ITEM 3. LEGAL PROCEEDINGS
Reference is made to Note 5 of the Company's Consolidated Financial Statements in Item 8 of this Form 10-K.
West Shore Processing Company, LLC ("West Shore"), and Basin Pipeline, LLC ("Basin"), indirect subsidiaries of the Company, filed a lawsuit against Michigan Production Company, LLC ("MPC"), on October 27, 1998, in District Court for the City and County of Denver, State of Colorado, for failure of MPC to convey a lateral pipeline and related rights of way in accordance with provisions of a Gas Gathering, Treating and Processing Agreement with West Shore dated May 2, 1996.
In its response dated December 24, 1998, MPC acknowledges the contract but denies an obligation to convey the facilities by reason of alleged breaches of contract by West Shore. MPC also asserted counterclaims for breach of contract, tortious interference, breach of fiduciary duty and civil conspiracy against West Shore, Basin and MarkWest Michigan, Inc. ("MWM"). MPC seeks to join MWM, a subsidiary of MarkWest Hydrocarbon, Inc., as an involuntary Plaintiff in the litigation. MPC seeks unspecified damages for alleged construction delays. The MPC claims are primarily asserted as a purported third-party beneficiary of rights under the Participation, Ownership and Operating Agreement for West Shore, an agreement entered into between MWM and Michigan Energy Company ("MEC"), an affiliate of MPC. The interest of MEC in West Shore was acquired by MWM pursuant to a Purchase and Sale Agreement dated November 21, 1997. As part of that agreement, any and all claims of MEC were released. The MarkWest entities intend to vigorously defend against these counterclaims, which are believed to be without merit.
In an unrelated matter, on February 1, 1999, MWM, West Shore and Basin, together with John Fox and Arthur Denney, were named as third-party defendants in connection with counterclaims asserted by MPC, Williams Energy Services Company, Millenium Energy Fund LLC, and MEF Production Payment Trust against KCS Michigan Resources, Inc., and DDD Energy, Inc., in the 27th Circuit Court for the County of Oceana, Michigan. KCS Michigan Resources, Inc., and DDD Energy, Inc., initiated that action as plaintiffs on or about October 7, 1998. Messrs. Fox and Denney are directors and officers of MarkWest. In this counterclaim, MPC and other parties who are defendants and counterclaimants assert valid title to certain leases in which the MarkWest entities have no interest. MPC and the other counterclaimants are also claiming slander of title to real and personal property, unjust enrichment, tortious interference with contract, civil conspiracy, breach of contracts, and breach of fiduciary duties, and they are seeking unspecified damages. The MarkWest entities are vigorously defending themselves against these claims, believing that they have been improperly named as third-party defendants and that the claims are without merit.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
There were no matters submitted to a vote of security holders during the quarter ended December 31, 1998.
PART II
ITEM 5.
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The American Stock Exchange began trading shares of MarkWest Hydrocarbon, Inc. under the ticker symbol NRG on Monday, February 22, 1999. The Company's stock formerly traded on the Nasdaq National Market under the ticker symbol MWHX. MarkWest's ticker symbol NRG was chosen to represent "energy."
As of January 7, 1999, there were 8,531,206 shares of common stock outstanding held by 379 holders of record. The following table sets forth quarterly high and low sales prices as reported by the Nasdaq National Market for the periods indicated.
The Company has paid no dividends on the common stock and anticipates that, for the foreseeable future, it will continue to retain earnings for use in the operation of its business. Payment of cash dividends in the future will depend upon the Company's earnings, financial condition, any contractual restrictions, restrictions imposed by law and other factors deemed relevant by the Company's Board of Directors.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
The selected consolidated statement of operations and balance sheet data for the years ended December 31, 1998, 1997 and 1996, and as of December 31, 1998 and 1997, are derived from, and are qualified by reference to, audited consolidated financial statements of the Company included elsewhere in this Form 10-K. The selected consolidated statement of operations and balance sheet data set forth below for the year ended December 31, 1995 and 1994, and as of December 31, 1996, 1995 and 1994, have been derived from audited financial statements not included in this Form 10-K. The selected consolidated financial information set forth below should be read in conjunction with "Management's Discussions and Analysis of Financial Condition and Results of Operations" and the Company's Consolidated Financial Statements and related notes thereto included in this Form 10-K.
_______________________ N/M--Not meaningful.
/(1)/ Prior to October 7, 1996, the Company was organized as a partnership-- MarkWest Hydrocarbon Partners, Ltd. ("MarkWest Partnership")--and consequently, was not subject to income tax. Effective October 7, 1996, the Company reorganized (the "Reorganization"), and the existing general and limited partners exchanged 100% of their interests in MarkWest Partnership for 5,725,000 common shares of the Company. Pro forma information has been presented for purposes of comparability as if the Company had been a taxable entity for all periods presented:
___________________ /(a)/ Pro forma weighted average shares outstanding for the year ended December 31, 1996, represents the weighted average of, for the period prior to the initial public offering (the "Offering"), the number of common shares issued in the Reorganization plus the number of shares issued in the Offering for which the net proceeds were used to repay outstanding indebtedness and, for the period subsequent to the Offering, the total number of common shares outstanding. Pro forma weighted average shares outstanding for the years ended December 31, 1995 and 1994, represent the weighted average number of common shares issued in the Reorganization. /(2)/ Weighted average shares outstanding for the year ended December 31, 1996, represents the weighted average of, for the period prior to the Company's initial public offering, the number of common shares issued in the Reorganization and, for the period subsequent to the Offering, the total number of common shares outstanding. Weighted average shares outstanding for the years ended December 31, 1995 and 1994, represent the weighted average number of common shares issued in the Reorganization. /(3)/ Includes cash of $2,055; $1,364; $4,401; $761; and $5,468, respectively. /(4)/ Represents cost of sales for Appalachia. Includes transportation cost of unfractionated liquids from Cobb and Boldman to Siloam and Cobb fuel charge, totaling approximately $0.20/MMBtu. /(5)/ 1998 and 1997 results reflect the Company's acquisition of the remaining 40 percent interest of the Michigan project in November 1997.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSIONS AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following analysis should be read in conjunction with the selected financial data and the Company's Consolidated Financial Statements included in this Form 10-K.
RESULTS OF OPERATIONS - ----------------------
Year Ended December 31, 1998, Compared to Year Ended December 31, 1997 (in thousands of dollars)
______________________ /(1)/ Excludes interest income, general and administrative expense and interest expense.
For the year ended December 31, 1998, MarkWest reported a net loss of $1.2 million, or $0.14 per share, on revenues of $63.7 million. These results compare to net income of $7.8 million, or $0.92 per share, on revenues of $79.7 million for the same period in 1997. The net loss in 1998, compared to net income in 1997, largely resulted from a reduction of $9.9 million, or $1.16 per share in after-tax gas processing margins (a $0.10 per MMBtu processing margin swing impacts MarkWest's after-tax earnings by approximately $600,000). Appalachia's full-year 1998 gas processing margin of $0.70 per MMBtu was more than 60% below its 10-year average of $1.80 per MMBtu and down by 70% compared to 1997's average of $2.36 per MMBtu. The decrease in margin was due to a combination of weak NGL prices, which resulted from 35% lower crude oil prices, and relatively strong natural gas costs that negatively impacted the entire natural gas processing industry. Michigan's after-tax operating income totaled $1.6 million for 1998, or $0.19 per share, up from break-even in 1997. Increases in depreciation, depletion and amortization, and net interest expense were largely offset by savings in operating costs and general and administrative costs.
Gathering, processing and marketing revenue. Gathering, processing and marketing revenue decreased $15.5 million or 20% for the year ended December 31, 1998, compared to the year ended December 31, 1997. The Company's Appalachian operations accounted for the majority of the overall revenue decrease, primarily as a result of weak NGL prices in 1998 compared to 1997. In addition, fee gas processed in 1998 only includes volumes processed at the Company's Kenova plant beginning March 1, 1998. In 1997 and early 1998, fee gas processed included volumes at the Boldman and Cobb plants in addition to the Kenova plant. The loss of fee revenue is partly offset by cost savings realized from not operating Boldman and Cobb.
The above factors were partially offset by an 80% increase in the volume of gas processed in the Company's Michigan operations during the year ended December 31, 1998, compared to the year ended December 31, 1997. Gas processed in the Company's Michigan operations contributed both fee-based processing income and revenues from the sale of propane and other liquids extracted at the Company's new NGL extraction plant, which began operations in January 1998.
Oil and gas revenue. Oil and gas revenue increased $296,000 for the year ended December 31, 1998, compared to the year ended December 31, 1997. This increase was primarily attributable to an increase in gas production from the prior year.
Interest income. Interest income decreased $461,000 for the year ended December 31, 1998, compared to the year ended December 31, 1997. During 1997, interest income was primarily derived from a note receivable, which accrued interest at a rate of 5.98%. The note was for the costs incurred by the Company for the construction of the 32-mile extension to the gas pipeline in Michigan, which was completed in 1997. During 1998, the note was forgiven in exchange for the title to the pipeline extension.
Cost of sales. Cost of sales decreased $2.8 million, or 6%, for the year ended December 31, 1998, compared to the year ended December 31, 1997. The Company's Appalachian operations accounted for the majority of the decrease, primarily as a result of a decrease in the unit cost of propane at the Company's terminals.
Operating expenses. Operating expenses decreased $501,000, or 4%, for the year ended December 31, 1998, compared to the year ended December 31, 1997. In response to low processing margins, the Company implemented cost-controlling measures and consequently reduced operating costs during 1998, compared to 1997. This decrease was partially offset by the introduction of operational costs from the Company's new NGL extraction plant in Michigan for a full year during 1998.
General and administrative expenses. General and administrative expenses decreased $1.3 million, or 20%, for the year ended December 31, 1998, compared to the year ended December 31, 1997. General and administrative expenses incurred during 1997 included a continuation of many initial costs, including significant professional service fees, incurred in connection with the Company's reorganization into a public company following the initial public offering in October 1996. In addition, in response to low processing margins throughout 1998, the Company implemented cost-controlling measures and consequently reduced general and administrative expenses.
Depreciation, depletion and amortization. Depreciation, depletion and amortization increased $1.3 million, or 42%, for the year ended December 31, 1998, compared to the year ended December 31, 1997. This increase was principally due to increased depreciation attributable to the Company's new NGL extraction plant and pipeline extension in Michigan.
Interest expense. Interest expense increased $1.3 million, or 154%, for the year ended December 31, 1998, compared to the year ended December 31, 1997. This increase was principally due to an increase in average outstanding long-term debt in 1998 compared to 1997.
Year Ended December 31, 1997, Compared to Year Ended December 31, 1996 (in thousands of dollars)
_______________________ /(1)/ Excludes interest income, general and administrative expense and interest expense. /(2)/ 1996 information is pro forma for net income. Prior to a reorganization in October 1996, MarkWest was organized as a partnership and, consequently, was not subject to income tax. Pro forma net income for 1996 has been presented for purposes of comparability as if MarkWest had been a taxable entity.
For the year ended December 31, 1997, income before income taxes was $12.4 million, compared to income before income taxes of $14.8 million, for the year ended December 31, 1996. The decrease in income before income taxes was primarily a result of the effect of an industrywide decrease in prices from 1996, when near record high levels had a positive impact on the Company's terminal operations. As a result, in 1996, the terminals recorded above average gross margins compared to relatively flat margins in 1997, when prices dropped significantly in the first quarter and margins remained low throughout the year. This factor was partially offset by increased volumes and margins at the Company's Appalachia plants.
Gathering, processing and marketing revenue. Gathering, processing and marketing revenue increased $7.5 million, or 11%, for the year ended December 31, 1997, compared to 1996, due to a variety of reasons.
The Company's Appalachian operations accounted for the majority of the overall revenue increase, primarily on the strength of favorable results recognized in 1997 from hedging positions put in place during the fourth quarter of 1996. Fee gas volumes processed in 1997, which includes fee gas processed at the Boldman and Cobb plants effective February 1997, as well as fee gas processed at the Kenova plant, increased because of a change in the structure of the Company's processing fee arrangements effective in early 1997. In addition, the Company's Siloam plant sold a record 103 million gallons in 1997, a 9% increase over the previous year.
The above factors were substantially offset by a 20% decrease in throughput at the Company's terminals. Moreover, the terminals suffered price decreases up to 18% compared to 1996, especially during the fourth quarter at which time near record prices existed in the prior year.
The Company's Michigan operations contributed the remaining increase in revenue in 1997 compared to the year ended December 31, 1996, principally as the result of a 180% increase in the volume of gas processed. The Company's activities in Michigan were operational for a full year for the first time in 1997. Additionally, the connection of another company's well to MarkWest's pipeline following the well's completion during the second quarter of 1997 also contributed to the volume increase.
Oil and gas revenue. Oil and gas revenue increased $531,000, or 149%, for the year ended December 31, 1997, compared to 1996. This increase was directly attributable to an increase in production from nine new wells in 1997.
Interest income. Interest income increased $469,000, or 244%, for the year ended December 31, 1997, compared to 1996. The increase was primarily due to interest earned on a note receivable, which accrued interest at a rate of 5.98%. The note was for the costs incurred by the Company for the construction of the 32-mile extension to the gas pipeline in Michigan.
Cost of sales. Cost of sales increased $4.8 million, or 12%, for the year ended December 31, 1997, compared to 1996. The Company's Appalachian operations accounted for the majority of the increase, primarily as a result of a 6% increase in unit costs and a 9% increase in volumes sold at the Company's Siloam plant. This increase was substantially offset by a 20% decrease in throughput at the Company's terminals. The remaining increase was a direct result of the increase in the volume of gas processed by the Company's Michigan operations.
Operating expenses. Operating expenses increased $3.7 million, or 49%, for the year ended December 31, 1997, compared to 1996. The majority of the increase was driven by the Company's operations in Michigan, which commenced operations in May 1996. The remaining increase resulted from additional repair and maintenance and other operating costs at the Company's Appalachian facilities, including operating costs attributable to the Company's Boldman plant and Columbia's Cobb plant, pursuant to the change in fee structure described previously.
General and administrative expenses. General and administrative expenses increased $1.9 million, or 40%, for the year ended December 31, 1997, compared to 1996. This increase was attributable to administrative support activities related to the new operations in Michigan and to costs incurred in connection with being a public company for a full year in 1997.
Depreciation, depletion and amortization expense. Depreciation, depletion and amortization expense increased $336,000, or 12%, for the year ended December 31, 1997, compared to 1996. This increase was principally due to increased depreciation attributable to the Company's new Michigan operations.
Provision for income taxes. The provision for income taxes decreased $2.4 million for the year ended December 31, 1997, compared to 1996. The decrease was primarily a result of the one-time charge of $3.7 million taken in the fourth quarter of 1996 in connection with the Company's reorganization from a partnership, together with reduced levels of pre-tax income.
LIQUIDITY AND CAPITAL RESOURCES
The Company's sources of liquidity and capital resources historically have been net cash provided by operating activities, funds available under its financing facilities, and in 1996, proceeds from an initial public offering of equity. In the past, these sources have been sufficient to meet its needs and finance the growth of its business.
The following summary table reflects comparative cash flows for the Company for the years ended December 31, 1998, 1997 and 1996:
For the year ended December 31, 1998, net cash provided by operating activities before adjustments for working capital decreased $7.9 million from the year ended December 31, 1997, to $4.8 million, primarily as a result of a decrease in gas processing margins at MarkWest's Appalachian plants since 1997. As shown above, this was enhanced by a $3.6 million net decrease in the Company's working capital accounts, excluding cash, for the year ended December 31, 1998, compared to a $7.9 million net increase in working capital accounts, excluding cash, for the year ended December 31, 1997. The change in working capital in 1998 was principally driven by decreases in accounts receivable, inventories, prepaid expenses and other assets. The change in working capital in 1997 was principally driven by increases in accounts receivable, prepaid expenses and other assets and decreases in inventories, accounts payable and accrued liabilities.
Cash used in investing activities decreased $18.8 million to $11.6 million for the year ended December 31, 1998 compared to 1997, primarily related to fewer capital expenditures and acquisitions (see further discussion under "Capital Investment Program") for the year ended December 31, 1998, compared for the year ended December 31, 1997. In addition, cash used in investing activities was reduced by $4.3 million from proceeds received on the sale of equipment in the third quarter of 1998, when the Company sold and leased back three compressors at its Kenova facility.
For the year ended December 31, 1998, cash provided by financing activities was $3.8 million, a decrease of approximately $18.7 million compared to the year ended December 31, 1997. The decrease was primarily attributable to paying down more debt in 1998.
Capital Investment Program
During 1998, the Company invested $15.9 million in capital expenditures, including $11 million in Michigan to fund the further extension of the pipeline. The remaining capital programs during 1998 included $2.3 million for various projects in Appalachia and $2.6 million for exploration and production activities, (net of dispositions of $0.7 million), including $2.4 million in the first quarter acquisition of 40 producing wells located in the northern San Juan Basin of southwest
Colorado. During 1997, the Company invested $19.3 million in capital expenditures, including $9.1 million in Michigan primarily to construct an NGL extraction plant. In addition, in 1997, the Company spent $8.5 million in Michigan to buy out its previous partner and an additional $1.9 million to complete a 32-mile gas pipeline extension in Michigan originally built on behalf of a producer.
The Company's capital investment program for 1999 is currently estimated at $5.3 million. Rocky Mountain exploration and production activities will total $3.1 million, including a $1.4 million acquisition in the San Juan Basin and several exploitation projects. The remaining capital programs for 1999 include various maintenance projects in Appalachia and Michigan, completion of various 1998 Michigan projects, and funding of several drilling projects in Michigan.
Financing Facilities
The Company's financing facilities are described in Note 3 to the Company's Consolidated Financial Statements in Item 8 of this Form 10-K. At December 31, 1998, the Company had approximately $39.2 million of available credit, of which net debt of $36.6 million had been utilized as of December 31, 1998, and working capital of $11.5 million. The Company believes that cash provided by operating activities, together with amounts available to be borrowed under its financing facilities, will provide sufficient funds to maintain its existing facilities and fund its current capital expenditure program. As 1999 progresses, the Company's credit availability is expected to increase as its Michigan volumes contribute more to the trailing cash flow calculation, the determinant of the Company's available credit, even if processing margins continue to be low.
In early 1999, the Company concluded the sale of non-core Rocky Mountain producing property interests generating $0.8 million, and plans to sell its corporate office building and other non-core assets for proceeds in excess of $10 million to increase its financial flexibility to pursue new processing opportunities. Depending on the timing and amount of the Company's future projects, it may be required to seek additional sources of capital. While the Company believes that it would be able to secure additional financing on terms acceptable to the Company, if required, no assurance can be given that it will be able to do so.
1999 OUTLOOK
NGL prices in the fourth quarter of 1998 were below historical levels and are expected to remain so during the first quarter of 1999. These prices are often correlated with and driven by the price of crude oil, which has not recovered from its decline over the fourth quarter of 1997 and the first quarter of 1998.
The Company anticipates that until a crude oil price recovery is underway and/or gas prices soften, the Company will continue to experience earnings pressures, like others in the industry. MarkWest's NGL commodity exposure is partially offset by selling liquids in a premium market, utilizing storage capability and its ability to prebuy some of its natural gas requirements. In addition, an increase of fee-based income, primarily a result of connecting new wells that increase system throughput in Michigan, and a growing volume of owned gas production help to offset the fluctuation of NGL and natural gas prices. Currently MarkWest's Michigan operations have an annual sensitivity to throughput volumes equal to approximately $350,000 in pretax income for every million cubic feet per day. The Company anticipates fee-based activity will generate approximately 50% of total gross margins in 1999 (assuming normal processing margins in Appalachia). This will provide an earnings mix that is less volatile to swings in commodity prices.
A substantial portion of the Company's revenues and as a result, its gross margins, remains dependent upon the sales price of NGLs, particularly propane, which fluctuates with the winter weather conditions, and other supply and demand determinants. The strongest demand for propane and the highest propane sales margins generally occur during the winter heating season. As a result, the Company recognizes a substantial portion of its annual income during the first and fourth quarters of the year.
RISK MANAGEMENT ACTIVITIES
The Company's primary risk management objectives are to meet or exceed budgeted gross margins by locking in budgeted or above-budgeted prices in the financial derivatives and physical markets and to protect margins from precipitous declines. The Company maintains a committee, including members of senior management, which oversees all hedging activity.
MarkWest achieves its goals utilizing a combination of fixed price forward contracts, New York Mercantile Exchange-traded futures, and fixed/floating price swaps on the over-the-counter ("OTC") market. First, the Company protects margins through purchases of natural gas forward contracts with predetermined BTU differentials based upon a basket of Gulf Coast NGL prices (or a substitute for propane, such as crude oil). Second, MarkWest protects margins by purchasing natural gas futures while simultaneously selling propane futures of approximately the same Btu value. Third, the Company manages its commodity price risk on terminal propane purchases and sales by purchasing and selling, respectively, propane futures contracts. Fourth, by purchasing propane futures contracts, the Company locks in desired prices on forward sales to certain customers. Fifth, the Company's wholly owned subsidiary, MarkWest Resources, Inc., enters into OTC swaps with certain other creditworthy companies to hedge exposure to changes in spot market prices on certain levels of production.
Gains and losses related to qualifying hedges, as defined by Statement of Financial Accounting Standards No. 80, Accounting for Futures Contracts, of firm commitments or anticipated transactions are recognized in revenue and cost of sales upon execution of the hedged physical transaction.
The Company had no material notional quantities of natural gas, NGL, or crude oil futures or options at December 31, 1998 and 1997.
During the years ended December 31, 1998 and 1997, a $32,000 gain and $989,000 gain, respectively, were recognized in operating income on the settlement of propane and natural gas futures. Financial instrument gains and losses on hedging activities were generally offset by amounts realized from the sale of the underlying products in the physical market.
In addition to these risk management tools, MarkWest utilizes its liquids storage facilities and contracts for third party storage to build product inventories during historically lower-priced periods for resale during higher- priced periods. Also, MarkWest has contractual arrangements to purchase certain quantities of its natural gas feedstock in advance of physical needs.
IMPACT OF THE YEAR 2000 ISSUE
The Year 2000 Issue is the result of computer programs being written using two digits rather than four to define the applicable year. Unless the Company's computer programs are Year 2000 compliant, any of the Company's computer programs that have date-sensitive software may recognize a date using "00" as the year 1900 rather than the year 2000. This could result in a system failure or miscalculations causing disruptions of operations, including, among other things, a temporary inability to process transactions, send invoices, or engage in similar normal business activities. The Company's most significant risk related to the Year 2000 Issue is the worst-case scenario that its plants and pipelines, if not Year 2000 compliant, may not be operable, causing a loss of both gathering and processing volumes and associated revenues.
In the first quarter of 1998, the Company began its preliminary assessment of the Year 2000 Issue. Many of the Company's computer systems, which include both financial systems and plant control systems, are purchased from third-party vendors who have represented to the Company that they are Year 2000 compliant. In some cases, the Company has upgraded or needs to upgrade to the most recent release. A complete analysis, including an evaluation of the extent to which the Company is vulnerable to the failure of significant customers and suppliers to properly remediate their own Year 2000 Issue, was completed in early 1999. Remediation has begun and is expected to be completed during the second quarter of 1999. A contingency plan to deal with unexpected Year 2000 issues will be completed in the second or third quarter of 1999. Based upon current information, the Company estimates that the total cost of its Year 2000 initiative will be approximately $110,000. The Year 2000 costs include all activities undertaken on Year 2000 related matters across the Company, including, but not limited to, remediation, testing, third-party review, risk mitigation and contingency planning. All Year 2000 costs have been and will continue to be funded through operating cash flow and are expensed in the period in which they are incurred. The Company believes that total Year 2000 project costs will not be material to the Company's results of operations, liquidity or capital resources, and that as a result of the Company's efforts, Year 2000 should have little impact on the Company's computer systems.
ITEM 7A.
ITEM 7A.-- QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company faces market risk from commodity price variations, primarily in the NGLs it sells and in the natural gas it purchases. It also incurs, to a lesser extent, credit risks and risks related to interest rate variations.
Commodity Price Risk. In the past, NGL prices and natural gas costs have fluctuated widely in response to changing market forces. The impacts of these price fluctuations on earnings from natural gas processing and marketing activities have been significant and have varied from year to year. Currently MarkWest's Appalachian operations have an annual sensitivity to NGL prices equal to $1.0 million in pretax income for every $0.01/gallon change in NGL prices and an annual sensitivity to natural gas prices equal to $1.0 million in pretax income for every $0.10/MMBtu change in natural gas prices.
As discussed in Risk Management Activities, the Company occasionally uses futures contracts and fixed/floating price swaps to hedge a portion of its commodity price risk. See related discussion in Note 7 to the Company's Consolidated Financial Statements. Gains and losses experienced on hedging transactions are generally offset by the related gains or losses on the sale of the underlying product in the physical market. The Company had no material quantities of natural gas, NGL, or crude oil futures, swaps or options at December 31, 1998 and 1997.
Credit Risk. The Company is exposed to potential losses as a result of nonperformance by counterparties pursuant to the terms of their contractual obligations. The Company maintains credit policies with regard to its counterparties that management believes minimize overall credit risk. Such policies include the evaluation of a prospective counterparty's financial condition, collateral requirements where deemed necessary, and the use of standardized agreements which facilitate the netting of cash flows associated with a single counterparty. The Company also monitors the financial condition of existing counterparties on an ongoing basis. Considering the system of internal controls in place, the Company believes it is unlikely that a material adverse effect on its financial position, results of operations or cash flows would occur as a result of counterparty nonperformance.
Interest Rate Risk. The Company is exposed to changes in interest rates, primarily as a result of its long-term debt with floating interest rates. The Company may make use of interest rate swap agreements to adjust the ratio of fixed and floating rates in the debt portfolio, although no such agreements are currently in place. The impact of a 100 basis point increase in interest rates on the Company's debt would result in an increase in interest expense and a decrease in income before taxes of approximately $386,600. This amount has been determined by considering the impact of the hypothetical interest rates on the Company's variable-rate debt balances as of December 31, 1998.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Stockholders of MarkWest Hydrocarbon, Inc.
In our opinion, the accompanying consolidated balance sheet and related consolidated statements of operations, of cash flows and of changes in stockholders' equity/partners' capital present fairly, in all material respects, the financial position of MarkWest Hydrocarbon, Inc., a Delaware corporation, and its subsidiaries at December 31, 1998 and 1997, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1998, in conformity with generally accepted accounting principles. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with generally accepted auditing standards which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for the opinion expressed above.
PricewaterhouseCoopers LLP
Denver, Colorado February 10, 1999
MARKWEST HYDROCARBON, INC. CONSOLIDATED BALANCE SHEET (000S, EXCEPT SHARE DATA)
The accompanying notes are an integral part of these financial statements.
MARKWEST HYDROCARBON, INC. CONSOLIDATED STATEMENT OF OPERATIONS (000S, EXCEPT PER SHARE DATA)
The accompanying notes are an integral part of these financial statements.
MARKWEST HYDROCARBON, INC. CONSOLIDATED STATEMENT OF CASH FLOWS (000S)
The accompanying notes are an integral part of these financial statements.
MARKWEST HYDROCARBON, INC. CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY/ PARTNERS' CAPITAL (000S)
The accompanying notes are an integral part of these financial statements.
MARKWEST HYDROCARBON, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. NATURE OF OPERATIONS AND SIGNIFICANT BUSINESS ACQUISITIONS
NATURE OF OPERATIONS
MarkWest Hydrocarbon, Inc. ("MarkWest" or the "Company"), provides natural gas processing and related services. The Company's activities include compression, gathering, treatment and natural gas liquids ("NGLs") extraction services for natural gas producers and pipeline companies and fractionation of NGLs into marketable products. The Company also purchases, stores and markets natural gas and NGLs and conducts strategic exploration for new natural gas sources for its processing services. The Company's operations are concentrated in three core areas: the southern Appalachian region of eastern Kentucky, southern West Virginia, and southern Ohio; western Michigan; and the Rocky Mountains.
1996 REORGANIZATION
The Company was incorporated in June 1996 to act as the successor to MarkWest Hydrocarbon Partners, Ltd. (the "Partnership"). Effective October 7, 1996, the Partnership reorganized and the existing general and limited partners exchanged 100% of their interests in the Partnership for 5,725,000 common shares of the Company. An additional 2,760,000 shares of common stock were offered for public sale, totaling 8,485,000 shares outstanding as of October 31, 1996. This transaction was a reorganization of entities under common control, and accordingly, it was accounted for at historical cost.
SIGNIFICANT BUSINESS ACQUISITIONS
The Company provides natural gas gathering, treatment, processing and NGL marketing in Manistee, Mason and Oceana Counties in Michigan. Effective May 6, 1996, the Company began to earn an interest in the Michigan core area by funding various capital programs. By June 1997, the Company completed its earn-in of a 60 percent interest after funding $16.8 million in capital programs. In November 1997, MarkWest acquired the remaining 40 percent interest from its partner, Michigan Energy Company, L.L.C., for a purchase price of $8.5 million plus up to $13.5 million in future contingent payments (see Note 5).
NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
PRINCIPLES OF CONSOLIDATION
The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation.
CASH AND CASH EQUIVALENTS
The Company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. Excess cash is used to pay down the credit facility. Accordingly, investments are limited to overnight investments of end-of-day cash balances.
INVENTORIES
Inventories comprise the following (in 000s):
At December 31, 1998 1997 ----------- ------------ Product inventory............................ $ 4,064 $ 4,728 Materials and supplies inventory............. 519 413 ----------- ------------ $ 4,583 $ 5,141 =========== ============
Product inventory consists primarily of finished goods (propane, butane, isobutane, natural gasoline, and in 1997, natural gas) and is valued at the lower of cost, using the first-in, first-out method, or market. Inventory write-downs at December 31, 1998 and 1997, were $525,000 and $585,000, respectively. In addition, the Company recorded a write-down of $0 and $251,000 related to firm commitments held at December 31, 1998 and 1997, respectively, for the purchase of natural gas inventory. Capitalized overhead costs of $280,000 and $166,000 were included in product inventory at December 31, 1998 and 1997, respectively. Materials and supplies are valued at the lower of average cost or estimated net realizable value.
PREPAID FEEDSTOCK
Prepaid feedstock consists of natural gas purchased in advance of its actual use. It is valued using the first-in/first-out method. Prepaid feedstock write- downs at December 31, 1998 and 1997, were $0 and $160,000, respectively.
MARKWEST HYDROCARBON, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment is recorded at cost. Expenditures that extend the useful lives of assets are capitalized. Repairs, maintenance and renewals that do not extend the useful lives of the assets are expensed as incurred. Interest costs for the construction or development of significant long-term assets are capitalized and amortized over the related asset's estimated useful life.
Depreciation is provided principally on the straight-line method over the following estimated useful lives: plant facilities and pipelines, 20 years; buildings, 40 years; furniture, leasehold improvements and other, 3 to 10 years. Depreciation for oil and gas properties is provided for using the units-of- production method.
Oil and gas properties consist of leasehold costs, producing and non-producing properties, oil and gas wells, equipment and pipelines. The Company uses the full cost method of accounting for oil and gas properties. Accordingly, all costs associated with acquisition, exploration and development of oil and gas reserves are capitalized to the full cost pool.
These capitalized costs, including estimated future costs to develop the reserves and estimated abandonment costs, net of salvage value, are amortized on a units-of-production basis using estimates of proved reserves. Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs. If the results of an assessment of such properties indicate that the properties are impaired, the amount of impairment is added to the capitalized cost base to be amortized. As of December 31, 1998 and 1997, approximately $489,000 and $967,000 of investments in unproved properties were excluded from amortization.
The capitalized costs included in the full cost pool are subject to a "ceiling test," which limits such costs to the aggregate of the estimated present value, using a 10 percent discount rate, of the future net revenues from proved reserves, based on current economics and operating conditions. No impairment existed during the three years ended December 31, 1998.
Sales of proved and unproved properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas, in which case the gain or loss is recognized in the consolidated statement of operations.
IMPAIRMENT OF LONG-LIVED ASSETS
During 1996, the Company adopted Statement of Financial Accounting Standards ("SFAS") No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of, which requires that an impairment loss be recognized when the carrying amount of an asset exceeds the expected future undiscounted net cash flows. There was no effect on the Company's financial statements for the three years ended December 31, 1998 as a result of adopting SFAS No. 121.
INTANGIBLE ASSETS
Intangible assets consist primarily of deferred financing costs that are amortized using the straight-line method over the term of the associated agreement.
NOTE RECEIVABLE AND OTHER ASSETS
Note receivable at December 31, 1997, consisted of a note receivable and related interest receivable due from Michigan Production Company, LLC ("MPC"). The note was for the costs incurred by the Company for the construction of a 32-mile pipeline extension in Michigan. During 1998, the note and related interest was forgiven in exchange for the title to the pipeline extension.
HEDGING ACTIVITIES
The Company limits its exposure to natural gas and propane price fluctuations related to future purchases and production with futures contracts. These contracts are accounted for as hedges in accordance with the provisions of SFAS No. 80, Accounting for Futures Contracts. Gains and losses on such hedge contracts are deferred and included as a component of revenues and cost of sales when the hedged production is sold, or gas supplies are purchased.
FAIR VALUE OF FINANCIAL INSTRUMENTS
The Company's financial instruments consist of cash and cash equivalents, receivables, accounts payable and other current liabilities, and long-term debt. Except for long-term debt, the carrying amounts of financial instruments approximate fair value due to their short maturities. At December 31, 1998 and 1997, based on rates available for similar types of debt, the fair value of long-term debt was not materially different from its carrying amount.
MARKWEST HYDROCARBON, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
REVENUE RECOGNITION
Revenue for sales or services is recognized at the time the product is shipped or at the time the service is performed.
INCOME TAXES
Deferred income taxes reflect the impact of "temporary differences" between amounts of assets and liabilities for financial reporting purposes and such amounts as measured by tax laws. These temporary differences are determined in accordance with the liability method of accounting for income taxes as prescribed by SFAS No. 109, Accounting for Income Taxes.
CONCENTRATION OF CREDIT RISK
Financial instruments that potentially subject the Company to concentrations of credit risk consist principally of trade accounts receivable. The trade accounts receivable risk is limited due to the large number of entities comprising the Company's customer base and their dispersion across industries and geographic locations. At December 31, 1998 and 1997, the Company had no significant concentrations of credit risk.
STOCK COMPENSATION
As permitted under SFAS No. 123, Accounting for Stock-Based Compensation, the Company has elected to continue to measure compensation costs for stock-based employee compensation plans as prescribed by Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees. See Note 9 for the applicable disclosures required by SFAS No. 123.
EARNINGS PER SHARE (EPS)
During 1997, the Company adopted SFAS No. 128, Earnings Per Share. SFAS No. 128 replaced the presentation of primary EPS with a presentation of basic EPS. Basic earnings per share are determined by dividing net income by the weighted- average number of common shares outstanding during the year. Earnings per share assuming dilution are determined by dividing net income by the weighted-average number of common shares and common stock equivalents outstanding.
SEGMENT REPORTING
In 1998, the Company adopted SFAS No. 131, Disclosures about Segments of an Enterprise and Related Information. SFAS No. 131 supersedes SFAS No. 14, Financial Reporting for Segments of a Business Enterprise, replacing the "industry segment" approach with the "management" approach. The management approach designates the internal organization that is used by management for making operating decisions and assessing performance as the source of the Company's reportable segments. SFAS No. 131 also requires disclosures about products and services, geographic areas, and major customers. The adoption of SFAS No. 131 did not affect results of operations or financial position but did affect the disclosure of segment information (see Note 11, "Segment Reporting").
SUPPLEMENTAL CASH FLOW INFORMATION
Interest of $2.4 million, $1.0 million and $1.0 million was paid during the years ended December 31, 1998, 1997 and 1996, respectively. Interest expense in 1998 is net of $298,000 capitalized to various construction projects. Income taxes of $596,000 and $7.0 million were paid during the years ended December 31, 1998 and 1997, respectively. There were no income taxes paid during the year ended December 31, 1996, because of the Company's partnership status.
Non-cash investing activities included in 1998 the forgiveness of the note and related interest receivable valued at $10.1 million in exchange for the title to a 32-mile pipeline in Michigan and in 1996, the contribution of Basin Pipeline, LLC, by Michigan Energy Company, L.L.C. to the Company, valued at approximately $9.2 million. In 1996, non-cash financing activities included the purchase of certain assets from the Dow Chemical Company by the assumption of a note valued at approximately $421,000.
RECENT ACCOUNTING PRONOUNCEMENTS
In June 1998, the Financial Accounting Standards Board issued Statement No. 133, Accounting for Derivative Instruments and Hedging Activities. This statement is effective for fiscal years beginning after June 15, 1999. Earlier application is encouraged; however, the Company does not anticipate adopting SFAS No. 133 until the fiscal year beginning January 1, 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. Although the Company is currently evaluating SFAS No. 133, it is not expected to have a material impact on the financial condition or results of operations of the Company.
MARKWEST HYDROCARBON, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
USE OF ESTIMATES
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
RECLASSIFICATIONS
Certain prior year amounts have been reclassified to conform to the 1998 presentation.
NOTE 3. DEBT
CREDIT FACILITY
Effective June 20, 1997, the Company replaced its existing financing agreements with a new $85 million credit facility with three commercial banks, which expires in 2004. Actual borrowing limits may be a lesser amount, depending on trailing cash flow, as defined in the agreement. The credit facility permits the Company to borrow money using either a base rate loan or a London Interbank Offered Rate ("LIBOR") loan option, plus an applicable margin of between 0% and 2.5%, based on a certain Company debt to earnings ratio. At December 31, 1998, the Company had $35 million outstanding under the credit facility bearing interest at an average rate of 7.8%. At December 31, 1997, the Company had $33.9 million outstanding under the credit facility bearing interest at an average rate of 6.6%. The Company pays a fee at a rate between 0.25% and 0.75% per annum on the unused commitment, based on a certain Company debt to earnings ratio. The credit facility is secured by a first mortgage on the Company's major assets. The loan agreement restricts certain activities and requires the maintenance of certain financial ratios and other conditions. As a direct result of entering into the new credit facility, the Company wrote off to interest expense previously deferred financing costs associated with a previous credit facility of approximately $235,000 in the second quarter of 1997.
155 INVERNESS BUILDING FINANCING
Effective January 14, 1998, the Company's wholly-owned subsidiary, 155 Inverness, Inc., obtained separate $3.7 million financing from an insurance company for the purchase of an office building. The 7.25% note matures on February 10, 2003, and is secured by the property's deed of trust and by a ten year master lease with the Company. As of December 31, 1998, approximately $3.65 million was outstanding under the note.
SCHEDULED DEBT MATURITIES
Scheduled debt maturities as of December 31, 1998, are as follows (in 000s):
1999 .................. $ 63 2000 .................. 3,812 2001 .................. 7,567 2002 .................. 9,447 2003 and thereafter.... 17,771 --------- Total.................. $ 38,660 =========
NOTE 4. RELATED PARTY TRANSACTIONS
The Company, through its wholly owned subsidiary, MarkWest Resources, Inc. ("Resources"), holds a varied undivided interest in several exploration and production assets owned jointly with MAK-J Energy Partners Ltd. ("MAK-J"), which owns a 51% undivided interest in such properties. The general partner of MAK-J is a corporation owned and controlled by the President and Chief Executive Officer of the Company. The properties are held pursuant to joint venture agreements entered into between Resources and MAK-J. Resources is the operator under such agreements. As the operator, Resources is obligated to provide certain engineering, administrative and accounting services to the joint ventures. The joint venture agreements provide for a monthly fee payable to Resources for all such expenses. As of December 31, 1998 and 1997, the Company has receivables due from MAK-J for approximately $0 and $790,000, and payables to MAK-J for approximately $488,000 and $202,000, respectively.
The Company made contributions of $164,000, $271,000 and $299,000 to a profit- sharing plan for the years ended December 31, 1998, 1997 and 1996, respectively. The plan is discretionary, with annual contributions determined by the Company's Board of Directors.
The Company (formerly a Partnership) periodically extended offers to employees to purchase interests in the Company. The employees provided the Company with promissory notes as part of the exercise price. According to the terms of the notes, interest accrues at 7% and payments are required
MARKWEST HYDROCARBON, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
for the greater of accrued interest or excess distributions and are payable in full on October 8, 1999. Notes in the amounts of $164,000 and $167,000 have been recorded as a reduction of additional paid-in capital at December 31, 1998 and 1997, respectively. Purchase of Company stock with financing provided by the Company was discontinued concurrent with the Company's public offering in October 1996.
NOTE 5. COMMITMENTS AND CONTINGENCIES
COLUMBIA GAS TRANSMISSION CORPORATION ARBITRATION
MarkWest filed arbitration proceedings in February 1998 to resolve issues with Columbia Gas Transmission Corporation ("Columbia") regarding three Appalachia natural gas processing plants. These plants are governed by several contracts, the most important of which extends through the year 2010. In this arbitration, MarkWest requests a declaration of rights and status to clarify agreements between the companies and certain monetary relief. Issues arose during ongoing negotiations between MarkWest and Columbia to finalize terms of a 1997 preliminary agreement in which, among other things, Columbia agreed to sell its Cobb plant to MarkWest and to transfer from Columbia to MarkWest the operation of the Boldman plant. These issues also include matters regarding operations at the Kenova plant. MarkWest owns the Boldman and Kenova plants.
In April 1998, Columbia filed a Complaint against MarkWest in the United States District Court for the Southern District of West Virginia. The Complaint seeks declaratory relief that certain agreements, or certain specified provisions thereof, are void and that MarkWest is in breach of the Federal Energy Regulatory Commission-approved settlement agreement under which MarkWest was to acquire the Cobb plant and operate the Boldman plant. The certain agreements concern, among other matters, Columbia's obligation to guarantee the delivery of natural gas or NGLs to MarkWest. In the Complaint, Columbia also seeks injunctive relief to enjoin MarkWest from interfering with arrangements Columbia may seek to undertake with natural gas producers and suppliers and with negotiations Columbia may pursue with third parties to terminate its interests in the products extraction business. In the third quarter of 1998, the District Court judge stayed proceedings pending the binding arbitration noted above. The arbitration is scheduled to begin in the second quarter of 1999. Management believes it will prevail in its position and, accordingly, the outcome of this dispute is not likely to have a material effect on the financial condition, results of operations or prospects of MarkWest.
MICHIGAN ACQUISITION
In connection with the Company's acquisition of the remaining 40 percent interest in its Michigan core area from its partner (see Note 1), the Company is committed to make additional future contingent payments of up to $13.5 million. The future contingent payments consist of nine payments ranging from $1.0 million to $2.7 million. The payments are contingent upon several factors, including substantial sustained increases in system throughput volumes to levels ranging from 45 million cubic feet per day ("MMcf/d") to 75 MMcf/d, and a minimum internal rate of return on the capital programs undertaken to expand throughput capacity.
NOTE 6. SIGNIFICANT CUSTOMERS
For the year ended December 31, 1998, 1997 and 1996, sales to one customer accounted for approximately 9%, 19% and 16% of total revenues. Management believes the loss of this customer would not adversely impact operations, because alternative markets are available.
NOTE 7. FINANCIAL DERIVATIVES
The Company uses futures contracts and fixed/floating price swaps to hedge a portion of its commodity price risk.
FUTURES
The Company enters into futures transactions on the New York Mercantile Exchange ("NYMEX") and is subject to margin requirement deposits. MarkWest may protect its processing gross margins by purchasing natural gas futures while simultaneously selling propane futures of approximately the same British thermal unit ("Btu") value. The Company may also use futures to fix or float its cost of natural gas purchases. The Company may also manage its commodity price risk on terminal propane purchases and/or sales by purchasing and/or selling, respectively, propane futures contracts. The Company may also use NYMEX futures to offset physical positions in its gas marketing activities. The Company had no material notional quantities of natural gas, NGL, or crude oil futures or options at December 31, 1998 and 1997.
During the years ended December 31, 1998 and 1997, a $32,000 gain and $989,000 gain, respectively, were recognized in operating income on the settlement of propane and natural gas futures. Financial instrument gains and losses on hedging activities were generally offset by amounts realized from the sale of the underlying products in the physical market.
The Company enters into speculative futures transactions on an infrequent basis. Specific approval by the Board of Directors is necessary prior to executing such transactions. Speculative futures are marked to market at the end of each accounting period, and any gain or loss is recognized in income for that period. Results from such speculative activities for the year ended December 31, 1998, were not material. No such transactions were executed for the year ended December 31, 1997.
MARKWEST HYDROCARBON, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SWAPS
The Company's wholly owned subsidiary, MarkWest Resources, Inc. ("Resources"), enters into OTC swaps with certain other creditworthy companies. Resources uses swap agreements to hedge exposure to changes in spot market prices on the amount of natural gas production covered in the agreement. At December 31, 1998, Resources had four open swap agreements that guaranteed Resources an average sales price of $2.00/Mcf for up to 1,720 Mcf/d of production ending at various times throughout 1999. At December 31, 1997, Resources had three open swap agreements that guaranteed Resources an average sales price of $2.22/Mcf for up to 956 Mcf/d of production ending at various times throughout 1998 and 1999.
NOTE 8. INCOME TAXES
In connection with the reorganization from a partnership to a corporation, the Company recorded deferred income taxes as of October 7, 1996, and a one-time charge to earnings of $3.7 million.
The total income tax provision (benefit) has been allocated as follows (in 000s):
The provision (benefit) for income taxes subsequent to reorganization is comprised of (in 000s):
The deferred tax liabilities (assets) are comprised of the tax effect of the following (in 000s):
The differences between the provision for income taxes at the statutory rate and the actual provision for income taxes for the years ended December 31, 1998, 1997 and 1996, are as follows (in 000s):
MARKWEST HYDROCARBON, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
At December 31, 1998, the Company had state NOL carryforwards for federal and state income tax purposes of approximately $2.2 million. These carryforwards expire as follows (in 000s):
2004...................................... $ 565 2014...................................... 1,645 ---------- Total $2,210 ==========
The Company believes that the carryforwards will be utilized prior to their expiration. They are expected to be realized by achieving future profitable operations based on the Company's dedicated and owned reserves, dedicated reserves behind its processing plants, past earnings history, and projections of future earnings.
NOTE 9. STOCK COMPENSATION PLANS
At December 31, 1998, the Company has two stock-based compensation plans, which are described below. The Company applies APB Opinion No. 25, Accounting for Stock Issued to Employees, and related Interpretations in accounting for its plans. Accordingly, no compensation cost has been recognized for its fixed stock option plans. Had compensation cost for the Company's two stock-based compensation plans been determined based on the fair value at the grant dates under those plans consistent with the method prescribed by SFAS No. 123, Accounting for Stock-Based Compensation, the Company's pro forma net income and earnings per share would have been reduced to the pro forma amounts listed below (in 000s, except per share data):
The Company historically granted employees the right to purchase partnership interests in the Partnership. As part of the Reorganization, such employee options to purchase partnership interests were replaced by options to purchase shares pursuant to the Company's 1996 Stock Incentive Plan.
Under the 1996 Stock Incentive Plan, the Company may grant options to its employees for up to 850,000 shares of common stock in the aggregate. Under this plan, the exercise price of each option equals the market price of the Company's stock on the date of the grant, and an option's maximum term is ten years. Options are granted periodically throughout the year and vest at the rate of 20% on the first anniversary of the option grant date and at the rate of 20% on each subsequent anniversary thereof until fully vested.
Under the 1996 Non-employee Director Stock Option Plan, the Company may grant options to its non-employee directors for up to 20,000 shares of common stock in the aggregate. Under this plan, the exercise price of each option equals the market price of the Company's stock on the date of the grant, and an option's maximum term is three years. Options are granted upon either the date the director first becomes a director, or on the date of each Annual Meeting of Stockholders, provided that the director has served since the date of the last Annual Meeting of Stockholders. Options granted upon the date the director first becomes a director vest at the rate of 33.33% on the first anniversary of the option grant date and at the rate of 33.33% on each subsequent anniversary thereof until fully vested. Options granted on the date of each Annual Meeting vest 100% on the first anniversary of the option grant date.
Effective October 1, 1998, the Company repriced all stock options granted in 1997 and mid-1998. The stock options were repriced at $10.75 per share, the fair market value on October 1, 1998.
MARKWEST HYDROCARBON, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The fair value of each option is estimated on the date of grant using the Black- Scholes Option-Pricing model with the following weighted-average assumptions: dividend yield of $0/share for options granted in 1998, 1997 and 1996; expected volatility of 34% for 1998 option grants, 30% for 1997 option grants and 33% for 1996 option grants; risk-free interest rate of 4.35% for 1998 option grants, 5.83% for 1997 option grants and 6.55% for 1996 option grants; expected lives of 6 years for 1998, 1997 and 1996 option grants.
A summary of the status of the Company's two fixed stock option plans as of December 31, 1998, 1997 and 1996, and changes during the years ended on those dates are presented below:
The following table summarizes information about fixed stock options outstanding at December 31, 1998:
NOTE 10. EARNINGS PER SHARE
During 1997, the Company adopted SFAS No. 128, Earnings per Share. This statement requires that all periods presented be retroactively restated in accordance with SFAS No. 128. SFAS No. 128 dictates that the computation of earnings per share shall not assume conversion, exercise or contingent issuance of securities that would have an antidilutive effect on earnings (loss) per share. As a result, the denominator for the year ended December 31, 1998, is not adjusted to reflect the Company's stock options outstanding. The options are antidulutive as the incremental shares result in a decrease in loss per share. The following table shows the amounts used in computing earnings per share and weighted average number of shares of dilutive potential common stock for the years ended December 31, 1998, 1997 and 1996 (in 000s, except per share data):
MARKWEST HYDROCARBON, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 11. SEGMENT REPORTING
In 1998, the Company adopted SFAS No. 131, Disclosures about Segments of an Enterprise and Related Information. The Company's operations are classified into two principal reportable segments, as follows:
(1) Processing and Related Services--provides compression, gathering, treatment and NGL extraction, and fractionation services; also purchases and markets natural gas and NGLs; and (2) Exploration and Production--explores for and produces natural gas.
The accounting policies of the segments are the same as those described in the "Summary of Significant Accounting Policies." There are no intersegment revenues. MarkWest evaluates the performance of its segments and allocates resources to them based on gross operating income. MarkWest's business is conducted solely in the United States.
The table below presents information about gross operating income for the reported segments for the three years ended December 31, 1998. Asset information by reportable segment is not reported, since MarkWest does not produce such information internally.
A reconciliation of total segment revenues to total consolidated revenues and of total segment gross operating income to total consolidated income, for the years ended December 31, 1998, 1997 and 1996, is as follows:
MARKWEST HYDROCARBON, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 12. QUARTERLY RESULTS OF OPERATIONS (UNAUDITED)
The following summarizes certain quarterly results of operations (in 000s):
- ------------------------- /(1)/ Excludes interest income. /(2)/ Excludes general and administrative expenses and interest expense.
NOTE 13. SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
Costs
The following tables set forth capitalized costs at December 31, 1998, 1997 and 1996, and costs incurred for oil and gas producing activities for the years ended December 31, 1998, 1997 and 1996 (in 000s):
MARKWEST HYDROCARBON, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
RESULTS OF OPERATIONS
The results of operations for oil and gas producing activities, excluding corporate overhead and interest costs, for the years ended December 31, 1998, 1997 and 1996, are as follows (in 000s):
/(1)/ The Company generated $206,000 in tax credits in 1998 that the Company was unable to utilize as a result of the Company's consolidated federal tax loss in 1998.
RESERVE QUANTITY INFORMATION
Reserve estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and of future net cash flows expected therefrom prepared by different engineers or by the same engineers at different times may vary substantially. Results of subsequent drilling, testing and production may cause either upward or downward revisions of previous estimates. Further, the volumes considered to be commercially recoverable fluctuate with changes in commodity prices and operating costs. Any significant revision of reserve estimates could materially adversely affect the Company's financial condition and results of operations.
The following table sets forth information for the years ended December 31, 1998, 1997 and 1996, with respect to changes in the Company's proved reserves, all of which are in the United States.
MARKWEST HYDROCARBOR, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
/(1)/ As previously mentioned, the Company was incorporated in 1996. Prior to 1996, the Company did not require the preparation of an estimate of reserves. Accordingly, beginning of the year reserves for 1996 simply reflect 1996 end of the year reserves plus 1996 production.
STANDARDIZED MEASURES OF DISCOUNTED FUTURE NET CASH FLOWS
Estimated discounted future net cash flows and changes therein were determined in accordance with SFAS No. 69, Disclosures about Oil and Gas Producing Activities. Certain information concerning the assumptions used in computing the valuation of proved reserves and their inherent
limitations are discussed below. The Company believes such information is essential for a proper understanding and assessment of the data presented.
Future cash inflows are computed by applying year-end prices of oil and gas relating to the Company's proved reserves to the year-end quantities of those reserves. Future price changes are considered only to the extent provided by contractual arrangements, including futures contracts in existence at year end.
The assumptions used to compute estimated future net revenues do not necessarily reflect the Company's expectations of actual revenues or costs, or their present worth. In addition, variations from the expected production rate also could result directly or indirectly from factors outside of the Company's control, such as unintentional delays in development, changes in prices or regulatory controls. The reserve valuation further assumes that all reserves will be disposed of by production. However, if reserves are sold in place, additional economic considerations could also affect the amount of cash eventually realized.
Future development and production costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions.
Future income tax expenses are computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the Company's proved oil and gas reserves. Permanent differences in oil and gas-related tax credits and allowances are recognized.
An annual discount rate of 10% was used to reflect the timing of the future net cash flows relating to proved oil and gas reserves.
Information with respect to the Company's estimated discounted future cash flows from its oil and gas properties for the years ended December 31, 1998, 1997 and 1996, is as follows (in 000s):
Principal changes in the Company's estimated discounted future net cash flows for the years ended December 31, 1998, 1997 and 1996 are as follows (in 000s):
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Pursuant to instruction G(3) to Form 10-K, Items 10, 11, 12 and 13 are omitted because the Company will file a definitive proxy statement pursuant to Regulation 14A under the Exchange Act of 1934 not later than 120 days after the close of the fiscal year. The information required by such Items will be included in the definitive proxy statement to be so filed for the Company's annual meeting of stockholders scheduled for May 13, 1999, and is hereby incorporated by reference.
PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) The following documents are filed as part of this report:
(1) Financial Statements:
Reference is made to the Index to Consolidated Financial Statements included in this Form 10-K for a list of all financial statements filed as a part of this report.
(2) Financial Statement Schedules:
None required.
(3) Exhibits
See (c) below.
(b) Reports on Form 8-K:
None filed in the fourth quarter of 1998.
(c) Exhibits required by Item 601 of Regulation S-K. See (a) (3) above.
2.1 Purchase and Sale Agreement between MarkWest Hydrocarbon, Inc., and Michigan Energy Company, L.L.C., dated November 21, 1997 (filed as Exhibit 2.1 to MarkWest Hydrocarbon, Inc.'s Form 8-K filed on January 29, 1998, and incorporated herein by reference).
3.1 Certificate of Incorporation of MarkWest Hydrocarbon, Inc. (filed as Exhibit 3.1). /(1)/
3.2 Bylaws of MarkWest Hydrocarbon, Inc. /(1)/
10.1 Amended and Restated Reorganization Agreement made as of August 1, 1996, by and among MarkWest Hydrocarbon, Inc.; MarkWest Hydrocarbon Partners, Ltd.; MWHC Holding, Inc.; RIMCO Associates, Inc.; and each of the limited partners of MarkWest Hydrocarbon Partners, Ltd. /(1)/
10.2 Participation, Ownership and Operating Agreement for West Shore Processing Company, L.L.C., dated May 2, 1996 (filed as Exhibit 10.7). /(1)/
10.3 Gas Treating and Processing Agreement, dated May 1, 1996, between West Shore Processing Company, LLC, and Shell Offshore, Inc. (filed as Exhibit 10.10). /(1)/
10.4 Processing Agreement (Kenova Processing Plant), dated March 15, 1995, between Columbia Gas Transmission Corporation and MarkWest Hydrocarbon Partners, Ltd. (filed as Exhibit 10.15). /(1)/
10.5 Agreement to Design and Construct New Facilities, dated March 15, 1995, between Columbia Gas Transmission Corporation and MarkWest Hydrocarbon Partners, Ltd. (filed as Exhibit 10.19). /(1)/
10.6 Natural Gas Liquids Purchase Agreement (Boldman Plant), dated December 24, 1990, between Columbia Gas Transmission Corporation and MarkWest Hydrocarbon Partners, Ltd. (filed as Exhibit 10.23). /(1)/
10.7 1996 Incentive Compensation Plan (filed as Exhibit 10.25). /(1)/
10.8 1996 Stock Incentive Plan (filed as Exhibit 10.26). /(1)/
10.9 1996 Non-employee Director Stock Option Plan (filed as Exhibit 10.27). /(1)/
10.10 Form of Non-Compete Agreement between John M. Fox and MarkWest Hydrocarbon, Inc. (filed as Exhibit 10.28). /(1)/
10.11 Pipeline Construction and Operating Agreement between Michigan Production Company, L.L.C. and West Shore Processing Company, L.L.C., dated October 1, 1996 (filed as Exhibit 10.31). /(2)/
10.12 Option and Agreement to Purchase and Sell Pipeline, dated October 1, 1996 (filed as Exhibit 10.34). /(2)/
10.13 Amendment to Participation, Ownership and Operating Agreement for West Shore Processing Company, L.L.C., dated December 12, 1996 (filed as Exhibit 10.36). /(2)/
10.14 Amended and Restated Credit Agreement, dated as of June 20, 1997, among MarkWest Hydrocarbon, Inc., as the Borrower; and Certain Commercial Lending Institutions as the Lenders; and Bank of Montreal, acting through certain U.S. branches or agencies, as the Agent for the Lenders (filed as Exhibit 10.1 to MarkWest Hydrocarbon, Inc.'s Form 10-Q for the three months ended June 30, 1997, and incorporated herein by reference).
10.15 MarkWest Hydrocarbon, Inc., 1997 Severance and Non-Compete Plan (filed as Exhibit 10.1 to MarkWest Hydrocarbon, Inc.'s Form 10- Q for the three months ended September 30, 1997, and incorporated herein by reference).
10.16 First Amendment dated as of December 24, 1997, to the Amended and Restated Credit Agreement dated as of June 20, 1997, between MarkWest Hydrocarbon, Inc., as the Borrower; and Certain Commercial Lending Institutions as the Lenders; and Bank of Montreal, acting through certain U.S. branches or agencies, as the Agent for the Lenders (filed as Exhibit 10.26) /(3)/
10.17 Second Amendment dated as of May 6, 1998, to the Amended and Restated Credit Agreement dated as of June 20, 1997, between MarkWest Hydrocarbon, Inc., as the Borrower; and Certain Commercial Lending Institutions as the Lenders; and Bank of Montreal, acting through certain U.S. branches or agencies, as the Agent for the Lenders (filed as Exhibit 10.1 to MarkWest Hydrocarbon, Inc.'s Form 10-Q for the three months ended June 30, 1998, and incorporated herein by reference).
11. Statement regarding computation of earnings per share.
21. List of Subsidiaries of MarkWest Hydrocarbon, Inc.
23. Consent of PricewaterhouseCoopers LLP.
27. Financial Data Schedule.
________________________
/(1)/ Incorporated by reference to MarkWest Hydrocarbon, Inc.'s Registration Statement on Form S-1, Registration No. 333-09513. /(2)/ Incorporated by reference to MarkWest Hydrocarbon, Inc.'s Form 10-K for the year ended December 31, 1996. /(3)/ Incorporated by reference to MarkWest Hydrocarbon, Inc.'s Form 10-K for the year ended December 31, 1997.
SIGNATURES
Pursuant to the requirements of section 13 or 15(d) 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, in the City of Englewood, State of Colorado, on March 24, 1999.
MarkWest Hydrocarbon, Inc. (Registrant)
BY: /s/ John M. Fox --------------------------- John M. Fox President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
/s/ John M. Fox March 24, 1999 ---------------------------- John M. Fox President, Chief Executive Officer and Director
/s/ Brian T. O'Neill March 24, 1999 ---------------------------- Brian T. O'Neill Senior Vice President, Chief Operating Officer and Director
/s/ Gerald A. Tywoniuk March 24, 1999 ---------------------------- Gerald A. Tywoniuk Chief Financial Officer and Vice President of Finance (Principal Financial and Accounting Officer)
/s/ Arthur J. Denney March 24, 1999 ---------------------------- Arthur J. Denney Director
/s/ Barry W. Spector March 24, 1999 ---------------------------- Barry W. Spector Director
/s/ David R. Whitney March 24, 1999 ---------------------------- David R. Whitney Director