ||
| 2006 | 2005 | 2004 |
| (in millions) | ||
Interest income and other earnings | $ 6.0 | $3.3 | $1.9 |
Allowance for other funds used during |
|
|
|
construction (capitalized finance costs) | 1.0 | 0.7 | 0.3 |
Return earned on working-gas inventory |
|
|
|
and purchased-gas-adjustment account | 5.9 | 5.0 | 4.1 |
Total | $12.9 | $9.0 | $6.3 |
Net gain on asset sales
During 2006, Questar E&P sold certain proved reserves and undeveloped leasehold interests in western Colorado and recognized a pre-tax gain of $22.7 million. The gain is included in the Consolidated Statement of Income line item “Net gain on asset sales”. For income tax purposes, the Company structured the sale of the Colorado properties and the March 2006 acquisition of certain Louisiana properties to qualify as a reverse like-kind exchange of property under Section 1031 of the Internal Revenue Code of 1986, as amended.
Income from unconsolidated affiliates
Gas Management has a 50% interest in Rendezvous that provides gas-gathering services for the Pinedale and Jonah producing areas of western Wyoming. Gas Management’s share of Rendezvous earnings amounted to $7.0 million in 2006 compared to $7.2 million in 2005 and $5.0 million in 2004. Rendezvous gathering volumes increased 1% in 2006 compared to 2005 and 47% in 2005 compared to 2004.
Interest expense and loss on early extinguishment of debt
Interest expense rose in 2006 compared to 2005 due primarily to increased average debt levels during and higher interest rates on short-term debt outstanding in the early part of 2006. Interest expense rose in 2005 because the Company increased borrowings to meet hedging collateral calls precipitated by increases in natural gas and oil prices. Market Resources recognized a $1.7 million pre-tax loss in 2006 on the early extinguishment of its 7% Notes due 2007.
Net mark-to-market loss on basis swaps
The Company uses basis-only swaps to protect cash flows and net income from widening natural gas-price basis differentials that may result from capacity constraints on regional gas pipelines. The Company recognized mark-to-market losses of $1.9 million on the NYMEX/Rockies basis swaps in 2006.
Income taxes
The effective combined federal and state income tax rate was 36.5% in 2006, 36.6% in 2005 and 36.1% in 2004.
QUESTAR 2006 FORM 10-K 37
LIQUIDITY AND CAPITAL RESOURCES
Operating Activities
Net cash provided from operating activities increased 39% in 2006 compare to 2005 and 19% in 2005 compared to 2004 due primarily to higher net income, changes in operating assets and liabilities and noncash adjustments to income.
| Year Ended December 31, | Change | Change | |||||||
| 2006 | 2005 | 2004 | 2006 vs. 2005 | 2005 vs. 2004 | |||||
| (in millions) | |||||||||
Net income | $444.1 | $325.7 | $229.3 | $118.4 | $ 96.4 | |||||
Noncash adjustments to net income | 438.3 | 378.7 | 359.8 | 59.6 | 18.9 | |||||
Changes in operating assets and liabilities | 83.8 | (9.3) | (3.4) | 93.1 | (5.9) | |||||
Net cash provided from operating activities | $966.2 | $695.1 | $585.7 | $271.1 | $109.4 | |||||
Investing Activities
Capital spending in 2006 amounted $916.1 million. The details of capital expenditures in 2006 and 2005 and a forecast for 2007 are shown in the table below:
| Year Ended December 31, | ||
| 2007 Forecast | 2006 | 2005 |
| (in millions) | ||
Market Resources |
|
|
|
Drilling and other exploration | $ 31.4 | $ 13.6 | $ 51.7 |
Dry exploratory well expenses |
| 26.3 | 3.1 |
Development drilling | 476.8 | 532.6 | 355.1 |
Wexpro development drilling | 62.6 | 76.8 | 53.7 |
Reserve acquisitions | 1.0 | 29.3 | 3.5 |
Production | 14.2 | 22.7 | 24.8 |
Gathering and processing | 108.5 | 80.4 | 96.7 |
Storage | 0.2 | 1.1 | 0.5 |
General | 5.1 | 5.6 | 2.9 |
Capital expenditure accruals |
| (35.7) | (15.8) |
| 699.8 | 752.7 | 576.2 |
Questar Pipeline |
|
|
|
Transmission system | 115.7 | 13.5 | 60.2 |
Overthrust Pipeline | 197.3 | 58.3 |
|
Southern Trails Pipeline | 1.5 | 0.1 | 0.7 |
Storage | 16.9 | 2.5 | 3.4 |
Gathering and processing | 3.0 | 3.4 | 0.1 |
General | 5.5 | 2.0 | 1.1 |
Capital expenditure accruals |
| (3.7) | 1.9 |
| 339.9 | 76.1 | 67.4 |
Questar Gas |
|
|
|
Distribution system and customer additions | 99.0 | 84.5 | 46.9 |
General | 17.4 | 12.7 | 17.0 |
Capital expenditure accruals |
| (10.5) | 4.0 |
QUESTAR 2006 FORM 10-K 38
| 116.4 | 86.7 | 67.9 |
Corporate and Other Operations | 1.1 | 0.6 | 1.2 |
Total capital expenditures | $1,157.2 | $916.1 | $712.7 |
Market Resources
In 2006 and 2005, Market Resources increased drilling activity at Pinedale and in the Midcontinent region. A water and condensate gathering system to serve the Pinedale Anticline was constructed in 2005. During 2006, Market Resources participated in 570 wells (196.3 net), resulting in 186.5 net successful gas and oil wells and 9.8 net dry or abandoned wells. The 2006 net drilling-success rate was 95%. There were 131 gross wells in progress at year end. Market Resources also increased investment in its midstream gathering and processing-services business to expand capacity in both western Wyoming and eastern Utah in response to growing equity and third-party production volumes.
Questar Pipeline
During 2006, a Questar Pipeline subsidiary completed a 27.2 miles extension of the Overthrust Pipeline from the Uinta County, Wyoming to a connection with the Kern River Gas Transmission pipeline at Opal, Wyoming.
Questar Gas
During 2006, Questar Gas added 818 miles of main, feeder and service lines to provide service to 26,095 new customers.
Financing Activities
Net cash provided from operating activities was sufficient to fund net capital expenditures and pay $79.7 million of dividends. On May 11, 2006, Market Resources sold $250 million principal amount of 6.05% Notes due 2016. Net proceeds of $247 million were used for general corporate purposes including the June 14, 2006, early extinguishment of its $200 million of 7% Notes due 2007 and repayment of short-term debt. Market Resources recorded a $1.7 million charge related to the early extinguishment of the 7% Notes. In 2005, Questar Gas borrowed $50 million from a bank under a five-year loan agreement and used the proceeds to repay short-term debt.
Short-term debt amounted to $40.0 million at December 31, 2006, and was comprised of commercial paper with an average interest rate of 5.4%. A year earlier short-term debt amounted to $94.5 million and was comprised of commercial paper with an average interest rate of 4.43%. Questar’s commercial paper borrowings are backed by short-term line-of-credit arrangements. At December 31, 2006, the Company had $400 million of short-term lines of credit available and Market Resources had a $182 million long-term revolving-credit facility with banks.
Questar consolidated capital structure consisted of 33% combined short- and long-term debt and 67% common shareholders’ equity at December 31, 2006, compared to 41% combined short- and long-term debt and 59% common shareholders’ equity a year earlier. Ratings of senior-unsecured debt as of December 31, 2006, were as shown below. Standard & Poor’s and Moody’s ratings were designated as stable.
| Moody’s | Standard & Poor’s |
Market Resources | Baa3 | BBB+ |
Questar Pipeline | A2 | A- |
Questar Gas | A2 | A- |
Questar – short-term debt | P2 | A2 |
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, 2006:
QUESTAR 2006 FORM 10-K 39
| Payments Due by Year | ||||
| Total | 2007 | 2008-2009 | 2010-2011 | After 2011 |
| (in millions) | ||||
Long-term debt | $1,033.5 | $10.0 | $101.4 | $242.0 | $680.1 |
Gas-purchase contracts | 291.5 | 169.8 | 95.5 | 26.2 |
|
Transportation contracts | 103.4 | 12.9 | 25.2 | 24.8 | 40.5 |
Operating leases | 30.1 | 5.6 | 11.4 | 10.3 | 2.8 |
Total | $1,458.5 | $198.3 | $233.5 | $303.3 | $723.4 |
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 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 decisions 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 remedial costs. The subjective decisions and variances in data for various fields make these estimates less precise than other estimates included in the financial statement disclosures. For 2006, revisions of reserve estimates, other than revisions related to Pinedale increased-density, resulted in a 23.8 Bcfe decrease in Questar E&P’s proved reserves and a 21.5 Bcfe increase in cost-of-service proved reserves, representing approximately one percent and three percent of reported proved reserves, respectively, as of December 31, 2006. Revisions associated with Pinedale increased-density drilling added 170.4 Bcfe to Questar E&P’s estimated proved reserves at December 31, 2006, and 104.6 Bcfe of additional cost-of-service proved reserves. See Note 17 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 independent reservoir-engineering consultants 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.
QUESTAR 2006 FORM 10-K 40
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 Derivatives Contracts
The Company uses derivative contracts, typically fixed-price swaps, 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 comprehensive income depending on the structure of the derivatives. The Company has structured virtually all energy-derivative instruments as cash-flow hedges as defined in SFAS 133 as amended. Changes in the fair value of cash-flow hedges are recorded on the balance sheet and in comprehensive income 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 index prices 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. 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 nongas 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 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 will be limited to one percent of total revenues for the first year.
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 SFAS 71, “Accounting for the Effects of Certain Types of Regulation,” 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 pension and postretirement-benefit plans covering a majority of its employees. The calculation of the Company’s expense and liability associated with its benefit plans requires the use of a number 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 makes 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.
QUESTAR 2006 FORM 10-K 41
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 5.75% as of December 31, 2006, and 6.00% as of December 31, 2005. A 0.25% decrease in the discount rate increased the Company’s 2006 qualified pension annual expense by $1.5 million.
In September 2006, the FASB issued SFAS 158 “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans.” The new accounting standard required disclosure of the over or under funded status of defined-benefit plans on the balance sheet effective with annual reports on Form 10-K for the year ending December 31, 2006. The over or under funded defined-benefit pension position was measured by the difference in the fair value of plan assets and the projected benefit obligation. The projected benefit obligation includes an estimate of future salary changes. The over or under funded position of other postretirement benefits was measured by the difference in the fair value of plan assets and the accumulated benefit obligation.
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 to provide for the benefits included in the benefit plan liability. 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 the historical and forecasted rates of return on these types of securities. The expected long-term rate of return determined by the Company was 8.00% as of January 1, 2006 and 8.25% as of January 1, 2005. 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 a $0.7 million increase in 2006 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 exposures arise from commodity-price changes for natural gas, oil and NGL, and volatility in interest rates. Energy Trading has long-term contracts for pipeline capacity and is obligated for transportation services with no guarantee that it will be able to recover the full cost of these transportation commitments.
Commodity-Price Risk Management
Market Resources bears the risk associated with commodity-price changes and uses gas- and oil-price-derivative arrangements in the normal course of business to limit the risk of adverse price movements. However these same arrangements typically limit future gains from favorable price movements. Derivative contracts are used for a significant share of Questar E&P-owned gas and oil production, a portion of Energy Trading gas- and oil-marketing transactions and some of Gas Management’s NGL.
Market Resources has established policies and procedures for managing commodity-price risks through the use of derivatives. Natural gas- and oil-price hedging support Market Resources rate of return and cash flow targets and protects earnings from downward movements in commodity prices. The volume of hedged production and the mix of derivative instruments are regularly evaluated and adjusted by management in response to changing market conditions and reviewed periodically by the Finance and Audit Committee of the Company’s Board of Directors. Market Resources may hedge up to 100% of forecast production from proved reserves when prices meet earnings and cash flow objectives. Market Resources does not enter into derivative arrangements for speculative purposes and does not hedge undeveloped reserves or Questar E&P equity NGL.
Market Resources uses fixed-price swaps to manage natural gas, oil and NGL price risk. A fixed-price swap is a derivative instrument that exchanges or “swaps” the “floating” or daily price of a specified volume of natural gas, oil or NGL, over a specified period, for a fixed price for the specified volume over the same period. In the normal course of business, the Company sells its equity natural gas, oil and NGL production to third parties at first-of-the-month or daily “floating” prices related to indices reported in industry publications. To reduce exposure to highly volatile daily and monthly commodity prices, the Company uses a derivative instrument that exchanges or “swaps” the “floating” or daily price of the commodity for a fixed-price for the specified period (typically for periods of three months or longer). The Company enters into these transactions with banks and industry counterparties with investment-grade credit ratings. Swap agreements do not require the physical transfer of gas between the parties at settlement. Swap transactions are settled monthly, in cash, with one party paying the other for the net difference in prices, multiplied by the relevant volume, for the settlement period.
QUESTAR 2006 FORM 10-K 42
Generally derivative instruments are matched to equity gas and oil production, thus qualifying as cash flow hedges under the accounting provisions of SFAS 133 as amended and interpreted. Changes in the fair value of cash-flow hedges are recorded on the balance sheet and in other comprehensive income or loss until the underlying gas or oil is produced. Gas hedges are typically structured as fixed-price swaps into regional pipelines, locking in basis and hedge effectiveness. The ineffective portion of cash flow hedges is immediately recognized in the determination of net income.
Market Resources also entered into natural gas basis-only swaps in 2006 to manage the risk of a widening of basis differentials in the Rocky Mountains. These contracts are marked-to-market with any change in the valuation recognized in the determination of net income.
Market Resources enters into commodity price derivative arrangements with several banks and energy-trading firms with a variety of credit requirements. Some contracts do not require collateral deposits, while others allow some amount of credit before Market Resources is required to deposit collateral for out-of-the-money contracts. The amount of credit available may vary depending on the credit rating assigned to Market Resources debt. In addition, to the counterparty arrangements, Market Resources has a $182 million long-term revolving-credit facility with banks with no borrowings outstanding at December 31, 2006.
A summary of Market Resources derivative positions for equity production as of December 31, 2006, is shown below. Currently fixed-price and basis-only swaps are with creditworthy counterparties. Fixed-price swaps allow Market Resources to realize a known price for a specific volume of production delivered into a regional sales point. The fixed-price swap price is then reduced by gathering costs and adjusted for product quality to determine the net-to-the-well price.
|
| Rocky |
|
|
| Rocky |
|
|
Time Periods | Mountains | Midcontinent | Total |
| Mountains | Midcontinent | Total | |
|
|
|
|
|
| Estimated | ||
|
| Gas (in Bcf) Fixed-Price Swaps |
| Average price per Mcf, net to the well | ||||
2007 |
|
|
|
|
|
|
| |
First half | 23.1 | 15.4 | 38.5 |
| $6.88 | $7.81 | $7.25 | |
Second half | 23.5 | 15.6 | 39.1 |
| 6.88 | 7.81 | 7.25 | |
12 months | 46.6 | 31.0 | 77.6 |
| 6.88 | 7.81 | 7.25 | |
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|
2008 |
|
|
|
|
|
|
| |
First half | 16.9 | 12.2 | 29.1 |
| $7.19 | $7.98 | $7.52 | |
Second half | 17.9 | 12.3 | 30.2 |
| 7.16 | 7.98 | 7.49 | |
12 months | 34.8 | 24.5 | 59.3 |
| 7.18 | 7.98 | 7.51 | |
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| |
2009 |
|
|
|
|
|
|
| |
First half | 13.4 | 8.7 | 22.1 |
| $7.07 | $7.55 | $7.26 | |
Second half | 13.7 | 8.8 | 22.5 |
| 7.07 | 7.55 | 7.26 | |
12 months | 27.1 | 17.5 | 44.6 |
| 7.07 | 7.55 | 7.26 | |
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| Gas (in Bcf) Basis-Only Swaps |
| Estimated Average basis per Mcf vs. NYMEX | ||||
2007 |
|
|
|
|
|
|
| |
First half | 8.4 |
| 8.4 |
| $1.92 |
| $1.92 | |
Second half | 8.6 |
| 8.6 |
| 1.92 |
| 1.92 | |
12 months | 17.0 |
| 17.0 |
| 1.92 |
| 1.92 | |
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|
QUESTAR 2006 FORM 10-K 43
2008 |
|
|
|
|
|
|
| |
First half | 13.6 |
| 13.6 |
| $1.60 |
| $1.60 | |
Second half | 13.7 |
| 13.7 |
| 1.60 |
| 1.60 | |
12 months | 27.3 |
| 27.3 |
| 1.60 |
| 1.60 | |
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2009 |
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First half | 1.7 |
| 1.7 |
| $0.95 |
| $0.95 | |
Second half | 1.7 |
| 1.7 |
| 0.95 |
| 0.95 | |
12 months | 3.4 |
| 3.4 |
| 0.95 |
| 0.95 | |
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| ||
|
| Oil (in Mbbl) Fixed-Price Swaps |
| Average price per bbl, net to the well | ||||
2007 |
|
|
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|
First half | 525 | 199 | 724 |
| $52.01 | $57.91 | $53.63 | |
Second half | 534 | 202 | 736 |
| 52.01 | 57.91 | 53.63 | |
12 months | 1,059 | 401 | 1,460 |
| 52.01 | 57.91 | 53.63 | |
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2008 |
|
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First half | 109 | 73 | 182 |
| $59.45 | $65.45 | $61.85 | |
Second half | 111 | 73 | 184 |
| 59.45 | 65.45 | 61.85 | |
12 months | 220 | 146 | 366 |
| 59.45 | 65.45 | 61.85 | |
As of December 31, 2006, Market Resources held commodity-price hedging contracts covering about 204.2 million MMBtu of natural gas, 1.8 MMbbl of oil and 22.7 million gallons of NGL. A year earlier Market Resources hedging contracts covered 184.4 million MMBtu of natural gas, 2.9 MMbbl of oil and 10.1 million gallons of NGL. Market Resources has also entered into basis-only swaps on an additional 47.7 million Mcf of natural gas. There were no basis-only swaps a year earlier.
Questar Gas had a fixed-price swap at December 31, 2006, locking-in the purchase price of 3.0 Bcf of natural gas during 2007. The fair value of this fixed-price swap was a $7.6 million liability at December 31, 2006, and is included in the tables below.
The following table summarizes changes in the fair value of derivative contracts from December 31, 2005 to December 31, 2006:
| Fixed-Price Swaps | Basis-Only Swaps | Total |
| (in millions) | ||
Net fair value of gas- and oil-derivative contracts outstanding at December 31, 2005 | ($319.1) |
| ($319.1) |
Contracts realized or otherwise settled | 167.1 |
| 167.1 |
236.6 |
| 236.6 | |
Contracts added | 113.4 | ($1.9) | 111.5 |
Net fair value of gas- and oil-derivative contracts outstanding at December 31, 2006 | $198.0 | ($1.9) | $196.1 |
A table of the net fair value of gas- and oil-derivative contracts as of December 31, 2006, is shown below. About 75% of the fair value of all contracts will settle in the next 12 months and the fair value of cash-flow hedges will be reclassified from other comprehensive income:
QUESTAR 2006 FORM 10-K 44
| Fixed-Price Swaps | Basis-Only Swaps | Total |
| (in millions) | ||
Contracts maturing by December 31, 2007 | $146.3 | $ 1.0 | $147.3 |
Contracts maturing between December 31, 2007 and December 31, 2008 | 40.9 | (3.0) | 37.9 |
Contracts maturing between December 31, 2008 and December 31, 2009 | 10.8 | 0.1 | 10.9 |
Net fair value of gas- and oil-derivative contracts outstanding at December 31, 2006 | $198.0 | ($1.9) | $196.1 |
The following table shows 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:
| At December 31, | |
| 2006 | 2005 |
| (in millions) | |
Net fair value – asset (liability) | $196.1 | ($319.1) |
Value if market prices of gas and oil and basis differentials decline by 10% | 327.0 | (166.9) |
Value if market prices of gas and oil and basis differentials increase by 10% | 65.2 | (471.4) |
Credit Risk
Market Resources requests credit support and, in some cases, prepayment from companies with unacceptable credit risks. Market Resources five largest customers are Sempra Energy Trading Corp., BP Energy Company, ONEOK Energy Services Company LP, Enterprise Products Operating and Nevada Power Company. Sales to these companies accounted for 27% of Market Resources revenues before elimination of intercompany transactions in 2006, and their accounts were current at December 31, 2006.
Questar Pipeline requests credit support, such as letters of credit and cash deposits, from those companies that pose unfavorable credit risks. All companies posing such concerns were current on their accounts at December 31, 2006. Questar Pipeline’s largest customers include Questar Gas, PacifiCorp, Kerr McGee, EOG Resources and Chevron/Texaco.
Questar Gas requires deposits from customers that pose unfavorable credit risks. No single customer accounted for a significant portion of revenue in 2006.
Interest Rate Risk
The fair value of fixed-rate debt is subject to change as interest rates fluctuate. The Company had $1,033.5 million of fixed-rate long-term debt with a fair value of $1,065.2 million at December 31, 2006. A year earlier the Company had $983.5 million of fixed-rate long-term debt with a fair value of $ 1,041.5 million. If interest rates would have declined 10%, fair value would increase to $1,094.4 million in 2006 and $1,062.6 million in 2005. The fair value calculations do not represent the cost to retire the debt securities.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
Page No.
Financial Statements:
Report of Independent Registered Public Accounting Firm
47
Consolidated Statements of Income, three years ended December 31, 2006
48
Consolidated Balance Sheets at December 31, 2006 and 2005
49
Consolidated Statements of Common Shareholders’ Equity, three years ended
50
Consolidated Statements of Cash Flows, three years ended December 31, 2006
53
Notes Accompanying the Consolidated Financial Statements
55
Financial Statement Schedules:
Valuation and Qualifying Accounts, for the three years ended December 31, 2006
85
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 2006 FORM 10-K 46
Report of Independent Registered Public Accounting Firm
The Board of Directors and Shareholders
Questar Corporation
We have audited the accompanying consolidated balance sheets of Questar Corporation and subsidiaries as of December 31, 2006 and 2005, 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, 2006. 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 and subsidiaries at December 31, 2006 and 2005, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2006, 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 3 to the financial statements, Questar Corporation and subsidiaries adopted Statement of Financial Accounting Standards No. 123R, Share Based Payment, under the modified prospective phase-in method, effective January 1, 2006, and as discussed in Note 13 to the financial statements, Questar Corporation and subsidiaries also adopted the requirements of Statement of Financial Accounting Standards No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, effective December 31, 2006
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Questar Corporation's internal control over financial reporting as of December 31, 2006, 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, 2007 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Salt Lake City, UT
February 26, 2007
QUESTAR 2006 FORM 10-K 47
QUESTAR CORPORATION | ||||
CONSOLIDATED STATEMENTS OF INCOME | ||||
| Year Ended December 31, | |||
| 2006 | 2005 | 2004 | |
| (in millions, except per share amounts) | |||
REVENUES |
|
|
| |
Market Resources | $1,659.4 | $1,668.7 | $1,053.9 | |
Questar Pipeline | 101.7 | 82.6 | 67.9 | |
Questar Gas | 1,059.1 | 956.4 | 759.5 | |
Corporate and other operations | 15.4 | 17.2 | 20.1 | |
Total Revenues | 2,835.6 | 2,724.9 | 1,901.4 | |
|
|
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| |
OPERATING EXPENSES |
|
|
| |
Cost of natural gas and other products sold | 1,223.6 | 1,371.3 | 821.8 | |
Operating and maintenance | 286.8 | 262.8 | 213.6 | |
General and administrative | 135.0 | 123.1 | 114.2 | |
Production and other taxes | 108.7 | 120.2 | 90.9 | |
Depreciation, depletion and amortization | 308.4 | 250.3 | 216.2 | |
Questar Gas rate-refund obligation |
|
| 4.1 | |
Impairment of California segment of Southern Trails Pipeline |
| 16.0 |
| |
Exploration | 34.4 | 11.5 | 9.2 | |
Abandonment and impairment | 7.6 | 7.9 | 15.8 | |
Total Operating Expenses | 2,104.5 | 2,163.1 | 1,485.8 | |
Net gain on asset sales | 25.3 | 4.7 | 0.3 | |
OPERATING INCOME | 756.4 | 566.5 | 415.9 | |
Interest and other income | 12.9 | 9.0 | 6.3 | |
Income from unconsolidated affiliates | 7.5 | 7.5 | 5.1 | |
Net mark-to-market loss on basis-only swaps | (1.9) |
|
| |
Loss on early extinguishment of debt | (1.7) |
|
| |
Interest expense | (73.6) | (69.4) | (68.4) | |
INCOME BEFORE INCOME TAXES | 699.6 | 513.6 | 358.9 | |
Income taxes | 255.5 | 187.9 | 129.6 | |
NET INCOME | $ 444.1 | $ 325.7 | $ 229.3 | |
|
|
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| |
EARNINGS PER COMMON SHARE |
|
|
| |
Basic | $5.20 | $ 3.84 | $2.74 | |
Diluted | $5.07 | $ 3.74 | $2.67 | |
Weighted average common shares outstanding |
|
|
| |
Used in basic calculation | 85.5 | 84.8 | 83.8 | |
Used in diluted calculation | 87.6 | 87.1 | 85.7 | |
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|
|
| |
See notes accompanying the consolidated financial statements | ||||
QUESTAR 2006 FORM 10-K 48
QUESTAR 2006 FORM 10-K 49
QUESTAR CORPORATION | |||
|
| ||
| December 31, | ||
| 2006 | 2005 | |
| (in millions) | ||
LIABILITIES AND SHAREHOLDERS’ EQUITY |
| ||
Current Liabilities |
|
| |
Short-term debt | $ 40.0 | $ 94.5 | |
Accounts payable and accrued expenses |
|
| |
Accounts and other payables | 436.2 | 444.4 | |
Production and other taxes | 68.9 | 81.5 | |
Questar Gas customer credit balances | 31.4 | 30.8 | |
Interest | 14.9 | 14.5 | |
Total accounts payable and accrued expenses | 551.4 | 571.2 | |
Fair value of derivative contracts | 8.2 | 222.1 | |
Purchase-gas adjustment | 34.3 |
| |
Deferred income taxes - current | 35.0 |
| |
Current portion of long-term debt | 10.0 |
| |
Total Current Liabilities | 678.9 | 887.8 | |
|
|
| |
Long-term debt, less current portion | 1,022.4 | 983.2 | |
Deferred income taxes | 763.9 | 624.2 | |
Asset retirement obligations | 132.4 | 78.2 | |
Pension liability | 106.0 | 44.6 | |
Postretirement benefits liability | 37.8 | 16.4 | |
Fair value of derivative contracts | 0.2 | 99.0 | |
Other long-term liabilities | 117.6 | 91.1 | |
Commitments and contingencies – Note 12 |
|
| |
|
|
| |
COMMON SHAREHOLDERS’ EQUITY |
|
| |
Common stock – without par value; 350.0 shares authorized; |
|
| |
85.9 outstanding at December 31, 2006, and 85.3 outstanding |
|
| |
at December 31, 2005 | 409.6 | 383.3 | |
Retained earnings | 1,750.2 | 1,385.8 | |
Accumulated other comprehensive income (loss) | 45.7 | (219.3) | |
Total Common Shareholders’ Equity | 2,205.5 | 1,549.8 | |
|
|
| |
Total Liabilities and Common Shareholders’ Equity | $5,064.7 | $4,374.3 | |
|
|
| |
See notes accompanying the consolidated financial statements |
| ||
QUESTAR 2006 FORM 10-K 50
QUESTAR CORPORATION | ||||||||
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS’ EQUITY | ||||||||
|
|
|
| Accumulated |
| |||
|
|
|
| Other |
| |||
| Common Stock | Retained | Comprehensive | Comprehensive | ||||
| Shares | Amount | Earnings | Income (Loss) | Income (Loss) | |||
| (in millions) | |||||||
Balances at January 1, 2004 | 83.2 | $324.8 | $ 977.8 | ($ 41.3) |
| |||
Common stock issued | 1.3 | 29.1 |
|
|
| |||
Common stock repurchased | (0.1) | (4.8) |
|
|
| |||
2004 net income |
|
| 229.3 |
| $229.3 | |||
Dividends paid ($0.85 per share) |
|
| (71.4) |
|
| |||
Share-based compensation |
| 2.4 |
|
|
| |||
Tax benefit from share-based compensation |
| 6.5 |
|
|
| |||
Other comprehensive income |
|
|
|
|
| |||
Change in unrealized loss on derivatives |
|
|
| (15.2) | (15.2) | |||
Minimum pension liability |
|
|
| (5.5) | (5.5) | |||
Income taxes |
|
|
| 7.8 | 7.8 | |||
Total comprehensive income |
|
|
|
| $216.4 | |||
Balances at December 31, 2004 | 84.4 | 358.0 | 1,135.7 | (54.2) |
| |||
Common stock issued | 1.1 | 16.9 |
|
|
| |||
Common stock repurchased | (0.2) | (9.7) |
|
|
| |||
2005 net income |
|
| 325.7 |
| $325.7 | |||
Dividends paid ($0.89 per share) |
|
| (75.6) |
|
| |||
Share-based compensation |
| 4.2 |
|
|
| |||
Tax benefit from share-based compensation |
| 13.9 |
|
|
| |||
Other comprehensive income |
|
|
|
|
| |||
Change in unrealized loss on derivatives |
|
|
| (251.5) | (251.5) | |||
Minimum pension liability |
|
|
| (14.8) | (14.8) | |||
Income taxes |
|
|
| 101.2 | 101.2 | |||
Total comprehensive income |
|
|
|
| $160.6 | |||
Balances at December 31, 2005 | 85.3 | 383.3 | 1,385.8 | (219.3) |
| |||
Common stock issued | 0.7 | 10.8 |
|
|
| |||
Common stock repurchased | (0.1) | (6.2) |
|
|
| |||
2006 net income |
|
| 444.1 |
| $444.1 | |||
Dividends paid ($0.93 per share) |
|
| (79.7) |
|
| |||
Share-based compensation |
| 9.7 |
|
|
| |||
Tax benefit from share-based compensation |
| 12.0 |
|
|
| |||
Other comprehensive income |
|
|
|
|
| |||
Change in unrealized gain on derivatives |
|
|
| 524.9 | 524.9 | |||
Minimum pension liability |
|
|
| 34.3 | 34.3 | |||
Unrecognized actuarial loss |
|
|
| (112.8) | (112.8) | |||
QUESTAR 2006 FORM 10-K 51
Unrecognized prior-service costs |
|
|
| (20.5) | (20.5) |
Income taxes |
|
|
| (160.9) | (160.9) |
Total comprehensive income |
|
|
|
| $709.1 |
Balances at December 31, 2006 | 85.9 | $409.6 | $1,750.2 | $ 45.7 |
|
See notes accompanying the consolidated financial statements
QUESTAR 2006 FORM 10-K 52
QUESTAR 2006 FORM 10-K 53
Long-term debt repaid | (200.0) | (200.0) | (72.0) | |
Early extinguishment of debt costs | (1.7) |
|
| |
Change in short-term debt | (54.5) | 26.5 | (37.5) | |
Dividends paid | (79.7) | (75.6) | (71.4) | |
Excess tax benefits from share-based compensation | 12.0 |
|
| |
NET CASH (USED IN) PROVIDED FROM FINANCING ACTIVITIES | (72.3) | 8.1 | (156.6) | |
Change in cash and cash equivalents | 11.2 | 9.7 | (10.2) | |
Beginning cash and cash equivalents | 13.4 | 3.7 | 13.9 | |
Ending cash and cash equivalents | $ 24.6 | $ 13.4 | $ 3.7 | |
|
|
|
| |
See notes accompanying the consolidated financial statements |
|
|
| |
QUESTAR 2006 FORM 10-K 54
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 four major lines of business – gas and oil exploration and production, midstream field services, interstate gas transportation, and retail gas distribution – which are conducted through its three principal subsidiaries:
·
Questar Market Resources, Inc. (Market Resources) is a sub-holding 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 services.
·
Questar Gas Company (Questar Gas) provides retail natural gas distribution.
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 with U.S. generally accepted accounting principles (GAAP) and with the instructions for annual reports on Form 10-K and Regulations S-X and S-K. All significant intercompany accounts and transactions have been eliminated in consolidation.
Investments 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 would be included in the determination of net income.
The principal affiliates and Questar’s ownership percentage as of December 31, 2006, were Rendezvous Gas Services, LLC, a limited liability corporation (50%), Uintah Basin Field Services, LLC, a limited liability corporation (38%) and Canyon Creek Compression Company, a general partnership (15%). These entities are engaged in gathering and compressing natural gas.
Use of Estimates
The preparation of consolidated financial statements and notes in conformity with GAAP requires management to formulate estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. 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, 2006 and 2005, were $2.7 million and $2.5 million, respectively.
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
QUESTAR 2006 FORM 10-K 55
engaged in buy/sell arrangements, as described in EITF 04-13 “Accounting for Purchases and Sales of Inventory with the Same Counterparty,” and therefore has not provided the related disclosure.
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 nongas revenues. The weather-normalization adjustment significantly reduces the impact of weather on gas-distribution earnings. In 2006, the PSCU approved a pilot program for a “conservation enabling tariff” (CET) 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 will be limited to one percent of total revenues for the first year.
Regulation
Questar Gas is regulated by the Public Service Commission of Utah (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.
The financial statements of rate-regulated businesses are presented in accordance with regulatory requirements. Methods of allocating costs to time periods, in order to match revenues and expenses, may differ from those of other businesses because of cost-allocation methods used in establishing rates. Regulatory assets and liabilities are recorded to reflect these timing differences.
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.
Derivative Collateral Deposits
Derivative collateral deposits represent cash collateral deposited with counterparties under the terms of derivative agreements. Some counterparties may require the Company to deposit cash collateral when the derivative transactions under these agreements are out-of-the-money by an amount that exceeds counterparty credit limits. The deposits are restricted until either the derivative transaction returns to in-the-money status or the open position is settled.
Purchased-Gas Adjustments and Other Regulatory Assets and Liabilities
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.
In addition, to purchased-gas adjustments, rate-regulated businesses are permitted to defer recognition of certain costs, which is different from the accounting treatment required of nonrate-regulated businesses. See Note 7 to the consolidated financial statements for a description and comparison of regulatory assets and liabilities as of December 31, 2006 and 2005.
QUESTAR 2006 FORM 10-K 56
Property, Plant and Equipment
Property, plant and equipment balances are stated at historical cost. Maintenance and repair costs are expensed as incurred.
Gas and oil properties
Questar E&P 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 and depreciated on a field basis using the unit-of-production method and the estimated proved developed gas and oil reserves. Costs of 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. 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 exploratory well costs
The Company capitalizes exploratory well costs until it determines whether the 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” gas and oil properties owned by Questar Gas and managed and developed by Wexpro. Cost-of-service gas and oil properties are properties for which the operations and return on investment are subject to the Wexpro Agreement (see Note 14). 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. That cost includes a return on Wexpro’s investment. Oil produced from the cost-of-service properties is sold at market prices. Proceeds are credited pursuant to the terms of the agreement, allowing Questar Gas to share in the proceeds for the purpose of reducing natural gas rates.
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 for the periods:
|
| 2006 | 2005 | 2004 |
Gas and oil properties, per Mcfe |
| $1.43 | $1.18 | $1.04 |
Cost-of-service gas and oil properties, per Mcfe | 1.04 | 0.83 | 0.82 | |
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. Gas-production fixed assets owned by Questar Gas are depreciated using the unit-of-production method.
QUESTAR 2006 FORM 10-K 57
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. Average depreciation, depletion and amortization rates for the year ended December 31, were as follows:
| 2006 | 2005 | 2004 |
Questar Pipeline transmission, processing and storage | 3.4% | 3.3% | 3.4% |
Questar Gas |
|
|
|
Distribution plant | 3.4% | 3.9% | 3.7% |
Gas wells, per Mcf | $0.11 | $0.11 | $0.11 |
Effective June 1, 2006, Utah customer rates were reduced by $9.7 million per year, primarily to reflect changes in the company’s depreciation rates. Depreciation expense was approximately $5.3 million lower for this seven-month period as a result of the depreciation rate change.
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 an impairment of gas and oil reserves caused by mechanical problems, a faster-than-expected decline of reserves, lease-ownership issues, an 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.
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 on cost-of-service construction projects. AFUDC amounted to $1.0 million in 2006, $0.7 million in 2005 and $0.3 million in 2004 and increased interest and other income in the Consolidated Statements of Income. Interest expense was reduced by $0.8 million in 2006, $1.0 million in 2005 and $0.2 million in 2004.
Derivative Instruments
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 other comprehensive income 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.
QUESTAR 2006 FORM 10-K 58
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.
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 net income.
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 cost of sales in the month of settlement.
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 a master-netting agreement with some customers that allows 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 $6.1 million in 2006, $8.8 million in 2005 and $5.5 million in 2004. The allowance for bad-debt expenses was $7.8 million at December 31, 2006, and $7.7 million at December 31, 2005. Questar Gas’s retail-gas operations account for a majority of the bad-debt expense. Questar Gas 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 timing 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. Interest earned on refunds is recorded in interest and other income. Interest expense charged on tax deficiencies is recorded in interest expense.
Earnings Per Share (EPS)
Basic earnings per share are computed by dividing net income available to common shareholders by the weighted average number of common shares outstanding during the accounting 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 plus an estimated number of nonvested restricted shares.
QUESTAR 2006 FORM 10-K 59
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). Prior to January 1, 2006, the Company accounted for share-based compensation using the intrinsic value method prescribed by Accounting Principles Board Opinion (APBO) 25 “Accounting for Stock Issued to Employees” and related interpretations. No compensation cost was recorded for stock options issued because the exercise price equaled the market price on the date of grant. The granting of restricted shares resulted in recognition of compensation cost measured at the grant-date market price.
The Company implemented Statement of Financial Accounting Standards 123R “Share Based Payment,” (SFAS 123R) effective January 1, 2006, and chose the modified prospective phase-in method. The modified prospective phase-in method requires recognition of compensation costs for all share-based payments granted, modified or settled after January 1, 2006, as well as for any awards that were granted prior to the implementation date for which the required service has not yet been performed. Questar uses an accelerated method in recognizing share-based compensation costs with graded-vesting periods.
Comprehensive Income
Comprehensive income is the sum of net income as reported in the Consolidated Statement of Income and other comprehensive income or loss reported in the Consolidated Statement of Common Shareholders’ Equity. Other comprehensive income or loss includes changes in the market value of gas and oil price derivatives and recognition of the under funded position of pension and other postretirement benefit plans. The pension liability and postretirement benefit liability increased as a result of implementing SFAS 158. 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. The balances of accumulated other comprehensive loss, net of income taxes, at December 31, were as follows:
|
| 2006 | 2005 | 2004 | |
| (in millions) |
| |||
Unrealized gain (loss) on derivatives | $128.1 | ($198.1) | ($42.2) |
| |
Pension liability | (68.9) | (21.2) | (12.0) |
| |
Postretirement benefits liability | (13.5) |
|
|
| |
Accumulated other comprehensive income (loss) | $45.7 | ($219.3) | ($54.2) |
| |
Income tax allocated to each component of other comprehensive income is shown in the table below:
|
| 2006 | 2005 | 2004 | |
| (in millions) |
| |||
Unrealized gain (loss) on derivatives | ($198.7) | $95.5 | $5.7 |
| |
Pension liability | 29.4 | 5.7 | 2.1 |
| |
Postretirement benefits liability | 8.4 |
|
|
| |
| ($160.9) | $101.2 | $7.8 |
| |
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
In July 2006, the Financial Accounting Standards Board (FASB) issued FASB Interpretation 48 “Accounting for Uncertainty in Income Taxes” (FIN 48). The interpretation applies to all tax positions related to income taxes subject to FASB Statement 109 “Accounting for Income Taxes.” FIN 48 clarifies 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. FIN 48 is effective for Questar beginning January 1, 2007. The Company does not expect the provisions of FIN 48 will have a significant impact on its financial statements.
QUESTAR 2006 FORM 10-K 60
In September 2006, the FASB issued SFAS 157 “Fair Value Measures”. SFAS 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measures required under other accounting pronouncements, but does not change existing guidance as to whether or not an instrument is carried at fair value. SFAS 157 is effective for fiscal years beginning after November 15, 2007. The Company is continuing to assess the impact of SFAS 157.
In December 2006, the FASB issued an exposure draft titled “Disclosures about Derivative Instruments and Hedging Activities.” The proposed statement would amend and expand the disclosure requirements in SFAS 133 “Accounting for Derivative Instruments and Hedging Activities”, and other related accounting pronouncements. The proposed expanded disclosure is intended to provide enhanced understanding of (i) how and why an entity uses derivative instruments; (ii) how derivative instruments and related hedged items are accounted for under SFAS 133 and its related interpretations; and (iii) how derivative instruments affect an entity’s financial position, results of operations, and cash flows. The proposed effective date would be for fiscal years and interim periods ending after December 15, 2007. The Company has not evaluated the potential effect of the proposed disclosures.
In February 2007, the FASB issued SFAS 159 “The Fair Value Option for Financial Assets and Financial Liabilities.” SFAS 159 permits the measurement of certain financial instruments at fair value. Entities may choose to measure eligible items at fair value at specified election dates, reporting unrealized gains and losses on such items at each subsequent reporting period. SFAS 159 is effective for fiscal years beginning after November 15, 2007. The Company has not evaluated the potential impact of the fair value option.
Reclassifications
Certain reclassifications were made to prior-year consolidated financial statements to conform with the 2006 presentation. Amounts are presented in millions of dollars, the Consolidated Statement of Income includes a line item for gain and loss on asset sales and exploratory dry hole expense is a line item in operating activities on the Consolidated Statement of Cash Flows requiring a reciprocal adjustment in capital expenditures. The information in Note 13 Employee Benefits and Note 15 Lines of Business was reorganized to improve the presentation.
Note 2 – Earnings Per Share and Common Stock
Earnings per share (EPS)
Basic EPS is computed by dividing net income available to common shareholders 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 plus an estimated number of nonvested restricted shares. A reconciliation of the components of basic and diluted shares used in the EPS calculation follows:
| Year Ended December 31, | |||
| 2006 | 2005 | 2004 | |
| (in millions) | |||
Weighted-average basic common shares |
|
|
| |
outstanding | 85.5 | 84.8 | 83.8 | |
Potential number of shares issuable under |
|
|
| |
the LTSIP | 2.1 | 2.3 | 1.9 | |
Average diluted common shares outstanding | 87.6 | 87.1 | 85.7 | |
In the past three years, Questar issued 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 relied on open market purchases to meet 2006 distributions. The Reinvestment Plan issued 2,675 shares in 2005 and 185,809 shares in 2004. At December 31, 2006, 1,018,130 shares were reserved for future issuance.
QUESTAR 2006 FORM 10-K 61
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 80% 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. Beginning in 2005, the EIP trustee purchases Questar shares on the open market as cash contributions are received. The Company recognizes expense equal to its contributions which amounted to $6.7 million, $6.2 million and $5.8 million for the years ended December 31, 2006, 2005 and 2004, respectively. The Company contributed 16,928 shares in 2005 and 143,436 shares in 2004. The Company did not contribute shares to the EIP in 2006. In 2005, a majority of the Questar shares held in the EIP were purchased in open market transactions.
Long-Term Stock Incentive Plan (LTSIP)
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 ten-year term. Options held by employees generally vest in four equal, annual installments beginning six months after grant. Options granted to nonemployee directors generally vest in one installment six months after grant. A majority of restricted shares vest in equal installments over a three to five-year period after the grant date. Several grants vest in a single installment after a specified period. Nonvested restricted shares have voting and dividend rights; however, sale or transfer is restricted. Options and restricted shares issued prior to February 2006, vested on an accelerated basis in the event of a qualified termination, such as retirement, and have postretirement exercise periods. For summarizes of LTSIP transactions see Note 3 - Share-Based Compensation following.
Note 3 – Share-Based Compensation
Prior to January 1, 2006, the Company accounted for share-based compensation using the intrinsic value method prescribed by APBO 25 “Accounting for Stock Issued to Employees” and related interpretations. No compensation cost was recorded for stock options issued because the exercise price equaled the market price on the date of grant. The granting of restricted shares resulted in recognition of compensation cost. Restricted shares are valued at the grant-date market price and amortized to expense over the vesting period.
The Company implemented SFAS 123R effective January 1, 2006, and chose the modified prospective phase-in method. The modified prospective phase-in method requires recognition of compensation costs for all share-based payments granted, modified or settled after January 1, 2006, as well as for any awards that were granted prior to the implementation date for which the required service has not yet been performed. As a result of adopting SFAS 123R, the Company’s income before income taxes and net income for the year ended December 31, 2006, were approximately $1.7 million and $1.0 million lower, respectively, than if the Company had continued to account for share-based compensation under APBO 25 resulting in a $0.01 reduction in basic and diluted earnings per share for the year ended December 31, 2006. Share-based compensation associated with unvested restricted shares for the 12 months ended December 31, 2006, 2005 and 2004, amounted to $8.0 million, $4.2 million and $2.4 million, respectively. At December 31, 2006, deferred share-based compensation amounted to $13.0 million, of which $3.2 million was attributed to unvested stock options.
SFAS 123R requires the benefits of tax deductions in excess of recognized compensation expense resulting from the exercise of share-based awards be reported in the financing activities section of the Consolidated Statements of Cash Flow. For the year ended December 31, 2006, this requirement reduced net cash provided from operating activities and reduced net cash used in financing activities by $12.0 million.
The following table shows pro forma net income had stock options been expensed in the prior period based on a fair value calculated using the Black-Scholes-Merton model:
| 2005 | 2004 |
| (in millions) | |
Net income, as reported | $325.7 | $229.3 |
Deduct: Share-based compensation expense |
|
|
determined under fair-value-based methods, (after tax) | (1.7) | (3.3) |
Pro forma net income | $324.0 | $226.0 |
Earnings per share |
|
|
QUESTAR 2006 FORM 10-K 62
Basic, as reported | $3.84 | $2.74 |
Basic, pro forma | 3.82 | 2.70 |
Diluted, as reported | 3.74 | 2.67 |
Diluted, pro forma | 3.72 | 2.64 |
Fair value of the stock options issued was determined on the grant date using the Black-Scholes-Merton option-valuation model. The fair-value calculation relies upon subjective assumptions and the use of a mathematical model to estimate value 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:
| 2005 | 2004 | |
| January | October |
|
Fair value of options at grant date | $14.90 | $21.46 | $9.66 |
Risk-free interest rate | 3.97% | 4.17% | 3.52% |
Expected price volatility | 29.9% | 27.0% | 28.4% |
Expected dividend yield | 1.77% | 1.17% | 2.34% |
Expected life in years | 6.4 | 5.0 | 7.3 |
Long-Term Stock Incentive Plan
There were 5,351,091 shares available for future grant at December 31, 2006. The Company granted restricted shares but did not grant stock options in 2006. Unvested stock options declined by 232,125 to 231,250 in 2006. Transactions involving stock options in the LTSIP for the three years ended December 31, 2006, are summarized below:
|
| Outstanding Options | Price Range | Weighted Average Price | ||||||||
| Balance at January 1, 2004 | 4,980,219 | $13.69 - $29.71 | $23.16 | ||||||||
| Granted | 25,000 | 35.10 | 35.10 | ||||||||
| Cancelled | (11,000) | 15.00 - 27.11 | 25.06 | ||||||||
| Exercised | (979,148) | 13.69 - 35.10 | 20.62 | ||||||||
| Balance at December 31, 2004 | 4,015,071 | 13.69 - 35.10 | 23.85 | ||||||||
| Granted | 250,000 | 48.66 - 77.14 | 71.44 | ||||||||
| Exercised | (1,013,083) | 13.69 - 35.10 | 22.84 | ||||||||
| Balance at December 31, 2005 | 3,251,988 | 13.69 - 77.14 | 27.82 | ||||||||
| Exercised | (565,634) | 15.00 - 35.10 | 23.99 | ||||||||
| Balance at December 31, 2006 | 2,686,354 | $15.00 - $77.14 | $28.63 | ||||||||
|
|
|
|
| ||||||||
Options Outstanding | Options Exercisable | Unvested Options | ||||||||||
Range of exercise prices | Number outstanding at Dec. 31, 2006 | Weighted-average remaining term in years | Weighted-average exercise price | Number exercisable at Dec. 31, 2006 | Weighted-average exercise price | Number unvested at Dec. 31, 2006 | Weighted average exercise price | |||||
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|
|
|
|
|
| |||||
$15.00 – $17.00 | 423,052 | 3.0 | $15.44 | 423,052 | $15.44 |
|
| |||||
19.13 – 23.95 | 616,370 | 4.5 | 22.76 | 616,370 | 22.76 |
|
| |||||
27.11 – 29.71 | 1,382,993 | 5.3 | 27.48 | 1,382,993 | 27.48 |
|
| |||||
QUESTAR 2006 FORM 10-K 63
35.10 – 77.14 | 263,939 | 6.3 | 69.52 | 32,689 | 45.47 | 231,250 | $72.92 | |||||
| 2,686,354 | 4.9 | $28.63 | 2,455,104 | $24.46 | 231,250 | $72.92 | |||||
Most restricted share grants vest in equal installments over a three to five year period from the grant date. Several grants vest in a single installment after a specified period. The weighted average vesting period of unvested restricted shares at December 31, 2006, was 16 months. Transactions involving restricted shares under the term of the LTSIP for the three years ended December 31, 2006, are summarized below:
| Restricted Shares |
| Weighted Average |
| Outstanding | Price Range | Price |
|
|
|
|
Balance at January 1, 2004 | 148,050 | $23.95 - $34.00 | $27.71 |
Granted | 132,400 | 34.90 - 50.60 | 35.99 |
Forfeited | (8,400) | 28.72 - 36.90 | 31.73 |
Distributed | (33,610) | 23.95 - 34.00 | 27.67 |
Balance at December 31, 2004 | 238,440 | 27.11 - 50.60 | 32.17 |
Granted | 113,975 | 48.66 - 86.03 | 53.98 |
Forfeited | (8,020) | 28.72 - 51.00 | 36.48 |
Distributed | (44,354) | 23.95 - 51.00 | 31.90 |
Balance at December 31, 2005 | 300,041 | 27.11 - 86.03 | 40.38 |
Granted | 158,715 | 68.22 - 89.54 | 74.01 |
Forfeited | (2,645) | 28.72 - 75.99 | 62.92 |
Distributed | (90,500) | 27.11 - 86.03 | 27.74 |
Balance at December 31, 2006 | 365,611 | $27.11 - $86.03 | $56.09 |
Note 4 – Property, Plant and Equipment
The details of property, plant and equipment and accumulated depreciation, depletion and amortization follow:
| December 31, | ||
| 2006 | 2005 | |
| (in millions) | ||
Property, plant and equipment |
| ||
Market Resources |
|
| |
Questar E&P gas and oil properties |
|
| |
Proved properties | $2,646.6 | $2,047.9 | |
Unproved properties, not being depleted | 42.7 | 41.5 | |
Support equipment and facilities | 18.5 | 18.4 | |
Questar E&P total | 2,707.8 | 2,107.8 | |
Wexpro cost-of-service gas and oil properties | 658.6 | 561.5 | |
Gas Management gathering and processing | 404.2 | 323.9 | |
Energy Trading marketing and other | 37.9 | 36.3 | |
Market Resources total | 3,808.5 | 3,029.5 | |
|
|
| |
Questar Pipeline transportation and storage | 1,173.9 | 1,101.5 | |
Questar Gas natural gas distribution | 1,418.0 | 1,383.4 | |
QUESTAR 2006 FORM 10-K 64
Corporate and other operations | 13.7 | 13.6 | |
| $6,414.1 | $5,528.0 | |
Accumulated depreciation, depletion and amortization |
|
| |
Market Resources |
|
| |
Questar E&P gas and oil properties | $ 901.5 | $ 731.1 | |
Wexpro cost-of-service gas and oil properties | 305.4 | 277.6 | |
Gas Management gathering and processing | 97.3 | 82.2 | |
Energy Trading marketing and other | 5.5 | 4.6 | |
Market Resources total | 1,309.7 | 1,095.5 | |
Questar Pipeline transportation and storage | 406.8 | 381.4 | |
Questar Gas natural gas distribution | 598.0 | 615.9 | |
Corporate and other operations | 8.2 | 7.7 | |
| 2,322.7 | 2,100.5 | |
Net Property, Plant and Equipment | $4,091.4 | $3,427.5 | |
Questar E&P proved and unproved leaseholds had a net book value at December 31 of $343.3 million in 2006 and $344.0 in 2005.
Southern Trails Pipeline
The California segment of the Southern Trails Pipeline, which extends from near the California-Arizona state line to Long Beach, California, is currently not in service. Questar Pipeline is pursuing several options to sell or place this line in service.
Questar Pipeline performed an impairment test on the California segment of Southern Trails during the fourth quarter of 2005 and recognized an impairment of $16 million, reducing its net investment to approximately $35 million. The value realized by Questar Pipeline for the California segment of Southern Trails, either by putting the line in service or selling the line, may vary from this amount.
A firm-transportation contract for 40 Mdth per day, representing about 50% of the total capacity, on the eastern segment of Southern Trails Pipeline is up for renewal in mid-2008. The company is working with the shipper to extend the contract. In addition, the company is actively remarketing this capacity in the event the shipper elects not to renew. An impairment of the eastern segment may be required if the company’s recontracting efforts result in significantly lower throughput or rates.
Note 5– Asset Retirement Obligations (ARO)
Questar recognizes ARO in accordance with SFAS 143 “Accounting for Asset Retirement Obligations.” SFAS 143 addresses the financial accounting and reporting of the fair value of legal obligations associated with the retirement of tangible long-lived assets. The Company’s ARO applies primarily to plugging and abandonment costs associated with gas and oil wells and certain other properties. The fair value of abandonment costs are estimated and depreciated over the life of the related assets. Revisions to estimates of the ARO result from changes in expected cash flows. The ARO liability is adjusted to present value each period through an accretion calculation using a credit-adjusted risk-free interest rate. Changes in asset retirement obligations were as follows:
| 2006 | 2005 |
| (in millions) | |
ARO liability at January 1, | $78.2 | $67.3 |
Accretion | 7.1 | 4.3 |
QUESTAR 2006 FORM 10-K 65
Liabilities incurred | 11.1 | 7.9 |
Revisions | 38.2 |
|
Liabilities settled | (2.2) | (1.3) |
ARO liability at December 31, | $132.4 | $78.2 |
Wexpro activities are governed by a long-standing agreement with the states of Utah and Wyoming (the Wexpro Agreement). The accounting treatment of reclamation activities associated with ARO for properties administered under the Wexpro Agreement is spelled out in a guideline letter between Wexpro and the Utah Division of Public Utilities and the staff of the Public Service Commission of Wyoming (PSCW). Accordingly, Wexpro collects from Questar Gas and deposits in trust funds related to estimated ARO costs. The funds are used to satisfy retirement obligations as the properties are abandoned. At December 31, 2006, approximately $5.8 million was held in this trust invested primarily in a short-term bond index fund.
Note 6 – Capitalized Exploratory Well Costs
Net changes in capitalized exploratory well costs in 2006, 2005 and 2004 are as follows and exclude amounts that were capitalized and subsequently expensed in the period:
| 2006 | 2005 | 2004 |
| (in millions) | ||
Balance at January 1, | $ 16.5 | $ 14.6 | $ 1.0 |
Additions to capitalized exploratory well costs pending the |
|
|
|
determination of proved reserves |
| 9.8 | 14.1 |
Reclassifications to property, plant and equipment after the |
|
|
|
determination of proved reserves | (5.0) | (5.7) | (0.5) |
Capitalized exploratory well costs charged to expense | (11.5) | (2.2) |
|
Balance at December 31, | $ | $16.5 | $14.6 |
The following table provides an aging of capitalized exploratory well costs based on the date drilling was completed and any projects for which exploratory well costs have been capitalized for a period greater than one year since the completion of drilling:
| December 31, | ||
| 2006 | 2005 | 2004 |
| (in millions) | ||
Capitalized exploratory well costs that have been capitalized |
|
|
|
one year or less | $ | $ 9.8 | $14.1 |
Capitalized exploratory well costs that have been capitalized |
|
|
|
longer than one year |
| 6.7 | 0.5 |
Balance at end of period | $ | $16.5 | $14.6 |
Note 7 – Other Regulatory Assets and Liabilities
The Company has other regulatory assets and liabilities in addition to purchased-gas adjustments. The regulated entities recover these costs 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 11 years as of December 31, 2006.
QUESTAR 2006 FORM 10-K 66
·
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.
·
The costs of complying with pipeline-integrity regulations are recovered in rates subject to a PSCU order effective June 1, 2006. Costs incurred prior to June 2006 were deferred and will now be recovered over a three-year period. Actual current costs in excess of $1.4 million annually will be deferred and recovered in future rates.
Questar Pipeline has accrued a regulatory liability for the collection of postretirement medical costs allowed in rates which exceeded actual charges. Regulatory liabilities are included with other long-term liabilities in the consolidated balance sheets. A list of regulatory assets and liabilities follows:
| December 31, | |
| 2006 | 2005 |
| (in millions) | |
Regulatory assets |
|
|
Cost of reacquired debt | $14.7 | $16.0 |
Asset retirement obligations – cost -of-service gas wells | 4.2 | 4.6 |
Deferred production taxes | 4.3 | 4.9 |
Income taxes recoverable to customers | 2.9 | 3.2 |
Questar Gas pipeline-integrity costs | 5.7 | 3.1 |
Other | 0.9 | 1.0 |
| $32.7 | $32.8 |
| December 31, | |
| 2006 | 2005 |
| (in millions) | |
Regulatory liabilities |
|
|
Postretirement medical | $4.3 | $4.2 |
Income taxes refundable to customers | 2.0 | 2.4 |
Conservation enabling tariff | 1.5 |
|
Demand side management | 1.2 |
|
| $9.0 | $6.6 |
Note 8 – Debt
The Company has short-term line-of-credit commitments from several banks under which it may borrow up to $400 million at December 31, 2006. These credit lines have interest rates 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 an annual commitment fee on the unused balance. The details of short-term debt are as follows:
| December 31, | ||
| 2006 | 2005 | |
| (in millions) | ||
Commercial paper with variable-interest rates | $40.0 | $94.5 | |
Weighted-average interest rate | 5.43% | 4.43% | |
QUESTAR 2006 FORM 10-K 67
All long-term notes and the term loan are unsecured obligations and rank equally with all other unsecured liabilities. Market Resources revolving credit agreement had no borrowings outstanding at December 31, 2006 or 2005, but was fully drawn during part of 2005. This credit agreement carries an annual commitment fee of 0.115% of the unused balance. At December 31, 2006, Market Resources could pay dividends of $634.0 million and Questar Gas could pay dividends of $130.0 million without violating the terms of their debt covenants.
On May 11, 2006, Market Resources sold $250 million principal amount of 6.05% Notes due 2016. Net proceeds of $247 million were used for general corporate purposes including the June 14, 2006, early extinguishment of $200 million of 7% Notes due 2007. Market Resources recorded a $1.7 million charge related to the early extinguishment. On December 15, 2005, Questar Gas borrowed $50 million from a bank under a five-year term loan agreement. The loan’s interest rate varies periodically with changes in short-term interest rates available in the credit markets. The details of long-term debt are listed in the table below:
| December 31, | |||
| 2006 | 2005 | ||
| (in millions) | |||
Market Resources |
|
| ||
7.0% notes due 2007 |
| $200.0 | ||
7.5% notes due 2011 | $ 150.0 | 150.0 | ||
6.05% notes due 2016 | 250.0 |
| ||
Questar Pipeline |
|
| ||
Medium-term notes 5.85% to 7.55%, due 2008 to 2018 | 310.4 | 310.4 | ||
Questar Gas |
|
| ||
Medium-term notes 5.00% to 7.58%, due 2007 to 2018 | 273.0 | 273.0 | ||
Five-year term loan 5.62% at December 31, 2006, due 2010 | 50.0 | 50.0 | ||
Corporate and other operations | 0.1 | 0.1 | ||
Total long-term debt outstanding | 1,033.5 | 983.5 | ||
Less current portion | (10.0) |
| ||
Less unamortized-debt discount | (1.1) | (0.3) | ||
Total long-term debt | $1,022.4 | $983.2 | ||
Maturities of long-term debt for the five years following December 31, 2006, are as follows:
| (in millions) |
2007 | $ 10.0 |
2008 | 101.3 |
2009 | 42.0 |
2010 | 50.0 |
2011 | 332.0 |
Cash paid for interest was $70.4 million in 2006, $67.8 million in 2005 and $66.8 million in 2004.
Note 9 – Financial Instruments and Risk Management
The carrying value and estimated fair values of Questar’s financial instruments were as follows:
QUESTAR 2006 FORM 10-K 68
| December 31, 2006 | December 31, 2005 | ||
| Carrying | Estimated | Carrying | Estimated |
| Value | Fair Value | Value | Fair Value |
| (in millions) | |||
Financial assets |
|
|
|
|
Cash and cash equivalents | $ 24.6 | $ 24.6 | $ 13.4 | $ 13.4 |
Fair value of derivative contracts | 204.5 | 204.5 | 2.0 | 2. 0 |
Financial liabilities |
|
|
|
|
Short-term loans | 40.0 | 40.0 | 94.5 | 94.5 |
Long-term debt | 1,033.5 | 1,065.2 | 983.5 | 1,041.5 |
Fair value of derivative contracts | 8.4 | 8.4 | 321.1 | 321.1 |
The Company used the following methods and assumptions in estimating fair values.
Cash and cash equivalents and short-term debt – the carrying amount approximates fair value.
Long-term debt – the carrying amount of variable-rate debt approximates fair value. The fair value of fixed-rate debt is based on the discounted present value of cash flows using the Company’s current borrowing rates.
Derivative instruments – fair value of the contracts is based on market prices as posted on the NYMEX from the last trading day of the year. Gas derivatives are structured as fixed-price swaps into regional pipelines, locking in basis and hedge effectiveness. Market Resources held gas-price-derivative instruments covering the price exposure for about 204.2 million MMBtu of natural gas, 1.8 MMbbl of oil and 22.7 MMgal of NGL as of December 31, 2006. Gas Management, a subsidiary of Market Resources, uses forward-sales contracts to secure the price received for NGL processed from its plants. About 75% of the fair value of all contracts will settle and be reclassified from other comprehensive income in the next 12 months. A year earlier Market Resources derivatives covered the price exposure for about 184.4 million MMBtu of natural gas, 2.9 MMbbl of oil and 10.1 MMgal of NGL.
At December 31, 2006, the Company reported assets, net of liabilities, of $196.1 million related to derivatives. The offset to the derivative assets, net of income taxes, was a $128.1 million unrealized gain on derivatives recorded in other comprehensive income in the shareholders’ equity section of the consolidated balance sheet. The ineffective portion of derivative transactions recognized in earnings was not significant. The fair-value calculation of gas- and oil-price derivatives does not consider changes in the fair value of the corresponding scheduled equity physical transactions, (i.e., the correlation between index price and the price realized for the physical delivery of gas or oil).
Note 10 – Income Taxes
Details of Questar’s income tax expense and deferred income taxes are provided in the following tables. The components of income taxes were as follows:
| Year Ended December 31, | ||
| 2006 | 2005 | 2004 |
| (in millions) | ||
Federal |
|
|
|
Current | $141.6 | $ 97.8 | $ 19.6 |
Deferred | 90.5 | 71.1 | 97.6 |
QUESTAR 2006 FORM 10-K 69
State |
|
|
|
Current | 12.5 | 12.2 | 1.5 |
Deferred | 11.3 | 7.2 | 11.3 |
Deferred investment-tax credits | (0.4) | (0.4) | (0.4) |
| $255.5 | $187.9 | $129.6 |
The difference between the statutory federal income tax rate and the Company’s effective income tax rate is explained as follows:
| Year Ended December 31, | ||
| 2006 | 2005 | 2004 |
Federal income taxes statutory rate | 35.0% | 35.0% | 35.0% |
Increase (decrease) as a result of: |
|
|
|
State income taxes, net of federal income |
|
|
|
tax benefit | 2.2 | 2.5 | 2.4 |
Domestic production benefit | (0.3) | (0.3) |
|
Percentage depletion | (0.1) | (0.1) | (0.3) |
Amortize investment-tax credits related to |
|
|
|
rate-regulated assets | (0.1) | (0.1) | (0.1) |
Tax benefits from dividends paid to ESOP | (0.2) | (0.3) | (0.4) |
Other |
| (0.1) | (0.5) |
Effective income tax rate | 36.5% | 36.6% | 36.1% |
Significant components of the Company’s deferred income taxes were as follows:
| December 31, | |
| 2006 | 2005 |
| (in millions) | |
Deferred tax liabilities |
|
|
Property, plant and equipment | $798.3 | $675.5 |
Energy price derivatives | 18.9 |
|
Total deferred tax liabilities | 817.2 | 675.5 |
Deferred tax assets |
|
|
Energy price hedging |
| 37.5 |
Employee benefits and compensation costs | 53.3 | 13.8 |
Total deferred tax assets | 53.3 | 51.3 |
Deferred income taxes – noncurrent | $763.9 | $624.2 |
Deferred income taxes – current asset (liability) |
|
|
Energy price derivatives | ($58.3) | $83.3 |
Purchased-gas adjustment |
| (15.1) |
Other | 23.3 | 18.5 |
Deferred income taxes – current | ($35.0) | $86.7 |
Cash paid for income taxes was $144.1 million in 2006, $86.5 million in 2005 and $23.3 million in 2004.
QUESTAR 2006 FORM 10-K 70
Note 11 – Rate Regulation
Questar Gas Rate Changes
In October 2006, the PSCU approved a pilot program for a CET effective January 1, 2006, to promote energy conservation. Under the company’s prior rate structure, declining usage lowered revenues and increasing usage per customer raised revenues. 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 will be limited to one percent of total revenues for the first year. The program will be reviewed after one year. Questar Gas recorded a $1.7 million revenue reduction in 2006 to recognize the impact of implementing the CET.
Effective June 1, 2006, the PSCU approved a settlement of other issues and ordered Questar Gas to reduce the nongas portion of customer rates by $9.7 million to reflect a reduction in depreciation rates, a change in capital structure, and recovery of pipeline integrity costs.
In January 2007, the PSCU approved a “demand-side management” program (DSM) effective January 1, 2007. Under the DSM, Questar Gas will encourage the conservation of natural gas through advertising, rebates for efficient homes and appliances, and energy audits. The costs of the DSM will be deferred and recovered from customers through periodic rate adjustments.
State Rate Regulation
Questar Gas files periodic applications with the PSCU and PSCW requesting permission to reflect annualized gas-cost increases or decreases in its rates. Gas costs are passed on to customers on a dollar-for-dollar basis with no markup.
Gas-Processing Dispute
In October 2005, Questar Gas, the Utah Division of Public Utilities and the Committee of Consumer Services submitted a stipulation to the PSCU to resolve issues related to cost recovery of carbon dioxide processing activities. The PSCU issued an order on January 6, 2006, approving the stipulation beginning on February 1, 2005. The stipulation provides for the recovery of 90% of the non fuel cost of service for processing and 100% of the fuel costs up to 360 Mdth per year. Half of the third-party processing revenues are shared with customers after the first $0.4 million. In the fourth quarter of 2005 Questar Gas reduced expenses for recovery of gas costs by $4.9 million for the period from February 1, 2005 to December 31, 2005. This settlement has been appealed to the Utah Supreme Court by a group of individuals.
Fuel-Gas Reimbursement Percentage (FGRP)
In July 2005, the FERC approved an uncontested offer of settlement to resolve the outstanding issues in the 2004 and 2005 FGRP filings. This settlement contains the following terms: (a) the settlement will cover the period from June 1, 2005 through December 31, 2007; (b) no adjustments will be made to FGRP amounts collected by Questar Pipeline prior to June 2005; (c) one-half of the Kastler plant liquid revenues from August 2001 through December 2007 will be refunded to customers and the remaining revenues will be retained by Questar Pipeline; and (d) Questar Pipeline will reduce the FGRP amount collected from customers from 2.6% to 2.1% effective June 1, 2005. This percentage consists of 1.95% of ongoing FGRP related costs and 0.15% of prior-period amortization of under-recovered volumes. If actual ongoing costs are less than the 1.95%, the difference will be shared equally with customers beginning January 2006. Questar Pipeline recorded the impact of the settlement in third quarter 2005 increasing liquid revenues by $2.7 million and net income by $1.7 million.
The actual FGRP for the 12-month period ended September 30, 2005, was 1.73%. Pursuant to the settlement, Questar Pipeline reduced its FGRP for calendar year 2006 to 1.84% plus 0.15% of prior period volume. The actual FGRP for the 12-month period ended September 2006, was 1.92%. In accordance with the settlement, the FGRP for 2007 is 1.94%.
Transmission Provider Standards of Conduct
On January 18, 2007, the FERC proposed permanent standards of conduct regulation in a Notice of Proposed Rulemaking (NOPR) that will replace an Interim Rule governing the relationship between transmission providers and their energy affiliates. The Interim Rule was put forth January 9, 2007, by the FERC in response to Order No. 2004 being vacated November 17, 2006, by the U.S. Court of Appeals for the District of Columbia Circuit. The Court of Appeals found that the FERC had not adequately supported the application of the standards of conduct to a broader definition of energy affiliates in Order No. 2004. In its NOPR the FERC proposed that the standards of conduct apply only to marketing affiliates. The proposed definition of marketing affiliate is similar to the definition found in Order No. 497 (pre-Order No. 2004).
QUESTAR 2006 FORM 10-K 71
Note 12 – 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 Questar’s financial position. An accrual is recorded for a loss contingency when its occurrence is probable and damages can be reasonably estimated based on the anticipated most likely outcome. 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.
Commitments
Historically, 40 to 50% of Questar Gas gas-supply portfolio has been provided from cost-of-service reserves. In 2006, the remainder of the gas supply was purchased from 14 suppliers using index-based or fixed-price contracts. Questar Gas has commitments to purchase gas for $170 million in 2007, $61 million in 2008, $35 million in 2009, $17 million in 2010 and $9 million in 2011. 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 $429.5 million in 2006, $447.4 million in 2005 and $336 million in 2004. In addition, Questar Gas makes use of various storage arrangements to meet peak-gas demand during certain times of the heating season.
Questar Gas has third-party transportation commitments requiring yearly payments of $5.3 million through 2018.
Subsidiaries of Market Resources have contracted for firm-transportation services with various third-party pipelines through 2018. Market conditions and competition may prevent full recovery of the cost. Annual payments and the years covered are as follows:
| (in millions) |
2007 | $ 7.8 |
2008 | 7.3 |
2009 | 7.3 |
2010 | 7.2 |
2011 | 6.9 |
2012 through 2018 | $22.2 |
Questar sold its headquarters building under a sale-and-leaseback arrangement committing the Company to occupy the building through January 12, 2012. Questar has four renewal options of five years each, following expiration of the original lease in 2012. Minimum future payments under the terms of long-term operating leases for the Company’s primary office locations are as follows:
| (in millions) |
2007 | $5.7 |
2008 | 5.8 |
2009 | 5.5 |
2010 | 5.2 |
2011 | 5.2 |
2012 | $2.8 |
Total minimum future-rental payments have not been reduced for sublease rentals of $0.4 million in 2007, $0.2 million in 2008, and $0.1 million in 2009. Total rental expense amounted to $5.3 million in 2006, $5.1 million in 2005 and $5.2 million in 2004. Sublease-rental receipts were $0.4 million in 2006, $0.3 million in 2005 and $0.2 million in 2004.
Note 13 – Employee Benefits
Pension and Postretirement Benefits
The Company has defined-benefit pension and postretirement medical and life insurance plans covering the majority of its employees. The Company’s Employee Benefits Committee (EBC) has oversight over investment of retirement-plan and
QUESTAR 2006 FORM 10-K 72
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:
| Actual Allocation |
| |
| December 31, | December 31, | Policy |
| 2006 | 2005 | Range |
Domestic equity securities | 44% | 45% | 40-50% |
Foreign equity securities | 22 | 21 | 15-25 |
Debt securities | 27 | 28 | 26-34 |
Real estate securities | 6 | 5 | 3-7 |
Other | 1 | 1 | 0-3 |
Questar sets aside funds 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 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 ERISA-qualified 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.
The EBC uses asset-mix guidelines that include targets and 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 an ongoing evaluation of each plan’s risk tolerance.
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.
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 benefits and life insurance are provided only to employees hired before January 1, 1997. The Company pays a portion of the costs of health-care benefits as 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. Prior to adopting SFAS 158, the Company was amortizing its transition obligation over a 20-year period, which began in 1992.
QUESTAR 2006 FORM 10-K 73
In September 2006, the FASB issued SFAS 158 “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans.” The new accounting standards of SFAS 158 require an employer to (i) recognize the overfunded or underfunded status of defined-benefit plans on the balance sheet, measured as the difference in the fair value of plan assets and the projected benefit obligation; (ii) recognize as a component of other comprehensive income, net of tax, the gains or losses and prior service costs or credits that arise during the period but are not recognized as components of the net periodic benefit cost; (iii) measure defined-benefit plan assets and obligations as of the date of the year-end balance sheet; and (iv) disclose additional information about certain effects on net periodic benefit cost for the next fiscal year that arise from delayed recognition of gains or losses, prior service costs or credits, and transition assets or obligations.
The adoption of SFAS 158 had no effect on the consolidated statements of income or consolidated statements of cash flow for the year ended December 31, 2006. The effects of adopting the provisions of SFAS 158 on the Company’s consolidated balance sheet at December 31, 2006, are presented in the table below.
Amounts recognized in the consolidated balance sheet at December 31, 2006, under SFAS 158:
| Pension | Postretirement Benefits |
| (in millions) | |
Current liabilities | ($1.1) |
|
Noncurrent liabilities | (106.0) | ($37.8) |
Other comprehensive loss | 68.9 | 13.5 |
Deferred income taxes | 42.7 | 8.3 |
Amounts recognized in the consolidated balance sheet at December 31, 2005, prior to SFAS 158:
| Pension | Postretirement Benefits |
| (in millions) | |
Current assets | $0.4 |
|
Current liability |
|
|
Noncurrent assets | 10.8 |
|
Noncurrent liabilities | (45.1) | ($16.4) |
Other comprehensive loss | 21.2 |
|
Deferred income taxes | 13.1 |
|
The pension projected-benefit obligation and postretirement benefit obligation were measured using a discount rate at December 31, of 5.75% in 2006 and 6.0% in 2005. Changes in discount rates are included in changes in plan assumptions. Asset-return assumptions are based on historical returns tempered for expectations of future performance. Assets were measured at December 31. A projected benefit obligation is shown below for the pension plan, whereas the accumulated benefit obligation is shown for the postretirement benefits:
| Pension | Postretirement Benefits | ||
| 2006 | 2005 | 2006 | 2005 |
| (in millions) | (in millions) | ||
Change in benefit obligation |
|
|
|
|
Benefit obligation at January 1, | $377.6 | $329.7 | $80.0 | $83.7 |
Service cost | 9.8 | 9.0 | 0.9 | 0.8 |
Interest cost | 22.8 | 21.2 | 4.5 | 4.6 |
Change in plan assumptions | 16.1 | 28.1 |
|
|
QUESTAR 2006 FORM 10-K 74
Actuarial loss | 10.1 | 3.0 | 3.0 | (4.0) |
Benefits paid | (14.9) | (13.4) | (5.4) | (5.1) |
Benefit obligation at December 31, | 421.5 | 377.6 | 83.0 | 80.0 |
|
|
|
|
|
Change in plan assets |
|
|
|
|
Fair value of plan assets at January 1, | 256.1 | 232.7 | 39.7 | 38.5 |
Actual return on plan assets | 48.5 | 18.8 | 6.0 | 3.0 |
Contributions to the plan | 24.7 | 18.0 | 4.9 | 3.3 |
Benefits paid | (14.9) | (13.4) | (5.4) | (5.1) |
Fair value of plan assets at December 31, | 314.4 | 256.1 | 45.2 | 39.7 |
Underfunded status | (107.1) | (121.5) | (37.8) | (40.3) |
Unrecognized net-actuarial loss |
| 111.1 |
| 13.1 |
Unrecognized transition obligation |
| 0.4 |
|
|
Unrecognized prior-service cost |
| 10.5 |
| 10.8 |
Minimum pension liability |
| (45.1) |
|
|
Accrued costs | ($107.1) | ($44.6) | ($37.8) | ($16.4) |
The accumulated-benefit obligation for the qualified defined-benefit pension plan was $293.7 million at December 31, 2005. The projected 2007 pension funding is expected to be $17.5 million. Estimated benefit-plan payments for the five years following 2006 and the subsequent five years aggregated are as follows:
| Pension | Postretirement Benefits |
| (in millions) | |
2007 | $ 13.6 | $ 4.9 |
2008 | 13.4 | 5.0 |
2009 | 14.0 | 5.0 |
2010 | 14.6 | 5.1 |
2011 | 15.6 | 5.1 |
2012 through 2016 | 105.7 | 26.9 |
Postretirement benefits other than pensions include an estimate of the effect of the Medicare Prescription Drug, Improvement and Modernization Act of 2003. The drug benefit offered as part of postretirement medical coverage is actuarially equivalent to Part D of Medicare. The components of pension and postretirement benefits expense are as follows. The pension expense includes costs of both qualified and nonqualified pension plans:
| Pension | Postretirement Benefits | ||||
| Year Ended December 31, | Year Ended December 31, | ||||
| 2006 | 2005 | 2004 | 2006 | 2005 | 2004 |
| (in millions) | (in millions) | ||||
Service cost | $ 9.8 | $ 9.0 | $ 8.2 | $ 0.9 | $ 0.8 | $ 0.8 |
Interest cost | 22.8 | 21.2 | 20.0 | 4.5 | 4.6 | 5.2 |
Expected return on plan assets | (21.0) | (19.8) | (18.8) | (3.0) | (3.0) | (3.0) |
Prior service and other costs | 1.5 | 1.6 | 2.2 | 1.9 | 1.9 | 1.8 |
Recognized net actuarial loss | 6.2 | 3.9 | 2.5 | 0.2 | 0.1 | 0.3 |
Special-termination benefits | 1.4 | 0.8 | 0.9 |
|
| 0.2 |
QUESTAR 2006 FORM 10-K 75
Accretion of regulatory liability |
|
|
| 0.8 | 0.8 | 0.8 |
Amortization of early retirement costs |
| 2.4 | 2.9 |
|
|
|
Periodic expense | $20.7 | $19.1 | $17.9 | $5.3 | $5.2 | $6.1 |
Assumptions at the beginning of the year used to calculate pension and postretirement benefits expense for the years were as follows:
| 2006 | 2005 | 2004 |
Discount rate | 6.00% | 6.50% | 6.75% |
Rate of increase in compensation | 4.00% | 4.00% | 4.00% |
Long-term return on assets | 8.00% | 8.25% | 8.50% |
Health-care inflation rate | 9.00% decreasing to 5.00% in 2011 | 10.00% decreasing to 5.00% by 2011 | 8.50% decreasing to 6.5% by 2009 |
The 2007 estimated pension expense is $18.9 million, which includes $6.2 million of unrecognized actuarial loss and $1.2 million of prior service costs previously included in other comprehensive loss. 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 $1.4 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 $1.3 million.
Note 14 – 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’s utility operations 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 20.9%.
b. Wexpro operates 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 12.9%.
c. Production from a finite group of oil-producing properties is sold at market prices with the revenues used to recover operating expenses and to give Wexpro a return on its investment. The after-tax rate of return is adjusted annually and is approximately 12.9%. Any net 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 17.9%. Any net income remaining after recovery of expenses and Wexpro’s return on investment is divided between Wexpro and Questar Gas with Wexpro retaining 46%.
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 investment base, net of depreciation and deferred income taxes, and the yearly average rate of return for 2006 and the previous two years are shown in the table below:
QUESTAR 2006 FORM 10-K 76
| 2006 | 2005 | 2004 |
Wexpro’s net investment base (in millions) | $260.6 | $206.3 | $182.8 |
Average annual rate of return (after tax) | 19.9% | 20.4% | 19.7% |
Note 15 – Operations by Line of Business
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, 2006:
| Questar | Interco. | Questar |
| Gas | Energy | Questar | Questar | Corp. | |||||||||
| Consol. | Trans. | E&P | Wexpro | Managmt. | Trading | Pipeline | Gas | and Other | |||||||||
| (in millions) | |||||||||||||||||
2006 |
| |||||||||||||||||
Revenues |
|
|
|
|
|
|
|
|
| |||||||||
From unaffiliated customers | $2,835.6 |
| $815.7 | $19.7 | $168.0 | $656.0 | $101.7 | $1,059.1 | $15.4 | |||||||||
From affiliated companies |
| ($951.0) |
| 150.5 | 15.9 | 697.8 | 79.7 | 5.5 | 1.6 | |||||||||
Total Revenues | 2,835.6 | (951.0) | 815.7 | 170.2 | 183.9 | 1,353.8 | 181.4 | 1,064.6 | 17.0 | |||||||||
Operating expenses |
|
|
|
|
|
|
|
|
| |||||||||
Cost of natural gas and other products sold | 1,223.6 | (941.6) | 2.8 |
|
| 1,335.8 |
| 821.8 | 4.8 | |||||||||
Operating and maintenance | 286.8 | (2.2) | 73.6 | 14.7 | 92.4 | 0.8 | 33.1 | 73.2 | 1.2 | |||||||||
General and administrative | 135.0 | (1.7) | 42.4 | 11.3 | 12.2 | 4.0 | 19.3 | 41.9 | 5.6 | |||||||||
Production and other taxes | 108.7 |
| 58.3 | 30.3 | 0.6 | 0.2 | 6.6 | 11.6 | 1.1 | |||||||||
Depreciation, depletion and |
|
|
|
|
|
|
|
|
| |||||||||
amortization | 308.4 |
| 185.7 | 33.1 | 15.3 | 0.9 | 31.5 | 40.9 | 1.0 | |||||||||
Other operating expenses | 42.0 | (5.5) | 42.0 | 5.5 |
|
|
|
|
| |||||||||
Total operating expenses | 2,104.5 | (951.0) | 404.8 | 94.9 | 120.5 | 1,341.7 | 90.5 | 989.4 | 13.7 | |||||||||
Net gain (loss) on asset sales | 25.3 |
| 24.3 | (0.1) | 1.0 |
|
| (0.3) | 0.4 | |||||||||
Operating income | 756.4 |
| 435.2 | 75.2 | 64.4 | 12.1 | 90.9 | 74.9 | 3.7 | |||||||||
Interest and other income (expense) | 9.3 | (39.0) | (3.7) | 1.3 |
| 31.6 | 0.8 | 6.6 | 11.7 | |||||||||
Income from unconsol. affiliates | 7.5 |
| 0.4 |
| 7.1 |
|
|
|
| |||||||||
Interest expense | (73.6) | 39.0 | (27.1) | (0.5) | (4.7) | (28.6) | (23.7) | (22.6) | (5.4) | |||||||||
Income tax expense | (255.5) |
| (150.9) | (26.0) | (24.2) | (5.5) | (25.6) | (21.9) | (1.4) | |||||||||
Net income | $444.1 |
| $253.9 | $50.0 | $42.6 | $9.6 | $42.4 | $37.0 | $8.6 | |||||||||
Identifiable assets | $5,064.7 |
| 2,169.6 | 375.7 | 374.9 | 233.5 | 818.0 | 1,068.7 | 24.3 | |||||||||
Goodwill | $70.7 |
| 60.9 |
|
|
| 4.2 | 5.6 |
| |||||||||
Investment in unconsol. affiliates | 37.5 |
|
|
| 37.3 | 0.2 |
|
|
| |||||||||
Capital expenditures | 916.1 |
| 586.3 | 82.7 | 82.2 | 1.5 | 76.1 | 86.7 | 0.6 | |||||||||
2005 |
|
|
|
|
|
|
|
|
| |||||||||
Revenues |
|
|
|
|
|
|
|
|
| |||||||||
From unaffiliated customers | $2,724.9 |
| $ 620.6 | $ 21.7 | $ 141.5 | $ 884.9 | $ 82.6 | $ 956.4 | $ 17.2 | |||||||||
From affiliated companies |
| ($869.8) |
| 132.3 | 13.7 | 632.4 | 83.4 | 6.1 | 1.9 | |||||||||
Total Revenues | 2,724.9 | (869.8) | 620.6 | 154.0 | 155.2 | 1,517.3 | 166.0 | 962.5 | 19.1 | |||||||||
Operating expenses |
|
|
|
|
|
|
|
|
| |||||||||
QUESTAR 2006 FORM 10-K 77
Cost of natural gas and other products sold | 1,371.3 | (860.2) | 4.2 |
|
| 1,501.7 |
| 720.2 | 5.4 | |||||||||
Operating and maintenance | 262.8 | (1.6) | 61.8 | 11.2 | 85.2 | 1.0 | 30.7 | 73.7 | 0.8 | |||||||||
General and administrative | 123.1 | (1.9) | 33.9 | 10.0 | 7.5 | 3.9 | 25.2 | 39.3 | 5.2 | |||||||||
Production and other taxes | 120.2 |
| 68.7 | 32.6 | 0.7 | 0.2 | 5.8 | 11.0 | 1.2 | |||||||||
Depreciation, depletion and |
|
|
|
|
|
|
|
|
| |||||||||
amortization | 250.3 |
| 134.7 | 26.9 | 11.3 | 0.9 | 29.4 | 45.8 | 1.3 | |||||||||
Other operating expenses | 35.4 | (6.1) | 18.8 | 6.7 |
|
| 16.0 |
|
| |||||||||
Total operating expenses | 2,163.1 | (869.8) | 322.1 | 87.4 | 104.7 | 1,507.7 | 107.1 | 890.0 | 13.9 | |||||||||
Net gain (loss) on asset sales | 4.7 |
| 1.1 | (0.2) |
|
| 0.4 |
| 3.4 | |||||||||
Operating income | 566.5 |
| 299.6 | 66.4 | 50.5 | 9.6 | 59.3 | 72.5 | 8.6 | |||||||||
Interest and other income | 9.0 | (34.3) | 0.6 | 0.9 | 0.3 | 30.0 | 1.0 | 5.0 | 5.5 | |||||||||
Income from unconsol. affiliates | 7.5 |
| 0.3 |
| 7.2 |
|
|
|
| |||||||||
Interest expense | (69.4) | 34.3 | (23.7) | (0.1) | (3.1) | (30.2) | (22.3) | (20.2) | (4.1) | |||||||||
Income tax expense | (187.9) |
| (104.0) | (23.5) | (19.2) | (3.4) | (13.6) | (21.3) | (2.9) | |||||||||
Net income | $ 325.7 |
| $ 172.8 | $ 43.7 | $ 35.7 | $ 6.0 | $ 24.4 | $ 36.0 | $ 7.1 | |||||||||
Identifiable assets | $4,374.3 |
| $1,656.4 | $ 305.9 | $ 301.2 | $ 237.7 | $ 757.6 | $1,090.4 | $ 25.1 | |||||||||
Goodwill | 71.3 |
| 61.5 |
|
|
| 4.2 | 5.6 |
| |||||||||
Investment in unconsol. affiliates | 30.7 |
| 0.1 |
| 30.3 | 0.3 |
|
|
| |||||||||
Capital expenditures | 712.7 |
| 424.2 | 57.8 | 93.3 | 0.9 | 67.4 | 67.9 | 1.2 | |||||||||
2004 |
|
|
|
|
|
|
|
|
| |||||||||
Revenues |
|
|
|
|
|
|
|
|
| |||||||||
From unaffiliated customers | $1,901.4 |
| $ 448.7 | $ 17.4 | $ 87.3 | $ 500.5 | $ 67.9 | $ 759.5 | $ 20.1 | |||||||||
From affiliated companies |
| ($662.4) | 0.1 | 115.6 | 11.6 | 426.3 | 88.6 | 4.7 | 15.5 | |||||||||
Total Revenues | 1,901.4 | (662.4) | 448.8 | 133.0 | 98.9 | 926.8 | 156.5 | 764.2 | 35.6 | |||||||||
Operating expenses |
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Cost of natural gas and other products sold | 821.8 | (642.0) | 2.2 |
| 0.9 | 918.7 |
| 536.1 | 5.9 | |||||||||
Operating and maintenance | 213.6 | (6.7) | 51.9 | 11.1 | 49.9 | 0.9 | 26.3 | 69.2 | 11.0 | |||||||||
General and administrative | 114.2 | (9.0) | 30.6 | 9.4 | 6.8 | 2.9 | 29.4 | 35.6 | 8.5 | |||||||||
Production and other taxes | 90.9 |
| 47.1 | 24.8 | 1.1 | 0.2 | 6.6 | 9.8 | 1.3 | |||||||||
Depreciation, depletion and |
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amortization | 216.2 |
| 107.5 | 25.1 | 9.4 | 0.7 | 28.2 | 42.0 | 3.3 | |||||||||
Other operating expenses | 29.1 | (4.7) | 22.2 | 7.5 |
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| 4.1 |
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Total operating expenses | 1,485.8 | (662.4) | 261.5 | 77.9 | 68.1 | 923.4 | 90.5 | 696.8 | 30.0 | |||||||||
Net gain (loss) on asset sales | 0.3 |
| 0.1 |
| 0.2 |
|
| (0.2) | 0.2 | |||||||||
Operating income | 415.9 |
| 187.4 | 55.1 | 31.0 | 3.4 | 66.0 | 67.2 | 5.8 | |||||||||
Interest and other income | 6.3 | (28.3) | 0.9 | 0.5 | 0.1 | 25.8 | 0.2 | 3.8 | 3.3 | |||||||||
Income from unconsol. affiliates | 5.1 |
| 0.2 |
| 4.9 |
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| |||||||||
Interest expense | (68.4) | 28.3 | (21.7) | (0.9) | (2.8) | (27.4) | (22.2) | (19.7) | (2.0) | |||||||||
Income tax expense | (129.6) |
| (58.6) | (19.4) | (12.2) | (0.9) | (16.4) | (19.8) | (2.3) | |||||||||
Net income | $ 229.3 |
| $ 108.2 | $ 35.3 | $ 21.0 | $ 0.9 | $ 27.6 | $ 31.5 | $ 4.8 | |||||||||
Identifiable assets | $3,684.9 |
| $1,244.3 | $ 272.1 | $ 204.6 | $ 172.1 | $ 745.6 | $ 989.7 | $ 56.5 | |||||||||
QUESTAR 2006 FORM 10-K 78
Goodwill | 71.3 |
| 61.5 |
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| 4.2 | 5.6 |
|
Investment in unconsol. affiliates | 33.2 |
| 0.1 |
| 32.6 | 0.5 |
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Capital expenditures | 446.5 |
| 263.9 | 38.9 | 26.3 | 7.7 | 30.1 | 77.0 | 2.6 |
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Note 16 – Quarterly Financial and Stock-Price Information (Unaudited)
Following is a summary of quarterly financial and stock-price information: | |||||
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| First | Second | Third | Fourth |
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| Quarter | Quarter | Quarter | Quarter | Year |
| (in millions, except per-share amounts) | ||||
2006 |
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|
|
Revenues | $911.4 | $596.2 | $555.1 | $772.9 | $2,835.6 |
Operating income | 230.8 | 166.1 | 167.7 | 191.8 | 756.4 |
Net income | 137.2 | 90.3 | 95.1 | 121.5 | 444.1 |
Basic earnings per common share | 1.61 | 1.06 | 1.11 | 1.42 | 5.20 |
Diluted earnings per common share | 1.57 | 1.03 | 1.08 | 1.39 | 5.07 |
Dividends per common share | 0.225 | 0.235 | 0.235 | 0.235 | 0.930 |
Market price per common share |
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|
High | $85.70 | $82.08 | $91.02 | $89.56 | $91.02 |
Low | 67.37 | 67.48 | 75.68 | 77.48 | 67.37 |
Close | 70.05 | 80.49 | 81.77 | 83.05 | 83.05 |
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2005 |
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Revenues | $680.3 | $520.2 | $583.0 | $941.4 | $2,724.9 |
Impairment of California segment of Southern Trails |
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|
| 16.0 | 16.0 |
Operating income | 163.8 | 112.2 | 115.5 | 175.0 | 566.5 |
Net income | 95.2 | 60.7 | 65.8 | 104.0 | 325.7 |
Basic earnings per common share | $1.13 | $0.71 | $0.78 | $1.22 | $3.84 |
Diluted earnings per common share | 1.10 | 0.70 | 0.75 | 1.19 | 3.74 |
Dividends per common share | $0.215 | $0.225 | $0.225 | $0.225 | $0.89 |
Market price per common share |
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|
High | $62.75 | $67.19 | $88.78 | $89.60 | $89.60 |
Low | 46.73 | 54.49 | 65.95 | 70.85 | 46.73 |
Close | $59.25 | $65.90 | $88.12 | $75.70 | $75.70 |
Note 17 – Supplemental Gas and Oil Information (Unaudited)
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 2006 FORM 10-K 79
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:
| December 31, | |
| 2006 | 2005 |
| (in millions) | |
Proved properties | $2,646.6 | $2,047.9 |
Unproved properties | 42.7 | 41.5 |
Support equipment and facilities | 18.5 | 18.4 |
| 2,707.8 | 2,107.8 |
Accumulated depreciation, depletion and |
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|
amortization | (901.5) | (731.1) |
| $1,806.3 | $1,376.7 |
Costs Incurred
The costs incurred in gas and oil exploration and development activities are displayed in the table below. The development costs include expenditures to develop a portion of the proved undeveloped reserves reported at the end of the prior year. These costs were $109.2 million in 2006, $116.7 million in 2005 and $80.1 million in 2004.
| Year Ended December 31, | ||
| 2006 | 2005 | 2004 |
| (in millions) | ||
Property acquisition |
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|
Unproved | $ 22.5 | $13.7 | $ 13.3 |
Proved | 20.6 | 3.4 | 1.2 |
Exploration (capitalized and expensed) | 34.5 | 49.4 | 25.1 |
Development | 581.2 | 381.7 | 239.7 |
| $658.8 | $448.2 | $279.3 |
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.
| Year Ended December 31, | ||
| 2006 | 2005 | 2004 |
| (in millions) | ||
Revenues | $815.7 | $620.6 | $448.8 |
Production expenses | 131.9 | 130.5 | 99.0 |
Exploration expenses | 34.4 | 11.1 | 9.2 |
Depreciation, depletion and amortization | 185.7 | 134.7 | 107.5 |
Abandonment and impairment | 7.6 | 7.7 | 13.0 |
Total expenses | 359.6 | 284.0 | 228.7 |
Revenues less expenses | 456.1 | 336.6 | 220.1 |
Income taxes | (170.1) | (126.6) | (77.5) |
Results of operation before corporate overhead and interest expenses | $286.0 | $210.0 | $142.6 |
QUESTAR 2006 FORM 10-K 80
Estimated Quantities of Proved Gas and Oil Reserves
Estimates of the Company’s proved gas and oil reserves have been prepared by Ryder Scott Company, H. J. Gruy and Associates, Inc. and Netherland, Sewell & Associates, Inc., independent reservoir engineers, in accordance with the SEC’s Regulation S-X and SFAS 69 “Disclosures about Oil and Gas Producing Activities.” The table below summarizes the changes in the estimated net quantities of proved natural gas, oil and NGL reserves for each of the three years in the period ended December 31, 2006. The quantities reported are based on existing economic and operating conditions at the time the estimates were made. All gas and oil reserves reported are located in the United States. The Company does not have any long-term supply contracts with foreign governments or reserves of equity investees.
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|
| Natural Gas |
| Natural Gas | Oil and NGL | Equivalents |
| (Bcf) | (MMbbl) | (Bcfe)(a) |
Proved Reserves |
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|
|
Balance at January 1, 2004 | 999.2 | 26.6 | 1,158.7 |
Revisions - |
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|
Previous estimates | (16.5) | (0.8) | (21.1) |
Pinedale increased-density(b) | 302.6 | 2.4 | 316.9 |
Extensions and discoveries | 74.2 | 1.3 | 82.2 |
Purchase of reserves in place | 0.8 |
| 0.8 |
Production | (89.8) | (2.3) | (103.5) |
Balance at December 31, 2004 | 1,270.5 | 27.2 | 1,434.0 |
Revisions - |
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|
Previous estimates | 11.9 | (0.7) | 7.9 |
Pinedale increased-density(b) | 31.5 | 0.3 | 33.0 |
Extensions and discoveries | 110.9 | 1.4 | 119.3 |
Purchase of reserves in place | 0.3 | 0.1 | 0.7 |
Sale of reserves in place | (0.3) |
| (0.3) |
Production | (100.0) | (2.4) | (114.2) |
Balance at December 31, 2005 | 1,324.8 | 25.9 | 1,480.4 |
Revisions - |
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|
Previous estimates | (38.9) | 2.6 | (23.8) |
Pinedale increased-density(b) | 163.0 | 1.2 | 170.4 |
Extensions and discoveries | 119.1 | 1.2 | 126.6 |
Purchase of reserves in place | 9.8 | 0.1 | 10.2 |
Sale of reserves in place | (2.7) |
| (2.8) |
Production | (113.9) | (2.6) | (129.6) |
Balance at December 31, 2006 | 1,461.2 | 28.4 | 1,631.4 |
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|
Proved-Developed Reserves |
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|
Balance at January 1, 2004 | 612.2 | 20.5 | 735.2 |
Balance at December 31, 2004 | 680.6 | 21.3 | 808.3 |
Balance at December 31, 2005 | 792.0 | 21.4 | 920.5 |
Balance at December 31, 2006 | 852.0 | 23.1 | 990.7 |
(a) Natural Gas Equivalents – oil 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.
QUESTAR 2006 FORM 10-K 81
(b) 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 an improved understanding of Lance Pool reservoir characteristics. The continued analysis of new data has led to progressive increases in estimates of original gas-in-place in the Lance Pool reservoirs at Pinedale and to a better understanding of the appropriate well density to maximize the economic recovery of the in-place volumes.
The Wyoming Oil and Gas Conservation Commission (WOGCC) has approved 10-acre-density drilling for Lance Pool wells on about 12,700 of the Company’s 18,208 acre (gross) Pinedale leasehold. The area approved for increased density corresponds to the estimated productive limits of the Company’s core acreage in the field. The Company currently believes that up to 932 wells will be required to fully develop the Lance Pool on 10-acre density. The Company will continue to disclose future revisions to proved reserves associated with Pinedale increased-density drilling separately.
Standardized Measure of Future Net Cash Flows Relating to Proved Reserves
Future net cash flows were calculated at December 31 using year-end prices and known contract-price changes. The year-end prices do not include any impact of hedging activities. The average year-end price per Mcf of proved natural gas reserves was $4.47 in 2006, $7.80 in 2005 and $5.50 in 2004. The average year-end price per barrel of proved oil and NGL reserves combined was $51.49 in 2006, $56.47 in 2005 and $40.60 in 2004. 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 $219.2 million in 2007, $217.9 million in 2008 and $159.7 million in 2009. At the end of this three-year period the Company expects to have evaluated about 53% 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.
| Year Ended December 31, | |||
| 2006 | 2005 | 2004 | |
| (in millions) | |||
Future cash inflows | $ 7,985.1 | $11,791.1 | $ 8,090.0 | |
Future production costs | (2,133.0) | (2,465.8) | (1,827.4) | |
Future development costs | (1,026.9) | (725.7) | (663.1) | |
Future income tax expenses | (1,396.2) | (2,930.3) | (1,854.5) | |
Future net cash flows | 3,429.0 | 5,669.3 | 3,745.0 | |
10% annual discount to reflect |
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| |
timing of net cash flows | (1,861.2) | (2,962.2) | (1,984.5) | |
Standardized measure of discounted |
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| |
future net cash flows | $ 1,567.8 | $ 2,707.1 | $ 1,760.5 | |
The principal sources of change in the standardized measure of discounted future net cash flows were:
| Year Ended December 31, | ||
| 2006 | 2005 | 2004 |
| (in millions) | ||
Beginning balance | $2,707.1 | $1,760.5 | $1,530.0 |
Sales of gas and oil produced, net |
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|
of production costs | (683.8) | (490.1) | (349.8) |
QUESTAR 2006 FORM 10-K 82
Net changes in prices and |
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|
production costs | (1,994.3) | 1,183.6 | (199.5) |
Extensions and discoveries, less |
|
|
|
related costs | 233.1 | 330.4 | 150.7 |
Revisions of quantity estimates | 269.9 | 113.3 | 542.3 |
Net purchases and sales of reserves in place | (7.5) | 0.5 | (0.2) |
Cost to develop proved undeveloped reserves | 109.2 | 116.7 | 80.1 |
Change in future development | (259.6) | (120.3) | (203.6) |
Accretion of discount | 411.0 | 176.1 | 153.0 |
Net change in income taxes | 760.8 | (440.3) | (29.0) |
Other | 21.9 | 76.7 | 86.5 |
Net change | (1,139.3) | 946.6 | 230.5 |
Ending balance | $1,567.8 | $2,707.1 | $1,760.5 |
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 regulated 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
Capitalized costs for cost-of-service gas and oil properties net of the related accumulated depreciation and amortization are shown below.
| December 31, | ||
| 2006 | 2005 | |
| (in millions) | ||
Wexpro | $353.2 | $283.9 | |
Questar Gas | 13.2 | 14.4 | |
| $366.4 | $298.3 | |
Costs Incurred
Costs incurred by Wexpro for cost-of-service gas and oil-producing activities were $100.3 million in 2006, $57.0 million in 2005 and $43.6 million in 2004.
Results of Operation
Following are the results of operation of cost-of-service gas and oil-development activities, before corporate overhead and interest expenses:
| Year Ended December 31, | |||
| 2006 | 2005 | 2004 | |
| (in millions) | |||
Revenues |
|
|
| |
From unaffiliated companies | $ 19.7 | $ 21.7 | $ 17.3 | |
From affiliates – Note A | 150.5 | 132.3 | 115.6 | |
Total revenues | 170.2 | 154.0 | 132.9 | |
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| |
Production expenses | 50.5 | 50.0 | 40.6 | |
QUESTAR 2006 FORM 10-K 83
Depreciation and amortization | 33.1 | 26.9 | 25.0 | |
Abandonment and impairment |
| 0.2 | 2.8 | |
Exploration |
| 0.4 |
| |
Total expenses | 83.6 | 77.5 | 68.4 | |
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| |
Revenues less expenses | 86.6 | 76.5 | 64.5 | |
Income taxes | (29.6) | (26.8) | (23.2) | |
Results of operation before corporate |
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| |
overhead and interest expense | $ 57.0 | $ 49.7 | $ 41.3 | |
Note A – Primarily represents revenues received from Questar Gas pursuant to the Wexpro Agreement.
Estimated Quantities of Cost-of-Service Proved Gas and Oil Reserves
Since the gas reserves operated by Wexpro are delivered to Questar Gas at cost-of-service, SEC guidelines with respect to standard economic assumptions are not applicable. The SEC anticipated this potential difficulty 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. The following estimates were made by the Wexpro’s reservoir engineers:
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| Natural Gas | |
| Natural Gas | Oil and NGL | Equivalents | |
| (Bcf) | (MMbbl) | (Bcfe) | |
Proved Reserves |
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|
| |
Balance at January 1, 2004 | 434.4 | 3.6 | 455.9 | |
Revisions - |
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| |
Previous estimates | 4.5 |
| 4.7 | |
Pinedale increased-density(a) | 112.7 | 0.9 | 118.3 | |
Extensions and discoveries | 18.3 | 0.1 | 18.7 | |
Production | (38.8) | (0.4) | (41.3) | |
Balance at December 31, 2004 | 531.1 | 4.2 | 556.3 | |
Revisions- |
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| |
Previous estimates | (30.8) | (0.1) | (32.2) | |
Pinedale increased-density | 7.8 |
| 8.1 | |
Extensions and discoveries | 29.2 | 0.2 | 30.7 | |
Production | (40.0) | (0.4) | (42.4) | |
Balance at December 31, 2005 | 497.3 | 3.9 | 520.5 | |
Revisions- |
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| |
Previous estimates | 22.3 | (0.1) | 21.5 | |
Pinedale increased-density | 100.0 | 0.8 | 104.6 | |
Extensions and discoveries | 39.8 | 0.2 | 41.3 | |
Production | (38.8) | (0.4) | (40.9) | |
Balance at December 31, 2006 | 620.6 | 4.4 | 647.0 | |
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Proved-Developed Reserves |
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| |
Balance at January 1, 2004 | 406.1 | 3.3 | 426.1 | |
Balance at December 31, 2004 | 409.2 | 3.2 | 428.4 | |
QUESTAR 2006 FORM 10-K 84
Balance at December 31, 2005 | 406.6 | 3.1 | 425.2 | |
Balance at December 31, 2006 | 440.6 | 2.9 | 458.2 | |
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(a) The area approved by the WOGCC for 10-acre-density drilling of Lance Pool wells corresponds to the estimated productive limits of the Company’s core acreage in the field. The Company will continue to disclose future revisions to proved reserves associated with Pinedale increased-density drilling separately.
Allowance for bad debts | $7.7 | $6.1 | ($6.0) | $7.8 |
Allowance for notes receivable | 3.2 |
| (0.1) | 3.1 |
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Year Ended December 31, 2005 |
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Allowance for bad debts | 6.1 | 8.8 | (7.2) | 7.7 |
Allowance for notes receivable |
| 3.2 |
| 3.2 |
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Year Ended December 31, 2004 |
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Allowance for bad debts | 6.7 | 5.5 | (6.1) | 6.1 |
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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.
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 (the Exchange Act)) as of the end of the period covered by the report (the Evaluation Date). Based on such evaluation, such officers have concluded that, as of the Evaluation Date, 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.
QUESTAR 2006 FORM 10-K 85
Changes in Internal Controls.
Since the Evaluation Date, there have not been any changes in the Company’s internal controls or other factors during the most recent fiscal quarter that could materially affect such controls.
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, 2006. 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, 2006, is effective based on those criteria.
Management’s assessment of the effectiveness of internal control over financial reporting as of December 31, 2006, has been audited by Ernst & Young LLP, an independent registered public accounting firm, as stated in their report which is included on the next page.
Report of Independent Registered Public Accounting Firm
The Board of Directors and Shareholders
Questar Corporation
We have audited management’s assessment, included under “Managements Assessment of Internal Control Over Financial Reporting”, that Questar Corporation maintained effective internal control over financial reporting as of December 31, 2006, 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. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of 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, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, 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, management’s assessment that Questar Corporation maintained effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on the COSO criteria. Also, in our opinion, Questar Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on the COSO criteria.
QUESTAR 2006 FORM 10-K 86
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, 2006 and 2005, 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, 2006 of Questar Corporation and our report dated February 26, 2007 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Salt Lake City, Utah
February 26, 2007
ITEM 9B. OTHER INFORMATION.
There is no information to report in this section.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
The information requested in this item 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 2006 annual meeting will be filed with the Securities and Exchange Commission.
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 2007 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 this item 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 this item for certain beneficial owners is presented in Questar’s definitive Proxy Statement for the Company’s 2007 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 2007 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, 2006, is presented in the definitive Proxy Statement for the Company’s 2007 annual meeting 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 this item for related transactions involving the Company’s directors and executive officers is presented in the definitive Proxy Statement for Questar’s 2007 annual meeting under the sections entitled “Information Concerning the Board of Directors” and Certain Relationships – “Executive Officers.”
QUESTAR 2006 FORM 10-K 87
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES.
The information requested in this item for principal accountant fees and services is presented in the definitive Proxy Statement for Questar’s 2007 annual meeting 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).
Exhibit No.
Description
2.*
Plan and Agreement of Merger dated as of December 16, 1986, by and among the Company, Questar Systems Corporation, and Universal Resources Corporation. (Exhibit No. 2. to Current Report on Form 8-K dated December 16, 1986.)
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 October 24, 2005. (Exhibit No. 3.2. to Form 10-Q Report for Quarter ended September 30, 2005.)
4.1.*
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 January 1, 2005. (Exhibit No. 10.2. to Form 10-K Annual Report for 2004.)
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 March 1, 2001. (Exhibit No. 10.4. to Form 10-K Annual Report for 2000.)
10.5. *1
Questar Corporation Executive Severance Compensation Plan, as amended and restated effective February 10, 2004. (Exhibit No. 10.5. to Form 10-K Annual Report for 2003.)
10.6.*1
Questar Corporation Deferred Compensation Plan for Directors, as amended and restated effective October 26, 2000. (Exhibit No. 10.6. to Form 10-K Annual Report for 2000.)
10.7.*1
Questar Corporation Supplemental Executive Retirement Plan, as amended and restated effective January 1, 2005. (Exhibit No. 10.7. to Form 10-K Annual Report for 2004.)
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.)
QUESTAR 2006 FORM 10-K 88
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, 2005. (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, 2005. (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, 2005. (Exhibit No. 10.13. to Form 10-K Annual Report for 2004.)
10.14.*1
Questar Corporation Long-Term Cash Incentive Plan effective January 1, 2004. (Exhibit No. 10.14. to Form 10-K Annual Report in 2003.)
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 effective January 1, 2005. (Exhibit No. 10.18. to Form 10-K Annual Report for 2004.)
10.18.*1
Form of Restricted Stock Agreement dated February 8, 2005, for shares granted to officers and key employees. (Exhibit No. 10.1 to Current Report on Form 8-K dated February 8, 2005.)
10.19.*1
Form of Restricted Stock Agreement dated February 8, 2005, for shares granted to non-employee directors. (Exhibit No. 10.2 to Current Report on Form 8-K dated February 8, 2005.)
10.20.*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.)
10.21.*1
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.)
10.22.*1
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.)
10.23.*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.)
10.24.*1
Questar Corporation Deferred Compensation Wrap Plan, as adopted on October 24, 2006. (Exhibit No. 10.1 to Form 10-Q Report for Quarter Ended September 30, 2006.)
10.25.*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.)
10.26.*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.)
10.27.*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.)
QUESTAR 2006 FORM 10-K 89
10.28.*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.)
10.29*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.)
10.30*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.)
10.31*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.)
10.32*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.)
10.33*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.)
12.
Ratio of earnings to fixed charges.
14.*
Business Ethics and Compliance Policy. (Exhibit No. 14. to Form 10-K Annual Report for 2005.)
21.
Subsidiary Information.
23.1.
Consent of Independent Registered Public Accounting Firm.
23.2.
Engineer’s Consent.
23.3.
Consent of Independent Petroleum Engineers and Geologists.
23.4.
Consent of H. J. Gruy and Associates, Inc.
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 S. E. Parks, Questar’s Senior Vice President and Chief Financial Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.
Certification signed by Keith O. Rattie and S. E. Parks, Questar’s Chairman, President and Chief Executive Officer and Senior Vice President and Chief Financial Officer, respectively, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*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 2006 FORM 10-K 90
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 28th day of February, 2007.
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 Chief Executive
Keith O. Rattie
Officer (Principal Executive Officer)
/s/ S. E. Parks
Senior Vice President and Chief
S. E. Parks
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 28, 2007
*/s/ Keith O. Rattie
Keith O. Rattie, Attorney in Fact
EXHIBIT INDEX
Exhibit No.
Description
2.*
Plan and Agreement of Merger dated as of December 16, 1986, by and among the Company, Questar Systems Corporation, and Universal Resources Corporation. (Exhibit No. 2. to Current Report on Form 8-K dated December 16, 1986.)
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 October 24, 2005. (Exhibit No. 3.2. to Form 10-Q Report for Quarter ended September 30, 2005.)
QUESTAR 2006 FORM 10-K 91
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 January 1, 2005. (Exhibit No. 10.2. to Form 10-K Annual Report for 2004.)
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 March 1, 2001. (Exhibit No. 10.4. to Form 10-K Annual Report for 2000.)
10.5. *1
Questar Corporation Executive Severance Compensation Plan, as amended and restated effective February 10, 2004. (Exhibit No. 10.5. to Form 10-K Annual Report for 2003.)
10.6.*1
Questar Corporation Deferred Compensation Plan for Directors, as amended and restated effective October 26, 2000. (Exhibit No. 10.6. to Form 10-K Annual Report for 2000.)
10.7.*1
Questar Corporation Supplemental Executive Retirement Plan, as amended and restated effective January 1, 2005. (Exhibit No. 10.7. to Form 10-K Annual Report for 2004.)
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, 2005. (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, 2005. (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, 2005. (Exhibit No. 10.13. to Form 10-K Annual Report for 2004.)
10.14.*1
Questar Corporation Long-Term Cash Incentive Plan effective January 1, 2004. (Exhibit No. 10.14. to Form 10-K Annual Report in 2003.)
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 effective January 1, 2005. (Exhibit No. 10.18. to Form 10-K Annual Report for 2004.)
QUESTAR 2006 FORM 10-K 92
10.18.*1
Form of Restricted Stock Agreement dated February 8, 2005, for shares granted to officers and key employees. (Exhibit No. 10.1 to Current Report on Form 8-K dated February 8, 2005.)
10.19.*1
Form of Restricted Stock Agreement dated February 8, 2005, for shares granted to non-employee directors. (Exhibit No. 10.2 to Current Report on Form 8-K dated February 8, 2005.)
10.20.*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.)
10.21.*1
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.)
10.22.*1
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.)
10.23.*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.)
10.24.*1
Questar Corporation Deferred Compensation Wrap Plan, as adopted on October 24, 2006. (Exhibit No. 10.1 to Form 10-Q Report for Quarter Ended September 30, 2006.)
10.25.*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.)
10.26.*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.)
10.27.*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.)
10.28.*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.)
10.29*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.)
10.30*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.)
10.31*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.)
10.32*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.)
10.33*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.)
12.
Ratio of earnings to fixed charges.
14.*
Business Ethics and Compliance Policy (Exhibit No. 14. to Form 10-K Annual Report for 2005.)
21.
Subsidiary Information.
23.1.
Consent of Independent Registered Public Accounting Firm.
QUESTAR 2006 FORM 10-K 93
23.2.
Engineer’s Consent.
23.3.
Consent of Independent Petroleum Engineers and Geologists.
23.4.
Consent of H. J. Gruy and Associates, Inc.
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 S. E. Parks, Questar’s Senior Vice President and Chief Financial Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.
Certification signed by Keith O. Rattie and S. E. Parks, Questar’s Chairman, President and Chief Executive Officer and Senior Vice President and Chief Financial Officer, respectively, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*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.
Exhibit 12.
Questar Corporation
Ratio of Earnings to Fixed Charges
| Year Ended December 31, | |||
| 2006 | 2005 | 2004 | |
| (dollars in millions) | |||
Earnings |
|
|
| |
Income before income taxes | $699.6 | $513.6 | $358.9 | |
Less company’s share of earnings of |
|
|
| |
equity investees | (7.5) | (7.5) | (5.1) | |
Plus distributions from equity investees | 7.1 | 10.0 | 8.3 | |
Plus minority interest in income |
|
| 0.3 | |
Plus interest expense | 73.6 | 69.4 | 68.4 | |
Plus allowance for borrowed funds used |
|
|
| |
during construction | 0.8 | 1.0 | 0.2 | |
Plus interest portion of rental expense | 2.7 | 2.5 | 2.6 | |
| $776.3 | $589.0 | $433.6 | |
|
|
|
| |
Fixed Charges |
|
|
| |
Interest expense | $ 73.6 | $ 69.4 | $ 68.4 | |
Plus allowance for borrowed funds used |
|
|
| |
QUESTAR 2006 FORM 10-K 94
during construction | 0.8 | 1.0 | 0.2 |
Plus interest portion of rental expense | 2.7 | 2.5 | 2.6 |
| $ 77.1 | $ 72.9 | $ 71.2 |
|
|
|
|
Ratio of Earnings to Fixed Charges | 10.1 | 8.1 | 6.1 |
For purposes of this presentation, earnings represent income before income taxes adjusted
for fixed charges, earnings and distributions of equity investees. Income before income taxes
includes Questar’s share of pretax earnings of equity investees. Fixed charges consist of
total interest charges (expensed and capitalized), amortization of debt issuance costs,
and the interest portion of rental expense estimated investees.
Exhibit 21.
SUBSIDIARY INFORMATION
Registrant Questar Corporation has the following subsidiaries: Questar Market Resources Company, Questar Pipeline Company and Questar Gas Company. Each of these companies is a Utah corporation.
Questar Market Resources has the following subsidiaries: Wexpro Company, Questar Exploration and Production Company, Questar Energy Trading Company, Questar Gas Management Company and Questar Employee Services, Inc. Questar Exploration and Production Company is a Texas corporation. The other listed companies are incorporated in Utah.
Questar Exploration and Production Company has two wholly owned subsidiaries: Questar Uinta Basin, Inc. and Questar URC Company, both of which are Delaware corporations. Questar Exploration and Production Company also does business under the names Universal Resources Corporation, Questar Energy Company and URC Corporation.
Questar Energy Trading Company has two subsidiaries: URC Canyon Creek Compression Company and Questar Oil and Gas Company. Both are Utah corporations.
Questar Pipeline Company has four subsidiaries: Questar Southern Trails Company, Questar Transportation Services Company, Questar Overthrust Pipeline Company and Questar InfoComm, Inc., all four are Utah corporations. Questar Overthrust Pipeline Company does business as Overthrust Pipeline Company.
Questar InfoComm, Inc. has four subsidiaries: Questar Energy Services, Inc., Questar Project Employee Company, Questar Applied Technology Services, Inc. and Salt Lake Data Center Company. All four are Utah corporations.
Exhibit 23.1.
Consent of Independent Registered Public Accounting Firm
We consent to the inclusion in this Annual Report (Form 10-K) of Questar Corporation of our report dated February 26, 2007, with respect to the consolidated financial statements and schedule of Questar Corporation, included in the 2006 Annual Report to Shareholders of Questar Corporation.
Our audits also included the financial statement schedule of Questar Corporation listed in Item 8. This schedule is the responsibility of Questar Corporation’s management. Our responsibility is to express an opinion based on our audits. In our
QUESTAR 2006 FORM 10-K 95
opinion, as to which the date is February 26, 2007, the financial statement schedule referred to above, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
We consent to the incorporation by reference in the following Registration Statements:
1. Registration Statement (Form S-8 No. 33-15149) pertaining to the Questar Corporation Stock Option Plan for Directors,
2. Registration Statement (Post-effective Amendment No. 3 to Form S-8 No. 33-4436) pertaining to the Questar Corporation Employee Savings and Stock Purchase Plan,
3. Registration Statement (Form S-8 No. 33-40800) pertaining to the Questar Corporation Long-Term Stock Incentive Plan,
4. Registration Statement (Form S-8 No. 33-40801) pertaining to the Questar Corporation Stock Option Plan for Directors (additional shares),
5. Registration Statement (Form S-8 No. 33-48169) pertaining to the Questar Corporation Employee Stock Purchase Plan,
6. Registration Statement (Form S-8 No. 333-04951) pertaining to the Questar Corporation Stock Option Plan for Directors (additional shares),
7. Registration Statement (Form S-8 No. 333-04913) pertaining to the Questar Corporation Directors' Stock Plan,
8. Registration Statement (Form S-8 No. 33-48168) pertaining to the Questar Corporation Dividend Reinvestment and Stock Purchase Plan,
9. Registration Statement (Form S-8 No. 333-67658) pertaining to the Questar Corporation Long-Term Stock Incentive Plan, and
10. Registration Statement (Form S-8 No. 333-89486) pertaining to the Questar Corporation Employee Investment Plan;
of our report dated February 26, 2007, with respect to the consolidated financial statements and schedule of Questar Corporation, our report dated February 26, 2007, with respect to Questar Corporation management's assessment of the effectiveness of internal control over financial reporting and the effectiveness of internal control over financial reporting of Questar Corporation included in this Annual Report (Form 10-K) of Questar Corporation.
/s/ Ernst & Young LLP
Salt Lake City, Utah
February 26, 2007
QUESTAR 2006 FORM 10-K 96
Exhibit 23.2.
Engineer’s Consent
As independent petroleum engineers, we hereby consent to the reference of our appraisal reports for Questar Exploration and Production Company as of years ended December 31, 2003, 2004, 2005 and 2006 incorporated herein by reference into the following Registration Statements: Form S-3 (No. 33-48168) and Form S-8 (33-04436, 33-15149, 33-40800, 33-40801, 33-48169, 333-04913, 333-04951, 333-67658 and 333-89486).
/s/Ryder Scott Company, L.P.
RYDER SCOTT COMPANY, L.P.
Denver, Colorado
February 28, 2007
Exhibit 23.3.
Consent of Independent Petroleum Engineers and Geologists
As independent petroleum engineers, we hereby consent to the reference of our appraisal reports for Questar Exploration and Production Company as of years ended December 31, 2003, 2004, 2005 and 2006 incorporated herein by reference into the following Registration Statements: Form S-3 (No. 33-48168) and Form S-8 (33-04436, 33-15149, 33-40800, 33-40801, 33-48169, 333-04913, 333-04951, 333-67658 and 333-89486).
NETHERLAND, SEWELL & ASSOCIATES, INC.
By: /s/Frederic D. Sewell, P.E.
Frederic D. Sewell, P.E.
Chairman and Chief Executive Officer
Dallas, Texas
February 27, 2007
QUESTAR 2006 FORM 10-K 97
Exhibit 23.4.
Consent of H. J. Gruy and Associates, Inc.
We hereby consent to the use of the name H. J. Gruy and Associates, Inc. and of references to H. J. Gruy and Associates, Inc. and to the inclusion of and references to our reports, or information contained therein, dated January 19, 2004, January 22, 2004, January 25, 2005, January 21, 2005, January 25, 2005 and January 13, 2006, January 18, 2006, and January 19, 2007, prepared for Questar Exploration and Production Company in the Annual Report on Form 10-K of Questar Corporation for the filing dated on or about February 28, 2007, and the incorporation by reference into the applicable previous filings with the Securities and Exchange Commission. We are unable to verify the accuracy of the reserves and discounted present worth values contained therein because our estimates of reserves and discounted present worth have been combined with estimates of reserves and present worth prepared by other petroleum consultants.
H. J. GRUY AND ASSOCIATES, INC.
Texas Registration Number F-000637
By: /s/Robert J. Naas
Name: Robert J. Naas
Title: Executive Vice President
February 28, 2007
Dallas, Texas
Exhibit 24.
POWER OF ATTORNEY
We, the undersigned directors of Questar Corporation, hereby severally constitute Keith O. Rattie and S. E. Parks, and each of them acting alone, our true and lawful attorneys, with full power to them and each of them to sign for us and in our names in the capacities indicated below, the Annual Report on Form 10-K for 2006 and any and all amendments to be filed with the Securities and Exchange commission by Questar Corporation, hereby ratifying and confirming our signatures as they may be signed by the attorneys appointed herein to the Annual Report on Form 10-K for 2006 and any and all amendments to such Report.
Witness our hands on the respective dates set forth below.
Signature
Title
Date
/s/K. O. Rattie______________
Chairman of the Board,
2/13/07
Keith O. Rattie
President, and Chief Executive Officer
Director
/s/Phillips S. Baker, Jr._______
Director
2/13/07
Phillips S. Baker, Jr.
QUESTAR 2006 FORM 10-K 98
/s/Teresa Beck______________
Director
2/13/07
Teresa Beck
/s/R. D. Cash ______________
Director
2/13/07
R. D. Cash
/s/L. Richard Flury__________
Director
2/13/07
L. Richard Flury
/s/James A. Harmon_________
Director
2/13/07
James A. Harmon
/s/Robert E. McKee III_______
Director
2/13/07
Robert E. McKee III
/s/Gary G. Michael __________
Director
2/13/07
Gary G. Michael
/s/M. W. Scoggins____________
Director
2/13/07
M. W. Scoggins
/s/Harris H. Simmons__________
Director
2/13/07
Harris H. Simmons
/s/Charles B. Stanley__________
Director
2/13/07
Charles B. Stanley
/s/Bruce A. Williamson________
Director
2/13/07
Bruce A. Williamson
Exhibit 31.1.
CERTIFICATION
I, Keith O. Rattie, certify that:
1.
I have reviewed this report of Questar Corporation on Form 10-K for the period ending December 31, 2006;
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
QUESTAR 2006 FORM 10-K 99
4.
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:
a)
designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)
designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;
c)
evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)
disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting.
5.
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):
a)
all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)
any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
February 28, 2007
/s/Keith O. Rattie
Keith O. Rattie,
Chairman, President and Chief
Executive Officer
Exhibit 31.2.
CERTIFICATION
I, S. E. Parks, certify that:
1.
I have reviewed this report of Questar Corporation on Form 10-K for the period ending December 31, 2006;
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
QUESTAR 2006 FORM 10-K 100
4.
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:
a)
designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)
designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;
c)
evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)
disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting.
5.
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):
a)
all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)
any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
February 28, 2007
/s/S. E. Parks
S. E. Parks
Senior Vice President
and Chief Financial Officer
Exhibit No. 32.
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Annual Report of Questar Corporation (the Company) on Form 10-K for the period ending December 31, 2006, as filed with the Securities and Exchange Commission on the date hereof (the Report), Keith O. Rattie, Chairman, President and Chief Executive Officer of the Company, and S. E. Parks, Senior Vice President and Chief Financial Officer of the Company, each hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to the best of his knowledge:
QUESTAR 2006 FORM 10-K 101
(1)
The Report fully complies with the requirements of Section 13(a) or Section 15(d) of the Securities Exchange Act of 1934; and
(2)
The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
QUESTAR CORPORATION
February 28, 2007
/s/Keith O. Rattie
Keith O. Rattie
Chairman, President and Chief Executive Officer
February 28, 2007
/s/S. E. Parks
S. E. Parks
Senior Vice President
and Chief Financial Officer
QUESTAR 2006 FORM 10-K 102