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TABLE OF CONTENTS
INDEX TO FINANCIAL STATEMENTS
As filed with the Securities and Exchange Commission on January 12, 2004
Registration Statement No. 333-111339
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Post-Effective Amendment No. 1
To
Form S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933
MarkWest Energy Partners, L.P.
(Exact name of registrant as specified in its charter)
Delaware | 1311 | 27-0005456 | ||
(State or other jurisdiction of incorporation or organization) | (Primary Standard Industrial Classification Code Number) | (I.R.S. Employer Identification No.) |
155 Inverness Drive West, Suite 200
Englewood, Colorado 80112
(303) 290-8700
(Address, including zip code, and telephone number,
including area code, of registrant's principal executive offices)
Donald C. Heppermann
MarkWest Energy Partners, L.P.
155 Inverness Drive West, Suite 200
Englewood, Colorado 80112
(303) 290-8700
(Name, address, including zip code, and telephone number,
including area code, of agent for service)
Copies to:
David P. Oelman Jeffrey M. Cameron Vinson & Elkins L.L.P. 1001 Fannin, Suite 2300 Houston, Texas 77002-6760 (713) 758-2222 | Joshua Davidson Douglass M. Rayburn Baker Botts L.L.P. One Shell Plaza, 910 Louisiana Street Houston, Texas 77002-4995 (713) 229-1234 |
Approximate date of commencement of proposed sale to the public:
As soon as practicable after the effective date of this registration statement.
If any of the securities being registered on this Form are being offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act, check the following box: o
If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act of 1933, please check the following box and list the Securities Act of 1933 registration statement number of the earlier effective registration statement for the same offering. o
If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act of 1933, check the following box and list the Securities Act of 1933 registration statement number of the earlier effective registration statement for the same offering. o
If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act of 1933, check the following box and list the Securities Act of 1933 registration statement number of the earlier effective registration statement for the same offering. o
If delivery of the prospectus is expected to be made pursuant to Rule 434, please check the following box. o
The registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933, or until the registration statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.
Filed Pursuant to Rule 424(a)
Registration No. 333-111339
Subject to completion, dated January 12, 2004
The information in this prospectus is not complete and may be changed. The securities offered hereby may not be sold until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.
PROSPECTUS
1,148,000 Common Units
MarkWest Energy Partners, L.P.
Representing Limited Partner Interests
We are offering 1,100,444 common units and the selling unitholders named in this prospectus are offering 47,556 common units. We will not receive any proceeds from the sale of the common units by the selling unitholders. Our common units are traded on the American Stock Exchange under the symbol "MWE." On January 9, 2004, the last reported sale price of our common units on the American Stock Exchange was $39.89 per common unit.
Investing in the common units involves risks.
See "Risk Factors" beginning on page 17.
These risks include the following:
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- If we are unable to successfully integrate our recent or future acquisitions, our future financial performance may be negatively impacted.
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- Our indebtedness may limit our ability to borrow additional funds, make distributions to you or capitalize on acquisitions or other business opportunities.
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- We may not have sufficient cash after the establishment of cash reserves and payment of our general partner's fees and expenses to enable us to pay the minimum quarterly distribution.
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- We derive a significant portion of our revenues from our gas processing, transportation, fractionation and storage agreements with MarkWest Hydrocarbon, Inc. and its failure to satisfy its payment or other obligations under these agreements could reduce our revenues and cash flow and in turn reduce our ability to make distributions to our unitholders.
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- We depend upon third parties for the raw natural gas we process and the natural gas liquids we fractionate at our facilities, and any reduction in these quantities could reduce our ability to make distributions to our unitholders.
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- MarkWest Hydrocarbon, Inc. controls our general partner, which has sole responsibility for conducting our business and managing our operations. Our general partner and its affiliates are reimbursed for all direct and indirect expenses they incur on our behalf, which may be substantial and may reduce our ability to make distributions to unitholders.
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- MarkWest Hydrocarbon, Inc. and its affiliates have conflicts of interest and limited fiduciary responsibilities, which may permit them to favor their own interests to your detriment.
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- Unitholders have less ability to elect or remove management than holders of common stock in a corporation.
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- You may be required to pay taxes even if you do not receive any cash distributions.
PRICE $ PER COMMON UNIT
| Per Common Unit | Total | ||||
---|---|---|---|---|---|---|
Public offering price | $ | $ | ||||
Underwriting discount | $ | $ | ||||
Proceeds, before expenses, to MarkWest Energy Partners, L.P. | $ | $ | ||||
Proceeds, before expenses, to the selling unitholders | $ | $ |
We have granted the underwriters a 30-day option to purchase up to an additional 172,200 common units to cover over-allotments. The underwriters expect to deliver the common units to purchasers on or about , 2004.
Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.
A.G. Edwards & Sons, Inc. | RBC Capital Markets | |
McDonald Investments Inc. |
Prospectus dated , 2004
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This summary highlights information contained elsewhere in this prospectus. You should read the entire prospectus carefully, including the historical and pro forma financial statements and notes to those financial statements. You should read "Risk Factors" beginning on page 17 for more information about important factors that you should consider before buying common units. We include a glossary of some of the terms used in this prospectus as Appendix A.
References in this prospectus to the MarkWest Hydrocarbon Midstream Business refer to the assets of the MarkWest Hydrocarbon Midstream Business that were contributed to us in connection with our initial public offering, which represented substantially all of MarkWest Hydrocarbon's natural gas gathering and processing and NGL transportation, fractionation and storage businesses. References in this prospectus to "the Partnership," "we," "our," "us," or like terms refer to MarkWest Energy Partners, L.P., the issuer of securities in this offering. References in this prospectus to "MarkWest Hydrocarbon" refer to MarkWest Hydrocarbon, Inc. and its direct and indirect consolidated subsidiaries. We refer to natural gas liquids, such as propane, butanes and natural gasoline, as "NGLs" in this prospectus.
MARKWEST ENERGY PARTNERS, L.P.
We are a rapidly growing, independent midstream energy company engaged in the gathering, processing and transmission of natural gas, the transportation, fractionation and storage of NGLs and the gathering and transportation of crude oil. A substantial portion of our revenues and cash flow are generated by providing fee-based services to customers, which provides us with a relatively stable base of cash flows. We have three primary geographic areas of operation.
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- Appalachia. We are the largest processor of natural gas in the Appalachian basin, one of the country's oldest natural gas producing regions. Our Appalachian assets include five natural gas processing plants, 136 miles of NGL pipeline, a NGL fractionation plant and an 11 million-gallon underground NGL storage facility.
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- Southwest. We own an aggregate of 302 miles of natural gas gathering pipelines in 21 gathering systems in Texas, Oklahoma, Kansas, Louisiana, Mississippi and New Mexico. We also own a gas processing plant and four Texas intrastate gas transmission pipelines that transmit natural gas to power plants, municipalities and other large industrial end users.
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- Michigan. We own a 90-mile gas gathering pipeline and one natural gas processing plant in Michigan. We also own approximately 250 miles of intrastate crude oil gathering pipeline, which we refer to as the Michigan Crude Pipeline, the primary intrastate crude oil pipeline in Michigan.
In these three areas, we provide midstream services to our customers under four types of contracts. On a pro forma basis for the nine months ended September 30, 2003, we generated approximately 69% of our gross margin (revenue less cost of gas purchases) from contracts under which we charge fees for providing midstream services. Gross margin from these fee-based services is dependent on throughput volume and is typically less affected by short-term changes in commodity prices. The remainder of our gross margin is generated pursuant to percent-of-index, percent-of-proceeds and keep-whole contracts and is more affected by changes in commodity prices. For a more complete description of each of these contract types, please see "Management's Discussion and Analysis of Financial Condition and Results of Operations."
We have grown rapidly through acquisitions and construction and expansion of our assets. Since our initial public offering in May 2002, we have completed four acquisitions with an aggregate purchase price of approximately $112 million. We have financed these acquisitions primarily through borrowings under our credit facility. Our net income was $5.9 million for the nine months ended September 30,
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2003. On a pro forma basis, as adjusted for this offering and our recent acquisitions, including the Lubbock pipeline since its acquisition in September 2003, net income for the nine months ended September 30, 2003 would have been $5.0 million. Our earnings before income taxes, plus depreciation and amortization expense and interest expense, or EBITDA, was $13.8 million for the nine months ended September 30, 2003. On a pro forma basis, as adjusted for this offering and our recent acquisitions, including the Lubbock pipeline since its acquisition in September 2003, EBITDA for the nine months ended September 30, 2003 would have been $18.3 million. For a discussion of EBITDA and a reconciliation of EBITDA to net income, please read footnote (1) to "Summary Historical and Pro Forma Financial and Operating Data."
Restatement of Financial Results. The financial statements presented in this prospectus include our statements of operations and cash flows for the year ended December 31, 2002 on a combined basis. We completed our initial public offering as a partnership on May 24, 2002. Our Annual Report on Form 10-K for 2002 and the form of this prospectus dated December 30, 2003 presented our 2002 financial results separately for the periods prior to and following our initial public offering. In this prospectus, our 2002 results are presented under one combined column that includes our operations both before and after our initial public offering. Generally, this combination required simple addition of the previously bifurcated line items. In addition, in this prospectus we have recorded the elimination of deferred tax liabilities resulting from our conversion to partnership form in the Partnership's statement of operations. Such elimination was previously presented as an adjustment to the Partnership's capital. We are in the process of filing an amendment to our most recent Annual Report on Form 10-K, as well as the affected 2003 Quarterly Reports on Form 10-Q, to restate our financial statements for 2002 to reflect the adjustments described above and included in this prospectus.
The Partnership previously reported two separate statements of operations and of cash flows for the year ended December 31, 2002. One statement of operations and one statement of cash flows was presented for the period from January 1, 2002 through May 23, 2002 for the MarkWest Hydrocarbon Midstream Business prior to its conveyance to the Partnership on May 24, 2002. Another statement of operations and statement of cash flows was presented for the period from May 24, 2002 through December 31, 2002. The conveyance of the MarkWest Hydrocarbon Midstream Business from MarkWest Hydrocarbon to the Partnership represented a reorganization of entities under common control and was recorded at historical cost. Consequently, the Partnership has now determined that it should have combined these statements and presented them for the full year ended December 31, 2002.
In addition, the Partnership had previously only reported net income per limited partner unit for the period from May 24, 2002 through December 31, 2002. In its restated financial statements, the Partnership has restated net income per limited partner unit to report such amount for the year ended December 31, 2002. Further, the Partnership has now reported income per limited partner unit for the years ended December 21, 2001 and 2000. Finally, the elimination of the deferred tax liability resulting from our conversion to partnership form had previously been credited to the partners' capital portion of the Partnership's balance sheet without impacting our statement of operations. In our revised presentation, the elimination of the deferred tax liability is reflected in the statement of operations as a part of the provision (benefit) for income taxes, increasing net income by $17.2 million and income per unit by $3.86 and ultimately reflected in the partners' capital portion of the balance sheet. Accordingly, the adjustment results in no net change to the balance sheet of the Partnership.
Our independent auditors have issued an opinion with respect to this revised presentation, which is included in the financial pages of this prospectus. Please see "Prospectus Summary—Summary Historical and Pro Forma Financial and Operating Data," "MarkWest Historical and Pro Forma Financial and Operating Data," "Selected Historical and Pro Forma Operating Data" and all other audited and unaudited financial statements included herein.
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Acquisitions
Pinnacle Merger. On March 28, 2003, we completed the acquisition of Pinnacle Natural Gas Company, or Pinnacle. The aggregate purchase price of $39.9 million was comprised of $23.4 million in cash plus the assumption of $16.6 million of bank indebtedness. The assets are primarily located in Texas and include three lateral natural gas pipelines and 20 natural gas gathering systems. The three lateral natural gas pipelines consist of approximately 67 miles of pipeline that deliver natural gas under firm contracts to power plants. The 20 natural gas gathering systems gathered an aggregate of approximately 43.8 MMcf/d of natural gas for the nine months ended September 30, 2003, and have an capacity of approximately 72.0 MMcf/d. This acquisition provided us with a new area for growth in the Southwest and diversified our lines of business and revenues. In addition, the acquisition is expected to increase the stability of our cash flows because Pinnacle has a high percentage of fee-based lateral pipeline contracts.
Lubbock Pipeline Acquisition. Effective September 1, 2003, we completed the acquisition of an intrastate gas transmission pipeline and related assets near Lubbock, Texas, from Power-Tex Joint Venture, a subsidiary of ConocoPhillips, for $12.2 million in cash. This gas pipeline is the only connection between the Northern Natural Gas and El Paso interstate pipelines and the City of Lubbock. For the nine months ended September 30, 2003, the pipeline transported an average of approximately 48.9 MMcf/d to our customers, including the City of Lubbock, Texas Tech University, Xcel Energy and several other end-use consumers. The current capacity of this pipeline is approximately 135.0 MMcf/d. This acquisition allowed us to further expand our operations in the Southwest with an additional lateral system while providing an added source of fee-based cash flows.
Western Oklahoma Acquisition. On December 1, 2003, we completed the acquisition of substantially all of the assets of American Central Western Oklahoma Gas Company, LLC, which we refer to in this prospectus as the western Oklahoma acquisition, for approximately $37.9 million in cash. These assets include 167 miles of natural gas gathering pipeline, known as the Foss Lake gathering system, and the associated Arapaho gas processing plant in western Oklahoma. The Foss Lake gathering system, which has a current capacity of 65.0 MMcf/d, connects to approximately 270 wells. For the nine months ended September 30, 2003, the Foss Lake system gathered an average of approximately 51.3 MMcf/d. The Arapaho gas processing plant has a current capacity of 75.0 MMcf/d. Capacity on the gathering system can be expanded to 75.0 MMcf/d with additional compression. By establishing a presence in Oklahoma, this acquisition significantly expanded our Southwest operations.
Michigan Crude Pipeline Acquisition. On December 18, 2003, we completed the acquisition of approximately 250 miles of intrastate crude oil gathering pipeline, which we refer to in this prospectus as the Michigan Crude Pipeline, for $21.2 million in cash. The pipeline serves over 1,000 oil and gas wells on the Niagaran Reef Trend and has 487,000 barrels of storage capacity in 15 storage tanks. For the nine months ended September 30, 2003, the pipeline transported approximately 15,900 bpd of crude oil. This acquisition further diversifies our lines of business with crude oil gathering and transportation services and provides us with the opportunity to leverage off our existing infrastructure and personnel in Michigan while adding additional fee-based cash flows.
Other Recent Developments
Distribution Increase. On November 14, 2003, we paid our distribution of $0.64 per unit, or $2.56 per unit on an annualized basis, for the quarter ended September 30, 2003. This represented an increase of 10.3% from our distribution of $0.58 per unit for the prior quarter. Since our initial public offering in May 2002, we have increased our quarterly distribution 28.0% from $0.50 per unit to $0.64 per unit.
Bank Credit Facility. We amended and restated our bank credit agreement in December 2003 to increase the revolving credit facility from $75 million to $140 million, to eliminate the term loan facility
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and to extend the expiration date to November 30, 2006. We used a portion of this increased borrowing capacity to finance the western Oklahoma and the Michigan Crude Pipeline acquisitions. Upon completion of this offering, we expect to have available capacity of approximately $62 million under our credit facility. For a more complete description of our credit facility, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Description of the Credit Facility."
Management Transition. On November 1, 2003, Frank M. Semple became the President of our general partner, and on January 1, 2004, Mr. Semple became the Chief Executive Officer of our general partner. In each position, Mr. Semple replaces John M. Fox, who announced his retirement in October 2003. Mr. Fox remains Chairman of the board of directors of our general partner.
An investment in our common units involves risks associated with our business, our partnership structure and the tax characteristics of our common units. Please carefully read the risks relating to these matters described under "Risk Factors" beginning on page 17.
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- If we are unable to successfully integrate our recent or future acquisitions, our future financial performance may be negatively impacted.
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- Our indebtedness may limit our ability to borrow additional funds, make distributions to you or capitalize on acquisitions or other business opportunities.
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- We may not have sufficient cash after the establishment of cash reserves and payment of our general partner's fees and expenses to enable us to pay the minimum quarterly distribution.
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- A significant decrease in natural gas production in our areas of operation, due to the decline in production from existing wells, depressed commodity prices or otherwise, would reduce our ability to make distributions to our unitholders.
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- A material decrease in the supply of crude oil available for transport through our Michigan Crude Pipeline, or a significant decrease in the demand for refined products in the markets served by this pipeline could adversely affect our revenues and cash flow.
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- We derive a significant portion of our revenues from our gas processing, transportation, fractionation and storage agreements with MarkWest Hydrocarbon and its failure to satisfy its payment or other obligations under these agreements could reduce our revenues and cash flow and in turn reduce our ability to make distributions to our unitholders.
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- The fees charged to third parties under our gathering, processing, transmission, transportation, fractionation and storage agreements may not escalate sufficiently to cover increases in costs and the agreements may not be renewed or may be suspended in some circumstances, which would reduce our ability to make distributions to our unitholders.
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- We are exposed to the credit risk of our customers and counterparties, and a general increase in the nonpayment and nonperformance by our customers could reduce our ability to make distributions to our unitholders.
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- We may not be able to retain existing customers or acquire new customers, which would reduce our revenues and limit our future profitability.
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- Growing our business by constructing new pipelines and processing and treating facilities subjects us to construction risks and risks that natural gas supplies will not be available upon completion of the facilities.
Risks Inherent in Our Business
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- Our profitability is affected by the volatility of NGL product and natural gas prices.
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- Our business is subject to federal, state and local laws and regulations with respect to environmental, safety and other regulatory matters, and the violation of or the cost of compliance with such laws and regulations could adversely affect our profitability.
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- We are indemnified for liabilities arising from an ongoing remediation of property on which our facilities are located and our results of operation and our ability to make cash distributions to our unitholders could be adversely affected if the indemnifying party fails to perform its indemnification obligation.
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- Cost reimbursements and fees due our general partner may be substantial and reduce our cash available for distribution to you.
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- MarkWest Hydrocarbon and its affiliates have conflicts of interest and limited fiduciary responsibilities, which may permit them to favor their own interests to your detriment.
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- Unitholders have less ability to elect or remove management than holders of common stock in a corporation.
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- The control of our general partner may be transferred to a third party, and that third party could replace our current management team, in each case without unitholder consent.
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- Our general partner's absolute discretion in determining the level of cash reserves may adversely affect our ability to make cash distributions to our unitholders.
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- Our partnership agreement contains provisions which reduce the remedies available to unitholders for actions that might otherwise constitute a breach of fiduciary duty by our general partner.
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- We do not have any employees and rely solely on employees of MarkWest Hydrocarbon and its affiliates who serve as our agents.
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- We may issue additional common units without your approval, which would dilute your ownership interests.
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- Our general partner has a limited call right that may require you to sell your common units at an undesirable time or price.
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- You may not have limited liability if a court finds that unitholder action constitutes control of our business.
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- Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to entity-level taxation by states. If the IRS treats us as a corporation or we become subject to entity-level taxation for state tax purposes, it would reduce the amount of cash available for distribution.
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- A successful IRS contest of the federal income tax positions we take may adversely impact the market for our common units, and the costs of any contest will be borne by our unitholders and our general partner.
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- You may be required to pay taxes even if you do not receive any cash distributions.
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- Tax gain or loss on disposition of our common units could be different than expected.
Risks Related to Our Partnership Structure
Tax Risks to Common Unitholders
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- Tax-exempt entities, regulated investment companies and foreign persons face unique tax issues from owning common units that may result in adverse tax consequences to them.
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- We are a registered tax shelter. This may increase the risk of an IRS audit of us or a unitholder.
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- We will treat each purchaser of common units as having the same tax benefits without regard to the units purchased. The IRS may challenge this treatment, which could adversely affect the value of our common units.
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- You will likely be subject to state and local taxes in states where you do not live as a result of an investment in our common units.
Our competitive strengths include:
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- Strategic position in the Appalachian basin and Michigan. We are the largest processor of natural gas in Appalachia and we believe our significant presence and asset base there provides us with a competitive advantage in capturing new supplies of natural gas. Our recent acquisition of the Michigan Crude Pipeline allowed us to enter into the crude oil gathering and transportation business and significantly expanded our presence in Michigan. In addition to our natural gas gathering and processing operations, we are now the primary intrastate pipeline transporter of crude oil in Michigan. This gives us a competitive advantage over other higher cost crude oil transportation methods, such as trucking.
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- Growing presence in the Southwest. Our recent Pinnacle, Lubbock pipeline and western Oklahoma acquisitions allowed us to expand our presence in long-lived natural gas basins in the Southwest, particularly in Texas and Oklahoma. The Pinnacle gathering systems and western Oklahoma assets are strategically located in the East Texas and Permian basins and the Anadarko basin in Oklahoma. Each of these areas is undergoing significant development and exploration activities and provides us with an opportunity to capture additional supplies of natural gas. The lateral natural gas pipelines acquired in the Pinnacle acquisition and the Lubbock pipeline acquisition allowed us to establish natural gas transmission operations in Central and West Texas. We believe we can use our proven expertise in expanding and developing acquired assets to develop and expand our presence in the Southwest.
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- Proven acquisition expertise. Since our initial public offering in May 2002, we have completed four acquisitions with an aggregate purchase price of approximately $112 million. We intend to use our experience in acquiring assets to grow through accretive acquisitions, focusing on opportunities in which we can improve volumes and cash flows.
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- Stable cash flows. On a pro forma basis for the nine months ended September 30, 2003, we generated approximately 69% of our gross margin from fee-based contracts providing natural gas gathering, processing and transmission services, NGL transportation, fractionation and storage services and crude oil gathering and transportation services. These fee-based services are dependent on throughput volume, but are typically not affected by short-term changes in commodity prices and provide us with a relatively stable base of cash flows.
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- Long-term contracts. On a pro forma basis for the nine months ended September 30, 2003, in excess of 80% of our gross margin was derived from contracts with remaining terms of two years or more. Pursuant to our contracts with MarkWest Hydrocarbon and Equitable Production Company, we process substantially all of the natural gas delivered into two of the three largest gathering systems in Appalachia and fractionate the NGLs extracted from such gas. These contracts have remaining terms ranging from six to 13 years. In Michigan, our natural gas transportation, treating and processing agreements have terms for the life of the wells. In conjunction with our Pinnacle assets, we have two significant, fixed fee contracts for the
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- Experienced management with operational and engineering expertise. Each member of our management team has at least 19 years of experience in the energy industry and our facility managers have extensive experience operating many of our facilities. Our technical and operational expertise has enabled us to upgrade existing facilities, as well as design and build new facilities.
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- Financial flexibility. Upon completion of this offering, we expect to have available borrowing capacity of approximately $62 million under our $140 million credit facility. This facility, together with our ability to issue additional partnership units for financing and acquisition purposes, should provide us with a flexible financial structure that will facilitate the execution of our business strategy.
transmission of natural gas that expire in 19 and 29 years. Our two largest customer contracts related to the Lubbock pipeline run through 2005 and 2008. Approximately 90% of our daily throughput in the Foss Lake gathering system in western Oklahoma is pursuant to contracts with remaining terms of five or more years.
Our primary strategy is to increase distributable cash flow per unit by:
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- Increasing utilization of our facilities. We seek to capture additional natural gas and crude oil production from existing customers and provide services to other natural gas and crude oil producers in our areas of operation. With our current excess capacity, we can increase throughput at our facilities with minimal incremental costs.
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- Expanding operations through new construction. By leveraging our existing infrastructure and customer relationships, we intend to continue expanding our asset base in our primary areas of operation to meet the anticipated need for additional midstream services.
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- Expanding operations through acquisitions. We intend to continue to pursue strategic acquisitions of assets and businesses in our existing areas of operation in order to leverage our current asset base, personnel and customer relationships. In addition, we seek to acquire assets outside of our existing areas of operation with a view towards creating new primary operating areas and to provide geographic and customer diversification.
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- Securing additional long-term, fee-based contracts. We intend to continue to secure long-term, fee-based contracts in both our existing operations and strategic acquisitions. While fee-based arrangements are dependent on throughput volume, they are typically less affected by short-term changes in commodity prices than other contractual arrangements in our industry.
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PARTNERSHIP STRUCTURE AND MANAGEMENT
Our operations are conducted through, and our operating assets are owned by, our subsidiaries. We own all of our subsidiaries through MarkWest Energy Operating Company, L.L.C. Upon completion of this offering:
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- The public unitholders will own a 55.5% limited partner interest in us, represented by 3,914,202 common units.
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- MarkWest Hydrocarbon will own 2,468,129 subordinated units and officers of our general partner and officers and key employees of MarkWest Hydrocarbon will own an aggregate of 31,871 subordinated units, totaling an aggregate 35.4% limited partner interest in us.
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- MarkWest Energy GP, L.L.C., our general partner, will continue to own a 2% general partner interest in us, as well as the "incentive distribution rights," which entitle it to receive increasing percentages, up to 50%, of any cash we distribute in excess of $0.55 per unit in any quarter.
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- MarkWest Hydrocarbon will continue to own a 89.7% interest in MarkWest Energy GP, L.L.C., our general partner. Officers of our general partner and officers and key employees of MarkWest Hydrocarbon will continue to own the remaining 10.3% interest in MarkWest Energy GP, L.L.C.
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- We own all of the membership interests in the operating company.
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- The operating company owns 100% of its various subsidiary companies.
Our general partner is entitled to distributions on its general partner interest and, if any, on its incentive distribution rights. Our general partner has sole responsibility for conducting our business and for managing our operations. Our general partner does not receive any management fee or other compensation in connection with its management of our business but is entitled to be reimbursed for all direct and indirect expenses incurred on our behalf.
Our principal executive offices are located at 155 Inverness Drive West, Suite 200, Englewood, Colorado 80112, and our phone number is (303) 290-8700.
The chart on the following page depicts the organization and ownership of MarkWest Energy Partners, L.P. and the operating company after giving effect to this offering.
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Common units offered by MarkWest Energy Partners, L.P. | 1,100,444 common units. | |||
1,272,644 common units if the underwriters exercise their over-allotment option in full. | ||||
Common units offered by the selling unitholders | 47,556 common units. For information about the selling unitholders, please read "Selling Unitholders." | |||
Units outstanding after this offering | 3,914,202 common units and 3,000,000 subordinated units, representing a 55.5% and 42.5% limited partner interest in MarkWest Energy Partners, L.P. | |||
Use of proceeds | We intend to use all of the net proceeds we receive from this offering to repay a portion of the borrowings under our bank credit facility incurred in connection with recent acquisitions. Please read "Use of Proceeds." | |||
Cash distributions | Common units are entitled to receive quarterly distributions of $0.50 per common unit prior to any distributions on the subordinated units to the extent we have sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to our general partner. In general, we pay any cash distributions we make each quarter in the following manner: | |||
• | first, 98% to the common units and 2% to our general partner, until each common unit has received a minimum quarterly distribution of $0.50 plus any arrearages from prior quarters; | |||
• | second, 98% to the subordinated units and 2% to our general partner, until each subordinated unit has received a minimum quarterly distribution of $0.50; and | |||
• | third, 98% to all units, pro rata, and 2% to our general partner, until each unit has received a distribution of $0.55 per quarter. | |||
If cash distributions exceed $0.55 per unit in a quarter, our general partner receives increasing percentages, up to 50%, of the cash we distribute in excess of that amount. We refer to these distributions as "incentive distributions." Because our distribution for the third quarter 2003 was $0.64 per unit, our general partner is receiving incentive distributions. | ||||
We must distribute all of our cash on hand at the end of each quarter, less reserves established by our general partner. We refer to this cash available for distribution as "available cash," and we define its meaning in our partnership agreement and in the glossary in Appendix A. The amount of available cash may be greater than or less than the minimum quarterly distribution. | ||||
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Timing of distributions | We pay distributions approximately 45 days after March 31, June 30, September 30 and December 31 to unitholders of record on the applicable record date and to our general partner. | |||
Subordination period and early conversion of subordinated units | The subordination period will end once we meet the financial tests in the partnership agreement, but it generally cannot end before June 30, 2009. When the subordination period ends, all subordinated units will convert into common units on a one-for-one basis, and the common units will no longer be entitled to arrearages. Our partnership agreement provides that subordinated units may convert into common units prior to June 30, 2009 in certain circumstances. Generally, the earliest possible date by which all subordinated units may be converted into common units is June 30, 2007. | |||
Issuance of additional units | In general, during the subordination period we can issue up to 1,207,500 additional common units without obtaining unitholder approval. We may, however, issue an unlimited number of common units for acquisitions, capital improvements or debt repayments that increase cash flow from operations per unit on a pro forma basis. We refer to acquisitions which increase cash flow from operations on a per unit basis as "accretive." | |||
Voting rights | Unlike the holders of common stock in a corporation, you will have only limited voting rights on matters affecting our business. You will have no right to elect our general partner or its directors on an annual or other continuing basis. Our general partner may not be removed except by a vote of the holders of at least 662/3% of the outstanding units, including any units owned by our general partner and its affiliates. Following the closing of this offering, our general partner and its affiliates will collectively own 36.2% of the outstanding units. | |||
Limited call right | If at any time more than 80% of the outstanding common units are owned by our general partner and its affiliates, our general partner has the right, but not the obligation, to purchase all of the remaining common units at a price not less than the then current market price of the common units. | |||
Estimated ratio of taxable income to distributions | We estimate that if you hold the common units you purchase in this offering through December 31, 2006, you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be no more than 20% of the cash distributed to you with respect to that period. | |||
Please read "Material Tax Consequences—Tax Consequences of Unit Ownership—Ratio of Taxable Income to Distributions" for the basis of this estimate. | ||||
Exchange listing | Our common units are listed on the American Stock Exchange under the symbol "MWE." |
11
SUMMARY HISTORICAL AND PRO FORMA FINANCIAL AND OPERATING DATA
The following table shows summary historical financial and operating data of the MarkWest Hydrocarbon Midstream Business and the Partnership as of and for the periods indicated and the summary pro forma financial and operating data of the Partnership as of September 30, 2003 and for the year ended December 31, 2002 and for the nine months ended September 30, 2003. The MarkWest Hydrocarbon Midstream Business represents substantially all of MarkWest Hydrocarbon's historical natural gas gathering and processing and NGL transportation, fractionation and storage businesses prior to the formation of the Partnership. The summary historical financial data for the MarkWest Hydrocarbon Midstream Business for the years ended December 31, 2000 and 2001 are derived from the audited financial statements of the MarkWest Hydrocarbon Midstream Business. The summary historical financial data for the Partnership for the year ended December 31, 2002 is derived from the audited financial statements of the Partnership. The summary historical financial data for the Partnership as of and for the nine months ended September 30, 2003 is derived from the unaudited financial statements of the Partnership and, in our opinion, has been prepared on the same basis as the audited financial statements and includes all adjustments, consisting of normal recurring adjustments, necessary for a fair presentation of this information.
Our unaudited pro forma balance sheet reflects the following transactions as if such transactions occurred as of September 30, 2003:
- •
- the western Oklahoma acquisition, which closed December 1, 2003;
- •
- the Michigan Crude Pipeline acquisition, which closed December 18, 2003;
- •
- borrowings of $59.5 million under our credit facility to finance these acquisitions; and
- •
- this offering and the use of the proceeds therefrom.
Our unaudited pro forma condensed consolidated statements of operations for the nine months ended September 30, 2003 and for the year ended December 31, 2002 reflect each of the above transactions and the following additional transactions as if all such transactions occurred on January 1, 2002:
- •
- the Pinnacle acquisition, which closed March 28, 2003;
- •
- borrowings of $39.9 million under our credit facility to finance the Pinnacle acquisition; and
- •
- our private placement in June 2003 of 375,000 common units, the net proceeds from which were used to repay indebtedness.
In addition, our unaudited pro forma condensed consolidated statement of operations for the year ended December 31, 2002 reflects the combination of our business and the MarkWest Hydrocarbon Midstream Business, our initial public offering and the transactions related to the formation of our partnership as if such transactions occurred on January 1, 2002.
The financial information presented below includes our financial and operating results for the year ended December 31, 2002 on a combined basis which have been restated. We completed our initial public offering as a partnership on May 24, 2002. Our 2002 Annual Report on Form 10-K and the form of this prospectus dated December 30, 2003 presented our 2002 financial results separately for the periods prior to and following our initial public offering. In this prospectus, our 2002 results are presented under one combined column that includes our operations both before and after our initial public offering. Generally, this combination required simple addition of the previously bifurcated line items. In addition, in this prospectus we have recorded the elimination of deferred tax liabilities resulting from our conversion to partnership form in the Partnership's statement of operations. Such elimination was previously presented as an adjustment to the Partnership's capital. In our revised presentation, the elimination of the deferred tax liability is reflected in the statement of operations as a part of the provision (benefit) for income taxes, increasing net income by $17.2 million and income per
12
unit by $3.86. We are in the process of filing an amendment to our most recent Annual Report on Form 10-K, as well as the affected 2003 Quarterly Reports on Form 10-Q, to restate our financial statements for 2002 to reflect the adjustments described above and included in this prospectus.
The historical financial statements for all periods prior to the formation of the Partnership differ substantially from our financial statements and unaudited pro forma financial statements, principally because of the contracts we entered into with MarkWest Hydrocarbon at the closing of our initial public offering. The largest of these differences is in revenues and purchased product costs. Historically, revenues and purchased product costs in the MarkWest Hydrocarbon Midstream Business were higher because:
- •
- its revenues included the aggregate sales price for all the NGL products produced in its operations; and
- •
- its purchased product costs included the cost of natural gas purchases needed to replace the Btu content of the NGLs extracted in its processing operations and the percentage of the proceeds from the sale of NGL products remitted to producers under percent-of-proceeds contracts.
In contrast, after entering into the new contractual arrangements,
- •
- our revenues related to these assets include just the fees we receive for processing natural gas, transporting, fractionating and storing NGLs and the aggregate proceeds from NGL sales we receive under our percent-of-proceeds contracts; and
- •
- our purchased product costs related to these assets primarily consist of the percentage of proceeds from the sale of NGL products remitted to producers under our percent-of-proceeds contracts, with a small portion of our purchased product costs attributable to natural gas purchases to satisfy our obligations under our keep-whole contracts.
Sustaining capital expenditures are capital expenditures made to replace partially or fully depreciated assets in order to maintain the existing operating capacity of our assets and to extend their useful lives. Expansion capital expenditures are capital expenditures made to expand the existing operating capacity of our assets, whether through construction or acquisition. We treat repair and maintenance expenditures that do not extend the useful life of existing assets as facility expenses as we incur them.
We derived the information in the following table from, and that information should be read together with and is qualified in its entirety by reference to, the historical and pro forma financial statements and the accompanying notes included elsewhere in this prospectus. The table should be read together with "Management's Discussion and Analysis of Financial Condition and Results of Operations."
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| | | Partnership | ||||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| MarkWest Hydrocarbon Midstream Business | ||||||||||||||||||||
| | | Pro Forma | ||||||||||||||||||
| Year Ended December 31, | Nine Months Ended September 30, 2003 | | Nine Months Ended September 30, 2003 | |||||||||||||||||
| Year Ended December 31, 2002 | ||||||||||||||||||||
| 2000 | 2001 | 2002(1) | ||||||||||||||||||
| (in thousands) | ||||||||||||||||||||
Statement of Operations Data: | |||||||||||||||||||||
Total revenues | $ | 109,810 | $ | 93,675 | $ | 70,246 | $ | 78,741 | $ | 125,688 | $ | 130,028 | |||||||||
Operating expenses: | |||||||||||||||||||||
Purchased product costs | 71,341 | 65,483 | 38,906 | 45,325 | 68,440 | 85,170 | |||||||||||||||
Facility expenses | 13,224 | 13,138 | 15,101 | 14,900 | 23,427 | 19,295 | |||||||||||||||
Selling, general and administrative expenses | 4,733 | 5,047 | 5,283 | 4,814 | 9,311 | 5,980 | |||||||||||||||
Depreciation | 4,341 | 4,490 | 4,980 | 5,231 | 10,347 | 9,256 | |||||||||||||||
Management fee | — | — | — | — | 1,867 | 1,400 | |||||||||||||||
Impairment expense | — | — | — | — | 1,672 | — | |||||||||||||||
Gain on sale of assets | — | — | — | — | (109 | ) | — | ||||||||||||||
Total operating expenses | 93,639 | 88,158 | 64,270 | 70,270 | 114,955 | 121,101 | |||||||||||||||
Income from operations | 16,171 | 5,517 | 5,976 | 8,471 | 10,733 | 8,927 | |||||||||||||||
Interest expense, net | (1,697 | ) | (1,307 | ) | (1,414 | ) | (2,592 | ) | (4,239 | ) | (3,985 | ) | |||||||||
Miscellaneous income (expense) | — | — | 52 | 51 | (92 | ) | 69 | ||||||||||||||
Income before income taxes | 14,474 | 4,210 | 4,614 | 5,930 | 6,402 | 5,011 | |||||||||||||||
Provision (benefit) for income taxes | 5,693 | 1,624 | (17,175 | ) | — | — | — | ||||||||||||||
Net income | $ | 8,781 | $ | 2,586 | $ | 21,789 | $ | 5,930 | $ | 6,402 | $ | 5,011 | |||||||||
Net income per limited partner unit | $ | 4.86 | $ | 1.04 | (1) | $ | 0.91 | $ | 0.70 | ||||||||||||
Balance Sheet Data (at period end): | |||||||||||||||||||||
Working capital | $ | 6,047 | $ | 18,240 | $ | 1,762 | $ | 1,880 | $ | 1,880 | |||||||||||
Property, plant and equipment, net | 77,501 | 82,008 | 79,824 | 126,177 | 185,662 | ||||||||||||||||
Total assets | 95,520 | 104,891 | 87,709 | 142,290 | 201,775 | ||||||||||||||||
Total debt, including debt due to parent | 20,782 | 19,179 | 21,400 | 61,300 | 78,432 | ||||||||||||||||
Capital/partnership equity | 50,751 | 65,429 | 60,863 | 67,441 | 109,794 | ||||||||||||||||
Cash Flow Data: | |||||||||||||||||||||
Net cash flow provided by (used in): | |||||||||||||||||||||
Operating activities | $ | 13,997 | $ | (524 | ) | $ | 33,502 | $ | 16,440 | ||||||||||||
Investing activities | (12,147 | ) | (8,997 | ) | (2,056 | ) | (52,391 | ) | |||||||||||||
Financing activities | (1,850 | ) | 9,521 | (28,670 | ) | 39,548 | |||||||||||||||
Other Financial Data: | |||||||||||||||||||||
EBITDA(2) | $ | 20,512 | $ | 10,007 | $ | 11,008 | $ | 13,753 | $ | 20,988 | $ | 18,252 | |||||||||
Sustaining capital expenditures | $ | 955 | $ | 576 | $ | 511 | $ | 691 | |||||||||||||
Expansion capital expenditures | 11,192 | 9,075 | 1,634 | 1,243 | |||||||||||||||||
Total capital expenditures | $ | 12,147 | $ | 9,651 | $ | 2,145 | $ | 1,934 | |||||||||||||
Operating Data: | |||||||||||||||||||||
Natural gas processed (Mcf/d)(3) | 196,000 | 192,000 | 202,000 | 198,000 | 251,000 | (4) | 249,000 | (4) | |||||||||||||
Pipeline throughput (Mcf/d) | 11,000 | 8,800 | 13,800 | 15,700 | 107,100 | (5) | 110,800 | (5) | |||||||||||||
NGL product production (gallons/day) | 406,000 | 423,000 | 476,000 | 449,000 | 476,000 | 449,000 | |||||||||||||||
NGL sales (gallons) | 9,200,000 | 8,000,000 | 11,075,000 | 9,112,000 | 11,075,000 | 9,112,000 |
- (1)
- As Restated. See Note 15 to the December 31, 2002 consolidated and combined financial statements of MarkWest Energy Partners, L.P. and Note 12 to the September 30, 2003 condensed consolidated and combined financial statements of MarkWest Energy Partners, L.P.
- (2)
- EBITDA is defined as income before income taxes, plus depreciation and amortization expense and interest expense. We present EBITDA on a partnership basis which includes both the general and limited partner interests. EBITDA (i) is not a measure of performance calculated in accordance with generally accepted accounting principles, or GAAP, and (ii) should not be considered in isolation or as a substitute for net income, income from operations or cash flow as reflected in our financial statements.
EBITDA is presented because such information is relevant and is used by management, industry analysts, investors, lenders and rating agencies to assess the financial performance and operating results of our fundamental business activities. Management believes that the presentation of EBITDA is useful to lenders and investors because of its use in the midstream natural gas industry and for master limited partnerships as an indicator of the strength and performance of our ongoing business operations, including the ability to fund capital expenditures, service debt and pay distributions. Additionally, management believes that EBITDA provides additional and useful information to our investors for trending, analyzing and benchmarking our operating results from period to period as compared to other companies that may have different financing and capital structures. The presentation of EBITDA allows investors to view our performance in a manner similar to the methods used by management and provides additional insight to our operating results.
EBITDA is used by management to determine our operating performance, and along with other data as internal measures for setting annual operating budgets, assessing financial performance of our numerous business locations, as a measure for
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evaluating targeted businesses for acquisition and as a measurement component of incentive compensation. We have a number of business locations located in different regions of the United Sates. EBITDA can be a meaningful measure of financial performance because it excludes factors which are outside the control of the employees responsible for operating and managing the business locations, and provides information management can use to evaluate the performance of the business locations, or the region where they are located, and the employees responsible for operating them.
There are material limitations to using a measure such as EBITDA, including the difficulty associated with using it as the sole measure to compare the results of one company to another, and the inability to analyze certain significant items that directly affect a company's net income or loss. In addition, our calculation of EBITDA may not be consistent with similarly titled measures of other companies and should be viewed in conjunction with measurements that are computed in accordance with GAAP. EBITDA for the periods described herein is calculated in the same manner as presented by us in the past. Management compensates for these limitations by considering EBITDA in conjunction with its analysis of other GAAP financial measures, such as gross profit, net income, and cash flow from operating activities. A reconciliation of EBITDA to net income is presented below.
The following table reconciles EBITDA with our net income:
| | | Partnership | ||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| MarkWest Hydrocarbon Midstream Business | ||||||||||||||||||
| | | Pro Forma | ||||||||||||||||
| Year Ended December 31, | Nine Months Ended September 30, 2003 | | Nine Months Ended September 30, 2003 | |||||||||||||||
| Year Ended December 31, 2002 | ||||||||||||||||||
| 2000 | 2001 | 2002(1) | ||||||||||||||||
Net income | $ | 8,781 | $ | 2,586 | $ | 21,789 | $ | 5,930 | $ | 6,402 | $ | 5,011 | |||||||
Plus: | |||||||||||||||||||
Interest expense, net | 1,697 | 1,307 | 1,414 | 2,592 | 4,239 | 3,985 | |||||||||||||
Depreciation | 4,341 | 4,490 | 4,980 | 5,231 | 10,347 | 9,256 | |||||||||||||
Provision (benefit) for income taxes | 5,693 | 1,624 | (17,175 | ) | — | — | — | ||||||||||||
EBITDA | $ | 20,512 | $ | 10,007 | $ | 11,008 | $ | 13,753 | $ | 20,988 | $ | 18,252 | |||||||
- (3)
- Represents throughput from our Kenova, Cobb and Boldman processing plants.
- (4)
- Includes operating data for the Arapaho gas processing plant.
- (5)
- Includes operating data for the Appleby gathering system and the Foss Lake gathering system. Excludes operating data for the lateral pipelines acquired in the Pinnacle and Lubbock pipeline acquisitions.
15
SUMMARY OF CONFLICTS OF INTEREST AND FIDUCIARY RESPONSIBILITIES
MarkWest Energy GP, L.L.C., our general partner, has a legal duty to manage us in a manner beneficial to our unitholders. This legal duty originates in statutes and judicial decisions and is commonly referred to as a "fiduciary" duty. Because our general partner is owned in substantial part by MarkWest Hydrocarbon, however, its officers and directors also have fiduciary duties to manage the business of our general partner in a manner beneficial to MarkWest Hydrocarbon and its stockholders. The officers and directors of our general partner have significant relationships with, and responsibilities to, MarkWest Hydrocarbon. As a result of these relationships and others, conflicts of interest may arise in the future between us and our unitholders, on the one hand, and our general partner and its affiliates, on the other hand. For a more detailed description of the conflicts of interest and fiduciary responsibilities of our general partner, please read "Conflicts of Interest and Fiduciary Responsibilities."
Our partnership agreement limits the liability and reduces the fiduciary duties of our general partner to the unitholders. Our partnership agreement also restricts the remedies available to unitholders for actions that might otherwise constitute breaches of our general partner's fiduciary duty. By purchasing a common unit, you are treated as having consented to various actions contemplated in the partnership agreement and conflicts of interest that might otherwise be considered a breach of fiduciary or other duties under applicable state law.
16
Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. You should carefully consider the following risk factors together with all of the other information included in this prospectus in evaluating an investment in the common units.
If any of the following risks were actually to occur, our business, financial condition, or results of operations could be materially adversely affected. In that case, we might not be able to pay distributions on our common units, the trading price of our common units could decline and you could lose all or part of your investment.
Risks Inherent in Our Business
If we are unable to successfully integrate our recent or future acquisitions, our future financial performance may be negatively impacted.
Our future growth will depend in part on our ability to integrate our recent acquisitions, and our ability to make future acquisitions of assets and businesses at attractive prices. We recently completed the Pinnacle, western Oklahoma and Michigan Crude Pipeline acquisitions, which geographically expanded our operations into the Southwest, particularly Texas and Oklahoma, and expanded our operations in Michigan. For the nine months ended September 30, 2003, on a pro forma basis, the assets from these acquisitions would have generated approximately 39% of our pro forma revenue and 26% of our pro forma gross margin. We cannot assure you that we will successfully integrate these or any other acquisitions into our operations, or that we will achieve the desired profitability from such acquisitions. Failure to successfully integrate these substantial or future acquisitions could adversely affect our operations and cash flows available for distribution to our unitholders.
The integration of acquisitions with our existing business involves numerous risks, including:
- •
- difficulties in the assimilation of the assets and operations of the acquired businesses, especially if the assets acquired are in a new business segment or geographic area;
- •
- the loss of customers or key employees from the acquired businesses;
- •
- the diversion of management's attention from other business concerns; and
- •
- the failure to realize expected synergies and cost savings.
Further, unexpected costs and challenges may arise whenever businesses with different operations or management are combined, and we may experience unanticipated delays in realizing the benefits of an acquisition. Following an acquisition, we may discover previously unknown liabilities associated with the acquired business for which we have no recourse from the seller under applicable indemnification provisions or otherwise. If we consummate any future acquisition, our capitalization and results of operation may change significantly, and you will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and other resources.
Our acquisition strategy is based in part on our expectation of ongoing divestitures of assets within the midstream industry. A material decrease in such divestitures will limit our opportunities for future acquisitions and could adversely affect our operations and cash flows available for distribution to our unitholders.
Our indebtedness may limit our ability to borrow additional funds, make distributions to you or capitalize on acquisitions or other business opportunities.
Upon completion of this offering, we expect our total outstanding long-term indebtedness to be approximately $78 million, all under our $140 million bank credit facility. Payments of principal and
17
interest on the indebtedness will reduce the cash available for distribution on our units. Our credit facility contains various covenants limiting our ability to incur indebtedness, grant liens, engage in transactions with affiliates, make distributions to our unitholders and capitalize on acquisition or other business opportunities. It also contains covenants requiring us to maintain certain financial ratios and minimum tangible net worth. We are prohibited from making any distribution to unitholders if such distribution would cause a default or an event of default under our credit facility. Borrowings under our bank credit facility that are used to pay distributions to unitholders may not exceed $0.50 per unit outstanding during any consecutive 12-month period. Any subsequent refinancing of our current indebtedness or any new indebtedness could have similar or greater restrictions. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Description of Credit Facility" for a discussion of our credit facility.
We may not have sufficient cash after the establishment of cash reserves and payment of our general partner's fees and expenses to enable us to pay the minimum quarterly distribution.
We may not have sufficient available cash each quarter to pay the minimum quarterly distribution. Under the terms of our partnership agreement, we must pay our general partner's fees and expenses and set aside any cash reserve amounts before making a distribution to our unitholders. Our ability to pay the minimum quarterly distribution will depend upon a number of factors, some of which are beyond our control, including:
- •
- cash flow generated by our operations;
- •
- the costs of acquisitions, if any;
- •
- fluctuations in our working capital;
- •
- restrictions contained in our debt instruments and required payments of principal and interest on our debt;
- •
- our ability to make borrowings under our credit facility;
- •
- the level of capital expenditures we make;
- •
- prevailing economic conditions; and
- •
- the amount, if any, of cash reserves made by our general partner in its discretion.
Furthermore, you should be aware that our ability to pay the minimum quarterly distribution each quarter depends primarily on cash flow, including cash flow from financial reserves and working capital borrowings, and not solely on profitability, which is affected by non-cash items. Therefore, we may make cash distributions during periods when we record losses and may not make distributions during periods when we record profits.
A significant decrease in natural gas production in our areas of operation, due to the decline in production from existing wells, depressed commodity prices or otherwise, would reduce our ability to make distributions to our unitholders.
Our profitability is materially impacted by the volume of natural gas we gather, transmit and process and NGLs we transport and fractionate at our facilities. A material decrease in natural gas production in our areas of operation would result in a decline in the volume of natural gas delivered to our pipelines and facilities for gathering, transmitting and processing and NGLs delivered to our pipelines and facility for fractionation and transportation. The effect of such a material decrease would be to reduce our revenue and operating income and, therefore, our ability to make distributions to our unitholders. Fluctuations in energy prices can greatly affect production rates and investments by third parties in the development of new oil and natural gas reserves. Drilling activity generally decreases as oil and natural gas prices decrease. We have no control over the level of drilling activity in the areas of
18
operations, the amount of reserves underlying the wells and the rate at which production from a well will decline, sometimes referred to as the "decline rate." In addition, we have no control over producers or their production decisions, which are affected by, among other things, prevailing and projected energy prices, demand for hydrocarbons, the level of reserves, geological considerations, governmental regulation and the availability and cost of capital. Failure to connect new wells to our gathering systems would, therefore, result in the amount of natural gas we gather, transmit and process and the amount of NGLs we transport and fractionate being reduced substantially over time and could, upon exhaustion of the current wells, cause us to abandon our gathering systems and, possibly, cease gathering operations. Our ability to connect to new wells will be dependent on the level of drilling activity in our areas of operations and competitive market factors. As a consequence of such declines, our revenues and our ability to make distributions to unitholders would be materially adversely affected.
A material decrease in the supply of crude oil available for transport through our Michigan Crude Pipeline, or a significant decrease in demand for refined products in the markets served by this pipeline could adversely affect our revenues and cash flow.
The volume of crude oil we transport through our Michigan Crude Pipeline depends on the availability of attractively priced crude oil produced in the areas accessible to our crude oil pipeline. If there were a material decrease in the volume of crude oil shipped on the pipeline due to reduced production from our shippers, less expensive supplies of crude oil available to the markets served by our pipeline, competition from trucks or reduced demand for refined product, our revenues would be reduced unless we are able to raise our tariffs on the pipeline sufficiently to offset the revenues lost to the reduced volumes. Our ability to raise tariffs might be constrained by competitive market forces.
Likewise, a sustained decrease in demand for refined products in the markets served by our crude oil pipeline would adversely affect our revenues and cash flow. Factors that could lead to a decrease in market demand include:
- •
- a recession or other adverse economic condition that results in lower spending by consumers on gasoline, diesel fuel, and travel;
- •
- an increase in the market price of crude oil that leads to higher refined product prices;
- •
- higher fuel taxes or other governmental or regulatory actions that increase, directly or indirectly, the cost of gasoline or other refined products; and
- •
- a shift by consumers to more fuel-efficient or alternative fuel vehicles or an increase in fuel economy, whether as a result of technological advances by manufacturers, pending legislation proposing to mandate higher fuel economy, or otherwise.
We depend upon third parties for the raw natural gas we process and the NGLs we fractionate at our Appalachian facilities, and any reduction in these quantities could reduce our ability to make distributions to our unitholders.
We depend upon Columbia Natural Resources, Inc., or Columbia Resources, and Equitable Production Company, or Equitable, to provide a significant portion of the raw natural gas and NGLs for our processing, transportation, fractionation, and storage facilities in the Appalachian basin. For the nine months ended September 30, 2003, we received approximately 35% of the raw natural gas that we processed in the Appalachian basin from Columbia Resources and 18% from Equitable.
Raw natural gas from Columbia Resources, Equitable and the other third party producers are committed to us pursuant to our processing agreements with MarkWest Hydrocarbon and our contract with Equitable. The raw gas and NGLs committed to us by MarkWest Hydrocarbon are in turn committed to it pursuant to its agreements with third party producers. We depend on these contracts for our supply of natural gas and NGLs. Pursuant to these contracts, Columbia Resources, Equitable
19
and the other producers are under no obligation to deliver a specific quantity of raw natural gas or NGLs to our facilities. If Columbia Resources, Equitable or a significant number of other producers were to decrease materially the supply of raw natural gas or NGLs to our facilities for any reason, we could experience difficulty in replacing those lost volumes. Because our operating costs are primarily fixed, a reduction in the volumes of raw natural gas or NGLs delivered to us would result not only in a reduction of revenues but also a decline in net income and cash flow of similar or greater magnitude, which would reduce our ability to make distributions to our unitholders.
We derive a significant portion of our revenues from our gas processing, transportation, fractionation and storage agreements with MarkWest Hydrocarbon and its failure to satisfy its payment or other obligations under these agreements could reduce our revenues and cash flow and in turn reduce our ability to make distributions to our unitholders.
On a pro forma basis for the nine months ended September 30, 2003, MarkWest Hydrocarbon accounted for approximately 14% of our revenues and 41% of our gross margin. These revenues and margins are generated by the volumes of raw natural gas contractually committed to MarkWest Hydrocarbon by the Appalachian producers described above, and for which we will provide MarkWest Hydrocarbon processing, transportation, fractionation and storage services for a fee. We expect to derive a significant portion of our revenues and gross margin from the services we provide under our contracts with MarkWest Hydrocarbon for the foreseeable future. Any default or nonperformance by MarkWest Hydrocarbon of its contractual obligations to us could significantly reduce our revenues and cash flows and reduce our ability to make distributions to our unitholders. Thus, any factor or event adversely affecting MarkWest Hydrocarbon's business, creditworthiness or its ability to perform under its contracts with us or its other contracts related to our business could also adversely affect us.
The fees charged to third parties under our gathering, processing, transmission, transportation, fractionation and storage agreements may not escalate sufficiently to cover increases in costs and the agreements may not be renewed or may be suspended in some circumstances, which would reduce our ability to make distributions to our unitholders.
Our costs may increase at a rate greater than the rate that the fees that we charge to third parties increase pursuant to our contracts with them. Furthermore, third parties may not renew their contracts with us. Additionally, some third parties' obligations under their agreements with us may be permanently or temporarily reduced upon the occurrence of certain events, some of which are beyond our control, including force majeure events wherein the supply of either natural gas, NGLs or crude oil are curtailed or cut off. Force majeure events include (but are not limited to) revolutions, wars, acts of enemies, embargoes, import or export restrictions, strikes, lockouts, fires, storms, floods, acts of God, explosions, mechanical or physical failures of equipment or facilities of the Partnership or third parties. If the escalation of fees is insufficient to cover increased costs, if third parties do not renew or extend their contracts with us, or if any third party suspends or terminates its contracts with us, our ability to make distributions to our unitholders will be reduced.
We are exposed to the credit risk of our customers and counterparties, and a general increase in the nonpayment and nonperformance by our customers could reduce our ability to make distributions to our unitholders.
We are subject to risks of loss resulting from nonpayment or nonperformance by our customers. Any increase in the nonpayment and nonperformance by our customers could reduce our ability to make distributions to our unitholders.
We may not be able to retain existing customers or acquire new customers, which would reduce our revenues and limit our future profitability.
The renewal or replacement of existing contracts with our customers at rates sufficient to maintain current revenues and cash flows depends on a number of factors beyond our control, including
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competition from other pipelines, and the price of, and demand for, natural gas, NGLs and crude oil in the markets we serve. Our competitors include large oil, natural gas, refining and petrochemical companies, some of whom have greater financial resources and access to raw natural gas and NGL supplies than we do. Our Siloam fractionation facility competes for volumes of mixed NGLs with other facilities in the region. Additionally, our customers who gather gas through facilities that are not otherwise dedicated to us may develop their own processing and fractionation facilities in lieu of using our services. In addition, certain of our competitors may have advantages in competing for acquisitions or other new business opportunities because of their financial resources and access to raw natural gas and NGL supplies.
As a consequence of the increase in competition in the industry and volatility of natural gas prices, end-users and utilities are reluctant to enter into long-term purchase contracts. Many end-users purchase natural gas from more than one natural gas company and have the ability to change providers at any time. Some of these end-users also have the ability to switch between gas and alternative fuels in response to relative price fluctuations in the market. Because there are numerous companies of greatly varying size and financial capacity that compete with us in the marketing of natural gas, we often compete in the end-user and utilities markets primarily on the basis of price. The inability of our management to renew or replace our current contracts as they expire and to respond appropriately to changing market conditions could have a negative effect on our profitability.
Growing our business by constructing new pipelines and processing and treating facilities subjects us to construction risks and risks that natural gas supplies will not be available upon completion of the facilities.
One of the ways we intend to grow our business is through the construction of additions to our existing gathering systems and construction of new gathering, processing and treating facilities. Construction activities to replace our Cobb processing plant are expected to begin in the first quarter of 2004 at an estimated cost to us of $450,000. The construction of gathering, processing and treating facilities requires the expenditure of significant amounts of capital, which may exceed our expectations, and involves numerous regulatory, environmental, political and legal uncertainties. If we undertake these projects, we may not be able to complete them on schedule or at all or at the budgeted cost. Moreover, our revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if we build a new pipeline, the construction will occur over an extended period of time, and we will not receive any material increases in revenues until after completion of the project. Furthermore, we may have only limited natural gas supplies committed to these facilities prior to their construction. Moreover, we may construct facilities to capture anticipated future growth in production in a region in which anticipated production growth does not materialize. We may also rely on estimates of proved reserves in our decision to construct new pipelines and facilities, which may prove to be inaccurate because there are numerous uncertainties inherent in estimating quantities of proved reserves. As a result, new facilities may not be able to attract enough natural gas to achieve our expected investment return, which could adversely affect our results of operations and financial condition.
Our profitability is affected by the volatility of NGL product and natural gas prices.
The profitability of our natural gas processing and NGL fractionation operations is affected by volatility in prevailing NGL product and natural gas prices. Changes in the prices of NGL products correlate closely with changes in the price of crude oil. NGL product and natural gas prices have been subject to significant volatility in recent years in response to relatively minor changes in the supply and demand for NGL products and natural gas, market uncertainty and a variety of additional factors that are beyond our control, including:
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- the level of domestic oil, natural gas and NGL production;
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- imports of crude oil, natural gas and NGLs;
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- seasonality;
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- the condition of the United Stated economy;
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- political conditions in other oil-producing and natural gas-producing countries; and
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- domestic government regulation, legislation and policies.
The gross margin we realize under percent-of-proceeds and percent-of-index contracts is directly affected by changes in NGL product prices and natural gas prices, and is therefore more subject to volatility in commodity prices than our fee-based contracts. For the nine months ended September 30, 2003, approximately 24% of the NGLs we fractionated in Appalachia and all of the NGLs we extracted in Michigan were pursuant to contracts containing a percent-of-proceeds component and approximately 80% of the natural gas volumes we gathered were subject to percent-of-proceeds or percent-of-index contracts. In addition, our Arapaho plant processes natural gas pursuant to keep-whole contracts. On a pro forma basis for the nine months ended September 30, 2003, a $0.01 per gallon change in NGL prices would have impacted our gross margin by approximately $60,000 and a $0.10 per MMBtu change in natural gas prices would have impacted our gross margin by approximately $45,000. Additionally, changes in natural gas prices may indirectly impact our profitability since prices can influence drilling activity and well operations and thus the volume of gas we gather and process.
In the past, the prices of natural gas and NGLs have been extremely volatile, and we expect this volatility to continue. For example, during the nine months ended September 30, 2003, the NYMEX settlement price for the prompt month contract ranged from a high of $9.58 per MMBtu to a low of $4.43 per MMBtu. A composite of the Mt. Belvieu average NGLs price based upon our average NGLs composition during the nine months ended September 30, 2003, ranged from a high of approximately $0.82 per gallon to a low of approximately $0.47 per gallon.
We are subject to operating and litigation risks that may not be covered by insurance.
Our operations are subject to all operating hazards and risks incidental to processing, transporting, fractionating, and storing natural gas and NGLs and to transporting and storing crude oil. These hazards include:
- •
- damage to pipelines, plants, related equipment and surrounding properties caused by floods and other natural disasters;
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- inadvertent damage from construction and farm equipment;
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- leakage of crude oil, natural gas, NGLs and other hydrocarbons;
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- fires and explosions; and
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- other hazards, including those associated with high-sulfur content, or sour gas, that could also result in personal injury and loss of life, pollution and suspension of operations.
As a result, we may be a defendant in various legal proceedings and litigation arising from our operations. We may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies have increased substantially, and could escalate further. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. For example, insurance carriers are now requiring broad exclusions for losses due to war risk and terrorist acts. If we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on our financial position.
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Our business is subject to federal, state and local laws and regulations with respect to environmental, safety and other regulatory matters, and the violation of or the cost of compliance with such laws and regulations could adversely affect our profitability.
Our business is subject to the jurisdiction of numerous governmental agencies with respect to a wide range of environmental, safety and other regulatory matters. We could be adversely affected by increased costs due to more strict pollution control requirements or liabilities resulting from non-compliance with required operating or other regulatory permits. New environmental regulations might adversely impact our products and activities, including the gathering, processing, transportation, fractionation, and storage of raw natural gas and NGLs and the transportation and storage of crude oil. Federal and state agencies also could impose additional safety requirements, any of which could affect our profitability. In addition, we face the risk of accidental releases or spills associated with our operations, which could result in material costs and liabilities, including those relating to claims for damages to property and persons.
Furthermore, our gas gathering and crude oil transportation operations in Michigan are subject to regulation at the state level, which increases the costs of operating our pipeline facilities. Matters subject to regulation include rates on our natural gas pipelines, as well as service and safety on all our pipelines. In addition, our lateral pipelines in Texas and Oklahoma are subject to the jurisdiction of the Texas Railroad Commission and the Oklahoma Corporation Commission, respectively. Changes in state regulations, or our status under these regulations due to configuration changes in our operating facilities, that subject us to further regulation could have a material adverse effect on our financial condition.
We are indemnified for liabilities arising from an ongoing remediation of property on which our facilities are located and our results of operation and our ability to make cash distributions to our unitholders could be adversely affected if the indemnifying party fails to perform its indemnification obligation.
Columbia Gas is the previous or current owner of the property on which our Kenova, Boldman, Cobb and Kermit facilities are located and is the previous operator of our Boldman and Cobb facilities. Columbia Gas has been or is currently involved in investigatory or remedial activities with respect to the real property underlying the Boldman and Cobb facilities pursuant to an "Administrative Order by Consent for Removal Actions" entered into by Columbia Gas and the U.S. Environmental Protection Agency and, in the case of the Boldman facility, an "Agreed Order" with the Kentucky Natural Resources and Environmental Protection Cabinet. Please see "Business—Environmental Matters—Ongoing Remediation and Indemnification from Columbia Gas" for a more detailed description of these matters.
Columbia Gas has agreed to retain sole liability and responsibility for, and to indemnify MarkWest Hydrocarbon against, any environmental liabilities associated with these regulatory orders or the real property underlying these facilities to the extent such liabilities arose prior to the effective date of the agreements pursuant to which such properties were acquired or leased from Columbia Gas. At the closing of our initial public offering, MarkWest Hydrocarbon assigned us the benefit of its indemnity from Columbia Gas with respect to the Cobb, Boldman and Kermit facilities. While we are not a party to the agreement under which Columbia Gas agreed to indemnify MarkWest Hydrocarbon with respect to the Kenova facility, MarkWest Hydrocarbon has agreed to provide to us the benefit of its indemnity, as well as any other third-party environmental indemnity of which it is a beneficiary. MarkWest Hydrocarbon has also agreed to provide us an additional environmental indemnity pursuant to the terms of the omnibus agreement. Our results of operation and our ability to make cash distributions to our unitholders could be adversely affected if in the future either Columbia Gas or MarkWest Hydrocarbon fails to perform under the indemnification provisions of which we are the beneficiary.
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The amount of gas we process, gather and transmit or the crude oil we gather and transport may be reduced if the pipelines to which we deliver the natural gas or crude oil cannot or will not accept the gas or crude oil.
All of the natural gas we process, gather and transmit is delivered into pipelines for further delivery to end users. If these pipelines cannot or will not accept delivery of the gas due to downstream constraints on the pipeline, we will be forced to limit or stop the throughput of gas through our pipelines and processing systems. In addition, interruption of pipeline service upstream of our processing facilities would likewise limit or stop throughput through our processing facilities. Likewise, if the pipelines into which we deliver crude oil are interrupted, we will be limited in, or prevented from, conducting our crude oil transportation operations. Such interruptions or constraints on pipeline service may be caused by any number of factors beyond our control, including necessary and scheduled maintenance as well as unexpected damage to the pipeline. Since our revenues and gross margin depend upon the volumes of natural gas we process, gather and transmit, the throughput of NGLs through our transportation, fractionation and storage facilities and the volume of crude oil we gather and transport, any such limitation or reduction of volumes could result in a material reduction in our gross margin.
Our business would be adversely affected if operations at any of our facilities were interrupted.
Our operations are dependent upon the infrastructure that we have developed, including processing and fractionation plants, storage facilities and various means of transportation. Any significant interruption at these facilities or pipelines or our inability to transmit natural gas or NGLs, or transport crude oil to or from these facilities or pipelines for any reason would adversely affect our results of operations. Operations at our facilities could be partially or completely shut down, temporarily or permanently, as the result of any number of circumstances that are not within our control, such as:
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- unscheduled turnarounds or catastrophic events at our physical plants;
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- labor difficulties that result in a work stoppage or slowdown; and
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- a disruption in the supply of crude oil to our crude oil pipeline, natural gas to our processing plants or gathering pipelines, or a disruption in the supply of NGLs to our transportation pipeline and fractionation facility.
Our business and operations could be adversely affected by terrorist attacks.
On September 11, 2001, the United States was the target of terrorist attacks of unprecedented scope, and the United States and others instituted military action in response. Since the September 11th attacks, the U.S. government has issued public warnings that indicate that energy assets, specifically our nation's pipeline infrastructure, production facilities and transmission and distribution facilities, might be specific targets of terrorist organizations. The continued threat of terrorism and the impact of military and other actions will likely lead to increased volatility in prices for natural gas and oil and could affect the markets for our products. In addition, future acts of terrorism could be directed against companies operating in the Untied States, particularly those engaged in sectors essential to our economic prosperity, such as natural resources. These developments have subjected our operations to increased risk and, depending on their ultimate magnitude, could have a material adverse affect on our business.
Due to our lack of asset diversification, adverse developments in our gathering, processing, transportation, transmission, fractionation and storage business would reduce our ability to make distributions to our unitholders.
We rely exclusively on the revenues generated from our gathering, processing, transportation, transmission, fractionation and storage businesses. Due to our lack of asset diversification, an adverse development in one of these businesses would have a significantly greater impact on our financial condition and results of operations than if we maintained more diverse assets.
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Risks Related to Our Partnership Structure
Cost reimbursements and fees due our general partner may be substantial and reduce our cash available for distribution to you.
Payments to our general partner may be substantial and reduce the amount of available cash for distribution to unitholders. Prior to making any distribution on the common units, we reimburse our general partner for all expenses it incurs on our behalf. Our general partner has sole discretion in determining the amount of these expenses. Our general partner and its affiliates also may provide us other services for which we will be charged fees as determined by our general partner.
MarkWest Hydrocarbon and its affiliates have conflicts of interest and limited fiduciary responsibilities, which may permit them to favor their own interests to your detriment.
MarkWest Hydrocarbon and its affiliates own and control our general partner and our general partner owns a 2% general partner interest in us. Upon completion of this offering, MarkWest Hydrocarbon and its affiliates will own a 35.4% limited partner interest in us. The officers of our general partner and the officers and key employees of MarkWest Hydrocarbon own 10.3% of our general partner and 31,871 of our subordinated units. Conflicts of interest may arise between MarkWest Hydrocarbon and its affiliates, including our general partner, on the one hand, and us, on the other hand. As a result of these conflicts, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders. These conflicts include, among others, the following situations:
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- employees of MarkWest Hydrocarbon who provide services to us also devote significant time to the businesses of MarkWest Hydrocarbon and are compensated by MarkWest Hydrocarbon for these services;
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- neither our partnership agreement nor any other agreement requires MarkWest Hydrocarbon to pursue a future business strategy that favors us or utilizes our assets for processing, transportation or fractionation services we provide. MarkWest Hydrocarbon's directors and officers have a fiduciary duty to make these decisions in the best interests of the stockholders of MarkWest Hydrocarbon;
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- our general partner is allowed to take into account the interests of parties other than us, such as MarkWest Hydrocarbon, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders;
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- our general partner may limit its liability and reduce its fiduciary duties, while also restricting the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty. As a result of purchasing units, our unitholders consent to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable state law;
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- our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates, including the processing, transportation and fractionation agreements with MarkWest Hydrocarbon;
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- our general partner decides whether to retain separate counsel, accountants or others to perform services for us;
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- in some instances, our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a
Conflicts Relating to Control:
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- •
- our partnership agreement gives our general partner broad discretion in establishing financial reserves for the proper conduct of our business. These reserves also will affect the amount of cash available for distribution. Our general partner may establish reserves for distribution on the subordinated units, but only if those reserves will not prevent us from distributing the full minimum quarterly distribution, plus any arrearages, on the common units for the following four quarters.
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- our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, issuance of additional partnership securities and reserves, each of which can affect the amount of cash that is distributed to our unitholders;
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- our general partner determines which costs incurred by MarkWest Hydrocarbon and its affiliates are reimbursable by us; and
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- our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered on terms that are fair and reasonable to us or entering into additional contractual arrangements with any of these entities on our behalf.
distribution on the subordinated units or to make incentive distributions or to hasten the conversion of subordinated units; and
Conflicts Relating to Costs:
Please read "Certain Relationships and Related Transactions—Omnibus Agreement" and "Conflicts of Interest and Fiduciary Responsibilities—Conflicts of Interest."
Unitholders have less ability to elect or remove management than holders of common stock in a corporation.
Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business, and therefore limited ability to influence management's decisions regarding our business. Unitholders did not elect our general partner or its board of directors and will have no right to elect our general partner or its board of directors on an annual or other continuing basis.
The board of directors of our general partner is chosen by MarkWest Hydrocarbon and its affiliates. The directors of our general partner also have a fiduciary duty to manage our general partner in a manner beneficial to its members, MarkWest Hydrocarbon and its affiliates.
Furthermore, if unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. First, our general partner generally may not be removed except upon the vote of the holders of at least 662/3% of the outstanding units voting together as a single class. Because MarkWest Hydrocarbon and its affiliates will control 36.2% of all outstanding units upon completion of this offering, our general partner currently cannot be removed without the consent of MarkWest Hydrocarbon and its affiliates. Also, if our general partner is removed without cause during the subordination period and units held by MarkWest Hydrocarbon and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically be converted into common units and any existing arrearages on the common units will be extinguished. A removal under these circumstances would adversely affect the common units by prematurely eliminating their contractual right to distributions over the subordinated units, which would otherwise have continued until we had met certain distribution and performance tests.
Cause is narrowly defined to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding our general partner liable for actual fraud, gross negligence, or willful or wanton misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of the business, so the removal of our general partner because of the
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unitholders' dissatisfaction with our general partner's performance in managing our partnership will most likely result in the termination of the subordination period.
Furthermore, unitholders' voting rights are further restricted by the partnership agreement provision which states that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot be voted on any matter. In addition, the partnership agreement contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders' ability to influence the manner or direction of management.
These provisions may discourage a person or group from attempting to remove our general partner or otherwise change our management. As a result of these provisions, the price at which the common units will trade may be lower because of the absence or reduction of a takeover premium in the trading price.
The control of our general partner may be transferred to a third party, and that party could replace our current management team, in each case without unitholder consent.
Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, there is no restriction in the partnership agreement on the ability of the owners of our general partner from transferring their ownership interest in our general partner to a third party. The new owner of our general partner would then be in a position to replace the board of directors and officers of our general partner with its own choices and to control the decisions taken by the board of directors and officers.
Our general partner's absolute discretion in determining the level of cash reserves may adversely affect our ability to make cash distributions to our unitholders.
Our partnership agreement requires our general partner to deduct from operating surplus cash reserves that in its reasonable discretion are necessary to fund our future operating expenditures. In addition, the partnership agreement permits our general partner to reduce available cash by establishing cash reserves for the proper conduct of our business, to comply with applicable law or agreements to which we are a party or to provide funds for future distributions to partners. These cash reserves will affect the amount of cash available for distribution to our unitholders.
Our partnership agreement contains provisions which reduce the remedies available to unitholders for actions that might otherwise constitute a breach of fiduciary duty by our general partner.
Our partnership agreement limits the liability and reduces the fiduciary duties of our general partner to our unitholders. The partnership agreement also restricts the remedies available to unitholders for actions that would otherwise constitute breaches of our general partner's fiduciary duties. If you choose to purchase a common unit, you will be treated as having consented to the various actions contemplated in the partnership agreement and conflicts of interest that might otherwise be considered a breach of fiduciary duties under applicable state law. Please read "Conflicts of Interest and Fiduciary Responsibilities."
MarkWest Hydrocarbon and its affiliates may engage in competition with us.
MarkWest Hydrocarbon and its affiliates may engage in competition with us. Pursuant to the omnibus agreement, MarkWest Hydrocarbon and its affiliates have agreed not to engage in, whether by acquisition, construction or otherwise, the business of processing natural gas and transporting, fractionating and storing NGLs. These restrictions, however, do not apply to:
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- the gathering of natural gas;
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- any business operated by MarkWest Hydrocarbon or any of its subsidiaries at the closing of our initial public offering;
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- any business that MarkWest Hydrocarbon or any of its subsidiaries acquires or constructs that has a fair market value of less than $7.5 million;
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- any business that MarkWest Hydrocarbon or any of its subsidiaries acquires or constructs that has a fair market value of $7.5 million or more if we have been offered the opportunity to purchase the business for fair market value, and we decline to do so with the concurrence of the conflicts committee of our general partner; and
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- any business that MarkWest Hydrocarbon or any of its subsidiaries acquires or constructs where the fair market value of the restricted business is $7.5 million or more and represents less than 20% of the aggregate value of the entire business acquired or constructed; provided, however, that following completion of such acquisition or construction, we are provided the opportunity to purchase such restricted business, and we decline to do so with the concurrence of the conflicts committee of our general partner.
Upon a change of control of MarkWest Hydrocarbon or a sale of the general partner by MarkWest Hydrocarbon, the non-competition provisions of the omnibus agreement will terminate. Please read "Certain Relationships and Related Transactions—Omnibus Agreement" for a description of the non-competition provisions of the Omnibus Agreement.
We do not have any employees and rely solely on employees of MarkWest Hydrocarbon and its affiliates who serve as our agents.
We do not have any employees and rely solely on employees of MarkWest Hydrocarbon and its affiliates who serve as our agents. MarkWest Hydrocarbon and its affiliates conduct businesses and activities of their own in which we have no economic interest. If these separate activities are significantly greater than our activities, there could be material competition for the time and effort of the employees who provide services to our general partner. If the employees of MarkWest Hydrocarbon and its affiliates do not devote sufficient attention to the management and operation of our business, our financial results may suffer and our ability to make distributions to our unitholders may be reduced.
We may issue additional common units without your approval, which would dilute your ownership interests.
During the subordination period, our general partner, without the approval of our unitholders, may cause us to issue up to 1,207,500 additional common units. Our general partner may also cause us to issue an unlimited number of additional common units or other equity securities of equal rank with the common units, without unitholder approval, in a number of circumstances such as:
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- the issuance of common units in connection with acquisitions or capital improvements that increase cash flow from operations per unit on a pro forma basis (as is the case for this offering);
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- the conversion of subordinated units into common units;
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- the conversion of units of equal rank with the common units into common units under some circumstances;
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- the conversion of our general partner interest and the incentive distribution rights into common units as a result of the withdrawal of our general partner;
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- issuances of common units under our long-term incentive plan; or
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- issuances of common units to repay indebtedness the cost of which to service is greater than the distribution obligations associated with the units issued in connection with the debt's retirement.
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The issuance of additional common units or other equity securities of equal or senior rank will have the following effects:
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- our unitholders' proportionate ownership interest in us will decrease;
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- the amount of cash available for distribution on each unit may decrease;
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- because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;
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- the relative voting strength of each previously outstanding unit may be diminished; and
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- the market price of the common units may decline.
After the end of the subordination period, we may issue an unlimited number of limited partner interests of any type without the approval of our unitholders. Our partnership agreement does not give our unitholders the right to approve our issuance of equity securities ranking junior to the common units at any time.
Our general partner has a limited call right that may require you to sell your common units at an undesirable time or price.
If at any time more than 80% of the outstanding common units are owned by our general partner and its affiliates, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the remaining common units held by unaffiliated persons at a price not less than their then-current market price. As a result, you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your units. For additional information about the call right, please read "The Partnership Agreement—Limited Call Right."
You may not have limited liability if a court finds that unitholder action constitutes control of our business.
Under Delaware law, you could be held liable for our obligations to the same extent as a general partner if a court determined that the right or the exercise of the right by our unitholders as a group to remove or replace our general partner, to approve some amendments to the partnership agreement, or to take other action under our partnership agreement constituted participation in the "control" of our business.
Our general partner generally has unlimited liability for the obligations of the Partnership, such as its debts and environmental liabilities, except for those contractual obligations of the Partnership that are expressly made without recourse to our general partner.
In addition, Section 17-607 of the Delaware Revised Uniform Limited Partnership Act provides that, under some circumstances, a unitholder may be liable to us for the amount of a distribution for a period of three years from the date of the distribution.
Tax Risks to Common Unitholders
You should read "Material Tax Consequences" for a more complete discussion of the expected federal income tax consequences of owning and disposing of common units.
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Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to entity-level taxation by states. If the IRS treats us as a corporation or we become subject to entity-level taxation for state tax purposes, it would reduce the amount of cash available for distribution.
The anticipated after-tax benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter that affects us.
If we were classified as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rates, currently at a maximum rate of 35%, and would likely pay state income tax at varying rates. Distributions to our unitholders would generally be taxed again as corporate distributions, and no income, gain, loss or deduction would flow through to our unitholders. Treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our unitholders and therefore would likely result in a substantial reduction in the value of our common units.
Current law or our business may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation.
In addition, because of widespread state budget deficits, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. If any state were to impose a tax upon us as an entity, the cash available to pay distributions would be reduced. Our partnership agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, then the minimum quarterly distribution amount and the target distribution amount will be adjusted to reflect the impact of that law on us.
A successful IRS contest of the federal income tax positions we take may adversely impact the market for our common units, and the costs of any contests will be borne by our unitholders and our general partner.
We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter that affects us. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not concur with our counsel's conclusions or the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will result in a reduction in cash available for distribution to our unitholders and our general partner and thus will be borne indirectly by our unitholders and our general partner.
You may be required to pay taxes even if you do not receive any cash distributions.
Unitholders will be required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable income whether or not they receive cash distributions from us. Unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the tax liability that results from the taxation of their share of our taxable income.
Tax gain or loss on disposition of common units could be different than expected.
A unitholder who sells common units will recognize a gain or loss equal to the difference between the amount realized and the adjusted tax basis in those common units. Prior distributions to a unitholder in excess of the total net taxable income allocated to that unitholder, which decreased the tax basis in that unitholder's common unit, will, in effect, become taxable income to that unitholder if the common unit is sold at a price greater than that unitholder's tax basis in that common unit, even if the price is less than the original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income to that unitholder.
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Tax-exempt entities, regulated investment companies and foreign persons face unique tax issues from owning common units that may result in adverse tax consequences to them.
Investment in common units by tax-exempt entities, including employee benefit plans and individual retirement accounts (known as IRAs), regulated investment companies (known as mutual funds) and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, will be unrelated business taxable income and will be taxable to such a unitholder. Very little of our income will be qualifying income to a regulated investment company. Distributions to non-U.S. persons will be reduced by withholding taxes imposed at the highest effective applicable tax rate, and non-U.S. persons will be required to file United States federal income tax returns and pay tax on their share of our taxable income.
We are registered as a tax shelter. This may increase the risk of an IRS audit of us or a unitholder.
We are registered with the IRS as a "tax shelter." Our tax shelter registration number is 0218400024. The IRS requires that some types of entities, including some partnerships, register as "tax shelters" in response to the perception that they claim tax benefits that the IRS may believe to be unwarranted. As a result, we may be audited by the IRS and tax adjustments could be made. Any unitholder owning less than a 1% profits interest in us has very limited rights to participate in the income tax audit process. Further, any adjustments in our tax returns will lead to adjustments in our unitholders' tax returns and may lead to audits of unitholders' tax returns and adjustments of items unrelated to us. You will bear the cost of any expense incurred in connection with an examination of your personal tax return.
We will treat each purchaser of common units as having the same tax benefits without regard to the units purchased. The IRS may challenge this treatment, which could adversely affect the value of our common units.
Because we cannot match transferors and transferees of common units, we will adopt depreciation and amortization positions that may not conform with all aspects of existing Treasury regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain on the sale of common units and could have a negative impact on the value of our common units or result in audits of and adjustments to our unitholders' tax returns.
You will likely be subject to state and local taxes in states where you do not live as a result of an investment in our common units.
In addition to federal income taxes, you will likely be subject to other taxes, including state and local income taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property, even if you do not reside in any of those jurisdictions. You will likely be required to file state and local income tax returns and pay state and local income taxes in many or all of the jurisdictions. Further, you may be subject to penalties for failure to comply with those requirements. It is your responsibility to file all United States federal, state and local tax returns. Our counsel has not rendered an opinion on the state or local tax consequences of an investment in the common units.
31
We estimate that we will receive net proceeds of approximately $41.4 million from the sale of the 1,100,444 common units by us, together with a capital contribution from our general partner of approximately $0.9 million to maintain its 2% general partner interest in our partnership, assuming an offering price of $40.42 per unit and after deducting underwriting discounts and estimated offering expenses. We expect to use the net proceeds of this offering to repay a portion of the borrowings under our credit facility incurred in connection with our recent acquisitions. Please read "Prospectus Summary—Recent Developments—Acquisitions." We will use any net proceeds from the exercise of the over-allotment option to further repay borrowings under our credit facility.
As of December 1, 2003, total borrowings under our credit facility were approximately $101.3 million, with a weighted-average interest rate of 4.67%. Our credit facility has a maturity date of November 30, 2006. A total of $111.7 million was borrowed under our credit facility between May 2002 and September 2003 and used for acquisitions, including the Pinnacle, Lubbock pipeline, western Oklahoma and Michigan Crude Pipeline acquisitions.
We will not receive any proceeds from the sale of 47,556 common units by the selling unitholders.
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The following table sets forth our capitalization as of September 30, 2003 on:
- •
- a historical basis;
- •
- an as adjusted basis to reflect the western Oklahoma and Michigan Crude Pipeline acquisitions and the borrowings associated with these acquisitions; and
- •
- a pro forma basis to reflect the sale by us of 1,100,444 common units in this offering, our general partner's proportionate capital contribution and the application of the net proceeds from this offering in the manner described under "Use of Proceeds."
This table is derived from, should be read together with and is qualified in its entirety by reference to our historical and pro forma financial statements and the accompanying notes included elsewhere in this prospectus. You should also read this table in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations."
| As of September 30, 2003 | ||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Historical | As Adjusted For Acquisitions | Pro Forma | ||||||||||
| | (in thousands) | | ||||||||||
Revolving credit facility | $ | 61,300 | $ | 120,785 | $ | 78,432 | |||||||
Capital: | |||||||||||||
Common units | 51,977 | 51,977 | 93,422 | ||||||||||
Subordinated units | 15,439 | 15,439 | 15,439 | ||||||||||
General partner interest | 496 | 496 | 1,404 | ||||||||||
Accumulated other comprehensive income (loss) | (471 | ) | (471 | ) | (471 | ) | |||||||
Total capital | 67,441 | 67,441 | 109,794 | ||||||||||
Total capitalization | $ | 128,741 | $ | 188,226 | $ | 188,226 | |||||||
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PRICE RANGE OF COMMON UNITS AND DISTRIBUTIONS
Our common units are listed and traded on the American Stock Exchange under the symbol "MWE." Our common units began trading on May 21, 2002 at an initial public offering price of $20.50 per common unit. The following table shows the low and high sales prices per common unit, as reported by the American Stock Exchange, for the periods indicated. For each quarter, an identical cash distribution was paid on all outstanding subordinated units.
| Low | High | Cash Distributions Per Unit | ||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
Fiscal 2004: | |||||||||||
First quarter (through January 9, 2004) | $ | 38.87 | $ | 41.66 | $ | — | |||||
Fiscal 2003: | |||||||||||
Fourth quarter | $ | 34.05 | $ | 40.90 | $ | — | |||||
Third quarter | 29.55 | 35.98 | 0.64 | ||||||||
Second quarter | 25.30 | 32.50 | 0.58 | ||||||||
First quarter | 22.95 | 26.00 | 0.58 | ||||||||
Fiscal 2002: | |||||||||||
Fourth quarter | $ | 20.80 | $ | 23.50 | $ | 0.52 | |||||
Third quarter | 17.90 | 22.64 | 0.50 | ||||||||
Second quarter (from May 24, 2002) | 20.50 | 21.90 | 0.21 | (1) |
- (1)
- Reflects the pro rata portion of the $0.50 minimum quarterly distribution per unit, representing the period from the May 24, 2002 closing of our initial public offering through June 30, 2002.
The last reported sale price of the common units on the American Stock Exchange on January 9, 2004 was $39.89. As of January 9, 2004, there were approximately 116 holders of record of our common units.
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Distributions of Available Cash
General. Within approximately 45 days after the end of each quarter, we distribute all of our available cash to unitholders of record on the applicable record date.
Definition of Available Cash. We define available cash in the glossary, and it generally means, for each fiscal quarter:
- •
- all cash on hand at the end of the quarter;
- •
- less the amount of cash that our general partner determines in its reasonable discretion is necessary or appropriate to:
- •
- provide for the proper conduct of our business;
- •
- comply with applicable law, any of our debt instruments, or other agreements; or
- •
- provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters;
- •
- plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter. Working capital borrowings are generally borrowings that are made under our credit facility and in all cases are used solely for working capital purposes or to pay distributions to partners.
Minimum Quarterly Distribution. Common units are entitled to receive distributions from operating surplus of $0.50 per quarter, or $2.00 on an annualized basis, before any distributions are paid on our subordinated units. There is no guarantee that we will pay the minimum quarterly distribution on the common units in any quarter, and we are prohibited from making any distributions to unitholders if it would cause an event of default under our credit facility. As reflected below, our definition of operating surplus contains a $6.3 million basket. This basket is a provision that enables us, if we choose, to distribute as operating surplus up to $6.3 million of cash we receive in the future from non-operating sources, such as asset sales, issuances of securities and long-term borrowings, that would otherwise be distributed as capital surplus.
Contractual Restrictions on our Ability to Distribute Available Cash. Our ability to distribute available cash is contractually restricted by the terms of our credit facility. Our credit facility contains covenants requiring us to maintain certain financial ratios and a minimum net worth. We are prohibited from making any distribution to unitholders if such distribution would cause an event of default or otherwise violate a covenant under our credit facility. In addition, our credit facility prohibits us from borrowing more than $0.50 per outstanding unit during any consecutive 12-month period for the purpose of making distributions to our unitholders. We are in the process of amending this facility to provide that any amount so borrowed must be repaid once annually. Please see "Management's Discussion and Analysis of Financial Condition and Results of Operations—Description of Credit Facility."
Operating Surplus and Capital Surplus
General. All cash distributed to unitholders is characterized as either "operating surplus" or "capital surplus." We distribute available cash from operating surplus differently than available cash from capital surplus.
35
Definition of Operating Surplus. We define operating surplus in the glossary, and for any period it generally means:
- •
- $470,000 representing cash on hand at the closing of our initial public offering; plus
- •
- $6.3 million (as described above); plus
- •
- all of our cash receipts since the initial public offering, excluding cash from borrowings that are not working capital borrowings, sales of equity and debt securities and sales or other dispositions of assets outside the ordinary course of business; plus
- •
- working capital borrowings made after the end of a quarter but before the date of determination of operating surplus for the quarter; less
- •
- all of our operating expenditures since the initial public offering, including the repayment of working capital borrowings, but not the repayment of other borrowings, and including maintenance capital expenditures; and less
- •
- the amount of cash reserves that our general partner deems necessary or advisable to provide funds for future operating expenditures.
Definition of Capital Surplus. We also define capital surplus in the glossary, and it is generally generated only by:
- •
- borrowings other than working capital borrowings;
- •
- sales of debt and equity securities; and
- •
- sales or other disposition of assets for cash, other than inventory, accounts receivable and other current assets sold in the ordinary course of business or as part of normal retirements or replacements of assets.
Characterization of Cash Distributions. We treat all available cash distributed as coming from operating surplus until the sum of all available cash distributed since we began operations equals the operating surplus as of the most recent date of determination of available cash. We treat any amount distributed in excess of operating surplus, regardless of its source, as capital surplus. While we do not currently anticipate that we will make any distributions from capital surplus in the near term, we may determine that the sale or disposition of an asset or business owned or acquired by us may be beneficial to our unitholders. If we distribute to you the equity we own in a subsidiary or the proceeds from the sale of one of our businesses, such a distribution would be characterized as a distribution from capital surplus.
General. During the subordination period, which we define below and in the glossary, the common units have the right to receive distributions of available cash from operating surplus in an amount equal to the minimum quarterly distribution of $0.50 per quarter, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. The purpose of the subordinated units is to increase the likelihood that during the subordination period there will be available cash to be distributed on the common units.
36
Definition of Subordination Period. We define the subordination period in the glossary. The subordination period will extend until the first day of any quarter beginning after June 30, 2009 that each of the following tests are met:
- •
- distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equaled or exceeded the minimum quarterly distribution for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;
- •
- the "adjusted operating surplus" (as defined below) generated during each of the three immediately preceding, non-overlapping four-quarter periods equaled or exceeded the sum of the minimum quarterly distributions on all of the outstanding common units and subordinated units during those periods on a fully diluted basis and the related distribution on the 2% general partner interest during those periods; and
- •
- there are no arrearages in payment of the minimum quarterly distribution on the common units.
Early Conversion of Subordinated Units. Before the end of the subordination period, a portion of the subordinated units may convert into common units on a one-for-one basis immediately after the distribution of available cash to the partners in respect of any quarter ending on or after:
- •
- June 30, 2005 with respect to 20% of the subordinated units;
- •
- June 30, 2006 with respect to 20% of the subordinated units;
- •
- June 30, 2007 with respect to 20% of the subordinated units; and
- •
- June 30, 2008 with respect to 20% of the subordinated units.
The early conversions will occur if at the end of the applicable quarter each of the following occurs:
- •
- distributions of available cash from operating surplus on each common unit and subordinated unit equaled or exceeded the minimum quarterly distribution for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;
- •
- the adjusted operating surplus generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of the minimum quarterly distributions on all of the outstanding common units and subordinated units during those periods on a fully diluted basis and the related distribution on the 2% general partner interest during those periods; and
- •
- there are no arrearages in payment of the minimum quarterly distribution on the common units.
However, the early conversion of the second, third or fourth 20% of the subordinated units may not occur until at least one year following the early conversion of the first, second or third 20% of the subordinated units, as the case may be.
In addition to the early conversion of subordinated units described above, 20% of the subordinated units may convert into common units on a one-for-one basis prior to the end of the subordination period if at the end of a quarter ending on or after June 30, 2005 each of the following occurs:
- •
- distributions of available cash from operating surplus on each common unit and subordinated unit equaled or exceeded $2.50 for each of the two consecutive, non-overlapping four-quarter periods immediately preceding that date;
- •
- the adjusted operating surplus generated during each of the two consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of a distribution of $2.50 on all of the outstanding common units and subordinated units during those periods on a fully diluted basis and the related distribution on the 2% general partner interest during those periods; and
37
- •
- there are no arrearages in payment of the minimum quarterly distribution on the common units.
This additional early conversion is a one time occurrence.
Finally, 20% of the subordinated units may convert into common units on a one-for-one basis prior to the end of the subordination period if at the end of a quarter ending on or after June 30, 2005 each of the following occurs:
- •
- distributions of available cash from operating surplus on each common unit and subordinated unit equaled or exceeded $3.00 for each of the two consecutive, non-overlapping four-quarter periods immediately preceding that date;
- •
- the adjusted operating surplus generated during each of the two consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of a distribution of $3.00 on all of the outstanding common units and subordinated units during those periods on a fully diluted basis and the related distribution on the 2% general partner interest during those periods; and
- •
- there are no arrearages in payment of the minimum quarterly distribution on the common units.
This additional early conversion is a one time occurrence.
Generally, the earliest possible date by which all subordinated units may be converted into common units is June 30, 2007.
Definition of Adjusted Operating Surplus. We define adjusted operating surplus in the glossary and for any period it generally means:
- •
- operating surplus generated during that period; less
- •
- any net increase in working capital borrowings during that period; less
- •
- any net reduction in cash reserves for operating expenditures during that period not relating to an operating expenditure made during that period; plus
- •
- any net decrease in working capital borrowings during that period; and plus
- •
- any net increase in cash reserves for operating expenditures during that period required by any debt instrument for the repayment of principal, interest or premium.
Adjusted operating surplus is intended to reflect the cash generated from operations during a particular period and therefore excludes net increases in working capital borrowings and net drawdowns of reserves of cash generated in prior periods.
Effect of Expiration of the Subordination Period. Upon expiration of the subordination period, each outstanding subordinated unit will convert into one common unit and will then participate pro rata with the other common units in distributions of available cash. In addition, if the unitholders remove our general partner other than for cause and units held by our general partner and its affiliates are not voted in favor of such removal, the subordination period will end, any then-existing arrearages on the common units will terminate and each subordinated unit will immediately convert into one common unit.
38
Distributions of Available Cash from Operating Surplus During the Subordination Period
We will make distributions of available cash from operating surplus for any quarter during the subordination period in the following manner:
- •
- First, 98% to the common unitholders, pro rata, and 2% to our general partner until we distribute for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter;
- •
- Second, 98% to the common unitholders, pro rata, and 2% to our general partner until we distribute for each outstanding common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period;
- •
- Third, 98% to the subordinated unitholders, pro rata, and 2% to our general partner until we distribute for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and
- •
- Thereafter, in the manner described in "—Incentive Distribution Rights" below.
Distributions of Available Cash from Operating Surplus After the Subordination Period
We will make distributions of available cash from operating surplus for any quarter after the subordination period in the following manner:
- •
- First, 98% to all unitholders, pro rata, and 2% to our general partner until we distribute for each outstanding unit an amount equal to the minimum quarterly distribution for that quarter; and
- •
- Thereafter, in the manner described in "—Incentive Distribution Rights" below.
Incentive distribution rights represent the right to receive an increasing percentage of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. Our general partner currently holds the incentive distribution rights, but may transfer these rights separately from its general partner interest, subject to restrictions in the partnership agreement.
If for any quarter:
- •
- we have distributed available cash from operating surplus to the common and subordinated unitholders in an amount equal to the minimum quarterly distribution; and
- •
- we have distributed available cash from operating surplus on outstanding common units in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution;
then, we will distribute any additional available cash from operating surplus for that quarter among the unitholders and our general partner in the following manner:
- •
- First, 98% to all unitholders, pro rata, and 2% to our general partner until each unit receives a total of $0.55 per unit for that quarter (the "first target distribution");
- •
- Second, 85% to all unitholders, pro rata, and 15% to our general partner, until each unitholder receives a total of $0.625 per unit for that quarter (the "second target distribution");
- •
- Third, 75% to all unitholders, pro rata, and 25% to our general partner, until each unitholder receives a total of $0.75 per unit for that quarter (the "third target distribution"); and
39
- •
- Thereafter, 50% to all unitholders, pro rata, and 50% to our general partner.
In each case, the amount of the target distribution set forth above is exclusive of any distributions to common unitholders to eliminate any cumulative arrearages in payment of the minimum quarterly distribution.
Target Amount of Quarterly Distribution
The following table illustrates the percentage allocations of the additional available cash from operating surplus between the unitholders and our general partner up to the various target distribution levels. The amounts set forth under "Marginal Percentage Interest in Distributions" are the percentage interests of the unitholders and our general partner in any available cash from operating surplus we distribute up to and including the corresponding amount in the column "Total Quarterly Distribution Target Amount," until available cash from operating surplus we distribute reaches the next target distribution level, if any. The percentage interests shown for the unitholders and our general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution.
| | Marginal Percentage Interest in Distributions | |||||
---|---|---|---|---|---|---|---|
| Total Quarterly Distribution Target Amount | Unitholders | General Partner | ||||
Minimum Quarterly Distribution | $0.50 | 98 | % | 2 | % | ||
First Target Distribution | up to $0.55 | 98 | % | 2 | % | ||
Second Target Distribution | above $0.55 up to $0.625 | 85 | % | 15 | % | ||
Third Target Distribution | above $0.625 up to $0.75 | 75 | % | 25 | % | ||
Thereafter | above $0.75 | 50 | % | 50 | % |
Distributions from Capital Surplus
How Distributions from Capital Surplus Will Be Made. We will make distributions of available cash from capital surplus, if any, in the following manner:
- •
- First, 98% to all unitholders, pro rata, and 2% to our general partner, until we distribute for each common unit that was issued in the initial public offering, an amount of available cash from capital surplus equal to the initial public offering price;
- •
- Second, 98% to the common unitholders, pro rata, and 2% to our general partner, until we distribute for each common unit an amount of available cash from capital surplus equal to any unpaid arrearages in payment of the minimum quarterly distribution on the common units; and
- •
- Thereafter, we will make all distributions of available cash from capital surplus as if they were from operating surplus.
Effect of a Distribution from Capital Surplus. The partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from the initial public offering, which is a return of capital. The initial public offering price less any distributions of capital surplus per unit is referred to as the "unrecovered initial unit price." Each time a distribution of capital surplus is made, the minimum quarterly distribution and the target distribution levels will be reduced in the same proportion as the corresponding reduction in the unrecovered initial unit price. Because distributions of capital surplus will reduce the minimum quarterly distribution, after any of these distributions are made, it may be easier for our general partner to receive incentive distributions and for the subordinated units to convert into common units. However, any distribution of capital surplus before
40
the unrecovered initial unit price is reduced to zero cannot be applied to the payment of the minimum quarterly distribution or any arrearages.
Once we distribute capital surplus on a unit in an amount equal to the initial unit price, we will reduce the minimum quarterly distribution and the target distribution levels to zero. We will then make all future distributions from operating surplus, with 50% being paid to the holders of units, 48% to the holders of the incentive distribution rights and 2% to our general partner.
Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels
In addition to adjusting the minimum quarterly distribution and target distribution levels to reflect a distribution of capital surplus, if we combine our units into fewer units or subdivide our units into a greater number of units, we will proportionately adjust:
- •
- the minimum quarterly distribution;
- •
- target distribution levels;
- •
- unrecovered initial unit price;
- •
- the number of common units issuable during the subordination period without a unitholder vote; and
- •
- the number of common units into which a subordinated unit is convertible.
For example, if a two-for-one split of the common units should occur, the minimum quarterly distribution, the target distribution levels and the unrecovered initial unit price would each be reduced to 50% of its initial level. We will not make any adjustment by reason of the issuance of additional units for cash or property.
In addition, if legislation is enacted or if existing law is modified or interpreted in a manner that causes us to become taxable as a corporation or otherwise subject to taxation as an entity for federal, state or local income tax purposes, we will reduce the minimum quarterly distribution and the target distribution levels by multiplying the same by one minus the sum of the highest marginal federal corporate income tax rate that could apply and any increase in the effective overall state and local income tax rates. For example, if we became subject to a maximum marginal federal, and effective state and local income tax rate of 38%, then the minimum quarterly distribution and the target distributions levels would each be reduced to 62% of their previous levels.
Distributions of Cash upon Liquidation
General. If we dissolve in accordance with the partnership agreement, we will sell or otherwise dispose of our assets in a process called liquidation. We will first apply the proceeds of liquidation to the payment of our creditors. We will distribute any remaining proceeds to the unitholders and our general partner, in accordance with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.
The allocations of gain and loss upon liquidation are intended, to the extent possible, to entitle the holders of outstanding common units to a preference over the holders of outstanding subordinated units upon our liquidation, to the extent required to permit common unitholders to receive their unrecovered initial unit price plus the minimum quarterly distribution for the quarter during which liquidation occurs plus any unpaid arrearages in payment of the minimum quarterly distribution on the common units. However, there may not be sufficient gain upon our liquidation to enable the holders of common units to fully recover all of these amounts, even though there may be cash available for distribution to the holders of subordinated units. Any further net gain recognized upon liquidation will be allocated in a manner that takes into account the incentive distribution rights of our general partner.
41
Manner of Adjustments for Gain. The manner of the adjustment for gain is set forth in the partnership agreement. If our liquidation occurs before the end of the subordination period, we will allocate any gain to the partners in the following manner:
- •
- First, to our general partner and the holders of units who have negative balances in their capital accounts to the extent of and in proportion to those negative balances;
- •
- Second, 98% to the common unitholders, pro rata, and 2% to our general partner until the capital account for each common unit is equal to the sum of:
- (1)
- the unrecovered initial unit price for that common unit; plus
- (2)
- the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs; and plus
- (3)
- any unpaid arrearages in payment of the minimum quarterly distribution;
- •
- Third, 98% to the subordinated unitholders, pro rata, and 2% to our general partner until the capital account for each subordinated unit is equal to the sum of:
- (1)
- the unrecovered initial unit price on that subordinated unit; and
- (2)
- the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs;
- •
- Fourth, 98% to all unitholders, pro rata, and 2% to our general partner, until we allocate under this paragraph an amount per unit equal to:
- (1)
- the sum of the excess of the first target distribution per unit over the minimum quarterly distribution per unit for each quarter of our existence; less
- (2)
- the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the minimum quarterly distribution per unit that we distributed 98% to the unitholders, pro rata, and 2% to our general partner, for each quarter of our existence;
- •
- Fifth, 85% to all unitholders, pro rata, and 15% to our general partner, until we allocate under this paragraph an amount per unit equal to:
- (1)
- the sum of the excess of the second target distribution per unit over the first target distribution per unit for each quarter of our existence; less
- (2)
- the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the first target distribution per unit that we distributed 85% to the unitholders, pro rata, and 15% to our general partner for each quarter of our existence;
- •
- Sixth, 75% to all unitholders, pro rata, and 25% to our general partner, until we allocate under this paragraph an amount per unit equal to:
- (1)
- the sum of the excess of the third target distribution per unit over the second target distribution per unit for each quarter of our existence; less
- (2)
- the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the second target distribution per unit that we distributed 75% to the unitholders, pro rata, and 25% to our general partner for each quarter of our existence;
- •
- Thereafter, 50% to all unitholders, pro rata, and 50% to our general partner.
42
If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that clause (3) of the second priority above and all of the third priority above will no longer be applicable.
Manner of Adjustments for Losses. Upon our liquidation, we will generally allocate any loss to our general partner and the unitholders in the following manner:
- •
- First, 98% to holders of subordinated units in proportion to the positive balances in their capital accounts and 2% to our general partner until the capital accounts of the subordinated unitholders have been reduced to zero;
- •
- Second, 98% to the holders of common units in proportion to the positive balances in their capital accounts and 2% to our general partner until the capital accounts of the common unitholders have been reduced to zero; and
- •
- Thereafter, 100% to our general partner.
If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that all of the first priority above will no longer be applicable.
Adjustments to Capital Accounts. We will make adjustments to capital accounts upon the issuance of additional units. In doing so, we will allocate any unrealized and, for tax purposes, unrecognized gain or loss resulting from the adjustments to the unitholders and our general partner in the same manner as we allocate gain or loss upon liquidation. In the event that we make positive adjustments to the capital accounts upon the issuance of additional units, we will allocate any later negative adjustments to the capital accounts resulting from the issuance of additional units or upon our liquidation in a manner which results, to the extent possible, in our general partner's capital account balances equaling the amount which they would have been if no earlier positive adjustments to the capital accounts had been made.
43
MARKWEST ENERGY PARTNERS, L.P.
UNAUDITED PRO FORMA FINANCIAL STATEMENTS
Introduction
The following are our unaudited pro forma financial statements as of September 30, 2003, for the year ended December 31, 2002 and the nine months ended September 30, 2003.
Our unaudited pro forma consolidated balance sheet as of September 30, 2003, reflects the following transactions as if such transactions occurred as of September 30, 2003:
- •
- the western Oklahoma acquisition, which closed December 1, 2003, for consideration of $37.8 million, plus $0.2 million in estimated transaction costs;
- •
- the Michigan Crude Pipeline acquisition, which closed December 18, 2003, for consideration of $21.2 million, plus $0.3 million in estimated transaction costs;
- •
- borrowings of $59.5 million under our credit facility to finance the western Oklahoma and Michigan Crude Pipeline acquisitions;
- •
- our public offering of 1,100,444 common units at an assumed offering price of $40.42 per common unit, resulting in aggregate gross proceeds to us of $44.5 million and a capital contribution from our general partner to maintain its 2% general partner interest;
- •
- the payment of underwriting fees and commissions, and other fees and expenses associated with the offering, expected to be approximately $3.0 million; and
- •
- the repayment of approximately $42.4 million of indebtedness incurred to finance a portion of the acquisitions.
Our unaudited pro forma consolidated statements of operations for the nine months ended September 30, 2003 and for the year ended December 31, 2002 reflect each of the above transactions and the following additional transactions as if all such transactions occurred on January 1, 2002:
- •
- the Pinnacle acquisition, which closed March 28, 2003, for consideration of $39.5 million, plus $0.4 million in transaction costs;
- •
- borrowings of $39.9 million under our credit facility to finance the Pinnacle acquisition; and
- •
- our private placement in June 2003 of 375,000 common units, the net proceeds from which were used to repay indebtedness incurred in connection with the Pinnacle acquisition and a capital contribution from our general partner to maintain its 2% general partner interest.
In addition, our unaudited pro forma consolidated statement of operations for the year ended December 31, 2002 reflects our initial public offering of 2,415,000 common units at an offering price of $20.50 per common unit and the formation transactions related to our partnership as if such transactions occurred on January 1, 2002.
Adjustments for these transactions are presented in the notes to the unaudited pro forma financial statements. The unaudited pro forma financial statements and accompanying notes should be read together with the financial statements and related notes included elsewhere in the prospectus.
You should be aware that the information under the headings "Pinnacle" in the pro forma financial statement presentation are the financial statements of PNG Corporation and its subsidiaries, which we refer to collectively as PNG. Although Pinnacle represents most of PNG's assets, liabilities and operations, we excluded from our acquisition certain liabilities and assets, and accordingly, we have made pro forma adjustments to the historical financial statements for PNG to exclude the impact of those liabilities and assets we did not acquire. Most significantly, we did not assume any pre-merger tax liabilities or any liabilities associated with an existing lawsuit against PNG. In addition, we did not
44
acquire the property and contract rights associated with the Hobbs, New Mexico lateral pipeline, although we are providing certain operating services to the Hobbs pipeline operation. Finally, the financial information presented under the heading "Pinnacle" in these unaudited pro forma statements of operations represents PNG's results of operations for the first three months of 2003. The results of operations for Pinnacle for the period from March 28, 2003, the date we completed the Pinnacle acquisition, through September 30, 2003, are included in our historical results of operations. We have made pro forma adjustments to eliminate the four days of results, March 28, 2003 through March 31, 2003, that are included in PNG's historical results.
Similarly, the information presented under the headings "Western Oklahoma" and "Michigan Crude Pipeline" represent the financial statements of American Central Western Oklahoma Gas Company, L.L.C., or American Central, and the Michigan Crude Oil Pipeline System, respectively. In these cases, there were no material items, other than working capital, that we excluded from these acquisitions and, accordingly, we have not further adjusted the historical results of operations for American Central or the Michigan Crude Oil Pipeline System.
In addition, while our historical consolidated balance sheet reflects our $12.2 million Lubbock pipeline acquisition in September 2003, our pro forma statements of operations present the effect of this acquisition for one month. This acquisition did not meet the applicable materiality thresholds that would require inclusion in these unaudited pro forma statements of operations.
The pro forma balance sheet and the pro forma statements of operations were derived by adjusting the historical financial statements of MarkWest Energy Partners, L.P. The adjustments are based on currently available information and, therefore, the actual adjustments may differ from the pro forma adjustments. However, management believes that the adjustments provide a reasonable basis for presenting the significant effects of the transactions described above. The unaudited pro forma financial statements do not purport to present our financial position or results of operations had the acquisitions or the other transactions actually been completed as of the dates indicated. Moreover, the statements do not project our financial position or results of operations for any future date or period.
45
MARKWEST ENERGY PARTNERS, L.P.
UNAUDITED PRO FORMA CONSOLIDATED BALANCE SHEET
September 30, 2003
(in thousands)
| MarkWest Energy Partners, L.P. | Western Oklahoma | Michigan Crude Pipeline | Acquisition Adjustments | As Adjusted For Acquisitions | Offering Adjustments | Pro Forma | ||||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
ASSETS | |||||||||||||||||||||||||
Current assets: | |||||||||||||||||||||||||
Cash and cash equivalents | $ | 6,373 | $ | 383 | $ | — | $ | (383) | (A) | $ | 6,373 | $ | 44,480 (3,035) 908 (42,353) | (C) (D) (E) (F) | $ | 6,373 | |||||||||
Receivables, net | 6,364 | 4,199 | 312 | (4,511) | (A) | 6,364 | 6,364 | ||||||||||||||||||
Receivables from affiliate | 2,247 | 2,247 | 2,247 | ||||||||||||||||||||||
Inventories | 114 | 633 | (633) | (A) | 114 | 114 | |||||||||||||||||||
Other assets | 135 | 156 | 68 | (224) | (A) | 135 | 135 | ||||||||||||||||||
Total current assets | 15,233 | 4,738 | 1,013 | (5,751 | ) | 15,233 | — | 15,233 | |||||||||||||||||
Property, plant and equipment, net | 126,177 | 36,659 | 10,614 | 12,212 | (B) | 185,662 | 185,662 | ||||||||||||||||||
Deferred financing costs, net | 880 | 880 | 880 | ||||||||||||||||||||||
Total assets | $ | 142,290 | $ | 41,397 | $ | 11,627 | $ | 6,461 | $ | 201,775 | $ | — | $ | 201,775 | |||||||||||
LIABILITIES AND CAPITAL | |||||||||||||||||||||||||
Current liabilities: | |||||||||||||||||||||||||
Accounts payable | $ | 8,489 | $ | 4,056 | $ | 225 | $ | (4,281) | (A) | $ | 8,489 | $ | — | $ | 8,489 | ||||||||||
Payables to affiliate | 815 | 274 | (274) | (A) | 815 | 815 | |||||||||||||||||||
Accrued liabilities | 3,786 | 3,786 | 3,786 | ||||||||||||||||||||||
Risk management liabilities | 263 | 263 | 263 | ||||||||||||||||||||||
Total current liabilities | 13,353 | 4,330 | 225 | (4,555 | ) | 13,353 | — | 13,353 | |||||||||||||||||
Long-term debt | 61,300 | 59,485 | (B) | 120,785 | (42,353) | (F) | 78,432 | ||||||||||||||||||
Risk management liability | 196 | 196 | 196 | ||||||||||||||||||||||
Commitment and contingencies | |||||||||||||||||||||||||
Capital: | |||||||||||||||||||||||||
Partners' capital/members' equity | 67,912 | 37,067 | 11,402 | (48,469) | (A) | 67,912 | 44,480 (3,035) 908 | (C) (D) (E) | 110,265 | ||||||||||||||||
Accumulated other comprehensive loss, net of tax | (471 | ) | (471 | ) | (471 | ) | |||||||||||||||||||
Total capital | 67,441 | 37,067 | 11,402 | (48,469 | ) | 67,441 | 42,353 | 109,794 | |||||||||||||||||
Total liabilities and capital | $ | 142,290 | $ | 41,397 | $ | 11,627 | $ | 6,461 | $ | 201,775 | $ | — | $ | 201,775 | |||||||||||
The accompanying notes are an integral part of these financial statements.
46
MARKWEST ENERGY PARTNERS, L.P.
UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS
Nine Months Ended September 30, 2003
(in thousands, except per unit data)
| MarkWest Energy Partners, L.P. | Pinnacle | Western Oklahoma | Michigan Crude Pipeline | Acquisition Adjustments | As Adjusted For Acquisitions | Offering Adjustments | Pro Forma | |||||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Revenues: | |||||||||||||||||||||||||||
Sales to affiliates | $ | 42,741 | $ | — | $ | — | $ | 1,609 | $ | — | $ | 44,350 | $ | — | $ | 44,350 | |||||||||||
Sales to unaffiliated parties | 36,000 | 18,614 | 30,241 | 1,701 | (51) (827) | (G) (H) | 85,678 | 85,678 | |||||||||||||||||||
Total revenues | 78,741 | 18,614 | 30,241 | 3,310 | (878 | ) | 130,028 | — | 130,028 | ||||||||||||||||||
Operating expenses: | |||||||||||||||||||||||||||
Purchased product costs | 45,325 | 15,305 | 25,220 | (680) | (H) | 85,170 | 85,170 | ||||||||||||||||||||
Facility expenses | 14,900 | 885 | 2,157 | 1,401 | (9) (39) | (G) (H) | 19,295 | 19,295 | |||||||||||||||||||
Selling, general and administrative expenses | 4,814 | 336 | 108 | 733 | (11) | (H) | 5,980 | 5,980 | |||||||||||||||||||
Depreciation | 5,231 | 1,031 | 1,752 | 469 | (52) (46) 871 | (G) (H) (I) | 9,256 | 9,256 | |||||||||||||||||||
Management fee | — | — | 1,400 | — | — | 1,400 | — | 1,400 | |||||||||||||||||||
Total operating expenses | 70,270 | 17,557 | 30,637 | 2,603 | 34 | 121,101 | — | 121,101 | |||||||||||||||||||
Income (loss) from operations | 8,471 | 1,057 | (396 | ) | 707 | (912 | ) | 8,927 | 8,927 | ||||||||||||||||||
Other income (expense): | |||||||||||||||||||||||||||
Interest income (expense), net | (2,592 | ) | (269 | ) | 8 | (2,631) | (J) | (5,214 | ) | 1,229 | (M) | (3,985 | ) | ||||||||||||||
270 | (K) | ||||||||||||||||||||||||||
Other income | 51 | 18 | 69 | 69 | |||||||||||||||||||||||
Total other income (expense) | (2,541 | ) | (251 | ) | 8 | — | 2,361 | (5,145 | ) | 1,229 | (3,916 | ) | |||||||||||||||
Income before income taxes | 5,930 | 806 | (388 | ) | 707 | (3,273 | ) | 3,782 | 1,229 | 5,011 | |||||||||||||||||
Provision (benefit) for income taxes | 294 | (294) | (L) | ||||||||||||||||||||||||
Net income (loss) | $ | 5,930 | $ | 512 | $ | (388 | ) | $ | 707 | $ | (2,979 | ) | $ | 3,782 | $ | 1,229 | $ | 5,011 | |||||||||
General partner's interest in net income | $ | 178 | $ | 172 | |||||||||||||||||||||||
Limited partners' interest in net income | $ | 5,752 | $ | 4,839 | |||||||||||||||||||||||
Basic net income per limited partner unit(1) | $ | 1.04 | $ | 0.70 | |||||||||||||||||||||||
Diluted net income per limited partner unit(1) | $ | 1.03 | $ | 0.70 | |||||||||||||||||||||||
Weighted average number of limited partners' units outstanding:(1) | |||||||||||||||||||||||||||
Basic | 5,543 | 247 | (K) | 1,100 | (N) | 6,890 | |||||||||||||||||||||
Diluted | 5,593 | 247 | (K) | 1,100 | (N) | 6,940 |
- (1)
- As Restated. See Note 12 to the condensed consolidated and combined financial statements of MarkWest Energy Partners, L.P. for the nine months ended September 30, 2003.
The accompanying notes are an integral part of these financial statements.
47
MARKWEST ENERGY PARTNERS, L.P.
UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS
Year Ended December 31, 2002
(in thousands, except per unit data)
| | Reversal of Historical Amounts Not Applicable to MarkWest Energy Partners, L.P. | | Year Ended December 31, 2002 | | | | | |||||||||||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Year Ended December 31, 2002(1) | IPO Adjustments | Pinnacle | Western Oklahoma | Michigan Crude Pipeline | Acquisition Adjustments | As Adjusted For Acquisitions | Offering Adjustments | Pro Forma | ||||||||||||||||||||||||
Revenues: | |||||||||||||||||||||||||||||||||
Sales to affiliates | $ | 26,093 | $ | — | $ | (6,318 | ) | $ | — | $ | — | $ | 3,103 | $ | — | $ | 22,878 | $ | — | $ | 22,878 | ||||||||||||
Sales to unaffiliated parties | 44,153 | (27,347 | )(O) | 16,147 | 43,667 | 24,651 | 1,906 | (367 | )(G) | 102,810 | 102,810 | ||||||||||||||||||||||
Total revenues | 70,246 | (27,347 | ) | 9,829 | (Q) | 43,667 | 24,651 | 5,009 | (367 | ) | 125,688 | — | 125,688 | ||||||||||||||||||||
Operating expenses: | |||||||||||||||||||||||||||||||||
Purchased product costs | 38,906 | (20,450 | )(O) | 32,613 | 17,371 | — | — | 68,440 | 68,440 | ||||||||||||||||||||||||
Facility expenses | 15,101 | 132 | (O) | 85 | (Q) | 3,909 | 2,699 | 1,550 | (49 | )(G) | 23,427 | 23,427 | |||||||||||||||||||||
Selling, general and administrative expenses | 5,283 | (323 | )(P) | 3,264 | 114 | 973 | — | 9,311 | 9,311 | ||||||||||||||||||||||||
Depreciation | 4,980 | 3,472 | 2,161 | 585 | (208 (643 | )(G) )(I) | 10,347 | 10,347 | |||||||||||||||||||||||||
Management fee | 1,867 | 1,867 | 1,867 | ||||||||||||||||||||||||||||||
Impairment expense | 1,672 | 1,672 | 1,672 | ||||||||||||||||||||||||||||||
Gain on sale of assets | (109 | ) | (109 | ) | (109 | ) | |||||||||||||||||||||||||||
Total operating expenses | 64,270 | (20,641 | ) | 85 | 44,821 | 24,212 | 3,108 | (900 | ) | 114,955 | — | 114,955 | |||||||||||||||||||||
Income (loss) from operations | 5,976 | (6,706 | ) | 9,744 | (1,154 | ) | 439 | 1,901 | 533 | 10,733 | 10,733 | ||||||||||||||||||||||
Other income (expense): | |||||||||||||||||||||||||||||||||
Interest expense, net | (1,414 | ) | (101 | )(R) | (1,269 | ) | 12 | (3,340 | )(J) | (5,755 | ) | 1,516 | (M) | (4,239 | ) | ||||||||||||||||||
357 | (K) | ||||||||||||||||||||||||||||||||
Equity in losses of unconsolidated affiliates | (42 | ) | (42 | ) | (42 | ) | |||||||||||||||||||||||||||
Impairment of unconsolidated affiliate | (249 | ) | (249 | ) | (249 | ) | |||||||||||||||||||||||||||
Minority interest in net loss of consolidated subsidiary | 147 | 147 | 147 | ||||||||||||||||||||||||||||||
Other income (expense) | 52 | — | 52 | 52 | |||||||||||||||||||||||||||||
Total other income (expense) | (1,362 | ) | — | (101 | ) | (1,413 | ) | 12 | — | (2,983 | ) | (5,847 | ) | 1,516 | (4,331 | ) | |||||||||||||||||
Income (loss) before income taxes | 4,614 | (6,706 | ) | 9,643 | (2,567 | ) | 451 | 1,901 | (2,450 | ) | 4,886 | 1,516 | 6,402 | ||||||||||||||||||||
Provision (benefit) for income taxes | (17,175 | ) | 17,175 | (L) | (4,213 | ) | 4,213 | (L) | — | ||||||||||||||||||||||||
Net income (loss) | $ | 21,789 | $ | (6,706 | ) | $ | (7,532 | ) | $ | 1,646 | $ | 451 | $ | 1,901 | $ | (6,663 | ) | $ | 4,886 | $ | 1,516 | $ | 6,402 | ||||||||||
General partner's interest in net income | $ | 89 | $ | 128 | |||||||||||||||||||||||||||||
Limited partners' interest in net income | $ | 21,700 | $ | 6,274 | |||||||||||||||||||||||||||||
Net income per limited partners' interest | $ | 4.86 | $ | 0.91 | |||||||||||||||||||||||||||||
Weighted average number of limited partners' units outstanding | 4,469 | 375 | (K) | 1,100 | (N) | 6,890 |
- (1)
- As Restated. See Note 15 to the consolidated and combined financial statements of MarkWest Energy Partners, L.P.
The accompanying notes are an integral part of these financial statements.
48
MARKWEST ENERGY PARTNERS, L.P.
NOTES TO UNAUDITED PRO FORMA FINANCIAL STATEMENTS
Pro Forma Adjustments
- (A)
- Reflects the elimination of the western Oklahoma and Michigan Crude Pipeline assets, liabilities and equity that we did not acquire. In each case, we did not acquire working capital.
- (B)
- Reflects the acquisitions and the related financing (all cash consideration and direct acquisition costs were financed by borrowings under the credit facility) of the western Oklahoma and Michigan Crude Pipeline assets. The consideration paid and the purchase price allocation for each acquisition is as follows:
| Western Oklahoma | Michigan Crude Pipeline | Total | ||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
| (in thousands) | ||||||||||
Acquisition costs: | |||||||||||
Cash consideration | $ | 37,850 | $ | 21,155 | $ | 59,005 | |||||
Direct acquisition costs | 150 | 330 | 480 | ||||||||
Total | $ | 38,000 | $ | 21,485 | $ | 59,485 | |||||
Allocation of acquisition costs: | |||||||||||
Property and equipment | $ | 38,000 | $ | 21,485 | $ | 59,485 | |||||
Book value of acquired property and equipment | 36,659 | 10,614 | 47,273 | ||||||||
Adjustment | $ | 12,212 | |||||||||
These acquisitions were accounted for as purchases in accordance with Statement of Financial Accounting Standards No. 141, Business Combinations.
- (C)
- Reflects the gross proceeds to us of $44.5 million from the issuance and sale of 1,100,444 common units at an assumed offering price of $40.42 per common unit.
- (D)
- Reflects the payment of underwriters' discounts and commissions and estimated offering expenses of $3.0 million. The underwriters' discounts and commissions and offering expenses will be allocated to the common units.
- (E)
- Reflects the contribution of $0.9 million from our general partner in order to maintain its 2% general partner interest.
- (F)
- Represents the repayment of $42.4 million of borrowings under our revolving credit facility from the net proceeds of the offering and our general partner's contribution.
- (G)
- This entry eliminates the operating results of the Hobbs, New Mexico lateral pipeline that was not acquired as part of the Pinnacle acquisition.
- (H)
- MarkWest Energy Partners acquired Pinnacle on March 28, 2003. This entry eliminates the four days of Pinnacle results (March 28 through March 31, 2003) included in MarkWest Energy Partners' results for the nine months ended September 30, 2003.
49
- (I)
- Reflects the pro forma adjustment to depreciation expense as follows:
For the year ended December 31, 2002:
| Pinnacle | Western Oklahoma | Michigan Crude Pipeline | Total | |||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| (in thousands) | ||||||||||||
Eliminate historical depreciation expense | $ | (3,472 | ) | $ | (2,161 | ) | $ | (585 | ) | $ | (6,218 | ) | |
Less the entry in note (G) | 208 | 208 | |||||||||||
Pro forma depreciation expense(1) | 2,393 | 1,900 | 1,074 | 5,367 | |||||||||
Pro forma adjustment to depreciation expense | $ | (871 | ) | $ | (261 | ) | $ | 489 | $ | (643 | ) | ||
For the nine months ended September 30, 2003:
| Pinnacle | Western Oklahoma | Michigan Crude Pipeline | Total | |||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| (in thousands) | ||||||||||||
Eliminate historical depreciation expense | $ | (1,031 | ) | $ | (1,752 | ) | $ | (469 | ) | $ | (3,252 | ) | |
Less the entry in note (G) | 52 | 52 | |||||||||||
Less the entry in note (H) | 46 | 46 | |||||||||||
Pro forma depreciation expense(1) | 1,795 | 1,425 | 805 | 4,025 | |||||||||
Pro forma adjustment to depreciation expense | $ | 862 | $ | (327 | ) | $ | 336 | $ | 871 | ||||
- (1)
- Pro forma depreciation is based on the lesser of the term of the associated long-term contract or estimated reserves supporting our asset or the asset's useful life, which is twenty years for property and equipment.
- (J)
- The pro forma adjustment to interest expense is calculated as follows:
| Year Ended December 31, 2002 | Nine Months Ended September 30, 2003 | |||||
---|---|---|---|---|---|---|---|
| (in thousands) | ||||||
Eliminate Pinnacle interest expense(1) | $ | 1,269 | $ | 269 | |||
Partnership bank debt ($99.6 million in additional principal) at assumed rates of 3.58% and 3.87%, respectively(2)(3) | (3,559 | ) | (2,112 | ) | |||
Amortization of deferred debt issuance costs | (1,050 | ) | (788 | ) | |||
Pro forma increase to interest expense from the acquisitions | $ | (3,340 | ) | $ | (2,631 | ) | |
- (1)
- Represents the elimination of Pinnacle's interest expense as Pinnacle's debt was paid in full in connection with the acquisition.
- (2)
- The Partnership incurred bank debt of $39.5 million in connection with the Pinnacle acquisition, $37.8 million in connection with the western Oklahoma acquisition and $21.2 million in connection with the Michigan Crude Pipeline acquisition, plus $0.9 million to pay aggregate transaction costs related to these three acquisitions.
- (3)
- The effects of fluctuations of 0.125% and 0.25% in annual interest rates under the Partnership's credit facility on pro forma interest expense would have been approximately $151,000 and $302,000 respectively, for the year ended December 31, 2002. The effects of fluctuations of 0.125% and 0.25% in annual interest rates under the Partnership's credit facility on pro forma interest expense would have been approximately $113,000 and $226,000, respectively, for the nine months ended September 30, 2003.
50
- (K)
- The pro forma adjustment to interest expense from the private placement is calculated as follows:
| Year Ended December 31, 2002 | Nine Months Ended September 30, 2003 | ||||
---|---|---|---|---|---|---|
| (in thousands) | |||||
Partnership bank debt ($10.0 million in reduced principal) at assumed rates of 3.58% and 3.87%, respectively (1) | $ | 357 | $ | 270 | ||
Pro forma decrease to interest expense | $ | 357 | $ | 270 | ||
- (1)
- The effects of fluctuations of 0.125% and 0.25% in annual interest rates under the Partnership's credit facility on pro forma interest expense would have been approximately $12,000 and $25,000, respectively, for the year ended December 31, 2002. The effects of fluctuations of 0.125% and 0.25% in annual interest rates under the Partnership's credit facility on pro forma interest expense would have been approximately $9,000 and $19,000, respectively, for the nine months ended September 30, 2003.
In addition, we adjusted the weighted average number of units outstanding to give full-period effect to the private placement.
- (L)
- The income tax provision (benefit) was eliminated because MarkWest Energy Partners is a partnership. In a partnership, income taxes are the responsibility of the unitholders and not the partnership.
- (M)
- The pro forma adjustment to interest expense from the offering is calculated as follows:
| Year Ended December 31, 2002 | Nine Months Ended September 30, 2003 | ||||
---|---|---|---|---|---|---|
| (in thousands) | |||||
Partnership bank debt ($42.4 million in reduced principal) at assumed rates of 3.58% and 3.87%, respectively (1) | $ | 1,516 | $ | 1,229 | ||
Pro forma decrease to interest expense | $ | 1,516 | $ | 1,229 | ||
- (1)
- The effects of fluctuations of 0.125% and 0.25% in annual interest rates under the Partnership's credit facility on pro forma interest expense would have been approximately $98,000 and $196,000, respectively, for the year ended December 31, 2002. The effects of fluctuations of 0.125% and 0.25% in annual interest rates under the Partnership's credit facility on pro forma interest expense would have been approximately $74,000 and $147,000, respectively, for the nine months ended September 30, 2003.
- (N)
- The weighted average limited partners' units outstanding used in the income per unit calculation includes the limited partners' common and subordinated units and excludes the general partner interest. The weighted average limited partners' units outstanding have been adjusted to reflect the common and subordinated units issued in connection with our initial public offering as if these units have been outstanding since January 1, 2002 and the common units assumed to be issued in connection with this offering.
- (O)
- Reflects the following reversal of historical revenues (primarily NGL product sales subject to commodity price risk), purchased product costs (primarily natural gas purchases subject to commodity price risk) and operating expenses pursuant to the contractual arrangements for the MarkWest Hydrocarbon Midstream Business that were retained by MarkWest Hydrocarbon following the Partnership's initial public offering. Specifically, MarkWest Hydrocarbon retained its keep-whole contractual arrangements in Appalachia. For a more detailed discussion of the
51
MarkWest Hydrocarbon Midstream Business' historical contracts, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—Items Impacting Comparability of Financial Results."
- (P)
- Reflects the reversal of certain historical general and administrative expenses for the MarkWest Hydrocarbon Midstream Business. Historical general and administrative expenses that were reversed include certain NGL marketing costs that will not be a part of our operations.
- (Q)
- Reflects the pro forma revenues and plant operating expenses pursuant to the terms of the operating agreements entered into between MarkWest Hydrocarbon and us concurrently with the closing of our initial public offering. For a more detailed discussion of our operating agreements with MarkWest Hydrocarbon, please read "Certain Relationships and Related Transactions."
The adjustments to pro forma revenues were calculated based on MarkWest Hydrocarbon's actual production volumes for the 143-day period ended May 23, 2002. Pro forma revenues are comprised of the fee per unit and processing plant fuel we receive under our contracts with MarkWest Hydrocarbon in Appalachia, and fees and NGL product sales in Appalachia and Michigan. Pro forma purchased product costs are comprised of the portion of NGL product sales proceeds we remit to Equitable in Appalachia and producers in Michigan. Pro forma plant operating expenses represent actual plant operating expenses (including Appalachian processing plant fuel) together with a $216,000 per year ($54,000 per quarter) contractual obligation related to one plant.
- (R)
- The pro forma adjustment to interest expense from the initial public offering is calculated as follows:
| Year Ended December 31, 2002 | |||
---|---|---|---|---|
| (in thousands) | |||
MarkWest Hydrocarbon Midstream Business interest expense (1) | $ | 461 | ||
Partnership bank debt ($29.5 million in additional principal) at an assumed rate of 3.85% (2) | (445 | ) | ||
Amortization of deferred debt issuance costs | (117 | ) | ||
Pro forma increase to interest expense | $ | (101 | ) | |
- (1)
- Represents the elimination of interest expense associated with debt of the MarkWest Hydrocarbon Midstream Business that was retired in connection with our initial public offering.
- (2)
- The effects of fluctuations of 0.125% and 0.25% in annual interest rates under the Partnership's credit facility on pro forma interest expense would have been approximately $37,000 and $74,000, respectively, for the year ended December 31, 2002.
52
SELECTED HISTORICAL AND PRO FORMA FINANCIAL AND OPERATING DATA
The following table shows selected historical financial and operating data of the MarkWest Hydrocarbon Midstream Business and the Partnership as of and for the periods indicated and the selected pro forma financial and operating data of the Partnership as of September 30, 2003 and for the year ended December 31, 2002 and for the nine months ended September 30, 2003. The selected historical financial and operating data of the Partnership for the year ended December 31, 2002 includes the historical financial and operating data of the MarkWest Hydrocarbon Midstream Business for the period prior to May 23, 2002 and the financial and operating data of the Partnership from May 24, 2002 through December 31, 2002. The MarkWest Hydrocarbon Midstream Business represents substantially all of MarkWest Hydrocarbon's historical natural gas gathering and processing and NGL transportation, fractionation and storage businesses prior to the formation of the Partnership. The selected historical financial data for the MarkWest Hydrocarbon Midstream Business for the years ended December 31, 1998 through 2001 are derived from the audited financial statements of the MarkWest Hydrocarbon Midstream Business. The selected historical financial data for the Partnership for the year ended December 31, 2002 is derived from the audited financial statements of the Partnership. The selected historical financial data for the Partnership as of and for the nine months ended September 30, 2003 is derived from the unaudited financial statements of the Partnership and, in our opinion, has been prepared on the same basis as the audited financial statements and includes all adjustments, consisting of normal recurring adjustments, necessary for a fair presentation of this information.
For a description of the pro forma adjustments please see "MarkWest Energy Partners, L.P. Unaudited Pro Forma Financial Statements."
The financial information presented below includes our financial and operating results for the year ended December 31, 2002 on a combined basis which have been restated. We completed our initial public offering as a partnership on May 24, 2002. Our Annual Report on Form 10-K and the form of this prospectus dated December 30, 2003 presented our 2002 financial results separately for the periods prior to and following our initial public offering. In this prospectus, our 2002 results are presented under one combined column that includes our operations both before and after our initial public offering. Generally, this combination required simple addition of the previously bifurcated line items. In addition, in this prospectus we have recorded the elimination of deferred tax liabilities resulting from our conversion to partnership form in the Partnership's statement of operations. Such elimination was previously presented as an adjustment to the Partnership's capital. In our revised presentation, the elimination of the deferred tax liability is reflected in the statement of operations as part of the provision (benefit) for income taxes, increasing net income by $17.2 million and income per unit by $3.86. We are in the process of filing an amendment to our most recent Annual Report on Form 10-K, as well as the affected 2003 Quarterly Reports on Form 10-Q to restate our financial statements for 2002 to reflect the adjustments described above and included in this prospectus. Please see note 15 to our Condensed Consolidated and Combined Financial Statements for the year ended December 31, 2002 and Note 12 to our Condensed Consolidated and Combined financial statements for the nine months ended September 30, 2003.
The historical financial statements for all periods prior to the formation of the Partnership differ substantially from our financial statements and unaudited pro forma financial statements, principally because of the contracts we entered into with MarkWest Hydrocarbon at the closing of our initial public offering. The largest of these differences is in revenues and purchased product costs. Historically, revenues and purchased product costs in the MarkWest Hydrocarbon Midstream Business were higher because:
- •
- its revenues included the aggregate sales price for all the NGL products produced in its operations; and
- •
- its purchased product costs included the cost of natural gas purchases needed to replace the Btu content of the NGLs extracted in its processing operations and the percentage of the proceeds from the sale of NGL products remitted to producers under percent-of-proceeds contracts.
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In contrast, after entering into the new contractual arrangements,
- •
- our revenues related to these assets include just the fees we receive for processing natural gas, transporting, fractionating and storing NGLs and the aggregate proceeds from NGL sales we receive under our percent-of-proceeds contracts; and
- •
- our purchased product costs related to these assets primarily consist of the percentage of proceeds from the sale of NGL products remitted to producers under our percent-of-proceeds contracts, with a small portion of our purchased product costs attributable to natural gas purchases to satisfy our obligations under our keep-whole contracts.
Sustaining capital expenditures are capital expenditures made to replace partially or fully depreciated assets in order to maintain the existing operating capacity of our assets and to extend their useful lives. Expansion capital expenditures are capital expenditures made to expand the existing operating capacity of our assets, whether through construction or acquisition. We treat repair and maintenance expenditures that do not extend the useful life of existing assets as plant operating expenses as we incur them.
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| | | | | Partnership | ||||||||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| MarkWest Hydrocarbon Midstream Business | ||||||||||||||||||||||||||
| | | Pro Forma | ||||||||||||||||||||||||
| Year Ended December 31, | Nine Months Ended September 30, 2003 | | Nine Months Ended September 30, 2003 | |||||||||||||||||||||||
| Year Ended December 31, 2002 | ||||||||||||||||||||||||||
| 1998 | 1999 | 2000 | 2001 | 2002(1) | ||||||||||||||||||||||
| (in thousands) | ||||||||||||||||||||||||||
Statement of Operations Data: | |||||||||||||||||||||||||||
Total revenues | $ | 42,676 | $ | 57,490 | $ | 109,810 | $ | 93,675 | $ | 70,246 | $ | 78,741 | $ | 125,688 | $ | 130,028 | |||||||||||
Operating expenses: | |||||||||||||||||||||||||||
Purchased product costs | 26,260 | 33,549 | 71,341 | 65,483 | 38,906 | 45,325 | 68,440 | 85,170 | |||||||||||||||||||
Facility expenses | 8,918 | 10,514 | 13,224 | 13,138 | 15,101 | 14,900 | 23,427 | 19,295 | |||||||||||||||||||
Selling, general and administrative expenses | 3,094 | 3,971 | 4,733 | 5,047 | 5,283 | 4,814 | 9,311 | 5,980 | |||||||||||||||||||
Depreciation | 2,958 | 3,413 | 4,341 | 4,490 | 4,980 | 5,231 | 10,347 | 9,256 | |||||||||||||||||||
Management fee | — | — | — | — | — | — | 1,867 | 1,400 | |||||||||||||||||||
Impairment expense | — | — | — | — | — | — | 1,672 | — | |||||||||||||||||||
Gain on sale of assets | — | — | — | — | — | — | (109 | ) | — | ||||||||||||||||||
Total operating expenses | 41,230 | 51,447 | 93,639 | 88,158 | 64,270 | 70,270 | 114,955 | 121,101 | |||||||||||||||||||
Income from operations | 1,446 | 6,043 | 16,171 | 5,517 | 5,976 | 8,471 | 10,733 | 8,927 | |||||||||||||||||||
Interest expense, net | (824 | ) | (1,741 | ) | (1,697 | ) | (1,307 | ) | (1,414 | ) | (2,592 | ) | (4,239 | ) | (3,985 | ) | |||||||||||
Miscellaneous income (expense) | — | — | — | — | 52 | 51 | (92 | ) | 69 | ||||||||||||||||||
Income before income taxes | 622 | 4,302 | 14,474 | 4,210 | 4,614 | 5,930 | 6,402 | 5,011 | |||||||||||||||||||
Provision for income taxes | 235 | 1,631 | 5,693 | 1,624 | (17,175 | ) | — | — | — | ||||||||||||||||||
Net income | $ | 387 | $ | 2,671 | $ | 8,781 | $ | 2,586 | $ | 21,789 | $ | 5,930 | $ | 6,402 | $ | 5,011 | |||||||||||
Net income per limited partner unit | $ | 4.86 | $ | 1.04 | (1) | $ | 0.91 | $ | 0.70 | ||||||||||||||||||
Balance Sheet Data (at period end): | |||||||||||||||||||||||||||
Working capital | $ | 1,914 | $ | 4,083 | $ | 6,047 | $ | 18,240 | $ | 1,762 | $ | 1,880 | $ | 1,880 | |||||||||||||
Property, plant and equipment, net | 62,564 | 69,695 | 77,501 | 82,008 | 79,824 | 126,177 | 185,662 | ||||||||||||||||||||
Total assets | 69,540 | 80,776 | 95,520 | 104,891 | 87,709 | 142,290 | 201,775 | ||||||||||||||||||||
Total debt, including debt due to parent | 22,875 | 17,956 | 20,782 | 19,179 | 21,400 | 61,300 | 78,432 | ||||||||||||||||||||
Capital/partnership equity | 35,288 | 46,646 | 50,751 | 65,429 | 60,863 | 67,441 | 109,794 | ||||||||||||||||||||
Cash Flow Data: | |||||||||||||||||||||||||||
Net cash flow provided by (used in): | |||||||||||||||||||||||||||
Operating activities | $ | 8,521 | $ | 6,776 | $ | 13,997 | $ | (524 | ) | $ | 33,502 | $ | 16,440 | ||||||||||||||
Investing activities | (9,463 | ) | (10,544 | ) | (12,147 | ) | (8,997 | ) | (2,056 | ) | (52,391 | ) | |||||||||||||||
Financing activities | 942 | 3,768 | (1,850 | ) | 9,521 | (28,670 | ) | 39,548 | |||||||||||||||||||
Other Financial Data: | |||||||||||||||||||||||||||
EBITDA(2) | $ | 4,404 | $ | 9,456 | $ | 20,512 | $ | 10,007 | $ | 11,008 | $ | 13,753 | $ | 20,988 | $ | 18,252 | |||||||||||
Sustaining capital expenditures | $ | 415 | $ | 489 | $ | 955 | $ | 576 | $ | 511 | $ | 691 | |||||||||||||||
Expansion capital expenditures | 9,048 | 10,055 | 11,192 | 9,075 | 1,634 | 1,243 | |||||||||||||||||||||
Total capital expenditures | $ | 9,463 | $ | 10,544 | $ | 12,147 | $ | 9,651 | $ | 2,145 | $ | 1,934 | |||||||||||||||
Operating Data: | |||||||||||||||||||||||||||
Natural gas processed (Mcf/d)(3) | 170,000 | 171,000 | 196,000 | 192,000 | 202,000 | 198,000 | 251,000 | (4) | 249,000 | (4) | |||||||||||||||||
Pipeline throughput (Mcf/d) | 16,000 | 17,800 | 11,000 | 8,800 | 13,800 | 15,700 | 107,100 | (5) | 110,800 | (5) | |||||||||||||||||
NGL product production (gallons/day) | 282,000 | 310,000 | 406,000 | 423,000 | 476,000 | 449,000 | 476,000 | 449,000 | |||||||||||||||||||
NGL sales (gallons) | 10,600,000 | 13,500,000 | 9,200,000 | 8,000,000 | 11,075,000 | 9,112,000 | 11,075,000 | 9,112,000 |
- (1)
- As Restated. See Note 15 to the December 31, 2002 consolidated and combined financial statements of MarkWest Energy Partners, L.P. and Note 12 to the September 30, 2003 condensed consolidated and combined financial statements of MarkWest Energy Partners, L.P.
- (2)
- EBITDA is defined as income before income taxes, plus depreciation and amortization expense and interest expense. We present EBITDA on a partnership basis which includes both the general and limited partner interests. EBITDA (i) is not a measure of performance calculated in accordance with generally accepted accounting principles, or GAAP, and (ii) should not be considered in isolation or as a substitute for net income, income from operations or cash flow as reflected in our financial statements.
- EBITDA is presented because such information is relevant and is used by management, industry analysts, investors, lenders and rating agencies to assess the financial performance and operating results of our fundamental business activities. Management believes that the presentation of EBITDA is useful to lenders and investors because of its use in the midstream natural gas industry and for master limited partnerships as an indicator of the strength and performance of our ongoing business operations, including the ability to fund capital expenditures, service debt and pay distributions. Additionally, management believes that EBITDA provides additional and useful information to our investors for trending, analyzing and benchmarking our operating results from period to period as compared to other companies that may have different financing and capital structures. The presentation of EBITDA allows investors to view our performance in a manner similar to the methods used by management and provides additional insight to our operating results.
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- EBITDA is used by management to determine our operating performance, and along with other data as internal measures for setting annual operating budgets, assessing financial performance of our numerous business locations, as a measure for evaluating targeted businesses for acquisition and as a measurement component of incentive compensation. We have a number of business locations located in different regions of the United Sates. EBITDA can be a meaningful measure of financial performance because it excludes factors which are outside the control of the employees responsible for operating and managing the business locations, and provides information management can use to evaluate the performance of the business locations, or the region where they are located, and the employees responsible for operating them.
- There are material limitations to using a measure such as EBITDA, including the difficulty associated with using it as the sole measure to compare the results of one company to another, and the inability to analyze certain significant items that directly affect a company's net income or loss. In addition, our calculation of EBITDA may not be consistent with similarly titled measures of other companies and should be viewed in conjunction with measurements that are computed in accordance with GAAP. EBITDA for the periods described herein is calculated in the same manner as presented by us in the past. Management compensates for these limitations by considering EBITDA in conjunction with its analysis of other GAAP financial measures, such as gross profit, net income, and cash flow from operating activities. A reconciliation of EBITDA to net income is presented below.
- The following table reconciles EBITDA with our net income:
| | | | | Partnership | ||||||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| MarkWest Hydrocarbon Midstream Business | ||||||||||||||||||||||||
| | | Pro Forma | ||||||||||||||||||||||
| Year Ended December 31, | Nine Months Ended September 30, 2003 | | Nine Months Ended September 30, 2003 | |||||||||||||||||||||
| Year Ended December 31, 2002 | ||||||||||||||||||||||||
| 1998 | 1999 | 2000 | 2001 | 2002(1) | ||||||||||||||||||||
| (in thousands) | ||||||||||||||||||||||||
Net income | $ | 387 | $ | 2,671 | $ | 8,781 | $ | 2,586 | $ | 21,789 | $ | 5,930 | $ | 6,402 | $ | 5,011 | |||||||||
Plus: | |||||||||||||||||||||||||
Interest expense, net | 824 | 1,741 | 1,697 | 1,307 | 1,414 | 2,592 | 4,239 | 3,985 | |||||||||||||||||
Depreciation | 2,958 | 3,413 | 4,341 | 4,490 | 4,980 | 5,231 | 10,347 | 9,256 | |||||||||||||||||
Provision (benefit) for income taxes | 235 | 1,631 | 5,693 | 1,624 | (17,175 | ) | — | — | — | ||||||||||||||||
EBITDA | $ | 4,404 | $ | 9,456 | $ | 20,512 | $ | 10,007 | $ | 11,008 | $ | 13,753 | $ | 20,988 | $ | 18,252 | |||||||||
- (3)
- Represents throughput from our Kenova, Cobb and Boldman processing plants.
- (4)
- Includes operating data for the Arapaho gas processing plant.
- (5)
- Includes operating data for the Appleby gathering system and the Foss Lake gathering system. Excludes operating data for the lateral pipelines acquired in the Pinnacle and Lubbock pipeline acquisitions.
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
You should read the following discussion of our financial condition and results of operations in conjunction with the historical and pro forma combined financial statements and notes thereto included in this prospectus. For more detailed information regarding the basis of presentation for the following information, you should read the notes to the historical and pro forma financial statements included in this prospectus.
We are a Delaware limited partnership formed by MarkWest Hydrocarbon on January 25, 2002 to acquire most of the assets, liabilities and operations of the MarkWest Hydrocarbon Midstream Business. Since our initial public offering in May of 2002, we have significantly expanded our operations through a series of acquisitions. We are engaged in the gathering, processing and transmission of natural gas, the transportation, fractionation and storage of NGL products and the gathering and transportation of crude oil.
To better understand our business and the results of operations discussed below, it is important to have an understanding of two factors:
- •
- the nature of the contracts from which we derive our revenues; and
- •
- the difficulty in comparing our results of operations across periods, both because of our significant and recent acquisition activity, as well as the restructuring of our business in connection with our initial public offering in May 2002.
We generate the majority of our revenues from natural gas gathering, processing and transmission, NGL transportation, fractionation and storage, and crude oil gathering and transportation. While all of these services constitute midstream energy operations, we provide our services pursuant to four different types of contracts:
- •
- Fee-based contracts. Under fee-based contracts, we receive a fee or fees for one or more of the following services: gathering, processing, and transmission of natural gas, transportation, fractionation and storage of NGLs, and gathering and transportation of crude oil. The revenue we earn from these contracts is directly related to the volume of natural gas, NGLs or crude oil that flows through our systems and facilities and is not directly dependent on commodity prices. In certain cases, our contracts provide for minimum annual payments. To the extent a sustained decline in commodity prices results in a decline in volumes, however, our revenues from these contracts would be reduced. On a pro forma basis for the nine months ended September 30, 2003, we would have collectively generated approximately 69% of our gross margin under fee-based contracts.
- •
- Percent-of-proceeds contracts. Under percent-of-proceeds contracts, we generally gather and process natural gas on behalf of producers, sell the resulting residue gas and NGLs at market prices and remit to producers an agreed upon percentage of the proceeds based on an index price. In other cases, instead of remitting cash payments to the producer, we deliver an agreed upon percentage of the residue gas and NGLs to the producer and sell the volumes we keep to third parties at market prices. Under these types of contracts, our revenues and gross margins increase as natural gas prices and NGL prices increase, and our revenues and gross margins decrease as natural gas prices and NGL prices decrease. On a pro forma basis for the nine months ended September 30, 2003, we would have collectively generated approximately 12% of our gross margin under percent-of-proceeds contracts.
57
- •
- Percent-of-index contracts. Under percent-of-index contracts, we generally purchase natural gas at either (1) a percentage discount to a specified index price, (2) a specified index price less a fixed amount or (3) a percentage discount to a specified index price less an additional fixed amount. We then gather and deliver the natural gas to pipelines where we resell the natural gas at the index price, or at a different percentage discount to the index price. With respect to (1) and (3), above, the gross margins we realize under the arrangements described above decrease in periods of low natural gas prices because these gross margins are based on a percentage of the index price. Conversely, our gross margins increase during periods of high natural gas prices. On a pro forma basis for the nine months ended September 30, 2003, we would have collectively generated approximately 13% of our gross margin under percent-of-index contracts.
- •
- Keep-whole contracts. Under keep-whole contracts, we gather natural gas from the producer, process the natural gas and sell the resulting NGLs to third parties at market prices. Because the extraction of the NGLs from the natural gas during processing reduces the Btu content of the natural gas, we must either purchase natural gas at market prices for return to producers or make a cash payment to the producers equal to the value of this natural gas. Accordingly, under these arrangements, our revenues and gross margins increase as the price of NGLs increases relative to the price of natural gas, and our revenues and gross margins decrease as the price of natural gas increases relative to the price of NGLs. On a pro forma basis for the nine months ended September 30, 2003, we would have collectively generated approximately 6% of our gross margin under keep-whole contracts.
In our current areas of operations, we have a combination of contract types and limited keep-whole arrangements. In many cases, we provides services under contracts that contain a combination of more than one of the arrangements described above. The terms of our contracts vary based on gas quality conditions, the competitive environment at the time the contracts are signed and customer requirements. Our contract mix and, accordingly, our exposure to natural gas and NGL prices, may change as a result of changes in producer preferences, our expansion in regions where some types of contracts are more common and other market factors. Any change in mix will impact our financial results.
Items Impacting Comparability of Financial Results
In reading the discussion of our historical results of operations, you should be aware of the impact of both our significant and recent acquisitions, as well as the restructuring we completed in connection with our initial public offering in May 2002. Together, these items fundamentally impact the comparability of our results of operations over the periods discussed.
Our Recent Acquisitions
Since our initial public offering, we have completed four acquisitions for an aggregate purchase price of approximately $112 million. These four acquisitions include:
- •
- the Pinnacle acquisition, which closed on March 28, 2003, for consideration of $39.9 million;
- •
- the Lubbock pipeline acquisition, which closed September 29, 2003, for consideration of $12.2 million;
- •
- the western Oklahoma acquisition, which closed December 1, 2003, for consideration of $38.0 million; and
- •
- the Michigan Crude Pipeline acquisition, which closed December 18, 2003, for consideration of $21.5 million.
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Three of these acquisitions closed in the second half of 2003. Accordingly, our historical results of operations for the nine months ended September 30, 2003 do not fully reflect the impact these acquisitions will have on our operations in future periods. The aggregate impact of each of these acquisitions will fundamentally change our future results of operations. For a more complete understanding of the effects of our recent acquisitions on our financial statements and results of operations, please read "MarkWest Energy Partners, L.P. Unaudited Pro Forma Financial Statements" included elsewhere in this prospectus.
Contractual Restructuring in Connection with our IPO
Our financial statements reflect the MarkWest Hydrocarbon Midstream Business on a historical cost basis for the years ended December 31, 1998 through 2001. Our financial statements for the year ended December 31, 2002 reflect in part the results of the MarkWest Hydrocarbon Midstream Business on a historical cost basis for the period from January 1, 2002 through May 23, 2002 combined with our results for the period from May 24, 2002, the date of our initial public offering, through December 31, 2002. Our results prior to May 24, 2002 include charges from MarkWest Hydrocarbon for direct costs and allocations of indirect corporate overhead and the results of contracts in force at the time. The MarkWest Hydrocarbon Midstream Business predominantly consists of our Appalachian operations. Our results of operations after our initial public offering differ substantially, primarily as a result of the contracts we entered into in connection with our initial public offering. These differences are primarily driven by the way in which we generate revenues and the way in which the MarkWest Hydrocarbon Midstream Business generated revenues. Historically, the MarkWest Hydrocarbon Midstream Business generated its revenues pursuant to keep-whole and percent-of-proceeds contracts.
In connection with our initial public offering, we entered into contracts with MarkWest Hydrocarbon that replaced our keep-whole contracts with fee-based contracts. Entering into these contracts significantly impacted our financial statements before and after the date of our initial public offering. The largest of the differences between the financial statements of the MarkWest Hydrocarbon Midstream Business and our financial statements is in revenues and purchased product costs. Generally, revenues and purchased product costs in the MarkWest Hydrocarbon Midstream Business's financial statements are higher because:
- •
- the MarkWest Hydrocarbon Midstream Business's revenues included the aggregate sales price for all the NGL products produced in its operations; and
- •
- the MarkWest Hydrocarbon Midstream Business's purchased product costs included the cost of natural gas purchases needed to replace the Btu content of the NGLs extracted in its processing operations and the percentage of the proceeds from the sale of NGL products remitted to producers under percent-of-proceeds contracts.
In contrast, after entering into the new contractual arrangements,
- •
- our revenues related to these assets include just the fees we receive for processing natural gas, transporting, fractionating and storing NGLs and the aggregate proceeds from NGL sales we receive under our percent-of-proceeds contracts; and
- •
- our purchased product costs related to these assets primarily consist of the percentage of proceeds from the sale of NGL products remitted to producers under our percent-of-proceeds contracts, with a small portion of our purchased product costs attributable to natural gas purchases to satisfy our obligations under our keep-whole contracts.
Our facility expenses, similar to the MarkWest Hydrocarbon Midstream Business, principally consist of those expenses needed to operate our facilities, including applicable personnel costs, fuel, plant utility costs and maintenance expenses. One difference between our Appalachian plant operating expenses and those of the MarkWest Hydrocarbon Midstream Business is fuel costs. MarkWest Hydrocarbon retains the producer fuel reimbursement related to these plants.
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Our general and administrative expenses are dictated by the terms of the omnibus agreement between MarkWest Hydrocarbon and us. We reimburse MarkWest Hydrocarbon monthly for the general and administrative support it provided us in the prior month.
The Partnership previously reported two separate statements of operations and of cash flows for the year ended December 31, 2002. One statement of operations and one statement of cash flows was presented for the period from January 1, 2002 through May 23, 2002 for the MarkWest Hydrocarbon Midstream Business prior to its conveyance to the Partnership on May 24, 2002. Another statement of operations and statement of cash flows was presented for the period from May 24, 2002 through December 31, 2002.
The conveyance of the MarkWest Hydrocarbon Midstream Business from MarkWest Hydrocarbon to the Partnership represented a reorganization of entities under common control and was recorded at historical cost. Consequently, the Partnership has now determined that it should have combined these statements and presented them for the full year ended December 31, 2002.
In addition, the Partnership had previously reported net income per limited partner unit for the period from May 24, 2002 through December 31, 2002. In its restated financial statements, the Partnership has restated income per limited partner unit to report such amount for the year ended December 31, 2002. Further, the Partnership has now reported income per limited partner unit for the years ended December 31, 2001 and 2000. Finally, the elimination of the deferred tax liability resulting from our conversion to partnership form had previously been credited to the partners' capital portion of the Partnership's balance sheet without impacting our statement of operations. In our revised presentation, the elimination of the deferred tax liability is reflected in the statement of operations as a part of the provision (benefit) for income taxes, increasing net income and income per unit and ultimately reflected in the partners' capital portion of the balance sheet. Accordingly, the adjustment results in no net change to the balance sheet of the Partnership. See Note 15 to our Condensed Consolidated and Combined Financial Statements for more information.
Nine Months Ended September 30, 2003 Compared to Nine Months Ended September 30, 2002
Revenues. Revenues were $78.7 million for the nine months ended September 30, 2003, compared to our combined revenues of $55.8 million for the nine months ended September 30, 2002, an increase of $23.0 million, or 41%. Revenues were higher in 2003 than in 2002 primarily due to the Pinnacle acquisition and, to a lesser extent, the Lubbock pipeline acquisition, which collectively added $32.8 million in revenues, partially offset by the impact of contracts entered into by us with MarkWest Hydrocarbon concurrent with the closing of our initial public offering. You should read "—Items Impacting Comparability of Financial Results" for a detailed discussion of the financial statement line item differences between the Partnership and the MarkWest Hydrocarbon Midstream Business.
Purchased Product Costs. Purchased product costs were $45.3 million for the nine months ended September 30, 2003, compared to our combined purchased product costs of $33.0 million for the nine months ended September 30, 2002, an increase of $12.3 million, or 37%. Purchased product costs were higher in 2003 than in 2002 primarily due to the Pinnacle acquisition, which increased purchased product costs $26.7 million. The Pinnacle acquisition impact was partially offset by the effect of new contracts entered into by us with MarkWest Hydrocarbon concurrent with the closing of our initial public offering.
Facility Expenses. Facility expenses were $14.9 million for the nine months ended September 30, 2003, compared to our combined facility expenses of $10.9 million for the nine months ended September 30, 2002, an increase of $4.0 million, or 36%. The Pinnacle acquisition and the Lubbock pipeline acquisition collectively increased facility expenses by $1.9 million. The remainder of the
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increase is principally attributable to higher fuel and repair costs in Appalachia and increased throughout in Michigan.
Selling, General and Administrative Expenses. Selling, general and administrative expenses were $4.8 million for the nine months ended September 30, 2003, compared to our combined selling, general and administrative expenses of $3.6 million for the nine months ended September 30, 2002, an increase of $1.2 million, or 33%. Selling, general and administrative expenses increased principally due to the Pinnacle acquisition and non-cash compensation expense related to employee grants of restricted units.
Depreciation. Depreciation expense was $5.2 million for the nine months ended September 30, 2003, compared to $3.7 million for the nine months ended September 30, 2002, an increase of $1.5 million, or 41%. Depreciation expense increased primarily due to the Pinnacle acquisition.
Interest Expense. Interest expense was $2.6 million for the nine months ended September 30, 2003, compared to $1.0 million for the nine months ended September 30, 2002, an increase of $1.6 million, or 162%. Interest expense increased due to additional debt used for the financing of the Pinnacle acquisition and Lubbock pipeline acquisition.
Income Taxes. The Partnership has not been subject to income taxes since its inception on May 24, 2002.
Year Ended December 31, 2002 Compared to Year Ended December 31, 2001
Revenues. Our combined revenues were $70.2 million for the year ended December 31, 2002, compared to $93.7 million for the year ended December 31, 2001, a decrease of $23.4 million, or 25%. Revenues were lower in 2002 than in 2001 primarily due to the terms of the new contracts entered into by us with MarkWest Hydrocarbon concurrent with the closing of our initial public offering. On the percent-of-proceed contracts retained by the Partnership, average NGL product sales prices were lower in the 2002 period than in the comparable 2001 period.
Purchased Product Costs. Our combined purchased product costs were $38.9 million for the year ended December 31, 2002, compared to $65.5 million for the year ended December 31, 2001, a decrease of $26.6 million, or 41%. Purchased product costs were lower in 2002 primarily due to the terms of new contracts entered into by MarkWest Hydrocarbon and us concurrent with the closing of our initial public offering.
Facility Expenses. Our combined facility expenses were $15.1 million for the year ended December 31, 2002, compared to $13.1 million for the year ended December 31, 2001, an increase of $2.0 million, or 15%. Facility expenses increased due to increased throughput in our Michigan facilities and the expansion of our Kenova processing plant.
Selling, General and Administrative Expenses. Our combined selling, general and administrative expenses were $5.3 million for the year ended December 31, 2002, compared to $5.0 million for the year ended December 31, 2001, an increase of $0.2 million, or 5%. Selling, general and administrative expenses increased principally due to the Partnership's incremental costs associated with being a publicly traded company, as well as increased insurance costs.
Depreciation. Our combined depreciation expense was $5.0 million for the year ended December 31, 2002, compared to $4.5 million for the year ended December 31, 2001, an increase of $0.5 million, or 11%. The increase is principally attributable to additional fixed assets placed into service during the second half of 2001.
Interest Expense. Our combined interest expense was $1.4 million for the year ended December 31, 2002, compared to $1.3 million for the year ended December 31, 2001 an increase of $0.1 million, or 8%.
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Income Taxes. The Partnership has not been subject to income taxes since its inception on May 24, 2002. The Midstream Business recorded a non-cash adjustment of $17.2 million to eliminate deferred income tax liabilities that existed at the date of conveyance of the MarkWest Hydrocarbon Midstream Business from MarkWest Hydrocarbon to the Partnership. Accordingly, the Midstream Business has recorded a benefit to the deferred tax provision for the year ended December 31, 2002, which increased net income by $17.2 million.
Year Ended December 31, 2001 Compared to the Year Ended December 31, 2000
Revenues. Revenues were $93.7 million for the year ended December 31, 2001 compared to $109.8 million for the year ended December 31, 2000, a decrease of $16.1 million, or 15%. Revenues were lower in 2001 than in 2000 primarily due to a decrease in the average Appalachian NGL sales price, which accounted for $14.9 million of the decrease. The average Appalachian NGL sales price was $0.53 per gallon for the year ended December 31, 2001, compared to $0.63 per gallon for the year ended December 31, 2000, a decrease of $0.10 per gallon, or 16%. Appalachian NGL sales volumes remained essentially flat from 2000 to 2001. Lower Michigan NGL sales volumes in 2001, a result of decreased pipeline throughput, accounted for the remainder of the decrease in revenues and were partially offset by a modest increase in average Michigan NGL sales price during 2001.
Purchased Product Costs. Purchased product costs were $65.5 million for the year ended December 31, 2001, compared to $71.3 million for the year ended December 31, 2000, a decrease of $5.9 million, or 8%. Purchased product costs were lower in 2001 primarily due to:
- •
- a decrease in the average Appalachian replacement natural gas cost, which accounted for an approximately $4.1 million decrease in purchased product costs. The average cost of Appalachian replacement natural gas was equivalent to $0.39 per NGL gallon for the year ended December 31, 2001, compared to $0.42 per gallon for the year ended December 31, 2000, a decrease of $0.03 per gallon, or 7%.
- •
- a decrease in our average Appalachian NGL prices, which accounted for $2.4 million of the decrease. Reduced average Appalachian NGL prices reduced the percent of proceeds remitted to an Appalachian producer.
- •
- increased transportation costs, a result of an increase in the number of our sales outlets, partially offset the decrease in the average Appalachian replacement natural gas cost.
Facility Expenses. Facility expenses were $13.1 million for the year ended December 31, 2001, compared to $13.2 million for the year ended December 31, 2000, a decrease of $0.1 million, or 1%.
Selling, General and Administrative Expenses. Selling, general and administrative expenses were $5.0 million for the year ended December 31, 2001, compared to $4.7 million for the year ended December 31, 2000, an increase of $0.3 million, or 7%.
Depreciation. Depreciation expense was $4.5 million for the year ended December 1, 2001, compared to $4.3 million for the year ended December 31, 2000, an increase of $0.1 million, or 3%.
Interest Expense. Interest expense was $1.3 million for the year ended December 31, 2001, compared to $1.7 million for the year ended December 31, 2000, a decrease of $0.4 million, or 23%. The decrease was principally caused by a reduction in interest rates throughout 2001.
Income Taxes. Income taxes for the year ended December 31, 2001, were $1.6 million, compared to $5.7 million for the year ended December 31, 2000, a decrease of $4.1 million, or 72%. Income taxes decreased principally due to lower income before income taxes.
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Net Income. Net income for the year ended December 31, 2001, was $2.6 million, compared to $8.8 million for the year ended December 31, 2000, a decrease of $6.2 million, or 71%. Net income decreased principally as a result of decreased average Appalachian NGL sales prices.
With respect to our percent-of-proceeds contracts, we are dependent, in some cases, upon the sales prices of NGL products, particularly propane, which fluctuate with winter weather conditions and other supply and demand determinants. After giving pro forma effect to the Pinnacle, Lubbock pipeline, western Oklahoma and Michigan Crude Pipeline acquisitions, these percent-of-proceeds contracts would have accounted for approximately 12% of gross margin for the nine months ended September 30, 2003.
Liquidity and Capital Resources
Cash Flows. Net cash provided by operating activities was $16.4 million for the nine months ended September 30, 2003, compared to our combined cash flow of $29.1 million for the nine months ended September 30, 2002. The difference in net cash provided by operating activities is attributable to the inherent differences in the businesses and contracts of the Partnership and the MarkWest Hydrocarbon Midstream Business.
Our combined net cash provided by operating activities was $33.5 million for the year ended December 31, 2002. Net cash used in operating activities was $0.5 million for the year ended December 31, 2001. Net cash provided by operating activities was higher in 2002 than in 2001 primarily due to new, ongoing contracts as well as the initial contracts entered into by us with MarkWest Hydrocarbon concurrent with the closing of our initial public offering.
Net cash used in investing activities was $52.4 million for the nine months ended September 30, 2003, compared to our combined net cash used in investing activities of $1.9 million for the nine months ended September 30, 2002. The increase was primarily due to the Pinnacle acquisition and the Lubbock pipeline acquisition.
Our combined net cash used in investing activities was $2.1 million for the year ended December 31, 2002, compared to $9.0 million for the year ended December 31, 2001, for the MarkWest Hydrocarbon Midstream Business. The decrease was principally attributable to the level of construction in Appalachia during 2001, which has since been completed.
Net cash provided by financing activities was $39.5 million for the nine months ended September 30, 2003. Our combined net cash used in financing activities was $25.8 million for the nine months ended September 30, 2002. Net cash provided by financing activities for 2003 was from borrowings used to finance the Pinnacle and Lubbock pipeline acquisitions and proceeds from the private placement of common units. In June 2003, we sold 375,000 common units to certain accredited investors in a private placement, with net proceeds of approximately $9.7 million, excluding the general partner contribution. These proceeds were used to reduce outstanding indebtedness. Financing activities through September 30, 2002 primarily represented repayments to MarkWest Hydrocarbon following the MarkWest Hydrocarbon Midstream Business's seasonal conversion of working capital to cash.
Our combined net cash used in financing activities was $28.7 million for the year ended December 31, 2002, compared to net cash provided by financing activities of $9.5 million for the year ended December 31, 2001, for the MarkWest Hydrocarbon Midstream Business. The financing activities for the year ended December 31, 2002, reflect the Partnership's initial public offering and related transactions.
Capital Requirements. The natural gas gathering, processing and transmission, NGL transportation, fractionation and storage and the crude oil gathering and transportation businesses are
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capital-intensive, requiring significant investment to upgrade or enhance existing operations. The capital requirements of these businesses consist primarily of:
- •
- sustaining capital expenditures, which are capital expenditures made to replace partially or fully depreciated assets in order to maintain the existing operating capacity of our assets and to extend their useful lives; and
- •
- expansion capital expenditures such as those to acquire additional assets to grow our business, to expand and upgrade plant or pipeline capacity and to construct new plants, pipelines and storage facilities.
Sustaining capital expenditures are estimated to be approximately $0.5 million for 2004. Additionally, our expected budget for gathering system pipeline connections and other system improvements for 2004 is $1.8 million. Under certain circumstances, the party from which we acquired the Pinnacle assets has the right to require us to purchase an additional lateral pipeline for up to $2.5 million.
We believe that cash generated from operations and funds available under our credit facility will be sufficient to meet both our short-term and long-term working capital requirements and sustaining capital expenditures. We fund our growth capital expenditures from cash provided by operations and, to the extent necessary, from the proceeds of borrowings under the bank credit facility and the issuance of additional common units. The Lubbock pipeline acquisition, the western Oklahoma acquisition and the Michigan Crude Pipeline acquisition were financed through borrowings under our credit facility.
Our ability to pay distributions to our unitholders and to fund planned capital expenditures and to make acquisitions will depend upon our future operating performance, which will be affected by prevailing economic conditions in our industry and financial, business and other factors, some of which are beyond our control.
Our primary customer remains MarkWest Hydrocarbon. On a pro forma basis for the nine months ended September 30, 2003, MarkWest Hydrocarbon accounted for 14% of our revenues and 41% of our gross margin. Consequently, matters affecting the business and financial condition of MarkWest Hydrocarbon—including its operations, management, customers, vendors, and the like—have the potential to impact, both positively and negatively, our liquidity. For a full discussion of matters affecting MarkWest Hydrocarbon, please read "Business—Our Relationship with MarkWest Hydrocarbon."
Total Contractual Cash Obligations. A summary of our total contractual cash obligations as of December 31, 2002, is as follows:
| | Payment due by period (in thousands) | ||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Type of Obligation | Total Obligation | Due in 2003 | Due in 2004-2005 | Due in 2006-2007 | Thereafter | |||||||||||
Operating Leases | $ | 2,495 | $ | 527 | $ | 1,054 | $ | 590 | $ | 324 | ||||||
Debt | 21,400 | — | 21,400 | — | — | |||||||||||
Total | $ | 23,895 | $ | 527 | $ | 22,454 | $ | 590 | $ | 324 | ||||||
Description of the Credit Facility. We have a revolving credit facility, under which up to $140 million (including letters of credit) is available to fund capital expenditures and acquisitions, working capital requirements and distributions to unitholders. Not more than $0.50 per outstanding unit, however, may be used in any twelve consecutive month period to fund distributions to unitholders. We are in the process of amending this facility to provide that any amount so borrowed must be repaid once annually. At December 1, 2003, $101.3 million was outstanding under our credit facility. Upon completion of this offering, we expect to have available borrowing capacity of approximately $62 million under our credit facility.
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We may prepay all loans at any time without penalty.
Indebtedness under our credit facility will bear interest, at our operating company's option, at either (i) the higher of the federal funds rate plus 0.50% or the prime rate as announced by lender plus an applicable margin of 0.625% to 2.125% or (ii) at a rate equal to LIBOR plus an applicable margin ranging from 2.00% per annum to 3.50% per annum depending on our ratio of Consolidated Funded Debt (as defined in the credit agreement) to Consolidated EBITDA (as defined in the credit agreement) for the four most recently completed fiscal quarters. As of December 1, 2003, the weighted average interest rate was 4.67%.
Our operating company incurs a commitment fee on the unused portion of the credit facility at a rate ranging from 37.5 to 50.0 basis points based upon the ratio of our Consolidated Funded Debt (as defined in the credit agreement) to Consolidated EBITDA (as defined in the credit agreement) for the four most recently completed fiscal quarters. The credit facility matures in November 2006. At that time, the credit facility will terminate and all outstanding amounts thereunder will be due and payable.
Our credit agreement contains various covenants that limit, among other things, our ability to:
- •
- incur indebtedness;
- •
- grant liens;
- •
- make loans, acquisitions and investments;
- •
- amend our material agreements, including certain agreements with MarkWest Hydrocarbon;
- •
- acquire another company;
- •
- enter into a merger, consolidation or sale of assets; or
- •
- make distributions in excess of Available Cash (as defined in the Partnership Agreement) for the preceding fiscal quarter.
Our credit agreement also contains covenants requiring us to maintain:
- •
- a ratio of not less than 3.50 to 1 of Consolidated EBITDA to interest expense for the prior fiscal quarter;
- •
- a ratio of not more than 4.75 to 1 prior to March 2004 and 3.50 to 1 after March 2004 of total debt to Consolidated EBITDA for the prior fiscal quarter;
- •
- a minimum net worth of $55 million plus 75% of the proceeds of equity issued after December 1, 2003; and
- •
- a ratio of not more than 3.00 to 1 of Consolidated EBITDA to cash interest payments on indebtedness for the prior fiscal quarter in the event that MarkWest Hydrocarbon has freely available cash reserves of less than $17.5 million.
If an event of default exists under the credit agreement, the lenders are permitted to accelerate the maturity of the credit agreement and exercise other rights and remedies. Each of the following is an event of default:
- •
- failure to pay any principal when due or any interest, fees or other amount when due;
- •
- failure of any representation or warranty to be materially true and correct;
- •
- failure to perform or otherwise comply with the covenants in the credit agreement or other loan documents, subject to certain grace periods;
- •
- default by us or any of our subsidiaries on the payment of any other indebtedness in excess of $5 million, or any default in the performance of any obligation or condition with respect to such
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- •
- bankruptcy or insolvency events involving us, our general partner or our subsidiaries;
- •
- the termination of any material agreement, if not replaced in a manner reasonably satisfactory to the lenders, that is reasonably expected to have a material adverse effect;
- •
- material default by any party to any material agreement, which is not cured within the time period specified in the material agreement for cure, that is reasonably expected to have a material adverse effect;
- •
- the entry, and failure to pay or contest in good faith, of one or more adverse judgments in an aggregate amount of $5 million or more in excess of third party insurance coverage;
- •
- Change of Control (as defined in the credit agreement); and
- •
- invalidity of any loan documentation.
indebtedness beyond the applicable grace period if the effect of the default is to permit or cause the acceleration of the indebtedness;
We and the subsidiaries of our operating company have given full, unconditional and joint and several guarantees of any obligation under the credit facility and have pledged substantially all of our assets to secure the credit facility.
The selection and application of accounting policies is an important process that has developed as our business activities have evolved and as the accounting rules have developed. Accounting rules generally do not involve a selection among alternatives, but involve an implementation and interpretation of existing rules, and the use of judgment, to the specific set of circumstances existing in our business. We make every effort to properly comply with all applicable rules on or before their adoption, and we believe the proper implementation and consistent application of the accounting rules is critical. Our critical accounting policy is discussed below. For further details on our accounting policies and a discussion of new accounting pronouncements, see Notes to Consolidated and Combined Financial Statements.
Impairment of Long-Lived Assets
In accordance with Statement of Financial Accounting Standards (SFAS) No. 144,Accounting for the Impairment or Disposal of Long-Lived Assets, we evaluate the long-lived assets, including related intangibles, of identifiable business activities for impairment when events or changes in circumstances indicate, in management's judgment, that the carrying value of such assets may not be recoverable. The determination of whether impairment has occurred is based on management's estimate of undiscounted future cash flows attributable to the assets as compared to the carrying value of the assets. If impairment has occurred, the amount of the impairment recognized is determined by estimating the fair value for the assets and recording a provision for loss if the carrying value is greater than fair value. For assets identified to be disposed of in the future, the carrying value of these assets is compared to the estimated fair value less the cost to sell to determine if impairment is required. Until the assets are disposed of, an estimate of the fair value is recalculated when related events or circumstances change.
When determining whether impairment of one of our long-lived assets has occurred, we must estimate the undiscounted cash flows attributable to the asset. Our estimate of cash flows is based on assumptions regarding the volume of reserves behind the asset and future NGL product and natural gas prices. The amount of reserves and drilling activity are dependent in part on natural gas prices.
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Projections of reserves and future commodity prices are inherently subjective and contingent upon a number of variable factors, including but not limited to:
- •
- changes in general economic conditions in regions in which our operations are located;
- •
- the availability and prices of NGL products 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 Hydrocarbon's (in the case of Michigan) 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; and
- •
- competition from other NGL processors, including major energy companies.
Any significant variance in any of the above assumptions or factors could materially affect our cash flows, which could require us to record an impairment of an asset.
Our operations are subject to environmental laws and regulations adopted by various governmental authorities in the jurisdictions in which these operations are conducted. We believe we are in material compliance with all applicable laws and regulations. For a more complete discussion of the environmental laws and regulations that impact us, see "Business—Environmental Matters."
Recent Accounting Pronouncements
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 did not have a material impact on our financial position or results of operations.
In June 2001, the FASB issued SFAS No. 143,Accounting for Asset Retirement Obligations, which addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. The standard applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset. SFAS No. 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset and this additional carrying amount is depreciated over the life of the asset. The liability is accreted at the end of each period through charges to operating expense. If the obligation is settled for other than the carrying amount of the liability, a gain or loss is recognized on settlement. The provisions of this statement are effective for fiscal years beginning after June 15, 2002. With respect to our midstream services, we have certain surface facilities with ground leases requiring us to dismantle and remove these facilities upon the termination of the applicable lease. We anticipate recording a liability, if one can be reasonably estimated, for such obligations in the first quarter of 2003.
In January 2002, the FASB Emerging Issues Task Force released Issue No. 02-3,Issues Related to Accounting for Contracts Involved in Energy Trading and Risk Management Activities. The Task Force reached a consensus to rescind EITF Issue No. 98-10,Accounting for Contracts Involved in Energy Trading and Risk Management Activities, the impact of which is preclude mark-to-market accounting for all energy trading contracts not within the scope of FASB Statement No. 133,Accounting for Derivative
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Instruments and Hedging Activities. The Task Force also reached a consensus that gains and losses on derivative instruments within the scope of Statement 133 should be shown net in the income statement if the derivative instruments are held for trading purposes. The consensus regarding the rescission of Issue 98-10 is applicable for fiscal periods beginning after December 15, 2002. We do not have any trading activities and did not account for any contracts as trading contracts in accordance with EITF Issue No. 98-10. Therefore, the EITF consensus to rescind EITF Issue No. 98-10 will not have an impact on our financial position or results of operations.
In April 2002, the FASB issued SFAS No. 145,Rescission of SFAS Nos. 4, 44 and 64; Amendment of SFAS Statement No. 13; andTechnical Corrections, which is generally effective for transactions occurring after May 15, 2002. Through the rescission of SFAS Nos. 4 and 64, SFAS No. 145 eliminates the requirement that gains and losses from extinguishments of debt be aggregated and, if material, be classified as an extraordinary item net of any income tax effect. SFAS No. 145 made several other technical corrections to existing pronouncements that may change accounting practice. SFAS No. 145 did not impact on our results of operations or financial position.
In June 2002, the FASB issued SFAS No. 146,Accounting for Costs Associated with Exit or Disposal Activities. SFAS No. 146 is effective for exit or disposal activities that are initiated after December 31, 2002. This Statement addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies EITF Issue No. 94-3,Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring). We do not believe that the adoption of SFAS No. 146 will have a material impact on our results of operations or financial position.
In November 2002, FASB Interpretation No. 45,Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others (FIN 45), was issued. The accounting recognition provisions of FIN 45 are effective January 1, 2003 on a prospective basis. They require that a guarantor recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. Under prior accounting principles, a guarantee would not have been recognized as a liability until a loss was probable and reasonably estimable. As FIN 45 only applies to prospective transactions, we are unable to determine the impact, if any, that adoption of the accounting recognition provisions of FIN 45 would have on our future financial position or results of operations.
In January of 2003, the FASB issued Interpretation No. 46,Consolidation of Variable Interest Entities, an interpretation of ARB No. 51 (FIN 46), which requires the consolidation of certain variable interest entities, as defined. FIN 46 is effective immediately for variable interest entities created after January 31, 2003, with disclosures are required currently if a company expects to consolidate any variable interest entities. On December 24, 2003, the FASB issued FIN 46 R which revised FIN 46 and extended certain applications of FIN 46 to financial statements for periods ending after March 15, 2004. We do not have investments in any variable interest entities, and therefore, the adoption of FIN 46 is not expected to have an impact on our results of operations, financial position or cash flows.
Quantitative and Qualitative Disclosures About Market Risk
Market risk is the risk of loss arising from adverse changes in market rates and prices. We face market risk from commodity price variations, primarily in the NGL products we sell. We also incur, to a lesser extent, credit risks and risks related to interest rate variations.
Commodity Price Risk. On a pro forma basis as of September 30, 2003, approximately 12% of our gross margin was directly subject to NGL product price risk. Our Maytown gas processing plant in Appalachia and our Michigan operations have percent-of-proceeds contracts. Under percent-of-proceeds contracts, we, as the processor, retain a portion of the sales price of the NGL products produced as compensation for our services. Additionally, we are subject to natural gas price risk as a result of our Pinnacle, Lubbock pipeline and western Oklahoma acquisitions. We gather and
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transport natural gas for producers behind our gathering systems, primarily under percent-of proceeds or percent-of-index contracts.
Our primary risk management objective is to manage our price risk, thereby reducing 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. A committee, which includes members of senior management of our general partner, oversees all of our hedging activity.
We may utilize a combination of fixed-price forward contracts, fixed-for-float price swaps and options on over-the-counter (OTC) market. New York Mercantile Exchange (NYMEX) traded futures are authorized for use. Swaps and futures allow us to protect our margins because corresponding losses or gains in the value of financial instruments are generally offset by gains or losses in the physical market.
We enter OTC swaps with counterparties that are primarily financial institutions. 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 (with non-bank counterparties) and NYMEX positions.
The use of financial instruments may expose us to the risk of financial loss in certain circumstances, including instances when (i) NGLs do not trade at historical levels relative to crude oil, (ii) sales volumes are less than expected requiring market purchases to meet commitments, or (iii) our OTC counterparties fail to purchase or deliver the contracted quantities of 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 may be similarly insulated against unfavorable changes in such prices.
We are also subject to basis risk. 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. We have two different types of NGL product basis risk. First, NGL product basis risk stems from the geographic price differentials between our sales locations and hedging contract delivery locations. We cannot hedge our geographic basis risk because there are no readily available products or markets. Second, NGL product basis risk also results from the difference in relative price movements between crude oil and NGL products. We may use crude oil, instead of NGL products, in our hedges because the NGL hedge products and markets are limited. Crude oil is typically highly correlated with certain NGL products. It is generally not cost effective to hedge our basis risk for NGL products.
We hedge our Appalachian and Michigan NGL product sales by selling forward propane or crude oil. As of September 30, 2003, we have hedged NGL product sales as follows:
| Year Ending December 31, 2003 | |||
---|---|---|---|---|
Butanes and Natural Gasoline Volumes Hedged Using Crude Oil | ||||
NGL gallons | 869,000 | |||
NGL sales price per gallon | $ | 0.50 | ||
Propane Volumes Hedged Using Propane | ||||
NGL gallons | 315,000 | |||
NGL sales price per gallon | $ | 0.41 | ||
Total NGL Volumes Hedged | ||||
NGL gallons | 1,184,000 | |||
NGL sales price per gallon | $ | 0.48 |
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All projected margins or prices on open positions assume (a) the basis differentials between our sales location and the hedging contract's specified location, and (b) the correlation between crude oil and NGL products, are consistent with historical averages.
We hedge our natural gas price risk in the Southwest by entering into fixed-for-float swaps or by purchasing puts. As of September 30, 2003, we had hedged our Southwest natural gas price risk via swaps as follows:
| Year Ending December 31, | ||||||||
---|---|---|---|---|---|---|---|---|---|
| 2003 | 2004 | 2005 | ||||||
MMBtu | 46,000 | 183,000 | 182,500 | ||||||
$/MMBtu | $ | 5.09 | $ | 4.57 | $ | 4.26 |
As of September 30, 2003, we had hedged our Southwest natural gas price risk via puts as follows:
| Year Ending December 31, | |||||
---|---|---|---|---|---|---|
| 2003 | 2004 | ||||
MMBtu | 92,000 | 366,000 | ||||
Strike price ($/MMBtu) | $ | 4.50 | $ | 4.00 |
Interest Rate Risk. We are exposed to changes in interest rates, primarily as a result of our long-term debt under our credit facility with floating interest rates. We make use of interest rate swap agreements expiring May 19, 2005 to adjust the ratio of fixed and floating rates in the debt portfolio. As of September 30, 2003, we are a party to contracts to fix interest rates on $8.0 million of our debt at 3.84% compared to floating LIBOR, plus an applicable margin.
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We are a rapidly growing, independent midstream energy company engaged in the gathering, processing and transmission of natural gas, the transportation, fractionation and storage of NGLs and the gathering and transportation of crude oil. A substantial portion of our revenues and cash flow are generated from providing fee-based services to our customers, which provides us with a relatively stable base of cash flows. We have three primary geographic areas of operation:
- •
- Appalachia. We are the largest processor of natural gas in the Appalachian basin, one of the country's oldest natural gas producing regions. Our Appalachian assets include five natural gas processing plants, 136 miles of NGL pipeline, a NGL fractionation plant and an 11 million-gallon underground NGL storage facility.
- •
- Southwest. We own an aggregate of 302 miles of natural gas gathering pipelines in 21 gathering systems in Texas, Oklahoma, Kansas, Louisiana, Mississippi and New Mexico. We also own a gas processing plant and four Texas intrastate gas transmission pipelines that transmit natural gas to power plants, municipalities and other large industrial end users.
- •
- Michigan. We own a 90-mile gas gathering pipeline and one natural gas processing plant in Michigan. We also own approximately 250 miles of intrastate crude gathering pipeline, which we refer to as the Michigan Crude Pipeline, the primary intrastate crude oil pipeline in Michigan.
In these three areas we provide midstream services to our customers under four types of contracts. On a pro forma basis for the nine months ended September 30, 2003, we generated approximately 69% of our gross margin from contracts under which we charge fees for providing midstream services. Gross margin from these fee-based services is dependent on throughput volume and is typically less affected by short-term changes in commodity prices. The remainder of our gross margin is generated pursuant to percent-of-index, percent-of-proceeds and keep-whole contracts and is more affected by changes in commodity prices. Under percent-of-index contracts we purchase natural gas at a percentage discount to a specified index price and then deliver the natural gas to pipelines where we resell the natural gas at the index price or at a different percentage discount to the index price. Under percent-of-proceeds arrangements, we gather and process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at market prices and remit to the producers an agreed upon percentage of the proceeds based on an index price. Under keep-whole arrangements, we gather natural gas from the producer, process the natural gas and sell the resulting NGLs to third parties at market prices. Because the extraction of the NGLs from the natural gas during processing reduces the Btu content of the natural gas, we must either purchase natural gas at market prices for return to producers or make a cash payment to the producers equal to the value of this natural gas.
We have grown rapidly through acquisitions and construction and expansion of our assets. Since our initial public offering in May 2002, we have completed four acquisitions with an aggregate purchase price of approximately $112 million. We have primarily financed these acquisitions through borrowings under our credit facility. Our net income was $5.9 million for the nine months ended September 30, 2003. On a pro forma basis, as adjusted for this offering and our recent acquisitions, including the Lubbock pipeline since its acquisition in September 2003 net income for the nine months ended September 30, 2003 would have been $5.0 million. Our EBITDA was $13.8 million for the nine months ended September 30, 2003. On a pro forma basis, as adjusted for this offering and our recent acquisitions, including the Lubbock pipeline since its acquisition in September 2003, and for this offering, EBITDA for the nine months ended September 30, 2003 would have been $18.3 million. For a discussion of EBITDA and a reconciliation of EBITDA to net income, please read footnote (1) to "Summary Historical and Pro forma Financial and Operating Data."
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At the closing of our initial public offering, all of our assets and operations were concentrated in the Appalachian region and Michigan, and our operations consisted solely of the gathering and processing of natural gas and the transportation, fractionation and storage of NGLs. Our operations were largely dependent on MarkWest Hydrocarbon, which accounted for approximately 43% of our revenue and 69% of our gross margin for the period from May 24, 2002 to December 31, 2002. As a result of our four recent acquisitions, we now have operations in nine states and have expanded our operations into the gathering, processing and transmission of natural gas in the Southwest and the gathering and transportation of crude oil in Michigan. These acquisitions have reduced our dependence on MarkWest Hydrocarbon. On a pro forma basis, for the nine-months ended September 30, 2003, MarkWest Hydrocarbon accounted for approximately 14% and 41%, respectively, of our revenue and gross margin.
Our competitive strengths include:
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- Strategic Position in the Appalachian basin and Michigan.
- •
- We are the largest processor of natural gas in Appalachia and we believe our significant presence and asset base there provides us with a competitive advantage in capturing new supplies of natural gas. The Appalachian basin is a large natural gas producing region characterized by long-lived reserves, modest decline rates and natural gas with high NGL content providing our operations with a stable supply of natural gas for our processing plants and our Siloam NGL fractionation plant. In addition, the Appalachian basin is characterized by consistently high levels of drilling activity, which supplies us with significant opportunities to access new supplies of natural gas and NGLs. The concentration and integration of our Appalachian operations and the efficiencies of our facilities create operational synergies that allow us to provide cost effective service to our customers. For example, we are able to transport a majority of the NGLs we extract at our processing plants to our Siloam fractionator via our pipeline, lowering our transportation costs. Our concentrated infrastructure and available land and storage assets in Appalachia provide us with a platform for additional cost-effective expansion.
- •
- Our recent acquisition of the Michigan Crude Pipeline allowed us to enter into the crude oil transportation business and significantly expanded our presence in Michigan. In addition to our natural gas gathering and processing operations, we are now the primary intrastate pipeline transporter of crude oil in Michigan. This gives us a competitive advantage over other higher cost crude oil transport methods, such as trucking. The Niagaran Reef Trend, from which the majority of our natural gas and crude oil in the state is produced, is generally characterized by long-lived natural gas and crude oil reserves.
- •
- Growing Presence in the Southwest. Our recent Pinnacle, Lubbock pipeline and western Oklahoma acquisitions have allowed us to expand our presence in long-lived natural gas basins in the Southwest, particularly in Texas and Oklahoma. The Pinnacle gathering systems and the western Oklahoma assets are strategically located in the East Texas and Permian basins and the Anadarko basin in Oklahoma. Each of these areas is undergoing significant development and exploration activities and provides us with an opportunity to capture additional supplies of natural gas. The lateral natural gas pipelines acquired in the Pinnacle acquisition and the Lubbock pipeline acquisition allowed us to establish natural gas transmission operations in Central and West Texas. We believe we can use our proven expertise in expanding and developing acquired assets to develop and expand our presence in the Southwest.
- •
- Proven Acquisition Expertise. Since our initial public offering in May 2002, we have completed four acquisitions with an aggregate purchase price of approximately $112 million. We intend to
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- •
- Stable Cash Flows. On a pro forma basis for the nine months ended September 30, 2003, we generated approximately 69% of our gross margin from fee-based contracts providing natural gas gathering, processing and transmission services, NGL transportation, fractionation and storage services and crude oil gathering and transportation services. These fee-based services are dependent on throughput volume but are typically not affected by short-term changes in commodity prices. In addition, our four lateral pipelines in the Southwest generally generate firm transportation fees independent of the volumes transported. We believe that the fee-based nature of a significant component of our business and the long-term nature of many of our contracts provide us with a relatively stable base of cash flows.
- •
- Long-term Contracts. On a pro forma basis for the nine months ended September 30, 2003, in excess of 80% of our gross margin was derived from contracts with remaining terms of two years or more. Pursuant to our contracts with MarkWest Hydrocarbon and Equitable Production Company, we process substantially all of the natural gas delivered into two of the three largest gathering systems in Appalachia and fractionate the NGLs extracted from such gas. These contracts have remaining terms ranging in length from six to 13 years. In Michigan, our gas transportation, treating and processing agreements have terms for the life of the wells. In conjunction with our Pinnacle assets, we have two significant, fixed fee contracts for the transmission of natural gas that expire in 19 and 29 years. Our two largest customer contracts related to the Lubbock pipeline run through 2005 and 2008. Approximately 90% of our daily throughput in the Foss Lake gathering system in western Oklahoma is pursuant to contracts with remaining terms of five years or more.
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- Experienced management with operational and engineering expertise. Each member of our management team has at least 19 years of experience in the energy industry and our facility managers have extensive experience operating many of our facilities. Our technical and operational expertise has enabled us to upgrade existing facilities, as well as design and build new facilities. In addition, the ownership of interests in our general partner and in our partnership by members of our management, as well as our compensation and incentive plans, closely aligns the interests of our management team with the interests of our common unitholders.
- •
- Financial flexibility. Upon completion of this offering, we expect to have available borrowing capacity of approximately $62 million under our $140 million credit facility. This facility, together with our ability to issue additional partnership units for financing and acquisition purposes, should provide us with a flexible financial structure that will facilitate the execution of our business strategy.
continue to use our experience in acquiring assets to grow through accretive acquisitions and focusing on opportunities in which we can improve volumes and cash flow.
Our primary strategy is to increase distributable cash flow per unit by:
- •
- Increasing utilization of our facilities. We seek to capture additional natural gas and crude oil production from existing customers and to provide services to other natural gas and crude oil producers in our areas of operation. With our current excess capacity, we can increase throughput at our facilities with minimal incremental costs.
- •
- Expanding operations through new construction. By leveraging our existing infrastructure and customer relationships, we intend to continue expanding our asset base in our primary areas of operation to meet the anticipated need for additional midstream services. In the first quarter 2004, we plan to construct a new, more efficient processing plant to replace our Cobb processing
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- •
- Expanding operations through acquisitions. We intend to continue to pursue strategic acquisitions of assets and businesses in our existing areas of operation in order to leverage our current asset base, personnel and customer relationships. Our acquisition of the Michigan Crude Pipeline allows us to leverage off of our existing Michigan infrastructure and personnel. In addition, we seek to acquire assets outside of our existing areas of operation with a view towards creating new primary operating areas. Our Pinnacle, Lubbock pipeline and western Oklahoma acquisitions enabled us to establish and develop a new primary area of operation in the Southwest.
- •
- Securing additional long-term, fee-based contracts. We intend to continue to secure long-term, fee-based contracts in both our existing operations and strategic acquisitions. While fee-based arrangements are dependent on throughput volume, they are typically less affected by short-term changes in commodity prices than other contractual arrangements in our industry.
plant. In the Southwest, drilling in our two largest gathering systems, Appleby in East Texas and Foss Lake in western Oklahoma, has significantly increased volumes over the past several years.
Our Relationship with MarkWest Hydrocarbon, Inc.
We were formed by MarkWest Hydrocarbon to acquire most of its natural gas gathering and processing and NGL transportation, fractionation and storage assets. MarkWest Hydrocarbon remains our largest customer and, for the period from May 24, 2002 to December 31, 2002, accounted for 43% of our revenues and 69% of our gross margin. On a pro forma basis for the nine months ended September 30, 2003, MarkWest Hydrocarbon accounted for 14% of our revenues and 41% of our gross margin. We will derive a significant portion of our revenues from the services we provide under our contracts with MarkWest Hydrocarbon for the foreseeable future. For a complete description of each of our material agreements with MarkWest Hydrocarbon, please read "Certain Relationships and Related Transactions." In addition, MarkWest Hydrocarbon and its affiliates will own 35.4% of our limited partner interests upon completion of this offering, and will direct our business operations through their ownership and control of our general partner. MarkWest Hydrocarbon employees are responsible for conducting our business and operating our assets on our behalf.
During 2003, MarkWest Hydrocarbon sold substantially all of its oil and gas properties. MarkWest Hydrocarbon's remaining business consists of its limited partnership interest in us, its ownership of a controlling interest in our general partner and the marketing of NGLs and natural gas. In 2002, MarkWest Hydrocarbon sold 183 million gallons of NGL products produced at our Siloam facility. NGL products are shipped from Siloam by truck, rail and barge. In addition, MarkWest Hydrocarbon ships propane from our Siloam facility, as well as propane purchased from third parties, to its wholesale propane terminals and to third party facilities for sale to customers. MarkWest Hydrocarbon's marketing customers include propane retailers, refineries, petrochemical plants and NGL product resellers. Most marketing sales contracts have terms of one year or less, are made on best efforts basis and are priced in reference to Mt. Belvieu index prices or plant posting prices. In addition to its NGL product sales, MarkWest Hydrocarbon's marketing operations are also responsible for the purchase of natural gas delivered for the account of producers pursuant to its keep whole processing contracts.
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Appalachian Gathering and Processing Facilities
The table below describes our processing assets in the Appalachian region:
| | | | Natural Gas Throughput (Mcf/d) | | ||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| | | | Utilization of Design Capacity | |||||||||||||
| | | | Years Ended December 31, | | ||||||||||||
| | | Design Throughput Capacity (Mcf/d) | Nine Months Ended September 30, 2003 | Nine Months Ended September 30, 2003 | ||||||||||||
Facility | | Year Constructed | |||||||||||||||
Location | 2000 | 2001 | 2002(1) | ||||||||||||||
Kenova Processing Plant(2) | Wayne County, WV | 1996 | 160,000 | 120,000 | 122,000 | 136,000 | 129,000 | 81 | % | ||||||||
Boldman Processing Plant | Pike County, KY | 1991 | 70,000 | 51,000 | 46,000 | 42,000 | 45,000 | 64 | % | ||||||||
Maytown Processing Plant(3) | Floyd County, KY | 2000 | 55,000 | 39,000 | 54,000 | 64,000 | |||||||||||
Cobb Processing Plant(4) | Kanawha County, WV | 1968 | 35,000 | 25,000 | 24,000 | 24,000 | 32,000 | 91 | % | ||||||||
Kermit Processing Plant(5) | Mingo County, WV | 2001 | 32,000 | N/A |
- (1)
- Represents MarkWest Hydrocarbon until May 23, 2002, and MarkWest Energy Partners, L.P. beginning May 24, 2002, the date our initial public offering closed.
- (2)
- A portion of the Boldman volumes and all of the Kermit volumes are included in Kenova throughput, as these volumes require further processing at our Kenova facility.
- (3)
- Natural gas throughput for the year ended December 31, 2002 exceeded design throughput capacity. Our processing plants were constructed to accommodate gas volumes somewhat in excess of their design throughput capacity. The inlet meter for the Maytown Processing plant is owned by Equitable and was taken out of service in 2003. Accordingly, volumetric data is no longer available.
- (4)
- We are planning to begin construction of a new 24 MMcf/d processing plant in the first quarter of 2004. This new plant will replace our existing Cobb plant.
- (5)
- The Kermit processing plant is operated by Columbia Gas and we do not receive inlet volume information.
Kenova Processing Plant. Our Kenova cryogenic facility was expanded by 40 MMcf/d in 2001 to accommodate expected new production from Columbia Resources. The cryogenic process utilizes a turbo-expander and heat exchangers to cool the gas, which condenses the NGLs. The NGLs are then separated from condensed gaseous components by distillation. This facility receives all of its intake of raw natural gas from Columbia Gas' transmission lines and processes gas produced in Knott, Magoffin, Floyd, Johnson, Martin and Lawrence Counties, Kentucky, and Mingo, Logan, Lincoln, Boone, Cabell, Putman, Wayne and Kanawha Counties, West Virginia. NGLs extracted at this facility are transported to our Siloam fractionator via our pipeline.
Boldman Processing Plant. Our Boldman straight refrigeration processing plant processes gas using a propane refrigeration system to cool the gas and condense the NGLs. The NGLs are then separated from condensed gaseous components by distillation. Prior to 2000, MarkWest Hydrocarbon leased the plant to Columbia Gas. This facility receives all of its intake of raw natural gas from Columbia Gas' transmission lines and processes gas produced in Pike, Floyd, Letcher and Knott Counties, Kentucky. NGLs extracted at this facility are first delivered by truck to our Maytown facility and transported on our leased pipeline to Ranger for further delivery on our pipeline to our Siloam fractionator.
Maytown Processing Plant. Pursuant to our contract with Equitable, Equitable operates our Maytown facility, a straight refrigeration plant, on our behalf. As operator, Equitable is responsible for the day-to-day operation of the Maytown plant. Under our Gas Processing Agreement with Equitable, we have the right to take over and assume the role of operator upon providing Equitable with 30 day written notice. Like the Boldman plant, the Maytown plant also processes gas using a propane refrigeration system to cool the gas and condense the NGLs. The NGLs are then separated from condensed gaseous components by distillation. This facility receives all of its intake of raw natural gas
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from Equitable's gathering system in Kentucky. NGLs extracted at this facility are transported to Siloam via pipeline. The plant also contains a truck unloading facility that allows for the delivery of NGLs into our pipeline system for transportation to our Siloam fractionator.
Under the terms of our Gas Processing Agreement, Equitable agrees to deliver to us all gas now or subsequently produced from specified wells, plus gas attributable to the interests of third parties that is currently being delivered into Equitable's gathering system (to the extent Equitable has the right to process such third party gas). Equitable also grants us the exclusive right to process all of this natural gas for liquid extraction and conveys to us the title to the NGLs and NGL products we extract from the gas.
As compensation for our services, we earn both a fee for our transportation and fractionation services as well as receive a percentage of the proceeds from the sale of NGLs produced on Equitable's behalf. A portion of the transportation and fractionation fee will be subject to annual adjustment in proportion to the annual average percentage change in the Producer Price Index for Oil and Gas Field Services. MarkWest Hydrocarbon, in a separate agreement, has agreed to buy the NGLs from us and pay us a purchase price equal to the proceeds it receives from the resale of such NGLs to third parties. Please see "Certain Relationships and Related Transactions." The initial term of our Gas Processing Agreement with Equitable runs through February 2015. The operating revenues we earn under the percent of proceeds component of this agreement will fluctuate with the sales price for the NGLs produced.
Cobb Processing Plant. Our Cobb facility, a refrigerated lean oil processing plant, was acquired in 2000. The refrigerated lean oil process utilizes a propane refrigeration system to cool the gas and the lean oil. The chilled lean oil then absorbs the NGLs which are then separated from the lean oil by distillation. An upgrade of this facility was completed in 2000 to decrease downtime and increase recoveries from the facility. This facility receives all of its intake of raw natural gas from Columbia Gas' transmission lines and processes gas produced in Kanawha, Clay, Roane and Jackson Counties, West Virginia. NGLs extracted at this facility are transported to our Siloam facility by tanker truck. We plan to replace our existing Cobb facility with a newly constructed 24 MMcf/d processing plant. Construction is expected to begin in the first quarter of 2004. We believe this new plant will require significantly less operating and maintenance expense. The cost of the construction is expected to be approximately $2.1 million. MarkWest Hydrocarbon will provide approximately $1.7 million in payment of a portion of the costs. We will pay the remaining approximately $450,000 and own and operate the plant.
Kermit Processing Plant. Our Kermit facility, a straight refrigeration plant, was constructed in connection with the expansion at our Kenova facility and in anticipation of increased demand for our services by Columbia Resources. This facility was designed and constructed to increase the volume of natural gas transported to our Kenova facility by decreasing the liquid content of the natural gas in Columbia Gas' transmission lines. The Kermit plant processes gas using the same straight refrigeration process used at our Boldman plant. NGLs extracted at this facility are transported to our Siloam facility via tanker truck.
We do not operate our Kermit plant. Under the terms of a Construction and Lease Agreement between MarkWest Hydrocarbon and Columbia Gas, Columbia Gas has the exclusive authority and responsibility for the operation, maintenance and repair of the Kermit Plant. Columbia has the right to operate the plant only during such times as it deems required for operational purposes. Columbia Gas has the right to purchase the Kermit plant from us at any time during the lease term and at the termination of the lease. The lease expires on December 31, 2015. If Columbia Gas does not exercise its option to purchase, we, at our own expense, must remove the plant from Columbia Gas' property within a reasonable time following the expiration of the lease.
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We generate most of our processing revenues in Appalachia by charging fees for processing gas. We completed a multi-year expansion of our Appalachian infrastructure in mid-2001, increasing our total natural gas designed processing capacity by 127 MMcf/d.
On a pro forma basis, gas processing in Appalachia accounted for approximately 7% of our revenues and approximately 20% of our gross margin for the nine months ended September 30, 2003.
Appalachian NGL Pipelines
In Appalachia, we earn fees for transporting NGLs through our pipelines to our Siloam fractionation plant. All of the NGLs we recover at our Kenova, Boldman and Maytown plants are transported to Siloam via pipeline (NGLs from Boldman are first transported to our Maytown facility via tanker trucks). NGLs from our Cobb and Kermit plants are transported to Siloam via tanker trucks.
Our Appalachia liquids pipeline includes the following segments:
| | | | NGL Throughput (gal/day) | Utilization of Design Capacity | ||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| | | | Year Ended December 31, | Nine Months Ended September 30, 2003 | Nine Months Ended September 30, 2003 | |||||||||||
| | | Design Throughput Capacity (gal/day) | ||||||||||||||
Pipeline | | Year Constructed | |||||||||||||||
Location | 2000 | 2001 | 2002 | ||||||||||||||
Maytown to Institute(1) | Floyd County, KY to Kanawha County, WV | 1956 | 250,000 | 84,000 | 129,000 | 145,000 | 144,000 | 58 | % | ||||||||
Ranger to Kenova(2) | Lincoln County, WV to Wayne County, WV | 1976 | 831,000 | 84,000 | 129,000 | 145,000 | 144,000 | 17 | % | ||||||||
Kenova to Siloam | Wayne County, WV to South Shore, KY | 1957 | 831,000 | 296,000 | 360,000 | 410,000 | 393,000 | 47 | % |
- (1)
- Includes 40 miles of currently unused pipeline extending from Ranger to Institute.
- (2)
- NGLs transported through the Ranger to Kenova pipeline are included in the Kenova to Siloam volumes.
Our 40-mile Ranger to Kenova NGL pipeline and the Maytown to Ranger segment of our leased Maytown to Institute pipeline, together with our existing Kenova to Siloam pipeline, form 136 miles of NGL pipeline running through the southern portion of the Appalachia basin. We acquired our Ranger to Kenova pipeline and leased the 100-mile Maytown to Institute pipeline in 2000 as part of our Appalachian expansion. We acquired our Kenova to Siloam pipeline in 1988. We lease the Maytown to Institute pipeline from Equitable. Our lease expires in 2015. Prior to leasing the Maytown to Institute pipeline, Boldman NGLs were acquired to be transported by truck to Siloam, at significantly greater expense than trucking to an injection point. We generate transportation revenues by charging fees for transporting NGLs to our Siloam fractionator on our pipeline.
Appalachian Fractionation Facility
Our Siloam fractionation plant receives substantially all of its extracted NGLs via pipeline or tanker truck from our five Appalachia processing plants, with the balance received from tanker truck and rail car deliveries from other third-party NGL sources. The extracted NGLs are then separated into NGL products, including propane, isobutane, normal butane and natural gasoline. The typical composition of the NGL throughput in our Appalachian operations has been approximately 64% propane, 18% normal butane, 6% isobutane, and 12% natural gasoline. We do not currently produce and sell any ethane. Our Siloam fractionation plant has been continually upgraded and maintained since its acquisition by MarkWest Hydrocarbon in 1988. We generate revenues by charging fees for fractionating NGLs that we receive from our processing plants and third parties.
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The following table provides additional detail regarding our Siloam fractionation plant:
| | | | NGL Throughput (gal/day) | Utilization of Design Capacity | ||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| | | | Year Ended December 31, | Nine Months Ended September 30, 2003 | Nine Months Ended September 30, 2003 | |||||||||||
| | | Design Throughput Capacity (gal/day) | ||||||||||||||
Facility | | Year Constructed | |||||||||||||||
Location | 2000 | 2001 | 2002 | ||||||||||||||
Siloam Fractionation Plant | South Shore, KY | 1957 | 600,000 | 406,000 | 423,000 | 476,000 | 449,000 | 75 | % |
Appalachian Storage Facilities
In Appalachia, our Siloam facility has both above ground, pressurized storage facilities, with capacity of three million gallons, and underground storage facilities, with capacity of 11 million gallons. Product can be received by truck, pipeline or rail car and can be transported from the facility by truck, rail car or barge. There are eight automated 24-hour-a-day truck loading and unloading slots, a modern rail loading/unloading rack with 12 unloading slots, and a river barge facility capable of loading barges with a capacity of up to 840,000 gallons. We generate revenues from our underground storage facilities by charging a fee based on annual gallons of storage contracted.
On a pro forma basis, our NGL transportation, fractionation and storage services accounted for approximately 6% of our revenues and approximately 18% of our gross margin for the nine months ended September 30, 2003.
Southwest Gathering and Processing Facilities
The table below describes our Southwest gathering assets:
| | | | Natural Gas Throughput (Mcf/d) | ||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| | | | Year Ended December 31, | Nine Months Ended September 30, 2003 | |||||||||
| | | Design Throughput Capacity (Mcf/d) | |||||||||||
Facility | | Year of Initial Construction | ||||||||||||
Location | 2000 | 2001 | 2002 | |||||||||||
Foss Lake Gathering System | Various counties, OK | 1998 | 65,000 | 41,100 | 44,600 | 48,700 | 51,300 | |||||||
Appleby Gathering System | Nacogdoches County, TX | 1990 | 32,000 | 9,500 | 18,900 | 21,400 | 23,900 | |||||||
19 Other Gathering Systems | Various in TX, LA, MS, KS, NM | Various | 40,000 | 28,700 | 24,400 | 23,200 | 19,900 |
Foss Lake Gathering System. We acquired the Foss Lake Gathering System as part of the western Oklahoma acquisition in December 2003. The system is a low-pressure gathering system consisting of approximately 167 miles of four to 20-inch pipeline connected to approximately 270 wells and includes 10,240 horsepower of owned-compression and 770 horsepower of leased-compression. The system gathers natural gas from the Anadarko Basin in western Oklahoma from approximately 50 producers. We generate operating margins by charging fixed fees per Mcf of natural gas gathered. All of the natural gas gathered into the system is dehydrated at our Butler compression station for delivery to our Arapaho processing plant. The gathering system has a capacity of 65 MMcf/d and throughput for the nine months ended September 30, 2003 was approximately 51 MMcf/d. Volumes on the system have increased 20% during the period from January 2000 to September 2003. We have the ability to increase capacity by adding additional compression to the system.
Appleby Gathering System. We acquired the Appleby Gathering System as part of the Pinnacle acquisition in March 2003. The system is a low-pressure gathering system consisting of approximately
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80 miles of three to eight-inch pipeline connected to approximately 120 wells and includes approximately 6,520 horsepower of leased-compression. The system gathers natural gas from the Travis Peak Basin in East Texas from approximately seven producers, with one producer accounting for approximately 50% of the volumes. We sell the gas to marketing companies and to an industrial user under short-term marketing contracts. We generate a majority of our operating margin through percent-of-index contracts, with the remaining margin generated through fee-based contracts. The gathering system has a capacity of 40 MMcf/d and throughput was approximately 24 MMcf/d for the nine months ended September 30, 2003. Volumes on the system have increased by approximately 300% during the period from January 2000 to September 2003.
Other Gathering Systems. As part of the Pinnacle acquisition, we acquired 19 other natural gas gathering systems, primarily located in Texas. The systems typically gather natural gas from mature producing wells. We generate operating margins from these systems through percent-of-index, percent-of-proceeds and fixed-fee contracts. The aggregate capacity of these systems is 53 MMcf/d and aggregate throughput was approximately 20 MMcf/d for the nine months ended September 30, 2003. Volumes on these more mature systems have declined by approximately 47% during the period from January 2000 to September 2003.
Arapaho Processing Plant. We acquired the Arapaho Processing Plant, located in Custer County, Oklahoma, as part of the western Oklahoma acquisition in December 2003. Our Arapaho gas processing plant is a cryogenic plant installed in early 2000. The plant is designed to recover ethane and heavier NGLs, including propane. The plant can also reject ethane and continue to recover high levels of propane. The plant delivers processed natural gas into the Panhandle Eastern Pipe Line, or PEPL, and recovered NGLs are sold to Koch Hydrocarbon LP. We generate operating margins through keep-whole contracts. Under these keep-whole arrangements, we process the natural gas and sell the resulting NGLs to third parties at market prices. Because the extraction of the NGLs from the natural gas during processing reduces the Btu content of the natural gas, we must either purchase natural gas at market prices for return to producers or make a cash payment to the producers. Accordingly, under these arrangements our revenues and gross margins increase as the price of NGLs increases relative to the price of natural gas, and our revenues and gross margins decrease as the price of natural gas increases relative to the price of NGLs. In the latter case, however, we have the option of not operating the plant in a low processing margin environment since the Btu content of the inlet natural gas meets the PEPL Btu specification. In addition, approximately 45% of the Foss Lake gas gathering contracts include additional fees to cover plant operating costs, fuel costs and shrinkage costs in a low processing margin environment. Because of the our ability to operate the plant in several recovery modes, including turning it off, and the additional fees provided for in the gas gathering contracts, our exposure is limited to a portion of the operating costs of the plant. The plant has a design capacity of 75 MMcf/d and throughput was approximately 51 MMcf/d for the nine months ended September 30, 2003.
Southwest Lateral Pipelines. We acquired the Lake Whitney lateral, the Rio Nogales lateral and the Blackhawk lateral as part of the Pinnacle acquisition in March 2003.
- •
- The Lake Whitney lateral, constructed in 2001 and 2002, is a 33-mile intrastate natural gas pipeline that transports natural gas to Mirant America Energy Marketing's 556 megawatt Bosque power plant, located near Waco, Texas. The lateral transports natural gas from the El Paso Field Services Pipeline and is the only pipeline connected to, and the sole source of natural gas for, the Bosque power plant. We have a 30-year fixed-fee contract with Mirant for natural gas transportation on this lateral pipeline. This contract expires in 2030.
- •
- The Rio Nogales lateral, constructed in 2001, consists of two natural gas lateral pipelines, which in aggregate total 27 miles in length. The laterals transport natural gas from the Duke Energy Field Services Pipe Line, the Houston Pipe Line and the Oasis Pipe Line to Constellation
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- The Blackhawk lateral is a seven-mile intrastate natural gas pipeline that serves as a back-up natural gas supply source for Borger Energy Associates' 200 megawatt cogeneration power facility, located in Borger, Texas. The lateral is connected to the El Paso Natural Gas pipeline. We have a fixed-fee contract through June 2005. In June 2005, ownership of the lateral will transfer to Borger Energy Associates.
Energy Group's 800 megawatt Rio Nogales power plant, located near Seguin Texas. We have a 20-year fixed-fee contract with Constellation. This contract expires in 2022.
We acquired the Lubbock Lateral from Power-Tex Joint Venture in September 2003. It consists of one 12-inch, 50-mile pipeline and one six-inch, 18-mile pipeline serving several industrial users and municipalities in and around Lubbock, Texas, including the City of Lubbock, Texas Tech University and Southwestern Public Service, a subsidiary of Xcel Energy. The Lubbock Lateral transports natural gas from the El Paso Natural Gas pipeline and the Northern Natural Gas Pipeline. We have fixed-fee contracts with maturities ranging from one to five years.
On a pro forma basis for the nine months ended September 30, 2003, gas gathering, processing and transportation in the Southwest accounted for approximately 62% of our revenues and 32% of our gross margin.
Michigan Gathering and Processing Facilities
The table below describes our Michigan gathering and processing assets:
| | | | Natural Gas Throughput (Mcf/d) | | |||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| | | | NGL Throughput (gallons) | ||||||||||||
| | | | Year Ended December 31, | | |||||||||||
| | | Design Throughput Capacity (Mcf/d)(1) | | ||||||||||||
Facility | | Year Constructed | Nine Months Ended September 30, 2003 | Nine Months Ended September 30, 2003 | ||||||||||||
Location | 2000 | 2001 | 2002(2) | |||||||||||||
90-mile Gas Gathering Pipeline | Manistee, Mason and Oceana Counties, MI | 1994 - 1998 | 35,000 | 11,000 | 8,800 | 13,800 | 15,700 | — | ||||||||
Fisk Processing Plant | Manistee County, MI | 1998 | 35,000 | 11,000 | 8,800 | 13,800 | 15,700 | 9.1 million |
- (1)
- MarkWest Hydrocarbon has retained a 70% net profit interest in all gathering and processing fees generated by quarterly throughput volumes in excess of 10 MMcf/d.
- (2)
- Represents MarkWest Hydrocarbon until May 23, 2002, and MarkWest Energy Partners, L.P. beginning May 24, 2002, the date our initial public offering closed.
Our Michigan gathering pipeline gathers and transports sour gas produced by third parties in Oceana, Mason and Manistee Counties for sulfur removal at a treatment plant that is owned and operated by Shell Offshore, Inc. Our Fisk processing plant is located adjacent to Shell's treatment plant. Our gathering pipeline serves approximately 30 wells and 13 producers in this three county area. The Fisk plant processes all of the natural gas gathered by our gathering pipeline and produces propane and a butane-natural gasoline mix. We process natural gas under a number of third-party agreements containing both fee and percent-of-proceeds components. Under these agreements, production from all of the acreage adjacent to our pipeline and processing facility is dedicated to our gathering and processing facilities. Under the fee component of these agreements, which represent approximately half of our gross margin in Michigan, producers pay us a fee to transport and treat their gas. Under the percent-of-proceeds component, we retain a portion of the proceeds from the sale of the NGLs as compensation for the processing services provided.
We receive 100% of all fee and percent-of-proceeds consideration for the first 10 MMcf/d that we gather and process in Michigan. MarkWest Hydrocarbon retains a 70% net profits interest in the
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gathering and processing income we earn on quarterly pipeline throughput in excess of 10 MMcf/d. Throughput averaged 15.7 MMcf/d for the nine months ended September 30, 2003.
Under a Gas Treating and Processing Agreement between our subsidiary, West Shore Processing Company, LLC and Shell Offshore, Inc., Shell operates our Fisk natural gas processing plant. Under the terms of this agreement, Shell treats and processes sour gas delivered to its treatment plant by us and delivers the treated gas to our Fisk plant where NGLs are extracted. We retain the NGLs. Shell retains any treating products (including carbon dioxide) and any liquids recovered prior to treating the gas at its treatment plant by use of conventional mechanical separation equipment, as well as any sulfur recovered. For these services, we pay Shell a set monthly treating fee and a volumetric treating fee based on the amount of gas we deliver to Shell. Both of these fees are annually increased in proportion to the change in a government reported index. In addition, Shell has agreed to pay us a per-gallon surcharge for propanes, butanes and pentanes (or a combination thereof) contained in the treated gas that is not subsequently delivered to us for processing at our natural gas processing plant.
We generate revenues from our Michigan natural gas and NGLs operations primarily by charging a fee for the gathering and processing services we provide. Our contracts in Michigan also provide that we retain a portion of the proceeds from the sale of NGLs that are produced at our Michigan facility. Our propane and butane-natural gasoline production is usually sold at the plant. MarkWest Hydrocarbon has retained a 70% net profit interest in all gathering and processing fees generated from Michigan throughput volumes in excess of 10 MMcf/d.
On a pro forma basis for the nine months ended September 30, 2003, gas gathering and processing in Michigan accounted for approximately 7% of our revenues and 14% of our gross margin.
Michigan Crude Pipeline
We acquired the Michigan Crude Pipeline in December 2003. The system consists of approximately 152 miles of eight to 16-inch main pipeline, approximately 92 miles of four to ten-inch gathering pipeline, four truck loading facilities and 15 storage tanks. The pipeline, which serves over 1,000 oil and gas wells on the Niagaran Reef Trend, delivers crude oil to the Enbridge Pipeline. Approximately 45% of the crude oil transported on the pipeline is supplied by one customer. We generate operating margins by charging a tariff per barrel of crude oil transported. Because we have the ability to set the amount of this tariff, we believe this pipeline will provide us with a relatively stable base of cash flows. The pipeline has a capacity of 60,000 bpd and transported approximately 15,900 bpd of crude oil for the nine months ended September 30, 2003.
On a pro forma basis for the nine months ended September 30, 2003, our crude oil transportation operations in Michigan would have accounted for approximately 3% of our revenues and 7% of our gross margin.
We face competition for crude oil and natural gas transportation and in obtaining natural gas supplies for our processing and related services operations, in obtaining unprocessed NGLs for fractionation, and in marketing our products and services. Competition for natural gas supplies is based primarily on location of gas gathering facilities and gas processing plants, operating efficiency and reliability, and ability to obtain a satisfactory price for products recovered. Competitive factors affecting our fractionation services include availability of capacity, proximity to supply and to industry marketing centers, and cost efficiency and reliability of service. Competition for customers is based primarily on price, delivery capabilities, flexibility, and maintenance of quality customer relationships.
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In competing for new business opportunities, we face strong competition in acquiring natural gas and crude oil supplies and competing for fees for service. Our competitors include:
- •
- major integrated oil companies;
- •
- major interstate and intrastate pipelines;
- •
- other large raw natural gas gatherers that gather, process and market natural gas and NGLs; and
- •
- a relatively large number of smaller gas gatherers of varying financial resources and experience.
Many of our competitors, such as major oil and gas and pipeline companies, have capital resources and control supplies of natural gas substantially greater than ours. Smaller local distributors may enjoy a marketing advantage in their immediate service areas.
Substantially all of our pipelines are constructed on rights-of-way granted by the apparent record owners of the property. Lands over which pipeline rights-of-way have been obtained may be subject to prior liens that have not been subordinated to the right-of-way grants. We have obtained, where necessary, easement agreements from public authorities and railroad companies to cross over or under, or to lay facilities in or along, watercourses, county roads, municipal streets, railroad properties and state highways, as applicable. In some cases, property on which our pipelines were built was purchased in fee. Our Siloam fractionation plant and Kenova processing plant are on land that we own in fee.
Some of the leases, easements, rights-of-way, permits, licenses and franchise ordinances that were transferred to us required the consent of the then-current landowner to transfer these rights, which in some instances was a governmental entity. Our general partner believes that it has obtained sufficient third-party consents, permits and authorizations for the transfer of the assets necessary for us to operate our business in all material respects as described in this prospectus.
Our general partner believes that we have satisfactory title to all of our assets. To the extent certain defects in title to the assets contributed to us or failures to obtain certain consents and permits necessary to conduct our business arise within three years after the closing of our initial public offering, we are entitled to indemnification from MarkWest Hydrocarbon under the Omnibus Agreement. Record title to some of our assets may continue to be held by affiliates of MarkWest Hydrocarbon until we have made the appropriate filings in the jurisdictions in which such assets are located and obtained any consents and approvals that are not obtained prior to transfer. Title to property may be subject to encumbrances. Our general partner believes that none of such encumbrances materially detract from the value of our properties or from our interest in these properties or should materially interfere with their use in the operation of our business.
Our activities are subject to various state and local laws and regulations, as well as orders of regulatory bodies, governing a wide variety of matters, including marketing, production, pricing, community right-to-know, protection of the environment, safety and other matters.
Some of our gas, liquids and crude oil gathering and transmission operations are subject to regulation by various state regulatory bodies. In many cases, various phases of our gas, liquids and crude oil operations in the various states in which we operate are subject to rate and service regulation. The applicable state statutes generally require that our rates and terms and conditions of service provide no more than a fair return on the aggregate value of the facilities used to render services. Regulatory authorities in the states in which we operate have generally not been aggressive in regulating gas, liquids and crude oil gathering and transmission facilities and have generally not investigated the rates or practices of the owners of such facilities in the absence of shipper complaints. Complaints to state agencies have been infrequent and are usually resolved informally.
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Our Appalachian pipeline carries NGLs across state lines. The primary shipper on the pipeline is MarkWest Hydrocarbon, who has entered into agreements with us providing for a fixed transportation charge for the term of the agreements, which expire on December 31, 2015. We are the only other shipper on the pipeline. As we do not operate our Appalachian pipeline as a common carrier and do not hold the pipeline out for service to the public generally, there are currently no third-party shippers on this pipeline and the pipeline is and will continue to be operated as a proprietary facility. Similarly, our Michigan Crude Pipeline delivers crude oil to a third party carrier which makes deliveries both within and outside Michigan, in this case for unaffiliated third parties. Neither pipeline is currently subject to regulation by the Federal Energy Regulatory Commission, or FERC. However, if a shipper sought to challenge the jurisdictional status of either of these pipelines, the FERC could determine that such transportation is within its jurisdiction under the Interstate Commerce Act. In such a case, we would be required to file a tariff for such transportation with the FERC and provide a cost justification for the transportation charge. Because MarkWest Hydrocarbon has agreed to not challenge the status of our Appalachian pipeline or the transportation charge during the term of our agreements with MarkWest Hydrocarbon and, moreover, the likelihood of other entities seeking to utilize our Appalachian pipeline is limited, the likelihood of such a challenge on our Appalachian pipeline is remote. Similarly, because we are operating our Michigan Crude Pipeline in the same manner as it was historically operated by Shell for a significant period of time prior to our acquisition and because our operations are entirely within the state of Michigan, we believe that the likelihood of a challenge to the status of this pipeline is remote. However, we cannot predict whether a FERC jurisdictional challenge might be made with respect to either of these pipelines, nor provide assurance that such a challenge would not adversely affect our results of operations.
Some of our liquids and crude oil gathering facilities deliver into pipelines that have the ability to make redeliveries in both interstate and intrastate commerce. The rates we charge on our liquids and crude oil facilities are not regulated at the state or federal level, however, there can be no assurance that the rates for service on these facilities will remain unregulated in the future.
General. Our operation of processing and fractionization plants, pipelines and associated facilities in connection with the gathering and processing of natural gas, the transportation, fractionization and storage of NGLs and the storage and gathering and transportation of crude oil is subject to stringent and complex federal, state and local laws and regulations relating to release of pollutants into the environment or otherwise relating to protection of the environment. As with the industry generally, compliance with existing and anticipated environmental laws and regulations increases our overall cost of doing business, including our cost of constructing, maintaining and upgrading equipment and facilities. Our failure to comply with these laws and regulations may result in the assessment of administrative, civil or criminal penalties, imposition of investigatory or remedial requirements, and, in less common circumstances, issuance of injunctions. We believe that our operations and facilities are in substantial compliance with applicable environmental laws and regulations and that the cost of compliance with such laws and regulations will not have a material adverse effect on our results of operations or financial condition.
Nevertheless, the clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. Moreover, risks of process upsets, accidental releases or spills are associated with our operations and we cannot assure you that we will not incur significant costs and liabilities as a result of such upsets, releases, or spills, including those relating to claims for damage to property and persons. In the event of future increases in costs, we may be unable to pass on those increases to our customers. We will attempt to anticipate future regulatory
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requirements that might be imposed and plan accordingly in order to remain in compliance with changing environmental laws and regulations and to minimize the costs of such compliance.
Hazardous Substance and Waste. To a large extent, the environmental laws and regulations affecting our operations relate to the release of hazardous substances or solid wastes into soils, groundwater, and surface water, and include measures to control environmental pollution of the environment. These laws and regulations generally regulate the generation, storage, treatment, transportation, and disposal of solid and hazardous wastes, and may require investigatory and corrective actions of facilities where such waste may have been released or disposed. For instance, the Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, also known as the "Superfund" law, and comparable state laws, impose liability without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to a release of "hazardous substance" into the environment. These persons include the owner or operator of a site where a release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, these persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. CERCLA also authorizes the Environmental Protection Agency, or EPA, and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. Although "petroleum" is excluded from CERCLA's definition of a "hazardous substance," in the course of our ordinary operations we will generate wastes that may fall within the definition of a "hazardous substance." We may be responsible under CERCLA for all or part of the costs required to clean up sites at which such wastes have been disposed. We have not received any notification that we may be potentially responsible for cleanup costs under CERCLA.
We also generate both hazardous and nonhazardous solid wastes which are subject to requirements of the federal Resource Conservation and Recovery Act, or RCRA, and comparable state statutes. From time to time, the EPA has considered the adoption of stricter disposal standards for nonhazardous wastes, including crude oil and natural gas wastes. We are not currently required to comply with a substantial portion of the RCRA requirements because our operations generate minimal quantities of hazardous wastes. However, it is possible that some wastes generated by us that are currently classified as nonhazardous may in the future be designated as "hazardous wastes," resulting in the wastes being subject to more rigorous and costly disposal requirements. Changes in applicable regulations may result in an increase in our capital expenditures or plant operating expenses.
We currently own or lease, and have in the past owned or leased, properties that have been used over the years for natural gas gathering and processing, for NGL fractionation, transportation and storage and for the storage and gathering and transportation of crude oil. Solid waste disposal practices within the NGL industry and other oil and natural gas related industries have improved over the years with the passage and implementation of various environmental laws and regulations. Nevertheless, a possibility exists that hydrocarbons and other solid wastes may have been disposed of on or under various properties owned or leased by us during the operating history of those facilities. In addition, a number of these properties may have been operated by third parties over whom we had no control as to such entities' handling of hydrocarbons or other wastes and the manner in which such substances may have been disposed of or released. These properties and wastes disposed thereon may be subject to CERCLA, RCRA, and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes or property contamination, including groundwater contamination or to perform remedial operations to prevent future contamination. We do not believe that there presently exists significant surface and subsurface contamination of our properties by hydrocarbons or other solid wastes for which we are currently responsible.
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Ongoing Remediation and Indemnification from Columbia Gas. Columbia Gas is the previous or current owner of the property on which our Kenova, Boldman, Cobb and Kermit facilities are located and is the previous operator of our Boldman and Cobb facilities. Columbia Gas has been or is currently involved in investigatory or remedial activities with respect to the real property underlying the Boldman and Cobb facilities pursuant to an "Administrative Order by Consent for Removal Actions" entered into by Columbia Gas and EPA Regions II, III, IV, and V in September 1994. Columbia Gas is also pursuing these remedial activities at the Boldman facility pursuant to an "Agreed Order" that it entered into with the Kentucky Natural Resources and Environmental Protection Cabinet in October 1994. The focus of the investigatory and remedial activities pursued by Columbia Gas has been the cleanup of polychlorinated biphenyls, also known as PCBs, and other hazardous substances which may be found in these real properties. Columbia Gas has agreed to retain sole liability and responsibility for, and indemnify MarkWest Hydrocarbon against, any environmental liabilities associated with the EPA Administrative Order, the Kentucky Agreed Order or any other environmental condition related to the real property prior to the effective dates of MarkWest Hydrocarbon's agreements pursuant to which MarkWest Hydrocarbon leased the real property or purchased the real property from Columbia Gas. In addition, Columbia Gas has agreed to perform all the required response actions at its cost and expense in a manner that minimizes interference with MarkWest Hydrocarbon's use of the properties. On May 24, 2002, MarkWest Hydrocarbon assigned to us the benefit of its indemnity from Columbia Gas with respect to the Cobb, Boldman and Kermit facilities. While we are not a party to the agreement under which Columbia Gas agreed to indemnify MarkWest Hydrocarbon with respect to the Kermit facility, MarkWest Hydrocarbon has agreed to provide us with the benefit of its indemnity, as well as any other third-party environmental indemnity of which it is a beneficiary. To date, Columbia Gas has been performing all actions required under these agreements, and, accordingly, we do not believe that the remediation of these properties by Columbia Gas pursuant to the EPA Administrative Order or the Kentucky Agreed Order will have a material adverse impact on our financial condition or results of operations. MarkWest Hydrocarbon has also agreed to provide us an additional environmental indemnification pursuant to the terms of the Omnibus Agreement. See "Certain Relationships and Related Transactions."
Air Emissions. Our operations are subject to the Clean Air Act and comparable state statutes. Amendments to the Clean Air Act were enacted in 1990. Moreover, recent or soon to be adopted changes to state implementation plans for controlling air emissions in regional, non-attainment areas require or will require most industrial operations in the United States to incur capital expenditures in order to meet air emission control standards developed by the EPA and state environmental agencies. As a result of these amendments, our processing and fractionating plants, pipelines, and storage facilities that emit volatile organic compounds or nitrogen oxides may become subject to increasingly stringent regulations, including requirements that some sources install maximum or reasonably available control technology. In addition, the 1990 Clean Air Act Amendments established a new operating permit for major sources, which applies to some of our facilities. Failure to comply with applicable air statutes or regulations may lead to the assessment of administrative, civil or criminal penalties, and may result in the limitation or cessation of construction or operation of certain air emission sources. Although we can give no assurances, we believe implementation of the 1990 Clean Air Act Amendments will not have a material adverse effect on our financial condition or results of operations.
Clean Water Act. The Federal Water Pollution Control Act, also known as the Clean Water Act, and similar state laws impose restrictions and strict controls regarding the discharge of pollutants, including natural gas liquid-related wastes, into state waters or waters of the United States. Regulations promulgated pursuant to these laws require that entities that discharge into federal and state waters obtain National Pollutant Discharge Elimination System, or NPDES, and/or state permits authorizing these discharges. The Clean Water Act and analogous state laws assess administrative, civil and criminal penalties for discharges of unauthorized pollutants into the water and impose substantial liability for the costs of removing spills from such waters. In addition, the Clean Water Act and analogous state laws
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require that individual permits or coverage under general permits be obtained by covered facilities for discharges of stormwater runoff. We believe that we are in substantial compliance with Clean Water Act permitting requirements as well as the conditions imposed thereunder, and that continued compliance with such existing permit conditions will not have a material effect on our results of operations.
Safety Regulation. Our pipelines are subject to regulation by the U.S. Department of Transportation under the Hazardous Liquid Pipeline Safety Act, as amended, or HLPSA, relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. The HLPSA covers crude oil, carbon dioxide, NGL and petroleum products pipelines and requires any entity which owns or operates pipeline facilities to comply with the regulations under the HLPSA, to permit access to and allow copying of records and to make certain reports and provide information as required by the Secretary of Transportation. We believe that our pipeline operations are in substantial compliance with applicable HLPSA requirements; however, due to the possibility of new or amended laws and regulations or reinterpretation of existing laws and regulations, there can be no assurance that future compliance with the HLPSA will not have a material adverse effect on our results of operations or financial position.
The Pipeline Safety Improvement Act of 2002 includes numerous provisions that tighten federal inspectors and safety requirements for natural gas and hazardous liquids pipeline facilities. Many of the statute's provisions build on existing statutory requirements and strengthen regulations of the Research and Special Programs Administration and the office of Pipeline Safety, in particular, with respect to operator qualifications programs, natural mapping system and safe excavation practices. Management of the Partnership believes that compliance with the Pipeline Safety Improvement Act of 2002 will not have a material effect on its operations.
The workplaces associated with the processing and storage facilities and the pipelines we operate are also subject to the requirements of the federal Occupational Safety and Health Act, or OSHA, and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities, and citizens. We believe that we have conducted our operations in substantial compliance with OSHA requirements, including general industry standards, record keeping requirements and monitoring of occupational exposure to regulated substances.
In general, we expect industry and regulatory safety standards to become more strict over time, thereby resulting in increased compliance expenditures. While these expenditures cannot be accurately estimated at this time, we do not expect such expenditures will have a material adverse effect on our results of operations.
We do not have any employees. To carry out our operations, our general partner or its affiliates employ approximately 70 individuals who operate our facilities as our agents, excluding general and administrative employees. The Paper, Allied Industrial, Chemical and Energy Workers International Union Local 5-372 represents fourteen employees at our Siloam fractionation facility in South Shore, Kentucky. The collective bargaining agreement with this Union expires on June 28, 2004. The agreement covers only hourly, non-supervisory employees. We consider labor relations to be satisfactory at this time.
We have been, and may continue to be, in the ordinary course of business, a defendant in various lawsuits and a party to various other legal proceedings, some of which are covered in whole or in part by insurance. We believe that the outcome of these lawsuits and other legal proceedings will not individually or in the aggregate have a future material adverse effect on our consolidated financial position, results of operations or cash flows.
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Management of MarkWest Energy Partners, L.P.
MarkWest Energy GP, L.L.C., as our general partner, manages our operations and activities on our behalf. Our general partner is not elected by our unitholders and will not be subject to reelection on a regular basis in the future. Unitholders do not directly or indirectly participate in our management or operation. Our general partner owes a fiduciary duty to our unitholders. Our general partner will be liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically non-recourse to it. However, whenever possible, our general partner intends to incur indebtedness or other obligations that are non-recourse.
Two members of the board of directors of our general partner serve on a Conflicts Committee to review specific matters that the board believes may involve conflicts of interest. The Conflicts Committee determines if the resolution of the conflict of interest is fair and reasonable to us. The members of the Conflicts Committee may not be officers or employees of our general partner or directors, officers, or employees of its affiliates and must meet the independence standards to serve on an audit committee of a board of directors established by the American Stock Exchange and certain other requirements. Any matters approved by the Conflicts Committee are conclusively deemed to be fair and reasonable to us, approved by all of our partners, and not a breach by our general partner of any duties it may owe us or our unitholders. The current members of the Conflicts Committee are Charles K. Dempster and William P. Nicoletti. Three members of the board of directors serve on the Compensation Committee, which oversees compensation decisions for the officers of our general partner as well as the compensation plans described below. Three members of the board of directors serve on the Audit Committee that review our external financial reporting, recommends engagement of our independent auditors and review procedures for internal auditing and the adequacy of our internal accounting controls. The members of the Compensation and Audit Committees are Charles K. Dempster, William A. Kellstrom and William P. Nicoletti.
Some officers of our general partner spend a substantial amount of time managing the business and affairs of MarkWest Hydrocarbon and its other affiliates. These officers may face a conflict regarding the allocation of their time between our business and the other business interests of MarkWest Hydrocarbon. Our general partner intends to cause its officers to devote as much time to the management of our business and affairs as is necessary for the proper conduct of our business and affairs.
Directors and Executive Officers of MarkWest Energy GP, L.L.C.
The following table shows information for the directors and executive officers of our general partner. Executive officers and directors are elected for one-year terms.
Name | Age | Position with our General Partner | ||
---|---|---|---|---|
John M. Fox | 63 | Chairman of the Board of Directors | ||
Frank M. Semple | 52 | President and Chief Executive Officer | ||
Arthur J. Denney | 55 | Director, Executive Vice President, Chief Operating Officer and Assistant Secretary | ||
Donald C. Heppermann | 60 | Director, Executive Vice President, Chief Financial Officer and Secretary | ||
Randy S. Nickerson | 42 | Senior Vice President, Corporate Development | ||
John C. Mollenkopf | 42 | Vice President, Business Development | ||
Charles K. Dempster | 61 | Director | ||
William A. Kellstrom | 62 | Director | ||
William P. Nicoletti | 58 | Director |
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John M. Fox has served as Chairman of the Board of Directors of our general partner since May 2002 and has served in the same capacity with MarkWest Hydrocarbon since its inception in April 1988. Mr. Fox also served as President and Chief Executive Officer of our general partner and MarkWest Hydrocarbon from April 1988 until his resignation as President on November 1, 2003 and his resignation as Chief Executive Officer effective December 31, 2003. Mr. Fox was a founder of Western Gas Resources, Inc. and was its Executive Vice President and Chief Operating Officer from 1972 to 1986. Mr. Fox holds a bachelor's degree in engineering from the United States Air Force Academy and a master of business administration degree from the University of Denver.
Frank M. Semple was appointed as President of both our general partner and MarkWest Hydrocarbon on November 1, 2003. Mr. Semple also became Chief Executive Officer of both our general partner and MarkWest Hydrocarbon on January 1, 2004. Prior to his appointment, Mr. Semple served as Chief Operating Officer of WilTel Communications, formerly Williams Communications, a $1.5 billion revenue, 2,500 employee telecommunications company based in Tulsa, Oklahoma. On April 22, 2002, Williams Communications, along with one of its subsidiaries filed petitions for relief under the Bankruptcy Code. On September 30, 2002, the Bankruptcy Court entered an order confirming the plan of reorganization, which became effective on October 15, 2002. Prior to his tenure at WilTel Communications, he was the Senior Vice President/General Manager of Williams Natural Gas from 1995 to 1997 as well as Vice President of Marketing and Vice President of Operations and Engineering for Northwest Pipeline and Director of Product Movements and Division Manager for Williams Pipeline during his 22-year career with the Williams Companies. During his tenure at Williams Communications, he served on the board of directors for PowerTel Communications and the Competitive Telecommunications Association (Comptel). He currently serves on the board of directors for the Tulsa Zoo and the Children's Medical Center. Mr. Semple holds a bachelor's degree in mechanical engineering from the United States Naval Academy.
Arthur J. Denney has served as Executive Vice President, Chief Operating Officer and Assistant Secretary of our general partner since January 2003. Prior to that, Mr. Denney served as Executive Vice President of our general partner since its inception in May 2002 and has served in the same capacity with MarkWest Hydrocarbon since December 2001. Prior to that, Mr. Denney served as MarkWest Hydrocarbon's Senior Vice President of Engineering and Project Development since January 1997, as a member of its Board of Directors since June 1996 and as its Vice President of Engineering and Business Development since January 1990. Mr. Denney has more than 29 years of experience in gas gathering, gas processing and NGL businesses. From 1987 to 1990, Mr. Denney served as Manager of Business Development for Lair Petroleum, Inc. From 1974 to 1987, Mr. Denney was employed by Enron Gas Processing Co. and predecessor companies in a variety of positions, including seven years as its Rocky Mountain Regional Manager of its midstream businesses. Mr. Denney holds a bachelor's degree in mechanical engineering and a master of business administration degree from the University of Nebraska.
Donald C. Heppermann has served as Executive Vice President, Chief Financial Officer and Secretary of our general partner since October 2003. He joined our general partner and MarkWest Hydrocarbon in November 2002 as Senior Vice President and Chief Financial Officer and served as Senior Executive Vice President beginning in January 2003. Mr. Heppermann has served on our general partner's board of directors since its inception in May 2002. Prior to joining our general partner and MarkWest Hydrocarbon, Mr. Heppermann was a private investor and a career executive in the energy industry with major responsibilities in operations, finance, business development and strategic planning. From 1990 to 1997 he served as President and Chief Operating Officer for InterCoast Energy Company, an unregulated subsidiary of Mid American Energy Company. From 1987 to 1990 Mr. Heppermann was with Pinnacle West Capital Corporation, the holding company for Arizona Public Service Company, where he was Vice President of Finance. Prior to 1987, Enron Corporation and its predecessors employed Mr. Heppermann in a variety of positions, including
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Executive Vice President, Gas Pipeline Group. Mr. Heppermann holds a bachelor's degree in accounting from the University of Missouri and a master of business degree from Creighton University.
Randy S. Nickerson has served as Senior Vice President, Corporate Development of our general partner since October 2003. Prior to that, Mr. Nickerson served as Executive Vice President, Corporate Development of our general partner since January 2003 and as Senior Vice President of our general partner since its inception in May 2002 and has served in the same capacity with MarkWest Hydrocarbon since December 2001. Prior to that, Mr. Nickerson served as MarkWest Hydrocarbon's Vice President and the General Manager of the Appalachia Business Unit since June 1997. Mr. Nickerson joined MarkWest Hydrocarbon in July 1995 as Manager, New Projects and served as General Manager of the Michigan Business Unit from June 1996 until June 1997. From 1990 to 1995, Mr. Nickerson was a Senior Project Manager and Regional Engineering Manager for Western Gas Resources, Inc. From 1984 to 1990, Mr. Nickerson worked for Chevron USA and Meridian Oil Inc. in various process and project engineering positions. Mr. Nickerson holds a bachelor's degree in chemical engineering from Colorado State University.
John C. Mollenkopf has served as Vice President, Business Development of our general partner since January 2003. Prior to that, he served as Vice President—Michigan Business Unit of our general partner since its inception in May 2002 and in the same capacity with MarkWest Hydrocarbon since December 2001. Prior to that, Mr. Mollenkopf was General Manager of the Michigan Business Unit of MarkWest Hydrocarbon since 1997. He joined MarkWest Hydrocarbon in 1996 as Manager, New Projects. From 1983 to 1996, Mr. Mollenkopf worked for ARCO Oil and Gas Company, holding various positions in process and project engineering, as well as operations supervision. Mr. Mollenkopf holds a bachelor's degree in mechanical engineering from the University of Colorado at Boulder.
Charles K. Dempster has served as a member of the board of directors of our general partner since December 2002. Mr. Dempster has more than 30 years of experience in the natural gas and power industry since 1969. He held various management and executive positions with Enron between 1969 and 1986 focusing on natural gas supply, transmission and distribution. From 1986 through 1992 Mr. Dempster served as President of Reliance Pipeline Company and Executive Vice President of Nicor Oil and Gas Corporation, which were oil and gas midstream and exploration subsidiaries of Nicor Inc. in Chicago. He was appointed President of Aquila Energy Corporation in 1993, a wholly owned midstream, pipeline and energy-trading subsidiary of Utilicorp, Inc. Mr. Dempster retired in 2000 as Chairman and CEO of Aquila Energy Company. Mr. Dempster holds a bachelor's degree in civil engineering from the University of Houston and attended graduate business school at the University of Nebraska.
William A. Kellstrom has served as a member of the Board of Directors of our general partner since its inception in May 2002 and has served as a director of MarkWest Hydrocarbon since May 2000. Mr. Kellstrom has held a variety of managerial positions in the natural gas industry since 1968. They include distribution, pipelines and marketing. He held various management and executive positions with Enron Corp., including Executive Vice President, Pipeline Marketing and Senior Vice President, Interstate Pipelines. In 1989, he created and was President of Tenaska Marketing Ventures, a gas marketing company for the Tenaska Power Group. From 1992 until 1997 he was with NorAm Energy Corporation (since merged with Reliant Energy, Incorporated) where he was President of the Energy Marketing Company and Senior Vice President, Corporate Development. Mr. Kellstrom holds an engineering degree from Iowa State University and a master of business administration degree from the University of Illinois. He retired in 1997 and is periodically engaged as a consultant to energy companies.
William P. Nicoletti has served as a member of the Board of Directors of our general partner since its inception in May 2002. Mr. Nicoletti is Managing Director of Nicoletti & Company Inc., a private banking firm serving clients in the energy and transportation industries. In addition, Mr. Nicoletti has
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served as a Senior Advisor to the Energy Investment Banking Group of McDonald Investments Inc. From March 1998 until July 1999, Mr. Nicoletti was a Managing Director and co-head of Energy Investment Banking for McDonald Investments Inc. Prior to forming Nicoletti & Company Inc. in 1991, Mr. Nicoletti was a Managing Director and head of Energy Investment Banking for PaineWebber Incorporated. Previously, he held a similar position at E.F. Hutton & Company Inc. He is chairman of the board of directors of Russell-Stanley Holdings, Inc., a manufacturer and marketer of plastic and steel industrial containers; a director of Southwest Royalties, Inc., an oil and gas production company; and a director of Star Gas LLC, the general partner of Star Gas Partners, L.P., a retail propane and heating oil master limited partnership. Mr. Nicoletti holds a bachelor's degree in mathematics from Seton Hall University and a master of business administration degree from Columbia University.
Reimbursement of Expenses of our General Partner
Our general partner does not receive any management fee or other compensation for its management of MarkWest Energy Partners, L.P. Our general partner and its affiliates are reimbursed for expenses incurred on our behalf. These expenses include the costs of employee, officer and director compensation and benefits properly allocable to us, and all other expenses necessary or appropriate to the conduct of the business of, and allocable to, us. The partnership agreement provides that our general partner will determine the expenses that are allocable to us in any reasonable manner determined by our general partner in its sole discretion.
The Partnership has no employees. It is managed by the officers of its general partner. Aside from restricted unit awards (discussed later), the executive officers of our general partner are compensated by MarkWest Hydrocarbon and do not receive compensation from our general partner or us for their services in such capacities. We reimburse MarkWest Hydrocarbon for a portion of their salaries.
The following table sets forth the cash and non-cash compensation earned for fiscal years 2002, 2001 and 2000 by our general partner's Chief Executive Officer and the three other highest paid officers, whose salary and bonus exceeded $100,000 for services rendered. The table also includes information regarding Gerald Tywoniuk, the former Chief Financial Officer of our general partner who would have been a Named Executive Officer but for the fact he was not an executive officer of our general partner as of December 31, 2002.
Our general partner was created in January 2002 and our initial public offering closed in May 2002, at which point we commenced reimbursing MarkWest Hydrocarbon for general and administrative expenses, including a portion of the Named Executive Officers' compensation. Information included in the following table for the periods ended prior to May 24, 2002 is provided for comparability purposes.
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Summary Compensation Table
| Annual Compensation | Long-Term Compensation | ||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Name and Principal Positions | Fiscal Year | Salary ($)(1) | Bonus ($)(2) | Restricted Unit Awards ($)(3) | Other Compensation ($)(4) | |||||||||
John M. Fox Chief Executive Officer | 2002 2001 2000 | $ | 190,515 186,213 179,196 | $ | 3,199 9,595 78,270 | $ | 110,000 — — | $ | 15,241 12,900 13,600 | |||||
Arthur J. Denney Executive Vice President, Chief Operating Officer and Assistant Secretary | 2002 2001 2000 | 176,096 172,120 164,797 | 2,957 8,868 72,346 | 110,000 — — | 14,088 12,692 13,184 | |||||||||
Randy S. Nickerson Senior Vice President, Corporate Development | 2002 2001 2000 | 154,943 147,628 141,432 | 2,601 7,602 62,013 | 110,000 — — | 12,395 10,948 11,301 | |||||||||
John C. Mollenkopf Vice President, Business Development | 2002 2001 2000 | 129,322 124,892 117,857 | 2,171 5,991 42,925 | 110,000 — — | 10,346 9,056 12,901 | |||||||||
Gerald A. Tywoniuk Former Chief Financial Officer | 2002 2001 2000 | 164,764 160,336 148,495 | 2,957 8,142 66,423 | 110,000 — — | 91,120 11,731 11,798 |
- (1)
- Represents actual salary earned in each respective fiscal year for services rendered on behalf of both the Partnership and MarkWest Hydrocarbon. Mr. Tywoniuk's salary in fiscal 2002 represents the pro rata portion of his annual salary from January 1 through the end of his employment with our general partner on November 30, 2002.
- (2)
- Represents actual bonus earned in each respective fiscal year for services rendered on behalf of both the Partnership and MarkWest Hydrocarbon. Bonuses are paid to all employees in quarterly installments based on year-to-date performance in May, August, and December with the balance paid in March of the following year in accordance with provisions of MarkWest Hydrocarbon's Incentive Compensation Plan.
- (3)
- Represents the sum of 2002 quarterly cash distributions received and the value of the executive officer's restricted unit award (calculated by multiplying $21.50, the closing market price of our common units on the date of grant, May 24, 2002, by the number of units awarded). Messrs. Fox, Denney, Nickerson, Mollenkopf, and Tywoniuk were granted 5,000 restricted units each. At December 31, 2002, our aggregate outstanding restricted units totaled 50,230 units, valued at $1.2 million. The restricted units vest over a period of four years, with 25% of the grant vesting at the end of each of the second and third years and 50% vesting at the end of the fourth year.
- (4)
- Represents actual MarkWest Hydrocarbon contributions under MarkWest Hydrocarbon's 401(k) Savings and Profit Sharing Plan. Mr. Tywoniuk's total also includes a one-time only payment of $0.1 million received upon his resignation from our general partner and MarkWest Hydrocarbon effective November 30, 2002 pursuant to his severance plan.
Officers or employees of our general partner who also serve as directors will not receive additional compensation. Each independent director receives an annual retainer of $12,000 and 500 restricted units per year. In addition, each independent director will receive compensation of $1,500 for in-person attendance and $700 for telephonic attendance at meetings of the board of directors or committees of the board of directors. The members of the audit and conflicts committees receive compensation of $1,000 for each committee meeting. Additionally, members of the audit and conflict committees receive an annual retainer of $3,000. Each independent director will be reimbursed for out-of-pocket expenses in connection with attending meetings of the board of directors or committees. Each director will be fully indemnified by us for actions associated with being a director to the extent permitted under Delaware law.
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Non-Competition, Non-Solicitation and Confidentiality Agreement and Severance Plan
Each of our general partner's named executive officers is a party to a Non-Competition, Non-Solicitation and Confidentiality Agreement. As a result of signing the Non-Competition, Non-Solicitation and Confidentiality Agreement, the named executive officers are eligible for the 1997 Severance Plan. The Severance Plan provides for payment of benefits in the event that (i) the employee terminates his or her employment for "good reason" (as defined), (ii) the employee's employment is terminated "without cause" (as defined), (iii) the employee's employment is terminated by reason of death or disability or (iv) the employee voluntarily resigns. In the case of (i), (ii) and (iii) above, the employee shall be entitled to receive base salary and continued medical benefits for a period ranging from six months to twenty-four months, depending upon the employee's status at the time of the termination. In the case of (iv) above, the employee shall be entitled to receive base salary for a period ranging from one month to six months and continued medical benefits for a period ranging from one month to six months. In either case, the aggregate amount of benefits paid to an employee shall in no event exceed twice the employee's annual compensation during the year immediately preceding the termination.
Our general partner has adopted the MarkWest Energy Partners, L.P. Long-Term Incentive Plan for employees and directors of our general partner and employees of its affiliates who perform services for us. The long-term incentive plan consists of two components, restricted units and unit options. The long-term incentive plan currently permits the grant of awards covering an aggregate of 500,000 common units, 200,000 of which may be awarded in the form of restricted units and 300,000 of which may be awarded in the form of unit options. The compensation committee of our general partner's board of directors administers the plan.
Our general partner's board of directors in its discretion may terminate or amend the long-term incentive plan at any time with respect to any units for which a grant has not yet been made. Our general partner's board of directors also has the right to alter or amend the long-term incentive plan or any part of the plan from time to time, including increasing the number of units that may be granted subject to unitholder approval as required by the exchange upon which the common units are listed at that time. However, no change in any outstanding grant may be made that would materially impair the rights of the participant without the consent of the participant.
Restricted Units. A restricted unit is a "phantom" unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit, or in the discretion of the compensation committee, cash equivalent to the value of a common unit. These restricted units will be entitled to receive distribution equivalents, which represent cash equal to the amount of cash distributions made on common units during the vesting period, from the date of grant and will vest over a period of four years, with 25% of the grant vesting at the end of each of the second and third years and 50% vesting at the end of the fourth year. In the future, the compensation committee may determine to make additional grants under the plan to employees and directors containing such terms as the compensation committee shall determine under the plan. The compensation committee will determine the period over which restricted units granted to employees and directors will vest. The committee may base its determination upon the achievement of specified financial objectives. In addition, the restricted units will vest upon a change of control of us, our general partner or MarkWest Hydrocarbon.
If a grantee's employment or membership on the board of directors terminates for any reason, the grantee's restricted units will be automatically forfeited unless, and to the extent, the compensation committee provides otherwise. Common units to be delivered upon the vesting of restricted units may be common units acquired by our general partner in the open market, common units already owned by our general partner, common units acquired by our general partner directly from us or any other
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person or any combination of the foregoing. Our general partner will be entitled to reimbursement by us for the cost incurred in acquiring common units. If we issue new common units upon vesting of the restricted units, the total number of common units outstanding will increase. The compensation committee, in its discretion, may grant distribution rights with respect to any additional restricted unit grants.
We intend the issuance of the common units upon vesting of the restricted units under the plan to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of the common units. Therefore, plan participants will not pay any consideration for the common units they receive, and we will receive no remuneration for the units.
In October 2003, the board of directors of our general partner approved the accelerated vesting of 23,758 restricted units effective December 1, 2003. As of December 1, 2003, there were 35,607 restricted units granted to officers, employees and directors of our general partner and its affiliates that remained outstanding.
Unit Options. The long-term incentive plan currently permits the grant of options covering common units. In the future, the compensation committee may determine to make grants under the plan to employees and directors containing such terms as the committee shall determine. Unit options will have an exercise price that, in the discretion of the committee, may be less than, equal to or more than the fair market value of the units on the date of grant. In general, unit options granted will become exercisable over a period determined by the compensation committee. In addition, the unit options will become exercisable upon a change in control of us, our general partner, MarkWest Hydrocarbon or upon the achievement of specified financial objectives.
Upon exercise of a unit option, our general partner will acquire common units in the open market or directly from us or any other person or use common units already owned by our general partner, or any combination of the foregoing. Our general partner will be entitled to reimbursement by us for the difference between the cost incurred by our general partner in acquiring these common units and the proceeds received by our general partner from an optionee at the time of exercise. Thus, the cost of the unit options will be borne by us. If we issue new common units upon exercise of the unit options, the total number of common units outstanding will increase, and our general partner will pay us the proceeds it received from the optionee upon exercise of the unit option. The unit option plan has been designed to furnish additional compensation to employees and directors and to align their economic interests with those of common unitholders.
At September 30, 2003, we had not granted common unit options to directors or employees of our general partner, or employees of its affiliates or members of senior management.
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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table sets forth the beneficial ownership of units as of December 29, 2003 held by beneficial owners of 5% or more of the units, by directors of our general partner, by each named executive officer and by all directors and officers of our general partner as a group.
Name of Beneficial Owner | Common Units Beneficially Owned | Percentage of Common Units Beneficially Owned | Subordinated Units Beneficially Owned | Percentage of Subordinated Units Beneficially Owned | Percentage of Total Units Beneficially Owned | ||||||
---|---|---|---|---|---|---|---|---|---|---|---|
MarkWest Energy GP, L.L.C. | — | — | — | — | — | ||||||
MarkWest Hydrocarbon, Inc.(1) | — | — | 2,468,129 | 82.3 | % | 42.5 | % | ||||
John M. Fox(2) | 23,500 | * | 2,487,755 | 82.9 | % | 43.2 | % | ||||
Tortoise MWEP, L.P. | — | — | 500,000 | 16.7 | % | 8.6 | % | ||||
Frank M. Semple. | — | — | 5,000 | * | * | ||||||
Arthur J. Denney | 2,000 | * | 4,626 | * | * | ||||||
Donald C. Heppermann | 4,500 | * | 4,000 | * | * | ||||||
Randy S. Nickerson | 4,375 | * | 4,626 | * | * | ||||||
John C. Mollenkopf | — | — | 4,626 | * | * | ||||||
William A. Kellstrom | 2,750 | * | — | — | * | ||||||
William P. Nicoletti | 2,500 | * | — | — | * | ||||||
Charles K. Dempster | — | — | — | — | — | ||||||
All directors and executive officers as a group (9 persons) | 39,625 | 1.4 | % | 2,510,633 | 83.7 | % | 43.9 | % | |||
Other(3) | — | — | 4,367 | * | * |
- *
- Less than 1%
- (1)
- Includes securities owned directly and indirectly through subsidiaries.
- (2)
- Includes 4,626 subordinated units owned directly by Mr. Fox, 2,473,129 subordinated units owned by MarkWest Hydrocarbon and its subsidiaries, and approximately 15,000 subordinated units owned by Tortoise MWEP, L.P. in which Mr. Fox owns an equity interest. As of September 30, 2003, Mr. Fox beneficially owned approximately 50% of the voting securities of MarkWest Hydrocarbon. Mr. Fox currently serves as MarkWest Hydrocarbon's Chairman of the Board. Mr. Fox resigned as President of MarkWest Hydrocarbon effective November 1, 2003 and as Chief Executive Officer effective January 1, 2004. As a result, Mr. Fox may be deemed to be the beneficial owner of the subordinated units owned by MarkWest Hydrocarbon.
- (3)
- Held by two key officers of MarkWest Hydrocarbon and one key officer of our general partner.
The following table sets forth the beneficial ownership of our general partner as of December 29, 2003 held by MarkWest Hydrocarbon, the directors of our general partner, each named executive officer and by all directors and officers of our general partner as a group.
Name of Beneficial Owner | Percentage of Limited Liability Company Interests Owned | ||
---|---|---|---|
MarkWest Hydrocarbon, Inc. | 89.7 | % | |
John M. Fox(1) | 91.3 | ||
Frank M. Semple | 2.0 | ||
Arthur J. Denney | 1.6 | ||
Donald C. Heppermann | 1.0 | ||
Randy S. Nickerson | 1.6 | ||
John C. Mollenkopf | 1.6 | ||
William A. Kellstrom | 0.0 | ||
William P. Nicoletti | 0.0 | ||
Charles K. Dempster | 0.0 | ||
All directors and executive officers as a group (9 persons) | 7.4 | ||
Other(2) | * |
- *
- Less than 1%
- (1)
- Includes a 1.6% ownership interest held directly by Mr. Fox and a 89.7% ownership interest held by MarkWest Hydrocarbon. As of September 30, 2003, Mr. Fox beneficially owned approximately 50% of the voting securities of MarkWest Hydrocarbon. Mr. Fox currently serves as MarkWest Hydrocarbon's Chairman of the Board. Mr. Fox resigned as President of MarkWest Hydrocarbon effective November 1, 2003, and as Chief Executive Officer effective January 1, 2004. As a result, Mr. Fox may be deemed to be the beneficial owner of the ownership interests owned by MarkWest Hydrocarbon.
- (2)
- Held by two key officers of MarkWest Hydrocarbon and one key officer of our general partner.
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The following table shows the beneficial ownership of common units held by the selling unitholders as of December 29, 2003 and to be held following the offering. Each of the selling unitholders acquired its common units in connection with the June 2003 private placement.
We and the selling shareholders are parties to a registration rights agreement. This registration rights agreement gives the holders of the securities covered under the agreement rights to request registration of their common units and to participate in any registration by us of any of our common units for sale to the public pursuant to the Securities Act (other than in connection with mergers, acquisitions, exchange offers, options or other employee benefit plans). We are required to pay all registration expenses if these registration rights are exercised, other than underwriting discounts and selling commissions. For a more detailed discussion of the registration rights agreement, please read "Units Eligible for Future Sale."
| Common Units Beneficially Owned Prior to this Offering | | Common Units Beneficially Owned Following this Offering | |||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|
Name of Selling Unitholder | Number | Percentage Owned | Units Offered in this Offering | Number | Percentage Owned | |||||||
Robert A. Tucci and Cynthia L. Tucci 8631 Cedar Drive Prairie Village, KS 66207 | 19,062 | * | 9,531 | 9,531 | * | |||||||
Ellkan, L.L.C. 4200 Somerset Drive, Suite 200 Prairie Village, KS 66208 | 19,062 | * | 9,531 | 9,531 | * | |||||||
Jonathan E. Baum Revocable Trust u/a dated January 29, 1992 3600 W. 64th Street Mission Hills, KS 66208 | 9,532 | * | 4,766 | 4,766 | * | |||||||
Sally K. Hilkene Revocable Trust Dated August 30, 2002 2700 Verona Road Shawnee Mission, KS 66208 | 7,624 | * | 3,812 | 3,812 | * | |||||||
Frederick M. Solberg, Jr. and Elizabeth T. Solberg 850 W. 52nd Street Kansas City, MO 64112 | 7,624 | * | 3,812 | 3,812 | * | |||||||
Dennis L. Baumann Trust A u/t/a dated November 24, 1992 17054 S. Demi Drive Belton, MO 64012 | 5,718 | * | 5,718 | — | — | |||||||
Douglas D. Klink Revocable Trust Dated March 16, 2000 3505 St. Francis Way Estes Park, CO 80517 | 3,812 | * | 3,812 | — | — | |||||||
Piontek Family L.P. 1495 Hemlock Drive Liberty, MO 64068 | 3,812 | * | 3,812 | — | — | |||||||
Richard C. Kruel 2205 W. 126th Street Leawood, KS 66209 | 2,000 | * | 2,000 | — | — | |||||||
William or Victoria Reisler 6225 Indian Lane Mission Hills, KS 66208 | 762 | * | 762 | — | — | |||||||
Total | 79,008 | 2.8 | % | 47,556 | 31,452 | * | % | |||||
- *
- Less than 1%
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CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
MarkWest Hydrocarbon controls our operations through its ownership of our general partner, as well as a significant limited partner ownership interest in us through its ownership of a majority of our subordinated units. As of December 29, 2003, affiliates of MarkWest Hydrocarbon, in the aggregate, owned a 44.1% interest in the Partnership, consisting of 2,500,000 subordinated units and a 2% general partner interest.
Distributions and Payments to our General Partner and its Affiliates
Our general partner does not receive any management fee or other compensation in connection with its management of our business, but is reimbursed for all direct and indirect expenses incurred on our behalf. Our general partner owns the 2% general partner interest and all of the incentive distribution rights. Our general partner is entitled to receive incentive distributions if the amount we distribute with respect to any quarter exceeds levels specified in our partnership agreement. Under the quarterly incentive distribution provisions, generally our general partner is entitled to 13% of amounts we distribute in excess of $0.55 per unit, 23% of the amounts we distribute in excess of $0.625 per unit and 48% of amounts we distribute in excess of $0.75 per unit.
Agreements with MarkWest Hydrocarbon
We entered into various agreements with MarkWest Hydrocarbon at the closing of our initial public offering. specifically, we entered into:
- •
- an Omnibus Agreement;
- •
- a Gas Processing Agreement;
- •
- a Pipeline Liquids Transportation Agreement;
- •
- a Fractionation, Storage and Loading Agreement; and
- •
- a Natural Gas Liquids Purchase Agreement.
These agreements were not the result of arm's-length negotiations.
Concurrently with the closing of our initial public offering, we entered into an agreement with MarkWest Hydrocarbon, our general partner and our operating company that governs potential competition and indemnification obligations among us and the other parties to the agreement.
Services. Pursuant to the omnibus agreement, MarkWest Hydrocarbon and our general partner agreed that, for the first year following our initial public offering, we would not be responsible for more than $4.9 million for the provision by MarkWest Hydrocarbon and our general partner of general and administrative services on our behalf pursuant to the partnership agreement. This limitation did not apply to the cost of any third party legal, accounting or advisory services received, or the direct expenses of MarkWest Hydrocarbon and its affiliates incurred, in connection with acquisition or business development opportunities evaluated on behalf of the Partnership. The time period of this limitation has expired and our general partner may allocate expenses to us in its sole discretion. Pursuant to the omnibus agreement, we have designated each current or future employee of MarkWest Hydrocarbon who fulfills a job function on our behalf as our agent, with full power and authority to perform such job function.
Non-Competition Provisions. MarkWest Hydrocarbon agreed, and caused its affiliates to agree, for so long as MarkWest Hydrocarbon controls the general partner, not to engage in, whether by
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acquisition, construction or otherwise, the business of processing natural gas and transporting, fractionating and storing NGLs. This restriction will not apply to:
- •
- the gathering of natural gas;
- •
- any business operated by MarkWest Hydrocarbon or any of its subsidiaries at the closing of our initial public offering;
- •
- any business that MarkWest Hydrocarbon or any of its subsidiaries acquires or constructs that has a fair market value of less than $7.5 million;
- •
- any business that MarkWest Hydrocarbon or any of its subsidiaries acquires or constructs that has a fair market value of $7.5 million or more if we have been offered the opportunity to purchase the business for fair market value, and we decline to do so with the concurrence of our conflicts committee; and
- •
- any business that MarkWest Hydrocarbon or any of its subsidiaries acquires or constructs where the fair market value of the restricted business is $7.5 million or more and represents less than 20% of the aggregate value of the entire business to be acquired or constructed; provided, however, that following completion of such acquisition or construction, we are provided the opportunity to purchase such restricted business.
Indemnification Provisions. Under the omnibus agreement, MarkWest Hydrocarbon has agreed to indemnify us for three years after the closing of our initial public offering against certain environmental and toxic tort liabilities associated with the operation of the assets contributed to us by MarkWest Hydrocarbon and occurring before the closing date of our initial public offering. However, MarkWest Hydrocarbon will have no obligation to indemnify us until our losses exceed $500,000 and MarkWest Hydrocarbon's maximum liability will not exceed $5 million. MarkWest Hydrocarbon will also specifically indemnify us against environmental and toxic tort liabilities to the extent that MarkWest Hydrocarbon is entitled to and receives indemnification from any third party. Please read "Business—Environmental Matters—Ongoing Remediation and Indemnification from Columbia Gas."
MarkWest Hydrocarbon will also indemnify us for liabilities relating to:
- •
- certain specified legal actions pending against MarkWest Hydrocarbon or its affiliates at the closing of our initial public offering;
- •
- certain defects in title to the assets contributed to us and failure to obtain certain consents and permits necessary to conduct our business that arise within three years after the closing of our initial public offering;
- •
- events and conditions associated with any assets retained by MarkWest Hydrocarbon or its affiliates; and
- •
- certain income tax liabilities attributable to the operation of the assets contributed to us prior to the time that they were contributed.
License Provisions. Pursuant to the omnibus agreement, MarkWest Hydrocarbon granted us a nontransferable, nonexclusive, royalty-free right to use the name and mark "MarkWest."
The omnibus agreement may not be amended without the concurrence of the conflicts committee. The omnibus agreement, other than the indemnification provisions, will terminate if:
- •
- a change of control of MarkWest Hydrocarbon occurs; or
- •
- we are no longer an affiliate of MarkWest Hydrocarbon.
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Concurrently with the closing of our initial public offering, we entered into a Gas Processing Agreement with MarkWest Hydrocarbon that governs the parties' obligations with respect to the processing of natural gas at our Kenova, Boldman and Cobb processing plants.
Gas Processing Services. Under the Gas Processing Agreement, until 2012 and on a year-to-year basis thereafter, MarkWest Hydrocarbon has agreed to:
- •
- commit to deliver, at specified locations, all of the natural gas that MarkWest Hydrocarbon has the right to process or have processed at our Kenova, Boldman or Cobb processing plants under its operating agreements with Columbia Gas; and
- •
- furnish all of the natural gas used as fuel in the operation of our Kenova, Boldman and Cobb processing plants.
We have agreed to:
- •
- accept and process, at our sole risk and expense, all of the natural gas that MarkWest Hydrocarbon delivers to our Kenova, Boldman or Cobb processing plants up to the then-existing design capacity of each processing plant;
- •
- redeliver, for the account of MarkWest Hydrocarbon, or for the parties designated by MarkWest Hydrocarbon, the residue gas to Columbia Gas' transmission facilities;
- •
- deliver all NGLs recovered or extracted at each processing plant to MarkWest Hydrocarbon for further transportation to our Siloam fractionator facility;
- •
- in the event the volumes delivered to any processing plant exceed the then-existing plant design capacity, use our reasonable, diligent efforts to process all the natural gas delivered by MarkWest Hydrocarbon to, or as near as possible to, the residue gas quality specifications; and
- •
- if at any time the volumes delivered to a processing plant exceed by 5% the daily average of volume that can be processed to residue gas for 60 days within a 90 day period, promptly begin and diligently complete the necessary work to increase the capacity of a processing plant.
As compensation for providing these services, MarkWest Hydrocarbon pays us a monthly gas processing fee based on the natural gas volumes delivered at our Kenova, Boldman and Cobb processing plants. A portion of this gas processing fee is annually adjusted on each anniversary of the effective date to reflect changes in the Producers Price Index for Oil and Gas Field Services.
Indemnification Provisions. Under the Gas Processing Agreement, MarkWest Hydrocarbon has agreed to indemnify us from any and all losses we incur arising from MarkWest Hydrocarbon facilities or its possession and control of the natural gas (except to the extent caused by our gross negligence or willful conduct). MarkWest Hydrocarbon will be in possession and control of the natural gas until it is delivered to one of our processing facilities and after our operating company redelivers the residue gas to MarkWest Hydrocarbon.
We have agreed to indemnify MarkWest Hydrocarbon from any and all losses incurred by MarkWest Hydrocarbon arising from our facilities or our possession and control of the natural gas (except to the extent caused by MarkWest Hydrocarbon's gross negligence or willful conduct). We will be in possession and control of the natural gas after it is delivered to one of our processing facilities and until we redeliver the residue gas to MarkWest Hydrocarbon.
We will also pay MarkWest Hydrocarbon a penalty of $5,000 per day (unless MarkWest Hydrocarbon can establish actual damages in excess of $5,000 per day) if we fail to process the natural
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gas at any of our processing plants to meet the agreed specifications or interrupt the NGL production process, unless the reason for the failure or interruption is:
- •
- the suspension of operations necessary for turnaround time, maintenance or repair time, not to exceed 30 days per year;
- •
- conditions of force majeure; or
- •
- reasons related to safety considerations and the integrity of our processing plants
If we interrupt processing at any of our processing plants for any reason for 30 consecutive days without making a good faith effort to resume processing as soon as reasonably possible, or, after notification from MarkWest Hydrocarbon, we are otherwise in default of any of the terms of the Gas Processing Agreement for 25 days, then MarkWest Hydrocarbon, in its sole discretion and in addition to any other available legal or equitable remedies, may:
- •
- satisfy any and all of our obligations and be reimbursed by us the amount paid, attorneys fees and annual interest;
- •
- seek interlocutory equitable relief and perform or have performed our obligations at our sole risk, liability, cost and expense; or
- •
- require us to specifically perform our obligations.
Pipeline Liquids Transportation Agreement
Concurrently with the closing of our initial public offering, we entered into a Pipeline Liquids Transportation Agreement with MarkWest Hydrocarbon that governs the parties' obligations with respect to the transportation of mixed NGLs to our Siloam fractionation facility.
Transportation Services. Under this Transportation Agreement, until 2012 and on a year-to-year basis thereafter, MarkWest Hydrocarbon delivers, at specified locations, all of its NGLs acquired from our Kenova processing facility, and any of its NGLs it desires to deliver from our Boldman extraction facility, or from other extraction plants or sources in the Appalachian region.
We maintain and operate our pipeline system, at our sole risk and expense, to transport all of the NGLs that MarkWest Hydrocarbon delivers from our extraction facilities to our Siloam fractionation facility.
As compensation for providing these services, MarkWest Hydrocarbon pays us a monthly transportation fee based on the number of gallons of the NGLs transported to our Siloam fractionation facility. A portion of this transportation fee is annually adjusted on January 1 of each year to reflect changes in the Producers Price Index for Oil and Gas Field Services. Under the agreement, MarkWest Hydrocarbon will incur all of the incidental losses incurred at our facilities, or the losses or gains due to variations in measurement equipment.
Indemnification Provisions. Under the Transportation Agreement, MarkWest Hydrocarbon has agreed to indemnify us from any and all losses we incur arising from MarkWest Hydrocarbon facilities or its possession and control of the NGLs (except to the extent caused by our gross negligence or willful conduct). MarkWest Hydrocarbon will be in possession and control of the NGLs until they are delivered to our pipeline system.
We have agreed to indemnify MarkWest Hydrocarbon from any and all losses incurred by MarkWest Hydrocarbon arising from our facilities or our possession and control of the NGLs (except to the extent caused by MarkWest Hydrocarbon's gross negligence or willful conduct). We will be in possession and control of the NGLs after they are delivered to our pipeline system.
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Fractionation, Storage and Loading Agreement
Concurrently with the closing of our initial public offering, we entered into a Fractionation, Storage and Loading Agreement with MarkWest Hydrocarbon that governs the parties' obligations with respect to the unloading and fractionation of NGLs, and the storage of the NGL products at our Siloam facility.
Services. Under the Fractionation, Storage and Loading Agreement, until 2012 and on a year-to-year basis thereafter, MarkWest Hydrocarbon has agreed to commit to deliver, at specified locations, all of the mixed NGLs produced at our Kenova, Boldman or Cobb processing plants for fractionation at our Siloam fractionation facility.
We have agreed to:
- •
- unload any NGLs that MarkWest Hydrocarbon delivers to our Siloam facility by railcar;
- •
- accept and fractionate into NGL products all of the NGLs that MarkWest Hydrocarbon delivers;
- •
- furnish and be responsible for all of the fuel needed in the operation of our Siloam facility;
- •
- operate, maintain and, if necessary, replace all facilities for loading the NGL products for shipment;
- •
- lease tracking rights on our Siloam railroad siding to MarkWest Hydrocarbon for no additional charge;
- •
- be, at our sole risk, responsible for loading the finished NGL products for shipments, as directed by MarkWest Hydrocarbon; and
- •
- at the direction of MarkWest, store the finished NGL products in underground storage caverns at our Siloam facility and, if also directed by MarkWest Hydrocarbon, withdraw the products from such storage caverns.
As compensation for providing our fractionating, loading and above ground storage services, MarkWest Hydrocarbon pays us a monthly fractionation fee based on the number of gallons delivered to us for fractionation. As compensation for our storage of the NGL products in underground storage caverns, MarkWest Hydrocarbon pays us an annual storage fee. And, as compensation for unloading any NGLs that MarkWest Hydrocarbon delivers to us by railcar, MarkWest Hydrocarbon pays us a monthly fee based on the number of gallons unloaded. A portion of each of the above fees is annually adjusted on January 1 of each year to reflect changes in the Producers Price Index for Oil and Gas Field Services. Under the agreement, MarkWest Hydrocarbon incurs all of the incidental losses incurred at our facilities, or the losses or gains due to variations in measurement equipment.
Indemnification Provisions. Under the Fractionation, Storage and Loading Agreement, MarkWest Hydrocarbon has agreed to indemnify us from any and all losses we incur arising from MarkWest Hydrocarbon facilities or its possession and control of the NGLs or NGL products (except to the extent caused by our gross negligence or willful conduct). MarkWest Hydrocarbon will be in possession and control of the NGLs until they are delivered to our Siloam facility, and of the NGL products after we load them into transportation facilities provided by MarkWest Hydrocarbon.
We have agreed to indemnify MarkWest Hydrocarbon from any and all losses incurred by MarkWest Hydrocarbon arising from our facilities or our possession and control of the NGLs or NGL products (except to the extent caused by MarkWest Hydrocarbon's gross negligence or willful conduct). We will be in possession and control of the NGLs after they are delivered to our Siloam facility and of the NGL products until we load them into transportation facilities provided by MarkWest Hydrocarbon.
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Natural Gas Liquids Purchase Agreement
Concurrently with the closing of our initial public offering, we entered into a Natural Gas Liquids Purchase Agreement with MarkWest Hydrocarbon that governs the parties' obligations with respect to the sale and purchase of NGL products we acquire under the Gas Processing (Maytown) Agreement between Equitable and MarkWest Hydrocarbon, which were assigned to us, as well as any other NGL products we acquire.
Purchase and Sale. Under the Natural Gas Liquids Purchase Agreement, until 2012, we have agreed to commit to deliver to MarkWest Hydrocarbon all of the NGL products produced from the NGLs we acquire under the Maytown Agreement together with such other NGLs to be sold at our facility. MarkWest Hydrocarbon has agreed to receive and purchase all of these NGL products.
As consideration for the sale of NGL products, MarkWest Hydrocarbon pays us a monthly fee equal to the Net Sales Price per gallon (determined under the Maytown Agreement), times the numbers of gallons of NGL products contained in our NGLs.
Indemnification Provisions. Under the Natural Gas Liquids Purchase Agreement, MarkWest Hydrocarbon has agreed to indemnify us from any and all losses we incur arising from MarkWest Hydrocarbon facilities or its possession and control of the NGL products (except to the extent caused by our gross negligence or willful misconduct). As between the parties, MarkWest Hydrocarbon will be in possession and control of the NGL products after they are delivered to MarkWest Hydrocarbon at the designated delivery point.
We have agreed to indemnify MarkWest Hydrocarbon from any and all losses incurred by MarkWest Hydrocarbon arising from our facilities or our possession and control of the NGL products (except to the extent caused by MarkWest Hydrocarbon's gross negligence or willful misconduct). As between the parties, we will be in possession and control of the NGL products until we deliver them to MarkWest Hydrocarbon at the designated delivery point.
Relationship of a Director of our General Partner with MarkWest Hydrocarbon
William P. Nicoletti, who serves as a member of our general partner's board of directors, is a member of the board of directors of Star Gas LLC, the general partner of Star Gas Partners, L.P., a retail propane and heating oil master limited partnership. Star Gas is a significant customer of MarkWest Hydrocarbon, and accounted for approximately 8% of its revenues for the year ended December 31, 2002.
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CONFLICTS OF INTEREST AND FIDUCIARY RESPONSIBILITIES
Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates (including MarkWest Hydrocarbon), on the one hand, and MarkWest Energy Partners, L.P., and our limited partners, on the other hand. The directors and officers of our general partner have fiduciary duties to manage our general partner in a manner beneficial to its owners. At the same time, our general partner has a fiduciary duty to manage MarkWest Energy Partners, L.P., in a manner beneficial to us and our unitholders. In addition, officers of our general partner and officers and key employees of MarkWest Hydrocarbon also own 10.3% of the membership interests in our general partner, a significant equity stake in MarkWest Hydrocarbon and will own 1.0% of the limited partner interests in us upon completion of this offering.
The partnership agreement contains provisions that allow our general partner to take into account the interests of parties in addition to our interests when resolving conflicts of interest. In effect, these provisions limit our general partner's fiduciary duties to the unitholders. The partnership agreement also restricts the remedies available to unitholders for actions taken that, without those limitations, might constitute breaches of fiduciary duty. Whenever a conflict arises between our general partner or its affiliates, on the one hand, and MarkWest Energy Partners, L.P. or any other partner, on the other, our general partner will resolve that conflict. At the request of our general partner, a conflicts committee of the board of directors of our general partner will review conflicts of interest. Our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or the unitholders if the resolution of the conflict is considered fair and reasonable to us. Any resolution is considered fair and reasonable to us if that resolution is:
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- approved by the conflicts committee, although no party is obligated to seek the approval of the Conflicts Committee and our general partner may adopt a resolution or course of action that has not received approval;
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- on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or
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- fair to us, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us.
Unless the resolution is specifically provided for in the partnership agreement, when resolving a conflict, our general partner may consider:
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- the relative interests of the parties involved in the conflict or affected by the action;
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- any customary or accepted industry practices or historical dealings with a particular person or entity; and
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- generally accepted accounting practices or principles and other factors it considers relevant, if applicable.
Conflicts of interest could arise in the situations described below, among others:
Actions taken by our general partner may affect the amount of cash available for distribution to unitholders or accelerate the right to convert subordinated units.
The amount of cash that is available for distribution to unitholders is affected by decisions of our general partner regarding such matters as:
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- amount and timing of asset purchases and sales;
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- cash expenditures;
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- borrowings;
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- issuance of additional units; and
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- the creation, reduction or increase of reserves in any quarter.
In addition, borrowings by us and our affiliates do not constitute a breach of any duty owed by our general partner to our unitholders, including borrowings that have the purpose or effect of:
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- enabling our general partner or its affiliates to receive distributions on any subordinated units held by them or the incentive distribution rights; or
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- hastening the expiration of the subordination period.
For example, in the event we have not generated sufficient cash from our operations to pay the minimum quarterly distribution on our common units and our subordinated units, the partnership agreement permits us to borrow funds, which would enable us to make this distribution on all outstanding units. Please read "Cash Distribution Policy—Subordination Period."
The partnership agreement provides that the Partnership and our subsidiaries may borrow funds from our general partner and its affiliates. Our general partner and its affiliates may not borrow funds from us, the operating company or the subsidiaries.
We do not have any officers or employees and rely solely on officers of our general partner and employees of MarkWest Hydrocarbon and its affiliates.
We do not have any officers or employees and rely solely on officers and employees of MarkWest Hydrocarbon and its affiliates. MarkWest Hydrocarbon and its affiliates conduct businesses and activities of their own in which we have no economic interest. If these separate activities are significantly greater than our activities, there could be material competition for the time and effort of the officers and employees who provide services to our general partner. The officers of our general partner are not required to work full time on our affairs. These officers are required to devote significant time to the affairs of MarkWest Hydrocarbon or its affiliates and are compensated by them for the services rendered to them.
We reimburse our general partner, MarkWest Hydrocarbon and its affiliates for expenses.
We reimburse our general partner, MarkWest Hydrocarbon and its affiliates for costs incurred in managing and operating us, including costs incurred in rendering corporate staff and support services to us. The partnership agreement provides that our general partner determines the expenses that are allocable to us in any reasonable manner determined by our general partner in its sole discretion. See "Certain Relationships and Related Transactions—Omnibus Agreement—Services."
Our general partner intends to limit its liability regarding our obligations.
Our general partner intends to limit its liability under contractual arrangements so that the other party has recourse only to our assets and not against our general partner or its assets or any affiliate of the general partner or its assets. The partnership agreement provides that any action taken by our general partner to limit its or our liability is not a breach of our general partner's fiduciary duties, even if we could have obtained terms that are more favorable without the limitation on liability.
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Common unitholders have no right to enforce obligations of our general partner and its affiliates under agreements with us.
Any agreements between us, on the one hand, and our general partner and its affiliates, on the other, will not grant to the unitholders, separate and apart from us, the right to enforce the obligations of our general partner and its affiliates in our favor.
Contracts between us, on the one hand, and our general partner and its affiliates, on the other, will not be the result of arm's-length negotiations.
The partnership agreement allows our general partner to pay itself or its affiliates for any services rendered, provided these services are rendered on terms that are fair and reasonable to us. Our general partner may also enter into additional contractual arrangements with any of its affiliates on our behalf. Neither the partnership agreement nor any of the other agreements, contracts and arrangements between us and our general partner and its affiliates are or will be the result of arm's-length negotiations. However, all of these transactions are to be on terms that are fair and reasonable to us.
Our general partner and its affiliates have no obligation to permit us to use any facilities or assets of our general partner and its affiliates, except as may be provided in contracts entered into specifically dealing with that use. There is no obligation of our general partner and its affiliates to enter into any contracts of this kind.
Common units are subject to our general partner's limited call right.
Our general partner may exercise its right to call and purchase common units as provided in the partnership agreement or assign this right to one of its affiliates or to us. Our general partner may use its own discretion, free of fiduciary duty restrictions, in determining whether to exercise this right. As a result, a common unitholder may have his common units purchased from him at an undesirable time or price. Please read "The Partnership Agreement—Limited Call Right."
We may not choose to retain separate counsel for ourselves or for the holders of common units.
The attorneys, independent accountants and others who perform services for us have been retained by our general partner. Attorneys, independent accountants and others who perform services for us are selected by our general partner or the conflicts committee and may perform services for our general partner and its affiliates. We may retain separate counsel for ourselves or the holders of common units in the event of a conflict of interest between our general partner and its affiliates, on the one hand, and us or the holders of common units, on the other, depending on the nature of the conflict. We do not intend to do so in most cases.
Our general partner's affiliates may compete with us.
The partnership agreement provides that our general partner is restricted from engaging in any business activities other than those incidental to its ownership of interests in us. Except as provided in the partnership agreement and the omnibus agreement, affiliates of our general partner are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us.
Fiduciary duties owed to unitholders by our general partner are prescribed by law and the partnership agreement.
Our general partner is accountable to us and our unitholders as a fiduciary. The Delaware Revised Uniform Limited Partnership Act, which we refer to in this prospectus as the Delaware Act, provides
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that Delaware limited partnerships may, in their partnership agreements, restrict or expand the fiduciary duties owed by our general partner to limited partners and the Partnership.
Our partnership agreement contains various provisions restricting the fiduciary duties that might otherwise be owed by our general partner. We have adopted these restrictions to allow our general partner to take into account the interests of other parties in addition to our interests when resolving conflicts of interest. We believe this is appropriate and necessary because our general partner's board of directors have fiduciary duties to manage our general partner in a manner beneficial both to its owners, MarkWest Hydrocarbon, as well as to you. Without these modifications, the general partner's ability to make decisions involving conflicts of interest would be restricted. The modifications to the fiduciary standards benefit the general partner by enabling it to take into consideration all parties involved in the proposed action, so long as the resolution is fair and reasonable to us as described above. These modifications also enable our general partner to attract and retain experienced and capable directors. These modifications represent a detriment to the common unitholders because they restrict the remedies available to unitholders for actions that, without those limitations, might constitute breaches of fiduciary duty, as described below. The following is a summary of the material restrictions of the fiduciary duties owed by our general partner to the limited partners:
State-law fiduciary duty standards | Fiduciary duties are generally considered to include an obligation to act with due care and loyalty. The duty of care, in the absence of a provision in a partnership agreement providing otherwise, would generally require a general partner to act for the Partnership in the same manner as a prudent person would act on his own behalf. The duty of loyalty, in the absence of a provision in a partnership agreement providing otherwise, would generally prohibit a general partner of a Delaware limited partnership from taking any action or engaging in any transaction where a conflict of interest is present. | |
Partnership agreement modified standards | Our partnership agreement contains provisions that waive or consent to conduct by our general partner and its affiliates that might otherwise raise issues as to compliance with fiduciary duties or applicable law. For example, our partnership agreement permits our general partner to make a number of decisions in its "sole discretion." This entitles our general partner to consider only the interests and factors that it desires and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Other provisions of the partnership agreement provide that our general partner's actions must be made in its reasonable discretion. These standards reduce the obligations to which our general partner would otherwise be held. | |
Our partnership agreement generally provides that affiliated transactions and resolutions of conflicts of interest not involving a required vote of unitholders must be "fair and reasonable" to us under the factors previously set forth. In determining whether a transaction or resolution is "fair and reasonable," our general partner may consider interests of all parties involved, including its own. Unless our general partner has acted in bad faith, the action taken by our general partner shall not constitute a breach of its fiduciary duty. These standards reduce the obligations to which our general partner would otherwise be held. | ||
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In addition to the other more specific provisions limiting the obligations of our general partner, our partnership agreement further provides that our general partner and its officers and directors will not be liable for monetary damages to us, the limited partners or assignees for errors of judgment or for any acts or omissions if our general partner and those other persons acted in good faith. | ||
Rights and Remedies of unitholders | The Delaware Act generally provides that a limited partner may institute legal action on behalf of the Partnership to recover damages from a third party where a general partner has refused to institute the action or where an effort to cause a general partner to do so is not likely to succeed. These actions could include actions against a general partner for breach of its fiduciary duties or of the partnership agreement. In addition, the statutory or case law of some jurisdictions may permit a limited partner to institute legal action on behalf of himself and all other similarly situated limited partners to recover damages from a general partner for violations of its fiduciary duties to the limited partners. |
In order to become one of our limited partners, a common unitholder is required to agree to be bound by the provisions in the partnership agreement, including the provisions discussed above. This is in accordance with the policy of the Delaware Act favoring the principle of freedom of contract and the enforceability of partnership agreements. The failure of a limited partner or assignee to sign a partnership agreement does not render the partnership agreement unenforceable against that person.
We must indemnify our general partner and its officers, directors, employees, affiliates, partners, members, agents and trustees, to the fullest extent permitted by law, against liabilities, costs and expenses incurred by our general partner or these other persons. We must provide this indemnification if our general partner or these persons acted in good faith and in a manner they reasonably believed to be in, or (in the case of a person other than our general partner) not opposed to, our best interests. We also must provide this indemnification for criminal proceedings if our general partner or these other persons had no reasonable cause to believe their conduct was unlawful. Thus, our general partner could be indemnified for its negligent acts if it met these requirements concerning good faith and our best interests. To the extent that these provisions purport to include indemnification for liabilities arising under the Securities Act, in the opinion of the Securities and Exchange Commission, such indemnification is contrary to public policy and therefore unenforceable. If you have questions regarding the fiduciary duties of our general partner, you should consult with your own counsel. Please read "The Partnership Agreement—Indemnification."
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DESCRIPTION OF THE COMMON UNITS
The common units and the subordinated units represent limited partner interests in us. The holders of units are entitled to participate in partnership distributions and exercise the rights or privileges available to limited partners under our partnership agreement. For a description of the relative rights and preferences of holders of common units and subordinated units in and to partnership distributions, please read "Cash Distribution Policy" and "Description of the Subordinated Units." For a description of the rights and privileges of limited partners under our partnership agreement, including voting rights, please read "The Partnership Agreement."
Duties
Computershare Trust Company, Inc. serves as registrar and transfer agent for the common units. We pay all fees charged by the transfer agent for transfers of common units, except the following that must be paid by unitholders:
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- surety bond premiums to replace lost or stolen certificates, taxes and other governmental charges;
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- special charges for services requested by a holder of a common unit; and
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- other similar fees or charges.
There is no charge to unitholders for disbursements of our cash distributions. We will indemnify the transfer agent, its agents and each of their stockholders, directors, officers and employees against all claims and losses that may arise out of acts performed or omitted for its activities in that capacity, except for any liability due to any gross negligence or intentional misconduct of the indemnified person or entity.
Resignation or Removal
The transfer agent may resign, by notice to us, or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If no successor has been appointed and accepted the appointment within 30 days after notice of the resignation or removal, our general partner may act as the transfer agent and registrar until a successor is appointed.
The transfer of the common units to persons that purchase directly from the underwriters will be accomplished through the completion, execution and delivery of a transfer application by the investor. Any later transfers of a common unit will not be recorded by the transfer agent or recognized by us unless the transferee executes and delivers a transfer application. By executing and delivering a transfer application, the transferee of common units:
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- becomes the record holder of the common units and is an assignee until admitted into our partnership as a substituted limited partner;
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- automatically requests admission as a substituted limited partner in our partnership;
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- agrees to be bound by the terms and conditions of, and executes, our partnership agreement;
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- represents that the transferee has the capacity, power and authority to enter into the partnership agreement;
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- grants powers of attorney to officers of our general partner and any liquidator of us as specified in the partnership agreement; and
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- makes the consents and waivers contained in the partnership agreement.
An assignee will become a substituted limited partner of our partnership for the transferred common units upon the consent of our general partner and the recording of the name of the assignee on our books and records. Our general partner may withhold its consent in its sole discretion.
A transferee's broker, agent or nominee may complete, execute and deliver a transfer application. We are entitled to treat the nominee holder of a common unit as the absolute owner. In that case, the beneficial holder's rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.
Common units are securities and are transferable according to the laws governing transfer of securities. In addition to other rights acquired upon transfer, the transferor gives the transferee the right to request admission as a substituted limited partner in our partnership for the transferred common units. A purchaser or transferee of common units who does not execute and deliver a transfer application obtains only:
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- the right to assign the common unit to a purchaser or other transferee; and
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- the right to transfer the right to seek admission as a substituted limited partner in our partnership for the transferred common units.
Thus, a purchaser or transferee of common units who does not execute and deliver a transfer application:
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- will not receive cash distributions or federal income tax allocations, unless the common units are held in a nominee or "street name" account and the nominee or broker has executed and delivered a transfer application; and
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- may not receive some federal income tax information or reports furnished to record holders of common units.
The transferor of common units has a duty to provide the transferee with all information that may be necessary to transfer the common units. The transferor does not have a duty to insure the execution of the transfer application by the transferee and has no liability or responsibility if the transferee neglects or chooses not to execute and forward the transfer application to the transfer agent. Please read "The Partnership Agreement—Status as Limited Partner or Assignee."
Until a common unit has been transferred on our books, we and the transfer agent may treat the record holder of the unit as the absolute owner for all purposes, except as otherwise required by law or applicable stock exchange regulations.
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The following is a summary of the material provisions of our partnership agreement. Our partnership agreement and the limited liability company agreement governing our operating company are included as exhibits to the registration statement of which this prospectus constitutes a part. We will provide prospective investors with a copy of these agreements upon request at no charge.
We summarize the following provisions of the partnership agreement elsewhere in this prospectus:
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- with regard to distributions of available cash, please read "Cash Distribution Policy."
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- with regard to the transfer of common units, please read "Description of the Common Units—Transfer of Common Units."
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- with regard to allocations of taxable income and taxable loss, please read "Material Tax Consequences."
We were organized on January 25, 2002 and will have a perpetual existence.
Our purpose under the partnership agreement is limited to serving as a member of the operating company and engaging in any business activities that may be engaged in by the operating company or that are approved by our general partner. All of our operations are conducted through our operating company, MarkWest Energy Operating Company, L.L.C., and its subsidiaries. We own 100% of the outstanding membership interest of the operating company. The limited liability company agreement of the operating company provides that the operating company may, directly or indirectly, engage in:
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- its operations as conducted immediately before our initial public offering;
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- any other activity approved by our general partner but only to the extent that our general partner reasonably determines that, as of the date of the acquisition or commencement of the activity, the activity generates "qualifying income" as this term is defined in Section 7704 of the Internal Revenue Code; or
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- any activity that enhances the operations of an activity that is described in either of the two preceding clauses or any other activity provided such activity does not affect our treatment as a partnership for Federal income tax purposes.
Our general partner is authorized in general to perform all acts deemed necessary to carry out our purposes and to conduct our business.
Each limited partner, and each person who acquires a unit from a unitholder and executes and delivers a transfer application, grants to our general partner and, if appointed, a liquidator, a power of attorney to, among other things, execute and file documents required for our qualification, continuance or dissolution. The power of attorney also grants our general partner the authority to amend, and to make consents and waivers under, the partnership agreement.
Unitholders are not obligated to make additional capital contributions, except as described below under "—Limited Liability."
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Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Act and that he otherwise acts in conformity with the provisions of the partnership agreement, his liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital he is obligated to contribute to us for his common units plus his share of any undistributed profits and assets. If it were determined, however, that the right, or exercise of the right, by the limited partners as a group:
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- to remove or replace our general partner;
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- to approve some amendments to the partnership agreement; or
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- to take other action under the partnership agreement;
constituted "participation in the control" of our business for the purposes of the Delaware Act, then the limited partners could be held personally liable for our obligations under the laws of Delaware, to the same extent as our general partner. This liability would extend to persons who transact business with us who reasonably believe that the limited partner is a general partner. Neither the partnership agreement nor the Delaware Act specifically provides for legal recourse against our general partner if a limited partner were to lose limited liability through any fault of our general partner. While this does not mean that a limited partner could not seek legal recourse, we know of no precedent for this type of a claim in Delaware case law.
Under the Delaware Act, a limited partnership may not make a distribution to a partner if, after the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specific property of the Partnership, would exceed the fair value of the assets of the limited partnership. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distribution for three years. Under the Delaware Act, an assignee who becomes a substituted limited partner of a limited partnership is liable for the obligations of his assignor to make contributions to the Partnership, except the assignee is not obligated for liabilities unknown to him at the time he became a limited partner and that could not be ascertained from the partnership agreement.
Our subsidiaries conduct business in nine states. Maintenance of our limited liability as a member of the operating company may require compliance with legal requirements in the jurisdictions in which the operating company conducts business, including qualifying our subsidiaries to do business there. Limitations on the liability of members for the obligations of a limited liability company have not been clearly established in many jurisdictions. If, by virtue of our membership interest in the operating company or otherwise, it were determined that we were conducting business in any state without compliance with the applicable limited partnership or limited liability company statute, or that the right or exercise of the right by the limited partners as a group to remove or replace our general partner, to approve some amendments to the partnership agreement, or to take other action under the partnership agreement constituted "participation in the control" of our business for purposes of the statutes of any relevant jurisdiction, then the limited partners could be held personally liable for our obligations under the law of that jurisdiction to the same extent as our general partner under the circumstances. We will operate in a manner that our general partner considers reasonable and necessary or appropriate to preserve the limited liability of the limited partners.
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The following matters require the unitholder vote specified below. Matters requiring the approval of a "unit majority" require:
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- during the subordination period, the approval of a majority of the common units, excluding those common units held by our general partner and its affiliates, and a majority of the subordinated units, voting as separate classes; and
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- after the subordination period, the approval of a majority of the common units.
Issuance of additional common units or units of equal rank with the common units during the subordination period | Unit majority, with certain exceptions described under "—Issuance of Additional Securities." | |
Issuance of units senior to the common units during the subordination period | Unit majority. | |
Issuance of units junior to the common units during the subordination period | No approval right. | |
Issuance of additional units after the subordination period | No approval rights. | |
Amendment of the partnership agreement | Certain amendments may be made by the general partner without the approval of the unitholders. Other amendments generally require the approval of a unit majority. See "—Amendment of the Partnership Agreement." | |
Merger of our partnership or the sale of all or substantially all of our assets | Unit majority. See "—Merger, Sale or Other Disposition of Assets." | |
Amendment of the limited liability company agreement and other action taken by us as sole member of the operating company | Unit majority if such amendment or other action would adversely affect our limited partners (or any particular class of limited partners) in any material respect. See "—Action Relating to the Operating Company." | |
Dissolution of our partnership | Unit majority. See "—Termination and Dissolution." | |
Reconstitution of our partnership upon dissolution | Unit majority. See "—Termination and Dissolution." | |
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Withdrawal of the general partner | Under most circumstances, the approval of a majority of the common units, excluding common units held by the general partner and its affiliates, is required for the withdrawal of the general partner prior to June 30, 2012 in a manner which would cause a dissolution of our partnership. See "—Withdrawal or Removal of our General Partner." | |
Removal of the general partner | Not less than 662/3% of the outstanding units, voting as a single class, including units held by our general partner and its affiliates. See "—Withdrawal or Removal of our General Partner." | |
Transfer of the general partner interest | Our general partner may transfer all, but not less than all, of its general partner interest in us without a vote of our unitholders to an affiliate or another person in connection with its merger or consolidation with or into, or sale of all or substantially all of its assets to such person. The approval of a majority of the common units, excluding common units held by the general partner and its affiliates, is required in other circumstances for a transfer of the general partner interest to a third party prior to June 30, 2012. See "—Transfer of General Partner Interests." | |
Transfer of incentive distribution rights | Except for transfers to an affiliate or another person as part of the general partner's merger or consolidation with or into, or sale of all or substantially all of its assets to or sale of all or substantially all its equity interests to such person, the approval of a majority of the common units, excluding common units held by our general partner and its affiliates, voting separately as a class, is required in most circumstances for a transfer of the incentive distribution rights to a third party prior to June 30, 2012. See "—Transfer of Incentive Distribution Rights." | |
Transfer of ownership interests in the general partner | No approval required at any time. See "—Transfer of Ownership Interests in the General Partner." |
Issuance of Additional Securities
The partnership agreement authorizes us to issue an unlimited number of additional partnership securities and rights to buy partnership securities for the consideration and on the terms and conditions established by our general partner in its sole discretion without the approval of the unitholders. During the subordination period, however, except as we discuss in the following paragraph, we may not issue equity securities ranking senior to the common units or an aggregate of more than 1,207,500 additional
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common units or units on a parity with the common units, in each case, without the approval of the holders of a majority of the outstanding common units and subordinated units, voting as separate classes.
During or after the subordination period, we may issue an unlimited number of common units without the approval of the unitholders as follows:
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- upon exercise of an underwriters' over-allotment option;
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- upon conversion of the subordinated units;
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- under employee benefit plans;
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- upon conversion of the general partner interest and incentive distribution rights as a result of a withdrawal of our general partner;
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- in the event of a combination or subdivision of common units;
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- in connection with an acquisition or a capital improvement that increases cash flow from operations per unit on a pro forma basis; or
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- if the proceeds of the issuance are used exclusively to repay indebtedness the cost of which to service is greater than the distribution obligations associated with the units issued in connection with its retirement.
It is possible that we will fund acquisitions through the issuance of additional common units or other equity securities. Holders of any additional common units we issue will be entitled to share equally with the then-existing holders of common units in our distributions of available cash. In addition, the issuance of additional partnership interests may dilute the value of the interests of the then-existing holders of common units in our net assets.
In accordance with Delaware law and the provisions of our partnership agreement, we may also issue additional partnership securities interests that, in the sole discretion of our general partner, have special voting rights to which the common units are not entitled.
Upon issuance of additional partnership securities, our general partner will be required to make additional capital contributions to the extent necessary to maintain its 2% general partner interest in us. Moreover, our general partner will have the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase common units, subordinated units or other equity securities whenever, and on the same terms that, we issue those securities to persons other than our general partner and its affiliates, to the extent necessary to maintain its percentage interest, including its interest represented by common units and subordinated units, that existed immediately prior to each issuance. The holders of common units will not have preemptive rights to acquire additional common units or other partnership securities.
Amendment of the Partnership Agreement
General. Amendments to the partnership agreement may be proposed only by or with the consent of our general partner, which consent may be given or withheld in its sole discretion, except as discussed below. In order to adopt a proposed amendment, other than the amendments discussed below, our general partner must seek written approval of the holders of the number of units required to approve the amendment or call a meeting of the limited partners to consider and vote upon the proposed amendment. Except as we describe below, an amendment must be approved by a unit majority.
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Prohibited Amendments. No amendment may be made that would:
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- enlarge the obligations of any limited partner without its consent, unless approved by at least a majority of the type or class of limited partner interests so affected;
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- enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by us to our general partner or any of its affiliates without the consent of our general partner, which may be given or withheld in its sole discretion;
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- change the term of our partnership;
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- provide that our partnership is not dissolved upon an election to dissolve our partnership by our general partner that is approved by a unit majority; or
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- give any person the right to dissolve our partnership other than our general partner's right to dissolve our partnership with the approval of a unit majority.
The provision of the partnership agreement preventing the amendments having the effects described in any of the clauses above can be amended upon the approval of the holders of at least 90% of the outstanding units voting together as a single class.
No Unitholder Approval. Our general partner may generally make amendments to the partnership agreement without the approval of any limited partner or assignee to reflect:
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- a change in our name, the location of our principal place of business, our registered agent or our registered office;
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- the admission, substitution, withdrawal, or removal of partners in accordance with the partnership agreement;
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- a change that, in the sole discretion of our general partner, is necessary or advisable for us to qualify or to continue our qualification as a limited partnership or a partnership in which the limited partners have limited liability under the laws of any state or to ensure that neither we, the operating company nor its subsidiaries will be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes;
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- an amendment that is necessary, in the opinion of our counsel, to prevent us or our general partner or its directors, officers, agents, or trustees from in any manner being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisors Act of 1940, or plan asset regulations adopted under the Employee Retirement Income Security Act of 1974, whether or not substantially similar to plan asset regulations currently applied or proposed;
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- subject to the limitations on the issuance of additional partnership securities described above, an amendment that in the discretion of our general partner is necessary or advisable for the authorization of additional partnership securities or rights to acquire partnership securities;
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- any amendment expressly permitted in the partnership agreement to be made by our general partner acting alone;
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- an amendment effected, necessitated or contemplated by a merger agreement that has been approved under the terms of the partnership agreement;
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- any amendment that, in the discretion of our general partner, is necessary or advisable for the formation by us of, or our investment in, any corporation, partnership or other entity, as otherwise permitted by the partnership agreement;
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- a change in our fiscal year or taxable year and related changes; or
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- •
- any other amendments substantially similar to any of the matters described in the clauses above.
In addition, our general partner may make amendments to the partnership agreement without the approval of any limited partner or assignee if those amendments, in the discretion of our general partner:
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- do not adversely affect the limited partners (or any particular class of limited partners) in any material respect;
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- are necessary or advisable to satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute;
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- are necessary or advisable to facilitate the trading of limited partner interests or to comply with any rule, regulation, guideline or requirement of any securities exchange on which the limited partner interests are or will be listed for trading, compliance with any of which our general partner deems to be in our best interest and the best interest of the limited partners;
- •
- are necessary or advisable for any action taken by our general partner relating to splits or combinations of units under the provisions of the partnership agreement; or
- •
- are required to effect the intent expressed in this prospectus or the intent of the provisions of the partnership agreement or are otherwise contemplated by the partnership agreement.
Opinion of Counsel and Unitholder Approval. Our general partner will not be required to obtain an opinion of counsel that an amendment will not result in a loss of limited liability to the limited partners or result in our being treated as an entity for federal income tax purposes if one of the amendments described above under "—No Unitholder Approval" should occur. No other amendments to the partnership agreement will become effective without the approval of holders of at least 90% of the units unless we obtain an opinion of counsel to the effect that the amendment will not affect the limited liability under applicable law of any of our limited partners or cause us, the operating company or its subsidiaries to be taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not previously taxed as such).
Any amendment that would have a material adverse effect on the rights or preferences of any type or class of outstanding units in relation to other classes of units will require the approval of at least a majority of the type or class of units so affected. Any amendment that reduces the voting percentage required to take any action must be approved by the affirmative vote of limited partners constituting not less than the voting requirement sought to be reduced.
Action Relating to the Operating Company
Without the approval of the holders of units representing a unit majority, our general partner is prohibited from consenting on our behalf, as the sole member of the operating company, to any amendment to the limited liability company agreement of the operating company or taking any action on our behalf permitted to be taken by a member of the operating company in each case that would adversely affect our limited partners (or any particular class of limited partners) in any material respect.
Merger, Sale or Other Disposition of Assets
The partnership agreement generally prohibits our general partner, without the prior approval of the holders of units representing a unit majority, from causing us to, among other things, sell, exchange or otherwise dispose of all or substantially all of our assets in a single transaction or a series of related transactions, including by way of merger, consolidation or other combination, or approving on our behalf the sale, exchange or other disposition of all or substantially all of the assets of our subsidiaries as a whole. Our general partner may, however, mortgage, pledge, hypothecate or grant a security
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interest in all or substantially all of our assets without that approval. Our general partner may also sell all or substantially all of our assets under a foreclosure or other realization upon those encumbrances without that approval.
If conditions specified in the partnership agreement are satisfied, our general partner may merge us or any of our subsidiaries into, or convey some or all of our assets to, a newly formed entity if the sole purpose of that merger or conveyance is to change our legal form into another limited liability entity. The unitholders are not entitled to dissenters' rights of appraisal under the partnership agreement or applicable Delaware law in the event of a merger or consolidation, a sale of substantially all of our assets or any other transaction or event for such purpose.
We will continue as a limited partnership until terminated under the partnership agreement. We will dissolve upon:
- •
- the election of our general partner to dissolve us, if approved by the holders of units representing a unit majority;
- •
- the sale, exchange or other disposition of all or substantially all of our assets and properties and our subsidiaries;
- •
- the entry of a decree of judicial dissolution of the Partnership; or
- •
- the withdrawal or removal of our general partner or any other event that results in its ceasing to be our general partner other than by reason of a transfer of its general partner interest in accordance with the partnership agreement or withdrawal or removal of the general partner following approval and admission of a successor.
Upon a dissolution under the last clause, the holders of a majority of the outstanding common units and subordinated units, voting as separate classes, may also elect, within specific time limitations, to reconstitute us and continue our business on the same terms and conditions described in the partnership agreement by forming a new limited partnership on terms identical to those in the partnership agreement and having as general partner an entity approved by the holders of a majority of the outstanding common units and subordinated units, voting as separate classes, subject to our receipt of an opinion of counsel to the effect that:
- •
- the action would not result in the loss of limited liability of any limited partner; and
- •
- neither we, the reconstituted limited partnership nor the operating company would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of that right to continue.
Liquidation and Distribution of Proceeds
Upon our dissolution, unless we are reconstituted and continued as a new limited partnership, the liquidator authorized to wind up our affairs will, acting with all of the powers of our general partner that the liquidator deems necessary or desirable in its judgment, liquidate our assets and apply the proceeds of the liquidation as provided in "Cash Distribution Policy—Distributions of Cash upon Liquidation." The liquidator may defer liquidation of our assets for a reasonable period or distribute assets to partners in kind if it determines that a sale would be impractical or would cause undue loss to the partners.
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Withdrawal or Removal of our General Partner
Except as described below, our general partner has agreed not to withdraw voluntarily as our general partner prior to June 30, 2012 without obtaining the approval of the holders of at least a majority of the outstanding common units, excluding common units held by our general partner and its affiliates, and furnishing an opinion of counsel regarding limited liability and tax matters. On or after June 30, 2012, our general partner may withdraw as general partner without first obtaining approval of any unitholder by giving 90 days' written notice, and that withdrawal will not constitute a violation of the partnership agreement. Notwithstanding the foregoing, our general partner may withdraw without unitholder approval upon 90 days' notice to the limited partners if at least 50% of the outstanding common units are held or controlled by one person and its affiliates other than our general partner and its affiliates. In addition, the partnership agreement permits our general partner in some instances to sell or otherwise transfer all of its general partner interest in us without the approval of the unitholders. Please read "—Transfer of General Partner Interests."
Upon the withdrawal of our general partner under any circumstances, other than as a result of a transfer by our general partner of all or a part of its general partner interest in us, the holders of a majority of the outstanding common units and subordinated units, voting as separate classes, may select a successor to that withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, we will be dissolved, wound up and liquidated, unless within 180 days after that withdrawal, the holders of a majority of the outstanding common units and subordinated units, voting as separate classes, agree in writing to continue our business and to appoint a successor general partner. Please read "—Termination and Dissolution."
Our general partner may not be removed unless that removal is approved by the vote of the holders of not less than 662/3% of the outstanding units, including units held by our general partner and its affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of our general partner is also subject to the approval of a successor general partner by the vote of the holders of a majority of the outstanding common units and subordinated units, voting as separate classes. The ownership of more than 331/3% of the outstanding units by our general partner and its affiliates would give it the practical ability to prevent its removal. At the closing of this offering, affiliates of our general partner will own 36.2% of the outstanding units.
The partnership agreement also provides that if our general partner is removed under circumstances where cause does not exist and units held by our general partner and its affiliates are not voted in favor of that removal:
- •
- the subordination period will end and all outstanding subordinated units will immediately convert into common units on a one-for-one basis;
- •
- any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and
- •
- our general partner will have the right to convert its general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests based on the fair market value of those interests at the time.
In the event of removal of a general partner under circumstances where cause exists or withdrawal of a general partner where that withdrawal violates the partnership agreement, a successor general partner will have the option to purchase the general partner interest and incentive distribution rights of the departing general partner for a cash payment equal to the fair market value of those interests. Under all other circumstances where our general partner withdraws or is removed by the limited partners, the departing general partner will have the option to require the successor general partner to purchase the general partner interest of the departing general partner and its incentive distribution
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rights for the fair market value. In each case, this fair market value will be determined by agreement between the departing general partner and the successor general partner. If no agreement is reached, an independent investment banking firm or other independent expert selected by the departing general partner and the successor general partner will determine the fair market value. Or, if the departing general partner and the successor general partner cannot agree upon an expert, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value.
If the option described above is not exercised by either the departing general partner or the successor general partner, the departing general partner's general partner interest and its incentive distribution rights will automatically convert into common units equal to the fair market value of those interests as determined by an investment banking firm or other independent expert selected in the manner described in the preceding paragraph.
In addition, we will be required to reimburse the departing general partner for all amounts due the departing general partner, including, without limitation, all employee-related liabilities, including severance liabilities, incurred for the termination of any employees employed by the departing general partner or its affiliates for our benefit.
Transfer of General Partner Interests
Except for transfer by our general partner of all, but not less than all, of its general partner interest in us to:
- •
- an affiliate of our general partner (other than an individual); or
- •
- another entity as part of the merger or consolidation of our general partner with or into another entity or the transfer by our general partner of all or substantially all of its assets to another entity,
our general partner may not transfer all or any part of its general partner interest in us to another person prior to June 30, 2012 without the approval of the holders of at least a majority of the outstanding common units, excluding common units held by our general partner and its affiliates. As a condition of this transfer, the transferee must, among other things, assume the rights and duties of our general partner, agree to be bound by the provisions of the partnership agreement and furnish an opinion of counsel regarding limited liability and tax matters.
Our general partner and its affiliates may at any time transfer units to one or more persons, without unitholder approval, except that they may not transfer subordinated units to us.
Transfer of Ownership Interests in General Partner
At any time, the members of our general partner may sell or transfer all or part of their membership interests in our general partner without the approval of the unitholders.
Transfer of Incentive Distribution Rights
Our general partner or its affiliates or a subsequent holder of the incentive distribution rights may transfer its incentive distribution rights to an affiliate or another person as part of its merger or consolidation with or into, or sale of all or substantially all of its assets to, or a sale of all or substantially all of its equity interests to, that person without the prior approval of the unitholders; but, in each case, the transferee must agree to be bound by the provisions of the partnership agreement. Prior to June 30, 2012, other transfers of the incentive distribution rights will require the affirmative vote of holders of a majority of the outstanding common units, excluding common units held by the general partner and its affiliates. On or after June 30, 2012, the incentive distribution rights will be freely transferable.
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Change of Management Provisions
The partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to remove MarkWest Energy GP, L.L.C. as our general partner or otherwise change management. If any person or group other than our general partner and its affiliates acquires beneficial ownership of 20% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to any person or group that acquires the units from our general partner or its affiliates and any transferees of that person or group approved by our general partner or to any person or group who acquires the units with the prior approval of the board of directors.
The partnership agreement also provides that if our general partner is removed under circumstances where cause does not exist and units held by our general partner and its affiliates are not voted in favor of that removal:
- •
- the subordination period will end and all outstanding subordinated units will immediately convert into common units on a one-for-one basis;
- •
- any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and
- •
- our general partner will have the right to convert its general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests.
If at any time our general partner and its affiliates hold more than 80% of the then-issued and outstanding partnership securities of any class, our general partner will have the right, which it may assign in whole or in part to any of its affiliates or to us, to acquire all, but not less than all, of the remaining partnership securities of the class held by unaffiliated persons as of a record date to be selected by our general partner, on at least ten but not more than 60 days notice. The purchase price in the event of this purchase is the greater of:
- •
- the highest cash price paid by either of our general partner or any of its affiliates for any partnership securities of the class purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those partnership securities; and
- •
- the current market price as of the date three days before the date the notice is mailed.
As a result of our general partner's right to purchase outstanding partnership securities, a holder of partnership securities may have his partnership securities purchased at an undesirable time or price. The tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his common units in the market. Please read "Material Tax Consequences—Disposition of Common Units."
Except as described below regarding a person or group owning 20% or more of any class of units then outstanding, unitholders or assignees who are record holders of units on the record date will be entitled to notice of, and to vote at, meetings of our limited partners and to act upon matters for which approvals may be solicited. Common units that are owned by an assignee who is a record holder, but who has not yet been admitted as a limited partner, will be voted by our general partner at the written direction of the record holder. Absent direction of this kind, the common units will not be voted, except that, in the case of common units held by our general partner on behalf of non-citizen assignees, our general partner will distribute the votes on those common units in the same ratios as the votes of limited partners on other units are cast.
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Our general partner does not anticipate that any meeting of unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by the unitholders may be taken either at a meeting of the unitholders or without a meeting if consents in writing describing the action so taken are signed by holders of the number of units necessary to authorize or take that action at a meeting. Meetings of the unitholders may be called by our general partner or by unitholders owning at least 20% of the outstanding units of the class for which a meeting is proposed. Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding units of the class or classes for which a meeting has been called, represented in person or by proxy, will constitute a quorum unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum will be the greater percentage.
Each record holder of a unit has a vote according to his percentage interest in us, although additional limited partner interests having special voting rights could be issued. Please read "—Issuance of Additional Securities." However, if at any time any person or group, other than our general partner and its affiliates, or a direct or subsequently approved transferee of our general partner or its affiliates, acquires, in the aggregate, beneficial ownership of 20% or more of any class of units then outstanding, that person or group will lose voting rights on all of its units and the units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum or for other similar purposes. Common units held in nominee or street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and his nominee provides otherwise. Except as the partnership agreement otherwise provides, subordinated units will vote together with common units as a single class.
Any notice, demand, request, report or proxy material required or permitted to be given or made to record holders of common units under the partnership agreement will be delivered to the record holder by us or by the transfer agent.
Status as Limited Partner or Assignee
Except as described under "—Limited Liability," the common units will be fully paid, and unitholders will not be required to make additional contributions.
An assignee of a common unit, after executing and delivering a transfer application, but pending its admission as a substituted limited partner, is entitled to an interest equivalent to that of a limited partner for the right to share in allocations and distributions from us, including liquidating distributions. Our general partner will vote and exercise other powers attributable to common units owned by an assignee that has not become a substitute limited partner at the written direction of the assignee. See "—Meetings; Voting." Transferees that do not execute and deliver a transfer application will not be treated as assignees nor as record holders of common units, and will not receive cash distributions, federal income tax allocations or reports furnished to holders of common units. Please read "Description of the Common Units—Transfer of Common Units."
Non-citizen Assignees; Redemption
If we are or become subject to federal, state or local laws or regulations that, in the reasonable determination of our general partner, create a substantial risk of cancellation or forfeiture of any property that we have an interest in because of the nationality, citizenship or other related status of any limited partner or assignee, we may redeem the units held by the limited partner or assignee at their current market price. In order to avoid any cancellation or forfeiture, our general partner may require each limited partner or assignee to furnish information about his nationality, citizenship or related status. If a limited partner or assignee fails to furnish information about his nationality, citizenship or other related status within 30 days after a request for the information or our general partner
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determines after receipt of the information that the limited partner or assignee is not an eligible citizen, the limited partner or assignee may be treated as a non-citizen assignee. In addition to other limitations on the rights of an assignee that is not a substituted limited partner, a non-citizen assignee does not have the right to direct the voting of his units and may not receive distributions in kind upon our liquidation.
Under the partnership agreement, in most circumstances, we will indemnify the following persons, to the fullest extent permitted by law, from and against all losses, claims, damages or similar events:
- •
- our general partner;
- •
- any departing general partner;
- •
- any person who is or was an affiliate of a general partner or any departing general partner;
- •
- any person who is or was a member, partner, officer, director, employee, agent or trustee of our general partner or any departing general partner or any affiliate of a general partner or any departing general partner; or
- •
- any person who is or was serving at the request of a general partner or any departing general partner or any affiliate of a general partner or any departing general partner as an officer, director, employee, member, partner, agent or trustee of another person.
Any indemnification under these provisions will only be out of our assets. Our general partner and its affiliates will not be personally liable for, or have any obligation to contribute or loan funds or assets to us to enable us to effectuate, indemnification. We may purchase insurance against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under the partnership agreement.
Our general partner is required to keep appropriate books of our business at our principal offices. The books will be maintained for both tax and financial reporting purposes on an accrual basis. For tax and fiscal reporting purposes, our fiscal year is the calendar year.
We will furnish or make available to record holders of common units, within 120 days after the close of each fiscal year, an annual report containing audited financial statements and a report on those financial statements by our independent public accountants. Except for our fourth quarter, we will also furnish or make available summary financial information within 90 days after the close of each quarter.
We will furnish each record holder of a unit with information reasonably required for tax reporting purposes within 90 days after the close of each calendar year. This information is expected to be furnished in summary form so that some complex calculations normally required of partners can be avoided. Our ability to furnish this summary information to unitholders will depend on the cooperation of unitholders in supplying us with specific information. Every unitholder will receive information to assist him in determining his federal and state tax liability and filing his federal and state income tax returns, regardless of whether he supplies us with information.
Right to Inspect our Books and Records
The partnership agreement provides that a limited partner can, for a purpose reasonably related to his interest as a limited partner, upon reasonable demand and at his own expense, have furnished to him:
- •
- a current list of the name and last known address of each partner;
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- •
- a copy of our tax returns;
- •
- information as to the amount of cash, and a description and statement of the agreed value of any other property or services, contributed or to be contributed by each partner and the date on which each became a partner;
- •
- copies of the partnership agreement, the certificate of limited partnership of the Partnership, related amendments and powers of attorney under which they have been executed;
- •
- information regarding the status of our business and financial condition; and
- •
- any other information regarding our affairs as is just and reasonable.
Our general partner may, and intends to, keep confidential from the limited partners trade secrets or other information the disclosure of which our general partner believes in good faith is not in our best interests or which we are required by law or by agreements with third parties to keep confidential.
Under the partnership agreement, we have agreed to register for resale under the Securities Act of 1933 and applicable state securities laws any common units, subordinated units or other partnership securities proposed to be sold by our general partner or any of its affiliates (including MarkWest Hydrocarbon, its officers and the officers, directors and owners of our general partner) or their assignees if an exemption from the registration requirements is not otherwise available. These registration rights continue for two years following any withdrawal or removal of MarkWest Energy GP, L.L.C. as our general partner. We are obligated to pay all expenses incidental to the registration, excluding underwriting discounts and commissions. Please read "Units Eligible for Future Sale."
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UNITS ELIGIBLE FOR FUTURE SALE
Affiliates of our general partner hold 2,500,000 subordinated units. All of the subordinated units will convert into common units at the end of the subordination period and some may convert earlier. The sale of these units could have an adverse impact on the price of the common units or on any trading market that may develop. Upon conversion, these units will be entitled to registration rights as described under "Certain Relationships and Related Transactions" or freely transferable without restriction or further registration under the Securities Act of 1933, subject to the affiliate restrictions described below.
The common units sold in the offering will generally be freely transferable without restriction or further registration under the Securities Act of 1933, except that any resale of common units purchased by an "affiliate" of our Partnership will be subject to the volume limitations contained in Rule 144 of the Securities Act.
While any subordinated units remain outstanding, we may not issue equity securities of the Partnership ranking prior or senior to the common units or an aggregate of more than 1,207,500 additional common units or an equivalent amount of securities ranking on a parity with the common units, without the approval of the holders of a majority of the outstanding common units and subordinated units, voting as separate classes, subject to certain exceptions described under "The Partnership Agreement—Issuance of Additional Securities."
The partnership agreement provides that, once no subordinated units remain outstanding, we may issue an unlimited number of limited partner interests of any type without a vote of the unitholders. The partnership agreement does not restrict our ability to issue equity securities ranking junior to the common units at any time. Any issuance of additional common units or other equity securities would result in a corresponding decrease in the proportionate ownership interest in us represented by, and could adversely affect the cash distributions to and market price of, common units then outstanding. Please read "The Partnership Agreement—Issuance of Additional Securities."
Under the partnership agreement, our general partner and its affiliates have the right to cause us to register under the Securities Act of 1933 and state laws the offer and sale of any units that they hold.
Subject to the terms and conditions of the partnership agreement, these registration rights allow our general partner and its affiliates or their assignees holding any units to require registration of any of these units and to include any of these units in a registration by us of other units, including units offered by us or by any unitholder. Our general partner will continue to have these registration rights for two years following its withdrawal or removal as a general partner. In connection with any registration of this kind, we will indemnify each unitholder participating in the registration and its officers, directors and controlling persons from and against any liabilities under the Securities Act of 1933 or any state securities laws arising from the registration statement or prospectus. We will bear all costs and expenses incidental to any registration, excluding any underwriting discounts and commissions. Except as described below, our general partners and their affiliates may sell their units in private transactions at any time, subject to compliance with applicable laws.
In addition, on June 13, 2003, we sold 375,000 common units to certain accredited investors in a private placement, with gross proceeds of $9,836,250. These proceeds were used to reduce outstanding indebtedness. Pursuant to a registration rights agreement dated June 13, 2003, the purchasers have the right to cause us to register under the Securities Act of 1933 and state laws the offer and sale of any units that they hold. These registration rights allow the purchasers who collectively hold at least 50 percent of the common units purchased in the private placement to require registration of at least such a number of securities in the event that there is no public offering by us within six months of the closing of the private placement. In addition, the purchasers have the right to include any of the units
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purchased in the private placement in a registration by us of other units, including units offered by us or by any unitholder. The purchasers will continue to have the demand registration rights for two years from the date of the registration rights agreement and the piggyback registration rights for three and one-half years. In connection with any registration under the registration rights agreement, we will indemnify each unitholder participating in the registration and its officers, directors and controlling persons from and against any liabilities under the Securities Act of 1933 or any state securities laws arising from the registration statement or prospectus. We will bear all costs and expenses incidental to any registration, excluding any underwriting discounts and commissions. Except as described below, the purchasers in the private placement and their affiliates may sell their units in private transactions at any time, subject to compliance with applicable laws.
MarkWest Hydrocarbon and its affiliates, our partnership, our operating company, our general partner, the directors and executive officers of our general partner, and the selling unitholders have agreed not to sell any common units they beneficially own for a period of 90 days from the date of this prospectus. Please read "Underwriting" for a description of these lock-up provisions.
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This section is a summary of the material tax consequences that we believe may be relevant to prospective unitholders who are individual citizens or residents of the United States and, unless otherwise noted in the following discussion, is the opinion of Vinson & Elkins L.L.P., counsel to our general partner and us, insofar as it relates to United States federal income tax matters. This section is based on current provisions of the Internal Revenue Code, existing and proposed regulations to the extent noted and current administrative rulings and court decisions, all of which are subject to change. Later changes in these authorities may cause the tax consequences to vary substantially from the consequences described below. Unless the context otherwise requires, references in this section to "us" or "we" are to MarkWest Energy Partners and the operating partnership.
This section does not address all federal income tax matters that affect us or the unitholders. Furthermore, this section focuses on unitholders who are individual citizens or residents of the United States and has only limited application to corporations, estates, trusts, non-resident aliens or other unitholders subject to specialized tax treatment, such as tax-exempt institutions, foreign persons, individual retirement accounts (IRAs), real estate investment trusts (REITs) or mutual funds. Accordingly, each prospective unitholder is urged to consult, and depend on, his own tax advisor in analyzing the federal, state, local and foreign tax consequences particular to him of the ownership or disposition of common units.
All statements as to matters of law and legal conclusions, but not as to factual matters, contained in this section, unless otherwise noted, are the opinion of Vinson & Elkins L.L.P. and are based on the accuracy of the representations we make and that are described herein.
No ruling has been or will be requested from the IRS regarding any matter that affects us or prospective unitholders. Instead, we will rely on opinions and advice of Vinson & Elkins L.L.P. Unlike a ruling, an opinion of counsel represents only that counsel's best legal judgment and does not bind the IRS or the courts. Accordingly, the opinions and statements made here may not be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may materially and adversely impact the market for the common units and the prices at which common units trade. In addition, the costs of any contest with the IRS will be borne directly or indirectly by the unitholders and the general partner. Furthermore, the tax treatment of us, or of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions. Any modifications may or may not be retroactively applied.
For the reasons described below, Vinson & Elkins L.L.P. has not rendered an opinion with respect to the following specific federal income tax issues:
- (1)
- the treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units (please read "—Tax Consequences of Unit Ownership—Treatment of Short Sales");
- (2)
- whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury regulations (please read "—Disposition of Common Units—Allocations Between Transferors and Transferees"); and
- (3)
- whether our method for depreciating Section 743 adjustments is sustainable (please read "—Tax Consequences of Unit Ownership—Section 754 Election").
A partnership is not a taxable entity and incurs no federal income tax liability. Instead, each partner of a partnership is required to take into account his share of items of income, gain, loss and deduction of the partnership in computing his federal income tax liability, even if no cash distributions
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are made to him by the partnership. Distributions by a partnership to a partner are generally not taxable to the partner unless the amount of cash distributed to him is in excess of his adjusted basis in his partnership interest.
Section 7704 of the Internal Revenue Code provides that publicly-traded partnerships will, as a general rule, be taxed as corporations. However, an exception, referred to as the "Qualifying Income Exception," exists with respect to publicly-traded partnerships of which 90% or more of the gross income for every taxable year consists of "qualifying income." Qualifying income includes income and gains derived from the transportation, storage and processing of crude oil, natural gas and products thereof and fertilizer. Other types of qualifying income include interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of assets held for the production of income that otherwise constitutes qualifying income. We estimate that less than 4% of our current income is not qualifying income; however, this estimate could change from time to time. Based upon and subject to this estimate, the factual representations made by us and the general partner and a review of the applicable legal authorities, Vinson & Elkins L.L.P. is of the opinion that at least 90% of our current gross income constitutes qualifying income.
No ruling has been or will be sought from the IRS and the IRS has made no determination as to our status or the status of the operating partnership for federal income tax purposes or whether our operations generate "qualifying income" under Section 7704 of the Internal Revenue Code. Instead, we will rely on the opinion of Vinson & Elkins L.L.P. that, based on the Internal Revenue Code, its regulations, published revenue rulings and court decisions and the representations set forth below, MarkWest Energy Partners will be classified as partnerships for federal income tax purposes.
In rendering its opinion, Vinson & Elkins L.L.P. has relied on factual representations made by us and the general partner. The representations made by us and our general partner upon which counsel has relied are:
- (a)
- Neither we nor the operating partnership has elected or will elect to be treated as a corporation; and
- (b)
- For each taxable year, more than 90% of our gross income has been and will be income that Vinson & Elkins L.L.P. has opined or will opine is "qualifying income" within the meaning of Section 7704(d) of the Internal Revenue Code.
If we fail to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery, in which case the IRS may also require us to make adjustments with respect to our unitholders or pay other amounts, we will be treated as if we had transferred all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation, and then distributed that stock to the unitholders in liquidation of their interests in us. This deemed contribution and liquidation would be tax-free to unitholders and us so long as we, at that time, do not have liabilities in excess of the tax basis of our assets. Thereafter, we would be treated as a corporation for federal income tax purposes.
If we were taxable as a corporation in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, our items of income, gain, loss and deduction would be reflected only on our tax return rather than being passed through to the unitholders, and our net income would be taxed to us at corporate rates. In addition, any distribution made to a unitholder would be treated as either taxable dividend income, to the extent of our current or accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital, to the extent of the unitholder's tax basis in his common units, or taxable capital gain, after the unitholder's tax basis in his common units is reduced to zero. Accordingly, taxation as a corporation would result in
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a material reduction in a unitholder's cash flow and after-tax return and thus would likely result in a substantial reduction of the value of the units.
The remainder of this section is based on Vinson & Elkins L.L.P.'s opinion that MarkWest Energy Partners will be classified as a partnership for federal income tax purposes.
Unitholders who have become limited partners of MarkWest Energy Partners will be treated as partners of MarkWest Energy Partners for federal income tax purposes. Also:
- (a)
- assignees who have executed and delivered transfer applications, and are awaiting admission as limited partners, and
- (b)
- unitholders whose common units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of their common units,
will be treated as partners of MarkWest Energy Partners for federal income tax purposes.
As there is no direct authority addressing the federal tax treatment of assignees of common units who are entitled to execute and deliver transfer applications and thereby become entitled to direct the exercise of attendant rights, but who fail to execute and deliver transfer applications, the opinion of Vinson & Elkins L.L.P. does not extend to these persons. Furthermore, a purchaser or other transferee of common units who does not execute and deliver a transfer application may not receive some federal income tax information or reports furnished to record holders of common units unless the common units are held in a nominee or street name account and the nominee or broker has executed and delivered a transfer application for those common units.
A beneficial owner of common units whose units have been transferred to a short seller to complete a short sale would appear to lose his status as a partner with respect to those units for federal income tax purposes. Please read "—Tax Consequences of Unit Ownership—Treatment of Short Sales."
Income, gain, deductions or losses would not appear to be reportable by a unitholder who is not a partner for federal income tax purposes, and any cash distributions received by a unitholder who is not a partner for federal income tax purposes would therefore be fully taxable as ordinary income. These holders are urged to consult their own tax advisors with respect to their status as partners in MarkWest Energy Partners for federal income tax purposes.
Tax Consequences of Unit Ownership
Flow-through of Taxable Income. We will not pay any federal income tax. Instead, each unitholder will be required to report on his income tax return his share of our income, gains, losses and deductions without regard to whether corresponding cash distributions are received by him. Consequently, we may allocate income to a unitholder even if he has not received a cash distribution. Each unitholder will be required to include in income his allocable share of our income, gains, losses and deductions for our taxable year ending with or within his taxable year. Our taxable year ends on December 31.
Treatment of Distributions. Cash distributions made by us to a unitholder generally will not be taxable to him for federal income tax purposes to the extent of his tax basis in his common units immediately before the distribution. Cash distributions made by us to a unitholder in an amount in excess of his tax basis in his common units generally will be considered to be gain from the sale or exchange of the common units, taxable in accordance with the rules described under "—Disposition of Common Units" below. To the extent that cash distributions made by us cause a unitholder's "at risk"
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amount to be less than zero at the end of any taxable year, he must recapture any losses deducted in previous years. Please read "—Limitations on Deductibility of Losses."
Any reduction in a unitholder's share of our liabilities for which no partner, including the general partner, bears the economic risk of loss, known as "nonrecourse liabilities," will be treated as a distribution of cash to that unitholder. A decrease in a unitholder's percentage interest in us because of our issuance of additional common units will decrease his share of our nonrecourse liabilities, and thus will result in a corresponding deemed distribution of cash, which may constitute a non-pro rata distribution. A non-pro rata distribution of money or property may result in ordinary income to a unitholder, regardless of his tax basis in his common units, if the distribution reduces the unitholder's share of our "unrealized receivables," including depreciation recapture, and/or substantially appreciated "inventory items," both as defined in Section 751 of the Internal Revenue Code, and collectively, "Section 751 Assets." To that extent, he will be treated as having received his proportionate share of the Section 751 Assets and having exchanged those assets with us in return for the non-pro rata portion of the actual distribution made to him. This latter deemed exchange will generally result in the unitholder's realization of ordinary income. That income will equal the excess of (1) the non-pro rata portion of that distribution over (2) the unitholder's tax basis for the share of Section 751 Assets deemed relinquished in the exchange.
Ratio of Taxable Income to Distributions. We estimate that a purchaser of common units in this offering who holds those common units from the date of closing of this offering through December 31, 2006, will be allocated an amount of federal taxable income for that period that will be less than 20% of the cash distributed with respect to that period. We anticipate that thereafter, the ratio of taxable income allocable to cash distributions to the unitholders will increase. These estimates are based upon the assumption that gross income from operations will approximate the amount required to make the minimum quarterly distribution on all units and other assumptions with respect to capital expenditures, cash flow and anticipated cash distributions including the assumption that any future issuance of common units will not be at a higher price. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, competitive and political uncertainties beyond our control. Further, the estimates are based on current tax law and tax reporting positions that we intend to adopt and with which the IRS could disagree. Accordingly, these estimates may not prove to be correct. The actual percentage of distributions that will constitute taxable income could be higher or lower, and any differences could be material and could materially affect the value of the common units.
Initial Basis of Common Units. A unitholder's initial tax basis for his common units generally will be the amount he paid for the common units plus his share of our nonrecourse liabilities. That basis generally will be increased by his share of our income and by any increases in his share of our nonrecourse liabilities. That basis generally will be decreased, but not below zero, by distributions to him from us, by his share of our losses, by any decreases in his share of our nonrecourse liabilities and by his share of our expenditures that are not deductible in computing taxable income and are not required to be capitalized. A unitholder generally will have no share of our debt that is recourse to the general partner, but will have a share, generally based on his share of profits, of our nonrecourse liabilities. Please read "—Disposition of Common Units—Recognition of Gain or Loss."
Limitations on Deductibility of Losses. The deduction by a unitholder of his share of our losses will be limited to the tax basis in his units and, in the case of an individual unitholder or a corporate unitholder, if more than 50% of the value of its stock is owned directly or indirectly by or for five or fewer individuals or certain tax-exempt organizations, to the amount for which the unitholder is considered to be "at risk" with respect to our activities, if that is less than his tax basis. A unitholder must recapture losses deducted in previous years to the extent that distributions cause his at-risk amount to be less than zero at the end of any taxable year. Losses disallowed to a unitholder or recaptured as a result of these limitations will carry forward and will be allowable as a deduction in a
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later year to the extent that his tax basis or at-risk amount, whichever is the limiting factor, is subsequently increased. Upon the taxable disposition of a unit, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at risk limitation but may not be offset by losses suspended by the basis limitation. Any excess loss above that gain previously suspended by the at risk or basis limitations is no longer utilizable.
In general, a unitholder will be at risk to the extent of his tax basis in his units, excluding any portion of that basis attributable to his share of our nonrecourse liabilities, reduced by any amount of money he borrows to acquire or hold his units, if the lender of those borrowed funds owns an interest in us, is related to the unitholder or can look only to the units for repayment, or any portion of that basis representing amounts otherwise protected against loss because of a guarantee, stop loss agreement or other similar arrangement. A unitholder's at-risk amount will increase or decrease as the tax basis of the unitholder's units increases or decreases, other than tax basis increases or decreases attributable to increases or decreases in his share of our nonrecourse liabilities.
The passive loss limitations generally provide that individuals, estates, trusts and some closely-held corporations and personal service corporations are permitted to deduct losses from passive activities, which are generally defined as corporate or partnership activities in which the taxpayer does not materially participate, only to the extent of the taxpayer's income from those passive activities. The passive loss limitations are applied separately with respect to each publicly-traded partnership. Consequently, any losses we generate will only be available to offset our passive income generated in the future and will not be available to offset income from other passive activities or investments, including our investments or investments in other publicly-traded partnerships, or salary or active business income. Similarly, a unitholder's share of our net income may not be offset by any other current or carryover losses from other passive activities, including those attributable to other publicly traded partnerships. Passive losses that are not deductible because they exceed a unitholder's share of income we generate may be deducted in full when he disposes of his entire investment in us in a fully taxable transaction with an unrelated party. The passive activity loss rules are applied after other applicable limitations on deductions, including the at-risk rules and the basis limitation.
Limitations on Interest Deductions. The deductibility of a non-corporate taxpayer's "investment interest expense" is generally limited to the amount of that taxpayer's "net investment income." Investment interest expense includes:
- •
- interest on indebtedness properly allocable to property held for investment;
- •
- our interest expense attributable to portfolio income; and
- •
- the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income.
The computation of a unitholder's investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income, but generally does not include gains attributable to the disposition of property held for investment. The IRS has indicated that net passive income earned by a publicly-traded partnership will be treated as investment income to its unitholders. In addition, the unitholder's share of our portfolio income will be treated as investment income.
Entity-Level Collections. If we are required or elect under applicable law to pay any federal, state or local income tax on behalf of any unitholder or the general partner or any former unitholder, we are authorized to pay those taxes from our funds. That payment, if made, will be treated as a distribution of cash to the unitholder on whose behalf the payment was made. If the payment is made on behalf of a unitholder whose identity cannot be determined, we are authorized to treat the payment as a
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distribution to all current unitholders. We are authorized to amend the partnership agreement in the manner necessary to maintain uniformity of intrinsic tax characteristics of units and to adjust later distributions, so that after giving effect to these distributions, the priority and characterization of distributions otherwise applicable under the partnership agreement is maintained as nearly as is practicable. Payments by us as described above could give rise to an overpayment of tax on behalf of a unitholder in which event the unitholder would be required to file a claim in order to obtain a credit or refund.
Allocation of Income, Gain, Loss and Deduction. In general, if we have a net profit, our items of income, gain, loss and deduction will be allocated among the general partner and the unitholders in accordance with their percentage interests in us. At any time that distributions are made to the common units and not to the subordinated units, or that incentive distributions are made to the general partner, gross income will be allocated to the recipients to the extent of those distributions. If we have a net loss for the entire year, that amount of loss will be allocated first to the general partner and the unitholders in accordance with their percentage interests in us to the extent of their positive capital accounts and then to our general partner.
Specified items of our income, gain, loss and deduction will be allocated to account for the difference between the tax basis and fair market value of our assets at the time of an offering, referred to in this discussion as "Contributed Property." The effect of these allocations to a unitholder who purchases common units in an offering will be essentially the same as if the tax basis of our assets were equal to their fair market value at the time of the offering. In addition, items of recapture income will be allocated to the extent possible to the unitholder who was allocated the deduction giving rise to the treatment of that gain as recapture income in order to minimize the recognition of ordinary income by other unitholders. Finally, although we do not expect that our operations will result in the creation of negative capital accounts, if negative capital accounts nevertheless result, items of our income and gain will be allocated in an amount and manner sufficient to eliminate the negative balance as quickly as possible.
Vinson & Elkins L.L.P. is of the opinion that, with the exception of the issues described in "—Tax Consequences of Unit Ownership—Section 754 Election" and "—Disposition of Common Units—Allocations Between Transferors and Transferees," allocations under our partnership agreement will be given effect for federal income tax purposes in determining a unitholder's share of an item of income, gain, loss or deduction.
Treatment of Short Sales. A unitholder whose units are loaned to a "short seller" to cover a short sale of units may be considered as having disposed of those units. If so, he would no longer be a partner for those units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period:
- •
- any of our income, gain, loss or deduction with respect to those units would not be reportable by the unitholder;
- •
- any cash distributions received by the unitholder as to those units would be fully taxable; and
- •
- all of these distributions would appear to be ordinary income.
Vinson & Elkins L.L.P. has not rendered an opinion regarding the treatment of a unitholder where common units are loaned to a short seller to cover a short sale of common units; therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller should modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units. The IRS has announced that it is actively studying issues relating to the tax treatment of short sales of partnership interests. Please also read "—Disposition of Common Units—Recognition of Gain or Loss."
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Alternative Minimum Tax. Each unitholder will be required to take into account his distributive share of any items of our income, gain, loss or deduction for purposes of the alternative minimum tax. The current minimum tax rate for noncorporate taxpayers is 26% on the first $175,000 of alternative minimum taxable income in excess of the exemption amount and 28% on any additional alternative minimum taxable income. Prospective unitholders are urged to consult with their tax advisors as to the impact of an investment in units on their liability for the alternative minimum tax.
Tax Rates. In general, the highest effective United States federal income tax rate for individuals currently is 35% and the maximum United States federal income tax rate for net capital gains of an individual currently is 15% if the asset disposed of was held for more than one year at the time of disposition.
Section 754 Election. We have made the election permitted by Section 754 of the Internal Revenue Code. That election is irrevocable without the consent of the IRS. The election will generally permit us to adjust a common unit purchaser's tax basis in our assets ("inside basis") under Section 743(b) of the Internal Revenue Code to reflect his purchase price. The Section 743(b) adjustment does not apply to a person who purchases common units directly from us and it belongs only to the purchaser and not to other unitholders. Please also read, however, "—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction." For purposes of this discussion, a unitholder's inside basis in our assets has two components: (1) his share of our tax basis in our assets ("common basis") and (2) his Section 743(b) adjustment to that basis.
Treasury regulations under Section 743 of the Internal Revenue Code require, if the remedial allocation method is adopted (which we have adopted), a portion of the Section 743(b) adjustment attributable to recovery property to be depreciated over the remaining cost recovery period for the Section 704(c) built-in gain. We have adopted the remedial allocation method. Under Treasury regulation Section 1.167(c)-l(a)(6), a Section 743(b) adjustment attributable to property subject to depreciation under Section 167 of the Internal Revenue Code rather than cost recovery deductions under Section 168 is generally required to be depreciated using either the straight-line method or the 150% declining balance method. Under our partnership agreement, the general partner is authorized to take a position to preserve the uniformity of units even if that position is not consistent with these Treasury regulations. Please read "—Tax Treatment of Operations—Uniformity of Units."
Although Vinson & Elkins L.L.P. is unable to opine as to the validity of this approach because there is no clear authority on this issue, we intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized book-tax disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the common basis of the property, or treat that portion as non-amortizable to the extent attributable to property the common basis of which is not amortizable. This method is consistent with the regulations under Section 743 of the Internal Revenue Code but is arguably inconsistent with Treasury regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. To the extent this Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized book-tax disparity, we will apply the rules described in the Treasury regulations and legislative history. If we determine that this position cannot reasonably be taken, we may take a depreciation or amortization position under which all purchasers acquiring units in the same month would receive depreciation or amortization, whether attributable to common basis or a Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our assets. This kind of aggregate approach may result in lower annual depreciation or amortization deductions than would otherwise be allowable to some unitholders. Please read "—Tax Treatment of Operations—Uniformity of Units."
Tax Reporting. Recently issued Treasury regulations require taxpayers to report certain information on Internal Revenue Service Form 8886 if they participate in a "reportable transaction."
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You may be required to file this form with the Internal Revenue Service if we participate in a "reportable transaction." A transaction may be a reportable transaction based upon any of several factors. You are urged to consult with your own tax advisor concerning the application of any of these factors to your investment in our common units. Congress is considering legislative proposals that, if enacted, would impose significant penalties for failure to comply with these disclosure requirements. The Treasury regulations also impose obligations on "material advisors" that organize, manage or sell interests in registered "tax shelters." As described in herein, we have registered as a tax shelter, and thus, one of our material advisors will be required to maintain a list with specific information, including your name and tax identification number, and to furnish this information to the Internal Revenue Service upon request. You are urged to consult with your own tax advisor concerning any possible disclosure obligation with respect to your investment and should be aware that we and our material advisors intend to comply with the list and disclosure requirements.
A Section 754 election is advantageous if the transferee's tax basis in his units is higher than the units' share of the aggregate tax basis of our assets immediately prior to the transfer. In that case, as a result of the election, the transferee would have, among other items, a greater amount of depreciation and depletion deductions and his share of any gain on a sale of our assets would be less. Conversely, a Section 754 election is disadvantageous if the transferee's tax basis in his units is lower than those units' share of the aggregate tax basis of our assets immediately prior to the transfer. Thus, the fair market value of the units may be affected either favorably or unfavorably by the election.
The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters. For example, the allocation of the Section 743(b) adjustment among our assets must be made in accordance with the Internal Revenue Code. The IRS could seek to reallocate some or all of any Section 743(b) adjustment we allocated to our tangible assets to goodwill instead. Goodwill, as an intangible asset, is generally amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure you that the determinations we make will not be successfully challenged by the IRS and that the deductions resulting from them will not be reduced or disallowed altogether. Should the IRS require a different basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of units may be allocated more income than he would have been allocated had the election not been revoked.
Accounting Method and Taxable Year. We use the year ending December 31 as our taxable year and the accrual method of accounting for federal income tax purposes. Each unitholder will be required to include in income his share of our income, gain, loss and deduction for our taxable year ending within or with his taxable year. In addition, a unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of his units following the close of our taxable year but before the close of his taxable year must include his share of our income, gain, loss and deduction in income for his taxable year, with the result that he will be required to include in income for his taxable year his share of more than one year of our income, gain, loss and deduction. Please read "—Disposition of Common Units—Allocations Between Transferors and Transferees."
Tax Basis, Depreciation and Amortization. The tax basis of our assets will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of these assets. The federal income tax burden associated with the difference between the fair market value of our assets and their tax basis immediately prior to an offering will be borne by the general partner, its affiliates and our other unitholders as of that time. Please read "—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction."
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To the extent allowable, we may elect to use the depreciation and cost recovery methods that will result in the largest deductions being taken in the early years after assets are placed in service. We were not entitled to any amortization deductions with respect to any goodwill conveyed to us on formation. Property we subsequently acquire or construct may be depreciated using accelerated methods permitted by the Internal Revenue Code.
If we dispose of depreciable property by sale, foreclosure, or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation previously deducted and the nature of the property, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a partner who has taken cost recovery or depreciation deductions with respect to property we own will likely be required to recapture some or all of those deductions as ordinary income upon a sale of his interest in us. Please read "—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction" and "—Disposition of Common Units—Recognition of Gain or Loss."
The costs incurred in selling our units (called "syndication expenses") must be capitalized and cannot be deducted currently, ratably or upon our termination. There are uncertainties regarding the classification of costs as organization expenses, which we may amortize, and as syndication expenses, which we may not amortize. The underwriting discounts and commissions we incur will be treated as syndication expenses.
Valuation and Tax Basis of Our Properties. The federal income tax consequences of the ownership and disposition of units will depend in part on our estimates of the relative fair market values, and the tax bases, of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates of basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deductions previously reported by unitholders might change, and unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.
Recognition of Gain or Loss. Gain or loss will be recognized on a sale of units equal to the difference between the amount realized and the unitholder's tax basis for the units sold. A unitholder's amount realized will be measured by the sum of the cash or the fair market value of other property he receives plus his share of our nonrecourse liabilities. Because the amount realized includes a unitholder's share of our nonrecourse liabilities, the gain recognized on the sale of units could result in a tax liability in excess of any cash received from the sale.
Prior distributions from us in excess of cumulative net taxable income for a common unit that decreased a unitholder's tax basis in that common unit will, in effect, become taxable income if the common unit is sold at a price greater than the unitholder's tax basis in that common unit, even if the price received is less than his original cost.
Except as noted below, gain or loss recognized by a unitholder, other than a "dealer" in units, on the sale or exchange of a unit held for more than one year will generally be taxable as capital gain or loss. Capital gain recognized by an individual on the sale of units held more than one year will generally be taxed at a maximum rate of 15%. A portion of this gain or loss, which will likely be substantial, however, will be separately computed and taxed as ordinary income or loss under Section 751 of the Internal Revenue Code to the extent attributable to assets giving rise to depreciation recapture or other "unrealized receivables" or to "inventory items" we own. The term "unrealized receivables" includes potential recapture items, including depreciation recapture. Ordinary income attributable to unrealized receivables, inventory items and depreciation recapture may exceed net taxable gain realized upon the sale of a unit and may be recognized even if there is a net taxable loss
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realized on the sale of a unit. Thus, a unitholder may recognize both ordinary income and a capital loss upon a sale of units. Net capital loss may offset capital gains and no more than $3,000 of ordinary income, in the case of individuals, and may only be used to offset capital gain in the case of corporations.
The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an "equitable apportionment" method. Treasury regulations allow a selling unitholder who can identify common units transferred with an ascertainable holding period to elect to use the actual holding period of the common units transferred. Thus, according to the ruling, a common unitholder will be unable to select high or low basis common units to sell as would be the case with corporate stock, but, according to the regulations, may designate specific common units sold for purposes of determining the holding period of units transferred. A unitholder electing to use the actual holding period of common units transferred must consistently use that identification method for all subsequent sales or exchanges of common units. A unitholder considering the purchase of additional units or a sale of common units purchased in separate transactions is urged to consult his tax advisor as to the possible consequences of this ruling and application of the Treasury regulations.
Specific provisions of the Internal Revenue Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an "appreciated" partnership interest, one in which gain would be recognized if it were sold, assigned or terminated at its fair market value, if the taxpayer or related persons enter(s) into:
- •
- a short sale;
- •
- an offsetting notional principal contract; or
- •
- a futures or forward contract with respect to the partnership interest or substantially identical property.
Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of Treasury is also authorized to issue regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.
Allocations Between Transferors and Transferees. In general, our taxable income and losses will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of units owned by each of them as of the opening of the applicable exchange on the first business day of the month (the "Allocation Date"). However, gain or loss realized on a sale or other disposition of our assets other than in the ordinary course of business will be allocated among the unitholders on the Allocation Date in the month in which that gain or loss is recognized. As a result, a unitholder transferring units may be allocated income, gain, loss and deduction realized after the date of transfer.
The use of this method may not be permitted under existing Treasury regulations. Accordingly, Vinson & Elkins L.L.P. is unable to opine on the validity of this method of allocating income and deductions between unitholders. If this method is not allowed under the Treasury regulations, or only applies to transfers of less than all of the unitholder's interest, our taxable income or losses might be reallocated among the unitholders. We are authorized to revise our method of allocation between unitholders to conform to a method permitted under future Treasury regulations.
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A unitholder who owns units at any time during a quarter and who disposes of them prior to the record date set for a cash distribution for that quarter will be allocated items of our income, gain, loss and deductions attributable to that quarter but will not be entitled to receive that cash distribution.
Notification Requirements. A purchaser of units from another unitholder is required to notify us in writing of that purchase within 30 days after the purchase. We are required to notify the IRS of that transaction and to furnish specified information to the transferor and transferee. However, these reporting requirements do not apply to a purchase by an individual who is a citizen of the United States and who effects the purchase through a broker. Failure to notify us of a purchase may lead to the imposition of substantial penalties.
Constructive Termination. We will be considered to have been terminated for tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a 12-month period. A constructive termination results in the closing of our taxable year for all unitholders. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may result in more than 12 months of our taxable income or loss being includable in his taxable income for the year of termination. We would be required to make new tax elections after a termination, including a new election under Section 754 of the Internal Revenue Code, and a termination would result in a deferral of our deductions for depreciation. A termination could also result in penalties if we were unable to determine that the termination had occurred. Moreover, a termination might either accelerate the application of, or subject us to, any tax legislation enacted before the termination.
Because we cannot match transferors and transferees of units, we must maintain uniformity of the economic and tax characteristics of the units to a purchaser of these units. In the absence of uniformity, we may be unable to completely comply with a number of federal income tax requirements, both statutory and regulatory. A lack of uniformity can result from a literal application of Treasury regulation Section 1.167(c)-1(a)(6). Any non-uniformity could have a negative impact on the value of the units. Please read "—Tax Consequences of Unit Ownership—Section 754 Election."
We intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized book-tax disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the common basis of that property, or treat that portion as nonamortizable, to the extent attributable to property the common basis of which is not amortizable, consistent with the regulations under Section 743 of the Internal Revenue Code, even though that position may be inconsistent with Treasury regulation Section 1.167(c)-1(a)(6) which is not expected to directly apply to a material portion of our assets. Please read "—Tax Consequences of Unit Ownership—Section 754 Election." To the extent that the Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized book-tax disparity, we will apply the rules described in the Treasury regulations and legislative history. If we determine that this position cannot reasonably be taken, we may adopt a depreciation and amortization position under which all purchasers acquiring units in the same month would receive depreciation and amortization deductions, whether attributable to a common basis or Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our property. If this position is adopted, it may result in lower annual depreciation and amortization deductions than would otherwise be allowable to some unitholders and risk the loss of depreciation and amortization deductions not taken in the year that these deductions are otherwise allowable. This position will not be adopted if we determine that the loss of depreciation and amortization deductions will have a material adverse effect on the unitholders. If we choose not to utilize this aggregate method, we may use any other reasonable depreciation and amortization method to preserve the uniformity of the intrinsic tax characteristics of any units that would not have a material
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adverse effect on the unitholders. The IRS may challenge any method of depreciating the Section 743(b) adjustment described in this paragraph. If this challenge were sustained, the uniformity of units might be affected, and the gain from the sale of units might be increased without the benefit of additional deductions. Please read "—Disposition of Common Units—Recognition of Gain or Loss."
Tax-Exempt Organizations and Other Investors
Ownership of units by employee benefit plans, other tax-exempt organizations, non-resident aliens, foreign corporations, other foreign persons and regulated investment companies raises issues unique to those investors and, as described below, may have substantially adverse tax consequences to them.
Employee benefit plans and most other organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, are subject to federal income tax on unrelated business taxable income. Virtually all of our income allocated to a unitholder which is a tax-exempt organization will be unrelated business taxable income and will be taxable to them.
A regulated investment company or "mutual fund" is required to derive 90% or more of its gross income from interest, dividends and gains from the sale of stocks or securities or foreign currency or specified related sources. It is not anticipated that any significant amount of our gross income will include that type of income.
Non-resident aliens and foreign corporations, trusts or estates that own units will be considered to be engaged in business in the United States because of the ownership of units. As a consequence they will be required to file federal tax returns to report their share of our income, gain, loss or deduction and pay federal income tax at regular rates on their share of our net income or gain. Under rules applicable to publicly traded partnerships, we will withhold tax, at the highest effective applicable rate, from cash distributions made quarterly to foreign unitholders. Each foreign unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8 or applicable substitute form in order to obtain credit for these withholding taxes. A change in applicable law may require us to change these procedures.
In addition, because a foreign corporation that owns units will be treated as engaged in a United States trade or business, that corporation may be subject to the United States branch profits tax at a rate of 30%, in addition to regular federal income tax, on its share of our income and gain, as adjusted for changes in the foreign corporation's "U.S. net equity," which are effectively connected with the conduct of a United States trade or business. That tax may be reduced or eliminated by an income tax treaty between the United States and the country in which the foreign corporate unitholder is a "qualified resident." In addition, this type of unitholder is subject to special information reporting requirements under Section 6038C of the Internal Revenue Code.
Under a ruling of the IRS, a foreign unitholder who sells or otherwise disposes of a unit will be subject to federal income tax on gain realized on the sale or disposition of that unit to the extent that this gain is effectively connected with a United States trade or business of the foreign unitholder. Apart from the ruling, a foreign unitholder will not be taxed or subject to withholding upon the sale or disposition of a unit if he has owned less than 5% in value of the units during the five-year period ending on the date of the disposition and if the units are regularly traded on an established securities market at the time of the sale or disposition.
Information Returns and Audit Procedures. We intend to furnish to each unitholder, within 90 days after the close of each calendar year, specific tax information, including a Schedule K-1, which describes his share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting
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positions, some of which have been mentioned earlier, to determine his share of income, gain, loss and deduction. We cannot assure you that those positions will yield a result that conforms to the requirements of the Internal Revenue Code, regulations or administrative interpretations of the IRS. Neither we nor counsel can assure prospective unitholders that the IRS will not successfully contend in court that those positions are impermissible. Any challenge by the IRS could negatively affect the value of the units.
The IRS may audit our federal income tax information returns. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year's tax liability, and possibly may result in an audit of his own return. Any audit of a unitholder's return could result in adjustments not related to our returns as well as those related to our returns.
Partnerships generally are treated as separate entities for purposes of federal tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings with the partners. The Internal Revenue Code requires that one partner be designated as the "Tax Matters Partner" for these purposes. The partnership agreement names MarkWest Energy GP, L.L.C. as our Tax Matters Partner.
The Tax Matters Partner will make some elections on our behalf and on behalf of unitholders. In addition, the Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our returns. The Tax Matters Partner may bind a unitholder with less than a 1% profits interest in us to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1% interest in profits or by any group of unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review will go forward, and each unitholder with an interest in the outcome may participate.
A unitholder must file a statement with the IRS identifying the treatment of any item on his federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.
Nominee Reporting. Persons who hold an interest in us as a nominee for another person are required to furnish to us:
- (a)
- the name, address and taxpayer identification number of the beneficial owner and the nominee;
- (b)
- whether the beneficial owner is
- (1)
- a person that is not a United States person,
- (2)
- a foreign government, an international organization or any wholly owned agency or instrumentality of either of the foregoing, or
- (3)
- a tax-exempt entity;
- (c)
- the amount and description of units held, acquired or transferred for the beneficial owner; and
- (d)
- specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from sales.
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Brokers and financial institutions are required to furnish additional information, including whether they are United States persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $50 per failure, up to a maximum of $100,000 per calendar year, is imposed by the Internal Revenue Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.
Registration as a Tax Shelter. The Internal Revenue Code requires that "tax shelters" be registered with the Secretary of the Treasury. It is arguable that we are not subject to the registration requirement on the basis that we will not constitute a tax shelter. However, we have registered as a tax shelter with the Secretary of Treasury in the absence of assurance that we will not be subject to tax shelter registration and in light of the substantial penalties which might be imposed if registration is required and not undertaken. Our tax shelter registration number is 0218400024.
Issuance of this registration number does not indicate that investment in us or the claimed tax benefits have been reviewed, examined or approved by the IRS.
A unitholder who sells or otherwise transfers a unit in a later transaction must furnish the registration number to the transferee. The penalty for failure of the transferor of a unit to furnish the registration number to the transferee is $100 for each failure. The unitholders must disclose our tax shelter registration number on Form 8271 to be attached to the tax return on which any deduction, loss or other benefit we generate is claimed or on which any of our income is included. A unitholder who fails to disclose the tax shelter registration number on his return, without reasonable cause for that failure, will be subject to a $250 penalty for each failure. Any penalties discussed are not deductible for federal income tax purposes.
Accuracy-Related Penalties. A penalty in an amount equal to 20% of the amount of any portion of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements, is imposed by the Internal Revenue Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for that portion and that the taxpayer acted in good faith regarding that portion.
A substantial understatement of income tax in any taxable year exists if the amount of the understatement exceeds the greater of 10% of the tax required to be shown on the return for the taxable year or $5,000 ($10,000 for a corporation other than an S Corporation or a personal holding company). The amount of any understatement subject to penalty generally is reduced if any portion is attributable to a position adopted on the return:
- (1)
- for which there is, or was, "substantial authority," or
- (2)
- as to which there is a reasonable basis and the relevant facts of that position are disclosed on the return.
More stringent rules apply to "tax shelters," a term that in this context does not appear to include us. If any item of income, gain, loss or deduction included in the distributive shares of unitholders might result in the kind of an "understatement" for which no "substantial authority" exists but for which a reasonable basis for the tax treatment of such item exists, we must disclose the relevant facts on our return. In such a case, we will make a reasonable effort to furnish sufficient information for unitholders to make adequate disclosure on their returns to avoid liability for this penalty.
A substantial valuation misstatement exists if the value of any property, or the adjusted basis of any property, claimed on a tax return is 200% or more of the amount determined to be the correct amount of the valuation or adjusted basis. No penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000 ($10,000 for a
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corporation other than an S Corporation or a personal holding company). If the valuation claimed on a return is 400% or more than the correct valuation, the penalty imposed increases to 40%.
State, Local and Other Tax Considerations
In addition to federal income taxes, you will be subject to other taxes, including state and local income taxes, unincorporated business taxes, and estate, inheritance or intangible taxes that may be imposed by the various jurisdictions in which we do business or own property or in which you are a resident. We currently do business or own property in nine states, most of which impose income taxes. We may also own property or do business in other states in the future. Although an analysis of those various taxes is not presented here, each prospective unitholder is urged to consider their potential impact on his investment in us. You may not be required to file a return and pay taxes in some states because your income from that state falls below the filing and payment requirement. You will be required, however, to file state income tax returns and to pay state income taxes in many of the states in which we do business or own property, and you may be subject to penalties for failure to comply with those requirements. In some states, tax losses may not produce a tax benefit in the year incurred and also may not be available to offset income in subsequent taxable years. Some of the states may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the state. Withholding, the amount of which may be greater or less than a particular unitholder's income tax liability to the state, generally does not relieve a non-resident unitholder from the obligation to file an income tax return. Amounts withheld may be treated as if distributed to unitholders for purposes of determining the amounts distributed by us. Please read "—Tax Consequences of Unit Ownership—Entity-Level Collections." Based on current law and our estimate of our future operations, the general partner anticipates that any amounts required to be withheld will not be material.
It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent states and localities, of his investment in us. Vinson & Elkins L.L.P. has not rendered an opinion on the state or local tax consequences of an investment in us. We strongly recommend that each prospective unitholder consult, and depend upon, his own tax counsel or other advisor with regard to those matters. It is the responsibility of each unitholder to file all state and local, as well as United States federal tax returns, that may be required of him.
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INVESTMENT IN MARKWEST ENERGY PARTNERS BY EMPLOYEE BENEFIT PLANS
An investment in us by an employee benefit plan is subject to additional considerations because the investments of these plans are subject to the fiduciary responsibility and prohibited transaction provisions of ERISA, and restrictions imposed by Section 4975 of the Internal Revenue Code. For these purposes the term "employee benefit plan" includes, but is not limited to, qualified pension, profit-sharing and stock bonus plans, Keogh plans, simplified employee pension plans and tax deferred annuities or IRAs established or maintained by an employer or employee organization. Among other things, consideration should be given to:
- (a)
- whether the investment is prudent under Section 404(a)(1)(B) of ERISA;
- (b)
- whether in making the investment, that plan will satisfy the diversification requirements of Section 404(a)(l)(C) of ERISA; and
- (c)
- whether the investment will result in recognition of unrelated business taxable income by the plan and, if so, the potential after-tax investment return.
The person with investment discretion with respect to the assets of an employee benefit plan, often called a fiduciary, should determine whether an investment in us is authorized by the appropriate governing instrument and is a proper investment for the plan.
Section 406 of ERISA and Section 4975 of the Internal Revenue Code prohibit employee benefit plans, and IRAs that are not considered part of an employee benefit plan, from engaging in specified transactions involving "plan assets" with parties that are "parties in interest" under ERISA or "disqualified persons" under the Internal Revenue Code with respect to the plan.
In addition to considering whether the purchase of common units is a prohibited transaction, a fiduciary of an employee benefit plan should consider whether the plan will, by investing in us, be deemed to own an undivided interest in our assets, with the result that our general partner also would be fiduciaries of the plan and our operations would be subject to the regulatory restrictions of ERISA, including its prohibited transaction rules, as well as the prohibited transaction rules of the Internal Revenue Code.
The Department of Labor regulations provide guidance with respect to whether the assets of an entity in which employee benefit plans acquire equity interests would be deemed "plan assets" under some circumstances. Under these regulations, an entity's assets would not be considered to be "plan assets" if, among other things,
- (a)
- the equity interests acquired by employee benefit plans are publicly offered securities; i.e., the equity interests are widely held by 100 or more investors independent of the issuer and each other, freely transferable and registered under some provisions of the federal securities laws,
- (b)
- the entity is an "operating company," that is, it is primarily engaged in the production or sale of a product or service other than the investment of capital either directly or through a majority owned subsidiary or subsidiaries, or
- (c)
- there is no significant investment by benefit plan investors, which is defined to mean that less than 25% of the value of each class of equity interest, disregarding some interests held by our general partner, its affiliates, and some other persons, is held by the employee benefit plans referred to above, IRAs and other employee benefit plans not subject to ERISA, including governmental plans.
Our assets should not be considered "plan assets" under these regulations because it is expected that the investment will satisfy the requirements in (a) above.
Plan fiduciaries contemplating a purchase of common units are urged to consult with their own counsel regarding the consequences under ERISA and the Internal Revenue Code in light of the serious penalties imposed on persons who engage in prohibited transactions or other violations.
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Subject to the terms and conditions of the underwriting agreement among us, the selling unitholders and the underwriters, the underwriters have agreed severally to purchase from us and the selling unitholders the following number of common units at the offering price less the underwriting discount set forth on the cover page of this prospectus.
Underwriters | Number of Common Units | ||
---|---|---|---|
A.G. Edwards & Sons, Inc | |||
RBC Dain Rauscher Inc. | |||
McDonald Investments Inc., a KeyCorp. company | |||
Total | 1,148,000 | ||
The underwriting agreement provides that the obligations of the underwriters are subject to certain conditions and that the underwriters will purchase all such common units if any of the units are purchased. The underwriters are obligated to take and pay for all of the common units offered by this prospectus, other than those covered by the over-allotment option described below, if any are taken.
The underwriters have advised us that they propose to offer the common units to the public at the offering price set forth on the cover page of this prospectus and to certain dealers at such price less a concession not in excess of $ per unit. The underwriters may allow, and such dealers may re-allow, a concession not in excess of $ per unit to certain other dealers. After the offering, the offering price and other selling terms may be changed by the underwriters.
Pursuant to the underwriting agreement, we have granted to the underwriters an option, exercisable for 30 days after the date of this prospectus, to purchase up to 172,200 additional common units at the public offering price, less the underwriting discount set forth on the cover page of this prospectus, solely to cover over-allotments.
To the extent the underwriters exercise such option, each underwriter will become obligated, subject to certain conditions, to purchase approximately the same percentage of such additional units as the number set forth next to such underwriter's name in the preceding table bears to the total number of units in the table, and we will be obligated, pursuant to the option, to sell such units to the underwriters.
We, our general partner, the directors and executive officers of the general partner, certain other affiliates and the selling unitholders have agreed that during the 90 days after the date of this prospectus, they will not, without the prior written consent of A.G. Edwards & Sons, Inc., directly or indirectly, offer for sale, contract to sell, sell, distribute, grant any option, right or warrant to purchase, pledge, hypothecate or otherwise dispose of any common units, any securities convertible into, or exercisable or exchangeable for, common units or any other rights to acquire such common units, other than (1) pursuant to employee benefit plans as in existence as of the date of this prospectus or (2) in connection with accretive acquisitions of assets or businesses in which common units are issued as consideration;provided, however, that with respect to clause (2), any recipient of common units will furnish to A.G. Edwards & Sons, Inc. a letter agreeing to be bound by these provisions for the remainder of the 90 day period.
A.G. Edwards & Sons, Inc. may, in its sole discretion, allow any of these parties to offer for sale, contract to sell, sell, distribute, grant any option, right or warrant to purchase, pledge, hypothecate or otherwise dispose of any common units, any securities convertible into, or exercisable or exchangeable for, common units or any other rights to acquire such common units prior to the expiration of such 90-day period in whole or in part at anytime without notice. A.G. Edwards & Sons, Inc. has informed
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us that in the event that consent to a waiver of these restrictions is requested by us or any other person, A.G. Edwards & Sons, Inc., in deciding whether to grant its consent, will consider, among other factors, the unitholder's reasons for requesting the release, the number of units for which the release is being requested, and market conditions at the time of the request for such release. However, A.G. Edwards & Sons, Inc. has informed us that as of the date of this prospectus there are no agreements between A.G. Edwards & Sons, Inc. and any party that would allow such party to transfer any common units, nor does it have any intention of releasing any of the common units subject to the lock-up agreements prior to the expiration of the lock-up period at this time.
The following table summarizes the discounts that we and the selling unitholders will pay to the underwriters in the offering. These amounts assume both no exercise and full exercise of the underwriters' option to purchase additional common units.
| No Exercise | Full Exercise | ||||
---|---|---|---|---|---|---|
Per Unit | $ | $ | ||||
Total | $ | $ |
In addition, we expect to incur expenses of approximately $700,000 in connection with this offering.
MarkWest Hydrocarbon, MarkWest Energy Partners, our general partner, the operating company and certain other parties and the selling unitholders have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act.
In connection with this offering, the underwriters may engage in stabilizing transactions, over-allotment transactions, syndicate covering transactions and penalty bids in accordance with Regulation M under the Securities Exchange Act of 1934.
- •
- Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum.
- •
- Over-allotment transactions involve sales by the underwriters of the common units in excess of the number of units the underwriters are obligated to purchase, which creates a syndicate short position. The short position may be either a covered short position or a naked short position. In a covered short position, the number of units over-allotted by the underwriters is not greater than the number of units they may purchase in the over-allotment option. In a naked short position, the number of units involved is greater than the number of units in the over-allotment option. The underwriters may close out any short position by either exercising their over-allotment option and/or purchasing common units in the open market.
- •
- Syndicate covering transactions involve purchases of the common units in the open market after the distribution has been completed in order to cover syndicate short positions. In determining the source of the common units to close out the short position, the underwriters will consider, among other things, the price of common units available for purchase in the open market as compared to the price at which they may purchase common units through the over-allotment option. If the underwriters sell more common units than could be covered by the over-allotment option, a naked short position, the position can only be closed out by buying common units in the open market. A naked short position is more likely to be created if the underwriters are concerned that there could be downward pressure on the price of the common units in the open market after pricing that could adversely affect investors who purchase in the offering.
- •
- Penalty bids permit the representatives to reclaim a selling concession from a syndicate member when the common units originally sold by the syndicate member are purchased in a stabilizing or syndicate covering transaction to cover syndicate short positions.
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Similar to other purchase transactions, the underwriters' purchases to cover the syndicate short sales may have the effect of raising or maintaining the market price of the common units or preventing or retarding a decline in the market price of the common units. As a result, the price of the common units may be higher than the price that might otherwise exist in the open market.
The underwriters will deliver a prospectus to all purchasers of common units in the short sales. The purchasers of common units in short sales are entitled to the same remedies under the federal securities laws as any other purchaser of common units covered by this prospectus.
The underwriters are not obligated to engage in any of the transactions described above. If they do engage in any of these transactions, they may discontinue them at any time.
Neither we, nor the underwriters make any representation or prediction as to the direction or magnitude of any effect that the transactions described above may have on the price of the common units. In addition, neither we nor the underwriters make any representation that the underwriters will engage in these transactions or that these transactions, once commenced, will not be discontinued without notice.
Because the National Association for Securities Dealers, Inc. views the common units offered hereby as interests in a direct participation program, the offering is being made in compliance with Rule 2810 of the NASD's Conduct Rules. Investor suitability with respect to the common units should be judged similarly to the suitability with respect to other securities that are listed for trading on a national securities exchange.
No sales to accounts of which the underwriter exercises discretionary authority may be made without the prior written approval of the customer.
Royal Bank of Canada, an affiliate of RBC Dain Rauscher Inc., which is one of the underwriters, is administrative agent and one of the lenders under our credit facility, for which it received customary compensation. The proceeds of this offering will be used to repay a portion of this indebtedness. A.G. Edwards & Sons, Inc., RBC Dain Rauscher Inc. and McDonald Investments Inc. were underwriters in our initial public offering that closed on May 24, 2002. The underwriters may, from time to time, engage in transactions with or perform services for us in the ordinary course of business.
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The validity of the common units will be passed upon for us by Vinson & Elkins L.L.P., Houston, Texas. Certain legal matters in connection with the common units offered hereby will be passed upon for the underwriters by Baker Botts L.L.P., Houston, Texas.
The combined financial statements of MarkWest Hydrocarbon Midstream Business as of December 31, 2001, and for each of the two years in the period ended December 31, 2001 and the consolidated financial statements of MarkWest Energy Partners, L.P. as of December 31, 2002 and for the year then ended and the balance sheet of MarkWest Energy GP, L.L.C. as of December 31, 2002, included in this Prospectus have been so included in reliance on the report of PricewaterhouseCoopers LLP, independent accountants given on the authority of said firm as experts in auditing and accounting.
The consolidated financial statements of PNG Corporation and its subsidiaries as of December 31, 2002 and 2001, and for each of the three years in the period ended December 31, 2002, included in this Prospectus have been so included in reliance on the report of PricewaterhouseCoopers LLP, independent accountants, given on the authority of said firm as experts in accounting and auditing.
The financial statements of Michigan Crude Oil Pipeline System as of December 31, 2001 and 2002, and for each of the two years in the period ended December 31, 2001, and for the period from January 1, 2002 through February 13, 2002 and the period from February 14, 2002 through December 31, 2002, included in this Prospectus have been so included in reliance on the report of PricewaterhouseCoopers LLP, independent accountants given on the authority of said firm as experts in auditing and accounting.
The financial statements of American Central Western Oklahoma Gas Company, L.L.C. as of December 31, 2002 and 2001, and for each of the three years in the period ended December 31, 2002, included in this Prospectus have been so included in reliance on the report of BKD, LLP, independent accountants given on the authority of said firm as experts in auditing and accounting.
WHERE YOU CAN FIND MORE INFORMATION
We have filed with the Securities and Exchange Commission a registration statement on Form S-l regarding the common units. This prospectus does not contain all of the information found in the registration statement. For further information regarding MarkWest Energy Partners, L.P. and the common units offered by this prospectus, you may desire to review the full registration statement, including its exhibits and schedules, filed under the Securities Act of 1933. The registration statement of which this prospectus forms a part, including its exhibits and schedules, may be inspected and copied at the public reference room maintained by the SEC at Room 1024, 450 Fifth Street, N.W., Washington, D.C. 20549. Copies of the materials may also be obtained from the SEC at prescribed rates by writing to the public reference room maintained by the SEC at Room 1024, Judiciary Plaza, 450 Fifth Street, N.W., Washington, D.C. 20549. You may obtain information on the operation of this public reference room by calling the SEC at l-800-SEC-0330.
The SEC maintains a World Wide Web site on the Internet at http://www.sec.gov. Our registration statement, of which this prospectus constitutes a part, can be downloaded from the SEC's web site and can also be inspected and copied at the offices of the American Stock Exchange at 86 Trinity Place, Manhattan, New York 10006.
We furnish our unitholders with annual reports containing our audited financial statements and furnish or make available quarterly reports containing our unaudited interim financial information for the first three fiscal quarters of each fiscal year.
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Statements included in this prospectus which are not historical facts (including any statements concerning plans and objectives of management for future operations or economic performance, or assumptions related thereto) are forward-looking statements. In addition, we and our representatives may from time to time make other oral or written statements which are also forward-looking statements.
These forward-looking statements are made based upon management's current plans, expectations, estimates, assumptions and beliefs concerning future events impacting us and therefore involve a number of risks and uncertainties. We caution that forward-looking statements are not guarantees and that actual results could differ materially from those expressed or implied in the forward-looking statements.
Important factors that could cause our actual results of operations or our actual financial condition to differ include, but are not necessarily limited to:
- •
- the availability of raw natural gas supply for our gathering and processing services;
- •
- the availability of NGLs for our transportation, fractionation and storage services;
- •
- our dependence on certain significant customers, producers, gatherers, treaters, and transporters of natural gas, including MarkWest Hydrocarbon, Inc.;
- •
- the risks that third-party natural gas exploration and production activities will not occur or be successful;
- •
- prices of NGL products and crude oil, including the effectiveness of any hedging activities, and indirectly by natural gas prices;
- •
- competition from other NGL processors, including major energy companies;
- •
- changes in general economic conditions in regions in which our products are located;
- •
- our ability to identify and consummate grass roots projects or acquisitions complementary to our business; and
- •
- our ability to integrate our acquisitions.
Many of such factors are beyond our ability to control or predict. Investors are cautioned not to put undue reliance on forward-looking statements. When considering our forward-looking statements, you should keep in mind the risk factors described in the "Risk Factors" section of this prospectus. These risk factors could cause our actual results to differ materially from those contained in any forward-looking statement. We will not update our forward-looking statements unless applicable securities laws require us to do so.
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F-1
REPORT OF INDEPENDENT AUDITORS
To the Board of Directors of MarkWest Energy GP, L.L.C.
In our opinion, the accompanying consolidated and combined balance sheets and the related consolidated and combined statements of operations, of cash flows and of changes in capital present fairly, in all material respects, the financial position of MarkWest Energy Partners, L.P., a Delaware partnership (the Partnership), and its subsidiaries at December 31, 2002 and the results of their operations and their cash flows for the year ended December 31, 2002 and the financial position of the MarkWest Hydrocarbon Midstream Business at December 31, 2001, and for each of the two years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Partnership'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 auditing standards generally accepted in the United States of America, 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 our opinion.
As described in Note 15 to the consolidated and combined financial statements, the Partnership has restated its consolidated and combined statements of operations, of cash flows and of changes in capital for the year ended December 31, 2002 and the presentation of basic and diluted net income per limited partner unit for the years ended December 31, 2001 and 2000.
/s/ PricewaterhouseCoopers LLP
Denver, Colorado
February 12, 2003, except for Note 14,
as to which the date is March 25, 2003 and, except for
Note 15, as to which the date is
January 10, 2004
F-2
MARKWEST ENERGY PARTNERS, L.P.
CONSOLIDATED AND COMBINED BALANCE SHEETS
(in thousands)
| December 31, 2002 (Partnership) | December 31, 2001 (MarkWest Hydrocarbon Midstream Business) | |||||||
---|---|---|---|---|---|---|---|---|---|
ASSETS | |||||||||
Current assets: | |||||||||
Cash and cash equivalents | $ | 2,776 | $ | — | |||||
Receivables | 976 | 8,538 | |||||||
Receivables from affiliate | 2,847 | — | |||||||
Inventories | 130 | 4,968 | |||||||
Prepaid replacement natural gas | — | 8,081 | |||||||
Risk management asset | — | 1,204 | |||||||
Other assets | 336 | 92 | |||||||
Total current assets | 7,065 | 22,883 | |||||||
Property, plant and equipment: | |||||||||
Gas gathering facilities | 34,398 | 34,386 | |||||||
Gas processing plants | 47,403 | 41,647 | |||||||
Fractionation and storage facilities | 22,076 | 18,730 | |||||||
NGL transportation facilities | 4,402 | 4,402 | |||||||
Land, building and other equipment | 3,021 | 2,977 | |||||||
Construction in progress | 348 | 6,758 | |||||||
111,648 | 108,900 | ||||||||
Less: Accumulated depreciation | (31,824 | ) | (26,892 | ) | |||||
Total property, plant and equipment, net | 79,824 | 82,008 | |||||||
Deferred financing costs, net of amortization of $291 | 820 | — | |||||||
Total assets | $ | 87,709 | $ | 104,891 | |||||
LIABILITIES AND CAPITAL | |||||||||
Current liabilities: | |||||||||
Accounts payable | $ | 1,199 | $ | 3,946 | |||||
Payables to affiliate | 723 | — | |||||||
Accrued liabilities | 2,880 | 697 | |||||||
Risk management liability | 501 | — | |||||||
Total current liabilities | 5,303 | 4,643 | |||||||
Deferred income taxes | — | 15,640 | |||||||
Debt due to parent | — | 19,179 | |||||||
Long-term debt | 21,400 | — | |||||||
Risk management liability | 143 | — | |||||||
Commitments and contingencies (Note 10) | |||||||||
Capital: | |||||||||
Partners' capital | 61,574 | — | |||||||
Net parent investment | — | 64,461 | |||||||
Accumulated other comprehensive income (loss) | (711 | ) | 968 | ||||||
Total capital | 60,863 | 65,429 | |||||||
Total liabilities and capital | $ | 87,709 | $ | 104,891 | |||||
The accompanying notes are an integral part of these financial statements.
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MARKWEST ENERGY PARTNERS, L.P.
CONSOLIDATED AND COMBINED STATEMENTS OF OPERATIONS
(in thousands, except per unit amounts)
| Year Ended December 31, 2002 (As Restated. See Note 15) | Year Ended December 31, 2001 (MarkWest Hydrocarbon Midstream Business) | Year Ended December 31, 2000 (MarkWest Hydrocarbon Midstream Business) | |||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|
Revenues: | ||||||||||||
Sales to affiliates | $ | 26,093 | $ | — | $ | — | ||||||
Sales to unaffiliated parties | 44,153 | 93,675 | 109,810 | |||||||||
Total revenues | 70,246 | 93,675 | 109,810 | |||||||||
Operating expenses: | ||||||||||||
Purchased product costs | 38,906 | 65,483 | 71,341 | |||||||||
Facility expenses | 15,101 | 13,138 | 13,224 | |||||||||
Selling, general and administrative expenses | 5,283 | 5,047 | 4,733 | |||||||||
Depreciation | 4,980 | 4,490 | 4,341 | |||||||||
Total operating expenses | 64,270 | 88,158 | 93,639 | |||||||||
Income from operations | 5,976 | 5,517 | 16,171 | |||||||||
Other income and (expenses): | ||||||||||||
Interest expense, net | (1,414 | ) | (1,307 | ) | (1,697 | ) | ||||||
Miscellaneous income | 52 | — | — | |||||||||
Income before income taxes | 4,614 | 4,210 | 14,474 | |||||||||
Provision (benefit) for income taxes: | ||||||||||||
Current due to (from) parent | (1,535 | ) | (1,468 | ) | 2,854 | |||||||
Deferred | (15,640 | ) | 3,092 | 2,839 | ||||||||
Provision (benefit) for income taxes | (17,175 | ) | 1,624 | 5,693 | ||||||||
Net income | $ | 21,789 | $ | 2,586 | $ | 8,781 | ||||||
General partner's interest in net income | $ | 89 | $ | — | $ | — | ||||||
Limited partners' interest in net income | $ | 21,700 | $ | 2,586 | $ | 8,781 | ||||||
Basic net income per limited partner unit(1) | $ | 4.86 | $ | 0.86 | $ | 2.93 | ||||||
Diluted net income per limited partner unit(1) | $ | 4.83 | $ | 0.86 | $ | 2.93 | ||||||
Weighted average units outstanding: | ||||||||||||
Basic(1) | 4,469 | 3,000 | 3,000 | |||||||||
Diluted(1) | 4,493 | 3,000 | 3,000 | |||||||||
- (1)
- As Restated. See Note 15.
The accompanying notes are an integral part of these financial statements.
F-4
MARKWEST ENERGY PARTNERS, L.P.
CONSOLIDATED AND COMBINED STATEMENTS OF CASH FLOWS
(in thousands)
| Year Ended December 31, 2002 (As Restated. See Note 15) | Year Ended December 31, 2001 (MarkWest Hydrocarbon Midstream Business) | Year Ended December 31, 2000 (MarkWest Hydrocarbon Midstream Business) | ||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Cash flows from operating activities: | |||||||||||||
Net income | $ | 21,789 | $ | 2,586 | $ | 8,781 | |||||||
Adjustments to reconcile net income to net cash provided by operating activities: | |||||||||||||
Depreciation | 4,980 | 4,490 | 4,341 | ||||||||||
Amortization of deferred financing costs included in interest expense | 291 | — | — | ||||||||||
Deferred income taxes | (15,640 | ) | 3,092 | 2,839 | |||||||||
Other | (293 | ) | 48 | — | |||||||||
Changes in operating assets and liabilities, net of working capital assumed: | |||||||||||||
(Increase) decrease in receivables | (43 | ) | 5,018 | (7,183 | ) | ||||||||
(Increase) decrease in inventories | 2,333 | (726 | ) | (1,492 | ) | ||||||||
(Increase) decrease in prepaid replacement natural gas and other assets | 4,933 | (7,952 | ) | 1,737 | |||||||||
Increase (decrease) in accounts payable and accrued liabilities | 12,062 | (7,080 | ) | 4,974 | |||||||||
Increase in long-term replacement natural gas payable | 3,090 | — | — | ||||||||||
Net cash provided by (used in) operating activities | 33,502 | (524 | ) | 13,997 | |||||||||
Cash flows from investing activities: | |||||||||||||
Capital expenditures | (2,145 | ) | (9,651 | ) | (12,147 | ) | |||||||
Proceeds from sale of assets | 89 | 654 | — | ||||||||||
Net cash used in investing activities | (2,056 | ) | (8,997 | ) | (12,147 | ) | |||||||
Cash flows from financing activities: | |||||||||||||
Proceeds from initial public offering, net | 43,625 | — | — | ||||||||||
Distribution to MarkWest Hydrocarbon | (63,476 | ) | — | — | |||||||||
Distributions to unitholders | (3,923 | ) | — | — | |||||||||
Payments for debt issuance costs | (1,111 | ) | — | — | |||||||||
Proceeds from long-term debt | 23,400 | — | — | ||||||||||
Repayment of long-term debt | (2,000 | ) | — | — | |||||||||
Net advances from (distributions to) parent | (24,218 | ) | 11,124 | (4,676 | ) | ||||||||
Debt due to (from) parent | (967 | ) | (1,603 | ) | 2,826 | ||||||||
Net cash provided by (used in) financing activities | (28,670 | ) | 9,521 | (1,850 | ) | ||||||||
Net increase (decrease) in cash | 2,776 | — | — | ||||||||||
Cash and cash equivalents at beginning of period | — | — | — | ||||||||||
Cash and cash equivalents at end of period | $ | 2,776 | $ | — | $ | — | |||||||
The accompanying notes are an integral part of these financial statements.
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MARKWEST ENERGY PARTNERS, L.P.
CONSOLIDATED AND COMBINED STATEMENTS OF CHANGES IN CAPITAL
(in thousands)
| | | PARTNERS' CAPITAL | |||||||||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| | | | | | | General Partner | | ||||||||||||||||||
| | | Limited Partners | | ||||||||||||||||||||||
| Net Parent Investment | Accumulated Other Comprehensive Income | | |||||||||||||||||||||||
| Common | Subordinated | | | ||||||||||||||||||||||
| $ | $ | Units | $ | Units | $ | $ | Total | ||||||||||||||||||
Balance, December 31, 1999 | $ | 46,646 | $ | — | — | $ | — | — | $ | — | $ | — | $ | 46,646 | ||||||||||||
Net income | 8,781 | — | — | — | — | — | — | 8,781 | ||||||||||||||||||
Net change in parent advances | (4,676 | ) | — | — | — | — | — | — | (4,676 | ) | ||||||||||||||||
Balance, December 31, 2000 | 50,751 | — | — | — | — | — | — | 50,751 | ||||||||||||||||||
Comprehensive income: | ||||||||||||||||||||||||||
Net income | 2,586 | — | — | — | — | — | — | 2,586 | ||||||||||||||||||
Other comprehensive income: | ||||||||||||||||||||||||||
Cumulative effect of change in accounting principle, net of tax | — | 1,328 | — | — | — | — | — | 1,328 | ||||||||||||||||||
Risk management activities, net of tax | — | (360 | ) | — | — | — | — | — | (360 | ) | ||||||||||||||||
Ending accumulated derivative gain | 968 | |||||||||||||||||||||||||
Comprehensive income | 3,554 | |||||||||||||||||||||||||
Net change in parent advances | 11,124 | — | — | — | — | — | — | 11,124 | ||||||||||||||||||
Balance, December 31, 2001 | 64,461 | 968 | — | — | — | — | — | 65,429 | ||||||||||||||||||
Net income applicable to the period from January 1 through May 23, 2002(1) | 17,332 | — | — | — | — | — | — | 17,332 | ||||||||||||||||||
Net change in parent advances | (24,218 | ) | — | — | — | — | — | — | (24,218 | ) | ||||||||||||||||
Adjustment to reflect net liabilities not assumed by the Partnership(1) | 23,316 | — | — | — | — | — | — | 23,316 | ||||||||||||||||||
Book value of net assets contributed by MarkWest Hydrocarbon to the Partnership(1) | (80,891 | ) | — | — | — | 3,000 | 79,273 | 1,618 | — | |||||||||||||||||
Distribution to MarkWest Hydrocarbon(1) | — | — | — | — | — | (62,206 | ) | (1,270 | ) | (63,476 | ) | |||||||||||||||
Issuance of units to public (including underwriter over-allotment), net of offering and other costs | — | — | 2,415 | 43,625 | — | — | — | 43,625 | ||||||||||||||||||
Distributions to unitholders | — | — | — | (1,715 | ) | — | (2,130 | ) | (78 | ) | (3,923 | ) | ||||||||||||||
Net income applicable to the period from May 24 through December 31, 2002 | — | — | — | 1,948 | — | 2,420 | 89 | 4,457 | ||||||||||||||||||
Risk management activities | — | (1,679 | ) | — | — | — | — | — | (1,679 | ) | ||||||||||||||||
Balance at December 31, 2002 | $ | — | $ | (711 | ) | 2,415 | $ | 43,858 | 3,000 | $ | 17,357 | $ | 359 | $ | 60,863 | |||||||||||
- (1)
- As Restated. See Note 15.
The accompanying notes are an integral part of these financial statements.
F-6
MARKWEST ENERGY PARTNERS, L.P.
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
1. Organization
MarkWest Energy Partners, L.P. (the Partnership) was formed on January 25, 2002 as a Delaware limited partnership. The Partnership and its subsidiary, MarkWest Energy Operating Company, L.L.C. (the Operating Company), were formed to acquire, own and operate most of the assets, liabilities and operations of MarkWest Hydrocarbon Midstream Business.
On May 24, 2002, MarkWest Hydrocarbon, Inc. (MarkWest Hydrocarbon), through its subsidiaries, MarkWest Energy GP, L.L.C., the general partner of the Partnership, and MarkWest Michigan, Inc., conveyed the MarkWest Hydrocarbon Midstream Business to the Partnership in exchange for:
- •
- 3,000,000 subordinated units;
- •
- A 2% general partner interest in the Partnership;
- •
- Incentive distribution rights (as defined in the Partnership Agreement);
- •
- The direct and indirect assumption of certain liabilities by the Partnership, including $1.8 million in working capital liabilities and $19.4 million of indebtedness;
- •
- The right to be reimbursed by the Partnership for $15.6 million of capital expenditures; and
- •
- The right to receive $26.7 million in cash upon the closing of the Initial Public Offering ("IPO") and the Operating Company's new $60 million credit facility. The Operating Company is a wholly owned subsidiary of the Partnership.
The transfer of assets and liabilities to the Partnership from MarkWest Hydrocarbon represented a reorganization of entities under common control and was recorded at historical cost.
The Partnership concurrently issued 2,415,000 common units in its IPO (including 315,000 units issued pursuant to the underwriters' over-allotment option), representing a 43.7% limited partnership interest in the Partnership, at a price of $20.50 per unit. The Operating Company concurrently entered into a $60 million credit facility with various lenders.
A summary of the proceeds received and use of proceeds is as follows (in thousands):
Proceeds received: | ||||
Sale of common units | $ | 49,508 | ||
Borrowing under term loan facility | 21,400 | |||
Use of proceeds: | ||||
Underwriters' fees | 3,466 | |||
Professional fees and other offering costs | 2,417 | |||
Debt issuance costs | 1,077 | |||
Repayment of assumed working capital liabilities | 1,800 | |||
Repayment of debt due to parent | 19,376 | |||
Reimbursement of capital expenditures to MarkWest Hydrocarbon | 15,600 | |||
Distribution to MarkWest Hydrocarbon | 26,700 | |||
Net proceeds remaining | $ | 472 | ||
F-7
2. Summary of Significant Accounting Policies
Basis of Presentation
The consolidated and combined financial statements include the accounts of the Partnership and the MarkWest Hydrocarbon Midstream Business and have been prepared in accordance with accounting principles generally accepted in the United States. Intercompany balances and transactions within the Partnership and MarkWest Hydrocarbon Midstream Business have been eliminated.
Prior to May 24, 2002, the date on which the MarkWest Hydrocarbon Midstream Business was conveyed to the Partnership (see Note 1) the financial statements include charges from MarkWest Hydrocarbon for direct costs and allocations of indirect corporate overhead as well as federal and state income tax provisions. Selling, general and administrative expenses for the MarkWest Hydrocarbon Midstream Business in 2000 and 2001 are comprised entirely of allocations of indirect corporate overhead from MarkWest Hydrocarbon. Management of the Partnership believes that the allocation methods are reasonable. Commencing with the conveyance of the MarkWest Hydrocarbon Midstream Business to the Partnership on May 24, 2002, the consolidated financial statements do not reflect any amounts for federal and state income taxes as the Partnership is not a taxable entity (see Note 8). However, the consolidated financial statements of the Partnership subsequent to May 24, 2002 do include charges from MarkWest Hydrocarbon for direct costs and allocation of indirect corporate overhead as more fully described in Note 3.
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.
Inventories
Product inventory consists primarily of finished energy products (propane, butane, isobutane, and natural gasoline) and is valued at the lower of weighted average cost or market. Materials and supplies are valued at the lower of average cost or estimated net realizable value.
Prepaid Replacement Natural Gas
Prepaid replacement natural gas consisted of natural gas purchased in advance of its actual use. It was valued using the first-in, first-out method.
Property, Plant and Equipment
�� Property, plant and equipment are 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 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: gas gathering and processing and NGL transportation, fractionation and storage facilities—20 years or the number of
F-8
years reserves behind our facilities are contractually dedicated, whichever is longer; buildings—40 years; furniture, leasehold improvements and other—3 to 10 years.
Impairment of Long-Lived Assets
In accordance with Statement of Financial Accounting Standards (SFAS) No. 144,Accounting for the Impairment or Disposal of Long-Lived Assets, the Partnership evaluates its long-lived assets, including related intangibles, of identifiable business activities for impairment when events or changes in circumstances indicate, in management's judgment, that the carrying value of such assets may not be recoverable. The determination of whether impairment has occurred is based on management's estimate of undiscounted future cash flows attributable to the assets as compared to the carrying value of the assets. If impairment has occurred, estimating the fair value for the assets and recording a provision for loss if the carrying value is greater than fair value determine the amount of the impairment recognized. For assets identified to be disposed of in the future, the carrying value of these assets is compared to the estimated fair value less the cost to sell to determine if impairment is required. Until the assets are disposed of, an estimate of the fair value is re-determined when related events or circumstances change. No impairment charges were recognized for any period presented.
Capitalization of Interest
We capitalize interest on major projects during construction. Interest is capitalized on borrowed funds. The interest rates used are based on the average interest rate on related debt.
Deferred Financing Costs
Deferred financing costs are amortized on a straight-line basis and charged to interest expense over the anticipated term of the associated agreement.
Commodity Price Risk Management Activities
Prior to January 1, 2001 and the implementation of SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities gains and losses on hedges of production were included in the carrying amount of the inventory and were ultimately recognized in purchased gas costs or sales when the related inventory was sold. Gains and losses related to qualifying hedges, as defined by SFAS No. 80, Accounting for Futures Contracts, of firm commitments or anticipated transactions (including hedges of equity production) were recognized in purchased gas costs or sales, as reported on the Consolidated Statement of Operations, when the hedged physical transaction occurred. For purposes of the Consolidated Statement of Cash Flows, all hedging gains and losses were classified in net cash provided by operating activities.
In June 1998, SFAS No. 133 was issued effective for fiscal years beginning after June 15, 2000. Under SFAS No. 133, which was subsequently amended by SFAS No. 138, we are required to recognize the change in the market value of all derivatives as either assets or liabilities in our Balance Sheet and measure those instruments at fair value. Changes in the fair value of derivatives are recorded each period in current earnings or other comprehensive income depending upon the nature of the underlying transaction.
See also Notes 6 and 7.
F-9
Fair Value of Financial Instruments
Our financial instruments consist of receivables, accounts payable and other current liabilities and debt. Except for debt, the carrying amounts of financial instruments approximate fair value due to their short maturities. At December 31, 2002 and 2001, based on rates available for similar types of debt, the fair value of our debt was not materially different from its carrying amount.
Net Parent Investment
The net parent investment represents a net balance as the result of various transactions between the MarkWest Hydrocarbon Midstream Business and MarkWest Hydrocarbon. There were no terms of settlement or interest charges associated with this balance. The balance was the result of the MarkWest Hydrocarbon Midstream Business's participation in MarkWest Hydrocarbon's central cash management program, wherein all of the MarkWest Hydrocarbon Midstream Business's cash receipts were remitted to MarkWest Hydrocarbon and all cash disbursements were funded by MarkWest Hydrocarbon. Other transactions included intercompany transportation and terminating revenues and related expenses, administrative and support expenses incurred by MarkWest Hydrocarbon and allocated to the MarkWest Hydrocarbon Midstream Business, and accrued interest and income taxes.
Revenue Recognition
Gas gathering and processing and NGL fractionation, transportation and storage revenues are recognized as volumes are processed, fractionated, transported and stored in accordance with contractual terms. Revenue for NGL product sales is recognized at the time the title is transferred.
Income Taxes
The Partnership is not a taxable entity. The MarkWest Hydrocarbon Midstream Business's operations were included in MarkWest Hydrocarbon's consolidated federal and state income tax returns. The MarkWest Hydrocarbon Midstream Business's income tax provisions were computed as though separate returns were filed up to the date of the formation of the Partnership. The MarkWest Hydrocarbon Midstream Business accounted for income taxes in accordance with the provisions of SFAS No. 109,Accounting for Income Taxes. This statement requires a company to recognize deferred tax liabilities and assets for the expected future tax consequences of events that have been recognized in a company's financial statements or tax returns. Using this method, deferred tax liabilities and assets were determined based on the difference between the financial statement carrying amounts and tax bases of assets and liabilities using enacted tax rates.
Stock and Unit Compensation
As permitted under SFAS No. 123,Accounting for Stock-Based Compensation, we have elected to continue to measure compensation costs for unit-based and stock-based employee compensation plans as prescribed by Accounting Principles Board Opinion No. 25,Accounting for Stock Issued to Employees. We have a variable plan and certain employees of MarkWest Hydrocarbon dedicated to or otherwise principally supporting MarkWest Energy Partners received stock-based compensation awards from MarkWest Hydrocarbon. These plans are described more fully in Note 9. We account for these plans using variable and fixed accounting as appropriate. Compensation expense for the variable plan,
F-10
including restricted unit grants, is measured using the market price of MarkWest Energy Partners' common units on the date the number of units in the grant becomes determinable and is amortized into earnings over the period of service. MarkWest Hydrocarbon stock options are issued under a fixed plan. Accordingly, compensation expense is not recognized for stock options unless the options were granted at an exercise price lower than market on the grant date.
Had compensation cost for those employees principally supporting the Partnership who participated in MarkWest Hydrocarbon's stock-based compensation plan been determined based on the fair value at the grant dates under the plan consistent with the method prescribed by SFAS No. 123, our net income and net income per limited partner unit would have been affected as follows:
| Year Ended December 31, 2002 (As Restated. See Note 15) | Year Ended December 31, 2001 (MarkWest Hydrocarbon Midstream Business) | Year Ended December 31, 2000 (MarkWest Hydrocarbon Midstream Business) | ||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
| (in thousands) | ||||||||||
Net income, as reported | $ | 21,789 | $ | 2,586 | $ | 8,781 | |||||
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects | (184 | ) | (248 | ) | (218 | ) | |||||
Pro forma net income | $ | 21,605 | $ | 2,338 | $ | 8,563 | |||||
Net income per limited partner unit:(1) | |||||||||||
Basic—as reported | $ | 4.86 | $ | 0.86 | $ | 2.93 | |||||
Basic—pro forma | $ | 4.81 | $ | 0.78 | $ | 2.85 | |||||
Diluted—as reported | $ | 4.83 | $ | 0.86 | $ | 2.93 | |||||
Diluted—pro forma | $ | 4.79 | $ | 0.78 | $ | 2.85 |
- (1)
- As Restated. See Note 15.
Segment Reporting
We operate in only one segment, the midstream services segment of the oil and gas industry.
Recent Accounting Pronouncements
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 did not have a material impact on the Partnership's financial position or results of operations.
In June 2001, the FASB issued SFAS No. 143,Accounting for Asset Retirement Obligations, which addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. The standard applies to legal obligations
F-11
associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset. SFAS No. 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset and this additional carrying amount is depreciated over the life of the asset. The liability is accreted at the end of each period through charges to operating expense. If the obligation is settled for other than the carrying amount of the liability, a gain or loss is recognized on settlement. The provisions of this statement are effective for fiscal years beginning after June 15, 2002. With respect to our midstream services, we have certain surface facilities with ground leases requiring us to dismantle and remove these facilities upon the termination of the applicable lease. We anticipate recording a liability, if one can be reasonably estimated, for such obligations in the first quarter of 2003.
In January 2002, the FASB Emerging Issues Task Force released Issue No. 02-3,Issues Related to Accounting for Contracts Involved in Energy Trading and Risk Management Activities. The Task Force reached a consensus to rescind EITF Issue No. 98-10,Accounting for Contracts Involved in Energy Trading and Risk Management Activities, the impact of which is preclude mark-to-market accounting for all energy trading contracts not within the scope of FASB Statement No. 133,Accounting for Derivative Instruments and Hedging Activities. The Task Force also reached a consensus that gains and losses on derivative instruments within the scope of Statement 133 should be shown net in the income statement if the derivative instruments are held for trading purposes. The consensus regarding the rescission of Issue 98-10 is applicable for fiscal periods beginning after December 15, 2002. We do not have any trading activities and did not account for any contracts as trading contracts in accordance with EITF Issue No. 98-10. Therefore, the EITF consensus to rescind EITF Issue No. 98-10 will not have an impact on our financial position or results of operations.
In April 2002, the FASB issued SFAS No. 145,Rescission of SFAS Nos. 4, 44 and 64; Amendment of SFAS Statement No. 13; and Technical Corrections, which is generally effective for transactions occurring after May 15, 2002. Through the rescission of SFAS Nos. 4 and 64, SFAS No. 145 eliminates the requirement that gains and losses from extinguishments of debt be aggregated and, if material, be classified as an extraordinary item net of any income tax effect. SFAS No. 145 made several other technical corrections to existing pronouncements that may change accounting practice. SFAS No. 145 did not impact on our results of operations or financial position.
In June 2002, the FASB issued SFAS No. 146,Accounting for Costs Associated with Exit or Disposal Activities. SFAS No. 146 is effective for exit or disposal activities that are initiated after December 31, 2002. This Statement addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies EITF Issue No. 94-3,Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring). We do not believe that the adoption of SFAS No. 146 will have a material impact on our results of operations or financial position.
In November 2002, FASB Interpretation No. 45,Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others (FIN 45), was issued. The accounting recognition provisions of FIN 45 are effective January 1, 2003 on a prospective basis. They require that a guarantor recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. Under prior accounting principles, a
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guarantee would not have been recognized as a liability until a loss was probable and reasonably estimable. As FIN 45 only applies to prospective transactions, we are unable to determine the impact, if any, that adoption of the accounting recognition provisions of FIN 45 would have on our future financial position or results of operations.
In January of 2003, the FASB issued Interpretation No. 46,Consolidation of Variable Interest Entities, an interpretation of ARB No. 51 (FIN 46), which requires the consolidation of certain variable interest entities, as defined. FIN 46 is effective immediately for variable interest entities created after January 31, 2003, and on July 1, 2003 for investments in variable interest entities acquired before February 1, 2003; however, disclosures are required currently if a company expects to consolidate any variable interest entities. We do not have investments in any variable interest entities, and therefore, the adoption of FIN 46 is not expected to have an impact on our results of operations, financial position or cash flows.
3. Related Party Transactions
Prior to the conveyance of the MarkWest Hydrocarbon Midstream Business to the Partnership, substantially all transactions with MarkWest Hydrocarbon and its subsidiaries were settled immediately through the net parent investment account. Subsequent to the conveyance, normal trade terms apply to transactions with MarkWest Hydrocarbon as contained in various agreements discussed below which were entered into concurrent with the conveyance.
Receivable from Affiliate
Affiliated revenues in the consolidated and combined statements of income consist of service fees and NGL product sales. Concurrent with the closing of the IPO, we entered into a number of contracts with MarkWest Hydrocarbon. Specifically, we entered into:
- •
- A gas processing agreement pursuant to which MarkWest Hydrocarbon delivers to us all natural gas it receives from Columbia Gas Transmission Corporation for processing at our processing plants. MarkWest Hydrocarbon pays us a monthly fee based on the natural gas volumes delivered to us for processing.
- •
- A transportation agreement pursuant to which MarkWest Hydrocarbon delivers all of its NGLs to us for transportation through our pipelines to our Siloam fractionator. MarkWest Hydrocarbon pays us a monthly fee based on the number of gallons delivered to us for transportation.
- •
- A fractionation agreement pursuant to which MarkWest Hydrocarbon delivers all of its NGLs to us for unloading, fractionation, loading and storage at our Siloam facility. MarkWest Hydrocarbon pays us a monthly fee based on the number of gallons delivered to us for fractionation, a percentage of the proceeds from the sale of a portion of the NGL products produced, an annual storage fee, and a monthly fee based on the number of gallons of NGLs unloaded; and
- •
- A natural gas liquids purchase agreement pursuant to which MarkWest Hydrocarbon receives and purchases, and we deliver and sell, all of the NGL products we produce pursuant to our gas processing agreement with a third party. Under the terms of this agreement, MarkWest
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Hydrocarbon pays us a purchase price equal to the proceeds it receives from the resale to third parties of such NGL products. This contract also applies to any other NGL products we acquire. We retain a percentage of the proceeds attributable to the sale of the NGL products we produce pursuant to our agreement with a third party, and remit the balance from such NGL products sale proceeds to this third party.
Payable to Affiliate
MarkWest Hydrocarbon provides centralized corporate functions such as accounting, treasury, engineering, information technology, insurance and other corporate services, which are included in selling, general and administrative expenses. We reimburse MarkWest Hydrocarbon monthly for the selling, general and administrative support MarkWest Hydrocarbon allocates to us. MarkWest Hydrocarbon has allocated to the Partnership approximately $2.2 million (during the period from January 1, 2002 to May 23, 2002) and $1.9 million (during the period from May 24, 2002 to December 31, 2002) of these costs which are included in selling, general and administrative expenses.
The Partnership is also reimbursing MarkWest Hydrocarbon for the salaries and employee benefits, such as 401(k), pension, and health insurance, of plant operating personnel as well as other direct operating expenses. For the year ended December 31, 2002, these costs totaled $2.6 million and appear in plant operating expenses. The Partnership has no employees.
In Michigan, we assumed the MarkWest Hydrocarbon Midstream Business's existing contracts and gather and process gas directly for those third parties. We receive 100% of all fee and percent-of-proceeds consideration for the first 10 MMcf/d that we gather in Michigan. MarkWest Hydrocarbon retains a 70% net profit interest in the gathering and processing income we earn on quarterly Michigan pipeline throughput in excess of 10 MMcf/d. For year ended December 31, 2002, MarkWest Hydrocarbon's net profit interest was $0.4 million and is included in plant operating and other expenses.
Debt Due to Affiliate
Prior to the IPO, the MarkWest Hydrocarbon Midstream Business financed its working capital requirements and its capital expenditures through intercompany accounts between the MarkWest Hydrocarbon Midstream Business and MarkWest Hydrocarbon. Effective October 12, 2001, MarkWest Hydrocarbon formalized the terms under which certain intercompany accounts would be settled between the MarkWest Hydrocarbon Midstream Business and MarkWest Hydrocarbon. Interest on the outstanding balance was charged annually based on MarkWest Hydrocarbon's average borrowing rate from a third party. Interest charges were settled through the net parent investment account. Interest was charged at a weighted average rate of 6.3% and 6.5% for the period from January 1, 2002 through May 23, 2002, and the year ended December 31, 2001, respectively. On May 24, 2002, debt due to MarkWest Hydrocarbon was assumed by the Partnership and paid in full with proceeds from the IPO.
4. Debt
In connection with our IPO, the Operating Company, a wholly owned subsidiary of the Partnership, entered into a $60 million credit facility (the Partnership Credit Facility) with various financial institutions. The Partnership Credit Facility was expanded by $15 million in March 2003. The
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Partnership Credit Facility is comprised of both a revolving and term loan credit facility. On December 1, we amended and restated the Partnership Credit Facility to increase the revolving credit facility, to eliminate the term loan facility and to extend the expiration date to November 30, 2006.
Under the revolving credit facility, up to $28.6 million is available to fund capital expenditures and acquisitions and up to $10 million is available for working capital purposes (including letters of credit) and to fund distributions to unitholders. However, not more than $2.25 million may be used in any four-quarter period to fund distributions to unitholders. At December 31, 2002, $21.4 million was outstanding under the Partnership Credit Facility. Total credit available to be drawn at December 31, 2002 was approximately $38.6 million.
The Operating Company may prepay all loans at any time without penalty. The Operating Partnership will be required to reduce all working capital borrowings under the revolving credit facility to zero for a period of at least 15 consecutive days once each calendar year.
Indebtedness under the credit facility bears interest, at the Operating Company's option, at either (i) the higher of the federal funds rate plus 0.50% or the prime rate as announced by lender plus an applicable margin of 0.375% to 1.375% or (ii) at a rate equal to LIBOR plus an applicable margin ranging from 1.75% per annum to 2.75% per annum depending on the Partnership's ratio of Funded Debt (as defined in the Partnership Credit Facility) to EBITDA (as defined in the Partnership Credit Facility) for the four most recently completed fiscal quarters. For the year ended December 31, 2002, the weighted average interest rate was 3.58%.
The Operating Company incurs a commitment fee on the unused portion of the credit facility at a rate ranging from 25.0 to 50.0 basis points based upon the ratio of our Funded Debt (as defined in the Partnership Credit Facility) to EBITDA (as defined in the Partnership Credit Facility) for the four most recently completed fiscal quarters. The Partnership Credit Facility matures in May 2005. At that time, both the revolving and term loan credit facilities will terminate and all outstanding amounts thereunder will be due and payable.
The Partnership Credit Facility contains various covenants limiting the Partnership's ability to:
- •
- Incur indebtedness;
- •
- Grant certain liens;
- •
- Make certain loans, acquisitions and investments;
- •
- Amend our material agreements, including agreements with MarkWest Hydrocarbon;
- •
- Acquire another company;
- •
- Enter into a merger, consolidation or sale of assets; or
- •
- Make distributions in excess of Available Cash (as defined in the Partnership Agreement) for the preceding fiscal quarter.
The Partnership Credit Facility also contains covenants requiring the Operating Company to maintain:
- •
- A ratio of not less than 3.50:1.00 of EBITDA to interest expense for the prior fiscal quarter;
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- •
- A ratio of not more than 3.50:1.00 of total debt to EBITDA for the prior fiscal quarter; and
- •
- A minimum net worth of $40 million, subject to adjustment for equity issuances.
�� The Partnership and the subsidiaries of the Operating Company serve as joint and several guarantors of any obligations under the Partnership Credit Facility. The guarantees are full and unconditional. The Partnership Credit Facility is secured by substantially all the assets of the Partnership and its subsidiaries.
Scheduled Debt Maturities
Scheduled debt maturities as of December 31, 2002, were as follows (in thousands):
2003 | $ | — | |
2004 | — | ||
2005 | 21,400 | ||
2006 | — | ||
2007 | — | ||
2008 and thereafter | — | ||
Total debt outstanding | $ | 21,400 | |
5. Significant Customers and Concentration of Credit Risk
For the year ended December 31, 2002, sales to MarkWest Hydrocarbon accounted for 37% of total revenues. For the year ended December 31, 2001, sales to two customers accounted for 16% and 10%, respectively, of total revenues. For the year ended December 31, 2000, sales to two customers accounted for 14% and 12%, respectively, of total revenues.
Financial instruments that potentially subject us to concentrations of credit risk consist principally of trade accounts receivable. Our primary customer is MarkWest Hydrocarbon. Consequently, matters affecting the business and financial condition of MarkWest Hydrocarbon—including its operations, management, customers, vendors and the like—have the potential to impact, both positively and negatively, our credit exposure. Outside of MarkWest Hydrocarbon, our customers are concentrated within the Appalachian basin and Michigan geographic areas and the retail propane, refining and petrochemical industries. Consequently, changes within these regions and/or industries also have the potential to impact, both positively and negatively, our credit exposure.
6. Commodity Price Risk Management
Commodity Price
Our 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. A committee, which includes members of senior management of our general partner, oversees all of our hedging activity.
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We utilize a combination of fixed-price forward contracts, fixed-for-float price swaps and options on 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 our margins because corresponding losses or gains in the value of financial instruments are generally offset by gains or losses in the physical market.
We enter OTC swaps with counterparties that are primarily financial institutions. 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 us to the risk of financial loss in certain circumstances, including instances when (i) NGLs do not trade at historical levels relative to crude oil, (ii) sales volumes are less than expected requiring market purchases to meet commitments, or iii) our OTC counterparties fail to purchase or deliver the contracted quantities of 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 unfavorable changes in such prices.
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. We are generally unable to hedge our basis risk for NGL products. We have two different types of NGL product basis risk. First, NGL product basis risk stems from the geographic price differentials between our sales locations and hedging contract delivery locations. We cannot hedge our geographic basis risk because there are no readily available products or markets. Second, NGL product basis risk also results from the difference in relative price movements between crude oil and NGL products. We may use crude oil, instead of NGL products, in our hedges because the NGL hedge products and markets are limited. Crude oil is typically highly correlated with certain NGL products. We hedge our NGL product sales by selling forward propane or crude oil. As of December 31, 2002, we have hedged NGL product sales as follows:
| Year Ending December 31, 2003 | |||
---|---|---|---|---|
NGL Volumes Hedged Using Crude Oil | ||||
NGL gallons | 3,731,000 | |||
NGL sales price per gallon | $ | 0.47 | ||
NGL Volumes Hedged Using Propane | ||||
NGL gallons | 1,260,000 | |||
NGL sales price per gallon | $ | 0.40 | ||
Total NGL Volumes Hedged | ||||
NGL gallons | 4,991,000 | |||
NGL sales price per gallon | $ | 0.45 |
All projected margins or prices on open positions assume (a) the basis differentials between our sales location and the hedging contract's specified location, and (b) the correlation between crude oil and NGL products, are consistent with historical averages.
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Interest Rate
We are exposed to changes in interest rates, primarily as a result of our long-term debt with floating interest rates. We may make use of interest rate swap agreements expiring May 19, 2005 to adjust the ratio of fixed and floating rates in the debt portfolio. As of December 31, 2002, we are a party to contracts to fix interest rates on $8.0 million of our debt at 3.84% compared to floating LIBOR, plus an applicable margin.
7. Adoption of SFAS No. 133
The MarkWest Hydrocarbon Midstream Business 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 No. 133, the MarkWest Hydrocarbon Midstream Business recorded on that date a $1.3 million net-of-tax cumulative effect gain to other comprehensive income to recognize at fair value all derivatives that are designated as cash-flow hedging instruments.
SFAS No. 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 No. 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 No. 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 No. 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. The MarkWest Hydrocarbon Midstream Business formally documents, designates and assesses the effectiveness of transactions receiving hedge accounting treatment.
The MarkWest Hydrocarbon Midstream Business entered into fixed-price contracts for the sale of NGL products and fixed-price contracts for the purchase of natural gas (designated as cash flow hedges) and NGL products (designated as fair value hedges). At January 1, 2001, the MarkWest Hydrocarbon Midstream Business recorded a risk management asset of $2.1 million and a deferred tax liability of $0.7 million, resulting in a $1.3 million gain reported in other comprehensive income.
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8. Income Taxes
The provision for income taxes is comprised of the following:
| Years Ended December 31, | |||||||||
---|---|---|---|---|---|---|---|---|---|---|
| 2002 (As Restated. See Note 15) | 2001 | 2000 | |||||||
| (in thousands) | |||||||||
Current taxes due to (from) parent: | ||||||||||
Federal | $ | (1,252 | ) | $ | (1,197 | ) | $ | 2,345 | ||
State | (283 | ) | (271 | ) | 509 | |||||
Total current due to (from) parent | $ | (1,535 | ) | (1,468 | ) | 2,854 | ||||
Deferred: | ||||||||||
Federal | $ | 1,406 | 2,722 | 2,390 | ||||||
State | 190 | 370 | 449 | |||||||
Change in tax status | (17,236 | ) | ||||||||
Total deferred | (15,640 | ) | 3,092 | 2,839 | ||||||
Total provision (benefit) for income taxes | $ | (17,175 | ) | $ | 1,624 | $ | 5,693 | |||
The deferred tax liabilities (assets) are comprised of the tax effect of the following at:
| Years Ended December 31, | ||||||
---|---|---|---|---|---|---|---|
| 2001 | 2000 | |||||
| (in thousands) | ||||||
Property and equipment | $ | 15,158 | $ | 12,015 | |||
Accrued liabilities | 534 | — | |||||
Total deferred tax liability | 15,692 | 12,015 | |||||
Alternative minimum tax credit carry forward | (52 | ) | — | ||||
Total deferred tax asset | (52 | ) | — | ||||
Net deferred tax liability | $ | 15,640 | $ | 12,015 | |||
As further described in Note 15, the Midstream Business recorded a non-cash adjustment of $17.2 million to eliminate deferred income tax liabilities that existed at the date of conveyance of the MarkWest Hydrocarbon Midstream Business from MarkWest Hydrocarbon to the Partnership. Accordingly, the Midstream Business has recorded a benefit to the deferred tax provision for the year ended December 31, 2002, which increased net income by $17.2 million.
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The differences between the provision for income taxes at the statutory rate and the actual provision for income taxes are summarized as follows:
| Year Ended December 31, | |||||||||
---|---|---|---|---|---|---|---|---|---|---|
| 2002 (As Restated. See Note 15) | 2001 | 2000 | |||||||
| (in thousands) | |||||||||
Income tax at statutory rate | $ | 53 | $ | 1,432 | $ | 4,921 | ||||
State income taxes, net of federal benefit | 8 | 192 | 772 | |||||||
Change in tax status | (17,236 | ) | — | — | ||||||
Total provision (benefit) for income taxes | $ | (17,175 | ) | $ | 1,624 | $ | 5,693 | |||
9. Long-Term Incentive Plan and Stock Compensation Plan
Long-Term Incentive Plan
Our general partner has adopted the MarkWest Energy Partners, L.P. Long-Term Incentive Plan for employees and directors of our general partner and its affiliates. The long-term incentive plan consists of two components, restricted units and unit options. The long-term incentive plan currently permits the grant of awards covering an aggregate of 500,000 common units, 200,000 of which may be awarded in the form of restricted units and 300,000 of which may be awarded in the form of unit options. The compensation committee of our general partner's board of directors administers the plan.
Restricted Units
A restricted unit is a "phantom" unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit, or in the discretion of the compensation committee, cash equivalent to the value of a common unit. These restricted units are entitled to receive distribution equivalents, which represent cash equal to the amount of cash distributions made on common units during the vesting period, from the date of grant and will vest over a period of four years, with 25% of the grant vesting at the end of each of the second and third years and 50% vesting at the end of the fourth year. The restricted units will vest upon a change of control of our general partner, MarkWest Hydrocarbon or us.
If a grantee's employment or membership on the board of directors terminates for any reason, the grantee's restricted units will be automatically forfeited unless, and to the extent, the compensation committee provides otherwise. Common units to be delivered upon the vesting of restricted units may be common units acquired by our general partner in the open market, common units already owned by our general partner, common units acquired by our general partner directly from us or any other person or any combination of the foregoing. Our general partner will be entitled to reimbursement by us for the cost incurred in acquiring common units. If we issue new common units upon vesting of the restricted units, the total number of common units outstanding will increase. The compensation committee, in its discretion, may grant distribution rights with respect to any additional restricted unit grants.
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For the year ended December 31, 2002, 55,587 phantom units had been granted to officers, employees and directors of our general partner and its affiliates. Of the amount granted, 5,357 units had subsequently been forfeited leaving 50,230 restricted units outstanding as of December 31, 2002. The Partnership recognized $0.1 million in compensation expense associated with these grants in 2002. The fair market value associated with these grants was $1.2 million on December 31, 2002.
Unit Options
The long-term incentive plan currently permits the grant of options covering common units. The compensation committee may determine to make grants under the plan to employees and directors containing such terms as the committee shall determine. Unit options will have an exercise price that, in the discretion of the committee, may be less than, equal to or more than the fair market value of the units on the date of grant. In general, unit options granted will become exercisable over a period determined by the compensation committee. In addition, the unit options will become exercisable upon a change in control of us, our general partner, MarkWest Hydrocarbon or upon the achievement of specified financial objectives.
Upon exercise of a unit option, our general partner will acquire common units in the open market or directly from us or any other person or use common units already owned by our general partner, or any combination of the foregoing. Our general partner will be entitled to reimbursement by us for the difference between the cost incurred by our general partner in acquiring these common units and the proceeds received by our general partner from an optionee at the time of exercise. Thus, the cost of the unit options will be borne by us. The unit option plan has been designed to furnish additional compensation to employees and directors and to align their economic interests with those of common unitholders.
As of December 31, 2002, no options had been granted under the long-term incentive plan.
Stock-Based Compensation Plan
Certain employees of MarkWest Hydrocarbon dedicated to or otherwise principally supporting MarkWest Energy Partners, L.P. receive stock-based compensation awards from MarkWest Hydrocarbon. We apply APB Opinion No. 25,Accounting for Stock Issued to Employees, and related Interpretations in accounting for those employees principally supporting the Partnership who participate in MarkWest Hydrocarbon's plan. Accordingly, no compensation cost has been recognized for the fixed stock option plan.
Under its 1996 Stock Incentive Plan, MarkWest Hydrocarbon may grant options to its employees for up to 925,000 shares of common stock in the aggregate. Under this plan, the exercise price of each option equals the market price of MarkWest Hydrocarbon'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 25% per year for options granted in 1999 and after and 20% per year for options granted prior to 1999.
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The fair value of each option granted in 2002, 2001, and 2000 was estimated using the Black-Scholes option pricing model. The following assumptions were used to compute the weighted average fair market value of options granted.
| 2002 | 2001 | 2000 | ||||
---|---|---|---|---|---|---|---|
Expected life options | 6 years | 6 years | 6 years | ||||
Risk free interest rates | 3.54 | % | 4.84 | % | 5.93 | % | |
Estimated volatility | 52 | % | 52 | % | 43 | % | |
Dividend yield | 0.0 | % | 0.0 | % | 0.0 | % |
A summary of the plan activity of those employees principally supporting the Partnership who participated in MarkWest Hydrocarbon's fixed stock option plan as of December 31, 2002, 2001 and 2000, and, changes during the years ended on those dates are presented below:
| 2002 | 2001 | 2000 | ||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Options | Weighted- Average Exercise Price | Options | Weighted- Average Exercise Price | Options | Weighted- Average Exercise Price | |||||||||
Fixed Options | |||||||||||||||
Outstanding at beginning of year | 343,849 | $ | 9.21 | 325,374 | $ | 9.29 | 270,721 | $ | 9.14 | ||||||
Change in employees considered to be primarily supporting the Partnership | (25,237 | ) | 9.21 | — | — | — | — | ||||||||
Granted | — | — | 19,778 | 7.84 | 54,653 | 10.08 | |||||||||
Exercised | — | — | — | — | — | — | |||||||||
Cancelled | — | — | (1,303 | ) | 8.34 | — | — | ||||||||
Outstanding at end of year | 318,612 | $ | 9.21 | 343,849 | $ | 9.21 | 325,374 | $ | 9.29 | ||||||
Options exercisable at December 31, 2002, 2001 and 2000, respectively | 256,886 | 218,482 | 156,516 | ||||||||||||
Weighted-average fair value of options granted during the year | $ | 0.00 | $ | 3.84 | $ | 4.94 |
The following table summarizes information about outstanding and exercisable MarkWest Hydrocarbon fixed stock options, held by employees principally supporting the Partnership, at December 31, 2002:
| Options Outstanding | | | |||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|
| Options Exercisable | |||||||||||
| | Weighted- Average Remaining Contractual Life | | |||||||||
Range of Exercise Prices | Number Outstanding at 12/31/02 | Weighted- Average Exercise Price | Number Exercisable At 12/31/02 | Weighted- Average Exercise Price | ||||||||
$ 5.38 to $ 7.65 | 86,453 | 4.23 | $ | 6.68 | 66,421 | $ | 6.63 | |||||
$ 7.86 to $10.00 | 89,597 | 4.73 | 9.14 | 70,901 | 9.25 | |||||||
$10.50 to $10.50 | 28,318 | 5.94 | 10.50 | 22,657 | 10.50 | |||||||
$10.75 to $10.75 | 88,266 | 4.94 | 10.75 | 83,887 | 10.75 | |||||||
$11.25 to $11.38 | 25,978 | 7.93 | 11.25 | 13,020 | 11.25 | |||||||
$ 5.38 to $11.38 | 318,612 | 5.02 | $ | 9.21 | 256,886 | $ | 9.27 | |||||
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10. Commitments and Contingencies
Legal
MarkWest Energy Partners, in the ordinary course of business, is a party to various legal actions. In the opinion of management, none of these actions, either individually or in the aggregate, will have a material adverse effect on our financial condition, liquidity or results of operations.
Lease Obligations
We have various non-cancelable operating lease agreements for equipment expiring at various times through fiscal 2015. Annual rent expense under these operating leases was $0.6 million for each period presented. Our minimum future lease payments under these operating leases as of December 31, 2002, are as follows (in thousands):
2003 | $ | 527 | |
2004 | 527 | ||
2005 | 527 | ||
2006 | 411 | ||
2007 | 179 | ||
2008 and thereafter | 324 | ||
Total | $ | 2,495 | |
11. Partners' Capital
As of December 31, 2002, partners' capital consisted of 2,415,000 common units representing a 43.7% limited partner interest, 3,000,000 subordinated units representing a 54.3% limited partner interest and a 2% general partner interest. Affiliates of MarkWest Hydrocarbon, in the aggregate, owned a 46.7% interest in the Partnership consisting of 2,479,762 subordinated units and a 2% general partner interest.
The Amended and Restated Agreement of Limited Partnership of MarkWest Energy Partners, L.P. (the Partnership Agreement) contains specific provisions for the allocation of net income and losses to each of the partners for the purposes of maintaining the partner capital accounts.
Cash distributions
The Partnership will distribute 100% of its Available Cash (as defined in the Partnership Agreement) within 45 days after the end of each quarter to unitholders of record and to the general partner. Available Cash is generally defined as all cash and cash equivalents of the Partnership on hand at the end of each quarter less reserves established by the general partner for future requirements plus all cash on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter. The general partner has the discretion to establish cash reserves that are necessary or appropriate to (i) provide for the proper conduct of our business; (ii) comply with applicable law, any of our debt instruments or other agreements; or (iii) provide funds for distributions to unitholders and the general partner for any one or more of the next four quarters. Working capital borrowings are generally borrowings that are made under our working capital facility and in all cases are used solely for working capital purposes such as to pay distributions to partners.
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During the subordination period (as defined in the Partnership Agreement and discussed further below), our quarterly distributions of available cash will be made in the following manner:
- •
- First, 98% to the common units and 2% to our general partner, until each common unit has received a minimum quarterly distribution of $0.50 plus any arrearages from prior quarters;
- •
- Second, 98% to the subordinated units and 2% to our general partner, until each subordinated unit has received a minimum quarterly distribution of $0.50 plus any arrearages from prior quarters; and
- •
- Third, 98% to all units, pro rata, and 2% to our general partner, until each unit has received a distribution of $0.55 per quarter.
Our general partner is entitled to incentive distributions if the amount we distribute with respect to any quarter exceeds specified target levels shown below:
| | Marginal Percentage Interest in Distributions | |||||
---|---|---|---|---|---|---|---|
| Total Quarterly Distribution Target Amount | Unitholders | General Partner | ||||
Minimum Quarterly Distribution | $0.50 | 98 | % | 2 | % | ||
First Target Distribution | up to $0.55 | 98 | % | 2 | % | ||
Second Target Distribution | above $0.55 up to $0.625 | 85 | % | 15 | % | ||
Third Target Distribution | above $0.625 up to $0.75 | 75 | % | 25 | % | ||
Thereafter | above $0.75 | 50 | % | 50 | % |
The quarterly cash distributions applicable to 2002 were as follows:
Quarter Ended | Record Date | Payment Date | Amount Per Unit | ||||
---|---|---|---|---|---|---|---|
June 30, 2002 | August 13, 2002 | August 15, 2002 | $ | 0.21 | |||
September 30, 2002 | October 31, 2002 | November 14, 2002 | $ | 0.50 | |||
December 31, 2002 | January 31, 2003 | February 14, 2003 | $ | 0.52 |
Subordination period
During the subordination period, the common units have the right to receive distributions of available cash in an amount equal to the minimum quarterly distribution of $0.50 per quarter, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. The purpose of the subordinated units is to increase the likelihood that during the subordination period there will be available cash to be distributed on the common units. The subordination period ends on the first day of any quarter beginning after June 30, 2009 when certain financial tests (defined in the Partnership Agreement) are met. Additionally, a portion of the subordinated units may convert earlier into common units on a one-for-one basis if additional financial tests (defined in the Partnership Agreement) are met. Generally, the earliest possible date by which all subordinated units may be converted into common units is June 30, 2007. When the subordination period ends, all remaining subordinated units will convert into common units on a one-for-one basis and the common units will no longer be entitled to arrearages.
F-24
12. Employee Benefit Plan
All employees dedicated to, or otherwise principally supporting, MarkWest Energy Partners are employees of MarkWest Hydrocarbon and substantially all of these employees are participants in MarkWest Hydrocarbon's defined contribution plan. MarkWest Energy Partners' costs related to this plan were $0.1 million, $0.1 million and $0.2 million for the years ended December 31, 2002, 2001 and 2000, respectively. The plan is discretionary, with annual contributions determined by MarkWest Hydrocarbon's Board of Directors.
13. Quarterly Results of Operations (Unaudited)
The following summarizes certain quarterly results of operations:
| Three Months Ended | |||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|
| March 31 | June 30(1) | September 30 | December 31 | ||||||||
| (in thousands, except per unit amounts) | |||||||||||
2002 | ||||||||||||
Revenue | $ | 27,440 | $ | 14,463 | $ | 13,868 | $ | 14,475 | ||||
Income (loss) from operations | $ | 1,422 | $ | 137 | $ | 2,906 | $ | 1,511 | ||||
Net income (loss) | $ | 690 | $ | 17,452 | $ | 2,526 | $ | 1,121 | ||||
Net income per limited partner unit(1) | $ | 0.23 | $ | 4.35 | $ | 0.46 | $ | 0.20 | ||||
Net income per limited partner unit assuming dilution(1) | $ | 0.23 | $ | 4.34 | $ | 0.45 | $ | 0.20 |
| MarkWest Hydrocarbon Midstream Business | |||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|
| Three Months Ended | |||||||||||
| March 31 | June 30 | September 30 | December 31 | ||||||||
| (in thousands, except per unit amounts) | |||||||||||
2001 | ||||||||||||
Revenue | $ | 35,959 | $ | 16,903 | $ | 19,223 | $ | 21,590 | ||||
Income (loss) from operations | $ | 3,053 | $ | (306 | ) | $ | (191 | ) | $ | 2,961 | ||
Net income (loss) | $ | 1,690 | $ | (420 | ) | $ | (382 | ) | $ | 1,698 | ||
Net income (loss) per limited partner unit(1) | $ | 0.56 | $ | (0.14 | ) | $ | (0.13 | ) | $ | 0.57 | ||
Net income (loss) per limited partner unit assuming dilution(1) | $ | 0.56 | $ | (0.14 | ) | $ | (0.13 | ) | $ | 0.57 |
F-25
- (1)
- As Restated and adjusted to reflect the $17.2 million deferred tax adjustment in the three months ended June 30, 2002, as discussed in Note 15. Amounts as previously reported were as follows:
| MarkWest Hydrocarbon Midstream Business(1) | Partnership | |||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| | Three Months Ended | |||||||||||||
| January 1 through March 31 | April 1 through May 23 | May 24 through June 30 | ||||||||||||
| September 30 | December 31 | |||||||||||||
| (in thousands, except per unit amounts) | ||||||||||||||
2002 | |||||||||||||||
Revenue | $ | 27,440 | $ | 9,603 | $ | 4,860 | $ | 13,868 | $ | 14,475 | |||||
Income (loss) from operations | $ | 1,422 | $ | (803 | ) | $ | 940 | $ | 2,906 | $ | 1,512 | ||||
Net income (loss) | $ | 690 | $ | (594 | ) | $ | 810 | $ | 2,526 | $ | 1,121 | ||||
Net income per limited partner unit | NA | NA | $ | 0.15 | $ | 0.46 | $ | 0.20 | |||||||
Net income per limited partner unit assuming dilution | NA | NA | $ | 0.15 | $ | 0.46 | $ | 0.20 |
MarkWest Hydrocarbon Midstream Business(A) | ||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|
| Three Months Ended | |||||||||||
| March 31 | June 30 | September 30 | December 31 | ||||||||
| (in thousands, except per unit amounts) | |||||||||||
2001 | ||||||||||||
Revenue | $ | 35,959 | $ | 16,903 | $ | 19,223 | $ | 21,590 | ||||
Income (loss) from operations | $ | 3,053 | $ | (306 | ) | $ | (191 | ) | $ | 2,961 | ||
Net income (loss) | $ | 1,690 | $ | (420 | ) | $ | (382 | ) | $ | 1,698 | ||
Net income per limited partner unit | NA | NA | NA | NA | ||||||||
Net income per limited partner unit assuming dilution | NA | NA | NA | NA |
NA—Not applicable
- (A)
- The MarkWest Hydrocarbon Midstream Business did not issue any units. Accordingly, no information on a per unit basis is available.
14. Subsequent Event
On March 24, 2003, we entered into an agreement to merge with Pinnacle Natural Gas Company and certain affiliates for approximately $38 million. The acquired assets, primarily located in Texas, are comprised of three lateral natural gas pipelines and eighteen gathering systems. The acquisition will be financed primarily through borrowings under our credit facility, which was recently expanded by $15 million.
15. Restatement
The Partnership previously reported two separate statements of operations and of cash flows for the year ended December 31, 2002. One statement of operations and one statement of cash flows was presented for the period from January 1, 2002 through May 23, 2002 for the MarkWest Hydrocarbon Midstream Business prior to its conveyance to the Partnership on May 24, 2002 (See Note 1). Another
F-26
statement of operations and statement of cash flows was presented for the period from May 24, 2002 (the date the MarkWest Hydrocarbon Midstream Business was conveyed to the Partnership) through December 31, 2002.
As indicated in Note 1, the conveyance of the MarkWest Hydrocarbon Midstream Business from MarkWest Hydrocarbon to the Partnership represented a reorganization of entities under common control and was recorded at historical cost. Consequently, the Partnership has concluded these statements should be presented on a combined basis for the year ended December 31, 2002.
In addition, the Partnership had previously reported net income per limited partner unit for the period from May 24, 2002 through December 31, 2002. In its restated financial statements, the Partnership has restated income per limited partner unit to report such amount for the year ended December 31, 2002. In addition, the Partnership has now reported income per limited partner unit for the years ended December 21, 2001 and 2000. The weighted average amounts outstanding used in the calculation of income per limited partner unit for the years ended December 31, 2001 and 2000 retroactively reflect the 3,000,000 subordinated units issued by the Partnership in connection with the conveyance of the MarkWest Hydrocarbon Midstream Business to the Partnership. The units used in the 2002 calculation represent the weighted average of the aforementioned 3,000,000 subordinated units and the 2,415,000 common units issued in the May 24, 2002 initial public offering. Net income used in the 2002 calculation has been reduced by the General Partner's interest in net income.
In its restated financial statements for the year ended December 31, 2002, the Midstream Business recorded a non-cash adjustment of $17.2 million to eliminate deferred income tax liabilities that existed at the date of conveyance of the MarkWest Hydrocarbon Midstream Business from MarkWest Hydrocarbon to the Partnership. Accordingly, the Midstream Business has recorded a benefit to the deferred tax provision for the year ended December 31, 2002 which increased net income by $17.2 million. This adjustment resulted from the change in the tax status of the MarkWest Hydrocarbon Midstream Business from a taxable entity to a Partnership, which is not subject to taxation.
In addition, the Partnership had previously reported certain captions in the consolidated and combined statements of changes in capital net of the following: (i) distribution of cash to MarkWest Hydrocarbon in connection with the conveyance, (ii) change in parent advances, and (iii) the net liabilities not assumed by the partnership. The Partnership has now reported these captions on a gross basis and separately disclosed the amounts.
The following sets forth the effects of the restatements discussed above.
F-27
MARKWEST ENERGY PARTNERS, L.P.
CONSOLIDATED AND COMBINED STATEMENTS OF OPERATIONS
(in thousands, except per unit amounts)
| As Previously Reported | | | ||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Period From Commencement of Operations (May 24, 2002) Through December 31, 2002 Partnership | Period From January 1, 2002 Through May 23, 2002 (MarkWest Hydrocarbon Midstream Business) | Adjustments | Total Year Ended December 31, 2002 (As Restated) | |||||||||||
Revenues: | |||||||||||||||
Sales to affiliates | $ | 26,093 | $ | — | $ | — | $ | 26,093 | |||||||
Sales to unaffiliated parties | 7,110 | 37,043 | 44,153 | ||||||||||||
Total revenues | 33,203 | 37,043 | 70,246 | ||||||||||||
Operating expenses: | |||||||||||||||
Purchased product costs | 12,308 | 26,598 | 38,906 | ||||||||||||
Facility expenses | 9,396 | 5,705 | 15,101 | ||||||||||||
Selling, general and administrative expenses | 3,077 | 2,206 | 5,283 | ||||||||||||
Depreciation | 3,064 | 1,916 | 4,980 | ||||||||||||
Total operating expenses | 27,845 | 36,425 | 64,270 | ||||||||||||
Income from operations | 5,358 | 618 | 5,976 | ||||||||||||
Other income and (expenses): | |||||||||||||||
Interest expense, net | (953 | ) | (461 | ) | (1,414 | ) | |||||||||
Miscellaneous income | 52 | — | 52 | ||||||||||||
Income before income taxes | 4,457 | 157 | 4,614 | ||||||||||||
Provision (benefit) for income taxes: | |||||||||||||||
Current due to (from) parent | — | (1,535 | ) | (1,535 | ) | ||||||||||
Deferred | — | 1,596 | (17,236 | ) | (15,640 | ) | |||||||||
Provision for income taxes | — | 61 | (17,236 | ) | (17,175 | ) | |||||||||
Net income | $ | 4,457 | $ | 96 | $ | 17,236 | $ | 21,789 | |||||||
General partner's interest in net income | $ | 89 | $ | 89 | |||||||||||
Limited partners' interest in net income | $ | 4,368 | $ | 21,700 | |||||||||||
Net income per limited partner unit | $ | 0.81 | $ | 4.86 | |||||||||||
Weighted average units outstanding | 5,415 | 4,469 | |||||||||||||
F-28
MARKWEST ENERGY PARTNERS, L.P.
CONSOLIDATED AND COMBINED STATEMENTS OF CASH FLOWS
(in thousands)
| As Previously Reported | | | |||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Period From Commencement of Operations (May 24, 2002) Through December 31, 2002 Partnership | Period From January 1, 2002 Through May 23, 2002 (MarkWest Hydrocarbon Midstream Business) | Adjustments | Total Year Ended December 31, 2002 (As Restated) | ||||||||||||
Cash flows from operating activities: | ||||||||||||||||
Net income | $ | 4,457 | $ | 96 | $ | 17,236 | $ | 21,789 | ||||||||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||||||||||
Depreciation | 3,064 | 1,916 | 4,980 | |||||||||||||
Amortization of deferred financing costs included in interest expense | 291 | — | 291 | |||||||||||||
Deferred income taxes | — | 1,596 | (17,236 | ) | (15,640 | ) | ||||||||||
Other | (41 | ) | (252 | ) | (293 | ) | ||||||||||
Changes in operating assets and liabilities, net of working capital assumed: | ||||||||||||||||
(Increase) decrease in receivables | (3,808 | ) | 3,765 | (43 | ) | |||||||||||
(Increase) decrease in inventories | (116 | ) | 2,449 | 2,333 | ||||||||||||
(Increase) decrease in prepaid replacement natural gas and other assets | (320 | ) | 5,253 | 4,933 | ||||||||||||
Increase in accounts payable and accrued liabilities | 4,292 | 7,770 | 12,062 | |||||||||||||
Increase in long-term replacement natural gas payable | — | 3,090 | 3,090 | |||||||||||||
Net cash provided by operating activities | 7,819 | 25,683 | — | 33,502 | ||||||||||||
Cash flows from investing activities: | ||||||||||||||||
Capital expenditures | (1,647 | ) | (498 | ) | (2,145 | ) | ||||||||||
Proceeds from sale of assets | 89 | — | 89 | |||||||||||||
Net cash used in investing activities | (1,558 | ) | (498 | ) | — | (2,056 | ) | |||||||||
Cash flows from financing activities: | ||||||||||||||||
Proceeds from initial public offering, net | 43,625 | — | 43,625 | |||||||||||||
Distribution to MarkWest Hydrocarbon | (63,476 | ) | — | (63,476 | ) | |||||||||||
Distributions to unitholders | (3,923 | ) | — | (3,923 | ) | |||||||||||
Payments for debt issuance costs | (1,111 | ) | — | (1,111 | ) | |||||||||||
Proceeds from long-term debt | 23,400 | — | 23,400 | |||||||||||||
Repayment of long-term debt | (2,000 | ) | — | (2,000 | ) | |||||||||||
Net distributions to parent | — | (24,218 | ) | (24,218 | ) | |||||||||||
Debt from parent | — | (967 | ) | (967 | ) | |||||||||||
Net cash used in financing activities | (3,485 | ) | (25,185 | ) | — | (28,670 | ) | |||||||||
Net increase in cash | 2,776 | — | — | 2,776 | ||||||||||||
Cash and cash equivalents at beginning of period | — | — | — | — | ||||||||||||
Cash and cash equivalents at end of period | $ | 2,776 | $ | — | $ | — | $ | 2,776 | ||||||||
F-29
The following sets forth the restated net income per limited partner unit for the years ended December 31, 2002, 2001 and 2000.
| 2002 | 2001 | 2000 | ||||||
---|---|---|---|---|---|---|---|---|---|
| (in thousands, except per unit amounts) | ||||||||
Limited partners' interest in net income as previously reported | $ | 4,368 | $ | — | $ | — | |||
Limited partners' interest in net income as restated | $ | 21,700 | $ | 2,586 | $ | 8,781 | |||
Basic weighted average units outstanding as previously reported | 5,415 | — | — | ||||||
Basic weighted average units outstanding as restated | 4,469 | 3,000 | 3,000 | ||||||
Diluted weighted average units outstanding, as previously reported | — | — | — | ||||||
Diluted weighted average units outstanding, as restated | 4,493 | 3,000 | 3,000 | ||||||
Basic net income per limited partner unit as previously reported | $ | 0.81 | $ | — | $ | — | |||
Basic net income per limited partner unit as restated | $ | 4.86 | $ | 0.86 | $ | 2.93 | |||
Diluted net income as previously reported | $ | — | $ | — | $ | — | |||
Diluted net income as restated | $ | 4.83 | $ | 0.86 | $ | 2.93 | |||
The following sets forth the restated captions in the consolidated statement of changes in capital for the year ended December 31, 2002:
| As Previously Reported | As Restated | ||||||
---|---|---|---|---|---|---|---|---|
| (in thousands) | |||||||
Net Parent Investment: | ||||||||
Net income applicable to the period from January 1 to May 23, 2002 | $ | 96 | $ | 17,332 | ||||
Net change in parent advances | — | (24,218 | ) | |||||
Adjustment to reflect net liabilities not assumed by the Partnership | (47,142 | ) | 23,316 | |||||
Book value of net assets contributed by MarkWest Hydrocarbon to the Partnership | (17,415 | ) | (80,891 | ) | ||||
Adjustments to net parent investment | $ | (64,461 | ) | $ | (64,461 | ) | ||
Limited Partners' Subordinated Units: | ||||||||
Book value of net assets contributed by MarkWest Hydrocarbon to the Partnership | $ | 17,067 | $ | 79,273 | ||||
Distribution to MarkWest Hydrocarbon | — | (62,206 | ) | |||||
Adjustments to Limited Partners' Subordinated Units | $ | 17,067 | $ | 17,067 | ||||
General Partner Interest: | ||||||||
Book value of net assets contributed by MarkWest Hydrocarbon to the Partnership | $ | 348 | $ | 1,618 | ||||
Distribution to MarkWest Hydrocarbon | — | (1,270 | ) | |||||
Adjustments to General Partner Interest | $ | 348 | $ | 348 | ||||
F-30
Total Partners' Capital: | ||||||||
Net income applicable to the period from January 1 through May 23, 2002 | $ | 96 | $ | 17,332 | ||||
Net change in parent advances | — | (24,218 | ) | |||||
Adjustment to reflect net liabilities not assumed by the Partnership | (47,142 | ) | 23,316 | |||||
Distribution to MarkWest Hydrocarbon | — | (63,476 | ) | |||||
Adjustments to Total Partners' Capital | $ | (47,046 | ) | $ | (47,046 | ) | ||
F-31
MARKWEST ENERGY PARTNERS, L.P.
CONDENSED CONSOLIDATED BALANCE SHEETS
(unaudited)
| September 30, 2003 | December 31, 2002 | |||||||
---|---|---|---|---|---|---|---|---|---|
| (in thousands) | ||||||||
ASSETS | |||||||||
Current Assets: | |||||||||
Cash and cash equivalents | $ | 6,373 | $ | 2,776 | |||||
Receivables | 6,364 | 976 | |||||||
Receivables from affiliate | 2,247 | 2,847 | |||||||
Inventories | 114 | 130 | |||||||
Other assets | 135 | 336 | |||||||
Total current assets | 15,233 | 7,065 | |||||||
Property, plant and equipment: | |||||||||
Gas gathering equipment | 47,112 | 34,398 | |||||||
Gas processing plants | 47,644 | 47,403 | |||||||
Pipelines | 38,103 | — | |||||||
Fractionation and storage equipment | 22,160 | 22,076 | |||||||
NGL transportation equipment | 4,415 | 4,402 | |||||||
Land, building and other equipment | 3,088 | 3,021 | |||||||
Construction in progress | 685 | 348 | |||||||
163,207 | 111,648 | ||||||||
Less: Accumulated depreciation | (37,030 | ) | (31,824 | ) | |||||
Total property, plant and equipment, net | 126,177 | 79,824 | |||||||
Deferred financing costs | 880 | 820 | |||||||
Total assets | $ | 142,290 | $ | 87,709 | |||||
LIABILITIES AND CAPITAL | |||||||||
Current liabilities: | |||||||||
Accounts payable | $ | 8,489 | $ | 1,199 | |||||
Payables to affiliate | 815 | 723 | |||||||
Accrued liabilities | 3,786 | 2,880 | |||||||
Risk management liability | 263 | 501 | |||||||
Total current liabilities | 13,353 | 5,303 | |||||||
Long-term debt | 61,300 | 21,400 | |||||||
Risk management liability | 196 | 143 | |||||||
Capital: | |||||||||
Partners' capital | 67,912 | 61,574 | |||||||
Accumulated other comprehensive loss, net of tax | (471 | ) | (711 | ) | |||||
Total capital | 67,441 | 60,863 | |||||||
Total liabilities and capital | $ | 142,290 | $ | 87,709 | |||||
F-32
MARKWEST ENERGY PARTNERS, L.P.
CONDENSED CONSOLIDATED AND COMBINED STATEMENTS OF OPERATIONS
(unaudited)
| Nine Months Ended September 30, 2003 (Partnership) | Nine Months Ended September 30, 2002 (As Restated See Note 12) | |||||||
---|---|---|---|---|---|---|---|---|---|
| (in thousands, except per unit amounts) | ||||||||
Revenues: | |||||||||
Sales to unaffiliated parties | $ | 42,741 | $ | 41,124 | |||||
Sales to affiliates | 36,000 | 14,647 | |||||||
Total revenues | 78,741 | 55,771 | |||||||
Operating expenses: | |||||||||
Purchased product costs | 45,325 | 33,034 | |||||||
Facility expenses | 14,900 | 10,941 | |||||||
Selling, general and administrative expenses | 4,814 | 3,629 | |||||||
Depreciation | 5,231 | 3,703 | |||||||
Total operating expenses | 70,270 | 51,307 | |||||||
Income from operations | 8,471 | 4,464 | |||||||
Other income (expenses): | |||||||||
Interest expense, net | (2,592 | ) | (989 | ) | |||||
Miscellaneous income | 51 | 18 | |||||||
Income before income taxes | 5,930 | 3,493 | |||||||
Benefit for income taxes: | |||||||||
Current due from parent | — | (1,535 | ) | ||||||
Deferred | — | (15,640 | ) | ||||||
Benefit for income taxes | — | (17,175 | ) | ||||||
Net income | $ | 5,930 | $ | 20,668 | |||||
General partner's interest in net income(1) | $ | 178 | $ | 67 | |||||
Limited partners' interest in net income(1) | $ | 5,752 | $ | 20,601 | |||||
Basic net income per limited partner unit(1) | $ | 1.04 | $ | 4.96 | |||||
Diluted net income per limited partner unit(1) | $ | 1.03 | $ | 4.95 | |||||
Weighted average units outstanding: | |||||||||
Basic | 5,543 | 4,150 | |||||||
Diluted | 5,593 | 4,166 | |||||||
- (1)
- As Restated. See Note 12.
The accompanying notes are an integral part of these unaudited financial statements.
F-33
MARKWEST ENERGY PARTNERS, L.P.
CONDENSED CONSOLIDATED AND COMBINED STATEMENTS OF CASH FLOWS
(unaudited)
| Nine Months Ended September 30, 2003 (Partnership) | Nine Months Ended September 30, 2002 (As Restated. See Note 12) | ||||||||
---|---|---|---|---|---|---|---|---|---|---|
| (in thousands) | |||||||||
Cash flows from operating activities: | ||||||||||
Net income | $ | 5,930 | $ | 20,668 | ||||||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||||
Depreciation | 5,231 | 3,703 | ||||||||
Amortization of deferred financing costs included in interest expense | 702 | — | ||||||||
Non-cash compensation expense | 554 | — | ||||||||
Deferred income taxes | — | (15,640 | ) | |||||||
Other | 20 | (184 | ) | |||||||
Changes in operating assets and liabilities: | ||||||||||
(Increase) decrease in receivables | 3,369 | (1,036 | ) | |||||||
Decrease in inventories | 16 | 2,349 | ||||||||
Decrease in prepaid replacement natural gas and other assets | 285 | 5,180 | ||||||||
Increase in accounts payable and accrued liabilities | 333 | 11,011 | ||||||||
Increase in long-term replacement natural gas payable | — | 3,090 | ||||||||
Net cash provided by operating activities | 16,440 | 29,141 | ||||||||
Cash flows from investing activities: | ||||||||||
Pinnacle acquisition, net of cash acquired | (38,238 | ) | — | |||||||
Lubbock pipeline acquisition | (12,222 | ) | — | |||||||
Capital expenditures | (1,934 | ) | (1,905 | ) | ||||||
Proceeds from sale of assets | 3 | 18 | ||||||||
Net cash used in investing activities | (52,391 | ) | (1,887 | ) | ||||||
Cash flows from financing activities: | ||||||||||
Proceeds from initial public offering, net of transaction costs | — | 43,662 | ||||||||
Proceeds from private placement of common units, net of transaction costs | 9,764 | — | ||||||||
Proceeds from long-term debt | 67,600 | 23,400 | ||||||||
Repayment of long-term debt | (27,700 | ) | (2,000 | ) | ||||||
Distributions to unitholders | (9,557 | ) | (1,160 | ) | ||||||
Capital contribution from general partner | 201 | — | ||||||||
Net distributions to parent | — | (24,218 | ) | |||||||
Debt due from parent | — | (967 | ) | |||||||
Payments for debt issuance costs | (760 | ) | (1,077 | ) | ||||||
Distribution to MarkWest Hydrocarbon | — | (63,476 | ) | |||||||
Net cash provided by (used in) financing activities | 39,548 | (25,836 | ) | |||||||
Net increase in cash | 3,597 | 1,418 | ||||||||
Cash and cash equivalents at beginning of period | 2,776 | — | ||||||||
Cash and cash equivalents at end of period | $ | 6,373 | $ | 1,418 | ||||||
The accompanying notes are an integral part of these unaudited financial statements.
F-34
MARKWEST ENERGY PARTNERS, L.P.
CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN CAPITAL
(unaudited)
| PARTNERS' CAPITAL | | | |||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Accumulated Other Comprehensive Income (Loss) | | ||||||||||||||||||
| Limited Partners | General Partner | | |||||||||||||||||
| Common | Subordinated | | | | |||||||||||||||
| Units | $ | Units | $ | $ | $ | Total | |||||||||||||
| (in thousands) | |||||||||||||||||||
Balance at December 31, 2002 | 2,415 | $ | 43,858 | 3,000 | $ | 17,357 | $ | 359 | $ | (711 | ) | $ | 60,863 | |||||||
Private placement of common units, net of transaction costs | 375 | 9,764 | — | — | 201 | — | 9,965 | |||||||||||||
Distributions to partners | — | (4,275 | ) | — | (5,040 | ) | (242 | ) | — | (9,557 | ) | |||||||||
Net income | — | 2,630 | — | 3,122 | 178 | — | 5,930 | |||||||||||||
Change in fair value of derivatives | — | — | — | — | — | 240 | 240 | |||||||||||||
Balance at September 30, 2003 | 2,790 | $ | 51,977 | 3,000 | $ | 15,439 | $ | 496 | $ | (471 | ) | $ | 67,441 | |||||||
The accompanying notes are an integral part of these unaudited financial statements.
F-35
MARKWEST ENERGY PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED
AND COMBINED FINANCIAL STATEMENTS
1. Organization
MarkWest Energy Partners, L.P., a Delaware limited partnership (the "Partnership", "we" or "us"), was formed in January 2002 to own and operate substantially all of the assets, liabilities and operations of MarkWest Hydrocarbon, Inc.'s ("MarkWest Hydrocarbon") midstream business (the "MarkWest Hydrocarbon Midstream Business" or the "Midstream Business"). Through its majority ownership of our general partner, MarkWest Energy GP, L.L.C., MarkWest Hydrocarbon controls and conducts our operations. We are engaged in the business of gathering, processing and transporting natural gas and the transportation, fractionation and storage of NGL products. We are not a taxable entity because of our partnership structure.
2. Basis of Presentation
The accompanying unaudited condensed consolidated and combined financial statements include the accounts of MarkWest Energy Partners, L.P. and its wholly owned subsidiaries. For periods prior to May 24, 2002, the date on which the assets of the Midstream Business were conveyed to the Partnership, the financial statements reflect historical cost-basis accounts of the Midstream Business. The financial statements have been prepared in accordance with accounting principles generally accepted in the United States for interim financial reporting. The year-end consolidated balance sheet data was derived from audited financial statements. Preparation of these financial statements involve the use of estimates and judgments where appropriate. In management's opinion, all adjustments necessary for a fair presentation of the Partnership's and the Midstream Business's results of operations, financial position and cash flows for the periods shown have been made. All such adjustments are of a normal recurring nature. You should read these condensed consolidated and combined financial statements along with the audited financial statements and notes thereto as of and for the three years ended in the period ended December 31, 2002 included in this Prospectus. Results for the three and nine months ended September 30, 2003, are not necessarily indicative of results for the full year 2003 or any other future period.
3. Pinnacle Acquisition
On March 28, 2003, we completed the acquisition (the "Pinnacle Acquisition") of Pinnacle Natural Gas Company, Pinnacle Pipeline Company, PNG Transmission Company, Inc., PNG Utility Company and Bright Star Gathering, Inc. (collectively, the "Sellers"). The purchase price was comprised of $23.4 million paid in cash to the Sellers, plus the assumption of specified liabilities, including $16.6 million of bank indebtedness.
The Pinnacle Acquisition was accomplished through a merger under Texas law of the Sellers and four newly formed wholly owned subsidiaries of the Partnership as buyers. In the merger, most of the assets and liabilities of the Sellers were allocated to the Partnership entities, and all entities survived the merger. The assets acquired from the Sellers, primarily located in the State of Texas, with the balance located in New Mexico, Louisiana, Mississippi and Kansas, are comprised of three lateral natural gas pipelines and twenty gathering systems.
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The purchase price was allocated as follows (in thousands):
Acquisition costs: | |||||
Long-term debt incurred | $ | 39,471 | |||
Direct acquisition costs | 450 | ||||
Current liabilities assumed | 8,150 | ||||
$ | 48,071 | ||||
Allocation of acquisition costs: | |||||
Current assets | $ | 10,643 | |||
Fixed assets (including long-term contracts) | 37,428 | ||||
Total | $ | 48,071 | |||
Pro Forma Results of Operations (Unaudited)
The following table reflects the unaudited pro forma consolidated results of operations for the comparable periods presented, as though the Pinnacle Acquisition had occurred on January 1, 2002. These unaudited pro forma results have been prepared for comparative purposes only and may not be indicative of future results.
| Nine Months Ended September 30, 2003 | Nine Months Ended September 30, 2002 (As Restated. See Note 12) | ||||
---|---|---|---|---|---|---|
| (in thousands, except per unit data) | |||||
Revenue | $ | 96,528 | $ | 85,861 | ||
Net income | $ | 6,645 | $ | 20,296 | ||
Basic net income per limited partner unit | $ | 1.17 | $ | 4.89 | ||
Diluted net income per limited partner unit | $ | 1.16 | $ | 4.87 |
4. Lubbock Pipeline Acquisition
Effective September 1, 2003, the Partnership, through its wholly owned subsidiary, MarkWest Pinnacle L.P., completed the acquisition (the "Lubbock Pipeline Acquisition") of a 68-mile intrastate gas transmission pipeline near Lubbock, Texas from a subsidiary of ConocoPhillips for approximately $12.2 million. The transaction was financed through borrowings under our existing credit facility. The acquisition was accounted for as a purchase business combination. The pro forma results of operations of the Lubbock Pipeline Acquisition have not been presented as they are not significant.
5. Private Placement
The Partnership sold 375,000 common units in two installments at a price of $26.23 per unit in a private placement to certain accredited investors. The first installment of 300,031 units was completed on June 27, 2003, and grossed approximately $7.9 million. The second installment of 74,969 units was completed on July 10, 2003, and grossed approximately $1.9 million. Transaction costs for both
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installments were less than $0.1 million. The Partnership's general partner paid its pro rata contribution in July 2003 after the second installment was completed. We used the net proceeds from both installments to pay down debt under our credit facility.
6. Distribution to Unitholders
On August 14, 2003, we paid our cash distribution of $0.58 per common and subordinated unit for the quarterly period ended June 30, 2003. The distribution was declared on July 11, 2003, payable to unitholders of record as of August 4, 2003.
On October 22, 2003, we declared our cash distribution of $0.64 per common and subordinated unit for the quarterly period ended September 30, 2003. The distribution was paid on November 14, 2003, to unitholders of record as of November 4, 2003.
7. Net Income Per Limited Partner Unit
Basic net income per unit is determined by dividing net income, after deducting the general partner's 2% interest, by the weighted average number of outstanding common units and subordinated units. Diluted net income per unit is determined by dividing net income, after deducting the general partner's 2% interest, by the weighted average number of outstanding common units and subordinated units, increased to include the dilutive effect of outstanding restricted units.
8. Stock and Unit Compensation
As permitted under SFAS No. 123, Accounting for Stock-Based Compensation, we have elected to continue to measure compensation costs for unit-based and stock-based employee compensation plans as prescribed by Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees. We have a variable plan and certain employees of MarkWest Hydrocarbon who perform services for us receive stock-based compensation awards from MarkWest Hydrocarbon. We account for these plans using variable and fixed accounting as appropriate. Compensation expense for the variable plan, including restricted unit grants, is measured using the market price of our common units on the last trading day of the corresponding quarter and is amortized into earnings over the period of service. For the nine months ended September 30, 2003, we recognized $0.6 million of compensation expense for the variable plan. MarkWest Hydrocarbon stock options are issued under a fixed plan. Accordingly, compensation expense is not recognized for stock options unless the options were granted at an exercise price lower than market on the grant date.
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Had compensation cost for those employees principally supporting the Partnership who participated in MarkWest Hydrocarbon's stock-based compensation plan been determined based on the fair value at the grant dates under the plan consistent with the method prescribed by SFAS No. 123, our net income and net income per limited partner unit would have been affected as follows:
| Nine Months Ended September 30, 2003 (Partnership) | Nine Months Ended September 30, 2002 (As Restated. See Note 12) | ||||||
---|---|---|---|---|---|---|---|---|
| (in thousands, except per unit data) | |||||||
Net income, as reported | $ | 5,930 | $ | 20,668 | ||||
Add: Compensation expense included in reported net income | 554 | — | ||||||
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects | (693 | ) | (138 | ) | ||||
Pro forma net income | $ | 5,791 | $ | 20,530 | ||||
Net income per limited partner unit: | ||||||||
Basic—as reported | $ | 1.04 | $ | 4.96 | ||||
Basic—pro forma | $ | 1.01 | $ | 4.85 | ||||
Diluted—as reported | $ | 1.03 | $ | 4.95 | ||||
Diluted—pro forma | $ | 1.00 | $ | 4.83 |
9. Adoption of SFAS No. 143
In June 2001, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards ("SFAS") No. 143, Accounting for Asset Retirement Obligations, which addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. The standard applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset. SFAS No. 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset and this additional carrying amount is depreciated over the life of the asset. The liability is accreted at the end of each period through charges to operating expense. If the obligation is settled for other than the carrying amount of the liability, a gain or loss is recognized on settlement. We adopted the provisions of SFAS No. 143 effective January 1, 2003. In connection with the adoption of SFAS No. 143, we reviewed current laws and regulations governing obligations for asset retirements as well as our leases. Based on that review we did not identify any legal obligations associated with the retirement of our tangible long-lived assets. Therefore, the adoption of SFAS No. 143 did not have an impact on our consolidated financial statements.
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10. Recent Accounting Pronouncements
In May 2003, the FASB issued Statement of Financial Accounting Standards No. 150 ("SFAS No. 150"), "Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity." This statement establishes standards for the measurement and classification of certain financial instruments with characteristics of both liabilities and equity. SFAS No. 150 is effective for financial instruments entered into or modified after May 31, 2003, and otherwise effective the first interim period beginning after June 15, 2003. The adoption of this standard did not have any impact on the Partnership's financial position or results of operations.
In April 2003, the FASB issued Statement of Financial Accounting Standards No. 149 ("SFAS No. 149"), "Amendment of Statement 133 on Derivative Instruments and Hedging Activities." This statement amends and clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities under Statement of Financial Accounting Standards No. 133 ("SFAS No. 133"), "Accounting for Derivative Instruments and Hedging Activities." SFAS No. 149 is effective for contracts entered into or modified after June 30, 2003 and should be applied prospectively. However, provisions related to SFAS No. 133 Implementation Issues effective for fiscal quarters beginning prior to June 15, 2003 should continue to be applied in accordance with their respective dates. The adoption of this standard did not have any impact on the Partnership's financial position or results of operations.
11. Subsequent Event
On November 7, 2003, MarkWest Energy Partners entered into a Purchase and Sale Agreement with Shell Pipeline Company LP and other Shell subsidiaries, for the acquisition of Shell's Michigan Crude Gathering Pipeline assets for approximately $21 million. The acquisition will be financed utilizing our existing credit facility, which we anticipate expanding in conjunction with this acquisition.
The crude gathering assets, located in northern Michigan, are comprised of approximately 250 miles of pipelines, 4 truck unloading stations, associated terminals and tank facilities. The system is a common carrier Michigan intrastate pipeline and gathers approximately 16,000 bpd per day of light crude oil from wells throughout Michigan. The oil is transported for a fee to the Lewiston station where it is batch injected into the Enbridge Lakehead Pipeline, which then transports the oil to refineries in Sarnia Ontario, Canada. The pipeline provides the producers in Michigan an alternative to trucking the crude to the Sarnia refinery complex.
12. Restatement
The Partnership previously reported two separate statements of operations and of cash flows for the nine months ended September 30, 2002. One statement of operations and one statement of cash flows was presented for the period from January 1, 2002 through May 23, 2002 for the MarkWest Hydrocarbon Midstream Business prior to its conveyance to the Partnership on May 24, 2002. Another statement of operations and statement of cash flows was presented for the period from May 24, 2002 (the date the MarkWest Hydrocarbon Midstream Business was conveyed to the Partnership) through September 30, 2002.
The conveyance of the MarkWest Hydrocarbon Midstream Business from MarkWest Hydrocarbon to the Partnership represented a reorganization of entities under common control and was recorded at
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historical cost. Consequently, the Partnership has concluded these statements should be presented on a combined basis for the nine months ended September 30, 2002.
In addition, the Partnership had previously reported net income per limited partner unit for the period from May 24, 2002 through September 30, 2002. In its restated financial statements, the Partnership has restated income per limited partner unit to report such amount for the nine months ended September 30, 2002. The units used in the 2002 calculation of income per limited partner unit represent the weighted average of the 3,000,000 subordinated units issued by the Partnership in connection with the conveyance of the MarkWest Hydrocarbon Midstream Business to the Partnership and the 2,415,000 common units issued in the May 24, 2002 initial public offering. Net income used in the 2002 calculation has been reduced by the general partner's interest in net income.
In its restated financial statements for the nine months ended September 30, 2002 the Midstream Business recorded a non-cash adjustment of $17.2 million to eliminate deferred income tax liabilities that existed at the date of conveyance of the MarkWest Hydrocarbon Midstream Business from MarkWest Hydrocarbon to the Partnership. Accordingly, the Midstream Business has recorded a benefit to the deferred tax provision for the nine-months ended September 30, 2002 which increased net income by $17.2 million. This adjustment resulted from the change in the tax status of the MarkWest Hydrocarbon Midstream Business from a taxable entity to a partnership, which is not subject to taxation.
We have also restated to reflect the general partner's incentive distribution rights paid during the nine-month period ended September 30, 2003. The following sets forth the effects of the restatements discussed above.
| Nine Months Ended September 30, 2003 As Previously Reported | Nine Months Ended September 30, 2003 As Restated | ||||
---|---|---|---|---|---|---|
| (In thousands, except per unit amounts) | | ||||
General partners' interest in net income | $ | 119 | $ | 178 | ||
Limited partners' interest in net income | $ | 5,811 | $ | 5,752 | ||
Basic net income per limited partners' unit | $ | 1.05 | $ | 1.04 | ||
Diluted net income per limited partners' unit | $ | 1.04 | $ | 1.03 |
The following sets forth the effects of the restatements described above.
F-41
MARKWEST ENERGY PARTNERS, L.P.
CONDENSED CONSOLIDATED AND COMBINED STATEMENTS OF OPERATIONS
(unaudited)
| As Previously Reported | | | ||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Period From Commencement of Operations (May 24, 2002) Through September 30, 2002 (Partnership) | Period From January 1, 2002 Through May 23, 2002 (MarkWest Hydrocarbon Midstream Business) | Adjustments | Total Nine Months Ended September 30, 2002 (As Restated) | |||||||||||
| (in thousands, except per unit amounts) | ||||||||||||||
Revenues: | |||||||||||||||
Sales to unaffiliated parties | $ | 4,081 | $ | 37,043 | $ | — | $ | 41,124 | |||||||
Sales to affiliates | 14,647 | — | 14,647 | ||||||||||||
Total revenues | 18,728 | 37,043 | — | 55,771 | |||||||||||
Operating expenses: | |||||||||||||||
Purchased product costs | 6,436 | 26,598 | 33,034 | ||||||||||||
Facility expenses | 5,236 | 5,705 | 10,941 | ||||||||||||
Selling, general and administrative expenses | 1,423 | 2,206 | 3,629 | ||||||||||||
Depreciation | 1,787 | 1,916 | 3,703 | ||||||||||||
Total operating expenses | 14,882 | 36,425 | — | 51,307 | |||||||||||
Income from operations | 3,846 | 618 | 4,464 | ||||||||||||
Other income (expenses): | |||||||||||||||
Interest expense, net | (528 | ) | (461 | ) | (989 | ) | |||||||||
Miscellaneous income | 18 | — | 18 | ||||||||||||
Income before income taxes | 3,336 | 157 | — | 3,493 | |||||||||||
Provision (benefit) for income taxes: | |||||||||||||||
Current due from parent | — | (1,535 | ) | (1,535 | ) | ||||||||||
Deferred | — | 1,596 | (17,236 | ) | (15,640 | ) | |||||||||
Provision (benefit) for income taxes | — | 61 | (17,236 | ) | (17,175 | ) | |||||||||
Net income | $ | 3,336 | $ | 96 | $ | 17,236 | $ | 20,668 | |||||||
General partner's interest in net income | $ | 67 | $ | 67 | |||||||||||
Limited partners' interest in net income | $ | 3,269 | $ | 20,601 | |||||||||||
Basic net income per limited partner unit | $ | 0.60 | $ | 4.96 | |||||||||||
Diluted net income per limited partner unit | $ | 0.60 | $ | 4.95 | |||||||||||
Weighted average units outstanding: | |||||||||||||||
Basic | 5,415 | 4,150 | |||||||||||||
Diluted | 5,449 | 4,166 | |||||||||||||
F-42
MARKWEST ENERGY PARTNERS, L.P.
CONDENSED CONSOLIDATED AND COMBINED STATEMENTS OF CASH FLOWS
(unaudited)
| As Previously Reported | | | |||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Period From Commencement of Operations (May 24, 2002) through September 30, 2002 (Partnership) | Period From January 1, 2002 through May 23, 2002 (MarkWest Hydrocarbon Midstream Business | Adjustments | Total Nine Months Ended September 30, 2002 (As Restated) | ||||||||||||
| (in thousands) | |||||||||||||||
Cash flows from operating activities: | ||||||||||||||||
Net income | $ | 3,336 | $ | 96 | $ | 17,236 | $ | 20,668 | ||||||||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||||||||||
Depreciation | 1,787 | 1,916 | 3,703 | |||||||||||||
Amortization of deferred financing costs included in interest expense | — | — | — | |||||||||||||
Non-cash compensation expense | — | — | — | |||||||||||||
Deferred income taxes | — | 1,596 | (17,236 | ) | (15,640 | ) | ||||||||||
Other | 68 | (252 | ) | (184 | ) | |||||||||||
Changes in operating assets and liabilities: | ||||||||||||||||
(Increase) decrease in receivables | (4,801 | ) | 3,765 | (1,036 | ) | |||||||||||
(Increase) decrease in inventories | (100 | ) | 2,449 | 2,349 | ||||||||||||
(Increase) decrease in prepaid replacement natural gas and other assets | (73 | ) | 5,253 | 5,180 | ||||||||||||
Increase in accounts payable and accrued liabilities | 3,241 | 7,770 | 11,011 | |||||||||||||
Increase in long-term replacement natural gas payable | — | 3,090 | 3,090 | |||||||||||||
Net cash provided by operating activities | 3,458 | 25,683 | — | 29,141 | ||||||||||||
Cash flows from investing activities: | ||||||||||||||||
Pinnacle acquisition, net of cash acquired | — | — | — | |||||||||||||
Lubbock pipeline acquisition | — | — | — | |||||||||||||
Capital expenditures | (1,407 | ) | (498 | ) | (1,905 | ) | ||||||||||
Proceeds from sale of assets | 18 | — | 18 | |||||||||||||
Net cash used in investing activities | (1,389 | ) | (498 | ) | — | (1,887 | ) | |||||||||
Cash flows from financing activities: | ||||||||||||||||
Proceeds from initial public offering, net of transaction costs | 43,662 | — | 43,662 | |||||||||||||
Proceeds from private placement of common units, net of transaction costs | — | — | — | |||||||||||||
Proceeds from long-term debt | 23,400 | — | 23,400 | |||||||||||||
Repayment of long-term debt | (2,000 | ) | — | (2,000 | ) | |||||||||||
Distributions to unitholders | (1,160 | ) | — | (1,160 | ) | |||||||||||
Capital contribution from general partner | — | — | — | |||||||||||||
Net distributions to parent | — | (24,218 | ) | (24,218 | ) | |||||||||||
Debt due from parent | — | (967 | ) | (967 | ) | |||||||||||
Payments for debt issuance costs | (1,077 | ) | — | (1,077 | ) | |||||||||||
Distribution to MarkWest Hydrocarbon | (63,476 | ) | — | (63,476 | ) | |||||||||||
Net cash used in financing activities | (651 | ) | (25,185 | ) | — | (25,836 | ) | |||||||||
Net increase in cash | 1,418 | — | — | 1,418 | ||||||||||||
Cash and cash equivalents at beginning of period | — | — | — | — | ||||||||||||
Cash and cash equivalents at end of period | $ | 1,418 | $ | — | $ | — | $ | 1,418 | ||||||||
F-43
REPORT OF INDEPENDENT AUDITORS
To the Board of Directors of PNG Corporation:
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, cash flows and stockholders' equity, present fairly, in all material respects, the financial position of PNG Corporation and its subsidiaries at December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America. 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 auditing standards generally accepted in the United States of America, 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 our opinion.
/s/ PRICEWATERHOUSECOOPERS LLP
Denver, Colorado
August 8, 2003
F-44
PNG CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
| December 31, 2002 | December 31, 2001 | |||||||
---|---|---|---|---|---|---|---|---|---|
ASSETS | |||||||||
Current assets: | |||||||||
Cash and cash equivalents | $ | 4,444,311 | $ | 3,642,963 | |||||
Certificate of deposit | 186,484 | 181,191 | |||||||
Accounts receivable: | |||||||||
Trade | 5,365,685 | 3,357,957 | |||||||
Other | 151,713 | 512,671 | |||||||
Prepaid and other current assets | 88,648 | 68,254 | |||||||
Total current assets | 10,236,841 | 7,763,036 | |||||||
Property, plant and equipment, net | 30,461,518 | 34,087,678 | |||||||
Investments in unconsolidated affiliates | 1,759,573 | 1,661,775 | |||||||
Deferred income taxes | 4,259,954 | — | |||||||
Other non-current assets, net | 86,081 | 256,098 | |||||||
Total assets | $ | 46,803,967 | $ | 43,768,587 | |||||
LIABILITIES AND STOCKHOLDERS' EQUITY | |||||||||
Current liabilities: | |||||||||
Accounts payable | $ | 8,192,736 | $ | 4,593,247 | |||||
Accrued liabilities | 876,849 | 987,143 | |||||||
Current portion of long-term debt | 11,053,762 | 3,264,590 | |||||||
Current portion of related party subordinated debentures | 4,300,000 | — | |||||||
Total current liabilities | 24,423,347 | 8,844,980 | |||||||
Long-term debt, net of current maturities | 5,500,000 | 20,853,765 | |||||||
Deferred revenue | 6,837,161 | 7,042,570 | |||||||
Accrued stock compensation expense | 3,572,621 | 2,055,003 | |||||||
Total liabilities | 40,333,129 | 38,796,318 | |||||||
Commitments and contingencies (Note 8) | |||||||||
Minority interest | 30,935 | 177,923 | |||||||
Stockholders' Equity: | |||||||||
Common stock, $.01 par value, Class D, 5,000,000 shares authorized, 3,240,739 shares issued and outstanding at December 31, 2002 and 2001 | 32,407 | 32,407 | |||||||
Additional paid-in capital | 8,717,593 | 8,717,593 | |||||||
Accumulated deficit | (2,310,097 | ) | (3,955,654 | ) | |||||
Total stockholders' equity | 6,439,903 | 4,794,346 | |||||||
Total liabilities and stockholders' equity | $ | 46,803,967 | $ | 43,768,587 | |||||
The accompanying notes are an integral part of these financial statements.
F-45
PNG CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
| Year Ended December 31, | |||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2002 | 2001 | 2000 | |||||||||
Sales: | ||||||||||||
Gas sales | $ | 37,652,664 | $ | 42,762,969 | $ | 38,507,228 | ||||||
Transportation revenues | 695,900 | 1,030,806 | 1,171,895 | |||||||||
Condensate and liquid sales | 275,714 | 664,166 | 960,335 | |||||||||
Capacity fees and other | 5,042,758 | 3,670,220 | 2,121,667 | |||||||||
Total sales | 43,667,036 | 48,128,161 | 42,761,125 | |||||||||
Operating expenses: | ||||||||||||
Gas purchases | 32,612,663 | 38,128,538 | 33,000,082 | |||||||||
System operating expenses | 3,909,179 | 3,558,655 | 2,975,816 | |||||||||
General and administrative (includes non-cash stock compensation of $1,517,618, $1,656,429, and $398,574 in 2002, 2001 and 2000, respectively) | 3,264,550 | 3,143,124 | 2,060,476 | |||||||||
Depreciation and amortization | 3,471,729 | 2,631,599 | 2,567,473 | |||||||||
Impairment of operating assets | 1,672,295 | 1,740,017 | 2,472,735 | |||||||||
Gain on sale of assets | (109,476 | ) | — | — | ||||||||
Total operating expenses | 44,820,940 | 49,201,933 | 43,076,582 | |||||||||
Loss from operations | (1,153,904 | ) | (1,073,772 | ) | (315,457 | ) | ||||||
Other (expense) income: | ||||||||||||
Interest income | 9,211 | 75,662 | 68,718 | |||||||||
Interest expense | (1,278,246 | ) | (1,716,064 | ) | (1,870,110 | ) | ||||||
Equity in earnings (losses) of unconsolidated affiliates | (42,360 | ) | 124,509 | 93,358 | ||||||||
Impairment of unconsolidated affiliate | (248,766 | ) | — | — | ||||||||
Minority interest in net (income) loss of consolidated subsidiary | 146,988 | 43,961 | (59,277 | ) | ||||||||
Total other expense | (1,413,173 | ) | (1,471,932 | ) | (1,767,311 | ) | ||||||
Loss before income taxes | (2,567,077 | ) | (2,545,704 | ) | (2,082,768 | ) | ||||||
Income tax (benefit) expense | (4,212,634 | ) | 404,504 | — | ||||||||
Net income (loss) | $ | 1,645,557 | $ | (2,950,208 | ) | $ | (2,082,768 | ) | ||||
The accompanying notes are an integral part of these financial statements.
F-46
PNG CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDER'S EQUITY
| Class D Common Stock | | | | |||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Additional Paid In Capital | Accumulated Earnings/(Deficit) | | ||||||||||||
| Shares | Amounts | Total | ||||||||||||
Balances, December 31, 1999 | 3,037,035 | $ | 30,370 | $ | 8,169,630 | $ | 1,077,322 | $ | 9,277,322 | ||||||
Net loss | — | — | — | (2,082,768 | ) | (2,082,768 | ) | ||||||||
Issuance of Class D common stock | 203,704 | 2,037 | 547,963 | — | 550,000 | ||||||||||
Balances, December 31, 2000 | 3,240,739 | 32,407 | 8,717,593 | (1,005,446 | ) | 7,744,554 | |||||||||
Net loss | — | — | — | (2,950,208 | ) | (2,950,208 | ) | ||||||||
Balances, December 31, 2001 | 3,240,739 | 32,407 | 8,717,593 | (3,955,654 | ) | 4,794,346 | |||||||||
Net income | — | — | — | 1,645,557 | 1,645,557 | ||||||||||
Balances, December 31, 2002 | 3,240,739 | $ | 32,407 | $ | 8,717,593 | $ | (2,310,097 | ) | $ | 6,439,903 | |||||
The accompanying notes are an integral part of these financial statements.
F-47
PNG CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
| Year Ended December 31, | ||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2002 | 2001 | 2000 | ||||||||||
Cash flows from operating activities: | |||||||||||||
Net income (loss) | $ | 1,645,557 | $ | (2,950,208 | ) | $ | (2,082,768 | ) | |||||
Adjustments to reconcile net income (loss) to net cash flows provided by operating activities: | |||||||||||||
Gain on sale of assets | (109,476 | ) | — | — | |||||||||
Depreciation and amortization | 3,471,729 | 2,631,599 | 2,567,473 | ||||||||||
Amortization of deferred revenue | (205,409 | ) | — | — | |||||||||
Impairment of operating assets | 1,921,061 | 1,740,017 | 2,472,735 | ||||||||||
Equity in (income) losses of unconsolidated affiliate and/or net of distributions received | 117,360 | (124,509 | ) | (93,358 | ) | ||||||||
Stock compensation | 1,517,618 | 1,656,429 | 398,574 | ||||||||||
Amortization of deferred financing costs | 26,060 | 15,083 | 81,219 | ||||||||||
Deferred taxes | (4,259,954 | ) | — | — | |||||||||
Minority interest | (146,988 | ) | (43,961 | ) | 59,277 | ||||||||
Deferred revenue | — | 7,042,570 | — | ||||||||||
Changes in operating assets and liabilities: | |||||||||||||
Accounts receivable | (1,646,770 | ) | 4,205,726 | (2,872,788 | ) | ||||||||
Accounts payable and accrued liabilities | 3,489,195 | (3,017,718 | ) | 2,181,489 | |||||||||
Prepaid and other current assets | (20,394 | ) | (59,385 | ) | 47,175 | ||||||||
Other assets and liabilities | 143,957 | (197,280 | ) | — | |||||||||
Net cash flows provided by operating activities | 5,943,546 | 10,898,363 | 2,759,028 | ||||||||||
Cash flows from investing activities: | |||||||||||||
Capital expenditures | (1,775,046 | ) | (12,559,608 | ) | (3,240,468 | ) | |||||||
Contributions to unconsolidated affiliates | (463,924 | ) | (615,311 | ) | (229,506 | ) | |||||||
Proceeds from the sale of assets | 366,658 | 45,000 | — | ||||||||||
Other | (5,293 | ) | (9,052 | ) | (9,417 | ) | |||||||
Net cash flows used in investing activities | (1,877,605 | ) | (13,138,971 | ) | (3,479,391 | ) | |||||||
Cash flows from financing activities: | |||||||||||||
Payments on debt | (3,264,593 | ) | (2,194,354 | ) | (489,439 | ) | |||||||
Proceeds from issuance of debt | — | 5,500,000 | 2,608,855 | ||||||||||
Deferred financing costs | — | (55,000 | ) | — | |||||||||
Distributions to minority interest | — | (61,111 | ) | — | |||||||||
Proceeds from issuance of class of common stock | — | — | 550,000 | ||||||||||
Net cash flows used in financing activities | (3,264,593 | ) | 3,189,535 | 2,669,416 | |||||||||
Net increase in cash and cash equivalents | 801,348 | 948,927 | 1,949,053 | ||||||||||
Cash and cash equivalents, beginning of period | 3,642,963 | 2,694,036 | 744,983 | ||||||||||
Cash and cash equivalents, end of period | $ | 4,444,311 | $ | 3,642,963 | $ | 2,694,036 | |||||||
Supplemental cash flow information: | |||||||||||||
Cash paid for interest | $ | 1,284,338 | $ | 1,806,103 | $ | 1,821,200 | |||||||
Cash paid for taxes | $ | — | $ | 250,000 | $ | — |
The accompanying notes are an integral part of these financial statements.
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PNG CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Organization and Business
PNG Corporation, a Delaware corporation ("PNG" or the "Company"), was incorporated on September 6, 1994. The Company's assets are primarily the result of the acquisition of the joint venture interest of Pinnacle Natural Gas Company, incorporated March 12, 1985, and affiliated companies. Effective April 4, 1997, PNG was acquired and simultaneously recapitalized by Energy Spectrum Partners LP ("Energy Spectrum"). The acquisition, which was accounted for under the purchase method of accounting, resulted in a "pushdown" of the purchase price to PNG's assets and liabilities based on their estimated fair values as of April 1, 1997, the effective date of the acquisition for accounting purposes.
These consolidated financial statements include the accounts of PNG and its subsidiaries. All subsidiaries are wholly owned, except for Bright Star Gathering Incorporated's 90-percent owned subsidiary, Bright Star Partnership. As reorganized, the principal operating subsidiaries of the Company are as follows:
Pinnacle Natural Gas Company
Pinnacle Natural Gas Transmission Company
Pinnacle Pipeline Company
Pinnacle Natural Gas Utility Company
Alabama Pinnacle Corporation
Bright Star Gathering Incorporated
Bright Star Partnership
PNG was organized to own and operate gas gathering and transmission facilities. The Company owns interest in and operates gas pipeline systems in Texas, New Mexico, Louisiana, Mississippi and Colorado. The Company provides gas gathering, processing, transmission and marketing services to its customers.
2. Summary of Significant Accounting Policies
Principles of Consolidation
The accompanying consolidated financial statements include the accounts of the entities described in Note 1. All intercompany transactions have been eliminated in consolidation. The Company's interest in certain non-controlled investments is accounted for by the equity method.
Use of Estimates
Preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States of America 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 consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Concentration of Risks
Financial instruments that may potentially subject the Company to a concentration of credit risk consist primarily of cash and cash equivalents and accounts receivable. All cash and cash equivalents are with creditworthy financial institutions. Substantially all of the Company's accounts receivable result
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from sales of products and transmission services provided to customers in the oil and gas industry. This concentration of customers may impact the Company's overall credit risk, either positively or negatively, in that entities in the same industry may be similarly affected by changes in economic or other conditions. To limit the credit risk, the Company evaluates its customers' financial strengths and ability to withstand negative market conditions. The Company had two customers that accounted for approximately 58% and 23%, two customers that accounted for approximately 35% and 12%, and four customers that accounted for approximately 16%, 14%, 10% and 10% of accounts receivable for the years ended December 31, 2002, 2001, and 2000, respectively. The Company had four suppliers that accounted for approximately 42%, 11% and 10%; three suppliers that accounted for approximately 20%, 18% and 12%; and one supplier that accounted for approximately 12% of accounts payable for the years ended December 31, 2002, 2001 and 2000, respectively. The Company had two customers that accounted for approximately 56% and 11%; three customers that accounted for approximately 25%, 10% and 10%; and three customers that accounted for approximately 13%, 11% and 11% of revenue for the years ended December 31, 2002, 2001 and 2000, respectively. The Company also had three suppliers that accounted for approximately 35%, 14% and 10% and two suppliers that accounted for approximately 14% and 10% of purchases for the years ended December 31, 2002 and 2001, respectively. For the year ended December 31, 2000, no one supplier represented more than 10% of purchases.
Cash and Cash Equivalents
Cash and cash equivalents consist of short-term, highly liquid investments readily convertible into cash with an original maturity of three months or less. The Company places its temporary cash investments with high-credit quality financial institutions. The Company believes no significant concentration of credit risk exists with respect to these cash investments.
Certificate of Deposit
As of December 31, 2002 and 2001, approximately $186,000 and $181,000, respectively, are invested in a certificate of deposit, with an original maturity in excess of three months, which collateralizes certain loans of one of the Company's unconsolidated affiliates (see Note 9).
Accounts Receivable
The Company has a consistent customer base. The Company controls credit risk related to accounts receivable through credit approvals, credit limits and monitoring procedures. An estimated allowance for doubtful accounts is provided based on prior experience and specific review of past-due balances.
Property, Plant and Equipment
Property, plant and equipment additions are recorded at cost. The Company's property, plant and equipment primarily consist of (a) gas gathering systems used to transport gas from the wellhead to major pipelines and (b) pipelines used to transport gas from the major pipelines to the end users. Depreciation of gas gathering systems and pipelines is provided using the straight-line method of depreciation based over their useful lives of such facilities, which range from five to twenty years. In
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addition, depreciation is computed using the straight-line method of depreciation over their useful lives of three to fifteen years for building, office furniture and fixtures and computer equipment.
The cost of normal maintenance and repairs is expensed as incurred. Significant expenditures that increase the life of an asset are capitalized and depreciated over the remaining estimated useful life of the asset. Upon sale or retirement of an asset, the cost and related accumulated depreciation are eliminated and any resulting gain or loss is reflected in operations.
Interest costs related to significant construction projects are capitalized based on the weighted average interest rate of outstanding borrowings. During 2002, no interest was capitalized. During 2001 and 2000, capitalized interest totaled approximately $77,000 and $149,000, respectively.
Impairment of Long-Lived Assets
When events or changes in circumstances indicate that the carrying amount of long-lived assets may not be recoverable, an evaluation is performed to determine if an impairment exists. We compare the carrying amount of the assets to the undiscounted expected future cash flows. If this comparison indicates that an impairment exists, the assets are written down to fair value. Fair value is calculated using discounted expected future cash flows. The Company recorded an impairment charge of approximately $1.9 million, $1.7 million and $2.5 million in 2002, 2001 and 2000, respectively.
Deferred Financing Costs
Other non-current assets primarily consist of deferred financing costs. Deferred financing costs are amortized over the life of the related bank financing using the straight-line method, which approximates the interest method. Amortization of these deferred financing costs totaled approximately $26,000, $15,000 and $81,000 in 2002, 2001 and 2000, respectively.
Revenue Recognition
Sales of natural gas are reported in the month of delivery and purchases of gas are reported in the month of receipt. Transmission and capacity fees for transporting natural gas are reported in the month transportation service is provided. Gas volumes received may be different from gas volumes delivered, resulting in gas imbalances. The Company records a receivable or payable for such imbalances based upon the prices in effect the month in which the imbalances arise. The balances are reduced upon receipt or payment of such amounts or the receipt or delivery of equivalent volumes of gas.
Under Staff Accounting Bulletin ("SAB") No. 101, "Revenue Recognition in Financial Statements," up-front fees received at the commencement of a service contract are deferred and amortized over the term of the contract. Amounts received by the Company relating to its construction of pipelines are deferred and amortized to revenue over the appropriate contract term. Such unamortized deferred revenues were approximately $6.8 million and $7.0 million at December 31, 2002 and 2001, respectively.
The Company received approximately $200,000 in 2001 as an early completion bonus relating to its pipeline construction agreement. These amounts are recognized when they are earned and realized, which is upon early completion of the project. No such amounts were realized or recorded in 2002 or 2000.
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Income Taxes
Deferred income tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis using enacted tax rates in effect for the year in which the differences are expected to affect taxable income. Valuation allowances are established when necessary to reduce deferred tax assets to the amounts expected to be ultimately realized.
Fair Value of Financial Instruments
The Company's financial instruments consist primarily of cash and cash equivalents, accounts receivable, accounts payable and debt. In management's opinion, the carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate their fair values at December 31, 2002 and 2001 due to the short-term nature of these instruments. In management's opinion, the fair value of the Company's debt approximates its carrying amounts at December 31, 2002 and 2001, because the debt is based on variable interest rates.
Stock-Based Compensation
The Company accounts for its employee stock options and other employee stock-based compensation arrangements in accordance with the provisions of Accounting Principles Board Opinion No. 25 ("APB Opinion No. 25"), "Accounting for Stock Issued to Employees," and related interpretations. The Company has adopted the disclosure-only provisions of Statement of Financial Accounting Standards No. 123 ("SFAS No. 123"), "Accounting for Stock-Based Compensation," as amended by SFAS No. 148, "Accounting for Stock-based Compensation—an Amendment to SFAS No. 123", which allows entities to continue to apply the provisions of APB Opinion No. 25 for transactions with employees and provide pro forma disclosures for employee stock grants as if the fair-value-based method of accounting in SFAS No. 123 had been applied to these transactions. The Company accounts for equity instruments issued to non-employees in accordance with the provisions of SFAS No. 123 and related interpretations. Had compensation cost been determined based on the fair value at the grant dates under the plan consistent with the method prescribed by SFAS No. 123, our net income (loss) would have been affected as follows:
| Year Ended December 31, | |||||||||
---|---|---|---|---|---|---|---|---|---|---|
| 2002 | 2001 | 2000 | |||||||
Net income (loss), as reported | $ | 1,645,557 | $ | (2,950,208 | ) | $ | (2,082,768 | ) | ||
Stock-based compensation as reported, net of related tax effects | 986,452 | 1,076,679 | 259,073 | |||||||
Pro forma stock-based employee compensation expense determined under fair value based method, net of related tax effects | (55,996 | ) | (75,155 | ) | (41,892 | ) | ||||
Pro forma net income (loss) | $ | 2,576,013 | $ | (1,948,684 | ) | $ | (1,865,587 | ) | ||
For purposes of this pro forma disclosure, pro forma stock-based compensation is calculated based on the fair value of the options granted and is amortized to expense on a straight-line basis over the
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vesting period. The fair value of the options were estimated using the Black-Scholes option valuation model with the following assumptions: a risk-free interest rate of five percent; expected term of five years; and a volatility and dividend yield of zero percent.
Comprehensive Income (Loss)
The Company adopted SFAS No. 130, "Reporting Comprehensive Income" ("SFAS No. 130") on January 1, 1998. SFAS No. 130 establishes standards for reporting and displaying comprehensive income and its components in a full-set of general-purpose financial statements. There was no difference between the Company's net income and its total comprehensive income (loss) for the years ended December 31, 2002, 2001 and 2000.
Recent Accounting Pronouncements
In June 2001, the Financial Accounting Standards Board (the "FASB") issued SFAS No. 143 ("SFAS No. 143"), "Accounting for Asset Retirement Obligations", which addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. The standard applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset. SFAS No. 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset and this additional carrying amount is depreciated over the life of the asset. The liability is accreted at the end of each period through charges to operating expense. If the obligation is settled for other than the carrying amount of the liability, a gain or loss is recognized on settlement. The provisions of this statement are effective for fiscal years beginning after June 15, 2002. The adoption of SFAS No. 143 will not have an impact on our consolidated financial statements.
On June 28, 2002, the FASB voted in favor of issuing SFAS No. 146 ("SFAS 146"), "Accounting for Exit or Disposal Activities". SFAS 146 addresses significant issues regarding the recognition, measurement and reporting of costs that are associated with exit and disposal activities, including restructuring activities that are currently accounted for pursuant to the guidance that the EITF has set forth in EITF Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)." The scope of SFAS 146 also includes (1) costs related to terminating a contract that is not a capital lease and (2) termination benefits that employees who are involuntarily terminated receive under the terms of a one-time benefit arrangement that is not an ongoing benefit arrangement or an individual deferred-compensation contract. SFAS 146 will be effective for financial statements issued with exit or disposal activities initiated after December 31, 2002. Management does not believe SFAS No. 146 will have a material impact on the Company's financial position, results of operations or cash flows.
In November 2002, the FASB issued FASB Interpretation No. 45 ("FIN 45"), "Guarantor's Accounting and Disclosure Requirements of Guarantees, Including Indirect Guarantees of Indebtedness of Others." FIN 45 requires that upon issuance of a guarantee, a guarantor must recognize a liability for the fair value of the obligation assumed under a guarantee. In addition, FIN 45 requires disclosures about the guarantees that an entity has issued.
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The recognition and measurement provisions of FIN 45 are effective for any guarantees issued or modified after December 31, 2002. Management does not expect that the adoption of FIN 45 will have a material effect on the Company's financial position, results of operations, or cash flows.
The FASB issued Interpretation No. 46 ("FIN 46"), "Consolidation of Variable Interest Entities, and An Interpretation of ARB 51". The primary objectives of FIN 46 are to provide guidance on the identification of entities for which control is achieved through means other than through voting rights ("variable interest entities" or "VIEs") and how to determine when and which business enterprise should consolidate the VIE (the "primary beneficiary"). This new model for consolidation applies to an entity which either (1) the equity investors (if any) do not have a controlling financial interest or (2) the equity investment at risk is insufficient to finance that entity's activities without receiving additional subordinated financial support from other parties. In addition, FIN 46 requires that both the primary beneficiary and all other enterprises with a significant variable interest in a VIE make additional disclosures. As of December 31, 2002, the Company was not party to a VIE; therefore, management does not believe FIN 46 will have a material impact on the Company's financial position, results of operations or cash flows.
3. Acquisitions and Disposition of Assets
In 2000, the Company completed construction of a 33-mile natural gas pipeline under a 30-year transportation contract with SEI Texas, LLP. The contract provides for a fixed monthly fee to operate and maintain the pipeline over the life of the contract. The construction cost was approximately $10.4 million, and operations began in May 2001. In order to finance this construction, the Company entered into a construction credit agreement (see Note 5) due in 2005.
In June 2001, the Company began construction of a seven-mile pipeline and a 21-mile pipeline to supply a power plant in Guadalupe County, Texas. Construction was completed in December 2001 for a total cost of approximately $12.0 million. In order to finance this construction, the Company borrowed an additional $5.5 million from its revolving credit facility (see Note 5), and an additional $7.0 million was funded by the owner of the power plant, which was classified as deferred revenues in the accompanying Consolidated Balance Sheet.
4. Property, Plant and Equipment
Property, plant and equipment consisted of the following as of December 31:
| 2002 | 2001 | |||||
---|---|---|---|---|---|---|---|
Gas gathering systems and pipelines | $ | 45,160,935 | $ | 33,537,546 | |||
Construction in progress | — | 12,102,864 | |||||
Building | 135,756 | 135,756 | |||||
Office furniture and fixtures and computer equipment | 551,521 | 547,787 | |||||
45,848,212 | 46,323,953 | ||||||
Less accumulated depreciation | (15,386,694 | ) | (12,236,275 | ) | |||
Total property, plant and equipment | $ | 30,461,518 | $ | 34,087,678 | |||
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Depreciation expense was approximately $3.5 million, $2.6 million and $2.6 million for the years ended December 31, 2002, 2001 and 2000, respectively.
5. Long-term Debt and Revolving Credit Agreement
Long-term debt consisted of the following as of December 31:
| 2002 | 2001 | ||||||
---|---|---|---|---|---|---|---|---|
Revolving credit facility | $ | 7,500,000 | $ | 9,000,000 | ||||
Construction credit agreement, A | 4,404,952 | 5,383,831 | ||||||
Construction credit agreement, B | 4,648,810 | 5,434,524 | ||||||
Related party subordinated debentures | 4,300,000 | 4,300,000 | ||||||
Total long-term debt | 20,853,762 | 24,118,355 | ||||||
Less-current portion | (15,353,762 | ) | (3,264,590 | ) | ||||
Long-term portion of debt | $ | 5,500,000 | $ | 20,853,765 | ||||
The Company's bank credit agreements consist of a $10.0 million revolving credit facility (the "Revolver") and two pipeline construction credit agreements (the "Construction Credit Agreements"), one of them for up to $7.5 million and the other for up to $5.5 million.
The Company had outstanding borrowings on the Revolver of $7.5 million as of December 31, 2002, and outstanding borrowings on the Construction Credit Agreements of $4.4 million and $4.6 million in 2002. The Company had outstanding borrowings on the Revolver of $9.0 million as of December 31, 2001 and outstanding borrowings on the Construction Credit Agreements of $5.4 million and $5.4 million in 2001.
Principal payments under the Revolver began January 1, 2001 (the "Commitment Termination Date"), and are made on the last day of each quarter in the amount of $375,000 until December 2003, escalating to $500,000 each quarter thereafter until June 2005, with the remaining outstanding balance of $2.5 million scheduled to be repaid at June 2005. Each year the Company may request and receive, at the sole discretion of the bank, a one-year extension of the Commitment Termination Date and the maturity date. Additionally, the borrowing base under the Revolver is redetermined each year.
Borrowings under the Revolver are collateralized by substantially all of the assets of the Company and bear interest at the bank's prime rate, plus an escalating rate up to 0.25 percent, or LIBOR plus 2.125 percent. The weighted average interest rate was 4.02 percent as of December 31, 2002. The Company is also required to pay a quarterly commitment fee (0.375 percent per annum) on the average daily amount by which the borrowing base exceeds the outstanding advances until the Commitment Termination Date. Interest is payable monthly on outstanding borrowings.
Conversion of the first Construction Credit Agreement to start principal payments began in April 2000 when construction of the 33-mile pipeline being built under the transportation agreement with SEI Texas, LLP (an unaffiliated third party) was completed. The Company's principal payments are paid in 59 consecutive monthly installments of an amount equal to 1/84 of the outstanding advance, with one lump-sum payment of the remaining outstanding aggregate principal balance due on April 4, 2005. Advances bear interest at the bank's prime rate or LIBOR, plus an escalating rate up to
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2.25 percent. The Company is also required to pay a quarterly commitment fee (0.375 percent per annum) on the average daily amount by which the borrowing base exceeds the outstanding advances until the completion of the pipeline construction. Interest is payable monthly on outstanding borrowings.
Conversion of the second Construction Credit Agreement to start principal payments began in December 2001 when the Company completed its construction of the pipelines in Guadalupe County. The Company's principal payments are paid in 59 consecutive monthly installments of an amount equal to 1/84 of the amount advanced, with one lump-sum payment of the remaining outstanding aggregate principal balance due in 2006.
Related Party Subordinated Debt
As of December 31, 2002 and 2001, the Company had $4.3 million outstanding in subordinated debt to Energy Spectrum, an affiliate of the Company, which is due in April 2003. Such debt bears simple interest at 11% per annum.
Bank Debt Covenants
The Revolver requires that the Company be in compliance with certain financial covenants including, but not limited to, restrictions on indebtedness, investments and dividends. The Company's annual capital expenditures cannot exceed an amount equal to its annually submitted budget plus $250,000. In addition, on a quarterly basis, the Company must comply with a current ratio of 1.00 to 1.00, an interest charge coverage ratio of 2.00 to 1.00 and a debt service coverage ratio of 1.25 to 1.00. At December 31, 2002, the Company was in violation of one financial covenant. The Company did not obtain a waiver for such violation and has classified such debt as current as of December 31, 2002. At December 31, 2001, the Company was in compliance with such covenants.
The Company's Construction Credit Agreements, upon conversion to term loans, requires that the Company be in compliance with certain financial covenants including, but not limited to, restrictions on indebtedness, investments and dividends. The Company's annual capital expenditures cannot exceed an amount equal to annually submitted budget plus $250,000. In addition, on a quarterly basis, the Company must comply with a current ratio of 1.00 to 1.00, an interest charge coverage ratio of 2.00 to 1.00 and a debt service coverage ratio of 1.15 to 1.00. At December 31, 2002, the Company was in violation of one financial covenant. The Company did not obtain a waiver for such violation and has classified such debt as current at December 31, 2002. At December 31, 2001, the Company was in compliance with such covenants.
There are no covenants governing the related party subordinated debentures.
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Maturities
The maturities of the Company's debt as of December 31, 2002, are as follows:
2003 | $ | 15,353,762 | |
2004 | 2,000,000 | ||
2005 | 3,500,000 | ||
2006 | — | ||
2007 | — | ||
2008 and thereafter | — | ||
$ | 20,853,762 | ||
In March 2003, the Company sold substantially all of its assets to MarkWest Energy Partners, L.P. (see Note 11). Upon completion of the sale, all bank and related party subordinated debt was paid in full.
6. Equity Transactions
The Company has an incentive equity plan (the "2000 Plan") whereby options to purchase 486,000 shares of the Company's common stock were issued to certain key employees in 2000. These option vest over a three-year period, with 162,000 options vesting on April 1, 2001, 2002 and 2003, and have a maximum term of five years (expiring on March 31, 2005). On the date of grant, the exercise price of the option approximated the fair value of the stock. The exercise price of each option increases periodically, and ranges between $2.70 and $4.24 over the term of the options.
Pursuant to APB No. 25, due to the escalation feature of the exercise price, the Company has accounted for the stock option grants under the 2000 Plan using variable plan accounting. The Company has and will continue to mark to market the outstanding options until the exercise of the related option occurs or the exercise price becomes fixed. As of December 31, 2002, 2001 and 2000, the Company recognized stock-based compensation for the fair value of the stock options in the amount of approximately $1.5 million, $1.7 million and $399,000, respectively, in the Consolidated Statement of Operations with a corresponding liability included in other non-current liabilities in the Consolidated Balance Sheet. Subsequent to December 31, 2002, these options were settled for approximately $0.5 million (see Note 11).
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The Company's stock option activity follows:
| Number of shares underlying options | ||
---|---|---|---|
Options | |||
Outstanding at December 31, 1999 | — | ||
Granted | 486,000 | ||
Exercised | — | ||
Expired | — | ||
Forfeited | — | ||
Outstanding at December 31, 2000 | 486,000 | ||
Granted | — | ||
Exercised | — | ||
Expired | — | ||
Forfeited | — | ||
Outstanding at December 31, 2001 | 486,000 | ||
Granted | — | ||
Exercised | — | ||
Expired | — | ||
Forfeited | (54,000 | ) | |
Outstanding at December 31, 2002 | 432,000 | ||
At December 31, 2002, approximately 288,000 options were exercisable at a weighted average price of $3.43 per share and a weighted average remaining contractual life of 2.44 years.
At December 31, 2001, approximately 162,000 options were exercisable at a weighted average price of $3.11. There were no options exercisable at December 31, 2000.
7. Income Taxes
The Company uses the asset and liability method of accounting for deferred income taxes. Total income tax expense (benefit) consists of the following as of December 31:
| 2002 | 2001 | 2000 | ||||||
---|---|---|---|---|---|---|---|---|---|
Current tax expense | $ | 47,320 | $ | 404,504 | $ | — | |||
Deferred tax benefit | (4,259,954 | ) | — | — | |||||
Total income tax (benefit) expense | $ | (4,212,634 | ) | $ | 404,504 | $ | — | ||
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The components of net deferred income taxes are as follows as of December 31:
| 2002 | 2001 | ||||||
---|---|---|---|---|---|---|---|---|
Deferred tax assets: | ||||||||
Stock-based compensation | $ | 1,250,417 | $ | 719,251 | ||||
Deferred revenue | 2,393,007 | 2,464,900 | ||||||
Net operating loss carryforwards | 5,092,792 | 4,811,576 | ||||||
Other | 37,302 | 152,860 | ||||||
Total deferred tax assets | 8,773,518 | 8,148,587 | ||||||
Deferred tax liabilities: | ||||||||
Property and equipment | (1,436,587 | ) | (1,884,231 | ) | ||||
Partnership income | (463,604 | ) | (391,280 | ) | ||||
Other | (12,515 | ) | — | |||||
Total deferred tax liabilities | (1,912,706 | ) | (2,275,511 | ) | ||||
Net deferred tax asset | 6,860,812 | 5,873,076 | ||||||
Valuation allowance | (2,600,858 | ) | (5,873,076 | ) | ||||
Net deferred taxes | $ | 4,259,954 | $ | — | ||||
The deferred tax asset of December 31, 2002, of $6.9 million was recorded net of a $2.6 million valuation allowance based on management's belief that the net tax asset is more likely than not to be realizable. In March 2003, the Company sold substantially all of its assets to MarkWest Energy Partners, L.P. (see Note 11). As a result of the sale, the Company expects to recognize taxable income and accordingly has reversed the valuation allowance previously recorded against certain net deferred tax assets. The remaining valuation allowance has been provided for certain net operating loss carryovers related to Bright Star Gathering, Inc., which are subject to annual limitation. Management believes that these assets will not be realized due to the limitation and as such did not reverse the valuation allowance associated with these assets. The Company's net operating losses will begin to expire in 2008.
The difference between the provision for income taxes and the amount that would be determined by applying the statutory income tax rate to income before income taxes is as follows for the years ended December 31:
| 2002 | 2001 | 2000 | ||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
Computed statutory tax benefit at 35% | $ | (949,923 | ) | $ | (906,383 | ) | $ | (708,222 | ) | ||
Changes in taxes resulting from: | |||||||||||
State tax, net of federal tax benefit | — | 170,683 | — | ||||||||
Permanent differences | 9,507 | 6,160 | 2,205 | ||||||||
Change in valuation allowance adjustment | (3,272,218 | ) | 1,134,044 | 706,017 | |||||||
Total income tax benefit | $ | (4,212,634 | ) | $ | 404,504 | $ | — | ||||
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8. Commitments and Contingencies
Leases
The Company has operating leases, primarily for office space and compression facilities. For the years ended December 31, 2002, 2001 and 2000, the Company charged $1.5 million $1.5 million and $1.3 million, respectively, to expense relating to operating leases.
As of December 31, 2002, future minimum rental payments are as follows:
2003 | $ | 619,465 | |
2004 | 137,651 | ||
2005 | — | ||
2006 | — | ||
2007 | — | ||
2008 and thereafter | $ | 757,116 | |
Litigation
In 2001, Pinnacle Natural Gas Company and a number of other parties were named as defendants in an action brought by Ray and Debra Noseff who seek unspecified compensatory and punitive damages for claims based on loss of consortium and Mr. Noseff's personal injuries. Mr. Noseff was injured on July 8, 1998 by a gas line fire at the Pinnacle Lea delivery point. The proceedings captionedRay Noseff, et al., Plaintiffs v. Pinnacle Natural Gas Company, Michael Tindle, Enron Corp., Northern Natural Gas Co., Daniel Industries, Inc., Constant Power Manufacturing Co., Peter Paul, Inc., Skinner, Inc., and Honeywell, Inc., Defendants (Case No. CV-200101278) are pending in the Second Judicial Circuit, Bernalillo County, New Mexico. The Company's costs and legal exposure related to this lawsuit are currently not determinable.
9. Investment in Unconsolidated Affiliates
In 2002, the Company had equity positions in two gathering systems, Texana Pipeline Company JV (37.5%) ("Texana") and Las Animas Landfill Gas, L.L.C. (18.48%) ("Las Animas").
Located in Refugio and San Patricio Counties, Texas, Texana is a joint venture between a private individual, Enbridge US and the Company that gathers wellhead gas from several locations and delivers the gas to industrial users and markets. For a monthly fee, the Company provides the accounting and financial reporting for Texana but does not exercise control over the operations and merchant capabilities of the system.
Las Animas is a limited liability company that provides gas processing, gathering and extraction for the Johnson County Landfill near Shawnee, Kansas. The principal shareholder/operator is South-Tex Treaters Inc. The Company participates in the Las Animas' annual meetings but does not exercise control over the operations and policies of Las Animas. As part of its financial responsibility to Las Animas, the Company guarantees up to 24% of the outstanding loan, or approximately $0.3 million as of December 31, 2002, held by Las Animas.
F-60
The Company uses the equity method of accounting for its investments in its unconsolidated affiliates. The following table summarizes the status and results of the Company's investments.
| 2002 | 2001 | 2000 | ||||||
---|---|---|---|---|---|---|---|---|---|
Beginning investments | $ | 1,661,775 | $ | 921,955 | $ | 599,091 | |||
Capital contributions | 463,924 | 615,311 | 229,506 | ||||||
Distributions received | (75,000 | ) | — | — | |||||
Impairment | (248,766 | ) | — | — | |||||
Equity in earnings (losses) | (42,360 | ) | 124,509 | 93,358 | |||||
Ending investments | $ | 1,759,573 | $ | 1,661,775 | $ | 921,955 | |||
10. Benefit Plan
The Company contributed approximately $17,000, $17,000 and $14,000 to a 401(k) savings plan for the year ended December 31, 2002, 2001 and 2000, respectively. The plan was terminated in early 2003.
11. Subsequent Event
On March 28, 2003, substantially all of Pinnacle Natural Gas Company and certain affiliates were merged with certain affiliates of MarkWest Energy Partners, L.P. for approximately $38 million. The acquisition price included the assumption and payment of all bank debt. These financial statements do not include any adjustments related to the acquisition.
F-61
INDEPENDENT ACCOUNTANTS' REPORT
Management Committee and Members
American Central Western Oklahoma
Gas Company, L.L.C.
Tulsa, Oklahoma
We have audited the accompanying balance sheets of AMERICAN CENTRAL WESTERN OKLAHOMA GAS COMPANY, L.L.C. as of December 31, 2002 and 2001, and the related statements of income, changes in members' equity, and cash flows for each of the three years in the period ended December 31, 2002. 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 in accordance with auditing standards generally accepted in the United States of America. Those standards 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. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of AMERICAN CENTRAL WESTERN OKLAHOMA GAS COMPANY, L.L.C. as of December 31, 2002 and 2001, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America.
/s/BKD,LLP
Tulsa, Oklahoma
February 18, 2003
F-62
AMERICAN CENTRAL WESTERN OKLAHOMA GAS COMPANY, L.L.C.
BALANCE SHEETS
DECEMBER 31, 2002 AND 2001
| 2002 | 2001 | ||||||
---|---|---|---|---|---|---|---|---|
ASSETS | ||||||||
Current Assets | ||||||||
Cash | $ | 217,137 | $ | 1,465,886 | ||||
Accounts receivable | 4,162,479 | 2,646,115 | ||||||
Other current assets | 161,093 | 85,344 | ||||||
Total current assets | 4,540,709 | 4,197,345 | ||||||
Property and Equipment, At Cost | ||||||||
Gas systems | 34,359,659 | 31,050,463 | ||||||
Gas plant | 9,290,885 | 9,290,885 | ||||||
Furniture and fixtures | 23,098 | 23,098 | ||||||
Construction in progress | 709,064 | 2,196,421 | ||||||
44,382,706 | 42,560,867 | |||||||
Less accumulated depreciation | 7,513,557 | 5,352,545 | ||||||
36,869,149 | 37,208,322 | |||||||
$ | 41,409,858 | $ | 41,405,667 | |||||
LIABILITIES AND MEMBERS' EQUITY | ||||||||
Current Liabilities | ||||||||
Accounts payable and accrued expenses | $ | 3,458,290 | $ | 2,986,898 | ||||
Accounts payable to related parties | 196,223 | 714,829 | ||||||
Total current liabilities | 3,654,513 | 3,701,727 | ||||||
Members' Equity | 37,755,345 | 37,703,940 | ||||||
$ | 41,409,858 | $ | 41,405,667 | |||||
The accompanying notes are an integral part of these financial statements.
F-63
AMERICAN CENTRAL WESTERN OKLAHOMA GAS COMPANY, L.L.C.
STATEMENTS OF INCOME
YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
| 2002 | 2001 | 2000 | ||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
Revenues | |||||||||||
Gas sales and gathering | $ | 21,938,520 | $ | 21,019,143 | $ | 16,387,209 | |||||
Plant liquid sales | 2,712,069 | 1,581,300 | 4,475,482 | ||||||||
24,650,589 | 22,600,443 | 20,862,691 | |||||||||
Cost of Gas and Liquid Sales | 17,371,159 | 17,190,770 | 13,067,670 | ||||||||
Gross Profit | 7,279,430 | 5,409,673 | 7,795,021 | ||||||||
Operating Expenses | |||||||||||
Cost of field operations | 2,452,753 | 2,292,732 | 1,989,718 | ||||||||
Equipment rental | 245,691 | 239,587 | 280,278 | ||||||||
Depreciation | 2,161,012 | 1,964,944 | 1,693,844 | ||||||||
General and administrative | 113,770 | 204,043 | 420,038 | ||||||||
Management fee to managing member, net of amount capitalized | 1,866,804 | 1,911,689 | 1,302,864 | ||||||||
Loss on asset exchange | — | 554,046 | — | ||||||||
6,840,030 | 7,167,041 | 5,686,742 | |||||||||
Income (Loss) from Operations | 439,400 | (1,757,368 | ) | 2,108,279 | |||||||
Other Income (Expense) | |||||||||||
Interest expense | — | — | (301,129 | ) | |||||||
Interest income | 12,005 | 77,812 | 119,494 | ||||||||
Interest income and late payment fee from related parties | — | 136,910 | 591,747 | ||||||||
Other income (expense) | — | (9,949 | ) | 5,460 | |||||||
12,005 | 204,773 | 415,572 | |||||||||
Net Income (Loss) | $ | 451,405 | $ | (1,552,595 | ) | $ | 2,523,851 | ||||
Net Income (Loss) Per Member Unit | $ | 451 | $ | (1,553 | ) | $ | 2,524 | ||||
The accompanying notes are an integral part of these financial statements.
F-64
AMERICAN CENTRAL WESTERN OKLAHOMA GAS COMPANY, L.L.C.
STATEMENTS OF CHANGES IN MEMBERS' EQUITY
YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
Members' Equity, December 31, 1999 | $ | 33,114,118 | |||
Contributions by members | 4,734,000 | ||||
Net income | 2,523,851 | ||||
Distributions to members | (3,095,000 | ) | |||
Members' Equity, December 31, 2000 | 37,276,969 | ||||
Contributions by members | 2,979,566 | ||||
Net loss | (1,552,595 | ) | |||
Distributions to members | (1,000,000 | ) | |||
Members' Equity, December 31, 2001 | 37,703,940 | ||||
Contributions by members | 360,000 | ||||
Net income | 451,405 | ||||
Distributions to members | (760,000 | ) | |||
Members' Equity, December 31, 2002 | $ | 37,755,345 | |||
The accompanying notes are an integral part of these financial statements.
F-65
AMERICAN CENTRAL WESTERN OKLAHOMA GAS COMPANY, L.L.C.
STATEMENTS OF CASH FLOWS
YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
| 2002 | 2001 | 2000 | ||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Operating Activities | |||||||||||||
Net income (loss) | $ | 451,405 | $ | (1,552,595 | ) | $ | 2,523,851 | ||||||
Items not requiring (providing) cash | |||||||||||||
Depreciation | 2,161,012 | 1,964,944 | 1,693,844 | ||||||||||
Loss on asset exchange | — | 554,046 | — | ||||||||||
Gain on sale of assets | — | — | (5,460 | ) | |||||||||
Changes in | |||||||||||||
Accounts receivable, net | (1,516,364 | ) | 3,458,359 | (670,241 | ) | ||||||||
Other current assets | (75,749 | ) | 94,634 | (114,698 | ) | ||||||||
Accounts payable and accrued expenses | (90,562 | ) | (1,063,052 | ) | (1,434,942 | ) | |||||||
Net cash provided by operating activities | 929,742 | 3,456,336 | 1,992,354 | ||||||||||
Investing Activities | |||||||||||||
Principal payment received on note receivable | — | — | 6,800,000 | ||||||||||
Purchase of property and equipment | (1,778,491 | ) | (5,173,708 | ) | (5,240,390 | ) | |||||||
Net cash used in investing activities | (1,778,491 | ) | (5,173,708 | ) | 1,559,610 | ||||||||
Financing Activities | |||||||||||||
Contributions by members | 360,000 | 2,979,566 | 4,734,000 | ||||||||||
Distributions to members | (760,000 | ) | (1,000,000 | ) | (3,095,000 | ) | |||||||
Net payments under revolving line of credit agreement | — | — | (4,968,000 | ) | |||||||||
Net cash provided by (used in) financing activities | (400,000 | ) | 1,979,566 | (3,329,000 | ) | ||||||||
Increase (Decrease) in Cash | (1,248,749 | ) | 262,194 | 222,964 | |||||||||
Cash, Beginning of Year | 1,465,886 | 1,203,692 | 980,728 | ||||||||||
Cash, End of Year | $ | 217,137 | $ | 1,465,886 | $ | 1,203,692 | |||||||
Supplemental Cash Flows Information | |||||||||||||
Purchases of property and equipment in accounts payable | $ | 43,348 | $ | — | $ | — |
The accompanying notes are an integral part of these financial statements.
F-66
Note 1: Nature of Operations and Summary of Significant Accounting Policies
Nature of Operations
American Central Western Oklahoma Gas Company, L.L.C. (the Company) revenues are predominantly earned from gathering and processing natural gas and related liquids for sale. The Company's operations are located in western Oklahoma. The Company extends unsecured credit to its customers, which are comprised of well-established regional oil, gas, and energy companies. The majority of customers' contracts are long term, extending for three to five years.
The Company was formed under an operating agreement effective July 1, 1997, between American Central Gas Technologies, Inc. (ACGT, formerly American Central Gas Companies, Inc.) and MCNIC Pipeline and Processing Company (MCNIC). In exchange for a contribution of primarily property and equipment, ACGT received 600 ownership units. MCNIC made a cash contribution in exchange for 400 ownership units. The term for existence of the Company is through December 31, 2038, or until earlier termination in accordance with certain provisions of the operating agreement.
The operating agreement between ACGT and MCNIC (the Members) provides for special allocations of certain income and expense amounts and the payment of cash distributions, which differ from each Member's percentage ownership of the Company.
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America 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.
Cash Equivalents
The Company considers all liquid investments with original maturities of three months or less to be cash equivalents. There were no cash equivalents at December 31, 2002 or 2001.
Accounts Receivable
Accounts receivable are stated at the amount billed to customers plus any accrued and unpaid interest. The Company provides allowance for doubtful accounts, which is based upon a review of outstanding receivables, historical collection information and existing economic conditions. Accounts receivable are ordinarily due 30 days after the issuance of the invoice. Accounts that are unpaid after the due date bear interest at 1% per month. Accounts past due more than 120 days are considered delinquent. Interest continues to accrue on delinquent accounts until the account is past due more than one year, at which time interest accrual ceases and does not resume until the account is no longer classified as delinquent. Delinquent receivables are written off based on individual credit evaluation and specific circumstances of the customer.
Property and Equipment
The Company provides for depreciation using the straight-line method over the estimated useful lives of the assets, which are as follows:
| Years | |
---|---|---|
Gas systems and plants | 20 | |
Furniture and fixtures | 5 |
F-67
The Company capitalizes interest costs as a component of construction in progress based on the rate paid for its debt borrowing. Total interest incurred was:
| 2002 | 2001 | 2000 | |||||||
---|---|---|---|---|---|---|---|---|---|---|
Interest costs capitalized | $ | — | $ | — | $ | 23,710 | ||||
Interest costs charged to expense | — | — | 301,129 | |||||||
Total interest incurred | $ | 0 | $ | 0 | $ | 324,839 | ||||
Fair Value of Financial Instruments
The carrying amount of the Company's financial instruments is a reasonable estimate of fair value.
Income Taxes
No provision for federal or state income taxes or related tax benefits has been made in the accompanying financial statements as the Members' report their respective share of the Company's taxable income or loss on their respective income tax returns. Individual items of taxable income and deductions are passed through to the individual members of the Company, and the ultimate tax liability or benefit depends on each Member's respective tax situation.
Revenue Recognition
The Company recognizes revenues based upon contractual terms and the related volumes delivered through the month and year-end.
Note 2: Related Party Transactions
The Company pays a management fee to ACGT for services rendered as the managing member of the Company. During 2002, 2001 and 2000, the Company incurred management fees from ACGT of approximately $2,119,000, $2,164,000 and $1,555,000, respectively, of which approximately $252,000 was capitalized in property and equipment for each of the three years. At December 31, 2002 and 2001, management fees payable to ACGT were $50,000 and $266,550, respectively.
Under the terms of the management agreement, amounts paid relating to management fees may be adjusted on a quarterly basis, and the Company will continue to pay the management fees for the life of the Company. Additionally, the Company reimburses ACGT for all direct operating expenses incurred by ACGT on behalf of the Company, of which $32,223 and $311,049 was payable at December 31, 2002 and 2001, respectively.
The Company had natural gas purchases from an oil and gas company with common ownership of approximately $1,005,000, $1,392,000 and $1,309,000 in 2002, 2001 and 2000, respectively, of which $114,000 and $137,230 was payable at December 31, 2002 and 2001, respectively.
During 2000, the Company received payment in full on a note receivable from stockholders of ACGT. Interest income of approximately $469,000 was received and recognized by the Company on this note in 2000. During 2001, the Company received approximately $136,000 as a late payment fee related to the note receivable from the stockholders.
Note 3: Capital Calls
Pursuant to the terms of the Company's contribution agreement effective July 1, 1997, the Company made capital calls to MCNIC during 1999 that were not paid by the due date. Since MCNIC defaulted on these payments when they were due, the Company assessed MCNIC with a 10%
F-68
liquidated damages charge plus interest in accordance with the contribution agreement. The damages and interest amounted to approximately $587,000 which MCNIC disputed. This amount was reflected as an outstanding receivable at December 31, 2001, and was paid in 2002 by MCNIC upon settlement of this dispute.
Note 4: Earnings (Loss) Per Member Unit
Earnings (loss) per member unit is computed based on the weighted average number of units outstanding during each year. Earnings (loss) per unit is computed as follows:
| 2002 | 2001 | 2000 | |||||||
---|---|---|---|---|---|---|---|---|---|---|
Net income (loss) | $ | 451,405 | $ | (1,552,595 | ) | $ | 2,523,851 | |||
Average member units outstanding | 1,000 | 1,000 | 1,000 | |||||||
Earnings (loss) per member unit | $ | 451 | $ | (1,553 | ) | $ | 2,524 | |||
Note 5: Significant Estimates and Concentrations
Accounting principles generally accepted in the United States of America require disclosure of certain significant estimates and current vulnerabilities due to certain concentrations. Those matters include the following:
Major Customers
For the year ended December 31, 2002, two customers individually comprised 69% and 11%, respectively, of the Company's gross revenues. At December 31, 2002, the receivables from two customers individually comprised approximately 54% and 29%, respectively, of the Company's total accounts receivable. At December 31, 2001, the receivables from two customers individually comprised approximately 56% and 18%, respectively, of the Company's total accounts receivable. In addition, three of the Company's customers individually comprised 18%, 10%, and 10%, respectively, of the Company's gross revenues for the year ended December 31, 2001. For the year ended December 31, 2000, three customers individually comprised 14%, 13%, and 11%, respectively, of the Company's gross revenues.
Cash Deposits
The Company maintains its cash in bank deposit accounts which, at times, may exceed federally insured limits. The Company has not experienced any losses in such accounts. The Company believes it is not exposed to any significant credit risk on cash and cash equivalents.
Note 6: Subsequent Event (Unaudited)
In addition to the Company, the Members (ACGT and MCNIC) also own similar interests in American Central Eastern Texas Gas Company, Limited Partnership (ACET), a gas gathering and processing system that operates in east Texas.
Effective April 1, 2003, ACGT entered into a letter of intent with MCNIC wherein ACGT agreed to swap its interest in the Company for MCNIC's interest in ACET. Each party will retain its proportionate share of working capital as of April 1, 2003. In addition, ACGT will pay MCNIC $22,500,000 at closing, which is expected to occur in May 2003. ACGT will continue to operate the Company for a period up to 12 months for a fee specified in the letter of intent.
The letter of intent provides that additional consideration is to be paid to MCNIC by ACGT if ACET is sold for more than a specified amount prior to December 31, 2004. Additional consideration is to be received by ACGT from MCNIC if MCNIC sells the Company for more than a specified amount prior to December 31, 2004.
F-69
AMERICAN CENTRAL WESTERN OKLAHOMA GAS COMPANY, L.L.C.
BALANCE SHEET
SEPTEMBER 30, 2003
| September 30, 2003 | ||||
---|---|---|---|---|---|
| (Unaudited) | ||||
ASSETS | |||||
Current Assets | |||||
Cash | $ | 382,347 | |||
Accounts receivable | 4,199,271 | ||||
Other current assets | 156,248 | ||||
Total current assets | 4,737,866 | ||||
Property and Equipment, At Cost | |||||
Gas systems | 35,299,355 | ||||
Gas plant | 9,290,885 | ||||
Furniture and fixtures | 23,098 | ||||
Construction in progress | 1,310,998 | ||||
45,924,336 | |||||
Less accumulated depreciation | 9,265,697 | ||||
36,658,639 | |||||
$ | 41,396,505 | ||||
LIABILITIES AND MEMBERS' EQUITY | |||||
Current Liabilities | |||||
Accounts payable and accrued expenses | $ | 4,055,622 | |||
Accounts payable to related parties | 273,551 | ||||
Total Current Liabilities | 4,329,173 | ||||
Members' Equity | 37,067,332 | ||||
$ | 41,396,505 | ||||
The accompanying notes are an integral part of these financial statements.
F-70
AMERICAN CENTRAL WESTERN OKLAHOMA GAS COMPANY, L.L.C.
STATEMENTS OF OPERATIONS
NINE MONTHS ENDED SEPTEMBER 30, 2003 AND 2002
| September 30, 2003 | September 30, 2002 | ||||||
---|---|---|---|---|---|---|---|---|
| (Unaudited) | (Unaudited) | ||||||
Revenues | ||||||||
Gas sales and gathering | $ | 29,885,225 | $ | 14,299,903 | ||||
Plant liquid sales | 355,713 | 1,933,275 | ||||||
30,240,938 | 16,233,178 | |||||||
Cost of Gas and Liquid Sales | 25,219,861 | 11,155,318 | ||||||
Gross Profit | 5,021,077 | 5,077,860 | ||||||
Operating Expenses | ||||||||
Cost of field operations | 2,009,571 | 1,857,064 | ||||||
Equipment rental | 147,603 | 172,166 | ||||||
Depreciation | 1,752,140 | 1,596,154 | ||||||
General and administrative | 108,058 | 88,970 | ||||||
Management fee to managing member, net of amount capitalized | 1,400,103 | 1,400,103 | ||||||
5,417,475 | 5,114,457 | |||||||
Loss from Operations | (396,398 | ) | (36,597 | ) | ||||
Interest Income | 8,385 | 8,732 | ||||||
Net Loss | $ | (388,013 | ) | $ | (27,865 | ) | ||
Net Loss per Member Unit | $ | (388 | ) | $ | (28 | ) | ||
The accompanying notes are an integral part of these financial statements.
F-71
AMERICAN CENTRAL WESTERN OKLAHOMA GAS COMPANY, L.L.C.
STATEMENT OF CHANGES IN MEMBERS' EQUITY
NINE MONTHS ENDED SEPTEMBER 30, 2003
Members' Equity, December 31, 2002 | $ | 37,755,345 | |||
Net loss | (388,013 | ) | |||
Distributions to members | (300,000 | ) | |||
Members' Equity, September 30, 2003 (Unaudited) | $ | 37,067,332 | |||
The accompanying notes are an integral part of these financial statements.
F-72
AMERICAN CENTRAL WESTERN OKLAHOMA GAS COMPANY, L.L.C.
STATEMENTS OF CASH FLOWS
NINE MONTHS ENDED SEPTEMBER 30, 2003 AND 2002
| September 30, 2003 | September 30, 2002 | ||||||||
---|---|---|---|---|---|---|---|---|---|---|
| (Unaudited) | (Unaudited) | ||||||||
Operating Activities | ||||||||||
Net loss | $ | (388,013 | ) | $ | (27,865 | ) | ||||
Item not requiring cash | ||||||||||
Depreciation | 1,752,140 | 1,596,154 | ||||||||
Changes in | ||||||||||
Accounts receivable, net | (36,792 | ) | (675,089 | ) | ||||||
Other current assets | 4,845 | 117,797 | ||||||||
Accounts payable and accrued expenses | 675,927 | (664,062 | ) | |||||||
Net cash provided by operating activities | 2,008,107 | 346,935 | ||||||||
Investing Activities | ||||||||||
Purchase of property and equipment | (1,542,897 | ) | (1,332,578 | ) | ||||||
Net cash used in investing activities | (1,542,897 | ) | (1,332,578 | ) | ||||||
Financing Activities | ||||||||||
Distributions to members | (300,000 | ) | — | |||||||
Net cash used in financing activities | (300,000 | ) | — | |||||||
Increase (Decrease) in Cash | 165,210 | (985,643 | ) | |||||||
Cash, Beginning of Period | 217,137 | 1,465,886 | ||||||||
Cash, End of Period | $ | 382,347 | $ | 480,243 | ||||||
Supplemental Cash Flows Information | ||||||||||
Purchases of property and equipment in accounts payable | $ | 42,081 | $ | 92,711 |
The accompanying notes are an integral part of these financial statements.
F-73
The accompanying unaudited condensed financial statements reflect all adjustments that are, in the opinion of the Company's management, necessary to fairly present the financial position, results of operations and cash flows of the Company. Those adjustments consist only of normal recurring adjustments.
The condensed balance sheet of the Company as of December 31, 2002, has been derived from the audited balance sheet of the Company as of that date.
Certain information and note disclosures normally included in the Company's annual financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted. These condensed financial statements should be read in conjunction with the financial statements and notes thereto included in the Company's annual financial statements.
Results of Operations
The results of operations for the interim period are not necessarily indicative of the results to be expected for the full year.
Earnings (Loss) Per Member Unit
Earnings (loss) per member unit is computed based on the weighted average number of units outstanding during each year. Earnings (loss) per unit is computed as follows:
| Unaudited September 30, 2002 | Unaudited September 30, 2003 | ||||||
---|---|---|---|---|---|---|---|---|
Net loss | $ | (388,013 | ) | $ | (27,865 | ) | ||
Average member units outstanding | 1,000 | 1,000 | ||||||
Loss per member unit | $ | (388 | ) | $ | (28 | ) | ||
Subsequent Event
On December 1, 2003, American Central Gas Technologies, Inc. (ACGT) purchased MCNIC Pipeline and Processing Company's (MCNIC) 400 ownership units for a cash price of $15,140,000. As a result, ACGT became the sole owner of the Company.
The purchase price of MCNIC's ownership units was funded by the proceeds received from the sale of the Company to MarkWest Western Oklahoma Gas Company, L.L.C., wholly owned subsidiary of MarkWest Energy Partners, L.P. for $37,850,000, which also occurred on December 1, 2003.
F-74
REPORT OF INDEPENDENT AUDITORS
To the Board of Directors of
Shell Pipeline Company L.P.
In our opinion, the accompanying balance sheets and the related statements of income and owner's net investment and cash flows of the Michigan Crude Oil Pipeline System (the "System") present fairly, in all material respects, the financial position of the System at December 31, 2002 and 2001, and the results of its operations and its cash flows for the period February 14, 2002 through December 31, 2002, the period January 1, 2002 through February 13, 2002, and for the years ended December 31, 2001 and 2000, in conformity with accounting principles generally accepted in the United States of America. 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 auditing standards generally accepted in the United States of America, 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 our opinion.
/s/ PricewaterhouseCoopers LLP
Houston, Texas
December 12, 2003
F-75
MICHIGAN CRUDE OIL PIPELINE SYSTEM
BALANCE SHEETS
DECEMBER 31, 2002 AND 2001
| 2002 | 2001 | ||||||
---|---|---|---|---|---|---|---|---|
Assets | ||||||||
Current assets | ||||||||
Allowance oil inventory | $ | 283,327 | $ | 803,103 | ||||
Accounts receivable trade | 232,542 | 216,342 | ||||||
Materials and supplies | 98,380 | 131,811 | ||||||
614,249 | 1,151,256 | |||||||
Property and equipment, net | 11,141,251 | 2,283,353 | ||||||
Total assets | $ | 11,755,500 | $ | 3,434,609 | ||||
Liabilities and Owner's Net Investment | ||||||||
Current liabilities | ||||||||
Property tax payable | $ | 221,295 | $ | 239,228 | ||||
Total current liabilities | 221,295 | 239,228 | ||||||
Owner's net investment | 11,534,205 | 3,195,381 | ||||||
Total liabilities and owner's net investment | $ | 11,755,500 | $ | 3,434,609 | ||||
The accompanying notes are an integral part of these financial statements.
The post-acquisition period financial statements reflect a new basis of accounting and pre-acquisition period and post-acquisition period financial statements are presented but are not comparable.
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MICHIGAN CRUDE OIL PIPELINE SYSTEM
STATEMENTS OF INCOME AND OWNER'S NET INVESTMENT
| | | Years Ended December 31, | ||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| February 14 - December 31, 2002 | January 1 - February 13, 2002 | |||||||||||||
| 2001 | 2000 | |||||||||||||
Revenue | |||||||||||||||
Transportation and allowance oil revenue | |||||||||||||||
Related parties | $ | 2,700,095 | $ | 403,123 | $ | 2,965,087 | $ | 3,806,838 | |||||||
Others | 1,677,270 | 223,972 | 2,254,889 | 2,040,970 | |||||||||||
Other revenue | 3,675 | 525 | 23,868 | 4,200 | |||||||||||
Total revenue | 4,381,040 | 627,620 | 5,243,844 | 5,852,008 | |||||||||||
Costs and expenses | |||||||||||||||
General and administrative | 842,892 | 130,175 | 980,244 | 984,129 | |||||||||||
Depreciation | 553,998 | 30,558 | 261,586 | 270,895 | |||||||||||
Salary and wages | 463,931 | 75,567 | 700,155 | 587,500 | |||||||||||
Maintenance | 326,974 | 27,642 | 219,038 | 343,118 | |||||||||||
Outside services | 274,142 | 36,406 | 344,544 | 113,713 | |||||||||||
Taxes other than taxes on income | 167,158 | 23,507 | 212,776 | 251,632 | |||||||||||
Power and fuel | 118,139 | 30,614 | 197,809 | 159,543 | |||||||||||
Loss on disposals | 6,353 | — | 78,013 | 15,257 | |||||||||||
Total costs and expenses | 2,753,587 | 354,469 | 2,994,165 | 2,725,787 | |||||||||||
Net income | 1,627,453 | 273,151 | 2,249,679 | 3,126,221 | |||||||||||
Deemed distributions to parent company | (2,764,471 | ) | (208,429 | ) | (2,390,407 | ) | (2,807,348 | ) | |||||||
Purchase price allocation | 9,411,120 | — | — | — | |||||||||||
Owner's net investment | |||||||||||||||
Beginning of year | 3,260,103 | 3,195,381 | 3,336,109 | 3,017,236 | |||||||||||
End of year | $ | 11,534,205 | $ | 3,260,103 | $ | 3,195,381 | $ | 3,336,109 | |||||||
The accompanying notes are an integral part of these financial statements.
The post-acquisition period financial statements reflect a new basis of accounting and pre-acquisition period and post-acquisition period financial statements are presented but are not comparable.
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MICHIGAN CRUDE OIL PIPELINE SYSTEM
STATEMENTS OF CASH FLOWS
| | | Years Ended December 31, | |||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| February 14 - December 31, 2002 | January 1 - February 13, 2002 | ||||||||||||||
| 2001 | 2000 | ||||||||||||||
Cash flows provided by operating activities | ||||||||||||||||
Net income | $ | 1,627,453 | $ | 273,151 | $ | 2,249,679 | $ | 3,126,221 | ||||||||
Adjustments to reconcile net income to net cash provided by operating activities | ||||||||||||||||
Depreciation | 553,998 | 30,558 | 261,586 | 270,895 | ||||||||||||
Loss on disposals | 6,353 | — | 78,013 | 15,257 | ||||||||||||
(Increase) decrease in working capital | ||||||||||||||||
Allowance oil inventory | 455,694 | 64,082 | (366,735 | ) | (370,476 | ) | ||||||||||
Property tax payable | 105,866 | (123,799 | ) | 28,754 | 45,282 | |||||||||||
Receivables | (14,202 | ) | (1,997 | ) | 194,555 | (279,831 | ) | |||||||||
Materials and supplies | 29,309 | 4,122 | 7,786 | — | ||||||||||||
Net cash provided by operating activities | 2,764,471 | 246,117 | 2,453,638 | 2,807,348 | ||||||||||||
Cash flows used for investing activities | ||||||||||||||||
Capital expenditures | — | (37,688 | ) | (63,231 | ) | — | ||||||||||
Net cash used for investing activities | — | (37,688 | ) | (63,231 | ) | — | ||||||||||
Cash flows used for financing activities | ||||||||||||||||
Deemed distributions to parent company | (2,764,471 | ) | (208,429 | ) | (2,390,407 | ) | (2,807,348 | ) | ||||||||
Net cash used for financing activities | (2,764,471 | ) | (208,429 | ) | (2,390,407 | ) | (2,807,348 | ) | ||||||||
Net increase in cash and cash equivalents | — | — | — | — | ||||||||||||
Cash and cash equivalents | ||||||||||||||||
Beginning of period | — | — | — | — | ||||||||||||
End of period | $ | — | $ | — | $ | — | $ | — | ||||||||
Nonmonetary activities | ||||||||||||||||
Purchase price allocation | $ | 9,411,120 | $ | — | $ | — | $ | — |
The accompanying notes are an integral part of these financial statements.
The post-acquisition period financial statements reflect a new basis of accounting and pre-acquisition period and post-acquisition period financial statements are presented but are not comparable.
F-78
MICHIGAN CRUDE OIL PIPELINE SYSTEM
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2002, 2001 AND 2000
1. Organization and Basis of Presentation
The accompanying financial statements present, in conformity with accounting principles generally accepted in the United States of America, the assets, liabilities, revenues and expenses of the historical operations of the transportation businesses comprised of the Michigan Crude Oil Pipeline System (the "System") owned by Shell Pipeline Company LP ("Shell Pipeline"), formerly Equilon Pipeline Company LLC. Throughout the period covered by the financial statements, Shell Pipeline owned and managed the Businesses' operations.
Effective January 1, 1998, Shell Oil Company ("Shell Oil") and Texaco, Inc. ("Texaco") formed Equilon Enterprises LLC ("Equilon Enterprises") with 56 percent and 44 percent membership interests, respectively. Shell Pipeline is a wholly owned subsidiary of Equilon Enterprises.
In connection with the 2002 merger of Chevron Corporation and Texaco, the Federal Trade Commission required Texaco to divest its interest in the Equilon Enterprises, and early 2002 Shell Oil acquired Texaco's 44 percent interest in Equilon Enterprises, making Shell Oil the 100 percent owner of Equilon Enterprises. The acquisition by Shell Oil was accounted for using the purchase method of accounting in accordance with generally accepted accounting principles, with Shell Pipeline allocating the purchase price paid by Shell Oil to Shell Pipeline's net assets as of the acquisition date. Accordingly, the post-acquisition financial statements reflect a new basis of accounting, and pre-acquisition period and post-acquisition period financial statements are presented but are not comparable.
The System extends from production facilities near Manistee, Michigan to a storage facility near Lewiston, Michigan. The Trunkline consists of approximately 150 miles of pipe ranging in diameter from 8" to 16". Crude is gathered into the System from 52 central production facilities and 5 truck unloading facilities for a total of 57 injection points comprised of approximately 100 miles of 3", 4" and 6" pipe. The System includes truck unloading stations at Manistee, Seeley Road, and Junction. The System also includes the Samaria Truck Unloading Station located in Monroe County, Michigan.
The accompanying financial statements are presented on a carve-out basis to include the historical operations of the System owned by Shell Pipeline. In this context, a direct relationship existed between the carve-out operations and the operator, Shell Pipeline. Shell Pipeline's net investment in the System (owner's net investment) is shown in lieu of stockholder's equity in the financial statements. The results of operations also include allocations generally based on total payroll costs, of Shell Pipeline's general corporate expenses primarily related to corporate and regional payroll costs.
Throughout the period covered by the financial statements, Shell Pipeline has provided cash management services to the System through centralized treasury systems. As a result, all charges and cost allocations for the System were deemed to have been paid by the System to Shell Pipeline, in cash, during the period in which the cost was recorded in the financial statements. The excess cash generated by the System during the periods is reflected as deemed distributions to the parent company in the Statement of Cash Flows.
All of the allocations and estimates in the financial statements were based on assumptions that Shell Pipeline management believes were reasonable under the circumstances. These allocations and estimates are not necessarily indicative of the costs and expenses that would have resulted if the System had been operated as a separate entity.
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2. Significant Accounting Policies
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosures of contingent assets and liabilities. Although management believes these estimates are reasonable, actual results could differ from those estimates.
Revenue Recognition
Revenues for the transportation of crude are recognized (1) based upon regulated tariff rates and the related transportation volumes and (2) when the delivery of crude is made to the shipper or another common carrier pipeline. Allowance oil revenue is recognized when the System receives the allowance oil volumes which are valued at current market value. Any allowance oil sold is recorded in revenue as a net amount based on the selling price less its weighted average cost. Other revenue consists of additional charges in accordance with the tariff agreement based on the viscosity of the crude.
Property and Equipment
Crude oil pipeline and gathering assets are carried at cost. Costs subject to depreciation are net of expected salvage values and deprecation is calculated on a straight-line basis over the estimated useful lives of the respective assets as follows:
Line pipe | 20-25 years | |
Equipment and other pipeline assets | 20-25 years | |
Oil tanks | 20-25 years | |
Other | 5-25 years |
Acquisitions and expenditures for renewals and betterments are capitalized while maintenance and repairs which do not improve or extend asset life are expensed as incurred.
Impairment of Long-Lived Assets
The System has adopted Statement of Financial Standards ("SFAS") No. 144,Accounting for the Impairment or Disposal of Long-Lived Assets, effective January 1, 2002. SFAS No. 144 retains the fundamental provisions of existing generally accepted accounting principles in the United States of America ("GAAP") with respect to the recognition and measurement of long-lived asset impairment contained in SFAS No. 121,Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of. However, SFAS No. 144 provides new guidance intended to address certain significant implementation issues associated with SFAS No. 121, including expanded guidance with respect to appropriate cash flows to be used to determine whether recognition of any long-lived asset impairment is required, and if required how to measure the amount of the impairment. SFAS No. 144 also requires that any net assets to be disposed of by sale to be reported at the lower of carrying value or fair value less cost to sell, and expands the reporting of discontinued operations to include any
F-80
component of any entity. The adoption of SFAS No. 144 did not have a material effect on the System's financial position, results of operations or liquidity.
Accounts Receivable
Accounts receivable are valued at historical cost less an allowance for doubtful accounts.
Allowance Oil
A loss allowance factor of 0.02%, by volume, is incorporated into crude oil tariffs to offset evaporation and other losses in transit. The net excess of allowance quantities, calculated in accordance with the tariffs, over actual losses is valued at the average market value at the time the excess occurred and the result is recorded as allowance oil revenue. Inventories of allowance oil are carried at the lower of such value (cost) or market value with cost being determined on an average-cost basis. Gains or losses on sales of allowance oil barrels are included in transportation and allowance oil revenue.
Materials and Supplies
Inventories of materials and supplies are carried at lower of average cost or market.
Environmental and Other Accrued Liabilities
The System accrues for environmental remediation and other accrued liabilities when it is probable that such liabilities exist, based on past events or known conditions, and the amount of such liability can be reasonably estimated. If the System can only estimate a range of probable liabilities, the minimum future undiscounted expenditure necessary to satisfy the System's future obligation is accrued.
Concentration of Credit and Other Risks
A significant portion of the System's revenues and receivables are from oil and gas companies. Although collection of these receivables could be influenced by economic factors affecting the oil and gas industry, management believes the risk of significant loss is considered remote.
Two customers represent approximately 21% and 16% of sales, respectively, for the period ended December 31, 2002, approximately 24% and 15% of revenue, respectively, for the period ended February 13, 2002, approximately 25% and 19% of sales, respectively, for the year ended December 31, 2001, and approximately 24% and 17% of sales, respectively, for the year ended December 31, 2000.
Development and production of crude in the service area of the pipeline are subject to among other factors, prices of crude and federal and state energy policy, none of which are within the System's control.
Income Taxes
The System has not historically incurred income tax expense as the System was included as part of Shell Pipeline, which, in accordance with the provisions of the Internal Revenue Code, is not subject to U.S. Federal income taxes. Rather, Shell Pipeline includes its allocated share of the System's income or loss in its own federal and state income tax returns.
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3. Property, Plant and Equipment
Property, plant and equipment consisted of the following at December 31, 2002 and 2001:
| 2002 | 2001 | ||||
---|---|---|---|---|---|---|
Facilities and equipment | $ | 10,958,053 | $ | 23,128,868 | ||
Right of way | 528,177 | 1,470,767 | ||||
Land | 56,666 | 48,758 | ||||
Construction work-in-progress | 57,041 | 63,231 | ||||
11,599,937 | 24,711,624 | |||||
Accumulated depreciation | 458,686 | 22,428,271 | ||||
Net property, plant and equipment | $ | 11,141,251 | $ | 2,283,353 | ||
On February 13, 2002, Shell Oil acquired Texaco's 44% interest in Equilon Enterprises, making Shell Oil the 100 percent owner of Equilon Enterprises. Shell Pipeline is a wholly owned subsidiary of Equilon Enterprises. The acquisition was accounted for using the purchase method of accounting in accordance with generally accepted accounting principles. Shell Oil's property, plant and equipment including the Michigan Crude Oil Pipeline System was adjusted to estimated fair market value on February 14, 2002, and depreciated based on revised estimated remaining useful lives. The System's accumulated depreciation and amortization provision balance at February 14, 2002, was eliminated pursuant to the purchase method of accounting.
The post-acquisition period financial statements reflect a new basis of accounting and pre-acquisition period and post-acquisition period financial statements are presented but are not comparable.
4. Related Party Transactions
The System has entered into transactions with Shell Oil including its affiliates. Such transactions are in the ordinary course of business and include the transportation of crude oil and petroleum products.
The aggregate amounts of such transactions for the periods ended February 13, 2002 and December 31, 2002, and for the years ended December 31, 2001 and 2000, consisted of pipeline tariff revenues totaling approximately $383,454, $2,322,026, $2,790,642 and $2,609,869, respectively.
Certain of the System's employees participate in the Alliance Pension Plan (a defined benefit plan) and the Alliance Savings Plan (a defined contribution plan). Also, certain of the System's employees participate in Shell sponsored benefit plans that provide pensions and other postretirement benefits. A portion of these plans are unfunded, and the costs are shared by Shell Oil and its employees. The System's allocated expense related to these plans was approximately $6,360, $49,856, $74,283 and $41,990 during the periods ended February 13, 2002 and December 31, 2002, and for the years ended December 31, 2001 and 2000, respectively.
The results of operations also include allocations of salary and wages. Such allocations totaled approximately $34,394, $237,347, $455,999 and $296,839 for the periods ended February 13, 2002 and December 31, 2002, and for the years ended December 31, 2001 and 2000, respectively.
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In addition, the results of operations also include allocations of Shell Pipeline's general corporate expenses, primarily related to corporate and regional charges amounting to approximately $100,524, $731,085, $1,199,282 and $926,276 during the periods ended February 13, 2002, and December 31, 2002, and for the years ended December 31, 2001 and 2000, respectively.
5. Commitments and Contingencies
The System leases certain real property, equipment and operating facilities under contracts which generally extend beyond one year but can be cancelled at any time should they not be required for operations. Future noncancellable commitments related to these items at December 31, 2002, were not significant.
The System is subject to possible loss contingencies including actions or claims based on environmental laws, federal regulations, and other matters.
The System may be obligated to take remedial action as a result of the enactment of laws or the issuance of new regulations or to correct for the effects of the System's actions on the environment. The System has not accrued for any liability at December 31, 2002, 2001 or 2000, for planned environmental remediation activities. In management's opinion, this is appropriate based on existing facts and circumstances.
6. Subsequent Event
On December 1, 2003, Shell Pipeline entered into a purchase and sale agreement with MarkWest Energy Partners L.P. MarkWest Energy Partners GP, L.L.C. serves as the general partner for MarkWest Energy Partners, L.P. The sales price is approximately $21,155,000 in cash, excluding direct acquisition and other costs. The sale excludes branding rights, trademarks and other similar property. The sale is expected to close by December 31, 2003.
F-83
MICHIGAN CRUDE OIL PIPELINE SYSTEM
BALANCE SHEETS
| September 30, 2003 | December 31, 2002 | ||||||
---|---|---|---|---|---|---|---|---|
| (unaudited) | | ||||||
Assets | ||||||||
Current assets | ||||||||
Allowance oil inventory | $ | 633,512 | $ | 283,327 | ||||
Accounts receivable, trade | 311,836 | 232,542 | ||||||
Materials and supplies | 67,989 | 98,380 | ||||||
1,013,337 | 614,249 | |||||||
Property and equipment, net | 10,613,804 | 11,141,251 | ||||||
Total assets | $ | 11,627,141 | $ | 11,755,500 | ||||
Liabilities and Owner's Net Investment | ||||||||
Current liabilities | ||||||||
Property tax payable | $ | 224,760 | $ | 221,295 | ||||
Total current liabilities | 224,760 | 221,295 | ||||||
Owner's net investment | 11,402,381 | 11,534,205 | ||||||
Total liabilities and owner's net investment | $ | 11,627,141 | $ | 11,755,500 | ||||
The accompanying notes are an integral part of these financial statements.
The post-acquisition period financial statements reflect a new basis of accounting and pre-acquisition period and post-acquisition period financial statements are presented but are not comparable.
F-84
MICHIGAN CRUDE OIL PIPELINE SYSTEM
STATEMENTS OF INCOME AND OWNER'S NET INVESTMENT
| January 1 - September 30, 2003 | February 14 - September 30, 2002 | January 1 - February 13, 2002 | |||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|
| (unaudited) | | ||||||||||
Revenue | ||||||||||||
Transportation and allowance oil revenue | ||||||||||||
Related parties | $ | 1,608,942 | $ | 1,883,227 | $ | 403,123 | ||||||
Other | 1,679,408 | 1,236,238 | 223,972 | |||||||||
Other revenue | 21,906 | 2,625 | 525 | |||||||||
Total revenue | 3,310,256 | 3,122,090 | 627,620 | |||||||||
Costs and expenses | ||||||||||||
General and administrative | 732,993 | 580,617 | 130,175 | |||||||||
Depreciation | 468,780 | 397,437 | 30,558 | |||||||||
Salary and wages | 332,687 | 344,036 | 75,567 | |||||||||
Maintenance | 355,999 | 260,746 | 27,642 | |||||||||
Outside services | 358,638 | 86,923 | 36,406 | |||||||||
Taxes other than taxes on income | 150,300 | 117,158 | 23,507 | |||||||||
Power and fuel | 121,873 | 80,765 | 30,614 | |||||||||
Loss on disposals | 82,021 | — | — | |||||||||
Total costs and expenses | 2,603,291 | 1,867,682 | 354,469 | |||||||||
Net income | 706,965 | 1,254,408 | 273,151 | |||||||||
Deemed distributions to parent company | (838,789 | ) | (1,522,411 | ) | (208,429 | ) | ||||||
Purchase price adjustment | — | 9,411,120 | — | |||||||||
Owner's net investment | ||||||||||||
Beginning of period | 11,534,205 | 3,260,103 | 3,195,381 | |||||||||
End of period | $ | 11,402,381 | $ | 12,403,220 | $ | 3,260,103 | ||||||
The accompanying notes are an integral part of these financial statements.
The post-acquisition period financial statements reflect a new basis of accounting and pre-acquisition period and post-acquisition period financial statements are presented but are not comparable.
F-85
MICHIGAN CRUDE OIL PIPELINE SYSTEM
STATEMENTS OF CASH FLOWS
| January 1 - September 30, 2003 | February 14 - September 30, 2002 | January 1 - February 13, 2002 | ||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| (unaudited) | | |||||||||||
Cash flows provided by operating activities | |||||||||||||
Net income | $ | 706,965 | $ | 1,254,408 | $ | 273,151 | |||||||
Adjustments to reconcile net income to net cash provided by operating activities | |||||||||||||
Depreciation | 468,780 | 397,437 | 30,558 | ||||||||||
Loss on disposals | 82,021 | — | — | ||||||||||
(Increase) decrease in working capital | |||||||||||||
Allowance oil inventory | (350,185 | ) | (363,933 | ) | 64,082 | ||||||||
Property tax payable | 3,465 | 79,373 | (123,799 | ) | |||||||||
Receivables | (79,295 | ) | 134,935 | (1,997 | ) | ||||||||
Materials and supplies | 30,391 | 20,191 | 4,122 | ||||||||||
Net cash provided by operating activities | 862,142 | 1,522,411 | 246,117 | ||||||||||
Cash flows used for investing activities | |||||||||||||
Capital expenditures | (23,353 | ) | — | (37,688 | ) | ||||||||
Net cash used for investing activities | (23,353 | ) | — | (37,688 | ) | ||||||||
Cash flows used for financing activities | |||||||||||||
Deemed distributions to parent company | (838,789 | ) | (1,522,411 | ) | (208,429 | ) | |||||||
Net cash used for financing activities | (838,789 | ) | (1,522,411 | ) | (208,429 | ) | |||||||
Net increase in cash and cash equivalents | — | — | — | ||||||||||
Cash and cash equivalents | |||||||||||||
At beginning of period | — | — | — | ||||||||||
At end of period | $ | — | $ | — | $ | — | |||||||
Nonmonetary activities | |||||||||||||
Purchase price allocation | $ | — | $ | 9,411,120 | $ | — |
The accompanying notes are an integral part of these financial statements.
The post-acquisition period financial statements reflect a new basis of accounting and pre-acquisition period and post-acquisition period financial statements are presented but are not comparable.
F-86
MICHIGAN CRUDE OIL PIPELINE SYSTEM
NOTES TO FINANCIAL STATEMENTS
1. Organization and Basis of Presentation
The accompanying financial statements present, in conformity with accounting principles generally accepted in the United States of America, the assets, liabilities, revenues and expenses of the historical operations of the transportation businesses comprised of the Michigan Crude Oil Pipeline System (the "System") owned by Shell Pipeline Company LP ("Shell Pipeline"), formerly Equilon Pipeline Company LLC. Throughout the period covered by the financial statements, Shell Pipeline owned and managed the System' operations.
The accompanying unaudited condensed financial statements reflect all adjustments that are, in the opinion of the Company's management, necessary to fairly present the financial position, results of operations and cash flows of the Company, those adjustments consist only of normal recurring adjustments.
Effective January 1, 1998, Shell Oil Company ("Shell Oil") and Texaco, Inc. ("Texaco") formed Equilon Enterprises LLC ("Equilon Enterprises") with 56 percent and 44 percent membership interests, respectively. Shell Pipeline is a wholly owned subsidiary of Equilon Enterprises.
In connection with the 2002 merger of Chevron Corporation and Texaco, the Federal Trade Commission required Texaco to divest its interest in the Equilon Enterprises, and early 2002 Shell Oil acquired Texaco's 44 percent interest in Equilon Enterprises, making Shell Oil the 100 percent owner of Equilon Enterprises. The acquisition by Shell Oil was accounted for using the purchase method of accounting in accordance with generally accepted accounting principles, with Shell Pipeline allocating the purchase price paid by Shell Oil to Shell Pipeline's net assets as of the acquisition date. Accordingly, the post-acquisition financial statements reflect a new basis of accounting, and pre-acquisition period and post-acquisition period financial statements are presented but are not comparable.
The System extends from production facilities near Manistee, Michigan to a storage facility near Lewiston, Michigan. The Trunkline consists of approximately 150 miles of pipe ranging in diameter from 8" to 16". Crude is gathered into the System from 52 central production facilities and 5 truck unloading facilities for a total of 57 injection points comprised of approximately 100 miles of 3", 4" and 6" pipe. The System includes truck unloading stations in Manistee, Seeley Road and Junction. The System also includes the Samaria Truck Unloading Station located in Monroe County, Michigan.
The accompanying financial statements are presented on a carve-out basis to include the historical operations of the System owned by Shell Pipeline. In this context, a direct relationship existed between the carve-out operations and the operator, Shell Pipeline. Shell Pipeline's net investment in the System (owner's net investment) is shown in lieu of stockholder's equity in the financial statements. The results of operations also include allocations generally based on total payroll costs, of Shell Pipeline's general corporate expenses primarily related to corporate and regional payroll costs.
Throughout the period covered by the financial statements, Shell Pipeline has provided cash management services to the System through centralized treasury systems. As a result, all charges and cost allocations for the System were deemed to have been paid by the System to Shell Pipeline, in cash, during the period in which the cost was recorded in the financial statements. The excess cash generated by the System during the periods is reflected as deemed distributions to the parent company in the Statement of Cash Flows.
All of the allocations and estimates in the financial statements were based on assumptions that Shell Pipeline management believes were reasonable under the circumstances. These allocations and
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estimates are not necessarily indicative of the costs and expenses that would have resulted if the System had been operated as a separate entity.
2. Significant Accounting Policies
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosures of contingent assets and liabilities. Although management believes these estimates are reasonable, actual results could differ from those estimates.
Revenue Recognition
Revenues for the transportation of crude are recognized (1) based upon regulated tariff rates and the related transportation volumes and (2) when the delivery of crude is made to the shipper or another common carrier pipeline. Allowance oil revenue is recognized when the System receives the allowance oil volumes which are valued at current market value. Any allowance oil sold is recorded in revenue as a net amount based on the selling price less its weighted average cost. Other revenue consists of additional charges in accordance with the tariff agreement based on the viscosity of the crude.
Property and Equipment
Crude oil pipeline and gathering assets are carried at cost. Costs subject to depreciation are net of expected salvage values and deprecation is calculated on a straight-line basis over the estimated useful lives of the respective assets as follows:
Line pipe | 20-25 years | |
Equipment and other pipeline assets | 20-25 years | |
Oil tanks | 20-25 years | |
Other | 5-25 years |
Acquisitions and expenditures for renewals and betterments are capitalized while maintenance and repairs which do not improve or extend asset life are expensed as incurred.
Impairment of Long-Lived Assets
The System has adopted Statement of Financial Standards ("SFAS") No. 144,Accounting for the Impairment or Disposal of Long-Lived Assets, effective January 1, 2002. SFAS No. 144 retains the fundamental provisions of existing generally accepted accounting principles in the United States of America ("GAAP") with respect to the recognition and measurement of long-lived asset impairment contained in SFAS No. 121,Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of. However, SFAS No. 144 provides new guidance intended to address certain significant implementation issues associated with SFAS No. 121, including expanded guidance with respect to appropriate cash flows to be used to determine whether recognition of any long-lived asset impairment is required, and if required how to measure the amount of the impairment. SFAS No. 144
F-88
also requires that any net assets to be disposed of by sale to be reported at the lower of carrying value or fair value less cost to sell, and expands the reporting of discontinued operations to include any component of any entity. The adoption of SFAS No. 144 did not have a material effect on the System's financial position, results of operations or liquidity.
Accounts Receivable
Accounts receivable are valued at historical cost less an allowance for doubtful accounts.
Allowance Oil
A loss allowance factor of 0.02%, by volume, is incorporated into crude oil tariffs to offset evaporation and other losses in transit. The net excess of allowance quantities, calculated in accordance with the tariffs, over actual losses is valued at the average market value at the time the excess occurred and the result is recorded as allowance oil revenue. Inventories of allowance oil are carried at the lower of such value (cost) or market value with cost being determined on an average-cost basis. Gains or losses on sales of allowance oil barrels are included in transportation and allowance oil revenue.
Materials and Supplies
Inventories of materials and supplies are carried at lower of average cost or market.
Environmental and Other Accrued Liabilities
The System accrues for environmental remediation and other accrued liabilities when it is probable that such liabilities exist, based on past events or known conditions, and the amount of such liability can be reasonably estimated. If the System can only estimate a range of probable liabilities, the minimum future undiscounted expenditure necessary to satisfy the System's future obligation is accrued.
Concentration of Credit and Other Risks
A significant portion of the System's revenues and receivables are from oil and gas companies. Although collection of these receivables could be influenced by economic factors affecting the oil and gas industry, management believes the risk of significant loss is considered remote.
Two customers represent approximately 32% and 16% of sales, respectively, for the nine months ended September 30, 2003, approximately 22% and 17% of sales, respectively, for the period ended September 30, 2002, and approximately 24% and 15% of revenue, respectively, for the period ended February 13, 2002.
Development and production of crude in the service area of the pipeline are subject to among other factors, prices of crude and federal and state energy policy, none of which are within the System's control.
Income Taxes
The System has not historically incurred income tax expense as the System was included as part of Shell Pipeline, which, in accordance with the provisions of the Internal Revenue Code, is not subject to
F-89
U.S. Federal income taxes. Rather, Shell Pipeline includes its allocated share of the partnership's income or loss in its own federal and state income tax returns.
3. Property, Plant and Equipment
Property, plant and equipment consisted of the following at September 30, 2003 and December 31, 2002:
| 2003 | 2002 | |||||
---|---|---|---|---|---|---|---|
| (unaudited) | | |||||
Facilities and equipment | $ | 10,953,794 | $ | 10,958,053 | |||
Right of way | 524,363 | 528,177 | |||||
Land | 56,666 | 56,666 | |||||
Construction work-in-progress | — | 57,041 | |||||
11,534,823 | 11,599,937 | ||||||
Accumulated depreciation | (921,019 | ) | (458,686 | ) | |||
Net property, plant and equipment | $ | 10,613,804 | $ | 11,141,251 | |||
On February 13, 2002, Shell Oil acquired Texaco's 44% interest in Equilon Enterprises, making Shell Oil the 100 percent owner of Equilon Enterprises. Shell Pipeline is a wholly owned subsidiary of Equilon Enterprises. The acquisition was accounted for using the purchase method of accounting in accordance with generally accepted accounting principles. Shell Oil's property, plant and equipment including the Michigan Crude Oil Pipeline System was adjusted to estimated fair market value on February 14, 2002, and depreciated based on revised estimated remaining useful lives. The System's accumulated depreciation and amortization provision balance at February 14, 2002, was eliminated pursuant to the purchase method of accounting.
The post-acquisition period financial statements reflect a new basis of accounting and pre-acquisition period and post-acquisition period financial statements are presented but are not comparable.
4. Related Party Transactions
The System has entered into transactions with Shell Oil including its affiliates. Such transactions are in the ordinary course of business and include the transportation of crude oil and petroleum products.
The aggregate amounts of such transactions for the periods ended February 13, 2002, and September 30, 2002, and for the nine months ended September 30, 2003, consisted of pipeline tariff revenues totaling approximately $383,454, $1,727,981 and $1,483,564, respectively.
Certain of the System's personnel participate in the Alliance Pension Plan (a defined benefit plan) and the Alliance Savings Plan (a defined contribution plan). Also, certain of the System's personnel participate in Shell sponsored benefit plans that provide pensions and other postretirement benefits. A portion of these plans are unfunded, and the costs are shared by Shell Oil and its employees. The System's allocated expense related to these plans was approximately $6,340, $36,964 and $42,190 during
F-90
the periods ended February 13, 2002, and September 30, 2002, and for the nine months ended September 30, 2003, respectively.
The results of operations also include allocations of salary and wages. Such allocations totaled approximately $34,394, $175,029 and $511,775 for the periods ended February 13, 2002, and September 30, 2002, and for the nine months ended September 30, 2003, respectively.
In addition, the results of operations also include allocations of Shell Pipeline's general corporate expenses, primarily related to corporate and regional charges amounting to approximately $100,524, $524,183 and $589,108 for the periods ended February 13, 2002 and September 30, 2002, and for the nine months ended September 30, 2003, respectively.
5. Commitments and Contingencies
The System leases certain real property, equipment and operating facilities under contracts which generally extend beyond one year but can be cancelled at any time should they not be required for operations. Future noncancellable commitments related to these items at September 30, 2003, were not significant.
The System is subject to possible loss contingencies including actions or claims based on environmental laws, federal regulations, and other matters.
The System may be obligated to take remedial action as a result of the enactment of laws or the issuance of new regulations or to correct for the effects of the System's actions on the environment. The System has not accrued for any liability at September 30, 2003, or December 31, 2002, for planned environmental remediation activities. In management's opinion, this is appropriate based on existing facts and circumstances.
6. Subsequent Event
On December 1, 2003, Shell Pipeline entered into a purchase and sale agreement with MarkWest Energy Partners L.P. MarkWest Energy Partners GP, L.L.C. serves as the general partner for MarkWest Energy Partners, L.P. The sales price is approximately $21,155,000 in cash, excluding direct acquisition and other costs. The sale excludes branding rights, trademarks and other similar property. The sale is expected to close by December 31, 2003.
F-91
REPORT OF INDEPENDENT AUDITORS
To the Board of Directors of MarkWest Energy GP, L.L.C.
In our opinion, the accompanying balance sheet presents fairly, in all material respects, the financial position of MarkWest Energy GP, L.L.C., in conformity with accounting principles generally accepted in the United States of America. This financial statement is the responsibility of the Company's management; our responsibility is to express an opinion on this financial statement based on our audit. We conducted our audit of this statement in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statement is free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statement, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
/s/ PRICEWATERHOUSECOOPERS LLP
Denver, Colorado
December 17, 2003
F-92
MARKWEST ENERGY GP, L.L.C.
BALANCE SHEETS
| December 31, 2002 | September 30, 2003 | ||||||
---|---|---|---|---|---|---|---|---|
| | (Unaudited) | ||||||
Assets | ||||||||
Cash and cash equivalents | $ | 882 | $ | 812 | ||||
Receivables from affiliate | 98 | 98 | ||||||
Total current assets | 980 | 910 | ||||||
Investment in MarkWest Energy Partners, L.P. | 358,705 | 435,569 | ||||||
Total assets | $ | 359,685 | $ | 436,479 | ||||
Members' Equity | ||||||||
Members' equity | $ | 359,685 | $ | 436,479 | ||||
Total members' equity | $ | 359,685 | $ | 436,479 | ||||
The accompanying notes are an integral part of this financial statement.
F-93
1. Organization and Nature of Operations
MarkWest Energy GP, L.L.C. (the "General Partner"), is a Delaware limited liability company formed on January 24, 2002, by MarkWest Hydrocarbon, Inc. ("MarkWest Hydrocarbon") to become the general partner of MarkWest Energy Partners, L.P. ("MarkWest Energy Partners" or "the Partnership"). MarkWest Hydrocarbon contributed $1,000 in exchange for all of the interest in the General Partner.
MarkWest Hydrocarbon and the General Partner formed MarkWest Energy Partners. MarkWest Hydrocarbon contributed $980 and the General Partner contributed $20 in exchange for a 98% limited partner interest and a 2% general partner interest, respectively.
Prior to the closing of MarkWest Energy Partners' initial public offering on May 24, 2002, MarkWest Hydrocarbon made a capital contribution to the General Partner consisting of the entire ownership interest in MarkWest Energy Appalachia, L.L.C. ("MEA"). Subsequently, the General Partner contributed this interest in MEA to MarkWest Energy Partners in exchange for 1,777,000 subordinated units, $25.8 million in cash and the reimbursement of $16.1 million in capital expenditures, among other consideration. In turn, the General Partner distributed to MarkWest Hydrocarbon the 1,777,000 subordinated units and $41.9 million in cash received from MarkWest Energy Partners.
The transfer of assets and liabilities to the Partnership from MarkWest Hydrocarbon represented a reorganization of entities under common control and was recorded at historical cost.
2. Summary of Significant Accounting Policies
Basis of Presentation
The financial statements include the accounts of the General Partner and have been prepared in accordance with accounting principles generally accepted in the United States.
Use of Estimates
The preparation of financial statements in conformity with U.S. 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.
Cash and Cash Equivalents
We consider all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. Investments are limited to overnight investments of end-of-day cash balances.
Investment in MarkWest Energy Partners
Our investment in the Partnership is accounted for utilizing the equity method. The investment represents a net balance as a result of various transactions in MarkWest Energy Partners, of which we are the General Partner. Generally, the investment is increased by our capital contributions and our share in the reported net income of MarkWest Energy Partners. Conversely, the investment is decreased by cash dividends declared and our share in the reported net loss, if any, of MarkWest Energy Partners. As General Partner, we are entitled quarterly distributions of 2% of available cash. Available cash is generally defined as all cash and cash equivalents of MarkWest Energy Partners on
F-94
hand at the end of each quarter less reserves, established by us, for future requirements plus all cash on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter.
We also hold the incentive distribution rights. Incentive distribution rights represent the right to receive an increasing percentage of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and certain target distribution levels have been achieved. We may transfer these rights separately from our general partner interest, subject to restrictions in the MarkWest Energy Partners' partnership agreement.
Income Taxes
For federal and state income tax purposes, the General Partner is treated as a partnership and is not a tax paying entity. All items of partnership income, gain, credit, loss and deduction are passed through to the members. Members shall mean collectively, and as of any date of reference, all Persons who as of such date are admitted as either a Class A or Class B Member (see Note 4) of the General Partner in accordance with the provisions of the Agreement. Agreement shall mean the Amended and Restated Limited Liability Company Agreement of MarkWest Energy GP, L.L.C., entered into as of May 24, 2002.
3. Related Party Transactions
Receivable from Affiliate
Receivable from affiliate in the balance sheet consists of fees paid directly for the affiliate.
4. Members' Capital
As of December 31, 2002, members' capital was owned 93% by MarkWest Hydrocarbon, Inc., deemed Class A Membership Interests and 7% by certain officers and directors of MarkWest Hydrocarbon who hold Class B Membership Interests. A percentage of Class A Membership Interest has an equivalent economic interest in the General Partner as a percentage of Class B Membership Interest. Membership Interests mean a percentage of the ownership interests in the Company, including but not limited to, a percentage ownership interest in Profits, Losses, and any other distributions, allocations, or rights, as defined in the Agreement.
Class A Membership Interests are only issued to and held by MarkWest Hydrocarbon. Class B Membership Interests acquired by MarkWest Hydrocarbon automatically convert into equivalent Class A Membership Interests. At its discretion, MarkWest Hydrocarbon may convert Class A Membership interests into Class B Membership Interests for the purposes of distribution or transfer of such Membership Interests to other Persons, as defined in the Agreement. Any Class B Membership Interests are only issued to or held by Persons other than MarkWest Hydrocarbon.
Except as discussed below, the holders of Class A and Class B Membership Interests each have the right and power to vote on any and all matters on which the holders of any Membership Interest are entitled to vote. Each Class A Member or Class B Member is entitled to that number of votes equal to the percentage of Membership Interest held by such Member. For so long as any Class A membership Interest are outstanding, the vote or written consent of the Class A Members, without separate consent or voting by the Class B Members as a class, is necessary for effecting or validating the following actions:
- •
- Any amendment, alteration, or repeal of any provision of the Agreement;
F-95
- •
- Any authorization, designation or issuance, whether by reclassification or otherwise, of any new Membership Interests;
- •
- Any transaction involving a Sale of the Company, as defined in the Agreement;
- •
- Any increase or decrease in the authorized number of members of the General Partner's Board of Directors;
- •
- The election of all of the members of the Board of Directors, the removal from office of such Directors and to fill any vacancy caused by the resignation, death or removal of such Directors.
Cash Distributions
The General Partner shall make distributions only to all Members simultaneously on apro rata basis in accordance with the percentage of Membership Interests held by each Member; provided, however, that any loans to Members pursuant to the Agreement therein that are then due and payable shall be repaid prior to any distributions to Members. Any distributions by the General Partner will be made only to Persons who, according to the books and records of the General Partner, were the Members who were holders of record of Membership Interests in the General Partner on the date determined by our board of directors as of which the Members are entitled to the distribution or distributions in question.
5. Investment in MarkWest Energy Partners, L.P.
At December 31, 2002, the General Partner's 2% interest in MarkWest Energy Partners is the General Partner's only unconsolidated affiliate. The 2% interest is accounted for by the equity method. The following is the condensed balance sheet data for MarkWest Energy Partners (in thousands):
| December 31, 2002 | |||||
---|---|---|---|---|---|---|
Assets | ||||||
Current assets | $ | 7,065 | ||||
Property and equipment, net | 79,824 | |||||
Other assets | 820 | |||||
Total assets | $ | 87,709 | ||||
Liabilities and capital | ||||||
Current liabilities | $ | 5,303 | ||||
Long-term debt | 21,400 | |||||
Risk management liability | 143 | |||||
Partners' Capital: | ||||||
Limited Partners' | 61,215 | |||||
General Partner's | 359 | |||||
Accumulated other comprehensive income | (711 | ) | ||||
Total partners' capital | 60,863 | |||||
Total liabilities and partners' capital | $ | 87,709 | ||||
F-96
adjusted operating surplus: For any period, operating surplus generated during that period is adjusted to:
- (a)
- decrease operating surplus by:
- (1)
- any net increase in working capital borrowings during that period; and
- (2)
- any net reduction in cash reserves for operating expenditures during that period not relating to an operating expenditure made during that period; and
- (b)
- increase operating surplus by:
- (1)
- any net decrease in working capital borrowings during that period; and
- (2)
- any net increase in cash reserves for operating expenditures during that period required by any debt instrument for the repayment of principal, interest or premium.
Adjusted operating surplus does not include that portion of operating surplus included in clause (a) (1) of the definition of operating surplus.
available cash: For any quarter ending prior to liquidation:
- (a)
- the sum of:
- (1)
- all cash and cash equivalents of MarkWest Energy Partners, L.P. and its subsidiaries on hand at the end of that quarter; and
- (2)
- all additional cash and cash equivalents of MarkWest Energy Partners, L.P. and its subsidiaries on hand on the date of determination of available cash for that quarter resulting from working capital borrowings made after the end of that quarter;
- (b)
- less the amount of cash reserves that is necessary or appropriate in the reasonable discretion of our general partner to:
- (1)
- provide for the proper conduct of the business of MarkWest Energy Partners, L.P. and its subsidiaries (including reserves for future capital expenditures and for future credit needs of MarkWest Energy Partners, L.P. and its subsidiaries) after that quarter;
- (2)
- comply with applicable law or any debt instrument or other agreement or obligation to which MarkWest Energy Partners, L.P. or any of its subsidiaries is a party or its assets are subject; and
- (3)
- provide funds for minimum quarterly distributions and cumulative common unit arrearages for any one or more of the next four quarters;
provided, however, that our general partner may not establish cash reserves for distributions to the subordinated units unless our general partner has determined that in its judgment the establishment of reserves will not prevent MarkWest Energy Partners, L.P. from distributing the minimum quarterly distribution on all common units and any cumulative common unit arrearages thereon for the next four quarters; and
provided, further, that disbursements made by MarkWest Energy Partners, L.P. or any of its subsidiaries or cash reserves established, increased or reduced after the end of that quarter but on or before the date of determination of available cash for that quarter shall be deemed to have been made,
Appendix A-1
established, increased or reduced, for purposes of determining available cash, within that quarter if our general partner so determines.
barrel: One barrel of petroleum products equals 42 U.S. gallons.
Bcf: One billion cubic feet of natural gas.
bpd: Barrels per day.
btu: British Thermal Units.
capital account: The capital account maintained for a partner under the partnership agreement. The capital account of a partner for a common unit, a subordinated unit, an incentive distribution right or any other partnership interest will be the amount which that capital account would be if that common unit, subordinated unit, incentive distribution right or other partnership interest were the only interest in MarkWest Energy Partners, L.P. held by a partner.
capital surplus: All available cash distributed by us from any source will be treated as distributed from operating surplus until the sum of all available cash distributed since the closing of the initial public offering equals the operating surplus as of the end of the quarter before that distribution. Any excess available cash will be deemed to be capital surplus.
closing price: The last sale price on a day, regular way, or in case no sale takes place on that day, the average of the closing bid and asked prices on that day, regular way. In either case, as reported in the principal consolidated transaction reporting system for securities listed or admitted to trading on the principal national securities exchange on which the units of that class are listed or admitted to trading. If the units of that class are not listed or admitted to trading on any national securities exchange, the last quoted price on that day. If no quoted price exists, the average of the high bid and low asked prices on that day in the over-the-counter market, as reported by the Nasdaq Stock Market or any other system then in use. If on any day the units of that class are not quoted by any organization of that type, the average of the closing bid and asked prices on that day as furnished by a professional market maker making a market in the units of the class selected by our general partner. If on that day no market maker is making a market in the units of that class, the fair value of the units on that day as determined reasonably and in good faith by our general partner.
common unit arrearage: The amount by which the minimum quarterly distribution for a quarter during the subordination period exceeds the distribution of available cash from operating surplus actually made for that quarter on a common unit, cumulative for that quarter and all prior quarters during the subordination period.
current market price: For any class of units listed or admitted to trading on any national securities exchange as of any date, the average of the daily closing prices for the 20 consecutive trading days immediately prior to that date.
incentive distribution right: A non-voting limited partner partnership interest issued to our general partner in connection with the formation of the Partnership. The partnership interest will confer upon its holder only the rights and obligations specifically provided in the partnership agreement for incentive distribution rights.
incentive distributions: The distributions of available cash from operating surplus initially made to our general partner that are in excess of our general partner's aggregate 2% general partner interest.
Appendix A-2
interim capital transactions: The following transactions if they occur prior to liquidation:
- (a)
- borrowings, refinancings or refundings of indebtedness and sales of debt securities (other than for working capital borrowings and other than for items purchased on open account in the ordinary course of business) by MarkWest Energy Partners, L.P. or any of its subsidiaries;
- (b)
- sales of equity interests by MarkWest Energy Partners, L.P. or any of its subsidiaries;
- (c)
- sales or other voluntary or involuntary dispositions of any assets of MarkWest Energy Partners, L.P. or any of its subsidiaries (other than sales or other dispositions of inventory, accounts receivable and other assets in the ordinary course of business, and sales or other dispositions of assets as a part of normal retirements or replacements).
Mcf: One thousand cubic feet.
Mcfe: One thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one barrel of crude oil, condensate or natural gas liquids, which approximates the relative energy content of crude oil, condensate and natural gas liquids as compared to natural gas.
Mcf/d: One thousand cubic feet per day.
Mcfe/d: One thousand cubic feet equivalent per day.
MMBtu/d: One million British Thermal Units per day.
NGLs: natural gas liquids, including propane, butane, isobutane, normal butane and natural gasoline.
operating expenditures: All expenditures of MarkWest Energy Partners, L.P. and our subsidiaries, including, but not limited to, facility operating costs, taxes, reimbursements of our general partner, repayment of working capital borrowings, debt service payments and capital expenditures, subject to the following:
- (a)
- Payments (including prepayments) of principal of and premium on indebtedness, other than working capital borrowings will not constitute operating expenditures.
- (b)
- Operating expenditures will not include:
- (1)
- capital expenditures made for acquisitions or for capital improvements;
- (2)
- payment of transaction expenses relating to interim capital transactions; or
- (3)
- distributions to partners.
operating surplus: For any period prior to liquidation, on a cumulative basis and without duplication:
- (a)
- the sum of
- (1)
- $6.3 million plus all the cash of MarkWest Energy Partners, L.P. and its subsidiaries on hand as of the closing date of our initial public offering;
- (2)
- all cash receipts of MarkWest Energy Partners, L.P. and our subsidiaries for the period beginning on the closing date of our initial public offering and ending with the last day of that period, other than cash receipts from interim capital transactions; and
- (3)
- all cash receipts of MarkWest Energy Partners, L.P. and our subsidiaries after the end of that period but on or before the date of determination of operating surplus for the period resulting from working capital borrowings; less
Appendix A-3
- (b)
- the sum of:
- (1)
- operating expenditures for the period beginning on the closing date of our initial public offering and ending with the last day of that period; and
- (2)
- the amount of cash reserves that is necessary or advisable in the reasonable discretion of our general partner to provide funds for future operating expenditures; provided however, that disbursements made (including contributions to a member of MarkWest Energy Partners, L.P. and our subsidiaries or disbursements on behalf of a member of MarkWest Energy Partners, L.P. and our subsidiaries) or cash reserves established, increased or reduced after the end of that period but on or before the date of determination of available cash for that period shall be deemed to have been made, established, increased or reduced for purposes of determining operating surplus, within that period if our general partner so determines.
subordination period: The subordination period will generally extend from the closing of the initial public offering until the first to occur of:
- (a)
- the first day of any quarter beginning after June 30, 2009, for which:
- (1)
- distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equaled or exceeded the sum of the minimum quarterly distribution on all of the outstanding common units and subordinated units for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;
- (2)
- the adjusted operating surplus generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of the minimum quarterly distribution on all of the common units and subordinated units that were outstanding during those periods on a fully-diluted basis, and the related distribution on our general partner interest in MarkWest Energy Partners, L.P.; and
- (3)
- there are no outstanding cumulative common units arrearages.
- (b)
- the date on which our general partner is removed as general partner of MarkWest Energy Partners, L.P. upon the requisite vote by the limited partners under circumstances where cause does not exist and units held by our general partner and its affiliates are not voted in favor of the removal.
provided, however, subordinated units may convert into common units as described in "Cash Distribution Policy—Subordination Period—Early Conversion of Subordinated Units."
throughput: The volume of gas transported or passing through a pipeline, plant or other facility.
working capital borrowings: Borrowings exclusively for working capital purposes made pursuant to a credit facility or other arrangement requiring all borrowings thereunder to be reduced to a relatively small amount each year for an economically meaningful period of time.
Appendix A-4
You may rely on the information contained in this prospectus. We have not authorized anyone to provide information different from that contained in this prospectus. Neither the delivery of this prospectus nor sale of common units means that information contained in this prospectus is correct after the date of this prospectus. This prospectus is not an offer to sell or solicitation of an offer to buy these common units in any circumstances under which the offer or solicitation is unlawful.
TABLE OF CONTENTS
| Page | |
---|---|---|
Prospectus Summary | 1 | |
Risk Factors | 17 | |
Use of Proceeds | 32 | |
Capitalization | 33 | |
Price Range of Common Units of Distribution | 34 | |
Cash Distribution Policy | 35 | |
Unaudited Pro Forma Financial Statements | 44 | |
Selected Historical and Pro Forma Financial and Operating Data | 53 | |
Management's Discussion and Analysis of Financial Condition and Results of Operations | 57 | |
Business | 71 | |
Management | 87 | |
Security Ownership of Certain Beneficial Owners and Management | 94 | |
Selling Unitholders | 95 | |
Certain Relationships and Related Transactions | 96 | |
Conflicts of Interest and Fiduciary Responsibilities | 102 | |
Description of the Common Units | 107 | |
The Partnership Agreement | 109 | |
Units Eligible for Future Sale | 123 | |
Material Tax Consequences | 125 | |
Investment in MarkWest Energy Partners by Employee Benefit Plans | 140 | |
Underwriting | 141 | |
Validity of the Common Units | 144 | |
Experts | 144 | |
Where You Can Find More Information | 144 | |
Forward-Looking Statements | 145 | |
Index to Financial Statements | F-1 | |
Appendix A—Glossary of Terms | A-1 |
1,148,000 Common Units
MarkWest Energy
Partners, L.P.
Representing
Limited Partner Interests
PROSPECTUS
A.G. Edwards & Sons, Inc.
RBC Capital Markets
McDonald Investments Inc.
, 2004
PART II
INFORMATION REQUIRED IN THE REGISTRATION STATEMENT
Item 13.Other Expenses of Issuance and Distribution.
Set forth below are the expenses (other than underwriting discounts and commissions) expected to be incurred in connection with the issuance and distribution of the securities registered hereby. With the exception of the Securities and Exchange Commission registration fee and the NASD filing fee, the amounts set forth below are estimates.
Registration fee | $ | 4,276 | ||
NASD filing fee | 5,786 | |||
AMEX listing fee | 22,500 | |||
Printing and engraving expenses | 250,000 | |||
Fees and expenses of legal counsel | 250,000 | |||
Accounting fees and expenses | 100,000 | |||
Transfer agent and registrar fees | 5,000 | |||
Miscellaneous | 62,438 | |||
Total | $ | 700,000 |
Item 14.Indemnification of Directors and Officers.
The section of the prospectus entitled "The Partnership Agreement—Indemnification" is incorporated herein by this reference. Reference is made to [Section 7] of the Underwriting Agreement filed as Exhibit 1.1 to the registration statement. Subject to any terms, conditions or restrictions set forth in the Partnership Agreement, Section 17-108 of the Delaware Revised Uniform Limited Partnership Act empowers a Delaware limited partnership to indemnify and hold harmless any partner or other person from and against all claims and demands whatsoever.
Item 15.Recent Sales of Unregistered Securities.
MarkWest Energy Partners, L.P. issued to MarkWest Energy GP, L.L.C. a 2% general partner interest in the Partnership in exchange for a capital contribution in the amount of $20 and a 98% limited partner interest in the Partnership in exchange for a capital contribution in the amount of $980 in connection with the formation of the Partnership in January 2002 in an offering exempt from registration under Section 4(2) of the Securities Act of 1933, as amended.
In June, 2003, MarkWest Energy Partners, L.P. sold 375,000 common units to certain accredited investors in a private placement. Gross proceeds of the sale were $9,836,250. The proceeds were used to reduce outstanding indebtedness. In connection with the sale, MarkWest Energy Partners, L.P. granted demand and piggyback registration rights to the purchasers, pursuant to a Registration Rights Agreement. The issuance of these securities were made in reliance upon the exemption from registration requirements provided by Section 4(2) of the Securities Act of 1933, as amended, for transactions by an issuer not involving a public offering.
The following documents are filed as exhibits to this registration statement:
Exhibit Number | | Description | ||
---|---|---|---|---|
1.1* | — | Underwriting Agreement | ||
II-1
2.1(a) | — | Purchase Agreement dated as of March 24, 2003, among PNG Corporation, Energy Spectrum Partners LP, MarkWest GP, L.L.C., MW Texas Limited, L.L.C. and MarkWest Energy Partners, L.P. | ||
2.2(a) | — | Plan of Merger entered into as of March 28, 2003, by and among MarkWest Blackhawk L.P., MarkWest Pinnacle L.P., MarkWest PNG Utility L.P., MarkWest Texas PNG Utility L.P., Pinnacle Natural Gas Company, Pinnacle Pipeline Company, PNG Transmission Company and Bright Star Gathering, Inc. | ||
2.3(b) | — | Asset Purchase and Sale Agreement dated as of November 18, 2003 by and between American Central Western Oklahoma Gas Company, L.L.C., MarkWest Western Oklahoma Gas Company, L.L.C. and American Central Gas Technologies, Inc. | ||
3.1(c) | — | Certificate of Limited Partnership of MarkWest Energy Partners, L.P. | ||
3.2(d) | — | Amended and Restated Agreement of Limited Partnership of MarkWest Energy Partners, L.P. dated May 24, 2002. | ||
3.3(c) | — | Certificate of Formation of MarkWest Energy Operating Company, L.L.C. | ||
3.4(d) | — | Amended and Restated Limited Liability Company Agreement of MarkWest Energy Operating Company, L.L.C. dated May 24, 2002. | ||
3.5(c) | — | Certificate of Formation of MarkWest Energy GP, L.L.C. | ||
3.6(d) | — | Amended and Restated Limited Liability Company Agreement of MarkWest Energy GP, L.L.C. dated May 24, 2002. | ||
4.1(e) | — | Purchase Agreement dated as of June 13, 2003 by and among MarkWest Energy Partners, L.P. and Tortoise Capital Advisors, LLC as attorney-in-fact for the Purchasers. | ||
4.2(e) | — | Registration Rights Agreement dated as of June 13, 2003 by and among MarkWest Energy Partners, L.P. and Tortoise Capital Advisors, LLC as attorney-in-fact for the Purchasers. | ||
5.1* | — | Opinion of Vinson & Elkins L.L.P. as to the legality of the securities being registered. | ||
8.1* | — | Opinion of Vinson & Elkins L.L.P. relating to tax matters. | ||
10.1(b) | — | Amended and Restated Credit Agreement dated as of December 1, 2003 among MarkWest Energy Operating Company, L.L.C., as Borrower, MarkWest Energy Partners, L.P., as Guarantor, Royal Bank of Canada, as Administrative Agent, Bank One, NA, as Syndication Agent, and Fortis Capital Corp., as Documentation Agent, to the $140,000,000 Senior Credit Facility. | ||
10.2(d) | — | Contribution, Conveyance and Assumption Agreement dated as of May 24, 2002 among MarkWest Energy Partners, L.P.; MarkWest Energy Operating Company, L.L.C.; MarkWest Energy GP, L.L.C.; MarkWest Michigan, Inc.; MarkWest Energy Appalachia, L.L.C.; West Shore Processing Company, L.L.C.; Basin Pipeline, L.L.C.; and MarkWest Hydrocarbon, Inc. | ||
10.3(d) | — | MarkWest Energy GP, L.L.C. Long-Term Incentive Plan | ||
10.4(d) | — | First Amendment to MarkWest Energy Partners, L.P. Long-Term Incentive Plan. | ||
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10.5(d) | — | Omnibus Agreement dated May 24, 2002 among MarkWest Hydrocarbon, Inc.; MarkWest Energy GP, L.L.C.; MarkWest Energy Partners, L.P. and MarkWest Energy Operating Company, L.L.C. | ||
10.6(d)† | — | Fractionation, Storage and Loading Agreement dated May 24, 2002 between MarkWest Energy Appalachia and MarkWest Hydrocarbon, Inc. | ||
10.7(d)† | — | Gas Processing Agreement dated May 24, 2002 between MarkWest Energy Appalachia and MarkWest Hydrocarbon, Inc. | ||
10.8(d)† | — | Pipeline Liquids Transportation Agreement dated May 24, 2002 between MarkWest Energy Appalachia and MarkWest Hydrocarbon, Inc. | ||
10.9(d) | — | Natural Gas Liquids Purchase Agreement dated May 24, 2002 between MarkWest Energy Appalachia and MarkWest Hydrocarbon, Inc. | ||
10.10(f)† | — | Gas Processing Agreement (Maytown) dated as of May 28, 2002, between Equitable Production Company and MarkWest Hydrocarbon, Inc. | ||
10.11(f)† | — | Amendment to Gas Processing Agreement (Maytown) dated as of March 26, 2002, between Equitable Production Company and MarkWest Hydrocarbon, Inc. | ||
21.1* | — | List of subsidiaries | ||
23.1 | — | Consent of PricewaterhouseCoopers LLP | ||
23.2 | — | Consent of PricewaterhouseCoopers LLP | ||
23.3 | — | Consent of BKD LLP | ||
23.4* | — | Consent of Vinson & Elkins L.L.P. (contained in Exhibit 5.1) | ||
23.5* | — | Consent of Vinson & Elkins L.L.P. (contained in Exhibit 8.1) | ||
24.1 | — | Powers of Attorney (included on the signature page to this Registration Statement) |
- *
- Previously filed.
- (a)
- Incorporated by reference to the Current Report on Form 8-K filed April 14, 2003.
- (b)
- Incorporated by reference to the Current Report on Form 8-K filed December 16, 2003.
- (c)
- Incorporated by reference to the Registration Statement on Form S-1 (No. 33-81780), filed January 31, 2002.
- (d)
- Incorporated by reference to the Current Report on Form 8-K filed June 7, 2002.
- (e)
- Incorporated by reference to the Current Report on Form 8-K filed June 19, 2003.
- (f)
- Incorporated by reference to Amendment No. 6 to the Registration Statement on Form S-1 (No. 33-81780), filed May 14, 2002.
- †
- The Securities and Exchange Commission has granted confidential treatment of certain provisions of these exhibits.
Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the Registrant pursuant to the foregoing provisions, or otherwise, the Registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the Registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being
II-3
registered, the Registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.
The undersigned Registrant hereby undertakes that:
(1) For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this Registration Statement in reliance upon Rule 430A and contained in a form of prospectus filed by the Registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this Registration Statement as of the time it was declared effective.
(2) For the purposes of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initialbona fide offering thereof.
The undersigned Registrant undertakes to send to each limited partner at least on an annual basis a detailed statement of any transactions with the general partner or its affiliates, and of fees, commissions and other benefits paid, or accrued to the general partner or its affiliates for the fiscal year completed, showing the amount paid or accrued to each recipient and the services performed.
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Pursuant to the requirements of the Securities Act of 1933, as amended, the Registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Englewood, state of Colorado, on January 9, 2004.
MARKWEST ENERGY PARTNERS, L.P. | |||
By: | MarkWest Energy GP, L.L.C., its General Partner | ||
By: | /s/ DONALD C. HEPPERMANN | ||
Name: | Donald C. Heppermann | ||
Title: | Executive Vice President, Chief Financial Officer, Secretary and Director |
Pursuant to the requirements of the Securities Act of 1933, as amended, this Registration Statement has been signed below by the following persons in the capacities and on the dates indicated.
Signature | Title | Date | ||
---|---|---|---|---|
/s/ FRANK M. SEMPLE Frank M. Semple | President and Chief Executive Officer (Principal Executive Officer) | January 9, 2004 | ||
/s/ DONALD C. HEPPERMANN Donald C. Heppermann | Executive Vice President, Chief Financial Officer, Secretary and Director (Principal Financial and Accounting Officer) | January 9, 2004 | ||
* Arthur J. Denney | Executive Vice President, Chief Operating Officer, Assistant Secretary and Director | January 9, 2004 | ||
* John M. Fox | Chairman of the Board of Directors | January 9, 2004 | ||
* Charles K. Dempster | Director | January 9, 2004 | ||
* William A. Kellstrom | Director | January 9, 2004 | ||
William P. Nicoletti | Director | |||
*/s/ DONALD C. HEPPERMANN Donald C. Heppermann Attorney-In-Fact |
II-5
Exhibit Number | | Description | ||
---|---|---|---|---|
1.1* | — | Underwriting Agreement | ||
2.1(a) | — | �� | Purchase Agreement dated as of March 24, 2003, among PNG Corporation, Energy Spectrum Partners LP, MarkWest GP, L.L.C., MW Texas Limited, L.L.C. and MarkWest Energy Partners, L.P. | |
2.2(a) | — | Plan of Merger entered into as of March 28, 2003, by and among MarkWest Blackhawk L.P., MarkWest Pinnacle L.P., MarkWest PNG Utility L.P., MarkWest Texas PNG Utility L.P., Pinnacle Natural Gas Company, Pinnacle Pipeline Company, PNG Transmission Company and Bright Star Gathering, Inc. | ||
2.3(b) | — | Asset Purchase and Sale Agreement dated as of November 18, 2003 by and between American Central Western Oklahoma Gas Company, L.L.C., MarkWest Western Oklahoma Gas Company, L.L.C. and American Central Gas Technologies, Inc. | ||
3.1(c) | — | Certificate of Limited Partnership of MarkWest Energy Partners, L.P. | ||
3.2(d) | — | Amended and Restated Agreement of Limited Partnership of MarkWest Energy Partners, L.P. dated May 24, 2002. | ||
3.3(c) | — | Certificate of Formation of MarkWest Energy Operating Company, L.L.C. | ||
3.4(d) | — | Amended and Restated Limited Liability Company Agreement of MarkWest Energy Operating Company, L.L.C. dated May 24, 2002. | ||
3.5(c) | — | Certificate of Formation of MarkWest Energy GP, L.L.C. | ||
3.6(d) | — | Amended and Restated Limited Liability Company Agreement of MarkWest Energy GP, L.L.C. dated May 24, 2002. | ||
4.1(e) | — | Purchase Agreement dated as of June 13, 2003 by and among MarkWest Energy Partners, L.P. and Tortoise Capital Advisors, LLC as attorney-in-fact for the Purchasers. | ||
4.2(e) | — | Registration Rights Agreement dated as of June 13, 2003 by and among MarkWest Energy Partners, L.P. and Tortoise Capital Advisors, LLC as attorney-in-fact for the Purchasers. | ||
5.1* | — | Opinion of Vinson & Elkins L.L.P. as to the legality of the securities being registered. | ||
8.1* | — | Opinion of Vinson & Elkins L.L.P. relating to tax matters. | ||
10.1(b) | — | Amended and Restated Credit Agreement dated as of December 1, 2003 among MarkWest Energy Operating Company, L.L.C., as Borrower, MarkWest Energy Partners, L.P., as Guarantor, Royal Bank of Canada, as Administrative Agent, Bank One, NA, as Syndication Agent, and Fortis Capital Corp., as Documentation Agent, to the $140,000,000 Senior Credit Facility. | ||
10.2(d) | — | Contribution, Conveyance and Assumption Agreement dated as of May 24, 2002 among MarkWest Energy Partners, L.P.; MarkWest Energy Operating Company, L.L.C.; MarkWest Energy GP, L.L.C.; MarkWest Michigan, Inc.; MarkWest Energy Appalachia, L.L.C.; West Shore Processing Company, L.L.C.; Basin Pipeline, L.L.C.; and MarkWest Hydrocarbon, Inc. | ||
10.3(d) | — | MarkWest Energy GP, L.L.C. Long-Term Incentive Plan | ||
10.4(d) | — | First Amendment to MarkWest Energy Partners, L.P. Long-Term Incentive Plan. | ||
10.5(d) | — | Omnibus Agreement dated May 24, 2002 among MarkWest Hydrocarbon, Inc.; MarkWest Energy GP, L.L.C.; MarkWest Energy Partners, L.P. and MarkWest Energy Operating Company, L.L.C. | ||
10.6(d)† | — | Fractionation, Storage and Loading Agreement dated May 24, 2002 between MarkWest Energy Appalachia and MarkWest Hydrocarbon, Inc. | ||
10.7(d)† | — | Gas Processing Agreement dated May 24, 2002 between MarkWest Energy Appalachia and MarkWest Hydrocarbon, Inc. | ||
10.8(d)† | — | Pipeline Liquids Transportation Agreement dated May 24, 2002 between MarkWest Energy Appalachia and MarkWest Hydrocarbon, Inc. | ||
10.9(d) | — | Natural Gas Liquids Purchase Agreement dated May 24, 2002 between MarkWest Energy Appalachia and MarkWest Hydrocarbon, Inc. | ||
10.10(f)† | — | Gas Processing Agreement (Maytown) dated as of May 28, 2002, between Equitable Production Company and MarkWest Hydrocarbon, Inc. | ||
10.11(f)† | — | Amendment to Gas Processing Agreement (Maytown) dated as of March 26, 2002, between Equitable Production Company and MarkWest Hydrocarbon, Inc. | ||
21.1* | — | List of subsidiaries | ||
23.1 | — | Consent of PricewaterhouseCoopers LLP | ||
23.2 | — | Consent of PricewaterhouseCoopers LLP | ||
23.3 | — | Consent of BKD LLP | ||
23.4* | — | Consent of Vinson & Elkins L.L.P. (contained in Exhibit 5.1) | ||
23.5* | — | Consent of Vinson & Elkins L.L.P. (contained in Exhibit 8.1) | ||
24.1 | — | Powers of Attorney (included on the signature page to this Registration Statement) |
- *
- Previously filed.
- (a)
- Incorporated by reference to the Current Report on Form 8-K filed April 14, 2003.
- (b)
- Incorporated by reference to the Current Report on Form 8-K filed December 16, 2003.
- (c)
- Incorporated by reference to the Registration Statement on Form S-1 (No. 33-81780), filed January 31, 2002.
- (d)
- Incorporated by reference to the Current Report on Form 8-K filed June 7, 2002.
- (e)
- Incorporated by reference to the Current Report on Form 8-K filed June 19, 2003.
- (f)
- Incorporated by reference to Amendment No. 6 to the Registration Statement on Form S-1 (No. 33-81780), filed May 14, 2002.
- †
- The Securities and Exchange Commission has granted confidential treatment of certain provisions of these exhibits.