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 September 30, 2006
[ ]
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 & nbsp;87-0287750
(State or 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
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 a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer [ ] Accelerated filer [ ] Non-accelerated filer [X]
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes [ ] No [X]
On October 31, 2006, 4,309,427 shares of the registrant’s common stock, $1.00 par value, were outstanding (all shares are owned by Questar Corporation).
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 Quarter Ended September 30, 2006
TABLE OF CONTENTS
Page
PART I.
FINANCIAL INFORMATION
Financial Statements (Unaudited)
3
Consolidated Statements of Income for the three and nine months ended
3
Condensed Consolidated Balance Sheets as of September 30, 2006
4
Condensed Consolidated Statements of Cash Flows for the nine months ended
5
Notes Accompanying the Consolidated Financial Statements
6
Management’s Discussion and Analysis of Financial Condition and
12
Quantitative and Qualitative Disclosures About Market Risk.
18
22
PART II.
OTHER INFORMATION
23
23
24
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PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
QUESTAR MARKET RESOURCES, INC.
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
3 Months Ended | 9 Months Ended | |||
September 30, | September 30, | |||
2006 | 2005 | 2006 | 2005 | |
(in thousands, except per share amounts) | ||||
REVENUES | ||||
From unaffiliated customers | $427,907 | $446,746 | $1,227,094 | $1,105,980 |
From affiliated customers | 39,985 | 34,746 | 132,586 | 108,571 |
TOTAL REVENUES | 467,892 | 481,492 | 1,359,680 | 1,214,551 |
OPERATING EXPENSES | ||||
Cost of natural gas and other products sold | 169,999 | 243,972 | 473,422 | 559,201 |
Operating and maintenance | 44,444 | 42,222 | 132,034 | 110,872 |
General and administrative | 18,211 | 13,332 | 50,270 | 41,037 |
Production and other taxes | 21,991 | 25,413 | 70,045 | 67,619 |
Depreciation, depletion and amortization | 61,766 | 44,083 | 169,401 | 125,199 |
Exploration | 16,847 | 2,574 | 30,247 | 9,423 |
Abandonment and impairment of gas, | ||||
oil and other properties | 1,955 | 1,712 | 5,497 | 4,610 |
Wexpro Agreement – oil-income sharing | 1,728 | 1,770 | 4,542 | 4,395 |
TOTAL OPERATING EXPENSES | 336,941 | 375,078 | 935,458 | 922,356 |
OPERATING INCOME | 130,951 | 106,414 | 424,222 | 292,195 |
Net gain on asset sales | 25,257 | 1,052 | 25,616 | 974 |
Interest and other income | 944 | 2,557 | 4,212 | 3,986 |
Income from unconsolidated affiliates | 1,801 | 1,910 | 5,333 | 5,131 |
Net unrealized mark-to-market loss on basis swaps | (5,140) | (10,754) | ||
Loss on early extinguishment of debt | (1,746) | |||
Interest expense | (7,892) | (8,546) | (25,394) | (22,356) |
INCOME BEFORE INCOME TAXES | 145,921 | 103,387 | 421,489 | 279,930 |
Income taxes | 53,919 | 38,108 | 155,537 | 103,269 |
NET INCOME | $ 92,002 | $ 65,279 | $ 265,952 | $ 176,661 |
See notes accompanying the consolidated financial statements
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QUESTAR MARKET RESOURCES, INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, | December 31, | ||
2006 | 2005 | ||
(in thousands) | |||
ASSETS | |||
Current assets | |||
Cash and cash equivalents | $ 4,350 | ||
Notes receivable from Questar | $ 77,800 | 89,100 | |
Federal income taxes recoverable | 6,627 | 14,136 | |
Accounts receivable, net | 182,969 | 241,714 | |
Accounts receivable from affiliates | 21,111 | 26,386 | |
Derivative collateral deposits | 5,150 | ||
Fair value of derivative contracts | 104,709 | 1,972 | |
Inventories, at lower of average cost or market | |||
Gas and oil storage | 20,256 | 33,192 | |
Materials and supplies | 32,248 | 24,018 | |
Prepaid expenses and other | 22,083 | 23,348 | |
Deferred income taxes – current | 97,136 | ||
Total current assets | 467,803 | 560,502 | |
Property, plant and equipment | 3,551,043 | 3,029,502 | |
Less accumulated depreciation, depletion and amortization | 1,249,279 | 1,095,543 | |
Net property, plant and equipment | 2,301,764 | 1,933,959 | |
Investment in unconsolidated affiliates | 37,437 | 30,681 | |
Goodwill | 60,882 | 61,423 | |
Fair value of derivative contracts | 51,990 | ||
Other noncurrent assets | 20,670 | 17,528 | |
$2,940,546 | $2,604,093 | ||
LIABILITIES AND SHAREHOLDER’S EQUITY | |||
Current liabilities | |||
Checks in excess of cash balances | $ 14,212 | ||
Notes payable to Questar | 93,500 | $ 180,800 | |
Accounts payable and accrued expenses | 272,952 | 349,208 | |
Accounts payable to affiliates | 2,688 | 3,755 | |
Fair value of derivative contracts | 6,397 | 222,049 | |
Deferred income taxes – current | 25,188 | ||
Total current liabilities | 414,937 | 755,812 | |
Long-term debt | 399,192 | 350,000 | |
Deferred income taxes | 543,567 | 408,399 | |
Asset retirement obligations | 106,197 | 74,273 | |
Fair value of derivative contracts | 176 | 99,044 | |
Other long-term liabilities | 47,376 | 42,710 | |
Common shareholder’s equity | |||
Common stock | 4,309 | 4,309 | |
Additional paid-in capital | 120,116 | 116,027 | |
Retained earnings | 1,204,598 | 951,621 | |
Accumulated other comprehensive income (loss) | 100,078 | (198,102) | |
Total common shareholder’s equity | 1,429,101 | 873,855 | |
$2,940,546 | $2,604,093 | ||
See notes accompanying the consolidated financial statements
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QUESTAR MARKET RESOURCES, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
9 Months Ended | ||
September 30, | ||
2006 | 2005 | |
(in thousands) | ||
OPERATING ACTIVITIES | ||
Net income | $265,952 | $176,661 |
Adjustments to reconcile net income to net cash | ||
provided from operating activities: | ||
Depreciation, depletion and amortization | 171,020 | 125,786 |
Deferred income taxes | 75,777 | 69,441 |
Share-based compensation | 4,089 | |
Abandonment and impairment of gas, | ||
oil and other properties | 5,497 | 4,610 |
Income from unconsolidated affiliates | (5,333) | (5,131) |
Distributed income from unconsolidated affiliates | 4,902 | 4,342 |
Net gain on asset sales | (25,616) | (974) |
Net unrealized mark-to-market loss on basis swaps | 10,754 | |
Loss on early extinguishment of debt | 1,746 | |
Ineffective portion of fixed-price swaps | (106) | 390 |
Changes in operating assets and liabilities | (10,732) | (259,928) |
NET CASH PROVIDED FROM OPERATING ACTIVITIES | 497,950 | 115,197 |
INVESTING ACTIVITIES | ||
Capital expenditures | ||
Property, plant and equipment | (497,312) | (373,350) |
Other investments | (6,325) | (6,787) |
Total capital expenditures | (503,637) | (380,137) |
Proceeds from disposition of assets | 30,893 | 1,710 |
NET CASH USED IN INVESTING ACTIVITIES | (472,744) | (378,427) |
FINANCING ACTIVITIES | ||
Change in notes receivable from Questar | 11,300 | 43,000 |
Change in notes payable to Questar | (87,300) | 46,200 |
Long-term debt issued, net of issue costs | 246,953 | 200,000 |
Long-term debt repaid | (200,000) | |
Changes in checks in excess of cash balances | 14,212 | (4,394) |
Early extinguishment of debt costs | (1,746) | |
Dividends | (12,975) | (12,975) |
NET CASH (USED IN) PROVIDED FROM FINANCING ACTIVITIES | (29,556) | 271,831 |
Change in cash and cash equivalents | (4,350) | 8,601 |
Beginning cash and cash equivalents | 4,350 | |
Ending cash and cash equivalents | $ - | $ 8,601 |
See notes accompanying the consolidated financial statements
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QUESTAR MARKET RESOURCES, INC.
NOTES ACCOMPANYING THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Note 1 – Nature of Business
Questar Market Resources, Inc. (Market Resources or the Company) is a natural gas-focused energy company, a wholly owned subsidiary of Questar Corporation (Questar) and Questar’s primary growth driver. Market Resources is a sub-holding company with four principal subsidiaries:
·
Questar Exploration and Production Company (Questar E&P) acquires, explores for, develops and produces natural gas, oil, and NGL;
·
Wexpro Company (Wexpro) manages, develops and produces cost-of-service reserves for gas utility affiliate, Questar Gas;
·
Questar Gas Management Company (Gas Management) provides midstream field services including natural gas-gathering and processing services for affiliates and third parties; and
·
Questar Energy Trading Company (Energy Trading) markets equity and third-party gas and oil, provides risk-management services, and owns and operates an underground gas-storage reservoir.
Note 2 – Summary of Significant Accounting Policies
Basis of Presentation of Interim Consolidated Financial Statements
The interim consolidated financial statements contain the accounts of Market Resources and its majority-owned or controlled subsidiaries. The consolidated financial statements were prepared in accordance with U.S. generally accepted accounting principles (GAAP) and with the instructions for annual reports on Form 10-K and Regulations S-X and S-K. All significant intercompany accounts and transactions have been eliminated in consolidation.
The 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. Interim consolidated financial statements do not include all of the information and notes required by GAAP for audited annual consolidated financial statements. These consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2005. Certain reclassifications were made to prior period financial statements to conform with the current presentation.
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. The results of operations for the nine months ended September 30, 2006, are not necessarily indicative of the results that may be expected for the year ending December 31, 2006, due to a variety of factors discussed in the Forward-Looking Statements located in Item 3 of this report.
Derivative Collateral Deposits
Derivative collateral deposits represent cash collateral deposited with counterparties under the terms of derivative agreements. Some counterparties may require the Company to deposit cash collateral when the derivatives under these agreements are out-of-the-money by an amount that exceeds counterparty credit limits. The deposits are restricted until either the derivative transaction returns to in-the-money status or the open position is settled.
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Investment in Unconsolidated Affiliates
Questar uses the equity method to account for investment in unconsolidated affiliates where it does not have control, but has significant influence. Generally, the investment in unconsolidated affiliates on the Company’s Consolidated Balance Sheets equals the Company’s proportionate share of equity reported by the unconsolidated affiliates. Investment is assessed for possible impairment when events indicate that the fair value of the investment may be below the Company’s carrying value. When such a condition is deemed to be other than temporary, the carrying value of the investment is written down to its fair value, and the amount of the write-down is included in net income.
Property, Plant and Equipment
Capitalized exploratory well costs
The Company capitalizes exploratory well costs until it determines whether the well is commercial or noncommercial. If the Company deems the well commercial, capitalized costs are depreciated on a field basis using the unit-of-production method and the estimated proved developed gas and oil reserves. If the Company concludes that the well is noncommercial, well costs are immediately charged to exploration expense. Exploratory well costs capitalized for a period greater than one year since the completion of drilling are expensed unless the Company remains engaged in substantial activities to assess whether the well is commercial.
Depreciation, depletion and amortization
Capitalized proved leasehold costs are depleted on a field-by-field basis using the unit-of-production method and the estimated proved gas and oil reserves. Oil, condensate and NGL volumes are converted to natural gas equivalents using the ratio of one barrel of crude oil, condensate or NGL to 6,000 cubic feet of natural gas. Capitalized costs of exploratory wells that have found proved gas and oil reserves and capitalized development costs are depreciated using the unit-of-production method based on estimated proved developed reserves on a field basis. The Company capitalizes an estimate of the fair value of future abandonment costs. Future abandonment costs, less estimated future salvage values are depreciated over the life of the related asset on a unit-of-production method.
Note 3 – Share-Based Compensation
Questar issues stock options and restricted shares to certain officers, employees and non-employee directors under its Long Term Stock Incentive Plan (LTSIP). Questar has granted and continues to grant share-based compensation to certain Market Resources employees. Prior to January 1, 2006, Questar and the Company accounted for share-based compensation using the intrinsic value method prescribed by Accounting Principles Board Opinion (APBO) 25 “Accounting for Stock Issued to Employees” and related interpretations. No compensation cost was recorded for stock options because the exercise price equaled the market price on the date of grant. The granting of restricted shares results in recognition of compensation cost. Restricted shares are valued at the grant-date market price and amortized to expense over the vesting period.
Questar and the Company implemented SFAS 123R “Share Based Payment,” effective January 1, 2006, and chose the modified prospective phase-in method of accounting by SFAS 123R. The modified prospective phase-in method requires recognition of compensation costs for all share-based payments granted, modified or settled after January 1, 2006, as well as for any awards that were granted prior to the implementation date for which the required service has not yet been performed. As a result of adopting SFAS 123R, the Company’s income before income taxes and net income for the nine months ended September 30, 2006, were approximately $0.5 million and $0.3 million lower, respectively, than if the Company had continued to account for share-based compensation under APBO 25. The pro forma share-based compensation expense impact for the first nine months of 2005 was approximately $0.6 mi llion.
Transactions involving stock options granted to employees of Market Resources under the LTSIP are summarized below:
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Outstanding Options | Price Range | Weighted- Average Price | |
Balance at January 1, 2006 | 901,319 | $15.00 – $77.14 | $30.17 |
Exercised | (175,348) | 15.00 – 35.10 | 23.09 |
Balance at September 30, 2006 | 725,971 | $15.00 – $77.14 | $31.88 |
The number of unvested stock options held by employees of Market Resources decreased by 66,436 shares in the first nine months of 2006.
Options Outstanding | Options Exercisable | Unvested Options | |||||
Range of exercise prices | Number outstanding at Sept. 30, 2006 | Weighted-average remaining term in years | Weighted-average exercise price | Number exercisable at Sept. 30, 2006 | Weighted-average exercise price | Number unvested at Sept. 30, 2006 | Weighted average exercise price |
$15.00 - $17.00 | 69,314 | 3.0 | $15.92 | 69,314 | $15.92 | ||
19.13 - 23.95 | 238,862 | 4.8 | 23.02 | 238,862 | 23.02 | ||
27.11 - 29.71 | 303,856 | 5.7 | 27.44 | 303,856 | 27.44 | ||
$35.10 - $77.14 | 113,939 | 4.5 | 72.00 | 6,250 | 35.10 | 107,689 | $74.14 |
725,971 | 4.9 | $31.88 | 618,282 | $24.52 | 107,689 | $74.14 | |
Most restricted share grants vest in equal installments over a three to five year period from the grant date. Several grants vest in a single installment after a specified period. The weighted average vesting period of unvested restricted shares at September 30, 2006, was 18 months. Transactions involving restricted shares in the LTSIP in the first nine months of 2006 are summarized below:
Weighted Average | |||
Shares | Price Range | Price | |
Balance at January 1, 2006 | 177,241 | $27.11 - $86.03 | $41.28 |
Granted | 114,790 | 70.40 - 89.54 | 74.10 |
Distributed | (59,749) | 27.11 - 77.06 | 34.45 |
Forfeited | (2,495) | 28.72 - 75.99 | 62.28 |
Balance at September 30, 2006 | 229,787 | $27.11 - $89.54 | $59.22 |
Note 4 – Operations by Line of Business
Market Resources has four primary reportable segments: Questar E&P, Wexpro, Gas Management and Energy Trading. Line of business information is 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 follows:
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3 Months Ended | 9 Months Ended | |||
September 30, | September 30, | |||
2006 | 2005 | 2006 | 2005 | |
(in thousands) | ||||
REVENUES FROM UNAFFILIATED CUSTOMERS | ||||
Questar E&P | $206,033 | $158,269 | $ 615,205 | $ 428,116 |
Wexpro | 6,104 | 6,228 | 16,076 | 14,779 |
Gas Management | 41,518 | 35,561 | 123,251 | 97,743 |
Energy Trading and other | 174,252 | 246,688 | 472,562 | 565,342 |
$427,907 | $446,746 | $1,227,094 | $1,105,980 | |
REVENUES FROM AFFILIATED CUSTOMERS | ||||
Wexpro | $ 36,384 | $ 31,657 | $ 111,627 | $ 97,845 |
Gas Management | 3,534 | 3,003 | 10,537 | 9,204 |
Energy Trading and other | 67 | 86 | 10,422 | 1,522 |
$ 39,985 | $ 34,746 | $ 132,586 | $ 108,571 | |
OPERATING INCOME | ||||
Questar E&P | $ 92,592 | $ 76,405 | $ 315,485 | $ 200,365 |
Wexpro | 18,657 | 16,850 | 55,168 | 48,599 |
Gas Management | 15,972 | 10,281 | 45,744 | 36,339 |
Energy Trading and other | 3,730 | 2,878 | 7,825 | 6,892 |
$130,951 | $106,414 | $ 424,222 | $ 292,195 | |
NET INCOME | ||||
Questar E&P | $ 66,045 | $ 44,753 | $ 192,635 | $ 115,430 |
Wexpro | 12,130 | 11,251 | 36,072 | 31,928 |
Gas Management | 10,999 | 7,299 | 30,923 | 25,069 |
Energy Trading and other | 2,828 | 1,976 | 6,322 | 4,234 |
$ 92,002 | $ 65,279 | $ 265,952 | $ 176,661 |
Note 5 – Disposition of Property
On August 30, 2006, Questar E&P sold certain proved reserves and undeveloped leasehold interests in western Colorado and recognized a pre-tax gain of $22.7 million. The gain is included in the Consolidated Statements of Income line item “Net gain on asset sales”. For income tax purposes, the Company structured the sale of the Colorado properties and the March 2006 acquisition of certain Louisiana properties to qualify as a reverse like-kind exchange of property under Section 1031 of the Internal Revenue Code of 1986, as amended.
Note 6 – 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
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costs are estimated and depreciated over the life of the related assets. Revisions to estimates of the ARO result from changes in expected cash flows. The ARO liability is adjusted to present value each period through an accretion calculation using a credit-adjusted risk-free interest rate. Changes in asset retirement obligations were as follows:
2006 | 2005 | |
(in thousands) | ||
ARO liability at January 1, | $ 74,273 | $66,375 |
Accretion | 4,439 | 3,097 |
Liabilities incurred | 7,057 | 3,010 |
Revisions | 22,340 | |
Liabilities settled | (1,912) | (724) |
ARO liability at September 30, | $106,197 | $71,758 |
Wexpro activities are governed by a long-standing agreement with the states of Utah and Wyoming (the Wexpro Agreement). The accounting treatment of reclamation activities associated with ARO for properties administered under the Wexpro Agreement is spelled out in a guideline letter between Wexpro and the Utah Division of Public Utilities and the staff of the Public Service Commission of Wyoming (PSCW). Accordingly, Wexpro collects from Questar Gas and deposits in trust funds related to estimated ARO costs. The funds are used to satisfy retirement obligations as the properties are abandoned. At September 30, 2006, approximately $4.6 million was held in this trust invested primarily in a short-term bond index fund.
Note 7 – Capitalized Exploratory Well Costs
Net changes in capitalized exploratory well costs for the first nine months of 2006 are as follows and exclude amounts that were capitalized and subsequently expensed in the period:
2006 | |
(in thousands) | |
Balance at January 1, | $ 16,514 |
Additions to capitalized exploratory well costs pending the | |
determination of proved reserves | 1,998 |
Reclassifications to property, plant and equipment after the | |
determination of proved reserves | (5,030) |
Capitalized exploratory well costs charged to expense | (11,484) |
Balance at September 30, | $ 1,998 |
The following table provides an aging of capitalized exploratory well costs based on the date drilling was completed and the number of projects for which exploratory well costs have been capitalized for a period greater than one year since the completion of drilling:
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September 30, | December 31, | |
2006 | 2005 | |
(in thousands) | ||
Capitalized exploratory well costs that have been capitalized | ||
one year or less | $1,998 | $16,514 |
Capitalized exploratory well costs that have been capitalized | ||
longer than one year | ||
Balance at end of period | $1,998 | $16,514 |
Note 8 – Financing
On May 11, 2006, Market Resources sold $250 million principal amount of 6.05% Notes due 2016. Net proceeds of $247 million were used for general corporate purposes including the June 14, 2006, early extinguishment of $200 million of 7% Notes due 2007. Market Resources recorded a $1.7 million pre-tax charge related to the early extinguishment.
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 Shareholder’s Equity. Other comprehensive income or loss includes changes in the market value of certain gas- and oil-price hedging arrangements. These results are not reported in current income or loss. Income or loss is realized when the physical gas, oil or NGL underlying the derivative instrument is sold or if the derivative is determined to be ineffective. A summary of comprehensive income is shown below:
3 Months Ended | 9 Months Ended | |||
September 30, | September 30, | |||
2006 | 2005 | 2006 | 2005 | |
(in thousands) | ||||
Net income | $ 92,002 | $ 65,279 | $ 265,952 | $ 176,661 |
Other comprehensive income (loss) | ||||
Net unrealized gain (loss) on energy hedging contracts | 196,613 | (352,386) | 479,895 | (500,204) |
Income taxes | (74,367) | 133,237 | (181,715) | 189,467 |
Net other comprehensive income (loss) | 122,246 | (219,149) | 298,180 | (310,737) |
Total comprehensive income (loss) | $214,248 | ($153,870) | $ 564,132 | ($134,076) |
Note 10 – Recent Accounting Developments
In July 2006, the Financial Accounting Standards Board (FASB) issued FASB Interpretation 48 “Accounting for Uncertainty in Income Taxes” (FIN 48). The interpretation applies to all tax positions related to income taxes subject to FASB Statement 109 “Accounting for Income Taxes.” FIN 48 clarifies the accounting for uncertainty in income taxes by prescribing a minimum recognition threshold for a tax position to be reflected in the financial statements. If recognized, the tax benefit is measured as the largest amount of tax benefit that is more-likely-than-not to be realized upon ultimate settlement. FIN 48 is effective January 1, 2007. The Company is evaluating the effect, if any, that FIN 48 will have on its financial statements.
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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion updates information as to Market Resources financial condition provided in its previous Form 10-Q and 10-K filings, and analyzes the changes in the results of operations between the three- and nine-month periods ended September 30, 2006 and 2005. For definitions of commonly used gas and oil terms found in this Form 10-Q, please refer to the “Glossary of Commonly Used Terms” provided in the 2005 Annual Report on Form 10-K.
Summary
Market Resources net income was 41% higher in the third quarter of 2006 and 51% higher for the first nine months of 2006 compared to the same periods of 2005. Higher natural gas production and higher realized prices for natural gas, oil and NGL, higher gas processing and gas gathering margins and an increased investment base for Wexpro drove the increase. Third quarter 2006 results also included a $15.8 million after-tax gain from the sale of assets, an $8.7 million after-tax charge related to unsuccessful exploratory wells in Wyoming and Utah and a $3.2 million after-tax charge for mark-to-market losses on natural gas basis-only swaps.
3 Months Ended | 9 Months Ended | ||||||
September 30, | % | September 30, | % | ||||
2006 | 2005 | Change | 2006 | 2005 | Change | ||
(in millions) | |||||||
Net income | |||||||
Questar E&P | $66.0 | $44.8 | 47% | $192.6 | $115.4 | 67% | |
Wexpro | 12.1 | 11.3 | 7 | 36.1 | 31.9 | 13 | |
Gas Management | 11.0 | 7.3 | 51 | 30.9 | 25.1 | 23 | |
Energy Trading and other | 2.9 | 1.9 | 53 | 6.4 | 4.3 | 49 | |
Market Resources total | $92.0 | $65.3 | 41% | $266.0 | $176.7 | 51% | |
Results of Operations
Market Resources, which conducts natural gas and oil exploration, development and production, gas gathering and processing, wholesale gas and oil marketing and gas storage, reported $92.0 million of net income for the third quarter of 2006 compared with $65.3 million for the year earlier period, a 41% increase. Net income for the first nine months of 2006 totaled $266.0 million versus $176.7 million for the same period in 2005, a 51% increase. Operating income increased $24.5 million, or 23%, in the quarter to quarter comparison, and $132.0 million, or 45%, in the nine month comparison due primarily to increased natural gas production and higher realized prices at Questar E&P, an increased investment base at Wexpro and increased gas-processing plant margins at Gas Management.
Following is a summary of Market Resources financial and operating results for the third quarter and first nine months of 2006 compared with the same periods of 2005:
3 Months Ended | 9 Months Ended | |||
September 30, | September 30, | |||
2006 | 2005 | 2006 | 2005 | |
(in thousands) | ||||
OPERATING INCOME | ||||
Revenues | ||||
Natural gas sales | $168,725 | $131,466 | $ 512,799 | $ 352,985 |
Oil and NGL sales | 41,997 | 31,254 | 114,963 | 86,178 |
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Cost-of-service gas operations | 36,588 | 32,051 | 111,048 | 97,704 |
Energy marketing | 174,950 | 248,069 | 484,214 | 568,979 |
Gas gathering, processing and other | 45,632 | 38,652 | 136,656 | 108,705 |
Total revenues | 467,892 | 481,492 | 1,359,680 | 1,214,551 |
Operating expenses | ||||
Energy purchases | 169,999 | 243,972 | 473,422 | 559,201 |
Operating and maintenance | 44,444 | 42,222 | 132,034 | 110,872 |
General and administrative | 18,211 | 13,332 | 50,270 | 41,037 |
Production and other taxes | 21,991 | 25,413 | 70,045 | 67,619 |
Depreciation, depletion and amortization | 61,766 | 44,083 | 169,401 | 125,199 |
Exploration | 16,847 | 2,574 | 30,247 | 9,423 |
Abandonment and impairment of gas, oil and other properties | 1,955 | 1,712 | 5,497 | 4,610 |
Wexpro Agreement – oil-income sharing | 1,728 | 1,770 | 4,542 | 4,395 |
Total operating expenses | 336,941 | 375,078 | 935,458 | 922,356 |
Operating income | $130,951 | $106,414 | $ 424,222 | $ 292,195 |
OPERATING STATISTICS | ||||
Questar E&P production volumes | ||||
Natural gas (MMcf) | 29,424 | 25,681 | 85,541 | 71,930 |
Oil and NGL (Mbbl) | 729 | 593 | 1,972 | 1,762 |
Total production (Bcfe) | 33.8 | 29.2 | 97.4 | 82.5 |
Average daily production (MMcfe) | 367 | 318 | 357 | 302 |
Questar E&P average realized price, net to the well (including hedges) | ||||
Natural gas (per Mcf) | $ 5.73 | $ 5.12 | $ 5.99 | $ 4.91 |
Oil and NGL (per bbl) | $ 49.81 | $ 43.04 | $ 50.10 | $ 40.61 |
Wexpro investment base at September 30, net | ||||
of depreciation and deferred income taxes (millions) | $ 224.8 | $ 197.6 | ||
Natural gas processing volumes | ||||
NGL sales volumes (Mgal) | 20,778 | 24,562 | 65,322 | 64,846 |
Processing fee based (in thousands of MMBtu) | 30,552 | 19,546 | 87,108 | 43,476 |
Natural gas processing revenues | ||||
NGL sales price (per gal) | $ 0.89 | $ 0.73 | $ 0.89 | $ 0.71 |
Processing fee based (per MMBtu) | $ 0.13 | $ 0.16 | $ 0.14 | $ 0.16 |
Natural gas gathering volumes (in thousands of MMBtu) | ||||
For unaffiliated customers | 41,341 | 35,619 | 109,775 | 101,693 |
For Questar Gas | 9,970 | 10,252 | 30,212 | 32,734 |
For other affiliated customers | 20,831 | 17,895 | 55,824 | 48,157 |
Total gathering | 72,142 | 63,766 | 195,811 | 182,584 |
Gathering revenue (per MMBtu) | $ 0.28 | $ 0.25 | $ 0.29 | $ 0.25 |
Natural gas and oil marketing volumes (Mdthe) | ||||
For unaffiliated customers | 29,320 | 32,064 | 84,607 | 87,320 |
For affiliated customers | 24,938 | 22,455 | 74,816 | 67,102 |
Total marketing | 54,258 | 54,519 | 159,423 | 154,422 |
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Questar E&P
Questar E&P, a Market Resources subsidiary that conducts natural gas and oil exploration, development and production, reported net income of $66.0 million in the third quarter, up 47% from $44.8 million in the 2005 quarter. Net income for the first nine months of 2006 was $192.6 million versus $115.4 million for the same period of 2005, a 67% 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 reported production volumes increased to 33.8 Bcfe in the third quarter of 2006, a 16% increase compared to the year-earlier period. Production for the first nine months of 2006 was 97.4 Bcfe versus 82.5 Bcfe for the 2005 period, an 18% increase. On an energy-equivalent basis, natural gas comprised approximately 87% of Questar E&P production for the third quarter of 2006. A comparison of natural gas-equivalent production by region is shown in the following table:
3 Months Ended | 9 Months Ended | ||||||||
September 30, | % | September 30, | % | ||||||
2006 | 2005 | Change | 2006* | 2005 | Change | ||||
(Bcfe) | (Bcfe) | ||||||||
Pinedale Anticline | 10.9 | 8.7 | 25% | 28.8 | 22.8 | 26% | |||
Uinta Basin | 6.5 | 6.6 | (2) | 18.9 | 19.2 | (2) | |||
Rockies Legacy | 4.5 | 4.3 | 5 | 14.5 | 12.3 | 18 | |||
Subtotal – Rocky Mountains | 21.9 | 19.6 | 12 | 62.2 | 54.3 | 15 | |||
Midcontinent | 11.9 | 9.6 | 24 | 35.2 | 28.2 | 25 | |||
Total Questar E&P | 33.8 | 29.2 | 16% | 97.4 | 82.5 | 18% | |||
*Includes 0.7 Bcfe related to settlement of an imbalance in Rockies Legacy. Without the one-time adjustment, total Questar E&P production grew 17%.
Questar E&P production from the Pinedale Anticline in western Wyoming grew 26% to 28.8 Bcfe in the first nine months of 2006 and comprised 30% of Questar E&P total production in the 2006 period. Production at Pinedale declines early in the year due to mid-November to early May seasonal access restrictions imposed by the Bureau of Land Management that restrict the company’s ability to drill and complete wells during the period. Production at Pinedale was 8.2 Bcfe in the second quarter of 2006 and 9.7 Bcfe in the first quarter of 2006.
In the Uinta Basin of eastern Utah, Questar E&P production decreased 2% to 18.9 Bcfe in the first nine months of 2006 compared to a year ago. Third quarter production of 6.5 Bcfe was up slightly compared to the 6.2 Bcfe recorded in both the second and first quarters of 2006.
Production from Questar E&P Rocky Mountain “Legacy” properties increased 18% to 14.5 Bcfe in the first nine months of 2006 compared to a year ago. Excluding a one-time adjustment, Legacy production for the first nine months of 2006 was 13.8 Bcfe, an increase of 12% over the 2005 period driven by the company’s emerging gas play in the Vermillion Basin. Legacy assets include all Questar E&P Rocky Mountain region properties except the Pinedale Anticline and the Uinta Basin.
In the Midcontinent, production grew 25% to 35.2 Bcfe in the first nine months of 2006, driven by ongoing infill-development drilling in the Elm Grove field in northwestern Louisiana. Questar E&P midcontinent production also benefited from the December 2005 completion of an exploratory well in the Arkoma Basin of eastern Oklahoma. The well has produced 1.7 Bcfe and has averaged 5.4 MMcfe per day since
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coming on line. Questar E&P has a 96.2% working interest and an 84.2% net revenue interest in the well before payout of a 200% nonconsent penalty and a 69.5% working interest and a 60.8% net revenue interest after payout.
Questar E&P also benefited from higher realized prices for natural gas, oil and NGL. For the first nine months of 2006, the weighted average realized natural gas price for Questar E&P (including the impact of hedging) was $5.99 per Mcf compared to $4.91 per Mcf for the same period in 2005, a 22% increase. Realized oil and NGL prices for the first nine months of 2006 averaged $50.10 per bbl, compared with $40.61 per bbl during the prior year period, a 23% increase. A regional comparison of average realized prices, including hedges, is shown in the following table:
3 Months Ended | 9 Months Ended | |||||
September 30, | % | September 30, | % | |||
2006 | 2005 | Change | 2006 | 2005 | Change | |
Natural gas (per Mcf) | ||||||
Rocky Mountains | $ 5.38 | $ 4.94 | 9% | $ 5.68 | $ 4.73 | 20% |
Midcontinent | 6.36 | 5.47 | 16 | 6.54 | 5.23 | 25 |
Volume-weighted average | $ 5.73 | $ 5.12 | 12% | $ 5.99 | $ 4.91 | 22% |
Oil and NGL (per bbl) | ||||||
Rocky Mountains | $46.59 | $44.13 | 6% | $47.88 | $41.38 | 16% |
Midcontinent | 57.68 | 40.34 | 43 | 55.28 | 38.84 | 42 |
Volume-weighted average | $49.81 | $43.04 | 16% | $50.10 | $40.61 | 23% |
Approximately 69% and 68% of Questar E&P gas production in the third quarter and nine months of 2006, respectively, was hedged or pre-sold. Hedging increased gas revenues $18.3 million and $21.0 million during the third quarter and first nine months of 2006, respectively. Approximately 76% and 78% of Questar E&P oil production in the third quarter and nine months of 2006, respectively, was hedged or pre-sold. Oil hedges reduced revenues $6.7 million and $17.1 million during the third quarter and first nine months of 2006, respectively.
Market Resources may hedge up to 100 percent of forecasted production from proved reserves to lock in acceptable returns on invested capital and to protect returns, cash flow and net income from a decline in commodity prices. During the third quarter of 2006, Questar E&P continued to take advantage of high natural gas and oil prices to hedge additional production through 2008. The Company uses basis-only swaps to protect cash flows and net income from widening natural gas-price basis differentials that may result from capacity constraints on regional gas pipelines. Derivative positions as of September 30, 2006, are summarized in Part I, Item 3 of this quarterly report.
Questar E&P production costs (the sum of depreciation, depletion and amortization expense, lease operating expense, general and administrative expense, allocated-interest expense and production taxes) per Mcfe of production increased 5% to $2.97 per Mcfe compared to the third quarter of 2005. For the first nine months of 2006, production costs rose 5% to $2.90 per Mcfe. Questar E&P production costs are summarized in the following table:
3 Months Ended | 9 Months Ended | |||||
September 30, | % | September 30, | % | |||
2006 | 2005 | Change | 2006 | 2005 | Change | |
(Per Mcfe) | (Per Mcfe) | |||||
Depreciation, depletion and amortization | $1.43 | $1.19 | 20% | $1.37 | $1.17 | 17% |
Lease operating expense | 0.56 | 0.52 | 8 | 0.55 | 0.55 | |
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General and administrative expense | 0.34 | 0.29 | 17 | 0.32 | 0.31 | 3 |
Allocated interest expense | 0.19 | 0.21 | (10) | 0.21 | 0.21 | |
Production taxes | 0.45 | 0.61 | (26) | 0.45 | 0.53 | (15) |
Total production costs | $2.97 | $2.82 | 5% | $2.90 | $2.77 | 5% |
Depreciation, depletion and amortization expense rose due to higher costs for drilling, completion and related services, increased cost of steel casing, other tubulars and wellhead equipment, and the ongoing depletion of older, lower-cost reserves. Per unit lease operating expense increased due to increased costs of materials and consumables and higher well workover costs. General and administrative expenses increased due to higher labor costs and an increase in the allowance for doubtful accounts. Interest expense per unit decreased in the 2006 quarter due to refinancing of long-term debt at a lower interest rate and higher production volumes. Production taxes per unit decreased with lower sales prices on natural gas, increased incentive tax credits related to well drilling and production enhancement projects, and adjustments to prior estimates.
Questar E&P’s exploration expense increased $14.3 million in the third quarter 2006 and $21.2 million in the first nine months compared to the 2005 periods. The increases were due to expenses for unsuccessful exploratory wells in Wyoming and Utah. Abandonment and impairment expense increased $0.2 million for the third quarter 2006 and $0.9 million for the first nine months of 2006.
Pinedale Anticline
As of September 30, 2006, Market Resources (both Questar E&P and Wexpro) operated and had working interest in 178 producing wells on the Pinedale Anticline compared to 127 at the end of the third quarter of 2005. Of the 178 producing wells, Questar E&P has working interests in 158 wells, overriding royalty interests only in an additional 19 Wexpro-operated wells, and no interest in one well operated by Wexpro. Wexpro has working interests in 57 of the 178 producing wells. Market Resources expects to complete between 48 and 51 Lance Pool wells (combined Lance and Mesaverde formations) on its Pinedale acreage during 2006.
In 2005, the Wyoming Oil and Gas Conservation Commission approved 10-acre-density drilling for Lance Pool wells on about 12,700 acres of Market Resources 18,208 acre (gross) Pinedale leasehold. The area approved for increased density corresponds to the currently estimated productive limits of Market Resources core acreage in the field. With 10-acre-density drilling, the company currently believes that up to 932 wells will be required to fully develop the Lance Pool on its acreage.
Uinta Basin
During the first nine months of 2006, the company drilled or participated in 39 Wasatch and Upper Mesaverde gas wells, three horizontal and two vertical Green River Formation oil wells, and three deeper Blackhawk, Mancos and Dakota formations gas wells on its core acreage block.
Rockies Legacy
In the Vermillion Basin on the southwest Wyoming-northwest Colorado border, Market Resources continues to evaluate the potential of several formations under the company’s 146,000 net leasehold acres. As of September 30, 2006, the company had recompleted two older wells, drilled and completed 10 new wells, and two were waiting on completion. The targets are the Baxter Shale, which extends across a 3,000-3,500 foot gross interval from about 9,500 feet deep to about 13,000 feet deep on most of the company’s leasehold in the basin, and the deeper Frontier and Dakota tight-sand formations at depths down to 14,000 feet.
Midcontinent
During the third quarter the company continued a two-rig infill-development project in the Elm Grove field in northwest Louisiana as it drilled or participated in 12 new wells. On March 31, 2006, Questar E&P acquired interests in 48 producing wells in nine spacing units in the Elm Grove field. The acquisition provides Questar E&P initial or additional working interest in approximately 75 undrilled locations.
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Wexpro
Wexpro, a Market Resources subsidiary that develops and produces cost-of-service reserves for Questar Gas, reported net income was $12.1 million, in the third quarter of 2006 compared with $11.3 million for the same period in 2005, a 7% increase. For the first nine months of 2006 Wexpro net income was $36.1 million, compared with $31.9 million for the same period in 2005, a 13% increase. Pursuant to the Wexpro Agreement, Wexpro recovers its costs and receives an unlevered after-tax return of approximately 19% to 20% on its investment in commercial wells and related facilities – adjusted for working capital and reduced for deferred income taxes and depreciation (investment base). Wexpro investment base at September 30, 2006, was $224.8 million, an increase of $27.2 million or 14%.
Gas Management
Gas Management, Market Resources gas-gathering and processing-services business, grew net income 51% to $11.0 million in the third quarter of 2006 from $7.3 million in the 2005 period. Net income for the first nine months of 2006 was $30.9 million versus $25.1 million for the same period in 2005, a 23% increase. Gas processing plant margin grew 79% from $16.9 million in the first nine months of 2005 to $30.3 million in the first nine months of 2006. Gathering volumes increased 13.2 million MMBtu to 195.8 million MMBtu in the first nine months of 2006 due primarily to expanding Pinedale production and new projects serving third parties in the Uinta Basin. Total gathering margins increased 5% despite increased start-up costs associated with the Pinedale liquids-gathering and transportation facilities.
To reduce processing margin risk, Gas Management has restructured a number of its processing agreements with producers from “keep-whole” contracts to “fee-based” contracts. A keep-whole contract protects producers from frac spread risk while fee-based contracts eliminate commodity-price risk for the plant owner. In the first nine months of 2006, revenues from keep-whole contracts benefited from a 24% increase in realized NGL sales prices versus the prior-year period. Revenues from fee-based contracts were impacted by a 100% increase in processing volumes offset by a $0.03 decrease in the average rate charged per MMBtu processed in the first nine months comparable periods. To further reduce margin volatility associated with keep-whole contracts, Gas Management began managing NGL price risk in 2004 by using forward-sales contracts. Forward sales contracts decreased NGL revenues by $0.8 mil lion in 2006.
Income before income tax from Gas Management’s 50% interest in Rendezvous Gas Services, LLC, (Rendezvous), a joint venture that operates gas-gathering facilities in western Wyoming, was $5.0 million for the first nine months of 2006, the same as the year earlier period. Rendezvous provides gas gathering services for the Pinedale and Jonah producing areas. Gas Management continues to invest in additional gas gathering and processing and liquids-handling facilities to serve growing equity and third-party production in its core areas of the Pinedale and Jonah fields in western Wyoming and the Uinta Basin in eastern Utah.
Energy Trading and Other
Energy Trading, a Market Resources subsidiary that sells Market Resources equity gas and oil, provides risk-management services and operates a natural-gas storage facility, reported net income for the third quarter of 2006 of $2.9 million compared to $1.9 million in 2005, a 53% increase. For the first nine months of 2006, net income was $6.4 million compared to $4.3 million for the same period in 2005, a 49% increase. Service fee revenues from affiliates were $0.1 million lower in the third quarter of 2006 and $0.8 million higher in the first nine months of 2006 relative to the 2005 periods. Gross margins for gas and oil marketing (gross revenues less costs for gas and oil purchases, transportation and gas storage), increased to $10.8 million for the first nine months of 2006 versus $9.8 million a year ago, a 10% increase. The increase in gross margin was due primarily to a 3% increase in volumes and increa sed storage activity over the same period last year.
Consolidated Results after Operating Income
Net gain on asset sales
During the third quarter Market Resources subsidiaries sold properties, primarily in western Colorado, and recognized pre-tax gains totaling $25.3 million. For the nine months ended September 30, 2006, pre-tax gains on asset sales totaled $25.6 million.
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Income from unconsolidated affiliates
Gas Management has a 50% interest in Rendezvous that provides gas-gathering services for the Pinedale and Jonah producing areas of western Wyoming. Gas Management’s share of Rendezvous’ earnings before income tax decreased by $0.2 million in the third quarter of 2006 and was unchanged in the first nine months of 2006 compared with the 2005 periods. Rendezvous gathering volumes decreased 2% in the third quarter of 2006 and increased 2% in the first nine months of 2006 compared to the year earlier periods.
Interest expense and loss on early extinguishment of debt
Interest expense rose in the first nine months of 2006 due primarily to increased average debt levels between the two nine month periods and higher interest rates on short-term debt outstanding in the early part of 2006. Market Resources recognized a $1.7 million pre-tax loss on the early extinguishment of its 7% Notes due 2007.
Unrealized mark-to-market loss on basis swaps
The Company uses basis-only swaps to protect cash flows and net income from widening natural gas-price basis differentials that may result from capacity constraints on regional gas pipelines. The Company recorded unrealized mark-to-market losses of $5.1 million and $10.8 million on the NYMEX/Rockies basis swaps in the third quarter and nine months of 2006, respectively.
Income taxes
The effective combined federal and state income tax rate was 36.9% in the first nine months of 2006 and 2005.
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, 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-derivative arrangements in the normal course of business to limit the risk of adverse price movements. However these same arrangements typically limit future gains from favorable price movements. Derivative contracts are used for a significant share of Questar E&P-owned gas and oil production, a portion of Energy Trading gas- and oil-marketing transactions and some of Gas Management’s NGL.
Market Resources has established policies and procedures for managing commodity-price risks through the use of derivatives. Natural gas- and oil-price hedging supports the Company’s 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 Company’s Board of Directors. Market Resources may hedge up to 100% of forecast production from proved reserves when prices meet earnings and cash flow objectives. Market Resources does not enter into derivative arrangements for speculative purposes and does not hedge undeveloped reserves or equity NGL.
Market Resources uses fixed-price swaps to manage natural gas, oil and NGL price risk. A fixed-price swap is a derivative instrument that exchanges or “swaps” the “floating” or daily price of a specified volume of natural gas, oil or NGL, over a specified period, for a fixed price for the specified volume over the same period. In the normal course of business, the Company sells its equity natural gas, oil and NGL production to third parties at first-of-the-month or daily “floating” prices related to indices reported in industry publications. To reduce exposure to highly volatile daily and monthly commodity prices, the Company uses a derivative
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instrument that exchanges or “swaps” the “floating” or daily price of the commodity for a fixed-price for the specified period (typically for periods of three months or longer). The Company enters into these transactions with banks and industry counterparties with investment-grade credit ratings. Swap agreements do not require the physical transfer of gas between the parties at settlement. Swap transactions are settled monthly, in cash, with one party paying the other for the net difference in prices, multiplied by the relevant volume, for the settlement period.
Generally derivative instruments are matched to equity gas and oil production, thus qualifying as cash flow hedges under the accounting provisions of SFAS 133 as amended and interpreted. Changes in the fair value of cash-flow hedges are recorded on the balance sheet and in other comprehensive income or loss until the underlying gas or oil is produced. Gas hedges are typically structured as fixed-price swaps into regional pipelines, locking in basis and hedge effectiveness. The ineffective portion of cash flow hedges is immediately recognized in the determination of net income.
Market Resources has also entered into natural gas basis-only swaps in the second quarter of 2006 to manage the risk of a widening of basis differentials in the Rocky Mountains. These contracts are marked-to-market with any change in the valuation recognized in the determination of net income.
Market Resources enters into commodity price derivative arrangements with several banks and energy-trading firms with a variety of credit requirements. Some contracts do not require collateral deposits, while others allow some amount of credit before Market Resources is required to deposit collateral for out-of-the-money contracts. The amount of credit available may vary depending on the credit rating assigned to Market Resources debt. In addition to the counterparty arrangements, Market Resources has a $182 million long-term revolving-credit facility with banks with no borrowings outstanding at September 30, 2006.
A summary of Market Resources derivative positions for equity production as of September 30, 2006, is shown below. Currently fixed-price and basis-only swaps are with creditworthy counterparties. Fixed-price swaps, allow Market Resources to realize a known price for a specific volume of production delivered into a regional sales point. The fixed price swap price is then reduced by gathering costs and adjusted for product quality to determine the net-to-the-well price:
Rocky | Rocky | |||||||
Time Periods | Mountains | Midcontinent | Total |
| Mountains | Midcontinent | Total | |
Estimated | ||||||||
Gas (in Bcf) Fixed-Price Swaps | Average price per Mcf, net to the well | |||||||
2006 | ||||||||
Fourth Quarter | 15.6 | 6.1 | 21.7 | $6.04 | $6.81 | $6.26 | ||
2007 | ||||||||
First half | 21.5 | 15.4 | 36.9 | $6.93 | $7.81 | $7.30 | ||
Second half | 21.8 | 15.6 | 37.4 | 6.93 | 7.81 | 7.30 | ||
12 months | 43.3 | 31.0 | 74.3 | 6.93 | 7.81 | 7.30 | ||
2008 | ||||||||
First half | 16.9 | 12.2 | 29.1 | $7.19 | $7.98 | $7.52 | ||
Second half | 17.9 | 12.3 | 30.2 | 7.16 | 7.98 | 7.49 | ||
12 months | 34.8 | 24.5 | 59.3 | 7.18 | 7.98 | 7.51 | ||
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2009 | ||||||||
First half | 6.7 | 5.2 | 11.9 | $7.01 | $7.68 | $7.30 | ||
Second half | 6.8 | 5.3 | 12.1 | 7.01 | 7.68 | 7.30 | ||
12 months | 13.5 | 10.5 | 24.0 | 7.01 | 7.68 | 7.30 | ||
Gas (in Bcf) Basis-Only Swaps | Estimated Average basis per Mcf vs. NYMEX | |||||||
2006 | ||||||||
Fourth quarter | 2.6 | 2.6 | $2.13 | $2.13 | ||||
2007 | ||||||||
First half | 8.4 | 8.4 | $1.92 | $1.92 | ||||
Second half | 8.6 |
| 8.6 | 1.92 | 1.92 | |||
12 months | 17.0 | 17.0 | 1.92 | 1.92 | ||||
2008 | ||||||||
First half | 13.6 | 13.6 | $1.60 | $1.60 | ||||
Second half | 13.7 |
| 13.7 | 1.60 | 1.60 | |||
12 months | 27.3 | 27.3 | 1.60 | 1.60 | ||||
2009 | ||||||||
First half | 1.7 | 1.7 | $0.95 | $0.95 | ||||
Second half | 1.7 |
| 1.7 | 0.95 | 0.95 | |||
12 months | 3.4 | 3.4 | 0.95 | 0.95 | ||||
Oil (in Mbbl) Fixed-Price Swaps | Average price per bbl, net to the well | |||||||
2006 | ||||||||
Fourth quarter | 313 | 101 | 414 | $47.77 | $59.89 | $50.73 | ||
2007 | ||||||||
First half | 525 | 199 | 724 | $56.85 | $57.83 | $57.12 | ||
Second half | 534 | 202 | 736 | 56.85 | 57.83 | 57.12 | ||
12 months | 1,059 | 401 | 1,460 | 56.85 | 57.83 | 57.12 | ||
2008 | ||||||||
First half | 109 | 73 | 182 | $64.23 | $65.30 | $64.66 | ||
Second half | 111 | 73 | 184 | 64.23 | 65.30 | 64.66 | ||
12 months | 220 | 146 | 366 | 64.23 | 65.30 | 64.66 | ||
As of September 30, 2006, Market Resources held commodity-price hedging contracts covering about $207.0 million MMBtu of natural gas, 2.2 MMbbl of oil and 31.5 million gallons of NGL. A year earlier Market Resources hedging contracts covered 182.3 million MMBtu of natural gas, 2.6 MMbbl of oil and 14.1 million
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gallons of NGL. Market Resources has also entered into basis-only swaps on an additional 50.3 million MMBtu of natural gas. There were no basis-only swaps a year earlier.
The following table summarizes changes in the fair value of derivative contracts from December 31, 2005 to September 30, 2006:
Fixed-Price Swaps | Basis-Only Swaps | Total | |
| (in thousands) | ||
Net fair value of gas- and oil-derivative contracts outstanding at December 31, 2005 | ($319,121) | ($319,121) | |
Contracts realized or otherwise settled | 157,170 | 157,170 | |
Change in gas and oil prices on futures markets | 229,486 | 229,486 | |
Contracts added since December 31, 2005 | 93,155 | ($10,564) | 82,591 |
Net fair value of gas- and oil-derivative contracts outstanding at September 30, 2006 | $160,690 | ($10,564) | $150,126 |
A table of the net fair value of gas- and oil-derivative contracts as of September 30, 2006, is shown below. About 65% of the fair value of all contracts will settle in the next twelve months and the fair value of cash-flow hedges will be reclassified from other comprehensive income:
Fixed-Price Swaps | Basis-Only Swaps | Total | |
| (in thousands) | ||
Contracts maturing by September 30, 2007 | $103,047 | ($ 4,735) | 98,312 |
Contracts maturing between October 1, 2007 and September 30, 2008 | 41,517 | (3,999) | 37,518 |
Contracts maturing between October 1, 2008 and September 30, 2009 | 15,000 | (1,686) | 13,314 |
Contracts maturing after September 30, 2009 | 1,126 | (144) | 982 |
$160,690 | ($10,564) | $150,126 | |
The following table shows sensitivity of fair value of gas and oil derivative contracts and basis-only swaps to changes in the market price of gas and oil and basis differentials:
At September 30, | ||
2006 | 2005 | |
(in millions) | ||
|
| |
Net fair value – asset (liability) | $150.1 | ($568.1) |
Value if market prices of gas and oil and basis differentials decline by 10% | 291.3 | (403.6) |
Value if market prices of gas and oil and basis differentials increase by 10% | 9.0 | ($732.6) |
Interest-Rate Risk Management
As of September 30, 2006, Market Resources had $399.2 million of fixed-rate long-term debt.
Forward-Looking Statements
This Quarterly Report may contain or incorporate by reference information that includes or is based upon “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements
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give expectations or forecasts of future events. You can identify these statements by the fact that they do not relate strictly to historical or current facts. They use words such as “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe,” and other words and terms of similar meaning in connection with a discussion of future operating or financial performance. In particular, these include statements relating to future actions, prospective services or products, future performance or results of current and anticipated services or products, exploration efforts, expenses, the outcome of contingencies such as legal proceedings, trends in operations and financial results.
Any or all forward-looking statements may turn out to be wrong. They can be affected by inaccurate assumptions or by known or unknown risks and uncertainties. Many such factors will be important in determining actual future results. These statements are based on current expectations and the current economic environment. They involve a number of risks and uncertainties that are difficult to predict. These statements are not guarantees of future performance. Actual results could differ materially from those expressed or implied in the forward-looking statements. Among factors that could cause actual results to differ materially are:
•
the risk factors discussed in Part I, Item 1A. of the Company’s Annual Report on Form 10-K for the year ended December 31, 2005;
•
general economic conditions, including the performance of financial markets and interest rates;
•
changes in industry trends;
•
changes in laws or regulations; and
•
other factors, most of which are beyond our control.
Market Resources undertakes no obligation to publicly correct or update the forward-looking statements in this Quarterly Report, in other documents, or on the website to reflect future events or circumstances. All such statements are expressly qualified by this cautionary statement.
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 Financial Officer also concluded that the controls and procedures were effective in ensuring that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is accumulated and communicated to the Company’s management including its principal executive and financial officers or persons performing similar functions as appropriate to allow timely decisions regarding required disclosure.
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.
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PART II. OTHER INFORMATION
Item 1. Legal Proceedings.
Market Resources is involved in various commercial and regulatory claims and litigation and other legal proceedings that arise in the ordinary course of its business. Management does not believe any of them will have a material adverse effect on Market Resources financial position. An accrual is recorded for a loss contingency when its occurrence is probable and damages can be reasonably estimated based on the anticipated most likely outcome. Some of the claims involve highly complex issues relating to liability, damages and other matters subject to substantial uncertainties and, therefore, the probability of liability or an estimate of loss cannot be reasonably determined.
Grynberg. Questar affiliates are involved in various pending lawsuits filed by Jack Grynberg, an independent producer. In United States ex rel. Grynberg v. Questar Corp., Civil No. 99-MD-1604, consolidated as In re Natural Gas Royalties Qui Tam Litigation, Consolidated Case MDL No. 1293 (D. Wyo.), Grynberg has filed qui tam claims against Questar under the federal False Claims Act substantially similar to other cases filed against other industry pipelines and their affiliates which have been consolidated for discovery and pre-trial motions in Wyoming’s federal district court. The cases involve allegations of industry-wide mismeasurement of natural gas quantities on which royalty payments are due the federal government.
The defendants filed a motion contending that the court has no jurisdiction over the case because Grynberg cannot satisfy the statutory requirements for jurisdiction. The defendants argued that Grynberg’s allegations were publicly disclosed prior to the filing of his complaint and that Grynberg is not the “original source” of the information on which the allegations are based. The Special Master appointed in the case issued a Report and Recommendation to the district court recommending dismissal of the Questar defendants, except for one small entity acquired by Questar Gas after these cases were filed. By order dated October 20, 2006, the district court granted defendants motion and dismissed all of Grynberg’s claims against all the defendants for lack of jurisdiction. The judge found that Grynberg was not the “original source” and therefore could not bring the action. Grynberg will likely file a notice of appeal.
In Grynberg and L & R Exploration Venture v. Questar Pipeline Co., Civil No. 97CV0471 (D. Wyo.) Grynberg brought breach of contract claims, statutory claims and fraud claims against Questar entities related to a certain gas purchase contract for the purchase of gas produced from wells located in Wyoming. In June 2001 the federal district judge entered an order granting partial summary judgment dismissing the antitrust claims from the case. By order dated September 12, 2006, the judge also dismissed the fraud claims and ratable-take claims. The breach of contract claims are the only issues remaining to be decided. Grynberg filed a notice of appeal on October 11, 2006.
Item 6. Exhibits
The following exhibits are being filed as part of this report:
Exhibit No.
Exhibits
12.
Ratio of earnings to fixed charges.
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.
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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.
*Exhibits so marked have been filed with the Securities and Exchange Commission as part of the referenced filing and are incorporated herein by reference.
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)
November 3, 2006
/s/Charles B. Stanley
Charles B. Stanley
President and Chief Executive Officer
November 3, 2006
/s/S. E. Parks
S. E. Parks
Vice President and Chief Financial Officer
Exhibits List
Exhibits
12.
Ratio of earnings to fixed charges.
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.
*Exhibits so marked have been filed with the Securities and Exchange Commission as part of the referenced filing and are incorporated herein by reference.
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Exhibit 12.
Questar Market Resources, Inc.
Ratio of Earnings to Fixed Charges
(Unaudited)
9 Months Ended September 30, | ||
2006 | 2005 | |
(dollars in thousands) | ||
Earnings | ||
Income before income taxes | $421,489 | $279,930 |
Less Company’s share of income of | ||
unconsolidated affiliates | (5,333) | (5,131) |
Plus distributed income of unconsolidated | ||
affiliates | 4,902 | 4,342 |
Plus interest expense | 25,394 | 22,356 |
Plus interest portion of rental expense | 906 | 834 |
$447,358 | $302,331 | |
Fixed Charges | ||
Interest expense | $ 25,394 | 22,356 |
Plus interest portion of rental expense | 906 | 834 |
$ 26,300 | $ 23,190 | |
Ratio of Earnings to Fixed Charges | 17.01 | 13.04 |
For purposes of this presentation, earnings represent income before income taxes adjusted for fixed charges, earnings and distributed income of equity investees and the amortization of capitalized interest, if any. Fixed charges consist of total interest charges (expensed or capitalized), amortization of debt issuance costs and the interest portion of rental costs (that is estimated at 50%). Income before income taxes includes the Company’s share of pre-tax earnings of equity investees.
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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 September 30, 2006;
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this 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)) 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)
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
c)
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.
November 3, 2006
/s/Charles B. Stanley
Charles B. Stanley
President and Chief Executive Officer
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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 September 30, 2006;
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this 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)) 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)
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
c)
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.
November 3, 2006
/s/S. E. Parks
S. E. Parks
Vice President and Chief Financial Officer
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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 September 30, 2006, 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.
November 3, 2006
/s/Charles B. Stanley
Charles B. Stanley
President and Chief Executive Officer
November 3, 2006
/s/S. E. Parks
S. E. Parks
Vice President and Chief Financial Officer
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