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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K/A
Amendment No. 1
(Mark One)
[X]
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 2003 OR
[ ]
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM _____ TO _____.
Commission File No. 1-8796
QUESTAR CORPORATION
(Exact name of registrant as specified in its charter)
State of Utah
87-0407509
(State or other jurisdiction of
(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)
(Zip code)
Registrant's telephone number, including area code:
(801) 324-5000
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
Name of each exchange on
Title of each class
which registered
Common Stock, Without Par Value, with
New York Stock Exchange
Common Stock Purchase Rights
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
None
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 Ö 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 registrants' 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. Ö
Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act)
Yes Ö No
The aggregate market value of the registrant's common stock, without par value, held by nonaffiliates on February 27, 2004, was $2,955,413,593 (based on the closing price of such stock).*
On February 27, 2004, 83,630,372 shares of the registrant's common stock, without par value, were outstanding.
Documents Incorporated by Reference. Portions of the definitive Proxy Statement for the 2004 Annual Meeting of Stockholders are incorporated by reference into Part III. The sections of the Proxy Statement labeled "Committee Report on Executive Compensation" and "Cumulative Total Shareholder Return" are expressly not incorporated into this document.
*Calculated by excluding all shares held by directors and executive officers of registrant and three non-profit foundations established by Questar Corporation without conceding that all such persons are affiliates purposes of federal securities laws.
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EXPLANATORY NOTE
Questar Corporation ("Questar" or the "Company") inadvertently neglected to include a conformed signature for the opinion rendered by Ernst & Young, LLP, when it filed its Annual Report on Form 10-K for 2003 with the Securities and Exchange Commission on March 12, 2004. Consequently, the Company is filing an opinion with a conformed signature for Ernst & Young, LLP, as part of Item 8, Financial Statements and Supplementary Data, which is set forth below in its entirety. Questar is not making any other changes to its financial statements. This amendment is accurate as of the date of the Company's Form 10-K that was originally filed and has not been updated to reflect any events that occurred subsequent to March 12, 2004. The Company is including currently dated certifications as listed in a new Item 15.
FORWARD-LOOKING STATEMENTS
This report includes "forward-looking statements" within the meaning of Section 27(a) of the Securities Act of 1933, as amended, and Section 21(e) of the Securities Exchange Act of 1934, as amended ("Exchange Act"). All statements other than statements of historical facts included or incorporated by reference in this report, including, without limitation, statements regarding the Company's future financial position, business strategy, budgets, projected costs and plans and objectives of management for future operations, are forward-looking statements. In addition, forward-looking statements generally can be identified by the use of forward-looking terminology such as "may," "will," "could," "expect," "intend," "project," "estimate," "anticipate," "believe," "forecast," or "continue" or the negative thereof or variations thereon or similar terminology. Although these statements are made in good faith and are reasonable representations of the Company's expected performance at the time, actual results may vary from management's stated expectations and projections due to a variety of factors.
Important assumptions and other significant factors that could cause actual results to differ materially from those expressed or implied in forward-looking statements include: changes in general economic conditions; changes in gas and oil prices and supplies; changes in rate-regulatory policies; regulation of the Wexpro Agreement; availability of gas and oil properties for sale or exploration and land-access issues; creditworthiness of counterparties to hedging contracts; rate of inflation and interest rates; assumptions used in business combinations; weather and other natural phenomena; the effect of environmental regulation; changes in customers' credit ratings; competition from other forms of energy, other pipelines and storage facilities; the effect of accounting policies issued periodically by accounting standard-setting bodies; terrorist attacks or acts of war; changes in the business or financial condition of the company; and changes in credit ratings for Questar and/or its subsidiaries.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
Financial Statements:
Report of Independent Auditors
Consolidated Statements of Income, three years ended December 31, 2003
Consolidated Balance Sheets at December 31, 2003 and 2002
Consolidated Statements of Common Shareholders' Equity, three years ended
Consolidated Statements of Cash Flows, three years ended December 31, 2003
Notes to Consolidated Financial Statements
Financial Statement Schedules:
For the three years ended December 31, 2003
Valuation and Qualifying Accounts
All other schedules are omitted because they are not applicable or the required information is shown in the Consolidated Financial Statements or Notes thereto.
ERNST & YOUNG LLP
Report of Independent Auditors
Shareholders and Board of Directors
Questar Corporation
We have audited the accompanying consolidated balance sheets of Questar Corporation and subsidiaries as of December 31, 2003 and 2002, 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, 2003. 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 auditing standards generally accepted in the 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, 2003 and 2002, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2003, in conformity with accounting principles generally accepted in the United States. 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 Notes 1, 3 and 7 to the financial statements, Questar Corporation and subsidiaries adopted Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets,” effective January 1, 2002 and Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations,” effective January 1, 2003.
Salt Lake City, Utah
/s/Ernst & Young LLP
February 10, 2004
Ernst & Young LLP
LIABILITIES AND SHAREHOLDERS' EQUITY | ||
December 31, | ||
2003 | 2002 | |
(in thousands) | ||
CURRENT LIABILITIES | ||
Short-term debt | $105,500 | $49,000 |
Accounts payable and accrued expenses | ||
Accounts and other payables | 181,012 | 159,485 |
Production and other taxes | 40,124 | 28,179 |
Distribution rate-refund obligation | 24,939 | |
Federal income taxes | 8,515 | 9,854 |
Interest | 15,155 | 16,418 |
Deferred income taxes – current | 210 | |
Total accounts payable and accrued expenses | 269,955 | 213,936 |
Fair value of hedging contracts | 52,959 | 24,278 |
Purchased-gas adjustments | 13,282 | |
Current portion of long-term debt | 55,011 | 10 |
TOTAL CURRENT LIABILITIES | 483,425 | 300,506 |
LONG-TERM DEBT, less current portion | 950,189 | 1,145,180 |
DEFERRED INCOME TAXES | 442,839 | 377,717 |
DEFERRED INVESTMENT-TAX CREDITS | 4,166 | 4,565 |
OTHER LONG-TERM LIABILITIES | 66,332 | 48,166 |
ASSET-RETIREMENT OBLIGATIONS | 61,358 | |
PENSION LIABILITY | 31,617 | 42,930 |
MINORITY INTEREST | 7,864 | 10,025 |
COMMON SHAREHOLDERS' EQUITY | ||
Common stock - without par value; 350,000,000 | ||
shares authorized; 83,233,951 outstanding at | ||
December 31, 2003, and 82,053,760 outstanding | ||
at December 31, 2002. | 324,783 | 298,718 |
Retained earnings | 977,780 | 868,702 |
Accumulated other comprehensive loss | (41,298) | (28,659) |
TOTAL COMMON SHAREHOLDERS' EQUITY | 1,261,265 | 1,138,761 |
$3,309,055 | $3,067,850 | |
See notes to consolidated financial statements | ||
QUESTAR CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1 - Summary of Accounting Policies
Principles of Consolidation: The consolidated financial statements contain the accounts of Questar Corporation and subsidiaries (Questar or the Company). Questar is an integrated natural gas company with two principal lines of business: nonregulated and regulated. Questar Market Resources and subsidiaries (Market Resources) conduct the nonregulated activities of gas and oil exploration, development and production, gas gathering and processing, wholesale-energy marketing, and operate a private gas-storage facility. The Company's regulated activities of natural gas distribution, interstate transmission and storage operations are conducted by Questar Regulated Services Co. and subsidiaries (Regulated Services). Questar Pipeline provides interstate natural gas transmission and storage services, and through a subsidiary, Questar Transportation Services, operates a gas-processing plant and provides gas-gathering services. Questar Gas conducts natural gas-distribution activities. Corporate and Other Operations include information-technology related businesses, unregulated energy services and corporate activities. All significant intercompany accounts and transactions have been eliminated in consolidation.
Investments in Unconsolidated Affiliates: Questar uses the equity method to account for investments in affiliates in which it does not have control. Generally, the Company's investment in these affiliates equals the underlying equity in net assets.
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's operations in a small area of southeastern Idaho. Questar Pipeline is regulated by the Federal Energy Regulatory Commission (FERC). Market Resources, through its investment in Clear Creek Storage Company, LLC, operates a gas-storage facility that is 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.
Use of Estimates: The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts of assets and liabilities and disclosure of contingent liabilities reported in the financial statements and accompanying notes. Actual results could differ from those estimates.
Revenue Recognition: Revenues are recognized in the period that services are provided or products are delivered. Questar Gas records revenues for gas delivered to residential and commercial customers but not billed at the end of the accounting period. The impact of abnormal weather on gas-distribution earnings is significantly reduced by a weather-normalization adjustment. While the transportation and storage operations of the gas-transportation business are influenced by weather conditions, the straight-fixed-variable rate design, which allows for recovery of substantially all fixed costs in the demand or reservation charge, reduces the earnings impact of weather conditions. Rate-regulated companies may collect revenues subject to possible refunds and establish reserves pending final orders from regulatory agencies.
Exploration and production operations use the sales method of accounting for gas revenues, whereby revenue is recognized on all gas sold to purchasers. A liability is recorded to the extent that the Company has sold gas in excess of its share of remaining gas reserves in an underlying property. The Company's net gas imbalances at December 31, 2003, and 2002 were $2.4 million and $1.8 million, respectively. Revenues and prices for gas and oil are reported "net to the well” in that costs for gathering and processing, oftentimes paid by purchasers of the products, are not included in the reported revenues. Market Resources manages commodity-price risk through the use of natural gas- and oil-price-hedging instruments.
Purchased-Gas Adjustments: Questar Gas accounts for purchased-gas costs in accordance with procedures authorized by the PSCU and the PSCW. Purchased-gas costs that are different from those provided for in present rates are accumulated and recovered or credited through future rate changes. Questar Gas hedges a portion of its natural gas supply to mitigate energy-price fluctuations for gas-distribution customers. The benefits and the costs of hedging are included in the purchased-gas-adjustment account. The regulatory commissions allow Questar Gas to record periodic mark-to-market adjustments for energy-hedging contracts in the purchased-gas-adjustment account.
Other Regulatory Assets and Liabilities: Rate-regulated businesses may be permitted to defer recognition of certain costs, which is different from the accounting treatment required of nonrate-regulated businesses. Questar Gas recorded a regulatory asset at January 1, 2003, amounting to $6.6 million, representing a retroactive charge for the abandonment costs associated with gas wells operated on its behalf by Wexpro. The regulatory asset will be reduced over approximately 18 years following an amortization schedule or as cash is paid to plug and abandon wells. Gains and losses on the reacquisition of debt by rate-regulated companies are deferred and amortized as debt expense over either the would-be remaining life of the retired debt or the life of the replacement debt. The reacquired debt costs had a weighted-average life of approximately 15 years as of December 31, 2003. The cost of the early retirement windows offered to employees of rate-regulated subsidiaries was capitalized and amortized over a five-year period, which will conclude in 2005. Rate-regulated operations record cumulative increases in deferred taxes as income taxes recoverable from customers, all of which are expected to be recovered in 2004. 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. A liability has been recorded for postretirement medical costs allowed in rates that exceed actual costs.
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.
Property, Plant and Equipment: Property, plant and equipment is stated at cost.
Gas and oil properties
Under the successful-efforts method of accounting, the Company capitalizes the costs of acquiring leaseholds, drilling development wells, drilling successful exploratory wells, and purchasing related support equipment and facilities. The costs of unsuccessful exploratory wells are charged to expense when it is determined that such wells have not located proved reserves. Unproved-leasehold costs are periodically reviewed for impairment. Costs related to impaired prospects are charged to expense. Costs of geological and geophysical studies and other exploratory activities are expensed as incurred. Costs associated with 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 amortization rate would be significantly affected.
Capitalized proved-leasehold costs are depleted using the unit-of-production method based on proved reserves on a field basis. The costs of unproved gas and oil leaseholds are generally combined and amortized over a period that is based on the average holding period for such properties. All other capitalized costs associated with gas and oil properties are depreciated using the unit-of-production method based on proved-developed reserves on a field basis. The Company capitalizes an estimate of the fair value of abandonment costs, less estimated salvage values, and depreciates those costs over the life of the related asset.
Cost-of-service gas and oil operations
The successful-efforts method of accounting is used for "cost-of-service" gas and oil properties managed and developed by Wexpro, a subsidiary of Market Resources. Cost-of-service gas and oil properties are properties for which the operations and return on investment are regulated by the Wexpro agreement (see Note 17). 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 costs are depreciated on an individual-field basis using the unit-of-production method based upon proved-developed gas and oil reserves attributable to the field. The Company capitalizes an estimate of the fair value of abandonment costs, less estimated salvage values, and depreciates those costs over the life of the related asset.
Average depreciation, depletion and amortization rates used in the 12 months ended December 31 were as follows:
2003 | 2002 | 2001 | ||
Market Resources | ||||
Gas and oil properties, per Mcfe | ||||
U.S. | $.95 | $.90 | $.79 | |
Canada (in U.S. dollars) | - | .98 | 1.10 | |
Combined U.S. and Canada | .95 | .91 | .83 | |
Cost-of-service gas and oil properties, per Mcfe | .59 | .59 | .49 | |
For the remaining Company properties, the provision for depreciation, depletion and amortization is based upon rates that will systematically charge the costs of assets against income over the estimated useful lives of those assets. The investment in natural gas-gathering and processing facilities is charged to expense using either the straight-line or unit-of-production method. For depreciation purposes, major categories of fixed assets in the gas-distribution, transmission 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 facilities are depreciated using the unit-of-production method. The Company has not capitalized future-abandonment costs on a majority of its long-lived distribution and transmission assets due to a lack of a legal obligation to abandon the assets or to an indeterminable abandonment date. If required, an obligation will be recognized when an abandonment date is known.
Average depreciation, depletion and amortization rates used in the 12 months ended December 31 were as follows:
2003 | 2002 | 2001 | |
Natural gas transmission, processing and storage | 3.2% | 3.2% | 2.9% |
Natural gas distribution | |||
Distribution plant | 3.7% | 3.9% | 3.8% |
Gas wells, per Mcf | $.13 | $.14 | $.14 |
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 in accordance with Statement of Financial Accounting Standard (SFAS) 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." An impairment is indicated when a triggering event occurs and the estimated undiscounted future net cash flows of an evaluated asset are less than its carrying value. Triggering events that may indicate an impairment of gas and oil reserves could be caused by mechanical problems, a faster decline of reserves than expected, lease-ownership issues, and/or an other-than-temporary decline in gas and oil prices. 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 pricing and operating costs.
Goodwill and Other Intangible Assets: Intangible assets consist primarily of goodwill acquired through business combinations. The excess of the cost over the fair value of net assets of acquired businesses is recorded as goodwill. On January 1, 2002, the Company adopted SFAS 142, "Goodwill and Other Intangible Assets." According to SFAS 142, goodwill is no longer amortized, but is tested for impairment at a minimum of once a year or when an event occurs. Annual impairment tests are conducted in the fourth quarter. When a triggering event occurs, the undiscounted net cash flows of the asset or entity to which the goodwill relates are evaluated. If undiscounted cash flows are less than the carrying value of the assets, impairment is indicated. The amount of the impairment is measured using a discounted-cash-flow model considering pricing, operating costs, a risk-adjusted discount rate and other factors.
Capitalized Interest and Allowance for Funds Used During Construction: When applicable, Market Resources capitalizes interest costs during the construction period of plant and equipment. However, the company did not capitalize interest costs in 2003, 2002 and 2001. Under provisions of the Wexpro Agreement, the company capitalizes an allowance for funds used during construction (AFUDC) on cost-of-service construction projects. The FERC requires the capitalization of AFUDC during the construction period of rate-regulated plant and equipment. AFUDC amounted to $1.1 million in 2003, $400,000 in 2002 and $203,000 in 2001, and is included in Interest and Other Income in the Consolidated Statements of Income.
Foreign-Currency Translation: The Company conducted gas and oil development-and-production operations in Canada, which were sold in 2002. The local currency, the Canadian dollar, was the functional currency of the Company's foreign operations. Revenue and expense accounts were translated using an average exchange rate. Adjustments resulting from such translations were reported as a separate component of other comprehensive income in shareholders' equity.
Energy-Price Financial Instruments: On January 1, 2001, the Company adopted the provisions of SFAS 133 as amended and recorded a cumulative effect of this accounting change that decreased other comprehensive income by $79.4 million after tax. The majority of its energy-price-derivative instruments are structured as cash-flow hedges. A $121 million hedging liability for derivative instruments was recorded as a result of adopting SFAS 133.
The Company may elect to designate a derivative instrument as a hedge of exposure to changes in fair value, cash flows or foreign currencies. 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 earnings in the current period.
A derivative instrument qualifies as a 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.
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At the inception of the hedge and throughout the hedge period, there is a high correlation between changes in the market value of the derivative instrument and the fair value of the underlying hedged item.
When the designated item associated with a derivative instrument matures, is sold, extinguished or terminated, derivative gains or losses are included in income in the same period that the underlying production or other contractual commitment is delivered. When a derivative instrument is associated with an anticipated transaction that is no longer expected to occur or if correlation no longer exists, the gain or loss on the derivative is reclassified from other comprehensive income and recognized currently in the results of operations.
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 which 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 Company's primary market areas are the Rocky Mountain and Midcontinent regions of the United States. Exposure to credit risk may be impacted 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 be affected differently by 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. 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. The Company is attempting to increase the number of contracts that contain netting provisions. Bad-debt expense amounted to $3.7 million, $7.9 million and $8.6 million for the years ended December 31, 2003, 2002 and 2001, respectively. The allowance for bad-debt expenses was $6.7 million and $7.1 million at December 31, 2003, and 2002, respectively.
Income Taxes: Questar and its subsidiaries file a consolidated federal income tax return. Deferred income taxes have been provided for temporary differences caused by differences 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.
Earnings Per Share: Basic earnings per share (EPS) 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 include the potential increase in outstanding shares that could result from exercising stock options, which is the sole difference between basic and diluted shares.
Stock-Based Compensation: The Company accounts for employee stock-based compensation using the intrinsic-value method prescribed by Accounting Principles Board (APB) Opinion 25, "Accounting for Stock Issued to Employees," and related interpretations. Under this method, no compensation expense is recorded for stock options granted because the exercise price of those options equals the market price of the Company's common stock on the date of grant. Compensation expense for awards of restricted shares is recognized over the vesting period, based on share value on the date of grant. A table showing income adjusted for stock-based compensation follows:
Year Ended December 31, | |||
2003 | 2002 | 2001 | |
(in thousands) | |||
Net income, as reported | $173,616 | $155,596 | $158,186 |
Deduct: Stock-based compensation expense | |||
determined under fair-value-based methods, | |||
net of income tax | (5,277) | (5,100) | (4,435) |
Pro forma net income | $168,339 | $150,496 | $153,751 |
Earnings per share | |||
Basic, as reported | $2.10 | $1.90 | $1.95 |
Basic, pro forma | 2.04 | 1.84 | 1.90 |
Diluted, as reported | 2.06 | 1.88 | 1.94 |
Diluted, pro forma | 2.00 | 1.82 | 1.88 |
Comprehensive Income: Comprehensive income is the sum of net income as reported in the Consolidated Statement of Income and other comprehensive income transactions reported in the Consolidated Statement of Common Shareholders' Equity. Other comprehensive income transactions result from changes in the market value of qualified energy derivatives and recognition of additional pension liability. 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 underlying energy product is sold.
The balances of accumulated other comprehensive loss, net of income taxes, at December 31, were as follows:
2003 | 2002 | ||
(in thousands) | |||
Unrealized loss on energy-hedging transactions | ($32,635) | ($16,880) | |
Additional pension liability | (8,663) | (11,779) | |
Accumulated other comprehensive loss | ($41,298) | ($28,659) | |
Business Segments: Questar's line-of-business disclosures are presented according to senior management’s basis for evaluating performance. Certain intersegment sales include intercompany profit.
Recent Accounting Developments:
The Securities and Exchange Commission has requested that the Financial Accounting Standards Board review the applicability of certain provisions of SFAS 141, "Business Combinations," and SFAS 142, "Goodwill and Other Intangible Assets," to companies in the exploration and production business. The issue is whether the provisions of SFAS 141 and SFAS 142 require companies to classify costs associated with mineral rights, including both proved and unproved lease-acquisition costs, as intangible assets on the balance sheet apart from other capitalized gas and oil property costs. As of December 31, 2003, Market Resources' proved and unproved leaseholds had a net book value of $385 million.
Reclassifications: Certain reclassifications were made to the 2002 and 2001 financial statements to conform with the 2003 presentation.
Note 2 – Distribution Rate Refund – Questar Gas Processing Dispute
On August 1, 2003, the Utah Supreme Court issued an order reversing a decision made by the PSCU in August of 2000 concerning certain processing costs incurred by Questar Gas. The court ruled that the PSCU did not comply with its responsibilities and regulatory procedures when approving a stipulation in Questar Gas's general rate case filed in December of 1999. The stipulation permitted Questar Gas to collect $5 million per year in rates to recover a portion of the gas-processing costs incurred. The Committee of Consumer Services (committee), a Utah state agency, appealed the PSCU's decision because the PSCU did not explicitly address whether the costs were prudently incurred.
As a result of the court's order, Questar Gas recorded a $24.9 million liability for a potential refund to gas-distribution customers. The liability reflects revenue received for processing costs from June 1999 through December 2003. This charge reduced Questar's consolidated net income by $15.5 million, or $.18 per diluted share. Recording the liability did not have a material impact on the credit, cash or liquidity of Questar or Questar Gas. Questar Gas has requested ongoing rate coverage for gas-processing costs in its recent gas-cost pass through filing and is currently collecting these costs in rates. Until the issue is decided by the PSCU, Questar Gas will continue to record a liability for the potential refund of the ongoing gas-processing costs.
On January 21, 2004, the Committee filed a petition for extraordinary relief with the Utah Supreme Court. The committee maintained that by reopening the proceeding to review the prudence of Questar's decision making with regards to gas processing, the PSCU did not comply with the mandate of the Utah Supreme Court. The committee questioned whether the PSCU can modify post-appeal evidentiary determinations. The company, as well as the PSCU and the Division of Public Utilities, filed memorandum opposing the committee’s filing.
Note 3 – New Accounting Standard – Accounting for Asset-Retirement Obligations
On January 1, 2003, Questar adopted SFAS 143, "Accounting for Asset Retirement Obligations," and recorded a $5.6 million after-tax charge ($.07 per diluted share) for the cumulative effect of implementing this accounting change. 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 new standard requires the Company to estimate a fair value of abandonment costs and to capitalize and depreciate those costs over the life of the related assets. The asset-retirement obligation is adjusted to its present value each period through an accretion process using a credit-adjusted risk-free interest rate. Both the accretion expense associated with the liability and the depreciation associated with the capitalized abandonment costs are noncash expenses.
With the adoption of SFAS 143, Questar changed the accounting method for plugging and abandonment costs associated with gas and oil wells and certain other properties. SFAS 143 was applied retroactively to prior years to determine the cumulative effect through December 31, 2002. Questar Gas recorded a regulatory asset at January 1, 2003, amounting to $6.6 million representing a retroactive charge for the abandonment costs associated with gas wells operated on its behalf by Wexpro. The regulatory asset will be reduced over 18 years following an amortization schedule or as cash is spent to plug and abandon the gas wells. Changes in the asset-retirement obligations are shown below:
(in thousands) | ||||
Balance at January 1, 2003 | $56,493 | |||
Accretion (expensed or capitalized) | 3,667 | |||
Additions | 2,268 | |||
Properties sold | (777) | |||
Retirements | (293) | |||
Balance at December 31, 2003 | $61,358 | |||
Assuming retroactive application of SFAS 143 as of January 1, 2001, the pro forma effect of applying this new accounting principle would have not materially affected income in 2002 and 2001. The pro forma asset-retirement obligation as of January 1, 2002 was $53.2 million.
Note 4 – Property, Plant and Equipment
The details of property, plant and equipment and accumulated depreciation, depletion and amortization follow:
December 31, | ||
2003 | 2002 | |
Property, plant and equipment | (in thousands) | |
Market Resources | ||
Gas and oil properties | ||
Proved properties | $1,315,330 | $1,103,686 |
Unproved properties, not being depleted | 95,208 | 131,817 |
Support equipment and facilities | 22,569 | 29,571 |
1,433,107 | 1,265,074 | |
Cost-of-service gas and oil properties | 472,983 | 428,597 |
Gathering, processing and marketing | 243,081 | 223,974 |
2,149,171 | 1,917,645 | |
Natural gas transmission | 1,034,958 | 1,020,838 |
Natural gas distribution | 1,240,553 | 1,193,553 |
Corporate and other operations | 78,113 | 79,515 |
4,502,795 | 4,211,551 | |
Accumulated depreciation, depletion and amortization
Market Resources | ||
Gas and oil properties | 501,825 | 424,392 |
Cost-of-service gas and oil properties | 239,035 | 224,440 |
Gathering, processing and marketing | 75,985 | 68,157 |
816,845 | 716,989 | |
Natural gas transmission | 336,206 | 316,433 |
Natural gas distribution | 532,747 | 513,485 |
Corporate and other operations | 48,468 | 46,846 |
1,734,266 | 1,593,753 | |
Net Property, Plant and Equipment | $2,768,529 | $2,617,798 |
Note 5 – Dispositions and Acquisitions
Sale of Canadian Properties
On October 21, 2002, Market Resources sold its Canadian exploration and production subsidiary, Celsius Energy Resources, Ltd (CERL), to EnerMark Inc., a subsidiary of Calgary-based Enerplus Resources Fund and recorded a pretax gain of $US19.7 million. Total consideration received was $US 101.6 million. CERL earned net income for the nine months ended September 30, 2002, of $US 1.5 million and had total assets of $US 80 million at September 30, 2002. Market Resources used the proceeds from the sale to repay debt.
Sale of TransColorado
On October 20, 2002, Questar Pipeline sold Questar TransColorado, Inc., the company owning Questar's interest in the TransColorado Pipeline, for $105.5 million. Proceeds from the sale were used to retire debt at Questar Pipeline.
Partnership Interests Acquired
In 2002, Questar Pipeline and affiliates acquired the final 28% partnership interests in the Overthrust Pipeline Company (Overthrust) for $5.4 million. Accounting for Overthrust changed from an unconsolidated affiliate to full consolidation as a result of acquiring controlling interest. The purchase included $4.1 million of goodwill.
Market Resources, through an affiliate, acquired El Paso Gas Gathering and Processing's 50% interest in the Blacks Fork processing plant for approximately $5.4 million, effective December 18, 2002. Market Resources now owns 100% of the plant. Accounting for the company's interest in Blacks Fork changed from an unconsolidated partnership to full consolidation as a result of this transaction.
Note 6 – Investment in Unconsolidated Affiliates
Questar, indirectly through subsidiaries, has interests in businesses accounted for on the equity basis. As of December 31, 2003, and 2002, these affiliates did not have debt obligations with third-party lenders. The principal business activities, form of organization and percentage ownership are listed below. Percentage of voting control and economic interest are identical. Canyon Creek Compression Co., a general partnership (15%) and Rendezvous Gas Services LLC, a limited-liability corporation (50%), are engaged in processing and/or gathering natural gas. TransColorado and Overthrust conducted transportation activities. In 2002, TransColorado was sold and the remaining interest in Overthrust was acquired.
Summarized results of the partnerships are listed below.
Year Ended December 31, | |||
2003 | 2002 | 2001 | |
(in thousands) | |||
Gas-gathering and processing partnerships | |||
Revenues | $15,916 | $25,490 | $24,992 |
Operating income | 9,775 | 8,805 | 2,830 |
Income before income taxes | 9,807 | 8,869 | 3,105 |
Current assets, at end of period | 5,167 | 11,806 | 21,000 |
Noncurrent assets, at end of period | 74,111 | 45,704 | 38,862 |
Current liabilities, at end of period | 909 | 5,178 | 3,893 |
Noncurrent liabilities, at end of period | 1,589 | 2,182 | 2,529 |
Transportation partnerships | |||
Revenues | $24,992 | $16,164 | |
Operating income (loss) | 14,732 | (4,805) | |
Income (loss) before income taxes | 14,791 | (13,606) | |
Current assets, at end of period |
| 13,315 | |
Noncurrent assets, at end of period |
| 301,431 | |
Current liabilities, at end of period |
| 5,146 | |
Noncurrent liabilities, at end of period |
| 13,662 | |
Note 7 – Goodwill and Other Intangible Assets
The Company adopted SFAS 142, "Goodwill and Other Intangible Assets," as of January 1, 2002, and performed an initial test that indicated an impairment of the goodwill acquired by Consonsus. The impairment amounted to $17.3 million, of which $15.3 million ($.19 per diluted common share) was attributed to Questar InfoComm's share and reported as a cumulative effect of a change in accounting for goodwill. The remaining $2 million loss was attributed to minority shareholders.
The balance in goodwill in each line of business is listed below:
Consolidated | Market Resources | Natural Gas Transmission | Natural Gas Distribution | Corporate and Other Operations | |
(in thousands) | |||||
Balance at December 31, 2001 | $90,927 | $66,823 | $5,876 | $18,228 | |
Impaired goodwill identified in initial test | (17,307) | (17,307) | |||
Goodwill attributed to dispositions | (6,545) | (5,400) | (224) | (921) | |
Goodwill purchase | 4,058 | $4,058 | |||
Balance at December 31, 2002 | 71,133 | 61,423 | 4,058 | 5,652 | - |
Adjustment | 127 | 127 | |||
Balance at December 31, 2003 | $71,260 | $61,423 | $4,185 | $5,652 | - |
The following table shows pro-forma net income, excluding the impairment and amortization of goodwill. Neither the impairment resulting from the change in accounting method nor the amortization of goodwill was deductible for income tax purposes.
Year-Ended December 31, | ||
2002 | 2001 | |
(in thousands) | ||
Net income | $155,596 | $158,186 |
Goodwill amortization | 2,224 | |
Cumulative effect of accounting change | ||
for goodwill, net of $2,010 attributed to | ||
minority interest | 15,297 | |
Pro-forma net income | $170,893 | $160,410 |
Basic earnings per share | ||
Net income as reported | $1.90 | $1.95 |
Pro-forma net income | 2.09 | 1.98 |
Diluted earnings per share | ||
Net income as reported | $1.88 | $1.94 |
Pro-forma net income | 2.07 | 1.96 |
As of December 31, 2003, the Company held about $1.1 million of intangible assets with indefinite lives. Intangible assets, primarily rights of way for pipelines, subject to amortization, amounted to $9.4 million, net of accumulated amortization of $1.8 million.
Note 8 – Other Regulatory Assets and Liabilities
In addition to purchased-gas adjustments, the Company has other regulatory assets and liabilities. The regulated entities recover these costs but do not receive a return on these assets. A list of regulatory assets follows:
December 31, | ||
2003 | 2002 | |
(in thousands) | ||
Cost of reacquired debt | $17,954 | $14,879 |
Asset-retirement obligations - | ||
cost-of-service gas wells | 8,256 | |
Early retirement costs | 5,370 | 8,334 |
Deferred production taxes | 3,090 | 2,719 |
Income taxes recoverable from customers | 3,010 | 4,269 |
Other | 159 | 645 |
$37,839 | $30,846 | |
Questar Pipeline has accrued a regulatory liability for the collection of postretirement medical costs allowed in rates which were in excess of actual charges. The balance as of December 31 was $3.2 million in 2003 and $2.9 million in 2002. Questar Pipeline has a regulatory liability for a refund of income taxes to customers amounting to $1.3 million and $1.6 million at December 31, 2003, and 2002, respectively. The balance will be refunded to customers through 2016.
Note 9 – Debt
Questar has short-term line-of-credit arrangements with several banks under which it may borrow up to $210 million. These lines have interest rates generally below the prime-interest rate. Commercial-paper borrowings with initial maturities of less than one year are backed by the short-term line-of-credit arrangements. The details of short-term debt are as follows:
December 31, | ||
2003 | 2002 | |
( in thousands) | ||
Commercial paper with variable-interest rates | $105,500 | $49,000 |
Weighted-average interest rate at December 31 | 1.11% | 1.62% |
The details of long-term debt are as follows:
December 31, | ||
2003 | 2002 | |
(in thousands) | ||
Market Resources | ||
Revolving-credit loan due 2004 with variable- | ||
interest rates (1.77% at December 31, 2003) | $ 55,000 | $ 200,000 |
7.0% notes due 2007 | 200,000 | 200,000 |
7.5% notes due 2011 | 150,000 | 150,000 |
Questar Pipeline | ||
Medium-term notes 5.85% to 7.55%, due 2008 | ||
to 2018 | 310,400 | 310,400 |
Questar Gas | ||
Medium-term notes 5.02% to 8.12%, due 2007 | ||
to 2024 | 290,000 | 285,000 |
Corporate and Other | 123 | 132 |
Total long-term debt outstanding | 1,005,523 | 1,145,532 |
Current portion | (55,011) | (10) |
Unamortized-debt discount | (323) | (342) |
$ 950,189 | $1,145,180 | |
Maturities of long-term debt for the five years following December 31, 2003, are as follows:
2004 2005 2006 2007 2008 | (in thousands) $ 55,011 12 14 210,016 101,318 |
Cash paid for interest was $70.2 million in 2003, $77.3 million in 2002 and $61.7 million in 2001.
Market Resources' revolving-credit loan contains covenants specifying a minimum amount of net equity and a maximum ratio of debt to equity. This facility matures in April 2004. The company is negotiating a new credit facility and has received letters of commitment for a new long-term agreement.
On January 24, 2003, Questar Gas issued $40 million of medium-term notes with an effective interest rate of 5.02% and a 10-year life. The proceeds were used to redeem debt with a higher interest rate.
In March 2003, Questar Gas sold $70 million of 15-year notes with a coupon rate of 5.31%. Proceeds from the offering were used to replace higher-cost debt with a weighted-average interest rate of 8.11%
Questar has an effective shelf registration with the Securities and Exchange Commission to issue up to $400 million of common equity or debt convertible into common stock. Currently there are no plans to issue securities under this shelf registration.
Note 10 – Earnings Per Share
Common shares outstanding increased as a result of issuances under the Long-Term Stock Incentive Plan, the Dividend Reinvestment and Stock Purchase Plan and the Employee Investment Plan discussed in Note 11. A reconciliation of the components of basic and diluted common shares used in the earnings-per-share calculation is as follows:
Year Ended December 31, | ||||
2003 | 2002 | 2001 | ||
(in thousands) | ||||
Weighted-average basic common shares | ||||
outstanding | 82,697 | 81,782 | 81,097 | |
Potential number of shares issuable under | ||||
stock plans | 1,493 | 791 | 561 | |
Weighted-average diluted common shares | ||||
Outstanding | 84,190 | 82,573 | 81,658 | |
Note 11 – Common Stock
Dividend Reinvestment and Stock Purchase Plan: The Dividend Reinvestment and Stock Purchase Plan (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 Reinvestment Plan issued total shares of 208,400, 112,761, and 219,846 in 2003, 2002 and 2001, respectively. At December 31, 2003, 1,379,754 shares were reserved for future issuance.
Employee Investment Plan: The Employee Investment Plan (Plan) allows eligible employees to purchase shares of Questar common stock or other investments through payroll deduction. The Company matches 80% of employees' pre-tax purchases up to a maximum of 6% of their qualifying earnings. In addition, each year the Company makes a nonmatching contribution of $200 to each eligible employee. The Company's expense equals its contribution. Questar's expense of the Plan amounted to $5.5 million, $5.5 million and $5.3 million for the years ended December 31, 2003, 2002 and 2001, respectively.
Stock Plans: The Company has an omnibus Long-term Stock Incentive Plan (Stock Plan) for officers, directors, and employees. The current plan was amended March 1, 2001, and approved by shareholders to combine optionees under one plan and reserve an additional 8,000,000 shares. The Company's separate Stock Option Plan for Directors terminated, but still has outstanding options granted between 1994 and 2002. Stock options for participants have 10-year terms. Options held by employees vest in four equal, annual installments beginning six months after grant. Options granted to nonemployee directors after 1996, generally vest in one installment six months after grant. Options vest on an accelerated basis in the event of retirement and have post-retirement exercise periods. The option price equals the closing market price of the stock on the grant date; therefore no compensation expense is recorded. There were 6,025,943 shares available for future grant at December 31, 2003.
Shares of restricted stock granted as sign-on bonuses, for retention purposes, and as partial payment of earned bonuses under the annual bonus plans adopted by the Company and its primary business units are granted under the terms of the Stock Plan.
Nonemployee directors may choose to receive shares of common stock instead of cash in payment of directors' fees pursuant to the terms of a plan approved by shareholders. As of December 31, 2003, there were 88,258 shares available for future use.
Transactions involving options in the stock plans are summarized as follows:
Weighted-Average | |||
Options | Price Range | Exercise Price | |
Balance at January 1, 2001 | 3,782,581 | $ 9.81 - $21.38 | $17.38 |
Granted | 1,085,500 | 27.42 - 28.01 | 27.96 |
Cancelled | (13,320) | 15.00 - 21.38 | 16.02 |
Exercised | (709,215) | 9.81 - 21.38 | 17.10 |
Balance at December 31, 2001 | 4,145,546 | 9.81 - 28.01 | 20.20 |
Granted | 1,364,000 | 22.95 - 23.95 | 23.02 |
Cancelled | (53,600) | 15.00 - 28.01 | 22.62 |
Exercised | (480,207) | 9.81 - 22.95 | 16.57 |
Balance at December 31, 2002 | 4,975,739 | 13.69 - 28.01 | 21.29 |
Granted | 1,156,500 | 27.11 - 29.71 | 27.18 |
Cancelled | (13,250) | 22.95 - 28.01 | 26.29 |
Exercised | (1,138,770) | 13.69 - 28.01 | 19.03 |
Balance at December 31, 2003 | 4,980,219 | $13.69 - $29.71 | $23.16 |
Options Outstanding | Options Exercisable | |||||
Weighted- | ||||||
Number | average | Weighted- | Number | Weighted- | ||
outstanding | remaining | average | exercisable | average | ||
Range of | December 31 | contract life | exercise | December 31, | exercise | |
Exercise prices | 2003 | in years | price | 2003 | price | |
$13.69 - $17.00 | 1,117,183 | 4.4 | $15.78 | 1,117,183 | $15.78 | |
19.13 - 23.95 | 1,668,545 | 6.4 | 22.33 | 1,238,545 | 22.08 | |
27.11 - 29.71 | 2,194,491 | 7.7 | 27.55 | 1,317,991 | 27.70 | |
4,980,219 | $23.16 | 3,673,719 | $22.18 | |||
A fair value of the stock options issued was determined on the grant date using the Black-Scholes 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 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:
2003 | 2002 | 2001 | |
(in thousands) | |||
Fair value of options at grant date | $7.54 | $6.58 | $8.90 |
Risk-free interest rate | 3.80% | 4.98% | 5.04% |
Expected price volatility | 30.0% | 30.5% | 30.7% |
Expected dividend yield | 2.70% | 3.14% | 2.52% |
Expected life in years | 7.3 | 7.3 | 7.3 |
Restricted Stock: The Company issues restricted stock as part of bonus payments in specified situations. Compensation expense is recorded in the period that the bonus is earned. These shares carry voting and dividend rights; however, sale or transfer is restricted. In 2003, the Company issued 136,800 restricted shares valued at $3.7 million with various vesting periods for employee-retention purposes. Subsequently, 5,750 of these shares were forfeited. Expense is recognized over the vesting period based on share value on the date of grant. Compensation expense amounted to $2.0 million, $1.1 million and $1.9 million in 2003, 2002 and 2001, respectively. Questar awarded 21,000 shares that vest in three years in both 2002 and 2001 as part of employment contracts. A portion of the restricted shares is reserved for under the Stock Plan. Distribution of restricted stock and vesting periods were as follows:
Year Ended December 31, | |||
2003 | 2002 | 2001 | |
One year | 23,091 | 28,913 | |
In equal installments over two years |
| 30,897 | |
In equal installments over three years | 21,000 | 21,000 | |
Various periods from 3 to 5 years | 241,101 | ||
Total restricted shares awarded | 241,101 | 44,091 | 80,810 |
Average market price per share at award date | $31.23 | $25.60 | $24.07 |
Shareholder Rights: On February 13, 1996, Questar's Board of Directors declared a stock-right dividend for each outstanding share of common stock. The stock rights were issued March 25, 1996. The rights become exercisable if a person, as defined, acquires 15% or more of the Company's common stock or announces an offer for 15% or more of the common stock. Each right initially represents the right to buy one share of the Company's common stock for $87.50. Once any person acquires 15% or more of the Company's common stock, the rights are automatically modified. Each right not owned by the 15% owner becomes exercisable for the number of shares of Questar's stock that have a market value equal to two times the exercise price of the right. This same result occurs if a 15% owner acquires the Company through a reverse merger when Questar and its stock survive. If the Company is involved in a merger or other business combination at any time after the rights become exercisable, rightholders will be entitled to buy shares of common stock in the acquiring Company having a market value equal to twice the exercise price of each right. The rights may be redeemed by the Company at a price of $.005 per right until 10 days after a person acquires 15% ownership of the common stock. The rights expire March 25, 2006.
Note 12 – Financial Instruments and Risk Management
The carrying value and estimated fair values of Questar's financial instruments were as follows:
December 31, 2003 | December 31, 2002 | |||
Carrying | Estimated | Carrying | Estimated | |
Value | Fair Value | Value | Fair Value | |
(in thousands) | ||||
Financial assets | ||||
Cash and cash equivalents | $ 13,905 | $ 13,905 | $ 21,641 | $ 21,641 |
Energy-price-hedging contracts | 3,861 | 3,861 | 3,617 | 3,617 |
Financial liabilities | ||||
Short-term debt | 105,500 | 105,500 | 49,000 | 49,000 |
Long-term debt | 1,005,200 | 1,130,243 | 1,145,190 | 1,268,592 |
Energy-price-hedging contracts | 52,959 | 52,959 | 24,278 | 24,278 |
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.
Energy-price-hedging contracts – fair value of the contracts is based on market prices as posted on the NYMEX from the last trading day of the year. The average price of the gas contracts at December 31, 2003, was $4.24 per MMBtu, representing the average of contracts with different terms including fixed, various "into-the-pipe" postings and NYMEX references. Energy-price-hedging contracts were in place for equity gas production and gas-marketing transactions. Deducting transportation and heat-value adjustments on the hedges of equity gas as of December 31, 2003, would result in an average price of approximately $4.00 per Mcf, net to the well.
Market Resources held gas-price-hedging contracts covering the price exposure for about 148.1 million dth of gas as of December 31, 2003. About 99% of those contracts will settle and be reclassified from other comprehensive income in 2004. At December 31, 2003, all oil-price-hedging contracts for Market Resources had expired. A year earlier Market Resources hedging contracts covered 85.2 million dth of natural gas and 1.1 million barrels of oil. Market Resources does not hedge the price of natural gas liquids.
At December 31, 2003, the Company reported a current liability, net of hedging assets, of $49.1 million from hedging activities. Settlement of contracts in 2003 resulted in the reclassification into expense of $15.6 million. The offset to the hedging liability, net of income taxes, was a $15.8 million unrealized loss on hedging activities recorded in other comprehensive loss in the shareholders' equity section of the balance sheet. Settlement of contracts resulted in reclassifying $42.4 million from comprehensive loss in 2002 and $68 million from comprehensive income in 2001 to the income statement. The ineffective portion of hedging transactions recognized in earnings was not significant. The fair-value calculation of energy-price hedges 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 13 – 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, | |||
2003 | 2002 | 2001 | |
(in thousands) | |||
Federal | |||
Current | $20,166 | $11,613 | $48,757 |
Deferred | 76,356 | 60,409 | 24,716 |
State | |||
Current | 383 | (2,347) | 5,641 |
Deferred | 6,057 | 16,184 | 3,688 |
Deferred investment-tax credits | (399) | (401) | (401) |
Foreign income taxes | 5,668 | 5,869 | |
| $102,563 | $91,126 | $88,270 |
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, | |||
2003 | 2002 | 2001 | |
Percentages | |||
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 | 1.5 | 3.4 | 2.5 |
Nonconventional fuel credits | (2.5) | (2.8) | |
Amortize investment-tax credits related to | |||
rate-regulated assets | (0.1) | (0.2) | (0.2) |
Amortize unrecorded timing difference related | |||
to rate-regulated assets | 0.3 | 0.4 | 0.4 |
Tax benefits from dividends paid to ESOP | (0.5) | (0.5) | |
Foreign income taxes | (0.3) | 1.0 | |
Goodwill, not deductible for income taxes | 0.3 | ||
Other | 0.2 | (0.5) | (.4) |
Effective income tax rate | 36.4% | 34.8% | 35.8 % |
Significant components of the Company's deferred income taxes were as follows:
December 31, | |||
2003 | 2002 | ||
(in thousands) | |||
Deferred-tax liabilities | |||
Property, plant and equipment | $494,332 | $425,373 | |
Deferred-tax assets | |||
Mark-to-market and hedging activities | 18,361 | 18,794 | |
Alternative minimum-tax credit carried forward | 18,834 | 9,113 | |
Net operating loss carried forward | 1,332 | 16,500 | |
Employee benefits and compensation costs | 12,966 | 3,249 | |
Total deferred tax assets | 51,493 | 47,656 | |
Deferred income taxes – noncurrent | $442,839 | $377,717 | |
Deferred income –taxes – current (asset) liability | |||
Purchased-gas adjustment | $210 | ($5,047) | |
Cash paid for income taxes was $18.9 million and $43.8 million in 2003 and 2001, respectively. In 2002, the Company received $8.8 million of refunded income taxes resulting primarily from timing differences caused by intangible-drilling costs.
Note 14 – Litigation and Commitments
Litigation
There are various legal proceedings against the Company and its affiliates. Management believes that the outcome of these cases will not have a material effect on the Company's financial position, operating results or liquidity.
Commitments
Historically, 40 to 50% of Questar Gas's gas-supply portfolio has been provided from company-owned gas reserves at the cost of service. The remainder of the gas supply has been purchased from more than 15 suppliers under approximately 46 gas-supply contracts using index-based or fixed pricing. Questar Gas has commitments of $132 million and $60.4 million to purchase gas in 2004 and 2005, respectively. Generally, at the conclusion of the heating season and after a bid process, new agreements for the upcoming heating season are put into place. Questar Gas bought significant quantities of natural gas under purchase agreements amounting to $180 million, $148 million and $261 million in 2003, 2002 and 2001, respectively. In addition, Questar Gas makes use of various storage arrangements to meet peak-gas demand during certain times of the heating season.
Questar Energy Trading, a subsidiary of Market Resources, has contracted for firm-transportation services with various pipelines through 2018. Due to market conditions and competition, it is possible that Questar Energy Trading may not be able to recover the full cost of the transportation commitments. Annual payments and the years covered are as follows:
(in thousands) | ||
2004 | $4,342 | |
2005 | 4,337 | |
2006 | 4,327 | |
2007 | 4,257 | |
2008 | 3,951 | |
2009 through 2018 | 26,899 | |
Questar sold its headquarters building under a sale-and-lease-back arrangement in November 1998. The operating agreement commits 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.
On January 12, 2012, the lessor is required to pay Questar on a lease-reduction payment of $12.1 million. On the following day Questar is required to pay a balloon-lease payment of $14.1 million. If the lessor does not make the lease-reduction payment on January 12, 2012, a lessor-nonpayment event occurs, and Questar's lease immediately extends for a period of 20 years with no additional rent due. Minimum future payments under the terms of long-term operating leases for the Company's primary office locations, including its headquarters building, for the five years following December 31, 2003, are as follows:
(in thousands) | |
2004 | $4,992 |
2005 | 5,025 |
2006 | 4,795 |
2007 | 4,581 |
2008 | 4,133 |
2009 through 2012 | 25,931 |
Total minimum future rental payments have not been reduced for sublease rentals of $176,000 in 2004, $178,000 in 2005, $180,000 in 2006, $155,000 in 2007 and $127,000 in 2008. Total rental expense amounted to $5.2 million in 2003, $4.9 million in 2002 and $4.7 million in 2001. Sublease-rental receipts were $287,000 in 2003, $206,000 in 2002 and $294,000 in 2001.
Note 15 - Rate Regulation and Other Matters
State Rate Regulation
Questar Gas files periodic applications with the PSCU and the PSCW requesting permission to reflect annualized gas-cost increases or decreases depending on gas prices. These requests for gas-cost increases or decreases are passed on to customers on a dollar-for-dollar basis with no markup. The impact of a gas-cost increase on customers is lessened by the fact that approximately 40 to 50% of the company's annual supply comes from its own wells and is priced to customers at cost-of-service prices rather than market prices.
2002 General rate case order
Effective December 30, 2002, the PSCU issued an order approving an $11.2 million general-rate increase for Questar Gas using an 11.2% rate of return on equity. The rate increase also reflects November 2002 usage per customer and costs. Previous general-rate-case increases relied on costs and customer-usage patterns that were typically 12 to 24 months old. Questar Gas originally requested a $23 million rate increase and a 12.6% rate of return on equity.
Purchased-gas filings
Effective July 1, 2003, the PSCU approved a $146.4 million pass-on increase in annual gas costs for Utah customers. Effective October 1, 2003, the PSCU approved a $43.4 million pass-on decrease in annual gas cost. The PSCW granted Questar Gas permission to pass on a $6.8 million increase in gas costs to Wyoming customers also effective July 1, 2003. Also, the PSCW approved a $1.7 million pass-on decrease effective October 1, 2003, due to falling gas costs. Pass-on rate increases or decreases result in equal adjustments of revenues and gas costs without affecting the earnings of Questar Gas.
Note 16 – Employees 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 (committee) has oversight over investment of retirement- plan and postretirement-benefit assets. The committee uses a third-party consultant to assist in setting targeted policy ranges for the allocation of assets among various investment categories. The Company changed its plan-asset and liability-measurement date from December 31 to October 31 in 2003. The majority of retirement-benefit assets were invested as follows:
Actual Allocation | |||
October 31, | December 31 | Policy | |
2003 | 2002 | Range | |
Domestic equity securities | 51% | 47% | 45% - 55% |
Foreign equity securities | 8% | 8% | 6% - 14% |
Debt securities | 33% | 40% | 32% - 42% |
Real estate securities | 5% | 5% | 3% - 7% |
Other | 3% | 0% | 0% - 3% |
Questar sets aside funds for retirement-benefit obligations to pay benefits currently due and to build adequate 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 the Employee Retirement Income Security Act (ERISA) and by the Internal Revenue Code. Subject to the above limitations, it is the Company’s objective to fund the qualified retirement plan approximately equal to the yearly expense. The majority of assets set aside for postretirement-benefit obligations are assets commingled with those of the Company’s ERISA-qualified retirement plan as permitted by section 401(h) of the Internal Revenue Code. The retirement plan (including commingled 401(h) assets within the plan) seeks investment returns consistent with reasonable and prudent levels of liquidity and risk.
The committee 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 committee 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, which are subject to guidelines specified by the committee. These guidelines are designed to ensure consistency with overall plan objectives.
The committee sets performance objectives for each investment manager, which 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 is 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 which have previously adopted permitting guidelines.
Pension Plan: Pension-plan benefits are generally 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. Continued lower interest rates resulted in the Company recording an additional pension liability of $28.7 million and a $14.7 million intangible-pension asset in 2003.
A summary of pension expense is as follows:
Year Ended December 31, | |||
2003 | 2002 | 2001 | |
(in thousands) | |||
Service cost | $7,608 | $6,770 | $7,038 |
Interest cost | 18,289 | 17,400 | 16,914 |
Expected return on plan assets | (17,758) | (18,187) | (17,065) |
Prior service and other costs | 1,922 | 1,922 | 1,978 |
Recognized net-actuarial (gain) loss | 904 | (16) | |
Amortization of early retirement costs | 3,241 | 3,504 | 3,504 |
Pension expense | $14,206 | $11,409 | $12,353 |
Assumptions at the beginning of the year used to calculate pension expense for the year were as follows: | |||
2003 | 2002 | 2001 | |
Discount rate | 7.00% | 7.50% | 7.75% |
Rate of increase in compensation | 4.00% | 4.50% | 5.00% |
Long-term return on assets | 8.50% | 9.00% | 9.25% |
The projected-benefit obligation was measured using a discount rate of 6.75% at October 31, 2003 and 7% at December 31 in 2002. 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.
October 31, | December 31, | |
Pension Plan | 2003 | 2002 |
(in thousands) | ||
Change in benefit obligation | ||
Projected benefit obligation at January 1, | $270,290 | $236,022 |
Service cost | 7,608 | 6,770 |
Interest cost | 18,289 | 17,400 |
Plan amendments | 178 | |
Change in plan assumptions | 11,046 | 19,946 |
Actuarial (gain) loss | (3,376) | 1,319 |
Benefits paid | (11,356) | (11,345) |
Projected benefit obligation at December 31, | 292,501 | 270,290 |
Change in plan assets | ||
Fair value of plan assets at January 1, | 173,202 | 188,761 |
Actual gain (loss) on plan assets | 31,057 | (15,623) |
Contributions to the plan | 14,206 | 11,409 |
Benefits paid | (11,356) | (11,345) |
Fair value of plan assets at December 31, | 207,109 | 173,202 |
Plan assets less-than-projected | ||
benefit obligation | (85,392) | (97,088) |
Unrecognized net-actuarial loss | 71,535 | 78,068 |
Unrecognized prior-service cost | 13,562 | 15,484 |
Accrued pension cost | (295) | (3,536) |
Accrued supplemental executive-retirement – | ||
plan cost | (2,641) | (3,408) |
Additional pension liability | (28,681) | (35,986) |
Pension liability | ($31,617) | ($42,930) |
The accumulated benefit obligation for the defined-benefit pension plan was $238.7 million and $216.1 million at December 31, 2003 and 2002.
Postretirement Benefits Other Than Pensions: 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. The Company is amortizing its transition obligation over a 20-year period, which began in 1992.
A summary of the expense of postretirement benefits other than pensions is listed below. Expenses do not include an estimate of the effect of the Medicare Prescription Drug, Improvement, Modernization Act of 2003. Future expenses will be adjusted when the accounting guidance is finalized.
Year Ended December 31, | |||
2003 | 2002 | 2001 | |
(in thousands) | |||
Service cost | $ 787 | $ 749 | $ 878 |
Interest cost | 5,303 | 5,351 | 5,686 |
Expected return on plan assets | (2,602) | (3,137) | (3,213) |
Amortization of transition obligation | 1,877 | 1,877 | 1,877 |
Amortization of losses | 481 | ||
Accretion of regulatory liability | 800 | 800 | 800 |
Postretirement benefit expense | $6,646 | $5,640 | $6,028 |
Assumptions at the beginning of the year used to calculate postretirement-benefit expense for the year were as follows:
2003 | 2002 | 2001 | |
Discount rate | 7.00% | 7.50% | 7.75% |
Long-term return on assets | 8.50% | 9.00% | 9.25% |
Health-care inflation rate decreasing to 6.5% | |||
by 2009 for 2003 purposes and by 2008 | |||
for measurements at 2002 and 2001 | 9.50% | 9.50% | 10.00% |
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 cost and interest cost by $173,000 and the accumulated postretirement benefit obligation by $2.5 million. A 1% decrease in the health-care inflation rate would decrease the yearly service cost and interest cost by $152,000 and the accumulated postretirement benefit obligation by $2.2 million.
October 31, | December 31, | |
2003 | 2002 | |
(in thousands) | ||
Postretirement Benefits Other Than Pensions | ||
Change in benefit obligation | ||
Projected benefit obligation at January 1, | $78,944 | $79,701 |
Service cost | 787 | 749 |
Interest cost | 5,303 | 5,351 |
Actuarial (gain) loss | 947 | (1,698) |
Benefits paid | (4,859) | (5,159) |
Projected benefit obligation | 81,122 | 78,944 |
Change in plan assets | ||
Fair value of plan assets at January 1, | 30,923 | 34,344 |
Actual gain (loss) on plan assets | 4,825 | (2,873) |
Contributions to the plan | 4,977 | 4,611 |
Benefits paid | (4,859) | (5,159) |
Fair value of plan assets at December 31, | 35,866 | 30,923 |
Projected benefit obligation in excess of plan assets | (45,256) | (48,021) |
Unrecognized transition obligation | 16,898 | 18,775 |
Unrecognized net loss | 13,970 | 15,727 |
Accrued postretirement-benefit cost | ($14,388) | ($13,519) |
Postemployment Benefits: The Company recognizes the net present value of the liability for postemployment benefits, such as long-term disability benefits and health-care and life-insurance costs, when employees become eligible for such benefits. Postemployment benefits are paid to former employees after employment has been terminated but before retirement benefits are paid. The Company accrues both current and future costs. Questar’s postemployment liability at December 31, 2003, 2002 and 2001 was $1.7 million, $1.5 million and $1.3 million, respectively.
Note 17 – 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 share in the results of 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 continues to hold and operate all oil-producing properties previously transferred from Questar Gas's nonutility accounts. The oil production 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. The after-tax rate of return is adjusted annually and is approximately 13.4%. 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%.
b. 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 18.4%. 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%.
c. Amounts received by Questar Gas from the sharing of Wexpro's oil income are used to reduce natural-gas costs to utility customers.
d. Wexpro conducts gas-development drilling on productive gas properties and bears any costs of dry holes. Natural gas produced from successful drilling is owned by Questar Gas. Wexpro is reimbursed for the costs of producing the gas plus a return on its investment in successful wells. The after-tax return allowed Wexpro is approximately 21.4%.
e. Wexpro operates natural-gas properties owned by 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 approximately 13.4%.
Wexpro's investment base, net of depreciation and deferred income taxes, and the yearly average rate of return for 2003 and the previous two years is shown in the table below:
2003 | 2002 | 2001 | |
Wexpro investment base, net of depreciation and | |||
deferred income taxes (in millions) | $172.8 | $164.5 | $161.3 |
Annual average rate of return (after tax) | 19.8% | 20.5% | 19.7% |
Note 18 – Operations by Line of Business | |||||||
Line-of-business disclosures and discussions were reorganized in 2003 and prior years to combine “Other Questar Regulated Services” information with Corporate and Other Operations. | |||||||
Following is a summary of operations by line of business for the Year Ended December 31: | |||||||
Corporate | |||||||
Questar | Intercompany | Market | Natural Gas | Natural Gas | and Other | ||
Consolidated | Transactions | Resources | Distribution | Transmission | Operations | ||
(in thousands) | |||||||
2003 | |||||||
Revenues | |||||||
From unaffiliated customers | $1,463,188 | $751,502 | $618,791 | $74,981 | $17,914 | ||
From affiliated companies | ($231,766) | 117,506 | 2,204 | 81,857 | 30,199 | ||
1,463,188 | (231,766) | 869,008 | 620,995 | 156,838 | 48,113 | ||
Operating expenses | |||||||
Cost of natural gas and other products | |||||||
sold | 542,441 | (199,209) | 342,476 | 394,523 | 4,651 | ||
Operating and maintenance | 284,266 | (30,358) | 130,680 | 100,279 | 53,249 | 30,416 | |
Depreciation, depletion and amortization | 192,382 | 121,316 | 40,126 | 26,141 | 4,799 | ||
Exploration | 4,498 | 4,498 | |||||
Distribution rate-refund obligation | 24,939 | 24,939 | |||||
Abandonment and impairment | |||||||
of gas and oil properties | 4,151 | 4,151 | |||||
Other taxes and expenses | 70,681 | (2,199) | 55,542 | 9,743 | 6,352 | 1,243 | |
Total operating expenses | 1,123,358 | (231,766) | 658,663 | 569,610 | 85,742 | 41,109 | |
Operating income | 339,830 | 210,345 | 51,385 | 71,096 | 7,004 | ||
Interest and other income (loss) | 7,435 | (3,435) | 2,851 | 3,228 | (426) | 5,217 | |
Income from unconsol. affiliates | 5,008 | 5,008 | |||||
Minority interest | 222 | 183 | 39 | ||||
Debt expense | (70,736) | 3,435 | (28,158) | (20,984) | (22,622) | (2,407) | |
Income tax expense | (102,563) | (69,126) | (13,113) | (17,746) | (2,578) | ||
Income before accounting change | 179,196 | 121,103 | 20,516 | 30,302 | 7,275 | ||
Cumulative effect of accounting | |||||||
change for asset retirement obligations | (5,580) | (5,113) | (334) | (133) | |||
Net income | $173,616 | $115,990 | $20,182 | $30,169 | $7,275 | ||
Identifiable assets | $3,309,055 | $1,612,208 | $884,478 | $746,535 | $65,834 | ||
Investment in unconsol. affiliates | 36,393 | 36,393 | |||||
Capital expenditures | 335,416 | 238,131 | 71,523 | 22,354 | 3,408 | ||
2002 | |||||||
Revenues | |||||||
From unaffiliated customers | $1,200,667 | $522,476 | $593,835 | $66,275 | $18,081 | ||
From affiliated companies | ($217,067) | 106,647 | 1,676 | 76,600 | 32,144 | ||
1,200,667 | (217,067) | 629,123 | 595,511 | 142,875 | 50,225 | ||
Operating expenses | |||||||
Cost of natural gas and other products | |||||||
Sold | 395,742 | (183,051) | 202,132 | 370,294 | 6,367 | ||
Operating and maintenance | 284,317 | (32,340) | 131,598 | 105,544 | 49,593 | 29,922 | |
Depreciation, depletion and amortization | 184,952 | 117,446 | 39,771 | 22,149 | 5,586 | ||
Exploration | 6,086 | 6,086 | |||||
Abandonment and impairment of gas and | |||||||
oil and other properties | 11,183 | 11,183 | |||||
Other taxes and expenses | 44,192 | (1,676) | 30,234 | 9,548 | 4,948 | 1,138 | |
Total operating expenses | 926,472 | (217,067) | 498,679 | 525,157 | 76,690 | 43,013 | |
Operating income | 274,195 | 130,444 | 70,354 | 66,185 | 7,212 | ||
Interest and other income | 56,667 | (6,058) | 50,894 | 2,329 | 515 | 8,987 | |
Income from unconsol. affiliates | 11,777 | 3,977 | 7,800 | ||||
Minority interest | 501 | 484 | 17 | ||||
Debt expense | (81,121) | 6,058 | (34,705) | (22,495) | (23,995) | (5,984) | |
Income tax expense | (91,126) | (53,165) | (17,789) | (17,897) | (2,275) | ||
Income before accounting change | 170,893 | 97,929 | 32,399 | 32,608 | 7,957 | ||
Cumulative effect of accounting | |||||||
change for goodwill | (15,297) | (15,297) | |||||
Net income (loss) | $155,596 | $97,929 | $32,399 | $32,608 | ($7,340) | ||
Identifiable assets | $3,067,850 | $1,415,871 | $831,411 | $744,855 | $75,713 | ||
Investment in unconsol. affiliates | 23,617 | 23,617 | |||||
Capital expenditures | 357,800 | 189,360 | 69,405 | 95,098 | 3,937 | ||
2001 | |||||||
Revenues | |||||||
From unaffiliated customers | $1,439,350 | $645,867 | $701,150 | $49,402 | $42,931 | ||
From affiliated companies | ($209,891) | 100,530 | 2,963 | 75,491 | 30,907 | ||
1,439,350 | (209,891) | 746,397 | 704,113 | 124,893 | 73,838 | ||
Operating expenses | |||||||
Cost of natural gas and other products | |||||||
Sold | 675,011 | (175,811) | 324,124 | 498,545 | 28,153 | ||
Operating and maintenance | 270,355 | (31,195) | 112,087 | 103,427 | 47,244 | 38,792 | |
Depreciation, depletion and amortization | 151,735 | 92,678 | 35,030 | 15,407 | 8,620 | ||
Exploration | 6,986 | 6,986 | |||||
Abandonment and impairment of gas | |||||||
and oil properties | 5,171 | 5,171 | |||||
Other taxes and expenses | 55,985 | (2,885) | 46,010 | 8,729 | 2,920 | 1,211 | |
Total operating expenses | 1,165,243 | (209,891) | 587,056 | 645,731 | 65,571 | 76,776 | |
Operating income (loss) | 274,107 | 159,341 | 58,382 | 59,322 | (2,938) | ||
Interest and other income | 35,298 | (12,034) | 17,259 | 5,158 | 5,950 | 18,965 | |
Income (loss) from unconsol. affiliates | 159 | 1,265 | (1,106) | ||||
Minority interest | 1,725 | 359 | 1,366 | ||||
Debt expense | (64,833) | 12,034 | (22,872) | (23,777) | (16,908) | (13,310) | |
Income tax expense | (88,270) | (54,218) | (13,890) | (17,517) | (2,645) | ||
Net income | $158,186 | $101,134 | $25,873 | $29,741 | $1,438 | ||
Identifiable assets | $3,244,496 | $1,516,022 | $833,268 | $775,659 | $119,547 | ||
Investment in unconsol. affiliates | 144,928 | 23,829 | 121,099 | ||||
Capital expenditures | 984,086 | 638,507 | 78,791 | 256,703 | 10,085 | ||
Market Resources had subsidiaries that conducted gas and oil exploration and production activities in western Canada. These subsidiaries were sold in the fourth quarter of 2002. Canadian operations reported revenues, measured in U. S. dollars, totaling $21.7 million and $38.5 million for the years ended December 31, 2002, and 2001, respectively.
Note 19 – Quarterly Financial and Stock-Price Information (Unaudited) | ||||||
Following is a summary of quarterly financial and stock-price data: | ||||||
First | Second | Third | Fourth | |||
Quarter | Quarter | Quarter | Quarter | Year | ||
(dollars in thousands, except per-share amounts) | ||||||
2003 | ||||||
Revenues | $469,804 | $270,669 | $273,503 | $449,212 | $1,463,188 | |
Operating income | 127,875 | 45,895 | 58,845 | 107,215 | 339,830 | |
Income before accounting change | 70,202 | 20,272 | 28,691 | 60,031 | 179,196 | |
Net income | 64,622 | 20,272 | 28,691 | 60,031 | 173,616 | |
Basic earnings per common share | ||||||
Income before accounting change | $0.86 | $0.24 | $0.35 | $0.72 | $2.17 | |
Net income | 0.79 | 0.24 | 0.35 | 0.72 | 2.10 | |
Diluted earnings per common share | ||||||
Income before accounting change | $0.84 | $0.24 | $0.34 | $0.71 | $2.13 | |
Net income | 0.77 | 0.24 | 0.34 | 0.71 | 2.06 | |
Dividends per common share | 0.185 | 0.185 | 0.205 | 0.205 | 0.78 | |
Market price per common share | ||||||
High | $29.85 | $34.12 | $33.99 | $35.50 | $35.50 | |
Low | 26.04 | 29.35 | 30.11 | 30.75 | 26.04 | |
Close | $29.57 | $33.47 | $30.81 | $35.15 | $35.15 | |
Price-earnings ratio on closing price | 17.1 | |||||
Annualized dividend yield on closing price | 2.5% | 2.2% | 2.7% | 2.3% | 2.2% | |
Market-to-book ratio on closing price | 2.32 | |||||
Average number of common shares traded per day (000) | 220 | 266 | 211 | 228 | 231 | |
First | Second | Third | Fourth | |||
Quarter | Quarter | Quarter | Quarter | Year | ||
(dollars in thousands, except per-share amounts) | ||||||
2002 | ||||||
Revenues | $402,533 | $224,614 | $190,670 | $382,850 | $1,200,667 | |
Operating income | 90,205 | 53,391 | 46,179 | 84,420 | 274,195 | |
Income before accounting change | 50,152 | 29,371 | 23,357 | 68,013 | 170,893 | |
Net income | 34,855 | 29,371 | 23,357 | 68,013 | 155,596 | |
Basic earnings per common share | ||||||
Income before accounting change | $0.62 | $0.36 | $0.28 | $0.83 | $2.09 | |
Net income | 0.43 | 0.36 | 0.28 | 0.83 | 1.90 | |
Diluted earnings per common share | ||||||
Income before accounting change | $0.61 | $0.36 | $0.28 | $0.82 | $2.07 | |
Net income | 0.42 | 0.36 | 0.28 | 0.82 | 1.88 | |
Dividends per common share | 0.18 | 0.18 | 0.18 | 0.185 | 0.725 | |
Market price per common share | ||||||
High | $25.84 | $29.45 | $25.61 | $28.39 | $29.45 | |
Low | 21.40 | 23.65 | 18.01 | 21.41 | 18.01 | |
Close | $25.71 | $24.70 | $22.84 | $27.82 | $27.82 | |
Price-earnings ratio on closing price | 14.8 | |||||
Annualized dividend yield on closing price | 2.8% | 2.9% | 3.2% | 2.7% | 2.7% | |
Market-to-book ratio on closing price | 2.00 | |||||
Average number of common shares traded per day (000) | 250 | 261 | 230 | 231 | 243 | |
2001 | |||||
Revenues | $562,638 | $285,138 | $225,142 | $366,432 | $1,439,350 |
Operating income | 110,386 | 49,049 | 47,045 | 67,627 | 274,107 |
Net income | 69,260 | 24,503 | 21,842 | 42,581 | 158,186 |
Basic earnings per common share | $0.86 | $0.30 | $0.27 | $0.52 | $1.95 |
Diluted earnings per common share | 0.85 | 0.30 | 0.27 | 0.52 | 1.94 |
Dividends per common share | 0.175 | 0.175 | 0.175 | 0.18 | 0.705 |
Market price per common share | |||||
High | $29.95 | $33.75 | $25.12 | $25.48 | $33.75 |
Low | 26.35 | 24.00 | 18.58 | 19.60 | 18.58 |
Close | $27.40 | $24.76 | $20.18 | $25.05 | $25.05 |
Price-earnings ratio on closing price | 12.9 | ||||
Annualized dividend yield on closing price | 2.6% | 2.8% | 3.5% | 2.8% | 2.8% |
Market-to-book ratio on closing price | 1.89 | ||||
Average number of common shares traded per day (000) | 221 | 314 | 275 | 199 | 252 |
Note 20 – 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 managed and developed by Wexpro.
Nonregulated Activities
This information pertains to nonregulated gas and oil activities. Cost-of-service activities are presented in a separate section of this note.
Gas and Oil Exploration and Development Activities: The following information is provided with respect to Questar's gas and oil exploration and development activities, which are located exclusively in the United States. The Company sold its Canadian subsidiary in the fourth quarter of 2002.
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. Future abandonment costs associated with asset-retirement obligations amounted to $23.5 million at December 31, 2003, and are included in proved properties.
December 31, | ||||||
2003 | 2002 | |||||
(in thousands) | ||||||
Proved properties Unproved properties Support equipment and facilities Accumulated depreciation, depletion and Amortization | $1,315,330 | $1,103,686 | ||||
95,208 | 131,817 | |||||
22,569 | 29,571 | |||||
1,433,107 | 1,265,074 | |||||
501,825 | 424,392 | |||||
$ 931,282 | $840,682 | |||||
Costs Incurred
The costs incurred in gas and oil exploration and development activities are displayed in the table below. The costs incurred to develop booked proved-undeveloped reserves amounted to $55.3 million, $51.1 million and $20.7 million in 2003, 2002 and 2001, respectively.
Total | United States | Canada | Total | |||
2003 | 2002 | |||||
(in thousands) | ||||||
Property acquisition | ||||||
Unproved | $ 3,779 | $1,092 | $119 | $1,211 | ||
Proved | 1,039 | 45 | 45 | |||
Exploration | 13,521 | 10,372 | 627 | 10,999 | ||
Development | 155,226 | 121,763 | 3,268 | 125,031 | ||
Development asset-retirement obligations | 1,616 | |||||
$175,181 | $133,272 | $4,014 | $137,286 | |||
United States | Canada | Total | ||||
2001 | ||||||
(in thousands) | ||||||
Property acquisition | ||||||
Unproved | $1,309 | $318 | $1,627 | |||
Proved | 303,757 | 303,757 | ||||
Exploration | 14,063 | 1,755 | 15,818 | |||
Development | 130,638 | 5,256 | 135,894 | |||
$449,767 | $7,329 | $457,096 | ||||
Results of Operations
Following are the results of operations of Market Resources' gas and oil exploration and development activities, before corporate overhead and interest expenses.
Total | United States | Canada | Total | |
2003 | 2002 | |||
(in thousands) | ||||
Revenues | ||||
From unaffiliated customers | $343,894 | $249,239 | $21,694 | $270,933 |
From affiliates | 1,172 | 1,172 | ||
Total revenues | 343,894 | 250,411 | 21,694 | 272,105 |
Production expenses | 76,380 | 62,625 | 6,924 | 69,549 |
Exploration | 4,498 | 5,459 | 627 | 6,086 |
Depreciation, depletion and amortization | 88,901 | 81,473 | 7,415 | 88,888 |
Accretion expense (asset-retirement obligations) | 1,852 | |||
Abandonment and impairment of gas, | ||||
oil and related properties | 4,151 | 11,030 | 153 | 11,183 |
Total expenses | 175,782 | 160,587 | 15,119 | 175,706 |
Revenues less expenses | 168,112 | 89,824 | 6,575 | 96,399 |
Income taxes - Note A | 61,698 | 27,247 | 4,228 | 31,475 |
Results of operations before corporate | ||||
overhead, interest expenses and cumulative | ||||
effect of accounting change | 106,414 | 62,577 | 2,347 | 64,924 |
Cumulative effect of accounting change | ||||
for asset retirement obligations | (4,550) | |||
Results of operations before corporate | ||||
overhead and interest expenses | $101,864 | $62,577 | $2,347 | $64,924 |
United States | Canada | Total | |
2001 | |||
(in thousands) | |||
Revenues | |||
From unaffiliated customers | $242,081 | $38,495 | $280,576 |
From affiliates | 807 | 807 | |
Total revenues | 242,888 | 38,495 | 281,383 |
Production expenses | 62,646 | 8,106 | 70,752 |
Exploration | 5,236 | 1,785 | 7,021 |
Depreciation, depletion and amortization | 58,537 | 12,064 | 70,601 |
Abandonment and impairment of gas | |||
and oil properties | 3,571 | 1,600 | 5,171 |
Total expenses | 129,990 | 23,555 | 153,545 |
Revenues less expenses | 112,898 | 14,940 | 127,838 |
Income taxes - Note A | 37,348 | 9,323 | 46,671 |
Results of operations before corporate | |||
overhead and interest expenses | $75,550 | $5,617 | $81,167 |
Note A - Income tax expenses have been reduced by nonconventional fuel-tax credits of $4.9 million in 2002 and $5 million in 2001. The availability of these credits ended after December 31, 2002.
Estimated Quantities of Proved Gas and Oil Reserves
The table below shows the estimated proved reserves owned by the Company. Estimates of U.S. reserves were prepared by Ryder Scott Company, H. J. Gruy and Associates, Inc., and Netherland, Sewell & Associates, independent reservoir engineers. 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. The quantities reported below are based on existing economic and operating conditions at December 31. All gas and oil reserves reported were located in the United States and Canada. Canadian properties were sold in the fourth quarter of 2002. The Company does not have any long-term supply contracts with foreign governments or reserves of equity investees.
Natural Gas | Oil | |||||
United States | Canada | Total | United States | Canada | Total | |
(MMcf) | (Mbbl) | |||||
Proved Reserves | ||||||
Balance at January 1, 2001 | 579,833 | 60,056 | 639,889 | 11,316 | 3,718 | 15,034 |
Revisions of estimates | (36,528) | 1,341 | (35,187) | (1,950) | (21) | (1,971) |
Extensions and discoveries | 175,423 | 7,144 | 182,567 | 1,515 | 340 | 1,855 |
Purchase of reserves in place | 300,353 | 300,353 | 19,185 | 19,185 | ||
Sale of reserves in place | (19,072) | (19,072) | (531) | (531) | ||
Production | (63,862) | (6,712) | (70,574) | (1,797) | (703) | (2,500) |
Balance at December 31, 2001 | 936,147 | 61,829 | 997,976 | 27,738 | 3,334 | 31,072 |
Revisions of estimates | (108,570) | 701 | (107,869) | (800) | 122 | (678) |
Extensions and discoveries | 240,872 | 1,712 | 242,584 | 2,812 | 26 | 2,838 |
Purchase of reserves in place | 42 |
| 42 |
|
| |
Sale of reserves in place | (43,220) | (59,433) | (102,653) | (270) | (3,028) | (3,298) |
Production | (74,865) | (4,809) | (79,674) | (2,310) | (454) | (2,764) |
Balance at December 31, 2002 | 950,406 | 950,406 | 27,170 | 27,170 | ||
Revisions of estimates | 14,057 | 14,057 | 445 | 445 | ||
Extensions and discoveries | 111,575 | 111,575 | 1,285 | 1,285 | ||
Purchase of reserves in place | 2,098 | 2,098 | 8 | 8 | ||
Sale of reserves in place | (152) | (152) | (3) | (3) | ||
Production | (78,811) | (78,811) | (2,324) | (2,324) | ||
Balance of December 31, 2003 | 999,173 | 999,173 | 26,581 | 26,581 | ||
Proved-Developed Reserves | ||||||
Balance at January 1, 2001 | 434,122 | 55,623 | 489,745 | 9,696 | 3,077 | 12,773 |
Balance at December 31, 2001 | 534,761 | 53,036 | 587,797 | 19,417 | 2,566 | 21,983 |
Balance at December 31, 2002 | 540,333 | 540,333 | 19,942 | 19,942 | ||
Balance at December 31, 2003 | 612,181 | 612,181 | 20,504 | 20,504 |
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 $5.57 in 2003, $3.34 in 2002 and $2.19 in 2001. The average year-end price per barrel of proved oil and NGL reserves combined was $30.45 in 2003, $28.46 in 2002 and $18.38 in 2001. 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. The statutes allowing income tax credits for nonconventional fuels expired for production after December 31, 2002. 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 $80.7 million, $91.1 million and $91.6 million in 2004, 2005 and 2006, respectively. At the end of this three-year period we expect to have evaluated about 80% 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.
Total | Total | United States | Canada | Total | |
Year Ended December 31, | 2003 | 2002 | 2001 | ||
(in thousands) | |||||
Future cash inflows | $6,378,076 | $3,951,706 | $2,541,716 | $192,762 | $2,734,478 |
Future production costs | (1,403,893) | (1,049,205) | (798,431) | (58,643) | (857,074) |
Future development costs | (338,245) | (326,169) | (266,097) | (3,421) | (269,518) |
Future asset-retirement obligations | (96,187) | ||||
Future income tax expenses | (1,514,814) | (768,402) | (392,152) | (38,767) | (430,919) |
Future net cash flows | 3,024,937 | 1,807,930 | 1,085,036 | 91,931 | 1,176,967 |
10% annual discount to reflect | |||||
timing of net cash flows | (1,494,924) | (908,304) | (536,876) | (35,789) | (572,665) |
Standardized measure of discounted | |||||
future net cash flows | $1,530,013 | $899,626 | $548,160 | $56,142 | $604,302 |
The principal sources of change in the standardized measure of discounted future net cash flows were:
Year Ended December 31, | |||
2003 | 2002 | 2001 | |
(in thousands) | |||
Beginning balance | $ 899,626 | $604,302 | $1,717,688 |
Sales of gas and oil produced, net | |||
of production costs | (267,514) | (202,556) | (210,631) |
Net changes in prices and | |||
production costs | 820,919 | 535,840 | (1,978,853) |
Extensions and discoveries, less | |||
related costs | 235,891 | 298,082 | 133,866 |
Revisions of quantity estimates | 33,092 | (128,917) | (31,451) |
Purchase of reserves in place | 1,039 | 45 | 303,757 |
Sale of reserves in place | (8,610) | (126,485) | (41,225) |
Change in future development | 7,448 | (12,128) | (70,979) |
Accretion of discount | 89,963 | 60,430 | 171,769 |
Net change in income taxes | (345,600) | (138,387) | 775,013 |
Change in production rate | 21,091 | (11,229) | (125,725) |
Asset-retirement obligations and other | 42,668 | 20,629 | (38,927) |
Net change | 630,387 | 295,324 | (1,113,386) |
Ending balance | $1,530,013 | $899,626 | $604,302 |
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. Future abandonment costs associated with asset-retirement obligations amounted to $8.2 million at December 31, 2003.
December 31, | |||
2003 | 2002 | 2001 | |
(in thousands) | |||
Wexpro | $233,947 | $204,157 | $198,373 |
Questar Gas | 17,194 | 18,915 | 20,991 |
$251,141 | $223,072 | $219,364 | |
Costs Incurred
Costs incurred by Wexpro for cost-of-service gas and oil producing activities were $36.6 million, including $295,000 associated with asset-retirement obligation in 2003, $26.7 million in 2002 and $58.5 million in 2001.
Results of Operations
Following are the results of operations of the Wexpro’s cost-of-service gas and oil-development activities, before corporate overhead and interest expenses.
Year Ended December 31, | |||
2003 | 2002 | 2001 | |
(in thousands) | |||
Revenues | |||
From unaffiliated companies | $ 13,006 | $8,699 | $12,465 |
From affiliates – Note A | 101,596 | 94,827 | 88,936 |
Total revenues | 114,602 | 103,526 | 101,401 |
Production expenses | 32,341 | 23,032 | 33,016 |
Depreciation and amortization | 20,169 | 20,475 | 15,051 |
Accretion expense (asset-retirement obligations) | 183 | ||
Total expenses | 52,693 | 43,507 | 48,067 |
Year Ended December 31, | |||
2003 | 2002 | 2001 | |
(in thousands) | |||
Revenues less expenses | $61,909 | $60,019 | $53,334 |
Income taxes | 22,252 | 21,572 | 19,181 |
Results of operations before corporate | |||
overhead, interest expenses and | |||
cumulative effect of accounting change | 39,657 | 38,447 | 34,153 |
Cumulative effect of accounting change | |||
for asset-retirement obligations | (563) | ||
Results of operations before corporate | |||
overhead and interest expense | $39,094 | $38,447 | $34,153 |
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
The following estimates were made by the Company's reservoir engineers.
Natural Gas | Oil | |
(MMcf) | (Mbbl) | |
Proved Reserves | ||
Balance at January 1, 2001 | 379,011 | 3,448 |
Revisions of estimates | (11,465) | 275 |
Extensions and discoveries | 76,042 | 479 |
Production | (37,907) | (515) |
Balance at December 31, 2001 | 405,681 | 3,687 |
Revisions of estimates | (658) | (122) |
Extensions and discoveries | 56,085 | 675 |
Production | (41,208) | (501) |
Balance at December 31, 2002 | 419,900 | 3,739 |
Revisions of estimates | 24,273 | 103 |
Extensions and discoveries | 30,286 | 187 |
Production | (40,088) | (449) |
Balance at December 31, 2003 | 434,371 | 3,580 |
Proved-Developed Reserves | ||
Balance at January 1, 2001 | 362,748 | 3,318 |
Balance at December 31, 2001 | 400,461 | 3,640 |
Balance at December 31, 2002 | 395,821 | 3,481 |
Balance at December 31, 2003 | 406,144 | 3,330 |
ITEM 15. EXHIBITS AND REPORTS ON FORM 8-K.
Financial statements and financial statement schedules filed as part of this report are listed in the index included in Item 8. Financial Statements and Supplementary Data of this report.
(a)(3) Exhibits. The following is a list of exhibits required to be filed as a part of this report in Item 15(c).
Exhibit No.
Description
31.1.
Certification signed by Keith O. Rattie, Questar's Chief Executive Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Securities and Exchange Act of 1934, as amended ("Exchange Act").
31.2.
Certification signed by S. E. Parks, Questar's Chief Financial Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Exchange Act.
32.
Certification signed by Keith O. Rattie and S. E. Parks, Questar's Chief Executive and Chief Financial Officer, respectively, pursuant to Section 906 of the Sarbanes Oxley Act of 2002.
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 24th day of May, 2004
QUESTAR CORPORATION
(Registrant)
By /s/Keith O. Rattie
Keith O. Rattie
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
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)
*Teresa Beck
Director
*P. S. Baker, Jr.
Director
*R. D. Cash
Director
*P. J. Early
Director
*L. Richard Flury
Director
*J. A. Harmon
Director
*Robert E. Kadlec
Director
* Robert E. McKee III
Director
*Gary G. Michael
Director
*Keith O. Rattie
Director
*Harris H. Simmons
Director
*C. B. Stanley
Director
May 24, 2004
*By /s/Keith O. Rattie
Date
Keith O. Rattie, Attorney in Fact
Exhibit List
Exhibit
Number
Description
31.1.
Certification signed by Keith O. Rattie, Questar's Chief Executive Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Securities and Exchange Act of 1934, as amended ("Exchange Act").
31.2.
Certification signed by S. E. Parks, Questar's Chief Financial Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Exchange Act.
32.
Certification signed by Keith O. Rattie and S. E. Parks, Questar's Chief Executive and Chief Financial Officer, respectively, pursuant to Section 906 of the Sarbanes Oxley Act of 2002.
Exhibit No. 31.1
CERTIFICATION |
I, Keith O. Rattie, certify that: |
1. | I have reviewed this annual report on Form 10-K for 2003 of Questar Corporation; |
2. | Based on my knowledge, this annual 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 annual 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; |
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; and |
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. |
May 24, 2004 Date | By: /s/Keith O. Rattie Keith O. Rattie | |
Exhibit No. 31.2
CERTIFICATION |
I, S. E. Parks, certify that: |
1. | I have reviewed this annual report on Form 10-K for 2003 of Questar Corporation; |
2. | Based on my knowledge, this annual 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 annual 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; |
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; and |
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. |
May 24, 2004 Date | By: /s/S. E. Parks S. E. Parks | |
Exhibit 32. | ||
CERTIFICATION PURSUANT TO | ||
In connection with the Annual Report of Questar Corporation (the "Company") on Form 10-K for 2003, as filed with the Securities and Exchange Commission on the date hereof (the "Report"), Keith O. Rattie, President and Chief Executive Officer of the Company, and S. E. Parks, Senior Vice President, Treasurer 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: | ||
(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 result of operations of the Company. | ||
QUESTAR CORPORATION | ||
May 24, 2004 | By /s/Keith O. Rattie Keith O. Rattie | |
May 24, 2004 | By /s/S. E. Parks S. E. Parks | |
This certification accompanies the Report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and shall not, except to the extent required by the Sarbanes-Oxley Act of 2002, be deemed filed by the Company for purposes of Section 18 of the Securities Exchange Act of 1934, as amended. | ||