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 quarter ended June 30, 2005
[ ]
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 0-30321
QUESTAR MARKET RESOURCES, INC.
(Exact name of registrant as specified in charter)
STATE OF UTAH 87-0287750
(State of other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
180 East 100 South Street, P.O. Box 45601 Salt Lake City, Utah 84145-0601
(Address of principal executive offices)
Registrant’s telephone number, including area code (801) 324-2600
Not Applicable
(Former name or former address, if changed since last report)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 of 15(d) of the Securities and 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 [ ] No [X]
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.
Class
Outstanding as of July 31, 2005
Common Stock, $1.00 par value
4,309,427 Shares
Registrant meets the conditions set forth in General Instruction H (1) (a) and (b) of Form 10-Q and is filing this Form 10-Q with the reduced disclosure format.
#
Questar Market Resources, Inc.
Form 10-Q for the Quarterly Period Ended June 30, 2005
TABLE OF CONTENTS
Page #
3
FORWARD-LOOKING STATEMENTS AND RISK FACTORS
3
GLOSSARY OF COMMONLY USED TERMS
5
SEC FILINGS AND WEBSITE INFORMATION
7
8
8
Consolidated Statements of Income for the three and six months
ended June 30, 2005 and 2004
8
Condensed Consolidated Balance Sheets at June 30, 2005
and December 31, 2004
9
Condensed Consolidated Statements of Cash Flows for the six months
ended June 30, 2005 and 2004
10
Notes Accompanying the Consolidated Financial Statements
11
Management’s Discussion and Analysis of Financial Condition and
Results of Operations
15
Quantitative and Qualitative Disclosures about Market Risk
21
24
24
24
24
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NATURE OF BUSINESS
Questar Market Resources, Inc. (Market Resources or the Company) is a wholly owned subsidiary of Questar Corporation (Questar) and is Questar’s primary growth driver. Market Resources has four principal subsidiaries: Questar Exploration and Production Company (Questar E&P) explores for, acquires, develops and produces natural gas and oil; Wexpro Company (Wexpro) develops and produces cost-of-service reserves for an affiliated company, Questar Gas Company (Questar Gas); Questar Gas Management Company (Gas Management) provides gas-gathering and processing services for affiliates and third parties; and Questar Energy Trading Company (Energy Trading) markets equity and third-party natural gas and oil, provides risk-management services and, through Clear Creek Storage Company, LLC, owns and operates an underground gas-storage reservoir.
Market Resources operates in the Rocky Mountain and Midcontinent regions of the United States of America and is headquartered in Salt Lake City, Utah.
FORWARD-LOOKING STATEMENTS AND RISK FACTORS
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 (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 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 negativ e thereof or variations thereon or similar terminology. Although these statements are made in good faith and are reasonable representations of Market Resources’ 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.
Market Resources’ subsidiaries find, produce and sell natural gas, oil and natural gas liquids (NGL)
Natural gas, oil and NGL prices are volatile and, therefore, Market Resources’ revenues, cash flow and earnings can be volatile. The Company cannot predict future natural gas, oil and NGL price movements, which are subject to forces beyond its control such as:
•
Domestic and foreign supply of 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;
•
The costs and availability of drilling rigs and other materials and services.
The Company uses financial contracts to hedge its exposure to volatile natural gas, oil and NGL prices and to protect cash flow, returns on capital, net income and credit ratings from downward commodity-price movements. While hedging reduces the impact of declining prices, it may also limit future revenues from favorable price movements. Market Resources believes its Wexpro subsidiary generates revenues that are not significantly sensitive to short-term fluctuations in natural gas and oil prices.
Market Resources’ profitability depends not only on prevailing prices for natural gas, oil and NGL, 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 E&P’s proved natural gas- and oil-reserve estimates are prepared annually by independent reservoir-engineering consultants. Gas- and oil-reserve estimates are subject to numerous uncertainties inherent in estimating quantities of proved reserves, projecting future rates of production and timing of development expenditures. The accuracy of these estimates depends on the quality of available data and on engineering and geological interpretation and judgment. Reserve estimates are imprecise and will change as additional information becomes available. Estimates of economically recoverable reserves and future net cash flows prepared by different engineers, or by the same engineers at different times may vary significantly. Results of subsequent drilling, testing and production may cause either upward or downward revisions of previous estimates. In additio n, 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; 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.
Market Resources must comply with numerous regulations from the federal, state and local level
Market Resources is subject to federal, state and local environmental, health and safety laws and regulations. Environmental laws and regulations are complex, change frequently and have 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.
Market Resources must comply with numerous and complex regulations governing their 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 leasehold. 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 Ame rican 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 Market Resources’ 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.
Other factors may affect Market Resources results
Market Resources results may also be affected by: changes in general economic conditions; changes in regulation; availability and economic viability of gas and oil properties for sale or exploration; creditworthiness of counterparties; rate of inflation and interest rates; assumptions used in business combinations; weather and natural disasters; changes in customers’ credit ratings; competition from other forms of energy; 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.
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. Market Resources undertakes no obligation to update any forward-looking statement provided in this report.
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 at sea level.
cash-flow hedge
A derivative instrument that complies with Statement of Financial Accounting Standards (SFAS) 133, as amended, and is used to reduce the exposure to variability in cash flows from the forecasted physical sale of gas and oil production whereby the gains (losses) on the derivative transaction are anticipated to offset the losses (gains) on the forecasted physical sale.
cf
Cubic foot is a common unit of gas measurement. One standard cubic foot equals the volume of gas in one cubic foot measured at standard conditions – a temperature of 60 degrees Fahrenheit and a pressure of 30 inches of mercury (approximately 14.73 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.
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.
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.
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.
SEC FILINGS AND WEBSITE INFORMATION
Market Resources files annual, quarterly, and current reports with the Securities and Exchange Commission (SEC). Interested parties can read and copy any materials filed with the SEC at its Public Reference Room at 450 Fifth Street, N.W., Washington, D.C. 20549, and can obtain information about the operations of the Public Reference Room by calling the SEC at 1-800-SEC-0300. The SEC also maintains a website that contains information filed electronically that can be accessed over the Internet at www.sec.gov.
Investors can also access financial and other information for Market Resources through Questar’s website at www.questar.com. Questar’s website contains Statements of Responsibility for Board Committees, Corporate Governance Guidelines and its Business Ethics Policy.
Market Resources makes available, free of charge through the Questar website, copies of Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and any amendments to such reports. Access to these reports is provided as soon as reasonably practical after such reports are electronically filed with the SEC.
#
PART I. FINANCIAL INFORMATION
QUESTAR MARKET RESOURCES, INC.
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
3 Months Ended | 6 Months Ended | |||
June 30, | June 30, | |||
2005 | 2004 | 2005 | 2004 | |
(in thousands) | ||||
REVENUES | ||||
From unaffiliated customers | $ 344,896 | $ 244,360 | $ 659,234 | $ 478,414 |
From affiliates | 35,741 | 34,090 | 73,825 | 68,447 |
TOTAL REVENUES | 380,637 | 278,450 | 733,059 | 546,861 |
OPERATING EXPENSES | ||||
Cost of natural gas and other products sold | 177,246 | 116,872 | 327,760 | 222,017 |
Operating and maintenance | 41,776 | 36,517 | 83,824 | 72,230 |
Depreciation, depletion and amortization | 41,257 | 37,084 | 81,116 | 71,033 |
Exploration | 5,476 | 1,266 | 6,849 | 2,353 |
Abandonment and impairment of gas, | ||||
oil and other properties | 1,493 | 2,287 | 2,898 | 6,693 |
Production and other taxes | 20,962 | 17,496 | 42,206 | 35,152 |
Wexpro Agreement – oil -income sharing | 1,364 | 1,016 | 2,625 | 2,148 |
TOTAL OPERATING EXPENSES | 289,574 | 212,538 | 547,278 | 411,626 |
OPERATING INCOME | 91,063 | 65,912 | 185,781 | 135,235 |
Interest and other income | 889 | 230 | 1,351 | 1,013 |
Earnings from unconsolidated affiliates | 1,675 | 1,264 | 3,221 | 2,574 |
Minority interest | (270) | |||
Debt expense | (7,016) | (6,722) | (13,810) | (13,874) |
INCOME BEFORE INCOME TAXES | 86,611 | 60,684 | 176,543 | 124,678 |
Income taxes | 31,850 | 22,521 | 65,161 | 46,260 |
NET INCOME | $ 54,761 | $ 38,163 | $ 111,382 | $ 78,418 |
See notes accompanying the consolidated financial statements
#
QUESTAR MARKET RESOURCES, INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
June 30, | December 31, | |
2005 | 2004 | |
(Unaudited) |
| |
(in thousands) | ||
ASSETS | ||
Current assets | ||
Notes receivable from Questar | $ 14,100 | $ 49,400 |
Accounts receivable, net | 142,201 | 174,539 |
Accounts receivable from affiliates | 18,044 | 19,247 |
Hedging collateral deposits | 62,600 | |
Fair value of hedging contracts | 199 | 9,334 |
Inventory, at lower of cost or market | ||
Gas and oil storage | 17,614 | 22,604 |
Materials and supplies | 20,169 | 8,631 |
Prepaid expenses and other | 16,427 | 16,632 |
Deferred income taxes - current | 53,406 | 20,592 |
Total current assets | 344,760 | 320,979 |
Property, plant and equipment | 2,652,779 | 2,456,332 |
Less accumulated depreciation, depletion and amortization | 1,013,384 | 937,267 |
Net property, plant and equipment | 1,639,395 | 1,519,065 |
Investment in unconsolidated affiliates | 36,075 | 33,229 |
Goodwill | 61,423 | 61,423 |
Fair value of hedging contracts | 1,815 | |
Other noncurrent assets | 12,579 | 12,879 |
$2,094,232 | $1,949,390 | |
Current liabilities | ||
Checks in excess of cash balances | $ 5,251 | $ 4,394 |
Notes payable to Questar | 65,000 | 61,200 |
Accounts payable and accrued expenses | 210,924 | 226,155 |
Accounts payable to affiliates | 3,566 | 6,372 |
Fair value of hedging contracts | 141,542 | 64,179 |
Total current liabilities | 426,283 | 362,300 |
Long-term debt | 350,000 | 350,000 |
Deferred income taxes | 338,745 | 334,103 |
Asset-retirement obligations | 69,199 | 66,375 |
Fair value of hedging contracts | 74,304 | 14,471 |
Other long-term liabilities | 35,687 | 33,271 |
Common shareholder’s equity | ||
Common stock | 4,309 | 4,309 |
Additional paid-in capital | 116,027 | 116,027 |
Retained earnings | 813,416 | 710,684 |
Accumulated other comprehensive loss | (133,738) | (42,150) |
Total common shareholder’s equity | 800,014 | 788,870 |
$2,094,232 | $1,949,390 | |
See notes accompanying the consolidated financial statements
#
QUESTAR MARKET RESOURCES, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
6 Months Ended | ||
June 30, | ||
2005 | 2004 | |
(in thousand) | ||
OPERATING ACTIVITIES | ||
Net income | $ 111,382 | $ 78,418 |
Adjustments to reconcile net income to net cash | ||
provided from operating activities: | ||
Depreciation, depletion and amortization | 81,507 | 73,352 |
Deferred income taxes | 28,058 | 15,337 |
Abandonment and impairment of gas, | ||
oil and other properties | 2,898 | 6,693 |
Earnings from unconsolidated affiliates, | ||
net of cash distributions | (1,004) | 1,971 |
Net (gain) loss from asset sales | 78 | (32) |
Hedge ineffectiveness and minority interest | 328 | 336 |
Changes in operating assets and liabilities | (46,305) | 14,140 |
NET CASH PROVIDED FROM | ||
OPERATING ACTIVITIES | 176,942 | 190,215 |
INVESTING ACTIVITIES | ||
Capital expenditures | ||
Purchases of property, plant and equipment | (207,072) | (107,117) |
Other investments | (1,842) | (1,000) |
Total capital expenditures | (208,914) | (108,117) |
Proceeds from disposition of assets | 665 | 613 |
NET CASH USED IN INVESTING ACTIVITIES | (208,249) | (107,504) |
FINANCING ACTIVITIES | ||
Checks in excess of cash balances | 857 | 240 |
Change in notes receivable from Questar | 35,300 | (5,400) |
Change in notes payable to Questar | 3,800 | (17,300) |
Long-term debt repaid | (55,000) | |
Dividends paid | (8,650) | (8,650) |
Other | (317) | |
NET CASH PROVIDED FROM (USED IN) FINANCING ACTIVITIES | 31,307 | (86,427) |
Change in cash and cash equivalents | - | (3,716) |
Beginning cash and cash equivalents | - | 3,716 |
Ending cash and cash equivalents | $ - | $ - |
See notes accompanying the consolidated financial statements
QUESTAR MARKET RESOURCES, INC.
NOTES ACCOMPANYING THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Note 1 – Basis of Presentation of Interim Consolidated Financial Statements
The accompanying interim consolidated financial statements of Market Resources 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 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 SEC’s instructions for Form 10-Q. 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 the 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 mak e 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 periods ended June 30, 2005, are not necessarily indicative of the results that may be expected for the year ending December 31, 2005, due to a variety of factors discussed in the Forward-Looking Statements and Risk Factors 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 for the year ended December 31, 2004.
Note 2 – Asset-Retirement Obligations (ARO)
Market Resources 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, | $66,375 | $60,493 |
Accretion | 2,009 | 900 |
Additions | 1,326 | 869 |
Revisions | 695 | |
Retirements and properties sold | (511) | (262) |
Balance at June 30, | $69,199 | $62,695 |
Wexpro activities are governed by a long-standing agreement with the states of Utah and Wyoming (the Wexpro Agreement). The accounting treatment of reclamation activities associated with ARO for properties administered under the Wexpro Agreement is spelled out in a guideline letter between Wexpro and the Utah Division of Public Utilities and the staff of the Public Service Commission of Wyoming. 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 June 30, 2005, approximately $3.4 million was held in this trust invested in a short-term bond index fund.
Note 3 – Investment in Unconsolidated Affiliates
Market Resources 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 Market Resources’ ownership percentage as of June 30, 2005, were: Rendezvous Gas Services, LLC (Rendezvous), a limited liability corporation, (50%) and Canyon Creek Compression Co., a general partnership (15%).
Operating results representing 100% of these businesses are listed below.
6 Months Ended | ||
June 30, | ||
2005 | 2004 | |
(in thousands) | ||
Revenues | $ 9,903 | $ 8,420 |
Operating income | 6,291 | 5,296 |
Income before income taxes | 6,346 | 5,306 |
Note 4 - Operations by Line of Business
Market Resources has four primary reportable segments: Questar E&P, Wexpro, Gas Management and Energy Trading. Lines of business information are presented according to management’s basis for evaluating performance including differences in the nature of products and services. Certain intersegment sales include intercompany profits. Financial information for reportable segments follow.
3 Months Ended | 6 Months Ended | |||
June 30, | June 30, | |||
2005 | 2004 | 2005 | 2004 | |
(in thousands) | ||||
REVENUES FROM UNAFFILIATED CUSTOMERS | ||||
Questar E&P | $137,350 | $108,113 | $269,847 | $215,067 |
Wexpro | 3,425 | 3,748 | 8,551 | 8,201 |
Gas Management | 24,598 | 15,377 | 49,651 | 34,021 |
Energy Trading and other | 179,523 | 117,122 | 331,185 | 221,125 |
$344,896 | $244,360 | $659,234 | $478,414 | |
REVENUES FROM AFFILIATES | ||||
Wexpro | $ 33,204 | $ 31,010 | $ 66,188 | $59,414 |
Gas Management | 3,029 | 2,660 | 6,201 | 5,640 |
Energy Trading and other | (492) | 420 | 1,436 | 3,393 |
$ 35,741 | $ 34,090 | $ 73,825 | $ 68,447 | |
OPERATING INCOME | ||||
Questar E&P | $ 60,518 | $ 45,802 | $123,960 | $ 91,326 |
Wexpro | 15,871 | 14,033 | 31,749 | 28,565 |
Gas Management | 13,115 | 5,991 | 26,058 | 13,771 |
Energy Trading and other | 1,559 | 86 | 4,014 | 1,573 |
$ 91,063 | $ 65,912 | $185,781 | $135,235 | |
NET INCOME (LOSS) | ||||
Questar E&P | $ 34,426 | $ 25,432 | $ 70,677 | $ 50,623 |
Wexpro | 10,495 | 8,793 | 20,677 | 17,815 |
Gas Management | 8,962 | 4,119 | 17,770 | 9,460 |
Energy Trading and other | 878 | (181) | 2,258 | 520 |
$ 54,761 | $ 38,163 | $111,382 | $ 78,418 | |
Note 5 – 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 Shareholder’s Equity. Other comprehensive income or loss includes changes in the market value of gas or oil-price derivatives. These results are not reported in current income or loss. Income or loss is realized when the physical gas or oil underlying the derivative instrument is sold. A summary of comprehensive income is shown below.
3 Months Ended | 6 Months Ended | |||
June 30, | June 30, | |||
2005 | 2004 | 2005 | 2004 | |
(in thousands) | ||||
Net income | $ 54,761 | $ 38,163 | $111,382 | $ 78,418 |
Other comprehensive income (loss) | ||||
Unrealized income (loss) on energy hedging transactions | 38,336 | (40,829) | (147,818) | (64,589) |
Income taxes | (14,541) | 15,266 | 56,230 | 24,201 |
Net other comprehensive income (loss) | 23,795 | (25,563) | (91,588) | (40,388) |
Total comprehensive income | $ 78,556 | $ 12,600 | $ 19,794 | $ 38,030 |
Note 6 – Recent Accounting Development
In March 2005 the Financial Accounting Standards Board (FASB) issued Interpretation No. 47 (FIN 47), “Accounting for Conditional Asset Retirement Obligations – an Interpretation of FASB Statement No. 143” (SFAS 143). FIN 47 clarifies the term conditional asset retirement obligation as used in SFAS 143 and requires a liability to be recorded if the fair value of the obligation can be reasonably estimated. The types of asset retirement obligations that are covered by FIN 47 are those for which an entity has a legal obligation to perform an asset retirement activity; however the timing and/or method of settling the obligation are conditional on a future event that may or may not be within the control of the entity. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. FIN 47 is effective no la ter than fiscal years ending after December 15, 2005. The Company does not expect the guidelines of FIN 47 will have a significant impact on its results of operations or financial position.
In June 2005 the FASB issued SFAS 154, “Accounting Changes and Error Corrections,” a replacement of existing accounting pronouncements. SFAS 154 modifies accounting and reporting requirements when a company voluntarily chooses to change an accounting principle or correct an accounting error. SFAS 154 requires retroactive restatement of prior period financial statements unless it is impractical. Previous accounting guidelines allowed recognition by cumulative effect in the period of the accounting change. SFAS 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. Earlier application is permitted for accounting changes and corrections of errors made occurring in fiscal years beginning after June 1, 2005. SFAS 154 does not change the transition provisions of any existing accounting pronouncements, including those that are in a transition phase as of the effective date of SFAS 154.
In July 2005 the FASB issued an exposure draft of a Proposed Interpretation “Accounting for Uncertain Tax Positions,” an Interpretation of FASB Statement 109. The exposure draft seeks to reduce perceived diversity in practice associated with recognition and measurement in the accounting for income taxes. The exposure draft would apply to all tax positions accounted for in accordance with SFAS 109 “Accounting for Income Taxes.” The exposure draft requires that a tax position meet a “probable recognition threshold” for the benefit of the uncertain tax position to be recognized in the financial statements. This threshold is to be met assuming that the tax authorities will examine the uncertain tax position. The exposure draft contains guidance with respect to the measurement of the benefit that is recognized for an uncertain tax position, when that benefit should be derecognized, and other matters. This interpretation is effective for Market Resources beginning January 1, 2006, under the timeframe in the proposed statement. The Company has not evaluated the potential effect of this proposed change in accounting principle.
Questar has granted and may continue to grant stock-based compensation to certain Market Resources employees. In December 2004 the FASB issued Statement 123 (revised 2004), (SFAS 123R), “Share Based Payment,” which replaces SFAS 123, “Accounting for Stock-Based Compensation” and supersedes APB Opinion 25, “Accounting for Stock Issued to Employees.” 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. The effective date for implementation of SFAS 123R is January 1, 2006, and alternative phase-in methods are allowed. Questar 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. The Company does not currently expect that any of the alternative phase-in methods for the recognition of stock-based compensation would have a material effect on its operating results or financial position.
#
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
(Unaudited)
SUMMARY
Market Resources consolidated net income for the second quarter of 2005 was $54.8 million compared with $38.2 million for the year earlier period, a 43% increase. Net income for the first half of 2005 totaled $111.4 million versus $78.4 million for the same period in 2004, a 42% increase. Operating income increased $25.2 million, or 38%, in the quarter to quarter comparison, and $50.5 million, or 37%, in the first half comparison due primarily to higher commodity prices and increased natural gas production at Questar E&P, an increased investment base at Wexpro, and increased NGL volumes coupled with improved gas gathering and processing margins at Gas Management.
Following is a comparison of net income (loss) by line of business.
3 Months Ended | 6 Months Ended | |||
June 30, | June 30, | |||
2005 | 2004 | 2005 | 2004 | |
(in thousands) | ||||
Questar E & P | $ 34,426 | $ 25,432 | $ 70,677 | $ 50,623 |
Wexpro | 10,495 | 8,793 | 20,677 | 17,815 |
Gas Management | 8,962 | 4,119 | 17,770 | 9,460 |
Energy Trading and other | 878 | (181) | 2,258 | 520 |
Total | $ 54,761 | $ 38,163 | $111,382 | $ 78,418 |
RESULTS OF OPERATIONS
Following is a summary of Market Resources’ financial and operating results for the second quarter and first half of 2005 compared with the same periods of 2004.
3 Months Ended | 6 Months Ended | |||
June 30, | June 30, | |||
2005 | 2004 | 2005 | 2004 | |
(in thousands) | ||||
OPERATING INCOME | ||||
Revenues | ||||
Natural gas sales | $112,918 | $ 91,127 | $221,519 | $179,696 |
Oil and natural-gas-liquids sales | 27,976 | 20,038 | 54,924 | 41,218 |
Cost-of-service gas operations | 32,020 | 31,552 | 65,653 | 60,446 |
Energy marketing | 179,806 | 117,620 | 333,441 | 225,078 |
Gas gathering, processing and other | 27,917 | 18,113 | 57,522 | 40,423 |
Total revenues | 380,637 | 278,450 | 733,059 | 546,861 |
Operating expenses | ||||
Energy purchases | 177,246 | 116,872 | 327,760 | 222,017 |
Operating and maintenance | 41,776 | 36,517 | 83,824 | 72,230 |
Depreciation, depletion and amortization | 41,257 | 37,084 | 81,116 | 71,033 |
Exploration | 5,476 | 1,266 | 6,849 | 2,353 |
Abandonment and impairment of gas, oil and other properties | 1,493 | 2,287 | 2,898 | 6,693 |
Production and other taxes | 20,962 | 17,496 | 42,206 | 35,152 |
Wexpro Agreement – oil-income sharing | 1,364 | 1,016 | 2,625 | 2,148 |
Total operating expenses | 289,574 | 212,538 | 547,278 | 411,626 |
Operating income | $ 91,063 | $ 65,912 | $185,781 | $135,235 |
OPERATING STATISTICS | ||||
Questar E&P production volumes | ||||
Natural gas (MMcf) | 23,410 | 21,827 | 46,249 | 43,715 |
Oil and natural gas liquids (Mbbl) | 586 | 559 | 1,169 | 1,146 |
Total production (bcfe) | 26.9 | 25.2 | 53.3 | 50.6 |
Average daily production (MMcfe) | 296 | 277 | 294 | 278 |
Average commodity prices, net to the well | ||||
Average realized price (including hedges) | ||||
Natural gas (per Mcf) | $ 4.82 | $ 4.17 | $ 4.79 | $ 4.11 |
Oil and natural gas liquids (per bbl) | $ 40.02 | $ 29.55 | $ 39.38 | $ 29.50 |
Average sales price (excluding hedges) | ||||
Natural gas (per Mcf) | $ 5.74 | $ 5.03 | $ 5.46 | $ 4.87 |
Oil and natural gas liquids (per bbl) | $ 48.52 | $ 35.38 | $ 47.06 | $ 33.57 |
Wexpro investment base at June 30, net | ||||
of depreciation and deferred income taxes (millions) | $ 188.0 | $ 165.3 | ||
Natural gas gathering volumes (in thousands of MMBtu) | ||||
For unaffiliated customers | 33,539 | 32,164 | 66,074 | 66,458 |
For Questar Gas | 11,226 | 9,149 | 22,482 | 18,906 |
For other affiliated customers | 14,416 | 13,336 | 30,262 | 27,894 |
Total gathering | 59,181 | 54,649 | 118,818 | 113,258 |
Gathering revenue (per MMBtu) | $ 0.25 | $ 0.21 | $ 0.25 | $ 0.21 |
Natural gas and oil marketing volumes (Mdthe) | ||||
For unaffiliated customers | 27,784 | 20,725 | 57,384 | 42,580 |
For affiliated customers | 20,658 | 19,446 | 42,519 | 39,796 |
Total marketing | 48,442 | 40,171 | 99,903 | 82,376 |
Questar E&P
For the second quarter of 2005, Questar E&P net income increased 35% to $34.4 million compared with $25.4 million for the same period in 2004. Net income for the first half of 2005 was $70.7 million versus $50.6 million for the same period in 2004, a 40% increase. The increases were driven by a combination of higher realized natural gas, oil and NGL prices and increased gas, oil and NGL production volumes.
Questar E&P’s production increased to 26.9 bcfe in the second quarter of 2005, a 7% increase compared to the year-earlier period. Production for the first half of 2005 was 53.3 bcfe versus 50.6 bcfe for the 2004 period, a 5% increase. Current year 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 half 2005 production growth.
Natural gas is Questar E&P’s primary focus. On an energy-equivalent basis, natural gas comprised approximately 87% of Questar E&P’s production for the first half of 2005. A comparison of energy equivalent production by region is shown in the following table.
3 Months Ended | 6 Months Ended | |||
June 30, | June 30, | |||
2005 | 2004 | 2005 | 2004 | |
(in bcfe) | ||||
Rocky Mountains | ||||
Pinedale Anticline | 6.5 | 4.9 | 14.1 | 11.0 |
Uinta Basin | 6.9 | 6.1 | 12.6 | 12.4 |
Rockies Legacy | 4.1 | 4.7 | 8.1 | 9.1 |
Subtotal – Rocky Mountains | 17.5 | 15.7 | 34.8 | 32.5 |
Midcontinent | 9.4 | 9.5 | 18.5 | 18.1 |
Total Questar E&P production | 26.9 | 25.2 | 53.3 | 50.6 |
Questar E&P’s first half 2005 production from Pinedale increased 28% to 14.1 bcfe versus 11.0 bcfe in the first half 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 drill and complete wells during the period.
Uinta Basin production increased 2% to 12.6 bcfe in the first half of 2005 compared to 12.4 bcfe a year ago. During the first quarter of 2005, 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. During the second quarter of 2005 the company completed installation of a separate gathering system for new high-pressure wells, which reduced the impact of high gathering system pressure on production from older wells reported in the first quarter of 2005.
Production from Rockies Legacy properties in the first half of 2005 was 8.1 bcfe compared to 9.1 bcfe during the 2004 period, an 11% decrease. Legacy properties include all of Questar E&P’s Rocky Mountain producing properties except Pinedale and the Uinta Basin. Legacy properties production during the 2005 period was negatively impacted by normal field decline, seasonal restrictions that limit access to the company’s leases and wells during the winter months and payout of a high-volume well that reduced the company’s working interest.
Midcontinent production was 18.5 bcfe in the first half of 2005 compared to 18.1 bcfe for the same period of 2004, a 2% increase. 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.
Questar E&P also benefited from higher realized prices for natural gas, oil and NGL. For the first half of 2005, the weighted average realized natural gas price for Questar E&P (including the effects of hedging) was $4.79 per Mcf compared to $4.11 per Mcf for the same period in 2004, a 17% increase. Realized oil and NGL prices for the first half of 2005 averaged $39.38 per bbl, compared with $29.50 per bbl during the prior year period, a 33% increase. A comparison of average realized prices by region, including hedges, is shown in the following table.
3 Months Ended | 6 Months Ended | |||
June 30, | June 30, | |||
2005 | 2004 | 2005 | 2004 | |
Natural gas (per Mcf) | ||||
Rocky Mountains | $ 4.67 | $ 3.83 | $ 4.62 | $ 3.89 |
Midcontinent | 5.09 | 4.71 | 5.11 | 4.50 |
Volume-weighted average | $ 4.82 | $ 4.17 | $ 4.79 | $ 4.11 |
Oil and NGL (per bbl) | ||||
Rocky Mountains | $40.42 | $28.41 | $39.94 | $28.62 |
Midcontinent | 39.18 | 32.14 | 38.14 | 31.51 |
Volume-weighted average | $40.02 | $29.55 | $39.38 | $29.50 |
Approximately 83% of Questar E&P’s gas production in the second quarter of 2005 was hedged or pre-sold at an average price of $4.88 per Mcf net to the well (which reflects adjustments for regional basis, gathering and processing costs and gas quality). Hedging reduced potential gas revenues $21.4 million during the current period. For the first half of 2005, approximately 85% of Questar E&P’s gas production was hedged or pre-sold at an average price of $4.93 per Mcf net to the well. Hedging reduced potential gas revenues $31.0 million during the first six months of 2005. For the current quarter, Questar E&P also hedged approximately 71% of its oil production at an average net to the well price of $37.95 per bbl. Hedging reduced potential oil revenues $5.0 million during the quarter. For the first half of 2005, Questar E&P hedged or pre-sold approximately 64% of its oil production at an average net to the well price of $36.50 per bbl. Oil hedges reduced potential revenues $9.0 million during the first half of 2005.
Market Resources 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 flow and earnings from a decline in commodity prices. Questar E&P has continued to take advantage of high natural gas and oil prices to add to its hedge positions through 2008. Natural gas and oil hedges as of June 30, 2005, are summarized in Part I, Item 3 of this report.
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 10% to $2.76 per Mcfe in the second quarter of 2005 versus $2.51 per Mcfe in the second quarter of 2004. For the first half of 2005, pre-income tax cost structure rose 12% to $2.73 per Mcfe compared to $2.44 per Mcfe in the first half of 2004.
Depreciation, depletion and amortization expense rose 15% in the second quarter to $1.16 per Mcfe and 14% to $1.14 per Mcfe for the first half of 2005 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.
Increased production taxes and lease operating expenses drove a $0.12 per Mcfe increase in lifting costs during the current quarter and first half of 2005 versus the comparable year-earlier periods. Increased production taxes were driven by higher gas, oil and NGL sales prices. 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 production-related costs.
For the second quarter of 2005, general and administrative expenses decreased $0.02 per Mcfe, or 6%, to $0.31 per Mcfe. For the first half of 2005, general and administrative expenses increased $0.03 per Mcfe, or 10% to $0.33. The company continues 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 | 6 Months Ended | ||
| June 30, | June 30, | ||
| 2005 | 2004 | 2005 | 2004 |
| (per Mcfe) | |||
| ||||
Lease-operating expense | $0.58 | $0.52 | $0.56 | $0.50 |
Production taxes | 0.50 | 0.44 | 0.49 | 0.43 |
Lifting costs | 1.08 | 0.96 | 1.05 | 0.93 |
Depreciation, depletion and amortization | 1.16 | 1.01 | 1.14 | 1.00 |
General and administrative expense | 0.31 | 0.33 | 0.33 | 0.30 |
Allocated-interest expense | 0.21 | 0.21 | 0.21 | 0.21 |
Total | $2.76 | $2.51 | $2.73 | $2.44 |
Exploration expense increased $3.8 million in the second quarter and $4.1 million in the first half of 2005 compared to the 2004 periods. The increase in expense was due to $2.7 million of exploratory dry hole expense in the second quarter and increased exploratory seismic acquisition expenditures in the Midcontinent and Uinta Basin divisions. Abandonment and impairment expense declined $0.8 million for the quarter and $3.8 million for the first half of 2005. The year to date decrease was primarily due to an impairment expense in the first quarter of 2004 resulting from a well with collapsed casing.
Pinedale Anticline Drilling Activity
As of August 9, 2005, Market Resources (both Questar E&P and Wexpro) operated 119 producing wells on the Pinedale Anticline compared to 76 at the end of the second quarter of 2004, and 104 at year-end 2004. Of the 119 producing wells, Questar E&P has working interests in 104 wells and overriding royalty interests in an additional 14 Wexpro-operated wells. Wexpro has working interests in 52 of the 119 producing wells. Market Resources anticipates drilling and completing about 35 Lance Pool wells (combined Lance and Mesaverde formations) on its Pinedale acreage during 2005.
In late June 2005, the company recommenced drilling operations on the Stewart Point 15-29 exploratory well. The well, targeting Rock Springs and Blair Formation sandstones, is currently drilling below 17,600 feet toward a projected total depth of 19,500 feet. The company anticipates reaching total depth during the third quarter of 2005.
On August 9, 2005, the Wyoming Oil and Gas Conservation Commission (WOGCC) approved Market Resources’ application for 10-acre-density drilling within the currently estimated productive limits of Market Resources’ core Pinedale leasehold. Since July 2004 when the WOGCC approved 20-acre-density drilling for the company’s Pinedale acreage, Market Resources has drilled and gathered data on seven 10-acre-density pilot wells and integrated the data into a detailed reservoir-simulation model. Data presented to the WOGCC with the company’s application indicates a substantial increase in the estimated gas-in-place in the reservoir. Market Resources previously estimated that a total of 470 20-acre-density wells would be required to fully develop the Lance Pool on its core Pinedale leasehold. With 10-acre-density drilling, the company now believes that up to 932 wells will be required .
Uinta Basin
During the first half of 2005, the company drilled or participated in five horizontal Green River formation oil wells, 32 Wasatch and Upper Mesaverde gas wells, and four deeper Blackhawk and Mancos formation gas wells on its core acreage block. In addition, the company completed its first well in the Flat Rock area approximately 40 miles south of the core acreage block. The Flat Rock 9P-36-14-19 well was drilled in late 2004 to a total depth of 12,453 feet and completed in the first quarter of 2005. The well is currently capable of producing approximately 4.0 MMcfe per day from the Entrada, Morrison, Cedar Mountain and Dakota formations. Market Resources is currently acquiring seismic data in the area and intends to drill three additional wells during 2005. The planned drilling program includes the first two test wells under the company’s Exploration and Development Agreement with the Ute Indian Tribe covering 12,557 acres of tribal minerals in the area.
Rockies Legacy
In the Vermillion Basin on the Wyoming-Colorado border, Market Resources continues to evaluate the potential of several formations at depths of 10,000 to 15,000 feet under the company’s 140,000 net leasehold acres. As of June 30, 2005, the company had recompleted two older wells, drilled and completed one new well, and was drilling two wells. The Alkali Gulch Unit Well No 1 was completed in June and produced an average of 2.4 MMcf per day from the Baxter, Frontier and Dakota formations during the first 30 days. The Hiawatha Deep Unit Well No. 2, an old well that was recompleted in the Baxter, Frontier and Dakota formations, produced an average of 3.3 MMcf per day during the first twelve days of commingled production. The Canyon Creek 34R well was recompleted in the Baxter, Frontier, and Dakota formations and production from all three formations will be commingled in the third quarter. The company plans extended production tests from recently completed and future wells to determine the economic viability of the play.
Midcontinent
During the second quarter the company continued one-rig development programs at both the Hartshorne coalbed-methane project in the Arkoma Basin of eastern Oklahoma and the infill-development drilling project in the Elm Grove properties in northwestern Louisiana. The company drilled or participated in 18 new Hartshorne wells in the first half of 2005 and anticipates participating in an additional 20 wells in the second half of the year. In the Elm Grove area, the company drilled or participated in 13 new wells through the first half of 2005, and 15 additional wells are planned in the second half.
Wexpro
For the second quarter of 2005 Wexpro earned $10.5 million, compared with $8.8 million for the same period in 2004, a 19% increase. For the first half of 2005 Wexpro’s net income was $20.7 million, compared with $17.8 million for the same period in 2004, a 16% 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 income taxes and depreciation (investment base). Wexpro’s investment base increased to $188.0 million at June 30, 2005, up $22.7 million over the year earlier period. Wexpro’s net income also benefited from higher oil and NGL prices in 2005.
Gas Management
Gas Management net income increased 118% to $9.0 million in the second quarter of 2005 from $4.1 million in the 2004 period. Net income for the first half of 2005 was $17.8 million versus $9.5 million for the same period in 2004, an 88% increase. Gross keep-whole processing margins (the difference between the market value of natural gas and the market value of NGL extracted from the gas stream or frac spread) grew 72% from $6.0 million in the first half of 2004 to $10.3 million in 2005. The first quarter 2005 acquisition of a gas plant in western Wyoming drove a 94% increase in extracted NGL volumes in the second quarter and 51% for the first half of 2005 versus the year earlier periods. Gathering volumes increased 5.5 million MMBtu to 118.8 million MMBtu in the first half of 2005 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 first half, keep-whole contracts benefited from a 22% increase in NGL sales prices versus the prior-year period. Fee-based contracts benefited from a $0.04 increase in the rate charged per MMBtu processed in the six month comparable periods. Forward sales contracts increased NGL revenues by $0.3 million in 2005.
Pre-tax earnings from Gas Management’s 50% interest in Rendezvous Gas Services, LLC, (Rendezvous) increased to $3.1 million for the first half of 2005 versus $2.6 million for 2004, a 21% increase. Earnings growth in Rendezvous was driven by 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 first quarter 2005 Gas Management completed a transaction in which the company exchanged its interest in an entity that owns and operates a gas gathering system in western Oklahoma for a gas plant in western Wyoming. The acquired 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 western Oklahoma gas gathering system did not contribute significantly to Gas Management’s 2004 earnings.
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. Construction of the facilities is progressing on schedule. The new facilities should be in service during the third quarter of 2005. Gas Management has also signed a letter of intent to form a joint venture with the Ute Indian Tribe and another industry participant to build a gas-gathering system for the Flat Rock area in southern Uinta Basin.
Energy Trading
Energy Trading’s net income for the second quarter of 2005 was $0.8 million compared to a loss of $0.2 million in 2004. For the first half of 2005, net income was $2.2 million compared to $0.5 million in 2004. Gross margins for gas and oil marketing (gross revenues less costs for gas and oil purchases, transportation and gas storage), increased to $5.7 million for the first half of 2005 versus $3.1 million a year ago, an 86% increase. The increase in gross margin was due primarily to a 54% higher unit margin and a 21% increase in volumes over the same period last year.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
Market Resources’ primary market risk exposures arise from commodity-price changes for natural gas, oil and NGL and volatility in interest rates. Energy Trading has long-term contracts for pipeline capacity and is obligated for transportation services with no guarantee that it will be able to recover the full cost of these transportation commitments.
Commodity-Price Risk Management
Market Resources bears the risk associated with commodity-price changes and uses gas- and oil-price-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 e quity 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 income. The ineffective portion of hedges was not significant in 2005 and 2004.
As of June 30, 2005, approximately 41.3 bcf of forecast gas production for the remainder of 2005 was hedged at an average price of $4.93 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 June 30, 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.
Time Periods | Rocky Mountains | Midcontinent | Total |
| Rocky Mountains | Midcontinent | Total | |
Gas (in bcf) | Average price per Mcf, net to the well | |||||||
Second half of 2005 | 28.3 | 13.0 | 41.3 | $4.78 | $5.23 | $4.93 | ||
First half of 2006 | 19.8 | 9.4 | 29.2 | $5.19 | $5.95 | $5.44 | ||
Second half of 2006 | 20.1 | 9.6 | 29.7 | 5.19 | 5.95 | 5.44 | ||
12 months of 2006 | 39.9 | 19.0 | 58.9 | 5.19 | 5.95 | 5.44 | ||
First half of 2007 | 6.3 | 4.2 | 10.5 | $5.64 | $6.78 | $6.09 | ||
Second half of 2007 | 6.4 | 4.2 | 10.6 | 5.64 | 6.78 | 6.09 | ||
12 months of 2007 | 12.7 | 8.4 | 21.1 | 5.64 | 6.78 | 6.09 | ||
First half of 2008 | 1.7 | 1.6 | 3.3 | $5.93 | $6.47 | $6.20 | ||
Second half of 2008 | 1.7 | 1.7 | 3.4 | 5.93 | 6.47 | 6.20 | ||
12 months of 2008 | 3.4 | 3.3 | 6.7 | 5.93 | 6.47 | 6.20 | ||
Oil (in Mbbl) | Average price per bbl, net to the well | |||||||
Second half of 2005 | 550 | 184 | 734 | $39.01 | $34.70 | $37.93 | ||
First half of 2006 | 471 | 72 | 543 | $46.15 | $53.44 | $47.12 | ||
Second half of 2006 | 478 | 74 | 552 | 46.15 | 53.44 | 47.12 | ||
12 months of 2006 | 949 | 146 | 1,095 | 46.15 | 53.44 | 47.12 | ||
First half of 2007 | 109 | 72 | 181 | $50.49 | $50.87 | $50.64 | ||
Second half of 2007 | 110 | 74 | 184 | 50.49 | 50.87 | 50.64 | ||
12 months of 2007 | 219 | 146 | 365 | 50.49 | 50.87 | 50.64 | ||
Market Resources held gas-price hedging contracts covering the price exposure for about 175.5 million MMBtu of gas and 2.2 MMbbl of oil as of June 30, 2005. A year earlier Market Resources’ hedging contracts covered 139.1 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 June 30, 2005.
A table of the net fair value of gas-hedging contracts as of June 30, 2005, is shown below. About 65% of the fair value of all contracts will settle and be reclassified from other comprehensive income in the next 12 months.
The following table shows sensitivity of the mark-to-market valuation of gas and oil price-hedging contracts to changes in the market price of gas and oil.
At June 30, | ||
2005 | 2004 | |
(in millions) | ||
|
| |
Mark-to-market valuation – liability | ($215.6) | ($115.4) |
Value if market prices of gas and oil decline by 10% | (105.8) | (55.6) |
Value if market prices of gas and oil increase by 10% | (325.5) | (175.1) |
Interest-Rate Risk Management
As of June 30, 2005, Market Resources had $350.0 million of fixed-rate long-term debt and no variable-rate long-term debt outstanding.
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-15(e) under the Securities Exchange Act of 1934, as amended (the Exchange Act)) as of the end of the period covered by the report (the Evaluation Date). Based on such evaluation, such officers have concluded that, as of the Evaluation Date, the Company’s disclosure controls and procedures are effective in alerting them on a timely basis to material information relating to the Company, including its consolidated subsidiaries, required to be included in the Company’s reports filed or submitted under the Exchange Act. The Company’s Chief Executive Officer and Chief Financ ial Officer also concluded that the controls and procedures were effective in ensuring that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is accumulated and communicated to the Company’s management including its principal executive and financial officers or persons performing similar functions as appropriate to allow timely decisions regarding required disclosure.
Changes in Internal Controls. Since the Evaluation Date, there have not been any changes in the Company’s internal controls or other factors during the most recent fiscal quarter that could materially affect such controls.
PART II. OTHER INFORMATION
ITEM 6. EXHIBITS
The following exhibits are being filed as part of this report:
Exhibit No.
Exhibit
31.1.
Certification signed by Charles B. Stanley, Questar Market Resources, Inc.’s Chief Executive Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2.
Certification signed by S. E. Parks, Questar Market Resources, Inc.’s Chief Financial Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.
Certification signed by Charles B. Stanley and S. E. Parks, Questar Market Resources, Inc.’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 MARKET RESOURCES, INC.
(Registrant)
August 11, 2005
/s/Charles B. Stanley
Date
Charles B. Stanley
President and Chief Executive Officer
August 11, 2005
/s/S. E. Parks
Date
S. E. Parks, Vice President and
Chief Financial Officer
Exhibits List
Exhibits
31.1.
Certification signed by Charles B. Stanley, Questar Market Resources, Inc.’s Chief Executive Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2.
Certification signed by S. E. Parks, Questar Market Resources, Inc.’s Chief Financial Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.
Certification signed by Charles B. Stanley and S. E. Parks, Questar Market Resources Inc.’s Chief Executive Officer and Chief Financial Officer, respectively, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
#
Exhibit 31.1.
CERTIFICATION
I, Charles B. Stanley, certify that:
1.
I have reviewed this quarterly report of Questar Market Resources, Inc. on Form 10-Q for the period ending June 30, 2005;
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 quarterly report;
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:
a)
designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)
designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)
evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)
disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting;
5.
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):
a)
all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)
any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
August 11, 2005
By: /s/Charles B. Stanley
Date
Charles B. Stanley
President and Chief
Executive Officer
#
Exhibit 31.2.
CERTIFICATION
I, S. E. Parks, certify that:
1.
I have reviewed this quarterly report of Questar Market Resources, Inc. on Form 10-Q for the period ending June 30, 2005;
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 quarterly report;
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:
a)
designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)
designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)
evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)
disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting;
5.
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):
a)
all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)
any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
August 11, 2005
By:
/s/S. E. Parks
Date
S. E. Parks
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 Market Resources, Inc. (the Company) on Form 10-Q for the period ending June 30, 2005, as filed with the Securities and Exchange Commission on the date hereof (the Report), Charles B. Stanley, President and Chief Executive Officer of the Company, and S. E. Parks, 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 MARKET RESOURCES, INC.
August 11, 2005
/s/Charles B. Stanley
Date
Charles B. Stanley
President and Chief Executive Officer
August 11, 2005
/s/S. E. Parks
Date
S. E. Parks
Vice President and Chief Financial Officer
#