UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
Form 10-Q
[X] | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED June 30, 2004. | |
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 Number 1-8796
QUESTAR CORPORATION | ||||
(Exact name of registrant as specified in its charter) | ||||
State of Utah | 87-0407509 | |||
| ||||
P.O. Box 45433 | 84145-0433 | |||
(801) 324-5000
(Registrant's telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. | |||
Yes [X] | No [ ] | ||
Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). | |||
Yes [X] | No [ ] | ||
Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date. | |||
Class | Outstanding as of July 31, 2004 | |
Common Stock, without par value with attached Common Stock Purchase Rights | 83,993,426 Shares |
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Questar Corporation
Form 10-Q for the Quarterly Period Ended June 30, 2004
TABLE OF CONTENTS
Page
PART I.
FINANCIAL INFORMATION
Item 1.
Financial Statements
Consolidated Statements of Income
6
Condensed Consolidated Balance Sheets
8
Condensed Consolidated Statements of Cash Flows
9
Notes Accompanying Consolidated Financial Statements
10
Item 2.
Management’s Discussion and Analysis of Financial Condition and
15
Item 3.
Quantitative and Qualitative Disclosures about Market Risk
27
Item 4.
29
PART II.
OTHER INFORMATION
Item 1.
Item 2.
Changes in Securities, Use of Proceeds and Issuer Purchases of Equity
Item 4.
Submission of Matters to a Vote of Security Holders
Item 5.
Item 6.
Exhibits and Reports on Form 8-K
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Glossary of Commonly Used Terms
bbl
Barrel, which is equal to 42 United States gallons and is a common unit of measurement of crude oil.
basis
The difference between a reference or benchmark commodity price and the corresponding selling prices at various regional sales points.
bcf
One billion cubic feet, a common unit of measurement of natural gas.
bcfe
One billion cubic feet of natural gas equivalent. Oil volume is converted to natural gas equivalent using the ratio of one barrel of crude oil to 6,000 cubic feet of natural gas.
Btu
One British Thermal Unit – a measure of the amount of energy required to raise the temperature of one pound of water one degree Fahrenheit.
cash flow hedge
A derivative instrument that complies with Statement of Financial Accounting Standards (“SFAS”) 133, as amended, and is used to reduce the exposure to variability in cash flows from the forecasted physical sale of gas and oil production whereby the gains (losses) on the derivative transaction are anticipated to offset the losses (gains) on the forecasted physical sale.
degree days
A measure of the number of degrees the average daily outside temperature is above or below 65 degrees Fahrenheit.
development well
A well drilled into a known producing formation in a previously discovered field.
dew point
A specific temperature and pressure at which hydrocarbons condense to form a liquid.
dry hole
A well drilled and found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.
dth
Decatherms or ten therms. One dth equals one million Btu or approximately one Mcf.
exploratory well
A well drilled into a previously untested geologic structure to determine the presence of gas or oil.
futures contract
An exchange-traded legal contract to buy or sell a standard quantity and quality of a commodity at a specified future date and price.
gross
“Gross” natural gas and oil wells or “gross” acres equals the total number of wells or acres in which the Company has an interest.
hedging
The use of derivative commodity and interest rate instruments to reduce financial exposure to commodity price and interest rate volatility.
Mbbl
One thousand barrels.
Mcf
One thousand cubic feet.
Mcfe
One thousand cubic feet of natural gas equivalents.
Mdth
One thousand decatherms.
Mdthe
One thousand decatherm equivalents.
MMbbl
One million barrels.
MMBtu
One million British Thermal Units.
MMcf
One million cubic feet.
MMcfe
One million cubic feet of natural gas equivalents
MMdth
One million decatherms.
natural gas liquids
Liquid hydrocarbons that are extracted and separated from the natural gas stream. NGL
(NGL)
stream. NGL products include ethane, propane, butane, natural gasoline and heavier hydrocarbons.
net
“Net” gas and oil wells or “net” acres are determined by multiplying gross wells or acres by the Company’s working interest in those wells or acres.
proved reserves
“Proved reserves” means those quantities of natural gas and crude oil, condensate, and natural gas liquids on a net revenue interest basis, which geological and engineering data demonstrate with reasonable certainty to be recoverable under existing economic and operating conditions. “Proved developed reserves” include proved developed producing reserves and proved developed behind-pipe reserves. “Proved developed producing reserves” include only those reserves expected to be recovered from existing completion intervals in existing wells. “Proved undeveloped reserves” include those reserves expected to be recovered from new wells on proved undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.
reservoir
A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.
wet gas
Unprocessed natural gas that contains a mixture of heavier hydrocarbons including ethane, propane, butane, and natural gasoline.
working interest
An interest that gives the owner the right to drill, produce, and conduct operating activities on a property and receive a share of any production.
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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. 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 Questar Corporation’s (“Questar” or the “Company”) 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 estimated quantities of gas and oil reserves. Gas and oil reserve estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves, the projection of future rates of production and the timing of development expenditures. The accuracy of these estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Reserve estimates are imprecise and should be expected to change as additional information becomes available. Estimates of economically recoverable reserves and of future net cash flows prepared by different engineers or by the same engineers at different times may vary significantly. Results of subsequent drilling, testing and production may cause either upward or downward revisions of previous estimates. In addition the estimates of future net revenues from proved reserves and the present value of those reserves are based upon certain assumptions about production levels, prices and costs, which may not be correct. The volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. The meaningfulness of such estimates is highly dependent upon the accuracy of the assumptions upon which they were based. Actual results may differ materially from the results estimated. Questar Exploration and Production’s (“Questar E&P”) reserves are prepared on an annual basis by independent reservoir engineers.
Presence of wildlife and potential endangered species could limit access to public lands. Various wildlife species occupy portions of Questar Market Resources (“Market Resources”) leasehold at Pinedale and in other areas. Current federal regulations restrict activities during certain times of the year on portions of Market Resources’ leasehold due to wildlife activity and/or habitat. Some species that are known to be present, such as the sage grouse, may in the future be listed under federal law as endangered or threatened species. Such listing could have a material impact on access to Market Resources’ leasehold in certain areas or during periods when the particular species is found to be present.
Changes in gas and oil prices. The sale of gas and oil production is a commodity-based business subject to pricing influenced by regional factors. Market Resources has established policies and procedures for managing commodity-price risks through the use of derivatives. Market Resources hedges commodity prices to support credit ratings, returns on invested capital, cash-flow targets, and protect earnings from downward movements in commodity prices. However these arrangements usually limit future gains from favorable price movements.
Other important assumptions: changes in general economic conditions; changes in regulatory policies; regulation of the Wexpro Agreement; availability and economic viability of gas and oil properties for sale or exploration; creditworthiness of counterparties; rate of inflation and interest rates; assumptions used in business combinations; weather and natural disasters; effects of environmental and other regulation; changes in customers' credit ratings; competition from other forms of energy, other pipelines and storage facilities; effects of accounting policies issued periodically by accounting standard-setting bodies; terrorist attacks or acts of war; changes in the business or financial condition of the Company; and changes in credit ratings and availability of financing for Questar and/or its subsidiaries.
#
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3 Months Ended | 6 Months Ended | 12 Months Ended | ||||
June 30, | June 30, | June 30, | ||||
2004 | 2003 | 2004 | 2003 | 2004 | 2003 | |
(in thousands, except per share amounts) | ||||||
DILUTED EARNINGS PER COMMON SHARE | ||||||
Income before cumulative effect | $ 0.50 | $ 0.24 | $ 1.39 | $ 1.08 | $ 2.44 | $ 2.19 |
Cumulative effect | (0.07) | (0.07) | ||||
Net income | $ 0.50 | $ 0.24 | $ 1.39 | $ 1.01 | $ 2.44 | $ 2.12 |
Weighted average common shares outstanding | ||||||
Used in basic calculation | 83,651 | 82,678 | 83,511 | 82,453 | 83,263 | 82,144 |
Used in diluted calculation | 85,445 | 84,274 | 85,305 | 83,866 | 84,945 | 83,212 |
Dividends per common share | $ 0.215 | $ 0.185 | $ 0.42 | $ 0.37 | $ 0.83 | $ 0.735 |
See notes accompanying consolidated financial statements | ||||||
#
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NOTES ACCOMPANYING CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2004
(Unaudited)
Note 1 – Basis of Presentation of Interim Financial Statements
The accompanying interim consolidated financial statements of Questar, with the exception of the condensed consolidated balance sheet at December 31, 2003, have not been audited by independent public accountants. The interim financial statements reflect all normal, recurring adjustments that are, in the opinion of management, necessary for a fair presentation of the results of operations for the interim periods presented. The preparation of financial statements in conformity with accounting principles generally accepted (“GAAP”) 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 estimates. All significant intercompany accounts and transactions were eliminated in consolidation.
The results of operations for the three-, six- and twelve-month periods ended June 30, 2004, are not necessarily indicative of the results that may be expected for the year ending December 31, 2004, due to the seasonal nature of the gas-distribution business. The impact of abnormal weather on gas-distribution earnings is significantly reduced by the operation of a weather-normalization adjustment. The straight fixed-variable rate design, which allows for recovery of substantially all fixed costs in the demand or reservation charges, reduces the earnings impact of weather conditions on gas-transportation and storage operations. Interim financial statements do not include all of the information and notes required by GAAP for audited annual financial statements. For further information please refer to the consolidated financial statements and notes included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2003, that was filed by Questar.
Note 2 – Asset-Retirement Obligations (“ARO”)
On January 1, 2003, Questar adopted SFAS 143 “Accounting for Asset Retirement Obligations.” SFAS 143 addresses the financial accounting and reporting of the fair value of legal obligations associated with the retirement of tangible long-lived assets. The fair value of abandonment costs are estimated and depreciated over the life of the related assets. ARO are adjusted to present value each period through an accretion calculation 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 non-cash expenses until the time that the asset is retired.
Changes in asset-retirement obligations were as follows.
2004 | 2003 | |
(in thousands) | ||
Balance at January 1, | $61,358 | $56,493 |
Accretion | 949 | 1,700 |
Additions | 869 | 606 |
Revisions | 695 | |
Retirements | (262) | (578) |
Balance at June 30, | $63,609 | $58,221 |
During the second quarter of 2004, Wexpro finalized a guideline letter with the Utah Division of Public Utilities and the staff of the Wyoming Public Service Commission agreeing to the accounting treatment of reclamation activity associated with ARO for properties administered under the Wexpro Agreement. Pursuant to the stipulation, Wexpro will collect and deposit in trust certain funds related to the estimated ARO costs. The funds will be used to satisfy reclamation obligations as the properties are reclaimed over time.
#
Note 3 – Questar Gas Processing Dispute
On August 1, 2003, the Utah Supreme Court issued an order reversing a decision made by the Public Service Commission of Utah (“PSCU”) in August of 2000 concerning certain processing costs incurred by Questar Gas Company (“Questar Gas”). The court ruled that the PSCU did not comply with Utah statute when approving a stipulation in Questar Gas’s general rate case filed in December 1999. The stipulation permitted Questar Gas to collect $5.0 million per year through May 2004 to recover a portion of the gas-processing costs. 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 prudent.
As a result of the court’s order, Questar Gas recorded a liability for a potential refund to gas-distribution customers. The liability of $27.9 million, including $3.0 million recorded in the first half of 2004, reflects revenue received for processing costs from June 1999 through June 2004. The court order did not have a material impact on the creditworthiness, cash flow or liquidity of Questar or Questar Gas. Questar Gas has requested ongoing rate coverage for gas-processing costs in its gas-cost pass-through filings and is currently collecting these ongoing costs in rates. Questar Gas will continue to record a liability for the potential refund of the ongoing gas-processing costs until the issue is decided by the PSCU.
In January 2004 the Committee filed a petition for extraordinary relief with the Utah Supreme Court asking the Court to stop PSCU proceedings on this issue. The Utah Supreme Court denied the petition in March 2004, clearing the way for the PSCU to reopen proceedings to review the prudence of Questar Gas’s decision-making on gas processing. Hearings on the issue were held with the PSCU during May 2004. On July 7, 2004, the PSCU stated it would issue an order in August 2004. The PSCU also ordered all parties to attempt to settle the recovery of processing costs from May 2004 forward. The PSCU also encouraged the parties to settle issues related to pre-May 2004 processing costs.
Note 4 – Earnings Per Share (“EPS”)
Basic EPS is computed by dividing net income available to common shareholders by the weighted average number of common shares outstanding during the accounting period. Diluted EPS includes the potential increase in the number of outstanding shares that could result from the exercise of in-the-money stock options and nonvested portion of restricted shares.
In the first half of 2004, Questar issued 716,000 shares under the terms of the Long-Term Stock Incentive Plan, the Dividend Reinvestment and Stock Purchase Plan, and the Employee Investment Plan.
3 Months Ended | 6 Months Ended | 12 Months Ended | ||||
June 30, | June 30, | June 30, | ||||
2004 | 2003 | 2004 | 2003 | 2004 | 2003 | |
(in thousands) | ||||||
Weighted-average basic common shares outstanding | 83,651 | 82,678 | 83,511 | 82,453 | 83,263 | 82,144 |
Potential number of shares issuable from exercising | ||||||
stock options and nonvested restricted shares | 1,794 | 1,596 | 1,794 | 1,413 | 1,682 | 1,068 |
Weighted-average diluted common shares outstanding | 85,445 | 84,274 | 85,305 | 83,866 | 84,945 | 83,212 |
Note 5 – Stock-Based Compensation
The Company accounts for employee stock-based compensation using the intrinsic value method prescribed by Accounting Principles Board Opinion 25, “Accounting for Stock Issued to Employees.” No compensation expense is recorded for stock options granted because the exercise price of those options is equal to the market price on the date of grant. The table below shows pro forma income as if the options were expensed using a fair-value calculated from the Black-Scholes model.
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3 Months Ended | 6 Months Ended | 12 Months Ended | ||||
June 30, | June 30, | June 30, | ||||
2004 | 2003 | 2004 | 2003 | 2004 | 2003 | |
(in thousands) | ||||||
Net income, as reported | $42,556 | $20,272 | $118,689 | $84,894 | $207,411 | $176,264 |
Additional stock-based compensation expense determined under fair-value based method | (652) | (1,363) | (1,304) | (2,726) | (3,854) | (5,510) |
Pro forma net income | $41,904 | $18,909 | $117,385 | $82,168 | $203,557 | $170,754 |
Earnings per share | ||||||
Basic, as reported | $ 0.51 | $ 0.24 | $ 1.42 | $ 1.03 | $ 2.49 | $ 2.14 |
Basic, pro forma | 0.50 | 0.22 | 1.41 | 1.00 | 2.44 | 2.07 |
Diluted, as reported | 0.50 | 0.24 | 1.39 | 1.01 | 2.44 | 2.12 |
Diluted, pro forma | 0.49 | 0.22 | 1.38 | 0.98 | 2.40 | 2.05 |
Note 6 – Operations by Line of Business
3 Months Ended | 6 Months Ended | 12 Months Ended | ||||||
June 30, | June 30, | June 30, | ||||||
2004 | 2003 | 2004 | 2003 | 2004 | 2003 | |||
(in thousands) | ||||||||
REVENUES FROM UNAFFILIATED CUSTOMERS | ||||||||
Market Resources | $244,360 | $155,980 | $478,414 | $369,173 | $ 860,743 | $ 642,946 | ||
Questar Pipeline | 17,869 | 19,504 | 35,882 | 37,640 | 73,223 | 77,075 | ||
Questar Gas | 102,235 | 90,594 | 409,114 | 325,108 | 702,797 | 575,981 | ||
Corporate and other operations | 5,051 | 4,591 | 9,721 | 8,552 | 19,083 | 17,991 | ||
$369,515 | $270,669 | $933,131 | $740,473 | $1,655,846 | $1,313,993 | |||
REVENUES FROM AFFILIATED COMPANIES | ||||||||
Market Resources | $ 34,090 | $ 29,957 | $ 68,447 | $ 56,406 | $ 129,547 | $ 106,143 | ||
Questar Pipeline | 21,794 | 19,307 | 44,087 | 39,646 | 86,298 | 76,365 | ||
Questar Gas | 1,017 | 568 | 2,154 | 1,457 | 2,901 | 2,035 | ||
Corporate and other operations | 5,079 | 7,512 | 11,606 | 15,249 | 26,556 | 31,445 | ||
$ 61,980 | $57,344 | $126,294 | $112,758 | $ 245,302 | $ 215,988 | |||
OPERATING INCOME (LOSS) | ||||||||
Market Resources | $ 65,912 | $ 48,212 | $135,235 | $107,769 | $ 237,811 | $ 171,552 | ||
Questar Pipeline | 17,051 | 17,290 | 35,338 | 35,575 | 70,859 | 71,052 | ||
Questar Gas | (2,428) | (22,082) | 45,471 | 26,624 | 70,232 | 53,861 | ||
Corporate and other operations | 1,762 | 2,475 | 3,043 | 3,802 | 6,245 | 7,904 | ||
$ 82,297 | $ 45,895 | $219,087 | $173,770 | $ 385,147 | $ 304,369 | |||
INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE | ||||||||
Market Resources | $ 38,163 | $ 27,776 | $ 78,418 | $ 61,825 | $ 137,696 | $ 119,335 | ||
Questar Pipeline | 7,232 | 7,342 | 15,345 | 15,395 | 30,252 | 32,717 | ||
Questar Gas | (3,999) | (16,458) | 22,312 | 9,546 | 33,282 | 21,288 | ||
Corporate and other operations | 1,160 | 1,612 | 2,614 | 3,708 | 6,181 | 8,504 | ||
$ 42,556 | $ 20,272 | $118,689 | $ 90,474 | $ 207,411 | $ 181,844 | |||
NET INCOME (LOSS) | ||||||||
Market Resources | $ 38,163 | $ 27,776 | $ 78,418 | $ 56,712 | $ 137,696 | $ 114,222 | ||
Questar Pipeline | 7,232 | 7,342 | 15,345 | 15,262 | 30,252 | 32,584 | ||
Questar Gas | (3,999) | (16,458) | 22,312 | 9,212 | 33,282 | 20,954 | ||
Corporate and other operations | 1,160 | 1,612 | 2,614 | 3,708 | 6,181 | 8,504 | ||
$ 42,556 | $ 20,272 | $118,689 | $ 84,894 | $ 207,411 | $ 176,264 | |||
Note 7 – Employee Benefits
Questar complies with minimum-required and maximum-allowed annual contribution levels for its qualified retirement plan as determined by the Employee Retirement Income Security Act and Internal Revenue Code. Subject to these limitations Questar's objective is to fund the qualified retirement plan in amounts approximately equal to the yearly expense. Presently the pension expense estimate for 2004 is $15.6 million. Components of pension expense included in the determination of interim net income are listed below.
Questar deferred recognizing the impact of the Medicare Prescription Drug, Improvement and Modernization Act (the “Act”). Questar will show the effect of the Act in the second half of 2004 and treat it as an actuarial gain by amortizing it over future periods.
Pension Expense
3 Months Ended | 6 Months Ended | |||
June 30, | June 30, | |||
2004 | 2003 | 2004 | 2003 | |
(in thousands) | ||||
Service cost | $ 1,898 | $ 1,902 | $ 4,039 | $ 3,804 |
Interest cost | 4,874 | 4,572 | 9,715 | 9,145 |
Expected return on plan assets | (4,679) | (4,440) | (9,421) | (8,879) |
Prior service and other costs | 481 | 481 | 961 | 961 |
Recognized net-actuarial loss | 512 | 226 | 1,053 | 452 |
Amortization of early-retirement costs | 719 | 810 | 1,437 | 1,621 |
Pension expense | $ 3,805 | $ 3,551 | $ 7,784 | $ 7,104 |
Expense of Postretirement Benefits Other than Pensions
The Company currently estimates a $5.3 million expense for postretirement benefits in 2004 before $800,000 for accretion of a regulatory liability. Expense components are listed below.
3 Months Ended | 6 Months Ended | |||
June 30, | June 30, | |||
2004 | 2003 | 2004 | 2003 | |
(in thousands) | ||||
Service cost | $ 172 | $ 197 | $ 392 | $ 394 |
Interest cost | 1,327 | 1,326 | 2,644 | 2,652 |
Expected return on plan assets | (871) | (651) | (1,524) | (1,301) |
Special termination benefits | 82 | 82 | ||
Amount of transition obligation | 470 | 469 | 939 | 939 |
Amortization of losses | 50 | 120 | 192 | 241 |
Accretion of regulatory liability | 200 | 200 | 400 | 400 |
Postretirement benefit other than pension expense | $ 1,430 | $ 1,661 | $ 3,125 | $ 3,325 |
Note 8 – Financing
On June 21, 2004, Questar Gas called $17 million in medium-term notes that carried an interest rate of 8.12%. A call premium of $690,000 will be amortized over the remaining life of the original notes in accordance with regulatory treatment.
On March 19, 2004, Market Resources completed a $200 million credit facility with a consortium of banks that replaced an existing facility that expired in April 2004. The facility allows for floating-rate interest and revolving loans of various maturities until March 2009. Key financial covenants place limits on minimum levels of cash flow compared to interest expense and maximum amounts of debt as a percentage of total capital. The interest rate credit spread on borrowings varies with changes in Market Resources’ credit rating, but a reduction in or loss of credit ratings does not trigger an event of default under the facility.
Note 9 – Investment in Unconsolidated Affiliates
Questar uses the equity method to account for investments in unconsolidated affiliates where the Company does not have control. These entities are engaged in gathering and compressing natural gas, and have no debt obligations with third-party lenders. The principal affiliates and Questar's ownership percentage as of June 30, 2004, were: Rendezvous Gas Services LLC, a limited liability corporation, (50%) and Canyon Creek Compression Co., a general partnership (15%).
Operating results are listed below.
6 Months Ended | ||
June 30, | ||
2004 | 2003 | |
(in thousands) | ||
Revenues | $8,420 | $7,908 |
Operating income | 5,296 | 4,787 |
Income before income taxes | 5,306 | 4,806 |
Note 10 – Comprehensive Income
Comprehensive income is the sum of net income as reported in the Consolidated Statements of Income and other comprehensive income or loss reported in Common Shareholders' Equity. Other comprehensive income or loss includes changes in the market value of gas or oil-price derivatives. These results are not reported in current income or loss. Income or loss is realized when the physical gas or oil underlying the derivative instrument is sold. A summary of comprehensive income is shown below.
3 Months Ended | 6 Months Ended | |||
June 30, | June 30, | |||
2004 | 2003 | 2004 | 2003 | |
(in thousands) | ||||
Net income | $ 42,556 | $ 20,272 | $ 118,689 | $ 84,894 |
Other comprehensive income or (loss) | ||||
Unrealized loss on hedging transactions | (40,829) | (16,740) | (64,589) | (39,928) |
Income taxes | 15,266 | 6,260 | 24,201 | 14,929 |
Other comprehensive loss | (25,563) | (10,480) | (40,388) | (24,999) |
Comprehensive income | $ 16,993 | $ 9,792 | $ 78,301 | $ 59,895 |
Note 11 – Reclassifications
Certain reclassifications were made to the 2003 financial statements to conform with the 2004 presentation.
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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
June 30, 2004
(Unaudited)
Results of Operations
Questar Corporation (“Questar” or “the Company”) is an integrated natural gas company that conducts operations through two groups, Questar Market Resources (“Market Resources”) and Questar Regulated Services (“Regulated Services”). Market Resources, through various subsidiaries, engages in gas and oil acquisition, exploration, development and production; cost-of-service gas development; gas gathering and processing; and wholesale gas and hydrocarbon-liquids marketing, risk management, and gas storage. Regulated Services has two primary subsidiaries. Questar Pipeline Company (“Questar Pipeline”) conducts interstate gas-transmission and storage activities and Questar Gas Company (“Questar Gas”) provides retail gas distribution services.
SUMMARY
Questar reported first half 2004 net income of $118.7 million or $1.39 per diluted share compared to $84.9 million or $1.01 per share for the first half of 2003. The 2003 period’s net income was reduced by $5.6 million or $0.07 per share related to the implementation of SFAS 143. Following is a comparison of net income by line of business.
Net Income | ||||
6 Months Ended June 30, | Increase | Percentage | ||
2004 | 2003 | (Decrease) | Change | |
(in thousands, except per share amounts) | ||||
Market Resources | $ 78,418 | $56,712 | $21,706 | 38% |
Questar Pipeline | 15,345 | 15,262 | 83 | 1% |
Questar Gas | 22,312 | 9,212 | 13,100 | 142% |
Corporate and other operations | 2,614 | 3,708 | (1,094) | (30%) |
Net income | $118,689 | $84,894 | $33,795 | 40% |
Earnings per diluted common share | $ 1.39 | $ 1.01 | $ 0.38 | 38% |
Market Resources first half 2004 net income increased 38% over the first half of 2003 because of a 13% increase in nonregulated production, a 16% increase in realized commodity prices, additions to Wexpro's investment base and increased gas-gathering throughput. Implementation of SFAS 143 reduced earnings in 2003 by $5.1 million.
Questar Pipeline net income increased 1% in the first half of 2004 compared with the first half of 2003. A 3% increase in revenues was offset by a 7% increase in total operating expenses. Implementation of SFAS 143 reduced 2003 net income by $133,000.
Questar Gas net income increased 142% in the first half of 2004 compared with the first half of 2003. The 2003 results include a $13.6 million after-tax charge for a potential refund of disputed-gas processing costs. The 2004 results include a $1.9 million after-tax charge in the unresolved processing dispute. Net income increased about $1.4 million in the first half of 2004 compared with the first half of 2003 excluding the impact of the potential refund accruals primarily due to revenues from new customers. Implementation of SFAS 143 reduced 2003 earnings by $334,000.
Net income from Corporate and Other Operations decreased $1.1 million in the first half of 2004 compared to the same period of 2003 because of reduced services provided to affiliates.
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Market Resources
Market Resources is a wholly-owned subsidiary of Questar. Market Resources conducts its operations through several subsidiaries. Questar Exploration and Production Company (“Questar E&P”) acquires, explores for, develops and produces gas and oil. Wexpro Company (“Wexpro”) manages, develops and produces cost-of-service reserves for affiliated company, Questar Gas. Questar Gas Management Company (“Gas Management”) provides gas gathering and processing services for affiliates and third parties. Questar Energy Trading Company (“Energy Trading”) markets equity and third-party gas and oil, provides risk-management services, and through its wholly-owned subsidiary Clear Creek Storage Company, LLC, owns and operates an underground gas-storage reservoir. Following is a summary of Market Resources’ financial results and operating information.
3 Months Ended | 6 Months Ended | 12 Months Ended | ||||
June 30, | June 30, | June 30, | ||||
2004 | 2003 | 2004 | 2003 | 2004 | 2003 | |
FINANCIAL RESULTS - (in thousands) | ||||||
Revenues | ||||||
From unaffiliated customers | $244,360 | $155,980 | $478,414 | $369,173 | $860,743 | $642,946 |
From affiliates | 34,090 | 29,957 | 68,447 | 56,406 | 129,547 | 106,143 |
Total revenues | $278,450 | $185,937 | $546,861 | $425,579 | $990,290 | $749,089 |
Operating income | $ 65,912 | $ 48,212 | $135,235 | $107,769 | $237,811 | $171,552 |
Income before cumulative effect | $ 38,163 | $ 27,776 | $ 78,418 | $ 61,825 | $137,696 | $119,335 |
Cumulative effect of accounting change | (5,113) | (5,113) | ||||
Net income | $ 38,163 | $ 27,776 | $ 78,418 | $ 56,712 | $137,696 | $114,222 |
OPERATING STATISTICS | ||||||
Nonregulated production volumes | ||||||
Natural gas (MMcf) | 21,827 | 17,957 | 43,715 | 38,061 | 84,465 | 77,872 |
Oil and natural gas liquids (Mbbl) | 559 | 568 | 1,146 | 1,140 | 2,330 | 2,421 |
Total production (bcfe) | 25.2 | 21.4 | 50.6 | 44.9 | 98.4 | 92.4 |
Average daily production (MMcfe) | 277 | 235 | 278 | 248 | 269 | 253 |
Average commodity prices, net to the well | ||||||
Average realized price (including hedges) | ||||||
Natural gas (per Mcf) | $ 4.17 | $ 3.66 | $ 4.11 | $ 3.59 | $ 3.89 | $ 3.12 |
Oil and natural gas liquids (per bbl) | 29.55 | 22.45 | 29.50 | 23.59 | 26.30 | 22.30 |
Average sales price (excluding hedges) | ||||||
Natural gas (per Mcf) | $ 5.03 | $ 4.34 | $ 4.87 | $ 4.27 | $ 4.48 | $ 3.29 |
Oil and natural gas liquids (per bbl) | 35.38 | 26.62 | 33.57 | 28.89 | 30.78 | 27.05 |
Wexpro investment base at June 30, net of | ||||||
depreciation and deferred income taxes (millions) | $ 165.3 | $ 160.3 | ||||
Natural gas and oil marketing volumes (Mdthe) | 20,725 | 16,900 | 42,580 | 38,211 | 84,565 | 79,451 |
Natural gas gathering volumes (Mdth) | ||||||
For unaffiliated customers | 32,164 | 28,031 | 66,458 | 56,357 | 124,875 | 111,716 |
For Questar Gas | 9,149 | 9,515 | 18,906 | 21,099 | 39,375 | 39,779 |
For other affiliated customers | 13,336 | 8,936 | 27,894 | 21,027 | 53,017 | 42,511 |
Total gathering | 54,649 | 46,482 | 113,258 | 98,483 | 217,267 | 194,006 |
Gathering revenue (per dth) | $ 0.21 | $ 0.20 | $ 0.21 | $ 0.20 | $ 0.21 | $ 0.18 |
Market Resources
Market Resources net income for the second quarter of 2004 totaled $38.2 million compared with $27.8 million for the year earlier period, a 37% increase. Net income for the first half of 2004 was $78.4 million, a 38% increase over the $56.7 million earned in the first half of 2003 as revenue growth continued to outpace increases in expenses. Operating income increased $17.7 million, or 37%, in the quarter-to-quarter comparison and $27.5 million, or 25%, in the first half comparison, due primarily to increased production and higher prices at Questar E&P and improved margins at Gas Management. Total revenues increased $92.5 million, or 50%, in the second quarter of 2004, and $121.3 million, or 28%, in the first half of 2004. Revenue growth was driven by increased nonregulated production volumes (nonregulated volumes exclude Wexpro “cost-of-service” production), higher realized commodity prices at Questar E&P, and increased throughput and higher fees at Gas Management. Expenses increased in the 2004 periods due to increased abandonment expense, production taxes, lease operating expense, and depreciation, depletion and amortization.
Questar E&P
For the second quarter of 2004, Questar E&P earned $25.4 million compared with $17.4 million for the same period in 2003. Net income for the first half of 2004 was $50.6 million, a 52% increase over the $33.4 million earned in 2003. Higher profits were driven by increased nonregulated production and higher realized natural gas, oil and NGL prices.
Questar E&P’s nonregulated production for the first half of 2004 was 50.6 bcfe compared to 44.9 bcfe for the 2003 period, a 13% increase. Production growth was driven by the accelerated pace of development drilling on the Pinedale Anticline in western Wyoming and significant year-over-year volume increases from Midcontinent properties. Natural gas remains the primary focus of Questar E&P’s exploration and production strategy. On an energy-equivalent ratio, natural gas comprised approximately 85% of nonregulated production for the second quarter and first half of 2004. The three-, six-, and twelve-month comparisons of energy-equivalent production by region are shown in the following table.
3 Months Ending | 6 Months Ending | 12 Months Ending | ||||
June 30, | June 30, | June 30, | ||||
2004 | 2003 | 2004 | 2003 | 2004 | 2003 | |
(in bcfe) | ||||||
Rocky Mountains | ||||||
Pinedale Anticline | 4.9 | 2.5 | 11.0 | 5.4 | 20.7 | 10.5 |
Uinta Basin | 6.1 | 7.0 | 12.4 | 15.5 | 26.0 | 29.0 |
Rockies Legacy | 4.7 | 3.9 | 9.1 | 8.4 | 17.4 | 18.5 |
Subtotal – Rocky Mountains | 15.7 | 13.4 | 32.5 | 29.3 | 64.1 | 58.0 |
Midcontinent | 9.5 | 8.0 | 18.1 | 15.6 | 34.3 | 32.0 |
Canada | - | - | - | - | - | 2.4 |
Total nonregulated production | 25.2 | 21.4 | 50.6 | 44.9 | 98.4 | 92.4 |
At June 30, 2004, Market Resources had 76 producing wells on the Pinedale Anticline compared to 51 at the beginning of 2003. Current quarter nonregulated production from Pinedale decreased 1.2 bcfe from first quarter 2004 volumes. Production at Pinedale typically declines during the second and third quarters due to a suspension of drilling and completion activities caused by access restrictions from mid-November to early May. (See the discussion of Pinedale Anticline Drilling Activity later in this Item.) Continued good performance from Questar E&P’s Hartshorne coal bed methane (“CBM”) project in the Arkoma Basin of eastern Oklahoma and ongoing development drilling on the Elm Grove properties in northwest Louisiana drove Midcontinent results. Current quarter Midcontinent production was up 0.9 bcfe, or 10%, versus the first quarter of 2004. Production volumes from the Uinta Basin in eastern Utah decreased 13% in the current quarter compared to the year earlier period and 20% in the first half comparison. The production decline in the Uinta Basin has flattened significantly from a year ago. Uinta Basin current quarter volumes were down only 0.2 bcfe compared to the first quarter of 2004. Second quarter 2004 volumes were negatively impacted by gathering and compression constraints that reduced Uinta Basin net production volumes approximately 0.3 bcfe. The constraint should be alleviated with installation of additional compression in early August, 2004. Production from Rockies “Legacy” properties in the first half of 2004 was 9.1 bcfe compared to 8.4 bcfe in 2003, a 9% increase. Legacy properties include all of Questar E&P’s Rocky Mountain producing properties exclusive of Pinedale and the Uinta Basin.
Questar E&P benefited from higher realized prices for natural gas, oil and NGL in the second quarter and first half of 2004. For the current quarter the weighted average realized gas price for Questar E&P (including the effects of hedging) was $4.17 per Mcf compared to $3.66 per Mcf for the same period in 2003, a 14% increase. For the 2004 quarter, realized oil and NGL prices averaged $29.55 per bbl, compared with $22.45 per bbl in the second quarter of 2003, a 32% increase. A comparison of average realized prices by region, including hedges, is shown in the following table.
3 Months Ending | 6 Months Ending | 12 Months Ending | ||||
June 30, | June 30, | June 30, | ||||
2004 | 2003 | 2004 | 2003 | 2004 | 2003 | |
Natural gas (per Mcf) | ||||||
Rocky Mountains | $3.83 | $3.27 | $3.89 | $3.13 | $3.64 | $2.69 |
Midcontinent | 4.71 | 4.27 | 4.50 | 4.40 | 4.32 | 3.90 |
Canada | - | - | - | - | - | 2.21 |
Volume weighted average | $4.17 | $3.66 | $4.11 | $3.59 | $3.89 | $3.12 |
Oil and NGL (per bbl) | ||||||
Rocky Mountains | $28.41 | $20.74 | $28.62 | $22.04 | $25.14 | $21.11 |
Midcontinent | 32.14 | 26.68 | 31.51 | 27.55 | 29.06 | 24.89 |
Canada | - | - | - | - | 24.21 | |
Volume weighted average | $29.55 | $22.45 | $29.50 | $23.59 | $26.30 | $22.30 |
Realized natural gas prices in Questar E&P’s core Rockies areas increased significantly in the second quarter and first half of 2004 compared to the 2003 periods. Approximately 60% of Questar E&P’s 2004 natural gas production came from properties located in the Rockies. Rockies basis, the regional difference between Rockies prices and the reference Henry Hub price, averaged $0.95 per MMBtu for the second quarter of 2004, compared to approximately $1.25 per MMBtu for the same period in 2003. For the first half of 2004 Rockies basis averaged $0.85, compared to $2.04 in the first half of 2003. The May 2003 completion of a major interstate pipeline expansion that delivers Rockies gas to California markets alleviated the transportation bottleneck that adversely affected prices in the 2003 periods.
Approximately 80% of Market Resources’ nonregulated gas production in the first half of 2004 was hedged or pre-sold at an average price of $4.05 per Mcf net to the well (which reflects adjustments for regional basis, gathering and processing costs, and gas quality) resulting in a $33.3 million reduction in revenue for the six months compared to results if the entire volume had not been hedged and instead was sold at prevailing market prices. Market Resources also hedged or pre-sold approximately 56% of its oil production for the first half of 2004 at an average net to the well price of $30.98 per bbl, which resulted in a $4.7 million reduction in revenues for the period versus sales at then-prevailing market prices. Market Resources may hedge up to 100 percent of its forecasted nonregulated production from proved developed reserves to lock in acceptable returns on invested capital and to protect cash flows and earnings from a decline in commodity prices.
Market Resources has continued to take advantage of higher natural gas and oil prices to add to its hedge positions in 2005 and 2006. Natural gas and oil hedges as of June 30, 2004, are summarized in Item 3 of this report.
Questar E&P’s cost structure is summarized in the following table.
3 Months Ending | 6 Months Ending | 12 Months Ending | ||||
June 30, | June 30, | June 30, | ||||
2004 | 2003 | 2004 | 2003 | 2004 | 2003 | |
(per Mcfe) | ||||||
Lease-operating expense | $0.52 | $0.52 | $0.50 | $0.48 | $0.50 | $0.51 |
Production taxes | 0.42 | 0.33 | 0.42 | 0.32 | 0.38 | 0.26 |
Lifting costs | 0.94 | 0.85 | 0.92 | 0.80 | 0.88 | 0.77 |
Depreciation, depletion and amortization | 1.01 | 0.94 | 1.00 | 0.94 | 0.99 | 0.94 |
General and administrative expense | 0.33 | 0.30 | 0.30 | 0.28 | 0.30 | 0.28 |
Allocated-interest expense | 0.21 | 0.24 | 0.21 | 0.24 | 0.21 | 0.26 |
Total | $2.49 | $2.33 | $2.43 | $2.26 | $2.38 | $2.25 |
Lifting costs per Mcfe were higher in the 2004 periods primarily due to increased production taxes related to higher gas, oil and NGL sales prices. Most production taxes are based on a fixed percentage of commodity sales prices. The slight reduction in lease operating expenses in the twelve month comparison was driven primarily by the sale of higher cost, non-core properties during the second half of 2002. Depreciation, depletion and amortization expense increased in the 2004 periods primarily due to higher reserve replacement costs. Increased industry activity in core operating areas has increased drilling and completion costs. General and administrative expenses per Mcfe increased $0.03 and $0.02, or 10% and 7%, in the second quarter and first half of 2004 when compared to the same periods of 2003. The increase in both periods of 2004 was primarily due to higher legal, insurance, and employee benefit costs and higher allocated corporate overhead (primarily employee benefits and compliance costs). For the second quarter and first half of 2004 allocated interest decreased to $0.21 per Mcfe compared to $0.24 per Mcfe for the same periods in 2003 due mostly to increased production.
Pinedale Anticline Drilling Activity
During the second quarter of 2004, Market Resources continued limited winter drilling for a second year on the Pinedale Anticline. Market Resources drilled three wells from a single pad over the winter of 2003/2004 and will continue drilling activity from the pad through the remainder of 2004. Sage grouse stipulations imposed by the Bureau of Land Management (“BLM”) delayed startup of drilling activities at some locations on Market Resources’ Pinedale acreage during May and June, including the 19,500 foot deep Stewart Point 15-29 well. Drilling began on the Stewart Point well in mid July. Questar E&P has a 71.25% working interest in the deeper zones. Market Resources currently has 14 rigs actively drilling on its Pinedale acreage. In spite of early-season delays, Market Resources still expects to drill and complete approximately 30 Lance/Mesaverde Formation development wells in 2004.
Questar E&P and Wexpro have a combined 62% average Lance/Mesaverde working interest in 14,800 acres at Pinedale.
Pinedale Anticline Year-Round Drilling Proposal
On April 15, 2004, Market Resources submitted a proposal to the BLM seeking a long-term exception to the winter drilling restrictions on its Pinedale acreage from November 15 through May 1. If approved Market Resources will be allowed to drill from three active pads with two drilling rigs per pad, starting in the winter of 2004/2005. The BLM has initiated an Environmental Assessment and is soliciting public comments on Market Resources’ proposal.
Market Resources believes that year-round drilling from pads is the most efficient and environmentally responsible approach for developing its Pinedale acreage. Market Resources’ proposal would shorten the anticipated development drilling period from 18 years to about 9 years. Under the proposal Market Resources would drill multiple directional wells from single surface pads. If approved Market Resources estimates that only nine additional surface disturbances will be required to fully develop its current Pinedale acreage on 20-acre spacing. With Market Resources’ proposal, surface disturbance will be reduced initially from almost 1,500 acres currently allowed to less than 540 acres. Surface disturbance would be further reduced to about 260 acres with post-drilling reclamation.
In addition to reduced surface disturbance and a shortened development drilling period, other benefits of Market Resources’ year-round proposal include a substantial reduction in emissions, noise, dust and traffic compared to the current situation in which activities are compressed into the summer months. Year-round drilling also creates year-round jobs and thus a more stable, better trained, more productive and safer workforce in the drilling and completion service industries. If the proposal is approved, Market Resources has committed to build pipelines to transport condensate and water production off the Mesa (that portion of the Pinedale Anticline where Market Resources’ acreage is located). The pipelines will eliminate the need for storage tanks at each location and up to 25,500 tanker-truck trips per year at peak production. Market Resources anticipates that the BLM will make a decision on its proposal in time for the 2004/2005 winter drilling season. Certain groups have sued the BLM over granting Market Resources prior winter-long exceptions to winter stipulations at Pinedale and the case is still pending.
Pinedale Anticline 20-Acre Spacing Approved
On July 13, 2004, the Wyoming Oil and Gas Conservation Commission unanimously approved 20-acre density drilling of Lance Pool (Lance and Mesaverde Formation) wells on Market Resources Pinedale Anticline acreage. The commission’s written order is expected by mid-September. Market Resources currently has 76 proved-developed producing wells at Pinedale and another 96 booked proved-undeveloped locations based on 40-acre spacing. With approval of 20-acre spacing, Market Resources expects to book incremental reserves on 124 additional proved-undeveloped locations, for a total of 220 locations. As a result Questar E&P expects its Pinedale reserves to increase by 250-300 bcfe by year end. There are approximately 134 additional locations that cannot be booked as proved at this time because they do not directly offset currently producing wells. Pursuant to Securities and Exchange Commission reserve-booking guidelines, only locations that directly offset currently producing wells can be booked as proved. Market Resources believes that no further approvals will be necessary to begin 20-acre development on its leasehold. Market Resources estimates that each 20-acre-spaced well drilled and completed in the Lance and Mesaverde Formations will recover between 3.8 and 8.8 bcfe of gross incremental reserves.
New Pinedale Lease
Questar E&P was the high bidder on a 1,425-acre lease at the June 8, 2004, Competitive Oil and Gas Lease Sale held by the BLM. The lease includes Sections 30 and 31, T32N, R109W and adjoins the southwest side of Market Resources current 14,800 acre leasehold. The Governor of Wyoming and various environmental groups filed protests against the BLM auction of this lease and eleven other leases in the Pinedale Resource Area. The BLM has stated that it will consider the protests but believes it acted properly.
Wexpro
For the second quarter of 2004 Wexpro earned $8.8 million, compared with $8.5 million for the same period in 2003. Net income for the first half of 2004 was $17.8 million, an 11% increase over the $16.1 million earned in 2003. Wexpro manages, develops and produces gas reserves on behalf of Questar Gas. Wexpro activities are governed by a long-standing agreement (Wexpro Agreement) with the States of Utah and Wyoming. Pursuant to the Wexpro Agreement, Wexpro recovers its costs and receives an after-tax return of approximately 19% on its net investment in commercial wells and related facilities – known as the investment base – adjusted for working capital, deferred taxes, and depreciation. Wexpro’s net investment base increased to $165.3 million at June 30, 2004, up $5.0 million over the year earlier period.
Gas Gathering and Processing; Gas and Oil Marketing
Net income from gas gathering, processing and marketing operations increased 108% to $4.0 million in the second quarter of 2004 from $1.9 million in the 2003 period. Net income for the first half of 2004 was $10.0 million versus $7.2 million for the same period in 2003, an increase of 38%. Gathering volumes increased 15% to 113.3 MMdth for the first half of 2004 due primarily to increased production from the Pinedale field in western Wyoming. Pre-tax earnings from Gas Management’s 50% interest in Rendezvous Gas Services increased from $2.3 million for the six months ended June 30, 2003, to $2.6 million for the comparable 2004 period. Rendezvous provides gas gathering services for the Pinedale and Jonah producing areas.
Gas Management continues to invest in additional gas gathering and processing and liquids-handling facilities to serve growing equity and third-party production in its core areas. These core areas are the Pinedale and Jonah fields in western Wyoming and the Uinta Basin in eastern Utah.
Energy Trading’s gross margins (gross revenues less the costs to purchase gas and oil, commitments to gas transportation contracts on interstate pipelines, and gas storage costs), increased to $4.1 million in the second quarter of 2004 versus $1.9 million for the year earlier period, a 110% increase. The increase was due primarily to 70% higher unit margins and a 23% increase in volumes over the same period last year.
In June 2004, Energy Trading purchased the remaining 25% interest in Clear Creek Storage LLC that it did not already own from Montana Power Ventures Inc, a subsidiary of EnCana Corp., for total consideration of $1.0 million. Energy Trading is now the sole owner of Clear Creek Storage, LLC and owns and operates the Clear Creek natural gas storage facility in southwestern Wyoming. Clear Creek has working gas storage capacity of approximately 3.0 bcf and is connected to four interstate pipelines – Kern River Gas Transmission, Northwest Pipeline, Questar Pipeline and Overthrust Pipeline.
Questar Pipeline
Questar Pipeline – a wholly owned subsidiary of Questar – provides Federal Energy Regulatory Commission (“FERC”) regulated interstate natural gas transmission and storage, and non-jurisdictional processing and gathering services. Following is a summary of financial results and operating information.
3 Months Ended | 6 Months Ended | 12 Months Ended | ||||||
June 30, | June 30, | June 30, | ||||||
2004 | 2003 | 2004 | 2003 | 2004 | 2003 | |||
FINANCIAL RESULTS – (in thousands) | ||||||||
Revenues | ||||||||
From unaffiliated customers | $17,869 | $19,504 | $35,882 | $37,640 | $ 73,223 | $ 77,075 | ||
From affiliates | 21,794 | 19,307 | 44,087 | 39,646 | 86,298 | 76,365 | ||
Total revenues | $39,663 | $38,911 | $79,969 | $77,286 | $159,521 | $153,440 | ||
Operating income | $17,051 | $17,290 | $35,338 | $35,575 | $ 70,859 | $ 71,052 | ||
Income before cumulative effect | $ 7,232 | $ 7,342 | $15,345 | $15,395 | $ 30,252 | $ 32,717 | ||
Cumulative effect of accounting change | (133) | (133) | ||||||
Net income | $ 7,232 | $ 7,342 | $15,345 | $15,262 | $ 30,252 | $ 32,584 | ||
OPERATING STATISTICS | ||||||||
Natural gas transportation volumes (in Mdth) | ||||||||
For unaffiliated customers | 55,250 | 61,880 | 108,984 | 127,396 | 233,253 | 264,227 | ||
For Questar Gas | 22,592 | 26,188 | 72,468 | 65,720 | 112,468 | 100,145 | ||
For other affiliated customers | 5,208 | 5,526 | 9,468 | 9,203 | 26,489 | 13,992 | ||
Total transportation | 83,050 | 93,594 | 190,920 | 202,319 | 372,210 | 378,364 | ||
Transportation revenue (per dth) | $0.32 | $0.27 | $0.28 | $0.25 | $0.28 | $0.27 | ||
Questar Pipeline’s net income was $7.2 million in the second quarter of 2004 and $15.3 million in the first half of 2004 compared with $7.3 million in the second quarter of 2003 and $15.3 million in the first half of 2003. The 2004 results reflect new firm transmission contracts and higher liquid revenues offset by higher operating costs.
Natural gas transmission and storage revenues grew 2% in the second quarter of 2004, 3% in the first half of 2004, and 4% in the 12 months ended June 30, 2004, compared with the year-earlier periods. Following is a summary of major changes in Questar Pipeline’s revenues for the second quarter, first half and 12 months ended June 30, 2004, compared with the same periods of 2003.
Revenue Variance Analysis | |||
3 Months Ended June 30, 2004 | 6 Months Ended June 30, 2004 | 12 Months Ended June 30, 2004 | |
(in thousands) | |||
New transportation contracts | $1,542 | $3,136 | $5,769 |
Expiration of prior transportation contracts | (390) | (585) | (834) |
Change in gas-processing revenues | 81 | 226 | 1,509 |
Other | (381) | (94) | (363) |
Increase | $852 | $2,683 | $6,081 |
Questar Pipeline has expanded its transportation system in response to growing regional natural gas production and transportation demand. Questar Pipeline added new transportation contracts in 2003 for deliveries to the Kern River Pipeline at Roberson Creek and for increased deliveries to Questar Gas customers in northern Utah.
Questar Pipeline’s existing transportation system is nearly fully subscribed. As of June 30, 2004, Questar Pipeline had firm-transportation contracts of 1,643 Mdth per day compared with 1,655 Mdth per day as of December 31, 2003, and 1,624 Mdth per day as of June 30, 2003. The amounts include 80 Mdth per day capacity on the eastern segment of Southern Trails. Questar Pipeline’s firm-transportation contracts had a weighted average remaining life of 9.4 years as of June 30, 2004.
Questar Gas is Questar Pipeline’s largest transportation customer with contracts for 951 Mdth per day, including 50 Mdth per day for winter-peaking service. The majority of Questar Gas’s transportation contracts extend to 2017.
Questar Pipeline’s primary storage facility is Clay Basin in eastern Utah. This facility is 100% subscribed under long-term contracts. In addition to Clay Basin Questar Pipeline also owns and operates three smaller aquifer gas storage facilities. Questar Pipeline’s firm storage contracts had a weighted average remaining life of 7.7 years as of June 30, 2004.
Questar Gas has contracted for 62% of firm-storage capacity at Clay Basin for terms extending from four to 15 years and 100% of the firm-storage capacity at the aquifer facilities for terms extending for 15 years.
Questar Pipeline is investigating a potential discrepancy of up to 11 bcf between the book volume of cushion gas at Clay Basin and indicated volumes of cushion gas in the storage reservoir based on pressure survey data obtained in recent field tests. The current book volume of the cushion gas is 61.5 bcf with a book value of $99.7 million. The cause and significance of this discrepancy is at this point unknown. Possible explanations include errors in measurement, leaks in the storage reservoir or in wells that permit migration of gas outside of the reservoir, or physical changes in the character of the storage reservoir. Initial reviews of accounting and measurement data confirm the book volume. Technical analysis to date has not revealed any leaks or gas migration. Additional tests and analysis, and reservoir modeling are underway to identify the cause or explain the disparity. Questar Pipeline at this time does not know if the volume of gas actually in the reservoir is less than book volume. Questar Pipeline will not know the financial impact, if any, until the cause of the disparity is determined, but will continue to meet its service obligations to Clay Basin storage customers.
If Questar Pipeline determines that the discrepancy is due to changes in the physical conditions in the storage reservoir and not of loss of cushion gas, then the financial impact may be any additional investment in cushion gas to meet service obligations. In this case Questar Pipeline may have additional storage capacity available for sale to customers. If the discrepancy is due to lost-and-unaccounted-for-gas in the measurement process, then Questar Pipeline would expense the cost of any replacement cushion gas. Questar Pipeline could file with the FERC to recover some or all of this replacement cushion gas.
Questar Pipeline charges FERC approved transportation and storage rates that are based on straight-fixed-variable rate design. Under this rate design all fixed costs of providing service including depreciation and return on investment are recovered through the demand charge. About 95% of QPC costs are fixed and recovered through these demand charges. Questar Pipeline’s earnings are driven primarily by demand revenues from firm shippers. Operating costs that vary based on throughput are recovered through volumetric charges. Since demand charges are based on contract levels and volumetric charges are about 5%, period-to-period changes in firm-transportation volumes do not have a significant impact on earnings.
During first quarter 2004 Questar Pipeline obtained long-term contracts to support a $54 million expansion of its central Utah transmission system. The expansion will add 102 Mdth per day of capacity from the Piceance and Uinta basins to the Kern River pipeline, a power-generation facility, and Questar Gas’s distribution system. Questar Pipeline will start construction in the summer of 2005 for a late-2005 in-service date. Annual revenues from this expansion will be about $9.7 million.
About 10 Mdth per day of this capacity is the result of reconfiguring existing compression. One of the customers is willing to use this service as soon as it is available. FERC approval to reconfigure the compression has been granted and service is expected to start by year-end 2004.
Questar Pipeline also obtained a long-term contract supporting a $15 million extension from the west end of its Mainline 104 near Goshen, Utah to a new power plant being built near Mona, Utah. This 190 Mdth line is scheduled to be in-service by the end of 2004. Annual revenues from this extension will be about $2.5 million.
Questar Transportation Services, a subsidiary of Questar Pipeline, owns non-jurisdictional gathering lines and a processing plant near Price, Utah. The plant was built in 1999 to process gas on behalf of Questar Gas. Questar Gas has contracted for 100% of the plant’s firm capacity and pays the cost of service for operating the plant.
Operating and maintenance expenses increased 6% in the second quarter of 2004, 6% in the first half of 2004 and 7% in the 12 months ended June 30, 2004, over the corresponding 2003 periods. The increases for all periods presented were primarily for processing plant fuel gas, employee benefits, insurance and maintenance. Operating and maintenance expenses per dth transported were $0.143 in the first half of 2004 compared with $0.128 in the first half of 2003.
Depreciation and property-tax expense increased in the 2004 periods, reflecting increased pipeline investment.
The western segment of the Southern Trails Pipeline, which runs from the California-Arizona border to Long Beach, California, is currently not in service. Questar Pipeline is actively seeking customers willing to enter into long-term gas transportation contracts necessary to place the pipeline into service. The company is also discussing the sale of the pipeline to the Los Angeles Department of Water and Power. Questar Pipeline's investment in the western segment is approximately $51 million.
Questar Gas
Questar Gas – a wholly owned subsidiary of Questar – distributes natural gas in Utah, southwestern Wyoming and southeastern Idaho. Following is a summary of financial results and operating information.
3 Months Ended | 6 Months Ended | 12 Months Ended | ||||
June 30, | June 30, | June 30, | ||||
2004 | 2003 | 2004 | 2003 | 2004 | 2003 | |
FINANCIAL RESULTS - (in thousands) | ||||||
Revenues | ||||||
From unaffiliated customers | $102,235 | $ 90,594 | $409,114 | $325,108 | $702,797 | $575,981 |
From affiliates | 1,017 | 568 | 2,154 | 1,457 | 2,901 | 2,035 |
Total revenues | 103,252 | 91,162 | 411,268 | 326,565 | 705,698 | 578,016 |
Cost of natural gas sold | 65,697 | 54,481 | 282,427 | 199,116 | 477,834 | 344,219 |
Margin | $ 37,555 | $ 36,681 | $128,841 | $127,449 | $227,864 | $233,797 |
Operating income (loss) | ($ 2,428) | ($22,082) | $ 45,471 | $ 26,624 | $ 70,232 | $ 53,861 |
Income (loss) before cumulative effect | ($ 3,999) | ($16,458) | $ 22,312 | $ 9,546 | $ 33,282 | $ 21,288 |
Cumulative effect of accounting change | (334) | (334) | ||||
Net income (loss) | ($ 3,999) | ($16,458) | $ 22,312 | $ 9,212 | $ 33,282 | $ 20,954 |
3 Months Ended | 6 Months Ended | 12 Months Ended | ||||
June 30, | June 30, | June 30, | ||||
2004 | 2003 | 2004 | 2003 | 2004 | 2003 | |
OPERATING STATISTICS | ||||||
Natural gas volumes (in Mdth) | ||||||
Residential and commercial sales | 11,633 | 12,999 | 53,317 | 48,467 | 89,243 | 85,118 |
Industrial sales | 2,011 | 2,201 | 5,025 | 5,428 | 9,210 | 10,361 |
Transportation for industrial customers | 8,208 | 9,421 | 18,146 | 18,973 | 37,514 | 43,741 |
Total deliveries | 21,852 | 24,621 | 76,488 | 72,868 | 135,967 | 139,220 |
Natural gas revenue (per dth) | ||||||
Residential and commercial | $7.29 | $5.82 | $6.90 | $6.01 | $7.05 | $5.99 |
Industrial sales | 5.35 | 4.23 | 5.45 | 4.27 | 5.38 | 3.94 |
Transportation for industrial customers | 0.19 | 0.19 | 0.19 | 0.19 | 0.18 | 0.17 |
Heating degree days | ||||||
colder (warmer) than normal | (16%) | 1% | 7% | (9%) | 2% | (5%) |
Average temperature-adjusted usage per | ||||||
customer (dth) | 17.2 | 17.2 | 66.5 | 69.3 | 116.1 | 118.3 |
Customers at June 30, | ||||||
Residential and commercial | 770,472 | 748,512 | ||||
Industrial | 1,223 | 1,282 | ||||
Total | 771,695 | 749,794 | ||||
Questar Gas lost $4.0 million in the second quarter of 2004 and reported income of $22.3 million in the first half of 2004 compared with a loss of $16.5 million in the second quarter of 2003 and income of $9.2 million in the first half of 2003. The 2003 second quarter results included an expense of $22.0 million ($13.6 million after-tax) accrued for potential refund to customers for a dispute over gas-processing costs with the PSCU. Questar Gas has continued to accrue a liability for this potential refund to customers pending an order from the PSCU which totaled $27.9 million as of June 30, 2004. Excluding these charges Questar Gas’s second quarter loss was $3.1 million in 2004 and $2.9 million in 2003. First half 2004 net income excluding the accrual was $24.2 million compared with $22.8 million for the first half of 2003.
Questar Gas’s margin increased by 2% in the second quarter of 2004, 1% in the first half of 2004 and decreased 3% in the 12 months ended June 30, 2004, compared with the 2003 periods. Following is a summary of major changes in Questar Gas’s margin for the second quarter, first half and 12 months ended June, 30, 2004, compared with the same periods of 2003.
Margin Variance Analysis | |||||
3 Months Ended June 30, 2004 | 6 Months Ended June 30, 2004 | 12 Months Ended June 30, 2004 | |||
(in thousands) | |||||
General rate case effective December 30, 2002 | $4,700 | ||||
New customers | $659 | $2,549 | 4,450 | ||
Change in usage per customer | (3,781) | (2,971) | |||
Customer contribution revenues in 2002 | (6,003) | ||||
2002 recovery of gas-processing costs | (3,800) | ||||
Other | 215 | 2,624 | (2,309) | ||
Increase (decrease) | $874 | $1,392 | ($5,933) | ||
Effective December 30, 2002, the PSCU approved an $11.2 million general-rate increase and an 11.2% allowed return on equity. The PSCU based the increase on November 2002 rate base, operating costs and usage per customer.
At June 30, 2004, Questar Gas was serving 771,695 customers. Customer growth remained above national averages at 2.9% over the prior year. Housing construction in Utah remained strong, driven by low mortgage-interest rates. Usage per customer, adjusted for normal temperatures, was flat in the second quarter of 2004 and declined 4% in the first half of 2004 and 2% in the 12 months ended June 30, 2004, compared with the 2003 periods. Usage per customer has been decreasing due to more efficient appliances and homes and customer response to higher prices.
Weather, as measured in degree days, was 16% warmer than normal in the second quarter of 2004 and 7% colder than normal in the first half of 2004 compared with 1% colder than normal in the second quarter of 2003 and 9% warmer than normal in the first half of 2003. A weather-normalization adjustment on customer bills generally offsets financial impacts of moderate temperature variations.
Questar Gas’s results for the 12 months ended June 30, 2003, included $3.8 million of recovery of previously denied 1999 gas-processing costs. The PSCU’s 2002 order allowing the recovery of gas-processing costs is part of a continuing dispute, as discussed below.
Questar Gas’s results for the 12 months ended June 30, 2003, also included revenues of $6.0 million due to upfront contributions from customers. Accounting for customer contributions changed beginning in 2003 as a result of the 2002 Utah general rate case. Customer contributions are now recorded as a reduction of investment instead of revenues and general rates were increased to make up for the change in revenues.
Industrial deliveries declined 12% in the second quarter of 2004, 5% in the first half of 2004 and 14% in the 12 months ended 2004 compared with the 2003 periods. These changes were primarily driven by power-generation requirements.
Cost of natural gas sold increased 21% in the second quarter of 2004, 42% in the first half of 2004 and 39% in the 12 months ended 2004 compared with the 2003 periods. These changes were due to increased volumes and increased natural gas purchase costs. Questar Gas accounts for purchased-gas costs in accordance with procedures authorized by the PSCU and the Public Service Commission of Wyoming. Purchased-gas costs that are different from those provided for in present rates are accumulated and recovered or credited through future rate changes. As of June 30, 2004, Questar Gas had a $25.3 million balance in the purchased-gas adjustment account representing gas costs incurred but not yet recovered from customers.
Operating and maintenance expenses increased 4% in the second quarter of 2004, 2% in the first half of 2004 and decreased 6% in the 12 months ended 2004 compared with the 2003 periods. Lower information technology and labor costs offset higher contracted services and bad-debt costs. Questar Gas has PSCU approval to record incremental pipeline integrity costs in a regulatory-asset account. The costs will be amortized over a five-year period beginning with the next general rate case or 2007, which ever occurs first. Operating and maintenance expenses per customer were $131 in the 12 months ended June 30, 2004, compared with $144 for the 2003 period.
The Utah Supreme Court, in August 2003, reversed earlier PSCU decisions in 2000 and 2002. The PSCU in August 2000 permitted Questar Gas to collect $5.0 million per year through May 2004 to recover a portion of the costs of processing certain gas volumes. The Btu content of natural gas entering parts of Questar Gas’s system has been declining over the past decade. Processing provides a multi-year transition period during which customers will be required to have their appliances adjusted to ensure safe and efficient operation. In August 2002 the PSCU allowed an additional $3.8 million of recovery from a previous period. As a result of the 2003 Utah Supreme Court order, Questar Gas recorded a $24.9 million before-tax liability in 2003 and an additional $3.0 million liability in the first half of 2004. The liability reflects a potential refund of gas processing costs collected in rates from June 1999 through June 2004 plus interest. The plant must be operated to protect customers; therefore, management believes past and future costs of gas processing are recoverable in rates. Questar Gas requested ongoing rate coverage for these costs in its last two gas pass-through filings and continues to collect $5.0 million per year. On July 7, 2004, the PSCU issued an order indicating that they would issue their final order in August 2004. They ordered the parties in the case to attempt to settle the issue of ongoing cost coverage. They also invited the parties to settle the issue of past cost coverage.
Depreciation expense increased 6% in the second quarter of 2004, 1% in the first half of 2004 and was flat in the 12 months ended 2004 compared with the 2003 periods. Retirements of plant assets have offset the depreciation impact of plant additions.
Corporate and Other Operations
This reporting segment includes noncore investments in information-technology related businesses, unregulated energy services and corporate activities.
In June of 2004 Questar reorganized its information-technology services. Eighty-two employees were transferred to Regulated Services and 23 employees to corporate. Fourteen employees were laid off and 10 more employees will be laid off in a year. Severance costs were approximately $500,000 in the second quarter of 2004.
Consolidated Results After Operating Income
Interest and other income
The 12 months ended June 30, 2003, includes gains from selling non-core properties of $38.3 million pretax.
Earnings from unconsolidated affiliates
Rendezvous Gas Services’ income increased in the 2004 periods due to higher throughput. Gas Management is a 50% owner in Rendezvous, which provides gas-gathering services for the Pinedale and Jonah producing areas of western Wyoming. Questar Pipeline’s 50% share of the TransColorado partnership earnings of $4.8 million pretax is included in the trailing 12 months ended June 30, 2003.
Debt expense
Lower debt balances and interest rates resulted in lower debt expense in 2004. In 2004 and 2003 Questar Gas replaced higher-cost fixed-rate debt with lower-cost fixed- and floating-rate debt. Market Resources reduced long-term debt by $55 million in 2004.
Income taxes
The effective combined federal and state income tax rate for the first half was 37.5% in 2004 and 37.4% in 2003.
Accounting change
On January 1, 2003, the Company adopted a new accounting standard, SFAS 143, “Accounting for Asset Retirement Obligations,” and recorded a cumulative effect that reduced net income by $5.6 million or $0.07 per diluted common share.
Liquidity and Capital Resources
Operating Activities
6 Months Ended | ||
June 30, | ||
2004 | 2003 | |
(in thousands) | ||
Net income | $118,689 | $ 84,894 |
Noncash adjustments to net income | 157,803 | 135,874 |
Changes in operating assets and liabilities | 15,004 | 20,553 |
Net cash provided from operating activities | $291,496 | $241,321 |
Net cash provided from operating activities increased 21% in 2004 compared with 2003 due to increased income and noncash adjustments to income. However higher sales prices for gas and oil in 2004 resulted in an increase in hedging collateral deposits when compared to a year ago.
Investing Activities
A comparison of capital expenditures for the first half of 2004 and 2003 plus an estimate for calendar year 2004 is presented below. In the second quarter the board of directors approved a $40 million increase in capital expenditures to support an expanded drilling program in 2004.
Forecast | |||
Actual | 12 Months | ||
6 Months Ended | Ended | ||
June 30, | Dec. 31, | ||
2004 | 2003 | 2004 | |
(in thousands) | |||
Market Resources | $ 96,207 | $ 57,146 | $308,200 |
Questar Pipeline | 9,894 | 8,948 | 51,000 |
Questar Gas | 31,577 | 29,035 | 82,800 |
Corporate and other operations | 1,374 | 1,632 | 13,000 |
$139,052 | $ 96,761 | $455,000 | |
Financing Activities
Net cash flow provided from operating activities was more than sufficient to fund capital expenditures and pay dividends in the first half of 2004. The excess cash flow was used to repay debt. As a result total debt was 43% of total capital at June 30, 2004. In 2004 Market Resources repaid $55 million of long-term debt and Questar Gas repaid $17 million in medium-term notes carrying an 8.12% interest rate.
Short-term debt amounted to $32.5 million of commercial paper with an average rate of 1.2% at June 30, 2004. The Company's lines-of-credit capacity is $200 million until October 1, 2004.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Questar’s primary market risk exposures arise from commodity-price changes for natural gas, oil and NGL, estimation of gas and oil reserves and volatility in interest rates. Energy Trading has long-term contracts for pipeline capacity and is obligated for transportation services with no guarantee that it will be able to recover the full cost of these transportation commitments.
Commodity-Price Risk Management
Market Resources bears the risk associated with commodity-price changes and uses gas- and oil-price hedging arrangements in the normal course of business to limit the risk of adverse price movements. However these same arrangements typically limit future gains from favorable price movements. The hedging contracts exist for a significant share of Market Resources-owned gas and oil production and for a portion of gas- and oil-marketing transactions.
Market Resources has established policies and procedures for managing commodity-price risks through the use of derivatives. Natural gas- and-oil-price hedging support Market Resources’ rate of return and cash flow targets and protect earnings from downward movements in commodity prices. The volume of hedged production and the mix of derivative instruments are regularly evaluated and adjusted by management in response to changing market conditions and reviewed periodically by Market Resources’ Board of Directors. Market Resources may hedge up to 100% of forecast nonregulated production from proved-developed reserves when prices meet earnings and cash flow objectives. Proved-developed production represents production from existing wells. Market Resources does not enter into derivative arrangements for speculative purposes and does not hedge undeveloped reserves and NGL.
Hedges are matched to equity gas and oil production, thus qualifying as cash-flow hedges under the accounting provisions of SFAS 133 as amended and interpreted. Gas hedges are structured as fixed-price swaps into regional pipelines, locking in basis and hedge effectiveness. The portion of hedges no longer deemed effective is immediately recognized in the income statement. The ineffective portion of hedges was not significant in 2004 and 2003.
As of June 30, 2004, approximately 67.9 bcf of forecast full-year 2004 gas production is hedged at an average price of $4.02 per Mcf, net to the well. Hedges are more heavily weighted to the Rockies to reduce basis risk and to protect returns on capital.
Market Resources enters into commodity-price hedging arrangements with several banks and energy-trading firms. Generally the contracts allow some amount of credit before Market Resources is required to deposit collateral for out-of-the-money hedges. In some contracts the amount of credit varies depending on the credit rating assigned to Market Resources’ debt. Market Resources’ current ratings support counterparty credit ranges from $5.0 million to $20 million. If Market Resources’ credit ratings fall below investment grade (BBB- by Standard & Poor’s or Baa3 by Moody’s), counterparty credit generally falls to zero. Questar maintains lines of credit to cover potential collateral calls. Collateral required at June 30, 2004, was $35.3 million.
A summary of Market Resources’ hedging positions for equity production as of June 30, 2004, is shown below. Prices are net to the well. Currently all hedges are fixed-price swaps with creditworthy counterparties, which allows Market Resources to achieve a known price for a specific volume of production delivered into a regional sales point, i.e., incorporating a known basis. The swap price is then reduced by gathering costs and adjusted for product quality to determine the net-to-the-well price.
Market Resources held gas-price hedging contracts covering the price exposure for about 139.1 MMdth of gas and 1.5 MMbbl of oil as of June 30, 2004. A year earlier Market Resources’ hedging contracts covered 127.3 MMdth of natural gas and 552,000 bbl of oil. Market Resources does not hedge the price of equity NGL.
The following table summarizes changes in the fair value of hedging contracts from December 31, 2003, to June 30, 2004.
A table of the net fair value of gas-hedging contracts as of June 30, 2004, is shown below. About 60% of the volumes and 76% of the fair value of all contracts will settle and be reclassified from other comprehensive income in the next 12 months.
The following table shows sensitivity of the mark-to-market valuation of gas and oil price-hedging contracts to changes in the market price of gas and oil.
At June 30, | ||
2004 | 2003 | |
(in millions) | ||
|
| |
Mark-to-market valuation – asset (liability) | ($115.4) | ($62.2) |
Value if market prices of gas and oil decline by 10% | (55.6) | (24.6) |
Value if market prices of gas and oil increase by 10% | (175.1) | (99.7) |
Interest-Rate Risk Management
As of June 30, 2004, Questar had $933.2 million of fixed-rate long-term debt and no variable-rate long-term debt.
Recent Accounting Pronouncements
On May 19, 2004, the Financial Accounting Standards Board (“FASB”) issued FASB Staff Position (“FSP”) FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.” The referenced legislation (“the Act”) was passed in December 2003, and provides for a federal subsidy to employers who offer retiree prescription drug benefits that are at least actuarially equivalent to those offered under the government sponsored Medicare Part D. The provisions of FSP FAS 106-2 will be effective in the Company’s third quarter of 2004 and amortized over future periods. Final regulations that would define actuarial equivalency have not yet been issued. As a result the expense amounts shown in Note 7 do not reflect the potential effects of the Act, which, due largely to a cap on Company contributions, are not expected to have a material effect on the Company’s consolidated financial statements.
In March 2004 the FASB issued the exposure draft, “Share-Based Payment.” The proposed standard would require all equity-based awards to employees to be recognized in the consolidated statements of income based on an estimate of fair value on the date of the grant. The proposed rule is in effect for fiscal years beginning after December 15, 2004. The new standard, if accepted in its present form, would apply to all awards granted, modified or settled after the effective date. Questar issues restricted shares and stock options to employees and non-employee directors. Restricted shares are expensed over the vesting period. Stock options are accounted for under the intrinsic-value method. The proforma net income effect of expensing the issuance of stock options is shown in Note 5.
Item 4.
Controls and Procedures
a.
Evaluation of Disclosure Controls and Procedures. The Company’s Chief Executive Officer and Chief Financial Officer have evaluated the effectiveness of the Company’s disclosure controls and procedures (as such term is defined in Rules 13a-14(c) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”). Based on such evaluation, such officers have concluded that, as of the Evaluation Date, the Company’s disclosure controls and procedures are effective in alerting them on a timely basis to material information relating to the Company, including its consolidated subsidiaries, required to be included in the Company’s reports filed or submitted under the Exchange Act.
b.
Changes in Internal Controls. Since the Evaluation Date, there have not been any significant changes in the Company’s internal controls in other factors that could significantly affect such controls.
#
PART II
OTHER INFORMATION
Item 1.
Legal Proceedings.
a.
See Note 3 in the Notes accompanying the Company’s Consolidated Financial Statements under Item 1. Financial Statements in Part I of this report for a discussion of the regulatory proceedings involving gas processing costs incurred by Questar Gas. These proceedings have been reviewed in the Company’s reports on Form 10-Q and Form 10-K filed since August 1, 2003.
b.
During the second quarter of 2004, the Environmental Protection Agency (“EPA”) issued two separate compliance orders alleging that Gas Management failed to comply with regulatory requirements adopted to enforce the federal Clean Air Act. Both orders involve facilities in the Uinta Basin of eastern Utah that were owned by Shenandoah Energy Inc. prior to its acquisition in mid-2001 Gas Management is currently operating the facilities and filing necessary reports in compliance with regulatory requirements. It is discussing the allegations with the EPA and expects to be required to pay a civil penalty in excess of $100,000 in conjunction with each order.
Item 2.
Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities.
The following table sets forth the Company’s purchases of common stock registered under Section 12 of the Exchange Act that occurred during the quarter ended June 30, 2004:
Total Number of Shares Purchased | Average Price per Share ($) | Total Number of Shares Purchased as Part of Publicly Announced Plans | Maximum Number of Shares that May Yet Be Purchased Under the Plans | |
April 1, 2004 to April 30, 2004 | 13,447 | 36.57 | - | - |
May 1, 2004 to May 31, 2004 | 3,939 | 36.18 | - | - |
June 1, 2004 to June 30, 2004 | 975 | 37.62 | - | - |
Total | 18,361 | 36.54 | - | - |
*All shares purchased by the Company were in conjunction with tax payment elections made by employees when recognizing ordinary income with nonqualified stock options exercises or when receiving distributions of formerly restricted shares of stock.
Item 4.
Submission of Matters to a Vote of Security Holders.
The Company held its annual meeting on May 18, 2004. The following individuals were elected at the meeting to serve three-year terms as directors: Teresa Beck, R. D. Cash, Robert E. McKee III, Gary G. Michael, and Charles B. Stanley. There was no solicitation in opposition to the nominees. The following is a tabulation of the votes received by nominees elected at the meeting:
#
Name | Votes For | Votes Withheld |
T. Beck | 74,467,605 | 2,675,406 |
R. D. Cash | 75,009,750 | 2,133,261 |
R. E. McKee | 58,832,022 | 18,310,989 |
G. G. Michael | 73,793,475 | 3,349,536 |
C. B. Stanley | 75,219,956 | 1,923,055 |
The Company’s directors are divided into three classes. Other directors whose terms extend beyond the meeting include Phillips S. Baker, Jr., P. J. Early, L. Richard Flury, James A. Harmon, Robert E. Kadlec, Keith O. Rattie, and Harris H. Simmons.
At the meeting, the Company’s shareholders also approved the Long-term Cash Incentive Plan, with 72,554,079 shares voted in favor, 3,771,507 shares voted against, and 813,415 shares abstaining.
Item 5.
Other Information.
a.
W. Whitley Hawkins resigned as a director effective May 18, 2004 because he had reached the mandatory retirement age of 72. Mr. Hawkins was appointed to serve as a senior director and will continue to serve as a director of Questar Gas. During his 13 years of service as a director, Mr. Hawkins served as a member and Chair of the Management Performance Committee, as a member and Chair of the Governance/Nominating Committee and as a member of the Executive Committee.
Mr. Hawkins’ resignation leaves a vacancy in the Board of Directors.
b.
On May 18, 2004, P. J. Early was appointed to serve as Chair of the Executive Committee, replacing Robert E. Kadlec, who will continue to serve as a member of it. As Chair of the Executive Committee, Mr. Early is the lead director and conducts executive sessions of the Board of Directors. Shareholders may communicate with the Board of Directors, including Mr. Early as the lead director, and all non-management directors as a group by sending a letter addressed to the full Board, Mr. Early, or the non-management directors in care of the Corporate Secretary at the Company’s headquarters, 180 East 100 South, P.O. Box 45433, Salt Lake City, Utah 84145-0433. The Corporate Secretary’s office has the authority to discard any solicitations, advertisements, or other inappropriate communications, but will forward any mail to the named director or group of directors that isn’t otherwise excluded.
c.
Gary G. Michael, on May 18, 2004, replaced Mr. Hawkins as the Chair of the Governance/Nominating Committee. Shareholders interested in submitting candidates for consideration as nominees for directors can submit in writing the names and qualifications of the candidate(s) to Mr. Michael at the address of the Company’s general headquarters provided above. Any nomination letters addressed to Mr. Michael will be forwarded without screening. Individuals so nominated will be reviewed using the criteria used by the Committee as set forth in the Committee’s charter published on the Company’s website (www.questar.com).
#
Item 6.
Exhibits and Reports on form 8-K:
a.
The following exhibits are being filed as part of this report:
Exhibit No.
Exhibit
12.
Ratio of earnings to fixed charges.
31.1.
Certification signed by Keith O. Rattie, Questar's Chief Executive Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2.
Certification signed by S. E. Parks, Questar's Chief Financial Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.
Certification signed by Keith O. Rattie and S. E. Parks, Questar's Chief Executive Officer and Chief Financial Officer, respectively, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
b.
During the quarter, Questar filed the following Current Report on Form 8-K: Current Report dated April 29, 2004, filing a copy of the Company's earnings release for the period ended March 31, 2004.
SIGNATURES
Pursuant to the requirements 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.
QUESTAR CORPORATION
(Registrant)
August 4, 2004
/s/Keith O. Rattie___________________________________
Date
Keith O. Rattie, Chairman of the Board,
President and Chief Executive Officer
August 4, 2004
/s/S. E. Parks______________________________________
Date
S. E. Parks, Senior Vice President and
Chief Financial Officer
#
Exhibit List
Exhibit No.
Exhibit
12. | Ratio of earnings to fixed charges. |
31.1. | Certification signed by Keith O. Rattie, Questar Corporation's Chief Executive Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
31.2. | Certification signed by S. E. Parks, Questar Corporation's Chief Financial Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
32. | Certification signed by Keith O. Rattie and S. E. Parks, Questar Corporation's Chief Executive Officer and Chief Financial Officer, respectively, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
#
For purposes of this presentation, earnings represent income before income taxes and cumulative effect of accounting change adjusted for fixed charges, earnings and distributions of equity investees and equity in minority interest. Fixed charges consist of total interest charges (expensed and capitalized), amortization of debt issuance costs, and the interest portion of rental expense estimated at 50%. Income before income taxes and a cumulative effect of accounting change includes Questar's share of pretax earnings of equity investees.
#
Exhibit No. 31.1.
CERTIFICATION
I, Keith O. Rattie, certify that:
1.
I have reviewed this quarterly report on Form 10-Q of Questar Corporation.
2.
Based on my knowledge, this quarterly 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 quarterly report.
3.
Based on my knowledge, the financial statements, and other financial information included in this quarterly 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 quarterly 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-14 and 15d-14) for the registrant and we have:
a)
designed such disclosure controls and procedures 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 quarterly report is being prepared;
b)
evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and
c)
presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5.
The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, 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 in the design or operation of internal controls that could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
b)
any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls;
6.
The registrant's other certifying officer and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
August 4, 2004
/s/Keith O. Rattie___________________________________
Date
Keith O. Rattie
Chairman, President and Chief Executive
Officer
#
Exhibit No. 31.2.
CERTIFICATION
I, S. E. Parks, certify that:
1.
I have reviewed this quarterly report on Form 10-Q of Questar Corporation.
2.
Based on my knowledge, this quarterly 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 quarterly report.
3.
Based on my knowledge, the financial statements, and other financial information included in this quarterly 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 quarterly 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-14 and 15d-14) for the registrant and we have:
a)
designed such disclosure controls and procedures 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 quarterly report is being prepared;
b)
evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and
c)
presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5.
The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, 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 in the design or operation of internal controls that could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
b)
any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls;
6.
The registrant's other certifying officer and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
August 4, 2004
/s/S. E. Parks______________________________________
Date
S. E. Parks
Senior Vice President and Chief
Financial Officer
#
Exhibit No. 32.
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTON 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Quarterly Report of Questar Corporation (the "Company") on Form
10-Q for the period ending June 30, 2004, as filed with the Securities and Exchange Commission on the date hereof (the "Report"), Keith O. Rattie, Chairman, President and Chief Executive Officer of the Company, and S. E. Parks, Senior Vice President and Chief Financial Officer of the Company, each hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to the best of his knowledge:
(1)
The Report fully complies with the requirements of Section 13(a) or Section 15(d) of the Securities Exchange Act of 1934; and
(2)
The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
QUESTAR CORPORATION
August 4, 2004
/s/Keith O. Rattie___________________________________
Date
Keith O. Rattie
Chairman, President and Chief Executive
Officer
August 4, 2004
/s/S. E. Parks______________________________________
Date
S. E. Parks
Senior Vice President and Chief
Financial Officer
#