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 MARCH 31, 2005 | |
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 | |||
| ||||
180 East 100 South | 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 April 30, 2005 | |
Common Stock, without par value with attached Common Stock Purchase Rights | 84,826,700 Shares |
Questar Corporation
Form 10-Q for the Quarterly Period Ended March 31, 2005
TABLE OF CONTENTS
Page #
GLOSSARY OF COMMONLY USED TERMS
FORWARD-LOOKING STATEMENTS
PART I.
FINANCIAL INFORMATION
Item 1.
Financial Statements
Consolidated Statements of Income for the three months ended
March 31, 2005 and 2004
8
Condensed Consolidated Balance Sheets at March 31, 2005
and December 31, 2004
9
Condensed Consolidated Statements of Cash Flows for the three months ended
March 31, 2005 and 2004
10
Notes Accompanying Consolidated Financial Statements
11
Item 2.
Management’s Discussion and Analysis of Financial Condition and
Results of Operations
18
Item 3.
Quantitative and Qualitative Disclosures about Market Risk
31
Item 4.
24
PART II.
OTHER INFORMATION
Item 1.
35
Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
35
Item 5.
36
Item 6.
36
36
GLOSSARY OF COMMONLY USED TERMS
bbl
Barrel, which is equal to 42 U.S. gallons and is a common unit of measurement of crude oil.
basis
The difference between a reference or benchmark-commodity price and the corresponding sales price 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 equivalents. 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.
cf
Cubic foot is a common unit of gas measurement. One standard cubic foot equals the volume of gas in one cubic foot measured at standard conditions – a temperature of 60 degrees Fahrenheit and a pressure of 30 inches of mercury (approximately 14.73 pounds per square inch).
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 production exceed 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 prospect to determine the presence of gas or oil.
finding costs
Finding costs are the sum of costs incurred for gas and oil exploration and development activities; including leasehold acquisitions, seismic, geological and geophysical, development and exploration drilling and asset-retirement obligations for a given period, divided by the total amount of estimated net-proved reserves added through discoveries, positive and negative revisions of previous estimates and purchases in-place for the same period. The Company expresses finding costs in dollars per Mcfe averaged over a five-year period.
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.
gas
All references to “gas” in this report refer to natural gas.
gross
“Gross” natural gas and oil wells or “gross” acres equal the total number of wells or acres in which the Company has a working interest.
heating-degree days
A measure of the number of degrees the average-daily outside temperature is below 65 degrees Fahrenheit.
hedging
The use of derivative-commodity and interest-rate instruments to reduce financial exposure to commodity-price and interest-rate volatility.
Mbbl
One thousand barrels.
Mcf
One thousand cubic feet.
Mcfe
One thousand cubic feet of natural gas equivalents. 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.
Mdth
One thousand decatherms.
Mdthe
One thousand decatherm equivalents. 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.
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.
MMgal
One million U. S. gallons.
natural gas liquids
Liquid hydrocarbons that are extracted and separated from the natural gas
(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 the sum of the fractional ownership working interest the Company has in those gross wells or acres.
production-
The production-replacement ratio is calculated by dividing the net-proved
replacement ratio
reserves added through discoveries, positive and negative revisions of previous estimates and purchases and sales in-place for a given period by the production for the same period, expressed as a percentage. The production-replacement ratio is typically reported on an annual basis.
proved reserves
Those quantities of natural gas, crude oil, condensate and NGL on a net-revenue-interest basis, which geological and engineering data demonstrate with reasonable certainty to be recoverable under existing economic and operating conditions. See 17 C.F.R. Section 4-10(a)(2) for a complete definition.
proved-developed
Reserves that include proved developed-producing reserves
reserves
and proved-developed behind-pipe reserves. See 17 C.F.R. Section 4-10(a)(3).
proved-developed-
Reserves expected to be recovered from existing completion intervals in
producing reserves
existing wells.
proved-undeveloped
Reserves expected to be recovered from new wells on proved-undrilled acreage
reserves
or from existing wells where a relatively major expenditure is required for recompletion. See 17 C.F.R. Section 4-10(a)(4).
reservoir
A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is 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.
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, but are not limited to, the following:
Questar subsidiaries find, produce and sell natural gas, oil and NGL
Natural gas, oil and NGL prices are volatile and, therefore, Questar revenues, cash flow and earnings can be volatile. The Company cannot predict future natural gas, oil and NGL prices, which are subject to forces beyond its control such as:
•
Domestic and foreign supply of and demand for natural gas and oil;
•
Regional basis differential due to pipeline-capacity constraints;
•
Domestic and global economic conditions;
•
Weather;
•
Domestic and foreign government regulations;
•
The price and availability of alternative fuels; and
•
The price and availability of drilling rigs and other materials and services.
Gas and oil prices are volatile
The Company uses financial contracts to hedge its exposure to volatile energy prices and to protect cash flow, returns on capital, net income and credit ratings from downward commodity-price movements. While hedging reduces the impact of declining prices, it may also limit future revenues from rising prices. Questar believes the Company’s regulated businesses – interstate natural gas transportation and retail gas distribution – and its Wexpro subsidiary generate revenues that are not significantly sensitive to short-term fluctuations in energy prices.
Questar’s profitability depends not only on prevailing prices for natural gas and oil, but also the Company’s ability to find, develop and acquire gas and oil reserves that are economically recoverable. Substantial capital expenditures are required to find, develop and acquire gas and oil reserves to replace those depleted by production.
Estimating gas and oil reserves, production and future net cash flow is difficult
Questar Exploration and Production’s proved natural gas and oil-reserve estimates are prepared annually by independent reservoir-engineering consultants. Gas and oil-reserve estimates are subject to numerous uncertainties inherent in estimating quantities of proved reserves, projecting future rates of production and timing of development expenditures. The accuracy of these estimates depends on the quality of available data and on engineering and geological interpretation and judgment. Reserve estimates are imprecise and will change as additional information becomes available. Estimates of economically recoverable reserves and future net cash flows prepared by different engineers, or by the same engineers at different times may vary significantly. Results of subsequent drilling, testing and production may cause either upward or downward revisions of previous estimates. In addition, the 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 change. The volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. The meaningfulness of such estimates depends on the accuracy of the assumptions upon which they were based. Actual results may differ materially from the estimated results.
Drilling is a high-risk activity
Operating risks include: blow-outs; fire; unexpected drilling conditions such as uncontrollable flows of gas, oil, formation water or drilling fluids; abandonment costs; explosions; pipe, cement or casing failures; oil spills; natural gas leaks; pipeline ruptures; and discharges of toxic gases. The Company could incur substantial losses as a result of injury or loss of life; environmental damage; destruction of property; fines; or curtailment of operations. The Company maintains insurance against some, but not all, of these potential risks and losses.
Questar must comply with numerous regulations from the federal, state and local level
Questar is subject to federal, state and local environmental, health and safety laws and regulations. Environmental laws and regulations are complex, change frequently and tend to become more onerous over time. In addition to the costs of compliance, the Company may incur substantial costs to take corrective actions at both owned and previously owned facilities. Accidental spills and leaks requiring cleanup may occur in the ordinary course of business. As standards change, the Company may incur significant costs in cases where past operations followed practices that were considered acceptable at the time but that now require remedial work to meet current standards. Failure to comply with these laws and regulations may result in fines, significant costs for remedial activities, or injunctions.
Questar must comply with numerous and complex regulations governing activities on federal and state lands in the Rocky Mountain region, notably the National Environmental Policy Act, the Endangered Species Act and the National Historic Preservation Act. Federal and state agencies frequently impose conditions on the Company’s activities. These restrictions tend to become more stringent over time, and can limit or prevent the Company from exploring for, finding and producing natural gas and oil on its Rockies leaseholds. Certain environmental groups oppose drilling on some of the Company’s federal and state leases.
Various federal agencies within the U.S. Department of the Interior, particularly the Minerals Management Service and the Bureau of Indian Affairs, along with each Native American tribe, promulgate and enforce regulations pertaining to gas and oil operations on Native American tribal lands. These regulations include such matters as lease provisions, drilling and production requirements, environmental standards and royalty considerations. In addition, each Native American tribe is a sovereign nation having the right to enforce laws and regulations independent from federal, state and local statutes and regulations, as long as they do not supersede or conflict with federal law. These tribal laws and regulations include various taxes, fees, requirements to employ Native American tribal members, and other conditions that apply to lessees, operators and contractors conducting operations on Native American tribal lands. Finally, lessees and operators conducting operations on tribal lands are generally subject to the Native American tribal court system. One or more of these factors may increase Questar’s costs of doing business on Native American tribal lands and have an impact on the viability of its gas and oil operations on such lands.
Questar Pipeline’s natural gas-transportation and storage operations are regulated by the Federal Energy Regulatory Commission (FERC) under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. The FERC has authority to: set rates for natural gas transportation, storage and related services; set rules governing business relationships between the pipeline subsidiary and its affiliates; approve new pipeline and storage-facility construction; and establish policies and procedures for accounting, purchase, sale, abandonment and other activities. FERC policies may adversely affect Questar Pipeline profitability.
Both Questar Pipeline and Questar Gas must incur significant costs to comply with federal pipeline-safety regulations. Questar may also be affected by possible future regulations requiring the tracking, reporting and reduction of greenhouse-gas emissions.
State agencies regulate the distribution of natural gas
Questar Gas’s natural gas-distribution business is regulated by the Public Service Commission of Utah (PSCU) and the Public Service Commission of Wyoming (PSCW). These commissions set rates for distribution services and establish policies and procedures for services, accounting, purchase, sale and other activities. PSCU and PSCW policies may adversely affect Questar Gas profitability.
Other factors may affect Questar’s results
Other factors may affect Questar’s results such as changes in general economic conditions; changes in regulation; availability and economic viability of gas and oil properties for sale or exploration; creditworthiness of counterparties; rate of inflation and interest rates; assumptions used in business combinations; weather and natural disasters; changes in customers’ credit ratings; competition from other forms of energy, other pipelines and storage facilities; effects of accounting policies issued periodically by accounting standard-setting bodies; terrorist attacks or acts of war; changes in the business or financial condition of the Company; changes in credit ratings; and availability of financing for Questar and its subsidiaries.
The Company cannot predict these factors nor can it assess the impact, if any, of such factors on its financial position or its results of operations. Accordingly, forward-looking statements should not be relied upon as a predictor of actual results. Questar undertakes no obligation to update any forward-looking statement provided in this report.
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
See notes accompanying consolidated financial statements
NOTES ACCOMPANYING CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Note 1 – Basis of Presentation of Interim Consolidated Financial Statements
The accompanying Questar interim consolidated financial statements have not been audited by an independent registered public accounting firm, with the exception of the condensed consolidated balance sheet at December 31, 2004, which was derived from the audited consolidated financial statements at that date. The unaudited consolidated financial statements were prepared in accordance with U.S. generally accepted accounting principles (GAAP) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. The interim consolidated financial statements reflect all normal, recurring adjustments and accruals that are, in the opinion of management, necessary for a fair presentation of financial position and results of operations for the interim periods presented. The preparation of consolidated financial statements and notes in conformity with GAAP requires that management make estimates and assumptions that affect the amounts of assets and liabilities and disclosure of contingent assets and liabilities. Actual results could differ from estimates. All significant intercompany accounts and transactions were eliminated in consolidation. Certain reclassifications were made to the 2004 financial statements to conform with the 2005 presentation.
The results of operations for the three months ended March 31, 2005, are not necessarily indicative of the results that may be expected for the year ending December 31, 2005, due to the volatility of gas and oil sales prices, the seasonal nature of the gas-distribution business and other risk factors discussed in the Forward-Looking Statements section of this report. Interim consolidated financial statements do not include all of the information and notes required by GAAP for audited annual consolidated 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 as amended for the year ended December 31, 2004.
Note 2 – Rate-Refund Obligations
Gas-Processing Dispute
On August 1, 2003, the Utah Supreme Court issued an order reversing an August 2000 decision made by the PSCU concerning certain natural gas-processing costs incurred by Questar Gas to manage the heat content of its gas supply. The court ruled that the PSCU did not comply with its statutory responsibilities and regulatory procedures when approving a stipulation in Questar Gas’s 1999 general rate case. The stipulation permitted Questar Gas to collect $5.0 million per year, a portion of the processing costs, through May 2004. The Committee of Consumer Services, a Utah state agency, appealed the PSCU’s decision, arguing that the PSCU had failed to 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. A total liability of $29.0 million includes revenue received for processing costs and interest from June 1999 through September 2004.
On August 30, 2004, the PSCU ruled that Questar Gas failed in 1999 to prove that its decision to contract for gas processing with an affiliate was prudent. The PSCU rejected the stipulation, denied the request for rate recovery and ordered the refund of gas-processing costs previously collected in rates. Because Questar Gas had previously accrued a liability for the refund, the order did not have a material impact on 2004 earnings. Questar Gas reduced its rates on September 1, 2004, to eliminate the collection of gas-processing costs and on October 1 began refunding previously collected costs, plus interest, over a 12-month period. As of March 31, 2005, Questar Gas had a refund liability of $9.2 million.
In response to a Questar Gas petition, the PSCU clarified that its order did not preclude recovery of ongoing and certain past-processing costs. Ongoing processing costs are approximately $6.0 million per year. Questar Gas has requested ongoing rate coverage for gas-processing costs in its pass-through filings, but is not currently collecting these costs in rates. The PSCU has conducted several technical conferences to determine what actions should be taken to manage the heat content of the gas supply. On January 31, 2005, Questar Gas filed a rate request with the PSCU to recover $5.7 million per year of gas-processing costs through its gas-balance account. Questar Gas filed expert testimony supporting the rate request on April 15, 2005, and hearings before the PSCU are scheduled for October 2005.
Fuel-Gas Reimbursement
During the fourth quarter of 2004, the FERC issued an order to Questar Pipeline in a case involving the annual fuel-gas reimbursement percentage (FGRP). The FERC previously granted Questar Pipeline’s request to increase the FGRP effective January 1, 2004. In its order, the FERC approved the FGRP but also ruled that Questar Pipeline is required to credit to transportation customers proceeds from the sale of natural gas liquids recovered from its hydrocarbon dew point facilities at the Clay Basin storage field in northeastern Utah. Questar Pipeline has filed a request for rehearing with the FERC. Questar Pipeline believes that any credit to customers should be reduced by the plant’s cost of service. Until the issue is resolved, Questar Pipeline will continue to accrue a potential liability equal to any liquid revenues from the dew point plant. As of March 31, 2005, Questar Pipeline had reduced revenues by $5.2 million as a potential credit to customers, including $0.5 million recorded in the first quarter of 2005.
Questar Pipeline made an annual FGRP filing with the FERC on November 30, 2004, requesting an increase in the FGRP to 2.6%. On December 30, 2004, the FERC approved the request on an interim basis subject to refund and final resolution of the 2004 FGRP proceeding. Several shippers have filed comments with the FERC protesting the FGRP level.
Note 3– Asset-Retirement Obligations (ARO)
Questar recognizes ARO in accordance with SFAS 143 “Accounting for Asset Retirement Obligations.” SFAS 143 addresses the financial accounting and reporting of the fair value of legal obligations associated with the retirement of tangible long-lived assets. The Company’s ARO applies primarily to plugging and abandonment costs associated with gas and oil wells and certain other properties. The fair value of abandonment costs are estimated and depreciated over the life of the related assets. ARO are adjusted to present value each period through an accretion calculation using a credit-adjusted risk-free interest rate.
Changes in asset-retirement obligations were as follows:
2005 | 2004 | ||
(in thousands) | |||
Balance at January 1, | $67,288 | $61,358 | |
Accretion | 1,025 | 939 | |
Additions | 399 | 427 | |
Retirements and properties sold | (384) | (2) | |
Balance at March 31, | $68,328 | $62,722 | |
Wexpro activities are governed by a long-standing agreement with the states of Utah and Wyoming (the Wexpro Agreement). The accounting treatment of reclamation activities associated with ARO for properties administered under the Wexpro Agreement is spelled out in a guideline letter between Wexpro and the Utah Division of Public Utilities and the staff of the PSCW. Pursuant to the stipulation, Wexpro collects and deposits in trust certain funds related to estimated ARO costs. The funds are used to satisfy retirement obligations as the properties are abandoned. At March 31, 2005, approximately $3.1 million was held in this trust invested in a short-term bond index fund.
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 plus an estimated number of nonvested restricted shares.
3 Months Ended | |||
March 31, | |||
2005 | 2004 | ||
(in thousands) | |||
Weighted-average basic common shares outstanding | 84,417 | 83,374 | |
Potential number of shares issuable from exercising | |||
stock options and from vesting restricted shares | 2,311 | 1,794 | |
Weighted-average diluted common shares outstanding | 86,728 | 85,168 | |
In the first three months of 2005, Questar issued 417,000 shares under the terms of the Long-Term Stock Incentive Plan, the Dividend Reinvestment and Stock Purchase Plan and to satisfy its contributions to the Employee Investment Plan.
Note 5 – Stock-Based Compensation
Questar issues stock options and nonvested restricted shares to employees and non-employee directors. The Company accounts for employee stock-based compensation using the intrinsic value method prescribed by Accounting Principles Board (APB) Opinion 25, “Accounting for Stock Issued to Employees” and related interpretations. No compensation expense is recorded because the exercise price of options is equal to the market price on the date of grant. The table below shows pro forma income had options been expensed according to SFAS 123 “Accounting for Stock-Based Compensation” based on fair value calculated using the Black-Scholes model.
3 Months Ended | |||
March 31, | |||
2005 | 2004 | ||
(in thousands) | |||
Net income, as reported | $95,171 | $76,133 | |
Deduct stock-based compensation expense | |||
determined under fair-value based methods | (359) | (652) | |
Pro forma net income | $94,812 | $75,481 | |
Earnings per share | |||
Basic, as reported | $1.13 | $0.91 | |
Basic, pro forma | 1.12 | 0.91 | |
Diluted, as reported | 1.10 | 0.89 | |
Diluted, pro forma | 1.09 | 0.89 | |
Net income, as reported in the table above, reflects expenses related to restricted stock awards. Restricted shares are valued at the market price on the grant date and amortized over the vesting period. Expense for the three months ended March 31, 2005 and 2004, amounted to $0.9 million and $0.6 million, respectively.
In December 2004 the Financial Accounting Standards Board (FASB) issued Statement 123 (revised 2004), or SFAS 123R, “Share Based Payment,” which replaces SFAS 123 and supersedes APB Opinion 25. SFAS 123R eliminates the alternative to use APB Opinion 25’s intrinsic value method of accounting that was provided in SFAS 123 as originally issued. After a phase-in period for SFAS 123R, pro forma disclosure will no longer be allowed. The Company’s effective date for implementation of SFAS 123R is January 1, 2006. Alternative phase-in methods are allowed under SFAS 123R. The Company currently anticipates using the modified prospective phase-in method that requires entities to recognize compensation costs for all share based payments granted, modified or settled after the date of implementation as well as for any awards that were granted prior to the implementation date for which the required service has not yet been performed. Questar does not believe that any of the alternative phase-in methods would have a materially different effect on the Company’s Consolidated Statements of Income or Balance Sheet.
Note 6 – Operations by Line of Business
Questar has three primary reporting segments: Market Resources, Questar Pipeline and Questar Gas. Lines of business information are presented according to senior management’s basis for evaluating performance including differences in the nature of products, services and regulation. Certain intersegment sales include intercompany profits. Financial information for reportable segments follows below:
3 Months Ended | |||
March 31, | |||
2005 | 2004 | ||
(in thousands) | |||
REVENUES FROM UNAFFILIATED CUSTOMERS | |||
Market Resources | $314,338 | $234,054 | |
Questar Pipeline | 17,912 | 18,013 | |
Questar Gas | 343,690 | 306,879 | |
Corporate and other operations | 4,384 | 4,670 | |
$680,324 | $563,616 | ||
REVENUES FROM AFFILIATED COMPANIES | |||
Market Resources | $ 38,084 | $ 34,357 | |
Questar Pipeline | 22,425 | 22,293 | |
Questar Gas | 1,261 | 1,137 | |
Corporate and other operations | 602 | 6,527 | |
$ 62,372 | $ 64,314 | ||
OPERATING INCOME | |||
Market Resources | $ 94,718 | $ 69,323 | |
Questar Pipeline | 18,357 | 18,287 | |
Questar Gas | 49,951 | 47,899 | |
Corporate and other operations | 675 | 1,281 | |
$163,701 | $136,790 | ||
NET INCOME | |||
Market Resources | $ 56,621 | $ 40,255 | |
Questar Pipeline | 8,339 | 8,113 | |
Questar Gas | 28,712 | 26,311 | |
Corporate and other operations | 1,499 | 1,454 | |
$ 95,171 | $ 76,133 | ||
Note 7 – Employee Benefits
Questar has defined-benefit pension and postretirement medical and life insurance plans covering the majority of its employees. 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. Currently the qualified pension expense estimate for 2005 is $16.4 million. Components of qualified pension expense included in the determination of interim net income are listed below:
Qualified Pension Expense
3 Months Ended | |||
March 31, | |||
2005 | 2004 | ||
(in thousands) | |||
Service cost | $2,265 | $2,140 | |
Interest cost | 5,135 | 4,840 | |
Expected return on plan assets | (4,962) | (4,674) | |
Prior service and other costs | 320 | 481 | |
Recognized net-actuarial loss | 736 | 541 | |
Amortization of early-retirement costs | 725 | 719 | |
Qualified pension expense | $4,219 | $4,047 | |
Expense of Postretirement Benefits Other than Pensions
The Company currently estimates a $5.5 million expense for postretirement benefits in 2005 before $0.8 million for accretion of a regulatory liability. Expense components are listed below:
3 Months Ended | |||
March 31, | |||
2005 | 2004 | ||
(in thousands) | |||
Service cost | $ 219 | $ 221 | |
Interest cost | 1,310 | 1,317 | |
Expected return on plan assets | (730) | (653) | |
Amortization of transition obligation | 470 | 470 | |
Amortization of losses | 119 | 142 | |
Accretion of regulatory liability | 200 | 200 | |
Postretirement benefit expense | $1,588 | $1,697 | |
Note 8 – 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 March 31, 2005, were: Rendezvous Gas Services, LLC, a limited liability corporation, (50%) and Canyon Creek Compression Co., a general partnership (15%).
Operating results representing 100% of the businesses are listed below:
3 Months Ended | |||
March 31, | |||
2005 | 2004 | ||
(in thousands) | |||
Revenues | $4,835 | $4,376 | |
Operating income | 3,069 | 2,767 | |
Income before income taxes | 3,090 | 2,772 | |
Note 9 – 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 in the first quarter 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 | |||||
March 31, | |||||
2005 | 2004 | ||||
(in thousands) | |||||
Net income | $ 95,171 | $ 76,133 | |||
Other comprehensive loss | |||||
Unrealized loss on energy-hedging transactions | (186,154) | (23,760) | |||
Income taxes | 70,771 | 8,935 | |||
Net other comprehensive loss | (115,383) | (14,825) | |||
Total comprehensive income (loss) | ($20,212) | $ 61,308 | |||
The components of accumulated other comprehensive loss are as follows, net of income taxes.
March 31, | March 31, | ||
2005 | 2004 | ||
Unrealized loss on energy-hedging transactions | ($157,533) | ($47,460) | |
Additional pension liability | (12,027) | (8,663) | |
Accumulated other comprehensive loss | ($169,560) | ($56,123) | |
Note 10 – Recent Accounting Development
On April 4, 2005, the FASB issued FSP FAS 19-1, “Accounting for Suspended Well Costs.” FSP FAS 19-1 modifies a requirement of SFAS 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies,” to capitalize the costs of drilling exploratory wells pending determination of whether the well has found proved reserves. The capitalized costs become part of the entity’s wells, equipment and facilities if the well successfully located proved reserves. However, if the well has not found proved reserves, the capitalized costs of drilling the well are expensed, net of any salvage value. FSP FAS 19-1 states that exploratory well costs can be capitalized beyond the previously prescribed one-year limit if the well has found a sufficient quantity of reserves to justify its completion as a producing well and the entity is making sufficient progress assessing the reserves and the economic and operating viability of the project.
The Company drills exploratory wells in onshore U.S. petroleum-producing regions with good access to downstream markets. Factors such as weather, seasonal access restrictions on federal land, or delays caused by permitting production facilities can cause minor delays in connecting successful exploratory wells to downstream markets, but those delays are typically less than one year. The Company currently has no completed exploratory wells classified as suspended.
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
(Unaudited)
SUMMARY
Questar Corporation (Questar or the Company) is a natural gas-focused energy company that conducts operations through three principal subsidiaries. Questar Market Resources (Market Resources), through various subsidiaries, engages in gas and oil exploration, acquisition, development and production; production and development of cost-of-service reserves; gas-gathering and processing services; and wholesale gas and hydrocarbon-liquids marketing, risk management and gas storage. Questar Pipeline Company (Questar Pipeline) conducts interstate gas-transportation and storage activities. Questar Gas Company (Questar Gas) provides retail gas distribution services.
Questar reported net income for the first three months of 2005 of $95.2 million or $1.10 per diluted share compared to $76.1 million or $0.89 per share for the first three months of 2004. Following is a comparison of net income by line of business.
3 Months Ended March 31, | Increase | Percentage | ||
2005 | 2004 | Change | ||
(in thousands, except per share amounts) | ||||
Market Resources | $56,621 | $40,255 | $16,366 | 41% |
Questar Pipeline | 8,339 | 8,113 | 226 | 3% |
Questar Gas | 28,712 | 26,311 | 2,401 | 9% |
Corporate and other operations | 1,499 | 1,454 | 45 | 3% |
Net Income | $95,171 | $76,133 | $19,038 | 25% |
Earnings per diluted common share | $1.10 | $0.89 | $0.21 | 24% |
Market Resources net income was 41% higher in the first quarter of 2005 compared to the first quarter of 2004. The increase in net income was driven by increased gas production, higher prices for gas, oil and NGL, increased investment base at Wexpro and increased throughput and higher margins at Gas Management.
Questar Pipeline net income increased 3%. Revenues and expenses were flat. The earnings increase reflected the capitalization of carrying costs on a construction project.
Questar Gas net income increased 9%. Margins from gas sales were higher due to a 3.1% growth in the number of customers and a 1% increase in temperature-adjusted gas usage per customer.
RESULTS OF OPERATIONS
Market Resources
Market Resources operates through several subsidiaries. Questar Exploration and Production Company (Questar E&P) explores for, acquires, develops and produces gas and oil. Wexpro Company (Wexpro) develops and produces cost-of-service reserves for an 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 Clear Creek Storage Company, LLC, owns and operates an underground gas-storage reservoir.
Market Resources Consolidated Results
Market Resources net income for the first quarter of 2005 totaled $56.6 million compared with $40.3 million for the year earlier period, a 41% increase. Operating income increased to $94.7 million versus $69.3 million in the 2004 quarter, a 37% increase.
Following is a summary of Market Resources’ financial and operating results for the first quarter of 2005 compared with 2004.
3 Months Ended | ||
March 31, | ||
2005 | 2004 | |
(in thousands) | ||
OPERATING INCOME | ||
Revenues | ||
Natural gas sales | $108,601 | $ 88,569 |
Oil and natural-gas-liquids sales | 26,948 | 21,180 |
Cost-of-service gas operations | 33,633 | 28,894 |
Energy marketing | 153,635 | 107,458 |
Gas gathering, processing and other | 29,605 | 22,310 |
Total revenues | 352,422 | 268,411 |
Operating expenses | ||
Energy purchases | 150,514 | 105,145 |
Operating and maintenance | 42,048 | 35,713 |
Depreciation, depletion and amortization | 39,859 | 33,949 |
Exploration | 1,373 | 1,087 |
Abandonment and impairment of gas, oil | ||
and other properties | 1,405 | 4,406 |
Production and other taxes | 21,244 | 17,656 |
Wexpro Agreement – oil-income sharing | 1,261 | 1,132 |
Total operating expenses | 257,704 | 199,088 |
Operating income | $ 94,718 | $ 69,323 |
OPERATING STATISTICS | ||
Questar E&P production volumes | ||
Natural gas (MMcf) | 22,839 | 21,888 |
Oil and natural gas liquids (Mbbl) | 583 | 587 |
Total production (bcfe) | 26.3 | 25.4 |
Average daily production (MMcfe) | 293 | 279 |
Average commodity prices, net to the well | ||
Average realized price (including hedges) | ||
Natural gas (per Mcf) | $4.76 | $4.05 |
Oil and natural gas liquids (per bbl) | $38.74 | $29.46 |
Average sales price (excluding hedges) | ||
Natural gas (per Mcf) | $5.18 | $4.72 |
Oil and natural gas liquids (per bbl) | $45.59 | $31.85 |
Wexpro investment base at March 31, net of depreciation and deferred income taxes (millions) | $185.7 | $169.0 |
Natural gas gathering volumes (in thousands of MMBtu) | ||
For unaffiliated customers | 32,535 | 34,294 |
For Questar Gas | 11,256 | 9,757 |
For other affiliated customers | 15,846 | 14,558 |
Total gathering | 59,637 | 58,609 |
Gathering revenue (per MMBtu) | $0.26 | $0.21 |
Natural gas and oil marketing volumes (Mdthe) | ||
For unaffiliated customers | 29,600 | 21,855 |
For affiliated customers | 21,861 | 20,350 |
Total marketing | 51,461 | 42,205 |
Questar E&P
For the first quarter of 2005, Questar E&P net income increased 44% to $36.3 million compared with $25.2 million for the same period in 2004. The increase was driven by a combination of increased gas production volumes and higher realized natural gas, oil and NGL prices.
Questar E&P’s production for the first three months of 2005 was 26.3 bcfe versus 25.4 bcfe for the 2004 period, a 4% increase. Current quarter production was negatively impacted by weather-related completion and workover delays on Uinta Basin and western Midcontinent properties, in addition to delays caused by seasonal access restrictions on Rockies Legacy properties. Seasonal access restrictions exist over much of Market Resources federal leasehold acreage in the Rockies. Delays in obtaining rigs to drill planned development wells in the western Midcontinent also impacted first quarter 2005 production growth.
Natural gas remains the primary focus of Questar E&P’s exploration and production strategy. On an energy-equivalent basis, natural gas comprised approximately 87% of Questar E&P’s production for the first quarter of 2005. A comparison of energy equivalent production by region is shown in the following table.
3 Months Ended | ||
March 31, | ||
2005 | 2004 | |
(in bcfe) | ||
Rocky Mountains | ||
Pinedale Anticline | 7.5 | 6.1 |
Uinta Basin | 5.7 | 6.3 |
Rockies Legacy | 4.1 | 4.4 |
Subtotal – Rocky Mountains | 17.3 | 16.8 |
Midcontinent | ||
Tulsa | 5.1 | 4.3 |
Oklahoma City | 3.9 | 4.3 |
Subtotal – Midcontinent | 9.0 | 8.6 |
Total Questar E&P production | 26.3 | 25.4 |
Questar E&P’s first quarter 2005 production from Pinedale increased 24% to 7.5 bcfe versus 6.1 bcfe in the first quarter of 2004. Production at Pinedale typically declines during the first through third quarters of each year due to mid-November to early May seasonal access restrictions imposed by the Bureau of Land Management (BLM) that restrict the company’s ability to complete wells during the period.
Uinta Basin production declined 9% to 5.7 bcfe in the 2005 quarter compared to 6.3 bcfe a year ago. Abnormal weather slowed completion and connection of new wells and routine workovers on existing wells. Weather-related conditions (mud) improved in mid-March, and Questar E&P has since reduced the backlog of well completions and workovers. In addition, high gathering-system pressures caused by a higher-pressure deep well continued to depress production from older lower-pressure wells. The company will install a separate gathering system for existing and new high-pressure wells, which should mitigate the impact on production from older wells.
Production from Rockies Legacy properties in the current quarter was 4.1 bcfe compared to 4.4 bcfe during the 2004 period, a 9% decrease. Legacy properties include all of Questar E&P’s Rocky Mountain producing properties except Pinedale and the Uinta Basin. Current period Legacy properties production was negatively impacted by normal decline and seasonal restrictions that limited access to the company’s leases and wells during the winter months.
Midcontinent production was 9.0 bcfe in the first quarter of 2005 compared to 8.6 bcfe for the same period of 2004, a 5% increase. During the quarter, the company continued one-rig-development programs in both the Hartshorne coalbed-methane development project in the Arkoma Basin of eastern Oklahoma and the ongoing infill-development drilling on the Elm Grove properties in northwest Louisiana. Delays in obtaining rigs to drill a backlog of development wells and weather-related downtime negatively impacted production volumes and workover activity in the western Midcontinent region.
Questar E&P also benefited from higher realized prices for natural gas, oil and NGL. For the current quarter the weighted average realized natural gas price for Questar E&P (including the effects of hedging) was $4.76 per Mcf compared to $4.05 per Mcf for the same period in 2004, an 18% increase. For the 2005 quarter, realized oil and NGL prices averaged $38.74 per bbl, compared with $29.46 per bbl during the first quarter of 2004, a 32% increase. A comparison of average realized prices by region, including hedges, is shown in the following table.
3 Months Ended | ||
March 31, | ||
2005 | 2004 | |
Natural gas (per Mcf) | ||
Rocky Mountains | $ 4.56 | $ 3.94 |
Midcontinent | 5.12 | 4.26 |
Volume-weighted average | $ 4.76 | $ 4.05 |
Oil and NGL (per bbl) | ||
Rocky Mountains | $ 39.47 | $ 28.83 |
Midcontinent | 37.01 | 30.91 |
Volume-weighted average | $ 38.74 | $ 29.46 |
Approximately 88% of Questar E&P’s gas production in the first quarter of 2005 was hedged or pre-sold at an average price of $4.98 per Mcf net to the well (which reflects adjustments for regional basis, gathering and processing costs and gas quality). Hedging reduced gas revenues $9.6 million during the quarter. Questar E&P also hedged approximately 56% of its oil production for the period at an average net to the well price of $34.64 per bbl. Hedging reduced oil revenues $4.0 million.
Questar may hedge up to 100 percent of its forecasted 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. During the quarter, Questar E&P has continued to take advantage of higher natural gas and oil prices to add to its hedge positions in 2005, 2006 and 2007. Natural gas and oil hedges as of March 31, 2005, are summarized in Part I, Item 3 of this report.
During the current quarter, Questar E&P’s pre-income tax cost structure per unit of production (the sum of depreciation, depletion and amortization expense, lifting costs, general and administrative expense and allocated-interest expense) increased 13% to $2.67 per Mcfe versus $2.37 per Mcfe in the first quarter of 2004.
Lifting costs in the 2005 period increased 12% versus the 2004 quarter due to a $0.04 per Mcfe increase in production taxes and a $0.07 per Mcfe increase in lease operating expenses. Most production taxes are based on a fixed percentage of commodity sales prices. Higher lease-operating expenses reflect a general increase in well service costs, including costs of contracted services and production-related supplies, increased workover and production enhancement projects and additional weather-related costs during the current period.
Depreciation, depletion and amortization expense rose 13% over the past year to $1.11 per Mcfe due to normal decline in production from older, lower cost successful-efforts pools, negative reserve revisions over the past 12 months at the company’s Uinta Basin properties and higher reserve replacement (finding and development) costs. Higher day rates for rigs and other services in core operating areas, along with sharply higher steel prices, resulted in higher drilling and completion costs.
General and administrative expenses increased $0.07 per Mcfe, or 26%, to $0.34 in the first quarter of 2005. The company continued to adjust employee compensation in response to industry competition for skilled professionals. Higher allocated corporate overhead (primarily employee benefits and compliance costs) also contributed to the increase.
Questar E&P’s pre-income tax cost structure is summarized in the following table:
3 Months Ended | ||
March 31, | ||
2005 | 2004 | |
(per Mcfe) | ||
Lease-operating expense | $0.55 | $0.48 |
Production taxes | 0.46 | 0.42 |
Lifting costs | 1.01 | 0.90 |
Depreciation, depletion and amortization | 1.11 | 0.98 |
General and administrative expense | 0.34 | 0.27 |
Allocated-interest expense | 0.21 | 0.22 |
Total | $2.67 | $2.37 |
Abandonment and impairment expense declined $3.0 million in the first quarter of 2005 primarily due to an impairment expense in the first quarter of 2004 resulting from a collapsed well casing.
Pinedale Anticline Drilling Activity
As of April 26, 2005, Market Resources operated 106 producing wells on the Pinedale Anticline compared to 76 at the end of the year-earlier quarter. Drilling continued on one winter pad with two rigs active throughout the quarter. A total of eight wells will be drilled from the current winter pad. Barring drilling problems, the company expects all eight wells to be drilled to total depth (TD) and cased before the end of the second quarter of 2005. In addition to the winter pad drilling activity, at the end of the current quarter the company had two rigs active on a state land section near the southern end of its Pinedale acreage. The company also completed and turned to sales two wells on the state land section that were drilled and cased in late 2004.
As of April 26, 2005, the company had the following wells in progress:
•
On the 2004/2005 winter pad, three wells drilled to TD, awaiting completion, three wells drilled to intermediate casing point and two wells drilling below intermediate casing point.
•
On the state section (Section 16, T32N R109W), one well is cased and awaiting completion, one well has been drilled and cased to intermediate casing point, one well is drilling below intermediate casing point and one well drilling above intermediate casing point.
•
On other pads, two wells drilled to intermediate casing point before seasonal restrictions forced suspension of drilling activity last fall; and one well drilled and cased to TD in late 2004 and waiting on completion due to seasonal restrictions.
•
The Stewart Point 15-29 deep exploratory well was suspended at intermediate casing depth of 14,200 feet in November 2004 due to seasonal access restrictions. Drilling to a planned TD of 19,500 feet is expected to resume in late May when seasonal restrictions are lifted by the BLM.
Uinta Basin – Lower Mesaverde, Blackhawk and Mancos formation drilling program update
Questar E&P continues to evaluate deep potential on its core Uinta Basin leasehold. During the quarter, the company drilled and completed the WV 11M-14-8-21 to a TD of 13,223 feet. Located approximately three miles north of the company’s GB 14M-28-8-21 deep well, the new well was completed in Mancos, Blackhawk and Lower Mesaverde formation sands. The well went to sales at a rate of 2.7 MMcfe per day, but quickly declined to approximately 1.0 MMcfe per day. Two additional deep Uinta Basin wells were drilling at the end of the quarter and should reach TD during the second quarter of 2005.
Uinta Basin – Green River Formation horizontal development pilot project update
At the end of the current quarter, Questar E&P had drilled two horizontal wells, the Gypsum Hills 19 located in Section 20, T8S R21E and the WV 3G-10-8-21, targeting Green River formation oil zones on the west side of the company’s 100% working interest Wonsits Valley Unit. The wells will be completed and evaluated during the second quarter of 2005. A third well, which will include multiple laterals drilled from a single existing vertical wellbore, is also planned on the south end of Questar E&P’s 100% working interest Red Wash Unit.
Uinta Basin - Flat Rock area update
The company’s Flat Rock 9P-36-14-19 well in Section 36, T14S R19E was drilled to a TD of 12,453 feet in late 2004 and is producing from multiple pay zones in the Entrada, Morrison, Cedar Mountain and Dakota formations. Additional productive intervals in the Wingate Formation remain isolated beneath a drillable composite frac plug. Questar E&P has a 100% working interest in the well. The well was turned to sales on February 12, 2005, at a facilities-constrained rate of about 1 MMcfe per day. The rate was increased to about 4 MMcfe per day on March 22, 2005, when improved weather conditions allowed the third-party gathering system operator to debottleneck facilities. A compressor will be installed during the second quarter of 2005 which should further increase the production rate.
Questar E&P and the Ute Indian Tribe of the Uintah and Ouray Indian Reservation (Ute Indian Tribe) entered into an Exploration and Development Agreement (EDA) on March 31, 2005, to explore for, develop and produce natural gas and oil on tribal lands. The EDA covers over 12,557 acres of tribal minerals in an area known as Wolf Flat, adjacent to the Flat Rock Area and the company’s recently completed Flat Rock 9P-36-14-19 well in Section 36, T14S R19E. Pursuant to the EDA, Questar E&P is committed to drill one well on the new acreage this summer – a direct offset to the Flat Rock well, and, after acquisition of new 2-D seismic on the EDA lands, the company has a continuous option to drill additional wells to earn gas and oil-development leases on tribal lands. The Ute Indian Tribe has the right, but not the obligation, to participate in the wells with up to a 50% working interest.
Rockies Legacy – activity update
During the 2005 quarter, Questar E&P drilled and completed 7 new wells on its Wamsutter area leasehold in south central Wyoming. Wamsutter wells target Cretaceous sandstone reservoirs at average depths of 9,500 feet and typically recover between 1 and 1.5 bcfe. Questar E&P has approximately 9,700 net acres in the Wamsutter area and has identified over 50 low-risk development locations on its leaseholds. During the current period, the company also completed a new well in its Wedge Unit. The Wedge Unit 13 well was completed from Almond Formation sandstones at an initial rate of 3.3 MMcfe per day. Questar E&P has a 49% working interest in the well. In the Vermillion Basin, Questar E&P was drilling ahead on a 15,000 foot exploratory well on its leasehold near the Hiawatha Field. The company has a 100% working interest in the well, which targets multiple objectives in the Jurassic and Cretaceous section.
Wexpro
For the first quarter of 2005 Wexpro’s net income was $10.2 million, compared with $9.0 million for the same period in 2004, a 13% increase. Wexpro develops and produces gas reserves on behalf of affiliate Questar Gas. Pursuant to the Wexpro Agreement, Wexpro recovers its costs and receives an unlevered after-tax return of approximately 19% on its investment in commercial wells and related facilities – adjusted for working capital and reduced for deferred taxes and depreciation (investment base). Wexpro’s investment base increased to $185.7 million at March 31, 2005, up $16.7 million over the year earlier period. Wexpro’s net income also benefited from higher oil and NGL prices in 2005.
Gas Management
Gas Management increased net income 65% to $8.8 million in the current-year quarter compared to a year earlier. Gross keep-whole processing margins grew 97% from $3.5 million in the first quarter of 2004 to $6.8 million in the 2005 quarter, driven by the difference between the market value of natural gas and the market value of NGL extracted from the gas stream (commonly referred to as the “frac spread”). Gathering volumes increased 1.0 million MMBtu to 59.6 million MMBtu in the 2005 quarter due primarily to expanding Pinedale production and new projects serving third parties in the Uinta Basin.
To reduce processing margin risk Gas Management has restructured a number of its processing agreements with producers from “keep-whole” contracts to “fee-based” contracts. (A keep-whole contract protects producers from frac spread risk while fee-based contracts eliminate commodity-price risk for the plant owner.) To further reduce margin volatility associated with keep-whole contracts, Gas Management began managing NGL price risk in 2004 by using forward-sales contracts. In the 2005 period, keep-whole contracts benefited from a 24% increase in NGL sales prices and fee-based contracts benefited from a $0.06 increase in the rate charged per MMBtu processed. Forward sales contracts increased NGL revenues by $0.1 million in 2005.
Pre-tax earnings from Gas Management’s 50% interest in Rendezvous Gas Services, LLC, (Rendezvous) increased to $1.5 million for the 2005 quarter versus $1.3 million for 2004 due primarily to increased gathering volumes. 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.
During the current quarter, Gas Management completed a transaction in which the company exchanged its interest in an entity that owns and operates the Beaver gas gathering system in western Oklahoma for the Emigrant Trail gas plant (ET plant) in western Wyoming. The ET plant, a cryogenic gas processing facility located approximately 13 miles south of Gas Management’s Blacks Fork plant, adds approximately 60 MMcf per day of raw gas processing and NGL extraction capacity at its western Wyoming hub. The plant will be connected to the Blacks Fork/Granger complex to significantly enhance processing and blending capacity for Pinedale, Jonah and other western Wyoming producers served by Gas Management and Rendezvous. The Beaver gas gathering system did not contribute significantly to Gas Management’s 2004 earnings. The effective date of the transaction was January 1, 2005.
Gas Management has also entered into an agreement with a third party producer to gather, compress and process gas in the Uinta Basin of eastern Utah. Under terms of the fee-based agreement, the company will construct gas compression facilities and expand its existing Red Wash gas plant to process an additional 70 MMcf per day of raw gas. The processed gas and liquids will be redelivered to the producer. The new facilities should be in service during the third quarter of 2005.
Energy Trading
Energy Trading’s net income for the first quarter of 2005 was $1.4 million compared to $0.7 million in 2004, a 106% increase. Gross margins for gas and oil marketing (gross revenues less costs for gas and oil purchases, transportation and gas storage), increased to $3.1 million for the current period versus $2.3 million a year ago, a 34% increase. The increase in gross margin was due primarily to a 9% higher unit margin and a 22% increase in volumes over the same period last year.
Questar Pipeline
Questar Pipeline provides Federal Energy Regulatory Commission (FERC)-regulated interstate natural gas transportation and storage and non-jurisdictional processing and gathering services. Following is a summary of financial results and operating information.
3 Months Ended | ||
March 31, | ||
2005 | 2004 | |
(in thousands) | ||
OPERATING INCOME | ||
Revenues | ||
Transportation | $26,586 | $26,699 |
Storage | 9,576 | 9,699 |
Carbon dioxide processing | 1,782 | 1,843 |
Liquid revenues and other | 2,393 | 2,065 |
Total revenues | 40,337 | 40,306 |
Operating expenses | ||
Operating and maintenance | 13,134 | 13,358 |
Depreciation and amortization | 7,254 | 6,964 |
Other taxes | 1,592 | 1,697 |
Total operating expenses | 21,980 | 22,019 |
Operating income | $18,357 | $18,287 |
OPERATING STATISTICS | ||
Natural gas transportation volumes (in Mdth) | ||
For unaffiliated customers | 55,592 | 53,734 |
For Questar Gas | 43,739 | 49,876 |
For other affiliated customers | 1,976 | 4,260 |
Total transportation | 101,307 | 107,870 |
Transportation revenue (per dth) | $0.26 | $0.25 |
Firm-daily transportation demand at March 31, (Mdth) | 1,625 | 1,646 |
Questar Pipeline’s net income was $8.3 million in the first quarter of 2005 compared with $8.1 million in the first quarter of 2004. Revenues and expenses were flat in the 2005 period versus the prior-year period. The earnings increase reflected the capitalization of carrying costs on a construction project. Questar Pipeline continued to accrue for the potential refund of liquids revenue from the Kastler processing plant as required by a November 2004 order from the FERC.
Revenues
Gas transportation volumes declined in the first quarter of 2005 due to warmer weather in Questar Gas’s service area. Following is a summary of major changes in Questar Pipeline’s revenues for the three months ended March 31, 2005, compared with the same period of 2004.
3 Months Ended March 31, 2005 Compared with 2004 | |
(in thousands) | |
Transportation | |
New transportation contracts | $ 452 |
Expiration of transportation contracts | (244) |
Elimination of Gas Research Institute surcharge | (294) |
Other transportation | (27) |
Storage | (123) |
Carbon dioxide processing | (61) |
Liquid revenues and other | |
Change in liquid revenues before credit | 618 |
Credit of Kastler liquid revenues | (464) |
Other | 174 |
Increase | $ 31 |
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 2004 and 2005 for deliveries to the Kern River pipeline at Goshen, Utah.
Questar Pipeline’s existing transportation system is nearly fully subscribed. As of March 31, 2005, Questar Pipeline had firm-transportation contracts of 1,625 Mdth per day compared with 1,643 Mdth per day as of December 31, 2004, and 1,646 Mdth per day as of March 31, 2004. 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 8.8 years as of March 31, 2005.
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 8.5 years as of March 31, 2005.
Questar Gas has contracted for 26% 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 charges FERC-approved transportation and storage rates that are based on straight-fixed-variable rate design. Under this rate design all fixed costs of providing service including depreciation and return on investment are recovered through the demand charge. About 95% of Questar Pipeline costs are fixed and recovered through these demand charges. Questar Pipeline’s earnings are driven primarily by demand revenues from firm shippers. 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.
Expenses
Operating and maintenance expenses decreased 2% in the first quarter of 2005 compared with the first quarter of 2004 primarily due to lower maintenance costs and elimination of the Gas Research Institute customer surcharge. Operating and maintenance expenses per dth transported were $0.130 in the first quarter of 2005 compared with $0.124 in the first quarter of 2004.
Depreciation expense increased in the 2005 first quarter reflecting increased pipeline investment.
Clay Basin Storage
Questar Pipeline continues to investigate a potential discrepancy of up to 9 bcf between the book volumes of cushion gas at Clay Basin and cushion-gas volumes implied by 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. Questar Pipeline has not determined if any gas is missing from the reservoir. Analysis to date has not revealed any leaks or gas migration out of the reservoir. Additional reservoir tests and analysis, including reservoir modeling, are under way to identify the cause of the potential discrepancy and may continue for several years. The gas may still be in the reservoir but not detectible with short-duration pressure surveys. Questar Pipeline conducted pressure-survey tests during October 2004 to evaluate the reservoir when it was nearly full. Preliminary interpretation of test results indicates that the discrepancy may not be significant. Additional tests were performed during April 2005. Questar Pipeline is integrating these tests into the reservoir model. This potential discrepancy has not prevented Questar Pipeline from meeting its obligations to storage customers.
New Long-term Contracts
During first quarter 2004 Questar Pipeline obtained long-term contracts to support a $54 million expansion of its central Utah transportation 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. On January 21, 2005, the FERC approved the expansion. Questar Pipeline has started construction and expects a late-2005 in-service date.
Questar Pipeline also obtained a long-term contract supporting an $11 million extension from the west end of its Mainline 104 near Goshen, Utah to a new power plant being built near Mona, Utah. Construction on this 190-Mdth-per-day line was completed in December 2004 and service began in April 2005.
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.
Southern Trails
The western segment of the Southern Trails line, which runs from the California-Arizona border to Long Beach, California, is currently not in service. Questar Pipeline’s investment is approximately $51 million. Additional investment would be required to complete the conversion of the pipeline from a liquid pipeline to a natural gas pipeline and make connections to customers. The Los Angeles Department of Water and Power (LADWP) budgeted funds to acquire a gas pipeline to serve a power-generation facility and issued a request for proposal on October 21, 2004. Questar Pipeline filed a response to the request in November 2004. On February 28, 2005, LADWP notified Questar Pipeline of its intent to pursue the proposal, although it is uncertain whether negotiations will be successful.
Regulation
FERC Order No. 2004, which defines standards of conduct for transportation providers, became effective on September 22, 2004. These standards of conduct are designed to ensure that employees engaged in transportation-system operations function independently from employees of marketing and energy affiliates. In addition, a transportation provider must treat all transportation customers on a non-discriminatory basis and must not operate its transportation system to preferentially benefit its marketing or energy affiliates. Questar Pipeline has determined that all Market Resources subsidiaries except Gas Management are marketing or energy affiliates. Questar Gas is not an energy or marketing affiliate. Questar Pipeline and other Questar companies have adopted new procedures to comply with this order.
Questar Pipeline is required to comply with the Pipeline Safety Improvement Act of 2002. This act and the rules issued by the Department of Transportation (DOT) require interstate pipelines and local distribution companies to implement a 10-year program of risk analysis, pipeline assessment and remedial repair for transportation pipelines located in high-consequence areas such as densely populated locations. Questar Pipeline’s plan for complying with the act was filed with the DOT during 2004. Questar Pipeline estimates that its annual cost to comply with the act will be approximately $1 million, not including costs of pipeline replacement, if necessary.
Questar Pipeline made an annual Fuel Gas Reimbursement Percentage (FGRP) filing with the FERC on November 30, 2004, requesting an increase in the FGRP to 2.6%. The request was approved on December 30, 2004, on an interim basis subject to refund, pending final resolution of the 2004 FGRP proceeding. Several shippers have filed comments with the FERC protesting the FGRP level.
Questar Gas
Questar Gas distributes natural gas in Utah, southwestern Wyoming and southeastern Idaho. Following is a summary of financial results and operating information.
3 Months Ended | ||
March 31, | ||
2005 | 2004 | |
(in thousands) | ||
OPERATING INCOME | ||
Revenues | ||
Residential and commercial sales | $322,046 | $283,054 |
Industrial sales | 10,407 | 16,645 |
Transportation for industrial customers | 1,607 | 1,878 |
Other | 10,891 | 6,439 |
Total revenues | 344,951 | 308,016 |
Cost of natural gas sold | 251,597 | 216,730 |
Margin | 93,354 | 91,286 |
Operating expenses | ||
Operating and maintenance | 28,911 | 28,422 |
Depreciation and amortization | 11,306 | 10,309 |
Rate-refund obligation | 1,490 | |
Other taxes | 3,186 | 3,166 |
Total operating expenses | 43,403 | 43,387 |
Operating income | $49,951 | $47,899 |
OPERATING STATISTICS | ||
Natural gas volumes (in Mdth) | ||
Residential and commercial sales | 39,919 | 41,684 |
Industrial sales | 1,703 | 3,014 |
Transportation for industrial customers | 8,655 | 9,938 |
Total deliveries | 50,277 | 54,636 |
Natural gas revenue (per dth) | ||
Residential and commercial | $8.07 | $6.79 |
Industrial sales | 6.11 | 5.52 |
Transportation for industrial customers | 0.19 | 0.19 |
Heating degree days | ||
colder (warmer) than normal | (5%) | 12% |
Average temperature adjusted usage | ||
per customer (dth) | 49.9 | 49.3 |
Customers at March 31, | 800,523 | 776,266 |
Questar Gas earned $28.7 million in the first quarter of 2005, $2.4 million higher than the first quarter of 2004.
Margin Analysis
Questar Gas’s margin (revenues less gas costs) increased $2.1 million, or 2% in the first quarter of 2005 compared to the first quarter of 2004. Following is a summary of major changes in Questar Gas’s margin for the first quarter of 2005.
3 Months Ended March 31, 2005 Compared with 2004 | ||
(in thousands) | ||
New customers | $ 2,300 | |
Increased usage per customer | 913 | |
2004 carbon dioxide processing revenues | (1,490) | |
Other | 345 | |
Increase | $ 2,068 | |
Residential and commercial sales volumes were down 4% as warmer weather offset increased usage per customer. At March 31, 2005, Questar Gas was serving 800,523 customers. Customer growth remained above national averages at 3.1% over the prior year. Housing construction in Utah remained strong, driven by population growth and low mortgage-interest rates. Usage per customer, adjusted for normal temperatures, was up 1% in the first quarter of 2005 compared with 2004. Over the long-term, 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 5% warmer than normal in the first quarter of 2005 compared with 12% colder than normal in the first quarter 2004. A weather-normalization adjustment on customer bills generally offsets financial impacts of moderate temperature variations.
Industrial deliveries declined 20% in the first quarter of 2005 compared with 2004 primarily driven by lower power-generation requirements in the current period.
Expenses
Cost of natural gas sold increased 16% in the first quarter of 2005 compared with 2004. Increased gas purchase costs more than offset lower volumes due to the warmer weather. Questar Gas accounts for purchased-gas costs in accordance with procedures authorized by the PSCU and the PSCW. Purchased-gas costs that are different from those provided for in present rates are accumulated and recovered or credited through future rate changes. As of March 31, 2005, Questar Gas had a $14.8 million balance in the purchased-gas adjustment account representing gas costs incurred but not yet recovered from customers.
Operating and maintenance expenses increased 2% in the first quarter of 2005 compared with 2004, primarily due to higher labor and bad debt costs.
Depreciation expense increased 10% in the first quarter of 2005 compared with 2004, due to plant additions, including a customer information system that was placed in service in July 2004 and transfers of information technology assets from affiliates.
Rate-refund Obligation
See Note 2 in the Notes Accompanying Consolidated Financial Statements under Item 1. Financial Statements in Part I of this report for a discussion of the regulatory proceedings involving Questar Gas’s processing costs.
Regulation
Questar Gas is subject to the requirements of the Pipeline Safety Improvement Act. Questar Gas estimates that it will cost $4.0 to $5.0 million per year to comply with the act, not including costs of pipeline replacement if necessary. The PSCU has allowed Questar Gas to record a regulatory asset for these incremental operating costs incurred to comply with this act until the next rate case or three years, whichever is sooner.
Consolidated Results After Operating Income
Earnings from unconsolidated affiliates
Gas Management’s 50% share of Rendezvous’ pre-tax income increased to $1.5 million in the 2005 quarter vs. $1.3 million in 2004 due to a 21% increase in gathering volumes. Gas Management has a 50% interest in Rendezvous, which provides gas-gathering services for the Pinedale and Jonah producing areas of western Wyoming.
Debt expense
Lower debt balances and long-term interest rates resulted in an $0.8 million lower debt expense in 2005.
Income taxes
The effective combined federal and state income tax rate for the first three months was 37.0% in 2005 and 37.7% in 2004.
Liquidity and Capital Resources
Operating Activities
3 Months Ended | ||
March 31, | ||
2005 | 2004 | |
(in thousands) | ||
Net income | $ 95,171 | $ 76,133 |
Noncash adjustments to net income | 65,299 | 73,677 |
Changes in operating assets and liabilities | 5,071 | 36,811 |
Net cash provided from operating activities | $165,541 | $186,621 |
Net cash provided from operating activities decreased 11% in 2005 compared with 2004. Cash generated from increased net income was offset by hedging collateral deposits. An $83.4 million hedging collateral deposit was made in response to higher sales prices for gas and oil in 2005. This cash outflow was partially offset by seasonal changes in other operating assets and liabilities during the first quarter of 2005.
Investing Activities
A comparison of capital expenditures for the first three months of 2005 and 2004 plus the budgeted amount for calendar year 2005 is presented below. Corporate and other operations include $25 million for as yet unidentified projects in 2005 in the operating subsidiaries.
Budget | |||
3 Months Ended | 12 Months Ended | ||
March 31, | December 31, | ||
2005 | 2004 | 2005 | |
(in thousands) | |||
Market Resources | $102,169 | $44,978 | $375,500 |
Questar Pipeline | 8,274 | 3,899 | 101,900 |
Questar Gas | 18,650 | 19,471 | 82,700 |
Corporate and other operations | 251 | 538 | 27,000 |
Total | $129,344 | $68,886 | $587,100 |
Financing Activities
Net cash flow provided from operating activities was more than sufficient to fund net capital expenditures and pay dividends in the first three months of 2005. The excess cash flow was used to repay short-term debt. Total debt was 41% of total capital at March 31, 2005.
Short-term debt at March 31, 2005 was comprised of commercial paper with an average interest rate of 2.8%. The Company has $190 million of short-term lines of credit at April 1, 2005. In addition, Market Resources has a $200 million revolving credit facility with banks with no borrowings outstanding at March 31, 2005.
In April 2005, Standard & Poor’s (S&P) downgraded the debt ratings of Questar’s regulated subsidiaries and commercial paper. S&P set an “A-2” rating for Questar’s commercial paper and “A-” long-term debt ratings for Questar Gas and Questar Pipeline. S&P affirmed its BBB+ long-term rating of Market Resources. S&P assigned a “stable outlook” for each Questar entity.
S&P said that Questar’s growing exploration and production business benefits Questar Gas and Questar Pipeline when commodity prices are high, but exposes them to greater risk when prices are low. S&P also cited a negative shift in Utah’s regulatory environment as a factor in its decision to downgrade the credit ratings of Questar Gas.
Moody’s ratings for the Company’s debt were unchanged during the quarter.
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. Hedging contracts are used for a significant share of Questar E&P-owned gas and oil production and for a portion of gas- and oil-marketing transactions and for some of Gas Management’s NGL.
Market Resources has established policies and procedures for managing commodity-price risks through the use of derivatives. Natural gas- and oil-price hedging supports Market Resources’ rate of return and cash-flow targets and protects earnings from downward movements in commodity prices. The volume of hedged production and the mix of derivative instruments are regularly evaluated and adjusted by management in response to changing market conditions and reviewed periodically by the Finance and Audit Committee of the Company’s Board of Directors. Market Resources may hedge up to 100% of forecast production from proved-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 or equity 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 typically structured as fixed-price swaps into regional pipelines, locking in basis and hedge effectiveness. Any ineffective portion of hedges is immediately recognized in the income statement. The ineffective portion of hedges was not significant in 2005 and 2004.
As of March 31, 2005, approximately 58.9 bcf of forecast gas production for the remainder of 2005 was hedged at an average price of $4.89 per Mcf, net to the well.
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 individual counterparty lines of credit of $5 million to $40 million. If Market Resources credit ratings fall below investment grade (BBB- by S&P or Baa3 by Moody’s), counterparty credit generally falls to zero. In addition to the counterparty arrangements, Market Resources has a $200 million long-term revolving-credit facility with banks.
A summary of Market Resources hedging positions for equity production as of March 31, 2005, is shown below. Prices are net to the well. Currently all hedges are fixed-price swaps with creditworthy counterparties, allowing Market Resources to achieve a known price for a specific volume of production delivered into a regional sales point. 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 174.9 million MMBtu of gas and 2.6 MMbbl of oil as of March 31, 2005. A year earlier Market Resources’ hedging contracts covered 148.2 million MMBtu of natural gas and 1.5 MMbbl 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, 2004, to March 31, 2005.
A table of the net fair value of gas-hedging contracts as of March 31, 2005, is shown below. About 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 March 31, | ||
2005 | 2004 | |
(in millions) | ||
|
| |
Mark-to-market valuation – liability | ($253.8) | ($73.7) |
Value if market prices of gas and oil decline by 10% | (145.5) | (16.7) |
Value if market prices of gas and oil increase by 10% | (338.1) | (131.4) |
Interest-Rate Risk Management
As of March 31, 2005, Questar had $933.2 million of fixed-rate long-term debt and no variable-rate long-term debt.
ITEM 4. CONTROLS AND PROCEDURES.
Evaluation of Disclosure Controls and Procedures.
The Company’s Chief Executive Officer and Chief Financial Officer have evaluated the effectiveness of the Company’s disclosure controls and procedures (as such term is defined in Rules 13a-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.
Through ongoing evaluation of internal controls over financial reporting, management continues to implement procedures and controls to enhance the reliability of Questar’s internal control procedures including planned improvements in financial closing and consolidation processes. However, there have been no changes in internal control over financial reporting that occurred during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, Questar’s internal control over financial reporting.
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS.
See Note 2 in the Notes Accompanying Consolidated Financial Statements under Item 1. Financial Statements in Part I of this report for a discussion of the regulatory proceedings involving Questar Gas’s processing costs and Questar Pipeline’s FGRP.
Beaver Gas Pipeline System. On April 8, 2005, Kaiser-Francis appealed the trial judge’s order granting Questar E&P’s motion to dismiss the lawsuit filed against it in Kaiser-Francis Oil v. Anadarko Petroleum Corp., Case No. CJ-2003-66518 (Dist. Ct. Okla.). Kaiser-Francis was a co-defendant of Questar E&P in a prior Oklahoma case, Bridenstine v. Kaiser-Francis Oil Co. The original lawsuit was a class action alleging improper royalty payments for wells connected to the Beaver Gas Pipeline System in western Oklahoma. Questar E&P and Anadarko (as the successor to another company) settled the lawsuit in December 2000 by agreeing to pay a total sum of $22.5 million, of which $16.5 million was allocated to Questar E&P. Kaiser-Francis chose not to settle and was assessed damages, including punitive damages, by a jury. Kaiser-Francis ultimately settled for $82.5 million, plus interest. As part of the settlement, Kaiser-Francis and the plaintiff class agreed to entry of a “superseding judgment” purporting to vacate the punitive damages award against Kaiser-Francis after the Oklahoma Supreme Court had affirmed that award and issued its mandate. Questar E&P and Anadarko have appealed the entry of the superseding judgment to the Oklahoma Supreme Court.
Kaiser-Francis’ current lawsuit claims that Questar E&P and Anadarko were obligated by express and implied indemnities to pay for a portion of the damages assessed in the jury trial and for its legal-defense costs. In dismissing the lawsuit for failure to state a claim, the district judge noted that the jury determined that Kaiser-Francis was involved in a conspiracy to commit fraud and was therefore barred by a doctrine similar to “unclean hands” from seeking indemnity for the judgment. On appeal, Kaiser-Francis contends that it should be allowed to amend its petition to argue that the superseding judgment shields it from the jury’s findings of wrongdoing. In dismissing the case, the trial judge found that the superseding judgment made no difference.
On January 2, 2005, the Department of Environmental Quality (DEQ) for the state of Oklahoma issued a seven-count Notice of Violation to Gas Management in conjunction with the operation of the Beaver processing plant in western Oklahoma. The DEQ alleges that Gas Management violated federal and state environmental laws and regulations concerning air emissions when operating the facility and when reporting about such operations. As requested by DEQ, Gas Management filed a compliance plan by the end of February 2005. On April 28, 2005, Gas Management received written confirmation of a penalty of $163,500 which amount may be reduced by 30 percent if Gas Management complies with the terms of a "fast track" consent order which DEQ has yet to send to Gas Management.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS.
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 March 31, 2005:
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 | |
January 1, 2005 – January 31, 2005 | 293 | $47.69 | - | - |
February 1, 2005 – February 28, 2005 | 64,913 | 51.90 | - | - |
March 1, 2005 – March 31, 2005 | 25,808 | 58.81 | - | - |
Total | 91,014 | $53.81 | - | - |
*The numbers include any shares purchased in conjunction with tax payment elections under the Company’s Long-term Stock Incentive Plan and rollover shares used in exercising stock options. They exclude any fractional shares purchased from terminating participants in Questar’s Dividend Reinvestment and Stock Purchase Plan, any shares of restricted stock forfeited when failing to satisfy vesting conditions and any shares delivered or attested to when exercising stock options.
ITEM 5. OTHER INFORMATION
On February 8, 2005 the Company’s Board of Directors approved compensation arrangements for the executive officers in the compensation table. See Exhibit 10.01.
ITEM 6. EXHIBITS
The following exhibits are being filed as part of this report:
Exhibit No.
Exhibit
10.01.
New compensation arrangements for named executive officers.
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.
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)
May 5, 2005
/s/Keith O. Rattie
Date
Keith O. Rattie, Chairman of the Board,
President and Chief Executive Officer
May 5, 2005
/s/S. E. Parks
Date
S. E. Parks, Senior Vice President and
Chief Financial Officer
Exhibits List
Exhibits
10.01.
New compensation arrangements for named executive officers.
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.
Exhibit No. 10.01
QUESTAR CORPORATION
NEW COMPENSATION ARRANGEMENTS
NAMED EXECUTIVE OFFICERS
On February 8, 2005, the Boards of Directors of Questar Corporation and its subsidiaries (“Questar” or the “Company” and its subsidiaries) approved compensation arrangements for the Company’s named executive officers. The following chart lists each named executive officer and his new compensation arrangements:
Name and Title | Base Salary1 | Restricted Stock2 | Annual Bonus3 | Long-term Cash Incentive Grant4 | |
Keith O. Rattie | $625,000 | 10,000 | $468,750 | $400,000 | |
Chairman, President & Chief Executive Officer | |||||
C. B. Stanley | $500,000 | 9,000 | $262,500 | $350,000 | |
President & Chief Executive Officer, Market Resources | $119,792 | ||||
Alan K. Allred | $285,700 | 3,700 | $142,850 | $100,000 | |
President & Chief Executive Officer, Questar Gas | |||||
S. E. Parks | $300,000 | 3,500 | $150,000 | $ 75,000 | |
Sr. Vice President & Chief Financial Officer | |||||
C. C. Holbrook | $264,000 | 0 | $132,000 | $0 | |
Sr. Vice President, General Counsel & Corporate Secretary5 | |||||
___________________
1Base salary amounts are effective March 1, 2005.
2The grants of restricted stock vest in three equal installments beginning in February of 2007.
3With the exception of the second entry for Mr. Stanley, the amounts specified are target bonus amounts. The named individuals can earn up to 199 percent of the target bonus amounts based on the performance metrics. The primary annual bonus amounts are earned under the terms of the Annual Management Incentive Plan II (if approved by shareholders in May of 2005) or the Annual Management Incentive Plan. Any amounts earned will be paid in February of 2006. Mr. Stanley is also eligible to earn a maximum bonus of $119,792 under the terms of Market Resources’ general employee incentive compensation plan for 2005.
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4These target cash awards are made under the Company’s Long-term Cash Incentive Plan, which was approved by the Company’s shareholders in 2004. Each named participant can earn up to three times the amount of his target award based on a comparison of the Company’s total shareholder return for the three-year period ending December 31, 2007, with total shareholder returns earned by designated peers.
5Ms. Holbrook retired as an employee and resigned as an officer of the Company effective April 30, 2005. Consequently, she was not granted any equity or given an award under the Long-term Cash Incentive Plan in February of 2005. In connection with her retirement, she received an accelerated vesting of the final annual installment of her 2002 option to purchase a total of 40,000 shares at a price of $22.95 per share and the final two annual installments of her 2003 option to purchase an aggregate of 45,000 shares at a price of $27.11 per share. She also received a distribution of the 3,500 shares of stock that were granted to her as restricted shares in February of 2004. She is eligible to earn a prorated portion of her 2005 bonus for the period of her employment in 2005.
Exhibit 31.1
CERTIFICATION
I, Keith O. Rattie, certify that:
1.
I have reviewed this quarterly report on Form 10-Q for first quarter 2005 of Questar Corporation;
2
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
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 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 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 report (the "Evaluation Date"); and
(c)
Presented in this 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 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.
May 5, 2005
By: /s/Keith O. Rattie
Date
Keith O. Rattie,
Chairman, President and Chief
Executive Officer
Exhibit 31.2.
CERTIFICATION
I, S. E. Parks, certify that:
1.
I have reviewed this quarterly report on Form 10-Q for first quarter 2005 of Questar Corporation;
2
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
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 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 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 report (the "Evaluation Date"); and
(c)
Presented in this 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 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.
May 5, 2005
By /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
SECTION 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 March 31, 2005, 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
May 5, 2005
/s/Keith O. Rattie
Date
Keith O. Rattie
Chairman, President and Chief Executive Officer
May 5, 2005
/s/S. E. Parks
Date
S. E. Parks
Senior Vice President and Chief Financial Officer
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