UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
ý | | QUARTERLY REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended September 30, 2001
OR
o | | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission File Number 1-11566
MARKWEST HYDROCARBON, INC.
(Exact name of registrant as specified in its charter)
Delaware | | 84-1352233 |
(State or other jurisdiction of incorporation or organization) | | (IRS Employer Identification No.) |
|
155 Inverness Drive West, Suite 200, Englewood, CO 80112-5000 |
(Address of principal executive offices) |
|
Registrant’s telephone number, including area code: 303-290-8700 |
| | |
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.
Yesý Noo
The registrant had 8,486,724 shares of common stock, $.01 per share par value, outstanding as of September 30, 2001.
Glossary of Terms |
| | |
Bbls | | barrels |
Bcf | | billion cubic feet of natural gas |
Btu | | British thermal units, an energy measurement |
EBITDA | | earnings before gain on sale, interest income, interest expense, income taxes, depreciation, depletion and amortization; a cash flow financial measure commonly used in the oil and gas industry |
MM | | million |
Mcf | | thousand cubic feet of natural gas |
Mcfd | | thousand cubic feet of natural gas per day |
Mcfe | | thousand cubic feet of natural gas equivalent |
Mcfed | | thousand cubic feet of natural gas equivalent per day |
MMBtu | | million British thermal units, an energy measurement |
MMcf | | million cubic feet of natural gas |
MMcfd | | million cubic feet of natural gas per day |
NGL | | natural gas liquids, such as propane, butanes and natural gasoline |
| | |
One barrel of oil or NGL is the energy equivalent of six Mcf of natural gas. |
Item 1. Consolidated Financial Statements
MARKWEST HYDROCARBON, INC.
CONSOLIDATED BALANCE SHEET
(UNAUDITED)
(000s, except share data)
| | September 30, | | December 31, | |
ASSETS | | 2001 | | 2000 | |
Current assets: | | | | | |
Cash and cash equivalents | | $ | 2,437 | | $ | 934 | |
Receivables | | 15,931 | | 36,695 | |
Inventories | | 7,322 | | 8,058 | |
Prepaid feedstock | | 7,276 | | — | |
Risk management asset | | 6,506 | | — | |
Other assets | | 1,247 | | 913 | |
Total current assets | | 40,719 | | 46,600 | |
| | | | | |
Property and equipment: | | | | | |
Gas processing, gathering, storage and marketing equipment | | 105,614 | | 97,311 | |
Oil and gas properties and equipment | | 108,652 | | 18,037 | |
Land, buildings and other equipment | | 6,546 | | 6,463 | |
Construction in progress | | 8,011 | | 6,241 | |
| | 228,823 | | 128,052 | |
Less: accumulated depreciation, depletion and amortization | | (34,117 | ) | (27,833 | ) |
Total property and equipment, net | | 194,706 | | 100,219 | |
| | | | | |
Risk management asset | | 1,875 | | — | |
Intangible assets, net of accumulated amortization of $119 and $708, respectively | | 2,828 | | 468 | |
| | | | | |
Total assets | | $ | 240,128 | | $ | 147,287 | |
| | | | | |
LIABILITIES AND STOCKHOLDERS’ EQUITY | | | | | |
Current liabilities: | | | | | |
Accounts payable | | $ | 19,307 | | $ | 17,713 | |
Accrued liabilities | | 7,669 | | 13,740 | |
Risk management liability | | 2,621 | | — | |
Total current liabilities | | 29,597 | | 31,453 | |
| | | | | |
Deferred income taxes | | 43,832 | | 11,240 | |
Long-term debt | | 101,000 | | 43,000 | |
Risk management liability | | 400 | | — | |
Commitments and contingencies (see Note 6) | | — | | — | |
| | | | | |
Stockholders’ equity: | | | | | |
Preferred stock, par value $0.01, 5,000,000 shares authorized, 0 shares outstanding | | — | | — | |
Common stock, par value $0.01, 20,000,000 shares authorized, 8,563,919 and 8,561,206 shares issued, respectively | | 87 | | 86 | |
Additional paid-in capital | | 42,549 | | 42,471 | |
Retained earnings | | 20,942 | | 19,679 | |
Accumulated other comprehensive income | | 2,197 | | — | |
Treasury stock, 77,195 and 104,093 shares, respectively | | (476 | ) | (642 | ) |
Total stockholders’ equity | | 65,299 | | 61,594 | |
| | | | | |
Total liabilities and stockholders’ equity | | $ | 240,128 | | $ | 147,287 | |
The accompanying notes are an integral part of these financial statements.
CONSOLIDATED STATEMENT OF OPERATIONS
(UNAUDITED)
(000s, except per share data)
| | For the three months ended | | For the nine months ended | |
| | September 30, | | September 30, | |
| | 2001 | | 2000 | | 2001 | | 2000 | |
Revenue: | | | | | | | | | |
Gathering, processing and marketing | | $ | 28,309 | | $ | 55,845 | | $ | 142,368 | | $ | 139,329 | |
Exploration and production | | 4,084 | | 1,461 | | 9,120 | | 3,279 | |
Total revenue | | 32,393 | | 57,306 | | 151,488 | | 142,608 | |
| | | | | | | | | |
Operating expenses: | | | | | | | | | |
Cost of sales | | 21,921 | | 46,351 | | 120,596 | | 109,643 | |
Operating expenses | | 4,946 | | 4,354 | | 13,943 | | 12,244 | |
General and administrative expenses | | 1,906 | | 2,173 | | 6,189 | | 6,031 | |
Depreciation, depletion and amortization | | 3,295 | | 1,427 | | 6,700 | | 4,323 | |
Total operating expenses | | 32,068 | | 54,305 | | 147,428 | | 132,241 | |
| | | | | | | | | |
Income from operations | | 325 | | 3,001 | | 4,060 | | 10,367 | |
| | | | | | | | | |
Other income and expense: | | | | | | | | | |
Interest income | | 32 | | 24 | | 114 | | 77 | |
Interest expense | | (974 | ) | (820 | ) | (2,234 | ) | (2,222 | ) |
Gain on sale of assets | | — | | — | | — | | 1,000 | |
Other income (expense) | | (4 | ) | (81 | ) | (253 | ) | 22 | |
| | | | | | | | | |
Income (loss) before income taxes | | (621 | ) | 2,124 | | 1,687 | | 9,244 | |
| | | | | | | | | |
Provision (benefit) for income taxes: | | | | | | | | | |
Current | | (120 | ) | 439 | | 348 | | 1,957 | |
Deferred | | (307 | ) | 360 | | 76 | | 1,601 | |
Provision for income taxes | | (427 | ) | 799 | | 424 | | 3,558 | |
| | | | | | | | | |
Net income (loss) | | $ | (194 | ) | $ | 1,325 | | $ | 1,263 | | $ | 5,686 | |
| | | | | | | | | |
Basic earnings (loss) per share of common stock | | $ | (0.02 | ) | $ | 0.16 | | $ | 0.15 | | $ | 0.67 | |
Earnings (loss) per share assuming dilution | | $ | (0.02 | ) | $ | 0.16 | | $ | 0.15 | | $ | 0.67 | |
| | | | | | | | | |
Weighted average number of outstanding shares of common stock: | | | | | | | | | |
Basic | | 8,479 | | 8,450 | | 8,473 | | 8,451 | |
Assuming dilution | | 8,501 | | 8,489 | | 8,500 | | 8,475 | |
The accompanying notes are an integral part of these financial statements.
CONSOLIDATED STATEMENT OF CASH FLOWS
(UNAUDITED)
(000s)
| | For the three months | | For the nine months | |
| | ended September 30, | | ended September 30, | |
| | 2001 | | 2000 | | 2001 | | 2000 | |
Cash flows from operating activities: | | | | | | | | | |
Net income | | $ | (194 | ) | $ | 1,325 | | $ | 1,263 | | $ | 5,686 | |
Add income items that do not affect working capital: | | | | | | | | | |
Depreciation, depletion and amortization | | 3,295 | | 1,427 | | 6,700 | | 4,323 | |
Deferred income taxes | | (307 | ) | 360 | | 76 | | 1,601 | |
Gain on sale of assets | | — | | — | | — | | (1,000 | ) |
Other | | (53 | ) | (12 | ) | (49 | ) | (148 | ) |
| | 2,741 | | 3,100 | | 7,990 | | 10,462 | |
| | | | | | | | | |
Adjustments to working capital: | | | | | | | | | |
(Increase) decrease in receivables | | 2,145 | | (5,563 | ) | 22,880 | | (5,624 | ) |
(Increase) decrease in inventories | | (2,074 | ) | (5,058 | ) | 736 | | (5,776 | ) |
(Increase) decrease in prepaid expenses and other assets | | (7,250 | ) | 486 | | (7,419 | ) | (1,770 | ) |
Increase (decrease) in accounts payable and accrued liabilities | | 2,838 | | 3,437 | | (11,755 | ) | 10,530 | |
| | (4,341 | ) | (6,698 | ) | (4,442 | ) | (2,640 | ) |
| | | | | | | | | |
Net cash flow provided by (used in) operating activities | | (1,600 | ) | (3,598 | ) | 12,432 | | 7,822 | |
| | | | | | | | | |
Cash flows from investing activities: | | | | | | | | | |
Capital expenditures | | (4,151 | ) | (3,139 | ) | (19,907 | ) | (12,427 | ) |
Acquisition of Canadian operations, net of cash acquired | | (46,530 | ) | — | | (46,530 | ) | — | |
Proceeds from sale of assets | | 16 | | 8 | | 36 | | 6,492 | |
| | | | | | | | | |
Net cash used in investing activities | | (50,665 | ) | (3,131 | ) | (66,401 | ) | (5,935 | ) |
| | | | | | | | | |
Cash flows from financing activities: | | | | | | | | | |
Proceeds from long-term debt | | 108,500 | | 20,000 | | 142,000 | | 40,500 | |
Repayment of long-term debt | | (53,500 | ) | (13,000 | ) | (84,000 | ) | (41,639 | ) |
Debt issuance costs | | (2,731 | ) | (73 | ) | (2,731 | ) | (336 | ) |
Exercise of options | | — | | — | | 18 | | — | |
Net reissuance (buy-back) of treasury stock | | 84 | | (2 | ) | 227 | | (54 | ) |
| | | | | | | | | |
Net cash provided by (used in) financing activities | | 52,353 | | 6,925 | | 55,514 | | (1,529 | ) |
| | | | | | | | | |
Effect of exchange rate changes on cash | | (42 | ) | — | | (42 | ) | — | |
| | | | | | | | | |
Net increase in cash and cash equivalents | | 46 | | 196 | | 1,503 | | 358 | |
| | | | | | | | | |
Cash and cash equivalents at beginning of period | | 2,391 | | 1,518 | | 934 | | 1,356 | |
| | | | | | | | | |
Cash and cash equivalents at end of period | | $ | 2,437 | | $ | 1,714 | | $ | 2,437 | | $ | 1,714 | |
The accompanying notes are an integral part of these financial statements.
CONSOLIDATED STATEMENT OF CHANGES IN
STOCKHOLDERS’ EQUITY
(000s)
| | Shares of Common Stock | | Shares of Treasury Stock | | Common Stock | | Additional Paid-In Capital | | Retained Earnings | | Treasury Stock | | Accumulated Other Comprehensive Income | | Total Stockholders’ Equity | |
| | | | | | | | | | | | | | | | | |
Balance, December 31, 2000 | | 8,561 | | (104 | ) | $ | 86 | | $ | 42,471 | | $ | 19,679 | | $ | (642 | ) | $ | 0 | | $ | 61,594 | |
Transition adjustment | | — | | — | | — | | — | | — | | — | | (1,230 | ) | (1,230 | ) |
| | | | | | | | | | | | | | | | | |
Net income | | — | | — | | — | | — | | 1,263 | | — | | — | | 1,263 | |
Risk management activities | | — | | — | | — | | — | | — | | — | | 4,687 | | 4,687 | |
Foreign currency translation adjustments | | — | | — | | — | | — | | — | | — | | (1,260 | ) | (1,260 | ) |
Comprehensive income | | | | | | | | | | | | | | | | | $ | 4,690 | |
| | | | | | | | | | | | | | | | | |
Exercise of options | | 3 | | — | | 1 | | 17 | | — | | — | | — | | 18 | |
Reissuance of treasury stock | | — | | 27 | | — | | 61 | | — | | 166 | | — | | 227 | |
| | | | | | | | | | | | | | | | | |
Balance, September 30, 2001 | | 8,564 | | (77 | ) | $ | 87 | | $ | 42,549 | | $ | 20,942 | | $ | (476 | ) | $ | 2,197 | | $ | 65,299 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
The accompanying notes are an integral part of these financial statements.
NOTE 1. GENERAL
The consolidated financial statements include the accounts of MarkWest Hydrocarbon, Inc. (“MarkWest”), and its wholly owned subsidiaries:
• MarkWest Resources, Inc. | • Matrex, LLC |
• MarkWest Michigan, Inc. | • MarkWest Resources Canada Corp. |
• Basin Pipeline, LLC | • MarkWest Canadian Midstream Services, Inc |
• West Shore Processing Company, LLC | |
Through consolidation, we have eliminated all significant intercompany accounts and transactions.
We have prepared the unaudited financial statements presented herein in accordance with the instructions to Form 10-Q. The statements do not include all the information and note disclosures required by generally accepted accounting principles for complete financial statements. Please read the interim consolidated financial statements in conjunction with the Consolidated Financial Statements and attached notes for the year ended December 31, 2000, included in the Company’s Annual Report on Form 10-K, as filed with the Securities and Exchange Commission. In the opinion of management, we have made all necessary adjustments for a fair statement of the results for the unaudited interim periods. These are only normal recurring adjustments.
We base the effective corporate tax rate for interim periods on the estimated annual effective corporate tax rate, excluding certain nonrecurring or unusual events. The effective tax rate varies from statutory rates primarily due to the tax effect of the Canadian acquisition (discussed in Note 2), tax credits and Canadian resource allowance.
The functional currency of MarkWest is the dollar, except for its Canadian operations that use the Canadian dollar. Assets and liabilities of the Canadian operations are translated at the spot rate in effect at the applicable reporting date, and the income statement accounts are translated at the average exchange rates in effect during the applicable period. The resulting cumulative translation adjustment is recorded as a component of accumulated other comprehensive income.
We have reclassified certain prior-year amounts to conform to the current year’s presentation.
NOTE 2. ACQUISITION
On August 10, 2001, MarkWest acquired for $50 million 100 percent of the voting shares of Leland Energy Canada, Ltd. and Watford Energy, Ltd. (“Leland/Watford”), two privately owned natural gas production companies active in central and southeast Alberta, Canada. The management of these companies has continued with MarkWest. The acquisition included 26 Bcfe of proved reserves (95 percent natural gas), 106,000 net acres, and an inventory of 300 drillable locations. The properties feature low-cost, shallow drilling for multiple pay horizons, with year-round drilling access. MarkWest is supplementing this acquisition with a midstream investment in gathering and compression facilities in the area.
The purchase price was allocated as follows (in thousands):
Acquisition costs: | | | |
Long term debt incurred | | $ | 49,005 | |
Direct acquisition costs | | 1,301 | |
| | 50,306 | |
| | | |
Current liabilities assumed | | 7,413 | |
Deferred income taxes | | 30,634 | |
Total acquisition costs | | $ | 88,353 | |
| | | |
Allocation of acquisition costs: | | | |
Current assets | | $ | 6,171 | |
Oil and gas properties—proved | | 46,886 | |
Undeveloped properties | | 32,610 | |
Other facilities | | 2,686 | |
Total | | $ | 88,353 | |
In addition to the $50 million acquisition cost identified above, we recorded a deferred income tax liability of $31 million to recognize the difference between the historical tax basis of the Leland/Watford assets and the acquisition costs recorded for book purposes. The recorded book value of the oil and gas properties was increased to recognize this tax basis differential.
MarkWest has entered into employment contracts with certain executives from Leland/Watford that provide for a minimum annual salary and incentives based on increases in reserve value, as defined, since the acquisition. The executives’ entitlement to these incentives vests over time through December 31, 2005, and are payable in cash or in kind by way of transferring to the executives a working interest in the acquired assets.
Pro Forma Results of Operations (Unaudited)
The following table reflects the unaudited pro forma consolidated results of operations for the nine months ended September 30, 2001 and 2000 as though the Canadian acquisitions had occurred on January 1st for the periods presented. These unaudited pro forma results have been prepared for comparative purposes only and are not indicative of future results.
| | Nine Months Ended September 30, | |
| | 2001 | | 2000 | |
| | (in thousands, except per share data) | |
| | | | | |
Revenue | | $ | 163,883 | | $ | 147,432 | |
Net income | | $ | 1,137 | | $ | 7,979 | |
Basic net income per share | | $ | 0.13 | | $ | 0.94 | |
Diluted net income per share | | $ | 0.13 | | $ | 0.94 | |
Proforma net income included a bonus expense of $2.8 million and a gain on settlement of derivatives of $1.1 million for the nine months ended September 30, 2001. Proforma net income included a gain on sale of a partnership of $4.3 million for the nine months ended September 30, 2000..
NOTE 3. LONG TERM DEBT
In conjunction with the Canadian acquisition (see Note 2), effective August 10, 2001, we amended our credit agreement with various financial institutions. The amended agreement provides for a $65 million increase to our maximum borrowing amount, now $130 million. The amended agreement is comprised of a $90 million revolving line of credit and a term loan of $40 million. The terms of the loans extend to August 2005. Actual borrowing limits may be a lesser amount, depending upon trailing cash flow, as defined in the agreement. All other aspects of the amended credit agreement, including rates, collateralization and restrictions are similar to the prior agreement.
Effective October 12, 2001, we amended our credit agreement to replace $35 million of the existing $90 million revolving line of credit with a Canadian credit facility for the same amount. Our combined maximum borrowing amount remains at $130 million. The term of this $35 million revolving line of credit extends through October 2007. All other aspects of the amended credit agreement, including rates, collateralization and restrictions are similar to the prior agreement.
NOTE 4. RECENT ACCOUNTING PRONOUNCEMENTS
In June 1998, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 133, Accounting for Derivative Instruments and Hedging Activities. This statement, as amended by SFAS Nos. 137 and 138, is effective for fiscal years beginning after June 15, 2000. SFAS No. 133 requires an entity to recognize all derivatives as assets or liabilities in the balance sheet and measure those instruments at fair value. MarkWest has adopted SFAS No. 133, as amended, on January 1, 2001. See Note 7 Adoption of SFAS No. 133.
In June 2001, the FASB issued SFAS No. 141, Business Combinations, which addresses financial accounting and reporting for business combinations. SFAS No. 141 is effective for all business combinations initiated after June 30, 2001 and for all business combinations accounted for under the purchase method initiated before but completed after June 30, 2001. All business combinations in the scope of this Statement are to be accounted for using one method – the purchase method. The adoption of SFAS No. 141 did not have a material impact on the Company’s financial position or results of operations.
In June 2001, the FASB issued SFAS No. 142, Goodwill and Other Intangible Assets, which is effective for fiscal years beginning after December 15, 2001, and applies to all goodwill and other intangibles recognized in the financial statements at that date. Under the provisions of this statement, goodwill will not be amortized, but will be tested for impairment on an annual basis. The adoption of SFAS No. 142 is not expected to have a material impact on the Company’s financial position or results of operations.
In July 2001, the FASB issued Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations (“SFAS 143”). SFAS 143, is effective for fiscal years beginning after June 15, 2002 (January 1, 2003 for MarkWest), and establishes an accounting standard requiring the recording of the fair value of liabilities associated with the retirement of long-lived assets in the period in which they are incurred. We are in the process of determining the future impact that the adoption of FAS 143 may have on our earnings and financial position.
In August 2001, the FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. This statement requires the recognition of an impairment loss if the carrying amount of a long-lived asset is not recoverable from its undiscounted cash flows and measures the impairment loss as the difference between the carrying amount and fair value of the asset. The adoption of SFAS No. 144 is not expected to have a material impact on the Company’s financial position or results of operations.
NOTE 5. SEGMENT REPORTING
We classify MarkWest’s operations into two reportable segments, as follows:
(1) Gathering, Processing and Marketing (“GPM”)—provide compression, gathering, treatment, NGL extraction and fractionation services; also purchase and market natural gas and NGLs; and
(2) Exploration and Production (“E & P”)—explore for and produce natural gas.
We evaluate the performance of our segments and allocate resources to them based on operating income. There are no intersegment revenues. We conduct our business in the United States and Canada.
The table below presents information about operating income for the reported segments for the second quarter of 2001 and 2000 and for the nine months ended September 30, 2001 and 2000. Operating income for each segment includes total revenues less operating expenses and excludes depreciation, depletion and amortization, general and administrative expenses, interest expense, interest income and income taxes. We have not reported asset information by reportable segment because we do not produce such information internally.
| | Gathering, Processing and Marketing (000s) | | Exploration and Production (000s) | | Total (000s) | |
For the quarter ended September 30, 2001: | | | | | | | |
Revenues | | $ | 28,309 | | $ | 4,084 | | $ | 32,393 | |
Segment operating income | | $ | 2,930 | | $ | 2,596 | | $ | 5,526 | |
| | | | | | | |
For the quarter ended September 30, 2000: | | | | | | | |
Revenues | | $ | 55,845 | | $ | 1,461 | | $ | 57,306 | |
Segment operating income | | $ | 6,177 | | $ | 424 | | $ | 6,601 | |
| | | | | | | |
For the nine months ended September 30, 2001: | | | | | | | |
Revenues | | $ | 142,368 | | $ | 9,120 | | $ | 151,488 | |
Segment operating income | | $ | 10,808 | | $ | 6,141 | | $ | 16,949 | |
| | | | | | | |
For the nine months ended September 30, 2000: | | | | | | | |
Revenues | | $ | 139,329 | | $ | 3,279 | | $ | 142,608 | |
Segment operating income | | $ | 19,721 | | $ | 1,000 | | $ | 20,721 | |
Following is a reconciliation of total segment operating income to total consolidated income before taxes (000s):
| | For the quarter ended September 30, | | For the nine months ended September 30, | |
| | 2001 | | 2000 | | 2001 | | 2000 | |
Total segment operating income | | $ | 5,526 | | $ | 6,601 | | $ | 16,949 | | $ | 20,721 | |
General and administrative expenses | | (1,906 | ) | (2,173 | ) | (6,189 | ) | (6,031 | ) |
Depreciation and amortization | | (3,295 | ) | (1,427 | ) | (6,700 | ) | (4,323 | ) |
Interest income | | 32 | | 24 | | 114 | | 77 | |
Interest expense | | (974 | ) | (820 | ) | (2,234 | ) | (2,222 | ) |
Gain on sale of assets | | — | | — | | — | | 1,000 | |
Other income (expense) | | (4 | ) | (81 | ) | (253 | ) | 22 | |
Income (loss) before taxes | | $ | (621 | ) | $ | 2,124 | | $ | 1,687 | | $ | 9,244 | |
NOTE 6. CONTINGENCY
In February 2001, three complaints were filed against MarkWest Hydrocarbon, Inc., in the Circuit Court of Wayne County, West Virginia, by Columbia Gas Transmission Corporation and Columbia Natural Resources, Inc.; Equitable Production Company and Equitable Energy LLC; and Cobra Petroleum Company et al. These complaints each allege breach of contract and seek various forms of relief (including injunctive relief) and damages. Losses, if any, with regard to these complaints are undeterminable. In July 2001, MarkWest filed an action in the Denver District Court, Denver, Colorado, against Columbia Gas Transmission Corporation and Columbia Natural Resources, Inc.; Equitable Production Company and Equitable Energy, LLC; and Cobra Petroleum Production Company et al, to compel arbitration on these matters in accordance with provisions in existing contracts. In August 2001, the Circuit Court of Wayne County, West Virginia, has granted the plaintiff’s motion for a temporary mandatory injunction requiring MarkWest to return natural gas to producers in accordance with contractual commitments. The ruling has no impact, as MarkWest has continually returned natural gas in accordance with its agreement. MarkWest has requested reconsideration of certain aspects of the ruling. In addition, a trial date has been scheduled for February 2002. MarkWest is continuing settlement negotiations with various parties.
NOTE 7. ADOPTION OF SFAS NO. 133
MarkWest adopted SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended, on January 1, 2001. In accordance with the transition provisions of SFAS 133, we recorded on that date a net-of-tax cumulative effect adjustment of approximately $1.2 million loss to other comprehensive income to recognize at fair value all derivatives that are designated as cash-flow hedging instruments.
SFAS 133 establishes accounting and reporting standards requiring derivative instruments to be recorded in the balance sheet as either an asset or liability measured at fair value. Changes in the derivative instruments’ fair value are recognized in earnings unless specific hedge accounting criteria are met.
SFAS 133 allows hedge accounting for fair-value and cash-flow hedges. A fair-value hedge applies to a recognized asset or liability or an unrecognized firm commitment. A cash-flow hedge applies to a forecasted transaction or a variable cash flow of a recognized asset or liability. SFAS 133 provides that the gain or loss on a derivative instrument designated and qualifying as a fair-value hedging instrument as well as the offsetting loss or gain on the hedged item be recognized currently in earnings in the same accounting period. SFAS 133 provides that the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash-flow hedging instrument be reported as a component of other comprehensive income and be reclassified into earnings in the same period during which the hedged forecasted transaction affects earnings. (The remaining gain or loss on the derivative instrument, if any, must be recognized currently in earnings.) Effectiveness is evaluated by the derivative instrument’s ability to generate offsetting changes in fair value or cash flows to the hedged item. We formally document, designate and assess the effectiveness of transactions receiving hedge accounting treatment.
In our gathering, processing and marketing segment, we enter into fixed-price contracts for the sale of NGLs and fixed-price purchases for the purchase of natural gas and NGLs. At January 1, 2001, we recorded a risk management asset of approximately $2.1 million in the balance sheet with an offsetting amount recorded, less a deferred tax liability of approximately $0.7 million, in other comprehensive income—approximately $1.3 million gain. At September 30, 2001, the risk management liability was $2.2 million, less $0.8 million deferred tax recovery, resulting in a $1.4 million loss in other comprehensive income. We also recorded a $0.4 million risk management liability and a corresponding risk management asset to reflect our fair value hedges.
In our exploration and production segment, MarkWest enters into fixed-price contracts for the sale of natural gas. At January 1, 2001, we recorded a risk management liability of approximately $3.9 million in the balance sheet with an offsetting amount recorded, less a deferred tax recovery of approximately $1.4 million, in other comprehensive income—approximately $2.5 million loss. At September 30, 2001, the risk management asset was $8.0 million, less $2.8 million deferred tax liability, resulting in a $5.2 million gain in other comprehensive income.
During the second quarter of 2001, we have entered into three year contracts to fix interest rates on $10 million of our debt at 5.28% compared to a floating LIBOR (in both cases, plus an applicable margin). At September 30, 2001, we recorded a risk management liability of approximately $0.4 million in the balance sheet with an offsetting amount recorded, less a deferred tax recovery of approximately $0.1 million, resulting in a $0.3 million loss in other comprehensive income.
Together, at January 1, 2001, these amounts comprise the above net-of-tax cumulative effect adjustment of approximately $1.2 million loss to other comprehensive income. At September 30, 2001, with all transactions considered, there is a $3.5 million gain to accumulated other comprehensive income.
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
This Management’s Discussion and Analysis contains statements which, to the extent that they are not recitations of historical fact, constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 (“Section 27A”) and Section 21E of the Securities and Exchange Act of 1934 as amended (“Section 21E”). This includes, among other things, statements with respect to the outcome of the pending litigation matters and contract negotiations. All forward-looking statements involve risks and uncertainties. We intend that all forward-looking statements in this document are subject to the safe harbor protection provided by Sections 27A and 21E. Factors that most typically impact MarkWest’s operating results and financial condition include:
• changes in general economic conditions in regions where our products are located
• the availability and prices of NGL and competing commodities
• the availability and prices of raw natural gas supply
• our ability to negotiate favorable marketing agreements
• the risks that third party or MarkWest’s natural gas exploration and production activities will not occur or be successful
• our dependence on certain significant customers, producers, gatherers, treaters and transporters of natural gas
• competition from other NGL processors, including major energy companies
• our ability to identify and consummate grass-roots projects or acquisitions complementary to our business
• winter weather conditions
• intermediate or final decisions in the pending litigation and the relative positions of the parties in the negotiation of new processing agreements
• changes in foreign economics, currency, and laws and regulations in Canada where MarkWest has made direct investments
• our ability to integrate the recent Canadian acquisition to operate an exploration and production company in Canada, and to manage the Company as a more exploration and production focused enterprise.
In addition, there are certain factors that impact MarkWest’s exploration and production segment. These include uncertainties inherent in estimating quantities of proven oil and gas reserves, projecting rates of production and timing of development expenditures. The drilling of wells can involve significant risks including those related to timing, success rates and cost overruns. Rig availability, complex geology and other factors can affect these risks. Future gas and oil prices also could affect results of operations and cash flows.
Forward-looking statements involve many uncertainties that are beyond our ability to control. In many cases, we cannot predict what factors would cause actual results to differ materially from those indicated by the forward-looking statements.
Operating data
| | Three Months Ended September 30, | | Nine Months Ended September 30, | |
| | 2001 | | 2000 | | % Change | | 2001 | | 2000 | | % Change | |
Gathering, processing and marketing | | | | | | | | | | | | | |
Appalachia: | | | | | | | | | | | | | |
NGL production—Siloam plant (gallons) | | 38,900,000 | | 41,500,000 | | (6 | )% | 111,000,000 | | 115,300,000 | | (4% | ) |
NGL sales—Siloam plant (gallons) | | 35,200,000 | | 39,800,000 | | (12 | )% | 106,200,000 | | 109,500,000 | | (3% | ) |
Processing margin per gallon: | | | | | | | | | | | | | |
Average NGL sales price | | $ | 0.46 | | $ | 0.63 | | (27 | )% | $ | 0.59 | | $ | 0.59 | | — | |
Average natural gas cost | | 0.36 | | 0.43 | | (16 | )% | 0.45 | | 0.38 | | 18 | % |
Processing margin per gallon | | $ | 0.10 | | $ | 0.20 | | (50 | )% | $ | 0.14 | | $ | 0.21 | | (33% | ) |
| | | | | | | | | | | | | |
Michigan: | | | | | | | | | | | | | |
Pipeline throughput (Mcfd) | | 10,200 | | 9,600 | | 6 | % | 8,700 | | 11,800 | | (26% | ) |
NGL sales (gallons) | | 2,400,000 | | 2,000,000 | | 20 | % | 5,900,000 | | 7,300,000 | | (19% | ) |
| | | | | | | | | | | | | |
Exploration and production | | | | | | | | | | | | | |
Natural gas produced (Mcfed) | | 16,700 | | 4,000 | | 318 | % | 10,200 | | 3,500 | | 191 | % |
Average price per Mcfe | | $ | 2.66 | | $ | 2.51 | | 6 | % | $ | 3.38 | | $ | 2.34 | | 44 | % |
| | | | | | | | | | | | | | | | | | |
Three Months Ended September 30, 2001, Compared to the Three Months Ended September 30, 2000
(in 000s)
| | 2001 | | 2000 | | | $ Change | |
Revenues | | $ | 32,393 | | $ | 57,306 | | $ | (24,913) | |
Income from operations | | $ | 325 | | $ | 3,001 | | $ | (2,676 | ) |
| | | | | | | |
Income (loss) before income taxes | | $ | (621 | ) | $ | 2,124 | | $ | (2,746 | ) |
Provision (benefit) for income taxes | | (427 | ) | 799 | | (1,226 | ) |
Net income | | $ | (194 | ) | $ | 1,325 | | $ | (1,520 | ) |
| | | | | | | |
Basic earnings (loss) per share | | $ | (0.02 | ) | $ | 0.16 | | $ | (0.18 | ) |
The strongest demand for propane, and consequently the highest volumes of and margins for propane sales, generally occur in the winter heating season. Therefore, a substantial portion of our net income is recognized in the first and fourth quarters. This seasonality occurs in the GPM segment of our business.
For the quarter ended September 30, 2001, we report a net loss of $0.2 million, or $0.02 per share, compared to net income, of $1.3 million, or $0.16 per share, for the same period last year. Earnings before interest, taxes and depreciation, depletion and amortization (“EBITDA”) was $3.6 million versus $4.3 million in the third quarter of 2001 and 2000, respectively.
The GPM segment’s cash operating income was down $3.2 million compared to 2000. MarkWest’s Appalachian operations experienced a lower spread between the price of the NGLs versus the cost of the natural gas than in the previous year, when the margin was significantly above average. The margin was $0.10 per gallon versus $0.20 per gallon, or $2.7 million less margin in third quarter 2001. Sales volumes were 26.5 million gallons versus 29.9 million gallons, down 11 percent from third quarter 2000 to 2001. This unfavorable volume variance translates to $0.7 million less margin in third quarter 2001. The decline was due to delays of additional third-party compression facilities and gathering pipeline relocations. Natural gas marketing revenues are $19.2 million less than last year. This decrease had a negligible affect on overall results of the GPM segment. Natural gas marketing activities are low margin transactions done in support of our processing business. The E&P segment’s cash operating income was $2.2 million ahead of last year due to the Canadian acquisition and in the Rocky Mountain E&P business segment, higher volume and prices as well as the San Juan property acquired earlier this year, improved 2001 results. Depreciation, depletion and amortization were up $1.9 million due to the Canadian acquisition and other company growth.
Nine Months Ended September 30, 2001, Compared to the Nine Months Ended September 30, 2000 (in 000s)
| | 2001 | | 2000 | | | $ Change | |
Revenues | | $ | 151,488 | | $ | 142,608 | | $ | 8,880 | |
Income from operations | | $ | 4,060 | | $ | 10,367 | | $ | (6,307 | ) |
| | | | | | | |
Income before income taxes | | $ | 1,687 | | $ | 9,244 | | $ | (7,557 | ) |
Provision for income taxes | | 424 | | 3,558 | | 3,134 | |
Net income | | $ | 1,263 | | $ | 5,686 | | $ | (4,423 | ) |
Net income, excluding gain on sale of assets | | $ | 1,263 | | $ | 5,066 | | $ | (3,803 | ) |
| | | | | | | |
Basic earnings per share | | $ | 0.15 | | $ | 0.67 | | $ | (0.52 | ) |
Basic earnings per share, excluding gain on sale of assets | | $ | 0.15 | | $ | 0.60 | | $ | (0.45 | ) |
For the nine months ended September 30, 2001, we report net income of $1.3 million, or $0.15 per share, compared to net income, excluding gain on sale, of $5.1 million, or $0.60 per share, for the same period last year. Earnings before interest, taxes and depreciation, depletion and amortization (“EBITDA”) was $10.5 million versus $14.7 million in 2001 and 2000, respectively.
The GPM segment’s cash operating income was down $8.9 million compared to 2000. MarkWest’s Appalachian operations experienced a lower spread between the price of the NGLs versus the cost of the natural gas than in the previous year when the margin was significantly above average. The margin was $0.14 versus $0.21, a difference of $0.07 per gallon, or $5.6 million less margin in 2001. The $0.14 margin per gallon earned in 2001 is slightly below the ten year average of $0.16 margin per gallon. Natural gas marketing revenues are $0.2 million less than last year. This decrease had a negligible affect on overall results of the GPM segment. Natural gas marketing activities are low margin transactions done is support of our processing business. The E&P segment was $5.1 million ahead of last year due to the Canadian acquisition and in the Rocky Mountain E&P business unit, higher volume and prices, as well as the additional San Juan properties acquired earlier this year improved 2001 results. Operating expenses as well as the general and administrative costs were higher in 2001 than the same period last year primarily due to the Canadian acquisition and increases related to the capital expansions and acquisitions since last year. Depreciation, depletion and amortization were up $2.4 million due to the Canadian acquisition and other company growth.
Gathering, Processing and Marketing (GPM)
We are paid for our processing in Appalachia through sales of liquids extracted and fees for units of throughput. A large portion, about 65 percent, of our processing services for gas producers in Appalachia involves extracting NGLs from inlet gas streams and replacing the equivalent heat content with dry natural gas purchased in the spot or forward market. Consequently, this segment of our business depends on a positive spread between the NGL prices and the cost of the replacement natural gas (“processing margin”).
The cash operating income for the GPM segment was $2.9 million for the third quarter and $10.8 million year to date for 2001. This compares with $6.2 million and $19.7 million respectively for the year 2000. The expansion of the Kenova plant is complete, but disappointing throughput in the Appalachian system was largely due to lack of adequate compressor capabilities of third parties supplying natural gas from the wellhead to our processing plants and gathering pipeline relocations.
A lower frac spread between the price of the NGL’s verses the cost of the natural gas negatively impacted our gross margin in Appalachia. 2000 margins were significantly above average. The unfavorable price variance in the third quarter was $2.6 million. Volumes sold at our Siloam fractionator during the third quarter are 11 percent lower than the same quarter last year, but on a year-to-date basis; the volume variance is negligible, less than 3 percent. The volumes were lower for the reason stated above.
Earlier in the year 2001, there was a dramatic decline in the prices of NGLs that triggered a write down of inventory value at our Appalachia propane terminals negatively impacting the Appalachian gross margins in 2001.
In western Michigan, volumes were up modestly, but should trend up in the fourth quarter and even more in the first quarter of 2002. As many as six additional, largely third party, wells are expected to be connected to the system by year-end which should double the throughput rate to 20,000 Mcfd as we enter the new year.
Exploration and Production (E & P)
Cash operating income for MarkWest’s E&P businesses increased to $2.6 million for the third quarter and $6.1 million year-to-date 2001. This compares favorably with the $0.4 million for the third quarter of 2000 and $1.0 million for year-to-date 2000. High natural gas prices, acquisitions, new projects in eastern Michigan and benefits of our prior year capital investments have all favorably impacted the operating income for this segment.
This large increase is due to a 77 percent increase in production volume in the San Juan basin properties and production from the $50 million acquisition of the Canadian units included for the first time. Canadian production included only the last two months of the quarter. Both units are in significant exploitation modes with a multi-year inventory of drillable locations. The success of the third quarter exploration program added between 5 and 6 Bcfe of additional reserves. Approximately 20 wells were awaiting connection at quarter’s end and should be flowing late fourth quarter and early first quarter 2002.
In eastern Michigan, the Au Gres project continues to grow with the addition of a second well and plans for a third recompletion are nearly complete.
Revenues and Expenses
Revenues
Revenues increased from $142.6 million to $151.5 million year-to-date 2000 compared to 2001. During the third quarter, the revenues are $24.9 million lower in 2001 compared to 2000.
Gas marketing activities are low margin transactions done in support of our processing business. The volume and gross margins have decreased this year. The 2001 year-to-date gas marketing revenues are $0.2 million behind last year at the same time, and third quarter 2001 revenues are $19.2 million behind third quarter 2000 revenues. However, this low margin activity impacted operating profit only negligibly.
Our GPM segment, excluding gas marketing activities previously mentioned, had revenues of $21.4 million and $29.7 million for the third quarter 2001 and 2000; however, year-to-date 2001 revenues are still ahead of prior year by $3.2 million. The quarterly decrease is predominately in the Appalachian NGL sales price. The prices decreased from $0.63 per gallon to $0.46 per gallon in 2001. NGL sales volumes were also down for the third quarter 2001 compared to 2000 by 4.6 million gallons. These price and volume decreases translate to $9.1 million less revenue for the third quarter 2001.
Our E&P segment contributed an additional $5.8 million to year-to-date revenues, with $2.6 million of that in the third quarter of 2001. The additional revenue is the result of the AuGres project coming on line in July 2000, high natural gas prices, and the benefits of last year’s capital expenditures. We also had higher volumes due to an acquisition earlier this year and the addition of Canadian production beginning in August 2001.
Cost of Sales
Cost of sales increased from $109.6 million to $120.6 million year-to-date 2000 compared to 2001. During the third quarter, cost of sales are $24.4 million lower in 2001 compared to 2000.
Gas marketing cost of sales, like revenues, are down $19.4 million in third quarter 2001 compared to 2000, and are down $0.9 million year-to-date. This low margin activity impacted operating profit only negligibly.
Our GPM segment cost of sales are $12.3 million higher year-to-date 2001 compared to 2000. The predominant cause of this increase is related to the feedstock cost increase. In 2000, the cost per gallon was $0.38 versus a cost of $0.45 for 2001.
Operating Expenses
Operating expenses increased $1.7 million or 14% for the nine months ended September 30, 2001 compared to the same period last year. The third quarter’s operating expenses increased $0.6 or 14% from 2000 to 2001. Much of the increased costs year-to-date relate to the acquisitions and expansions from 2000 being on line for all of 2001 as opposed to only part of 2000, as well as higher fuel costs in 2001. The third quarter’s increased costs are almost entirely attributable to the Canadian acquisition
General and Administrative Expenses
General and administrative expenses were $6.2 and $6.0 million year-to-date 2001 and 2000, respectively. General and administrative expenses were $1.9 and $2.2 for the third quarter 2001 and 2000, respectively. The third quarter decrease is due to capitalization of overhead costs for construction projects and general cost cutting, partially offset by the new Canadian unit and legal expenses.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization increased significantly year-to-date ($2.4 million) and for the third quarter ($1.9 million) 2001 compared to 2000. The increase is primarily related to oil and gas properties of $82.1 million acquired in the Canadian acquisition. A portion of the additional depletion is being recovered with a deferred tax benefit related to the step-up in basis of Canadian assets. In addition, there were significant capital expenditures made in 2000 and early in 2001.
Other income and expense
During the second quarter 2000, we sold an asset for a $1.0 million pre-tax gain.
Liquidity and Capital Resources
MarkWest’s sources of liquidity and capital resources historically have been internal cash flow and our revolving line of credit. In the first quarter of 2000, we supplemented these sources with proceeds from the sale of our corporate office building. In the second quarter of 2000, we increased our line of credit by $15 million to $65 million. In the third quarter of 2001, we increased our credit line further to $130 million.
The following summary table reflects our comparative cash flows for the nine months ended September 30, 2001 and 2000 (in thousands):
| | For the nine months ended September 30, | |
| | 2001 | | 2000 | |
| | | | | |
Net cash provided by operating activities before change in working capital | | $ | 7,990 | | $ | 10,462 | |
Net cash provided by (used in) operating activities from change in working capital | | $ | 4,442 | | $ | (2,640 | ) |
Net cash provided by (used in) investing activities | | $ | (66,401 | ) | $ | (5,935 | ) |
Net cash used in financing activities | | $ | 55,514 | | $ | (1,529 | ) |
Capital Investment Program
MarkWest forecasts a baseline capital budget of $28 million in 2001 in addition to our $50 million acquisition. In our gathering, processing and marketing segment the 2001 capital budget includes $8 million for completion of Appalachia’s Phase II expansion and up to $5 million for new infrastructure to serve our recently acquired Canadian properties. The 2001 capital budget also includes $13 million for our exploration and production segment—$5 million for the acquisition of San Juan Basin properties in January 2001; $2 million for infill drilling in the San Juan Basin; $2 million in Michigan; and $4 million for our new Canadian properties. In addition, MarkWest spent $50 million for the Canadian acquisition.
Financing Facilities
Financing activities consist primarily of net borrowings under MarkWest’s credit facilities. At September 30, 2001, we had $130 million of available credit, of which we had utilized $98.6 million. Depending on the timing and amount of our capital projects, we may have to seek additional sources of capital. While we believe that we will be able to secure additional financing on acceptable terms, if required, we have no assurance that we will be able to do so.
Commodity Price Risk Management
MarkWest’s primary risk management objective is to reduce volatility in our cash flows. Our hedging approach uses a statistical method that analyzes momentum and average pricing over time and various fundamental data, such as industry inventories, industry production, demand and weather. Hedging levels increase with capital commitments and debt levels and when above-average margins exist. We maintain a committee, including members of senior management, which oversees all hedging activity.
We achieve our goals utilizing a combination of fixed-price forward contracts and fixed-for-float price swaps on the over-the–counter (“OTC”) market. New York Mercantile Exchange (“NYMEX”)-traded futures are authorized for use, but only occasionally used. Swaps and futures allow us to protect margins, because gains or losses in the physical market are generally offset by corresponding losses or gains in the value of financial instruments.
We enter OTC swaps with counterparties that are primarily of other energy companies. We conduct a standard credit review and have agreements with such parties that contain collateral requirements. We use standardized swap agreements that allow for offset of positive and negative exposures. Net credit exposure is marked to market daily. We are subject to margin deposit requirements under OTC agreements (and NYMEX positions).
The use of financial instruments may expose MarkWest to the risk of financial loss in certain circumstances, including instances when (a) sales volumes are less than expected, requiring market purchases to meet commitments; or (b) our OTC counterparties fail to purchase or deliver the contracted quantities of natural gas, NGLs, or crude oil, or otherwise fail to perform. To the extent that we engage in hedging activities, we may be prevented from realizing the benefits of favorable price changes in the physical market. However, we are similarly insulated against decreases in such prices.
MarkWest hedges our basis risk for natural gas, but we are generally unable to do so for NGLs. Our basis risk stems from the geographic price differentials between our sales locations and hedging contract delivery locations. Basis risk is the risk that an adverse change in the hedging market will not be completely offset by an equal and opposite change in the price of the physical commodity being hedged.
In our gathering, processing and marketing segment, we hedge Appalachia processing margins by using a combination of methods. We protect margins by purchasing natural gas priced on predetermined Btu differentials to propane or crude, by simultaneously selling propane or crude oil and purchasing natural gas, and by using swaps. Crude oil is highly correlated with certain NGL products. All projected margins on open positions assume the basis differentials between crude oil, and NGLs are consistent with historical averages. As of September 30, 2001, we have hedged NGL volumes and associated projected margin per NGL gallon, as follows:
| | Hedged Processing Margin | |
| | | | | | | | | | | |
| | 4th Qtr | | 1st Qtr | | 2nd Qtr | | 3rd Qtr | | Total | |
| | 2001 | | 2002 | | 2002 | | 2002 | | 2002 | |
Using Crude Oil | | | | | | | | | | | |
NGL gallons | | 11,250,000 | | 6,420,000 | | 2,520,000 | | 1,680,000 | | 10,620,000 | |
NGL processing margin ($/gallon) | | $ | 0.26 | | $ | 0.25 | | $ | 0.20 | | $ | 0.18 | | $ | 0.23 | |
| | | | | | | | | | | |
Using Propane | | | | | | | | | | | |
Propane gallons | | 17,470,000 | | 18,600,000 | | 2,520,000 | | — | | 21,120,000 | |
NGL processing margin ($/gallon) | | $ | 0.19 | | $ | 0.19 | | $ | 0.16 | | — | | $ | 0.19 | |
| | | | | | | | | | | |
Total | | | | | | | | | | | |
NGL gallons | | 28,720,000 | | 25,020,000 | | 5,040,000 | | 1,680,000 | | 31,740,000 | |
NGL processing margin ($/gallon) | | $ | 0.22 | | $ | 0.21 | | $ | 0.18 | | $ | 0.18 | | $ | 0.20 | |
| | | | | | | | | | | | | | | | | | |
We have also hedged natural gas liquid sales as follows:
| | | | Hedged Sales Price for NGLs | | | |
| | 2nd Qtr | | 3rd Qtr | | 4th Qtr | | Total | |
| | 2002 | | 2002 | | 2002 | | 2002 | |
| | | | | | | | | |
NGL gallons | | 2,500,000 | | 5,000,000 | | 1,700,000 | | 9,200,000 | |
| | | | | | | | | |
| $/gallon | | $ | 0.47 | | $ | 0.47 | | $ | 0.47 | | $ | 0.47 | |
| | | | | | | | | | | | | | |
Subsequent to September 30, 2001, as of October 30, 2001, we have also hedged more natural gas liquid sales as follows:
| | | | Hedged Sales Price for NGLs | | | |
| | 2nd Qtr 2002 | | 3rd Qtr 2002 | | 4th Qtr 2002 | | Total 2002 | |
| | | | | | | | | |
NGL gallons | | 3,800,000 | | 12,500,000 | | 5,100,000 | | 21,400,000 | |
| | | | | | | | | |
$/gallon | | $ | 0.47 | | $ | 0.47 | | $ | 0.47 | | $ | 0.47 | |
| | | | | | | | | | | | | |
For certain Appalachia natural gas liquid purchases, as of September 30, 2001, we have hedged 0.7 million and 1.1 million gallons at $0.54 per gallon for fourth quarter 2001 and first quarter 2002, respectively. For certain Appalachia natural gas sales, as of September 30, 2001, we have hedged 206,000 and 444,000 MMBtu at $5.19 per MMBtu for 2001 and 2002, respectively.
In addition to these risk management tools, MarkWest utilizes our NGL storage facilities and contracts for third-party storage to build product inventories during historically lower-priced periods for resale during higher-priced periods. We also have contracts to purchase certain quantities of our natural gas feedstock in advance of physical needs.
In our exploration and production segment, we hedge our exposure to changes in market prices for our natural gas production. As of September 30, 2001, we had hedged natural gas volumes and prices as follows:
| | | | | | Hedged Natural Gas Sales | | | | | | | |
| | 4th Qtr | | 1st Qtr | | 2nd Qtr | | 3rd Qtr | | 4th Qtr | | Total | | | | | |
| | 2001 | | 2002 | | 2002 | | 2002 | | 2002 | | 2002 | | 2003 | | 2004 | |
| | | | | | | | | | | | | | | | | |
MMBtu | | 1,340,000 | | 1,260,000 | | 1,220,000 | | 1,280,000 | | 1,250,000 | | 5,010,000 | | 3,700,000 | | 1,820,000 | |
$ /MMBtu | | $ | 3.25 | | $ | 3.38 | | $ | 3.14 | | $ | 3.13 | | $ | 3.15 | | $ | 3.20 | | $ | 3.25 | | $ | 3.09 | |
| | | | | | | | | | | | | | | | | |
Henry Hub Equivalent $/MMBtu | | $ | 3.66 | | $ | 3.82 | | $ | 3.59 | | $ | 3.58 | | $ | 3.60 | | $ | 3.64 | | $ | 3.68 | | $ | 3.57 | |
As a result of the Canadian E&P acquisition, we are transitioning our hedging strategy to recognize the natural hedge between our E&P production and our natural gas purchase requirements in our Appalachian GPM business. Going forward, we anticipate hedging NGL sales and net gas sales (i.e. the excess of production over purchases).
MarkWest’s hedging strategy benefited our after-tax earnings compared to the situation of not hedging. In the gathering, processing and marketing segment, without hedging, net income would have been lower by $0 million and $1.2 million for the three and nine months ended September 30, 2001. For comparison, net income would have been higher by $0.7 million and $1.6 million for the three and nine months ended September 30, 2000. This impact considers only hedges of Appalachia processing margin and does not reflect other decisions made concerning when to buy natural gas or store NGL production for sale in later months. In the exploration and production segment, without hedging, net income would have been lower by $0.4 million and higher by $0.4 million for the three and nine months ended September 30, 2001. For comparison, net income would have been higher by $0.2 million and $0.3 million for the three and nine months ended September 30, 2000.
We enter into speculative transactions on an infrequent basis. Specific approval by the Board of Directors is necessary prior to executing such transactions. Speculative transactions are marked to market at the end of each accounting period, and any gain or loss is recognized in income for that period. There were no such speculative activities for the quarters ended September 30, 2001 and 2000.
Outlook
In the Appalachian GPM segment, the expansion of the Kenova gas plant is complete and on line. This completes the Phase II expansion program which also involved the building of a new plant near the existing Kenova plant. NGL production is ramping up to 170 million gallons in 2002 compared to the anticipated 145 million gallons in 2001 from these new and expanded facilities. Planning for other new projects is also underway.
In the Michigan GPM segment, the two new discoveries made with industry partners earlier this year and a newly contracted third party well will start to flow late in the fourth quarter of this year. Other third party wells that have not been flowing due to a third party title dispute started flowing in the third quarter. By early 2002, the throughput volumes should be 15,000 to 20,000 Mcfd.
In the Exploration and Production segment, the company expects natural gas production to average 35,000 Mcfed in 2002 compared to the anticipated 13,000 Mcfed in 2001. Over 50 exploitation wells are planned in Canada and the United States. This 2002 production level is approximately the same as natural gas shrinkage needs for our midstream business and constitutes a natural hedge, which should mitigate future earnings volatility.
EBITDA for the year 2002 is expected to be about $40 million, with the assumption that natural gas averages $3.00 per MMBtu at Henry Hub and West Texas Intermediate oil averages $21.00 per barrel. NGL pricing has a very high correlation to crude oil pricing. The 2001 EBITDA is expected to be about $20 million.
Pending new projects, capital expenditures for the Gas Processing and Marketing segment are expected to be nominal for 2002 compared with an anticipated level of $13 million in 2001. The Exploration and Production segment plans expenditures of about $20 million compared with $13 million in 2001 (not including the $50 million Canadian acquisition). These are split about two-thirds to Canada and one-third to the U.S.
Item 3. Quantitative and Qualitative Disclosures about Market Risk
Reference is made to Commodity Price Risk Management in Item 2 of this Form 10-Q.
Item 1. Legal Proceedings
(a) As we reported in a current report on Form 8-K, dated February 22, 2001, three complaints have been filed against us in the Circuit Court of Wayne County, West Virginia, by Columbia Gas Transmission Corporation and Columbia Natural Resources, Inc.; Equitable Production Company and Equitable Energy, LLC; and Cobra Petroleum Production Company et al. These complaints each allege breach of contract and seek various forms of relief (including injunctive relief) and damages.
In July 2001, MarkWest has filed an action in the Denver District Court, in Denver, Colorado, against Columbia Gas Transmission Corporation and Columbia Natural Resources, Inc.; Equitable Production Company and Equitable Energy, LLC; and Cobra Petroleum Production Company et al to compel arbitration on these matters in accordance with provisions in existing contracts. In August 2001, the Circuit Court of Wayne County, West Virginia, granted the plaintiff’s motion for a temporary mandatory injunction requiring MarkWest to return natural gas to producers in accordance with contractual commitments. The ruling has no impact, as MarkWest has continually returned natural gas in accordance with its agreement. MarkWest has requested reconsideration of certain aspects of the ruling. In addition, a trial date has been scheduled for February 2002. MarkWest is continuing settlement negotiations with various parties.
In the winter of 2000-2001, current and futures prices for natural gas had risen dramatically relative to prices for NGLs (propane, butane, etc.). A large portion—about 75 percent—of MarkWest’s processing services for gas producers in Appalachia involves extracting NGLs from inlet gas streams and replacing the equivalent heat content with dry natural gas purchased in the spot or forward markets. This part of our operating margin depends on a positive spread between NGL prices and natural gas costs. Effective February 1, 2001, we provided producers with an alternative processing contract that provides for additional compensation to MarkWest when processing margins are low and reduced compensation when these margins are high. To date, over 90 producers (accounting for a minority share of the volume) have agreed to an amended contract. If producers elect to remain with the existing contract, we have stated that we will return the replacement natural gas at a later date. We believe this is permitted under the existing contract such that we can earn a reasonable fee for our services.
Since the winter of 2000-2001, the relationship between NGLs and natural gas has improved substantially.
(b) On June 6, 2001, Level Propane Gases, Inc. filed suit against MarkWest Hydrocarbon, Inc. in the Court of Common Pleas, Cuyahoga County, Ohio alleging breach of contract for failure to furnish a specified quantity of gallons of propane gas on a monthly basis from May 1, 2000 to April 30, 2001, and seeking direct and punitive damages.
On July 25, 2001, MarkWest filed a Motion to stay proceedings pending arbitration in Denver, Colorado in the Court of Common Pleas, Cuyahoga County, Ohio.
MarkWest believes Level’s breach of contract claim has no merit.
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
11 — Statement regarding computation of earnings per share.
(b) Reports on Form 8-K
(i) A report on Form 8-K was filed on August 14, 2001, announcing the acquisition of two Canadian
natural gas production companies.
(ii) A report on Form 8-K was filed August 27, 2001, presenting the purchase and sale and financing
agreements on the acquisition of the two Canadian companies announced on August 14, 2001.
(iii) A report on Form 8K/A was filed on October 24, 2001, presenting audited financial statements of the
two Canadian companies acquired in August 2001 and pro forma financials for MarkWest.
Pursuant to the requirements of the Securities Exchange Act of 1934, MarkWest, as registrant, had this report signed on our behalf by the undersigned, who has been duly authorized.
| MarkWest Hydrocarbon, Inc. |
| | (Registrant) |
| | |
| | |
Date: November 12, 2001 | By: | /s/ Gerald A. Tywoniuk |
| | Gerald A. Tywoniuk |
| | Chief Financial Officer and Vice President Of Finance |
| | (On Behalf of the Registrant and as Principal Financial Officer) |
