EX-99.1 2 a13-11982_1ex99d1.htm EX-99.1

Exhibit 99.1

MarkWest Energy Partners, L.P.	Contact:	Frank Semple, Chairman, President & CEO
1515 Arapahoe Street		Nancy Buese, Senior VP and CFO
Tower 1, Suite 1600		Josh Hallenbeck, VP of Finance & Treasurer
Denver, Colorado 80202	Phone:	(866) 858-0482
	E-mail:	investorrelations@markwest.com

MarkWest Energy Partners Reports First Quarter Financial Results, Record Volumes and Increases Common Unit Distribution

· Acquired Granite Wash midstream assets from Chesapeake Energy in Texas Panhandle and Western Oklahoma for $245 million and entered into long-term fee-based gathering and processing agreements.

· Placed into service four additional processing facilities with combined capacity of 645 MMcf/d. The Partnership has 18 major processing and fractionation projects currently under construction, which are expected to be completed by the end of 2014.

· Executed an agreement with Antero Resources to expand the Sherwood processing complex by 200 MMcf/d, bringing total capacity in the Marcellus Shale to 3.2 Bcf/d by the end of 2014.

· Executed agreements with four producers in the Utica Shale, bringing total producers under contract to six.

· Executed long-term fee-based agreement with Newfield Exploration to acquire and develop rich- gas gathering facilities in the Eagle Ford Shale.

· Fee-based net operating margin increased from 39 percent to 58 percent when compared to the first quarter of last year.

DENVER—May 8, 2013—MarkWest Energy Partners, L.P. (NYSE: MWE) (the Partnership) today reported quarterly cash available for distribution to common unitholders, or distributable cash flow (DCF), of $110.2 million for the three months ended March 31, 2013, compared to $109.2 million for the three months ended March 31, 2012. DCF for the three months ended March 31, 2013 represents 102 percent coverage of the first quarter distribution of $108.4 million or $0.83 per common unit, which will be paid to unitholders on May 15, 2013. The first quarter 2013 distribution represents an increase of $0.01 per common unit or 1.2 percent over the fourth quarter 2012 distribution and an increase of $0.04 per common unit or 5.1 percent compared to the first quarter 2012 distribution. As a Master Limited Partnership, cash distributions to common unitholders are largely determined based on DCF. A reconciliation of DCF to net income, the most directly comparable GAAP financial measure, is provided within the financial tables of this press release.

The Partnership reported Adjusted EBITDA of $140.8 million for the three months ended March 31, 2013, compared to $153.1 million for the same period in 2012. The Partnership believes the presentation of Adjusted EBITDA provides useful information because it is commonly used by investors in Master Limited Partnerships to assess financial performance and operating results of ongoing business operations. A reconciliation of Adjusted EBITDA to net income, the most directly comparable GAAP financial measure, is provided within the financial tables of this press release.

The Partnership reported (loss) income before provision for income tax for the three months ended March 31, 2013 of ($14.2) million, compared to $20.8 million for the same period in 2012. Income (loss) before provision for income tax includes non-cash gains (losses) associated with the change in fair value of derivative instruments of $9.0 million and ($48.2) million for the three months ended March 31, 2013 and March 31, 2012, respectively, and a (loss) associated with the redemption of debt of ($38.5) million for the three months ended March 31, 2013. Excluding these items, income before provision for income tax for the three months ended March 31, 2013 and 2012 would have been $15.3 million and $69.0 million, respectively.

“Our diverse set of midstream assets continues to deliver strong financial results and create opportunities for future growth,” said Frank Semple, Chairman, President and Chief Executive Officer. “The recent completion of nine major projects since last October and the planned completion of 18 additional major projects over the next year and a half will continue to grow our fee-based income and distributable cash flow for years to come. In addition, we are very pleased with the acquisition of the Chesapeake assets in the Granite Wash and our entrance into the liquids-rich Eagle Ford Shale through our strategic agreement with Newfield Exploration.”

BUSINESS HIGHLIGHTS

Liberty:

In February 2013, the Partnership commenced operations of an additional 120 million cubic feet per day (MMcf/d) processing facility at the Mobley complex in Wetzel County, West Virginia. This facility is supported by long-term, fee-based agreements with EQT Corporation (NYSE: EQT), Magnum Hunter Resources Corporation (NYSE: MHR) and other producers. With the completion of the second facility, total processing capacity at Mobley is 320 MMcf/d and in less than six months the utilization of the complex has increased to approximately 70 percent.

· In May 2013, the Partnership commenced operations of Majorsville III, a 200 MMcf/d processing facility in Marshall County, West Virginia. Majorsville III is supported by long-term, fee-based agreements with Consol Energy, Inc. (NYSE: CNX) (CNX) and Noble Energy, Inc. (NYSE: NBL). The facility will also provide additional processing capacity to Range Resources Corporation (NYSE: RRC) (Range), Chesapeake Energy Corporation (NYSE: CHK) (Chesapeake) and other producers prior to the completion of subsequent facilities. The Partnership’s first two processing facilities are operating at approximately 90 percent utilization and with the addition of the third facility, total processing capacity of the Majorsville complex has increased to 470 MMcf/d.

· In May 2013, the Partnership commenced operations of Sherwood II, a 200 MMcf/d processing facility in Doddridge County, West Virginia. Sherwood II is supported by long-term, fee-based agreements with Antero Resources (Antero). The Partnership’s first 200 MMcf/d facility is operating near full capacity in just over six months and the completion of the second facility brings total processing capacity at the Sherwood complex to 400 MMcf/d.

Utica:

· In February 2013, the Partnership, together with EMG, completed an Amended and Restated Limited Liability Company Agreement (Amended LLC Agreement) for MarkWest Utica EMG. The Amended LLC Agreement increases EMG’s capital commitment to MarkWest Utica EMG from $500 million to $950 million. The transaction provides the Partnership with flexibility in the timing of future capital contributions to MarkWest Utica EMG and accelerates the

continued development of critical midstream infrastructure in the highly prospective Utica Shale.

· In February 2013, MarkWest Utica EMG announced the execution of definitive agreements with Rex Energy Corporation (NYSE: REXX) (Rex) to provide gathering, processing, fractionation, and marketing services in the Utica Shale. MarkWest Utica EMG expects to begin providing the full-suite of midstream services for Rex by the end of the second quarter of 2013.

· In March 2013, MarkWest Utica EMG announced the execution of definitive agreements with PDC Energy, Inc. (NASDAQ: PDCE) (PDC) to provide gathering, processing, fractionation, and marketing services in the Utica Shale. MarkWest Utica EMG expects to begin providing the full-suite of midstream services for PDC by the end of the second quarter of 2013.

· In May 2013, MarkWest Utica EMG announced the execution of definitive agreements with CNX and an additional producer to provide processing, fractionation, and marketing services in the Utica Shale.

· In May 2013, MarkWest Utica EMG is commencing operations of Cadiz I, a 125 MMcf/d cryogenic processing facility in Harrison County, Ohio. Cadiz I is supported by fee-based agreements with Gulfport Energy Corporation (NASDAQ: GPOR), Antero and other producers.

Southwest:

· Today, the Partnership announced the execution of definitive agreements to acquire 100% of the ownership interests of midstream assets in the Texas Panhandle and Western Oklahoma from a wholly owned subsidiary of Chesapeake for consideration of $245 million in cash. In conjunction with the acquisition, the Partnership has executed long-term, fee-based agreements with Chesapeake for gas gathering and processing services. As part of the gas processing agreement, Chesapeake has dedicated to the Partnership approximately 130,000 acres throughout the Anadarko Basin. The transaction is immediately accretive and the Partnership expects it to contribute $30 million to EBITDA for the full-year 2014.

· In May 2013, the Partnership announced the execution of long-term fee-based agreement with Newfield Exploration (NYSE: NFX) (Newfield) to acquire and develop rich-gas gathering facilities in the Eagle Ford Shale. The Partnership will construct additional gathering pipelines, field compression, and liquids storage to support production from Newfield’s West Asherton project in Dimmit County, Texas. The Partnership plans capital investment of approximately $50 million to support Newfield’s development plans.

Capital Markets

· In January 2013, the Partnership completed a public offering of $1.0 billion of 4.50% senior unsecured notes priced at par due in 2023. A portion of the net proceeds of approximately $986.0 million, together with cash on hand resulting in part from recent equity offerings, was used to fund the redemption of all of its outstanding 8.75% senior notes due 2018, and a portion of its 6.50% senior notes due 2021 and 6.25% senior notes due 2022, with the balance of such proceeds to be used to fund the Partnership’s capital expenditure program and for general partnership purposes.

· During the first quarter of 2013, the Partnership offered 1.9 million units and received net proceeds of approximately $103.9 million under the continuous offering program that was launched in the fourth quarter of 2012.

FINANCIAL RESULTS

Balance Sheet

· As of March 31, 2013, the Partnership had $502.3 million of cash and cash equivalents in wholly owned subsidiaries and $1.19 billion remaining capacity under its $1.2 billion revolving credit facility after consideration of $11.3 million of outstanding letters of credit.

Operating Results

· Operating income before items not allocated to segments for the three months ended March 31, 2013, was $163.1 million, a decrease of $31.1 million when compared to segment operating income of $194.2 million over the same period in 2012. This decrease was primarily attributable to lower commodity prices compared to the prior year quarter. Processed volumes continued to remain strong, growing approximately 40 percent when compared to the first quarter of 2012, primarily due to the Partnership’s Liberty Segment and East Texas operations.

A reconciliation of operating income before items not allocated to segments to income (loss) before provision for income tax, the most directly comparable GAAP financial measure, is provided within the financial tables of this press release.

· Operating income before items not allocated to segments does not include gains (losses) on commodity derivative instruments. Realized gains (losses) on commodity derivative instruments were $1.8 million in the first quarter of 2013 and ($17.6) million in the first quarter of 2012.

Capital Expenditures

· For the three months ended March 31, 2013, the Partnership’s portion of capital expenditures was $366.2 million.

2013 DCF AND GROWTH CAPITAL EXPENDITURE FORECAST

For 2013, the Partnership’s forecast for DCF has been narrowed to a range of $500 million to $540 million based on its current forecast of operational volumes and revised prices for crude oil, natural gas and natural gas liquids; and derivative instruments currently outstanding. A commodity price sensitivity analysis for forecasted 2013 DCF is provided within the tables of this press release.

The Partnership’s portion of growth capital expenditures for 2013 is unchanged and remains in a range of $1.5 billion to $1.8 billion. These expenditures do not include the Granite Wash acquisition cost of $245 million.

CONFERENCE CALL

The Partnership will host a conference call and webcast on Thursday, May 9, 2013, at 12:00 p.m. Eastern Time to review its first quarter 2013 financial results. Interested parties can participate in the call by dialing (800) 475-0218 (passcode “MarkWest”) approximately ten minutes prior to the scheduled start time. To access the webcast, please visit the Investor Relations section of the Partnership’s website at www.markwest.com. A replay of the conference call will be available on the MarkWest website or by dialing (888) 402-8736 (no passcode required).

###

MarkWest Energy Partners, L.P. is a master limited partnership engaged in the gathering, processing and transportation of natural gas; the gathering, transportation, fractionation, storage and marketing of natural gas liquids; and the gathering and transportation of crude oil. MarkWest has a leading presence in many unconventional gas plays including the Marcellus Shale, Utica Shale, Huron/Berea Shale, Haynesville Shale, Woodford Shale and Granite Wash formation.

This press release includes “forward-looking statements.” All statements other than statements of historical facts included or incorporated herein may constitute forward-looking statements. Actual results could vary significantly from those expressed or implied in such statements and are subject to a number of risks and uncertainties. Although MarkWest believes that the expectations reflected in the forward-looking statements are reasonable, MarkWest can give no assurance that such expectations will prove to be correct. The forward-looking statements involve risks and uncertainties that affect operations, financial performance, and other factors as discussed in filings with the Securities and Exchange Commission (SEC). Among the factors that could cause results to differ materially are those risks discussed in the periodic reports filed with the SEC, including MarkWest’s Annual Report on Form 10-K for the year ended December 31, 2012 and our Quarterly Report on Form 10-Q for the quarter ended March 31, 2013. You are urged to carefully review and consider the cautionary statements and other disclosures made in those filings, specifically those under the heading “Risk Factors.” MarkWest does not undertake any duty to update any forward-looking statement except as required by law.

MarkWest Energy Partners, L.P.

Financial Statistics

(in thousands, except per unit data)

	Three months ended March 31,
	2013			2012
Statement of Operations Data
Revenue:
Revenue	$	376,137		$	399,181
Derivative loss	(185		)	(48,715		)
Total revenue	375,952			350,466

Operating expenses:
Purchased product costs	152,557			154,555
Derivative (gain) loss related to purchased product costs	(10,704		)	18,800
Facility expenses	59,755			48,840
Derivative gain related to facility expenses	(332		)	(1,746		)
Selling, general and administrative expenses	25,408			25,224
Depreciation	69,597			41,145
Amortization of intangible assets	14,830			10,985
Loss on disposal of property, plant and equipment	138			986
Accretion of asset retirement obligations	353			238
Total operating expenses	311,602			299,027

Income from operations	64,350			51,439

Other (expense) income:
Loss from unconsolidated affiliate	(85		)	(9		)
Interest income	149			72
Interest expense	(38,336		)	(29,472		)
Amortization of deferred financing costs and discount (a component of interest expense)	(1,830		)	(1,270		)
Loss on redemption of debt	(38,455		)	—
Miscellaneous income, net	—			58
(Loss) income before provision for income tax	(14,207		)	20,818

Provision for income tax (benefit) expense:
Current	(5,414		)	15,341
Deferred	11,971			(10,796		)
Total provision for income tax	6,557			4,545

Net (loss) income	(20,764		)	16,273

Net loss (income) attributable to non-controlling interest	5,304			(253		)

Net (loss) income attributable to the Partnership’s unitholders	$	(15,460	)	$	16,020

Net (loss) income attributable to the Partnership’s common unitholders per common unit:	.
Basic	$	(0.12	)	$	0.16
Diluted	$	(0.12	)	$	0.14

Weighted average number of outstanding common units:
Basic	128,615			96,840
Diluted	128,615			117,593

Cash Flow Data
Net cash flow provided by (used in):
Operating activities	$	85,043		$	207,913
Investing activities	$	(609,361	)	$	(252,969	)
Financing activities	$	830,589		$	278,674

Other Financial Data
Distributable cash flow	$	110,194		$	109,177
Adjusted EBITDA	$	140,810		$	153,140

	March 31, 2013		December 31, 2012
Balance Sheet Data
Working capital	$	173,419	$	(82,587	)
Total assets	7,720,554		6,835,716
Total debt	3,022,521		2,523,051
Total equity	3,240,300		3,215,591

MarkWest Energy Partners, L.P.

Operating Statistics

	Three months ended March 31,
	2013	2012
Liberty
Gathering system throughput (Mcf/d)	605,400	308,100
Natural gas processed (Mcf/d)	828,100	392,100
NGLs fractionated (Bbl/d)	37,000	20,000
NGL sales (gallons, in thousands) (1)	145,900	97,500

Utica (2)
Gathering system throughput (Mcf/d)	9,000	N/A
Natural gas processed (Mcf/d)	7,900	N/A

Northeast
Natural gas processed (Mcf/d)	302,600	321,700
NGLs fractionated (Bbl/d)	17,100	16,700

Keep-whole sales (gallons, in thousands)	37,400	49,500
Percent-of-proceeds sales (gallons, in thousands)	34,900	33,000
Total NGL sales (gallons, in thousands)	72,300	82,500

Crude oil transported for a fee (Bbl/d)	10,300	10,400

Southwest
East Texas gathering systems throughput (Mcf/d)	500,300	410,000
East Texas natural gas processed (Mcf/d)	339,500	242,500
East Texas NGL sales (gallons, in thousands)	80,600	63,400

Western Oklahoma gathering system throughput (Mcf/d) (3)	202,600	262,000
Western Oklahoma natural gas processed (Mcf/d)	186,300	203,800
Western Oklahoma NGL sales (gallons, in thousands)	54,800	57,300

Southeast Oklahoma gathering system throughput (Mcf/d)	461,300	501,200
Southeast Oklahoma natural gas processed (Mcf/d) (4)	151,200	101,700
Southeast Oklahoma NGL sales (gallons, in thousands)	39,300	33,000
Arkoma Connector Pipeline throughput (Mcf/d)	273,800	328,700

Other Southwest gathering system throughput (Mcf/d) (5)	20,600	25,000

Gulf Coast refinery off-gas processed (Mcf/d)	95,300	120,300
Gulf Coast liquids fractionated (Bbl/d)	17,200	23,400
Gulf Coast NGL sales (gallons excluding hydrogen, in thousands)	65,100	89,300

(1) Includes sale of all purity products fractionated at the Liberty facilities and sale of all unfractionated NGLs.

(2) Utica operations began in August 2012.

(3) Includes natural gas gathered in Western Oklahoma and from the Granite Wash formation in the Texas Panhandle as management considers this one integrated area of operations.

(4) The natural gas processing in Southeast Oklahoma is outsourced to Centrahoma or other third party processors.

(5) Excludes lateral pipelines where revenue is not based on throughput.

MarkWest Energy Partners, L.P.

Reconciliation of GAAP Financial Measure to Non-GAAP Financial Measure

Operating Income before Items not Allocated to Segments

(in thousands)

Three months ended March 31, 2013	Southwest			Northeast			Liberty		Utica			Total
Revenue	$	211,446		$	57,336		$	108,497	$	623		$	377,902

Operating expenses:
Purchased product costs	114,102			19,662			18,793		—			152,557
Facility expenses	29,123			6,524			22,636		3,962			62,245
Total operating expenses before items not allocated to segments	143,225			26,186			41,429		3,962			214,802

Portion of operating income (loss) attributable to non-controlling interests	1,387			—			—		(1,339		)	48
Operating income (loss) before items not allocated to segments	$	66,834		$	31,150		$	67,068	$	(2,000	)	$	163,052

Three months ended March 31, 2012	Southwest			Northeast			Liberty		Utica			Total
Revenue	$	238,954		$	86,918		$	75,577	$	—		$	401,449

Operating expenses:
Purchased product costs	104,233			25,687			24,635		—			154,555
Facility expenses	32,630			6,378			12,247		—			51,255
Total operating expenses before items not allocated to segments	136,863			32,065			36,882		—			205,810

Portion of operating income attributable to non-controlling interests	1,446			—			—		—			1,446
Operating income before items not allocated to segments	$	100,645		$	54,853		$	38,695	$	—		$	194,193

	Three months ended March 31,
	2013			2012

Operating income before items not allocated to segments	$	163,052		$	194,193
Portion of operating income attributable to non-controlling interests	48			1,446
Derivative gain (loss) not allocated to segments	10,851			(65,769		)
Revenue deferral adjustment	(1,765		)	(2,268		)
Compensation expense included in facility expenses not allocated to segments	(387		)	(449		)
Facility expenses adjustments	2,877			2,864
Selling, general and administrative expenses	(25,408		)	(25,224		)
Depreciation	(69,597		)	(41,145		)
Amortization of intangible assets	(14,830		)	(10,985		)
Loss on disposal of property, plant and equipment	(138		)	(986		)
Accretion of asset retirement obligations	(353		)	(238		)
Income from operations	64,350			51,439
Other income (expense):
Loss from unconsolidated affiliate	(85		)	(9		)
Interest income	149			72
Interest expense	(38,336		)	(29,472		)
Amortization of deferred financing costs and discount (a component of interest expense)	(1,830		)	(1,270		)
Loss on redemption of debt	(38,455		)	—
Miscellaneous income, net	—			58
(Loss) income before provision for income tax	$	(14,207	)	$	20,818

Reconciliation of GAAP Financial Measure to Non-GAAP Financial Measure

Distributable Cash Flow

(in thousands)

	Three months ended March 31,
	2013			2012

Net (loss) income	$	(20,764	)	$	16,273
Depreciation, amortization, impairment, and other non-cash operating expenses	84,996			53,432
Loss on redemption of debt, net of tax benefit	36,178			—
Amortization of deferred financing costs and discount	1,830			1,270
Non-cash loss from unconsolidated affiliate	85			9
Distributions from unconsolidated affiliate	—			900
Non-cash compensation expense	2,384			2,710
Non-cash derivative activity	(9,033		)	48,217
Provision for income tax - deferred	11,971			(10,796		)
Cash adjustment for non-controlling interest of consolidated subsidiaries	633			(1,017		)
Revenue deferral adjustment	1,765			2,268
Other	2,040			2,208
Maintenance capital expenditures, net of joint venture partner contributions	(1,891		)	(6,297		)
Distributable cash flow	$	110,194		$	109,177

Maintenance capital expenditures	$	1,891		$	6,297
Growth capital expenditures	629,667			247,966
Total capital expenditures	631,558			254,263
Acquisitions, net of cash acquired	—			—
Total capital expenditures and acquisitions	631,558			254,263
Joint venture partner contributions	(265,320		)	—
Total capital expenditures and acquisitions, net	$	366,238		$	254,263

Distributable cash flow	$	110,194		$	109,177
Maintenance capital expenditures, net of joint venture partner contributions	1,891			6,297
Changes in receivables and other assets	1,109			57,655
Changes in accounts payable, accrued liabilities and other long-term liabilities	(27,608		)	35,244
Cash adjustment for non-controlling interest of consolidated subsidiaries	(633		)	1,017
Other	90			(1,477		)
Net cash provided by operating activities	$	85,043		$	207,913

MarkWest Energy Partners, L.P.

Reconciliation of GAAP Financial Measure to Non-GAAP Financial Measure

Adjusted EBITDA

(in thousands)

	Three months ended March 31,
	2013			2012

Net (loss) income	$	(20,764	)	$	16,273
Non-cash compensation expense	2,384			2,710
Non-cash derivative activity	(9,033		)	48,217
Interest expense (1)	38,022			28,552
Depreciation, amortization, impairment, and other non-cash operating expenses	84,996			53,432
Loss on redemption of debt	38,455			—
Provision for income tax	6,557			4,545
Adjustment for cash flow from unconsolidated affiliate	85			909
Other	108			(1,498		)
Adjusted EBITDA	$	140,810		$	153,140

(1) Includes amortization of deferred financing costs and discount, and excludes interest expense related to the Steam Methane Reformer.

MarkWest Energy Partners, L.P.

Distributable Cash Flow Sensitivity Analysis

(unaudited, in millions)

MarkWest periodically estimates the effect on DCF resulting from its commodity risk management program, changes in crude oil and natural gas prices, and the ratio of NGL prices to crude oil. The table below reflects MarkWest’s estimate of the range of DCF for 2013 and forecasted crude oil and natural gas prices for 2013. The analysis assumes various combinations of crude oil and natural gas prices as well as three NGL-to-crude oil ratio scenarios, including:

a. NGL-to-crude oil ratio at 55% for 2013.

b. NGL-to-crude oil ratio at 45% for 2013.

c. NGL-to-crude oil ratio at 35% for 2013.

The analysis further assumes derivative instruments outstanding as of May 8, 2013, and production volumes estimated through December 31, 2013. The range of stated hypothetical changes in commodity prices considers current and historic market performance.

Estimated Range of 2013 DCF

Crude Oil		NGL-to-Crude	Natural Gas Price (Henry Hub)
Price (WTI)		oil ratio	$3.00		$3.50		$4.00		$4.50		$5.00
		55% of WTI	$	568	$	566	$	564	$	563	$	561
$	110	45% of WTI	$	526	$	524	$	522	$	520	$	518
		35% of WTI	$	484	$	483	$	481	$	479	$	477
		55% of WTI	$	551	$	549	$	547	$	546	$	544
$	100	45% of WTI	$	512	$	511	$	509	$	507	$	505
		35% of WTI	$	475	$	473	$	471	$	469	$	468
		55% of WTI	$	531	$	529	$	527	$	526	$	524
$	90	45% of WTI	$	497	$	495	$	493	$	491	$	489
		35% of WTI	$	461	$	459	$	457	$	455	$	453
		55% of WTI	$	513	$	512	$	510	$	508	$	506
$	80	45% of WTI	$	484	$	482	$	480	$	478	$	476
		35% of WTI	$	451	$	449	$	447	$	445	$	442
		55% of WTI	$	501	$	499	$	497	$	495	$	493
$	70	45% of WTI	$	471	$	469	$	467	$	466	$	464
		35% of WTI	$	446	$	443	$	441	$	438	$	435

(1) The composition is based on MarkWest’s average projected barrel of approximately: Ethane: 35%, Propane: 35%, Iso-Butane: 6%, Normal Butane: 12%, Natural Gasoline: 12%.

The table is based on current information, expectations, and beliefs concerning future developments and their potential effects, and does not consider actions MarkWest management may take to mitigate exposure to changes. Nor does the table consider the effects that such hypothetical adverse changes may have on overall economic activity. Historical prices and ratios of NGL-to-crude oil do not guarantee future results.

Although MarkWest believes the expectations reflected in this analysis are reasonable, MarkWest can give no assurance that such expectations will prove to be correct and readers are cautioned that projected performance, results, or distributions may not be achieved. Actual changes in market prices, and the ratio between crude oil and NGL prices, may differ from the assumptions utilized in the analysis. Actual results, performance, distributions, volumes, events, or transactions could vary significantly from those expressed, considered, or implied in this analysis. All results, performance, distributions, volumes, events, or transactions are subject to a number of uncertainties and risks. Those uncertainties and risks may not be factored into or accounted for in this analysis. Readers are urged to carefully review and consider the cautionary statements and disclosures made in MarkWest’s periodic reports filed with the SEC, specifically those under the heading “Risk Factors.”