August 7, 2008	MEDIA AND INVESTOR RELATIONS CONTACT:	Karen L. Taylor
	Phone:	303/633-2913
	24-Hour:	303/809-9160

DCP MIDSTREAM PARTNERS REPORTS

SECOND QUARTER 2008 RESULTS

·   Executing on significant organic growth opportunities in Piceance Basin and East Texas

·   Natural gas services drives strong earnings

·   Distribution up 13 percent over second quarter 2007, to $0.60 per unit

DENVER - DCP Midstream Partners, LP (NYSE: DPM), or the Partnership, today reported financial results for the three and six months ended June 30, 2008.

SECOND QUARTER AND YEAR-TO-DATE HIGHLIGHTS

	Three Months Ended June 30,					Six Months Ended June 30,
	2008			2007		2008			2007
	(unaudited) (Millions, except per unit amounts)
Net (loss) income	$	(159.3	)	$	0.8	$	(165.8	)	$	16.6
Net (loss) income per unit	$	(5.66	)	$	0.01	$	(6.33	)	$	0.60
Adjusted EBITDA	$	26.1		$	21.0	$	63.2		$	45.3
Adjusted net income	$	11.0		$	12.7	$	33.1		$	31.5
Adjusted net income per unit	$	0.29		$	0.57	$	0.95		$	1.25

Adjusted EBITDA increased $5.1 million and $17.9 million for the three and six months ended June 30, 2008, as compared to the same periods in 2007, primarily due to increased earnings from the natural gas services segment, partially offset by increased operating and maintenance expense associated with 2007 acquisitions and operational disruptions occurring in the second quarter of 2008 at our Douglas system.

Adjusted EBITDA, adjusted net income and adjusted net income per unit, which are non-generally accepted accounting principles (“non-GAAP”) financial measures, eliminate the impact of non-cash mark-to-market gains and losses which arise from valuing certain of the Partnership’s derivative transactions. Each are explained in greater detail under “Non-GAAP Financial Information” below and are reconciled to their most comparable GAAP financial measures, in “Reconciliation of Non-GAAP Measures” below.

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CEO PERSPECTIVE

“Our operations supported our ninth consecutive increase to our quarterly distribution, providing our unitholders with $0.60 per unit or $2.40 annually,” said Mark Borer, president and CEO. “Results from our natural gas services segment were the primary drivers of earnings increases over 2007 results. Our results were tempered, in part, this quarter by operational issues at our Douglas system.”

“We are pleased to have a slate of organic projects under way to continue to grow the Partnership,” continued Borer. “Soon we will begin expanding our East Texas joint venture gathering system and we’re finalizing plans for a significant expansion of our Piceance Basin gathering system. Both of these projects will provide attractive accretion to our unitholders. We are also pursuing development of an intrastate pipeline through the Haynesville Shale play in North Louisiana with M2 Midstream LLC. If built, our Haynesville Connector pipeline would leverage off our existing Pelico intrastate pipeline infrastructure, providing us a great opportunity to establish a powerful presence in one of the fastest growing natural gas plays in the United States.”

“As you will recall, DCP Midstream previously announced its plan to offer to sell the remaining 75 percent of East Texas to the Partnership,” continued Borer. “While we and DCP Midstream remain committed to pursuing a drop down of the East Texas asset, given continued volatility in capital markets, we may defer the drop down beyond our original 2008 targeted closing date. Our strong financial position and the strength of the Partnership’s sponsorship affords us flexibility in the timing of drop-downs as we continue to execute our growth strategy, including our slate of organic growth projects.”

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CORPORATE AND OTHER

General and administrative expense decreased by $1.6 million to $5.3 million, and by $0.9 million to $10.8 million, for the three and six months ended June 30, 2008, respectively, as compared to the same periods in 2007, primarily due to transaction costs incurred in 2007 related to acquisitions and decreased benefits cost in 2008, partially offset by increased fees paid to DCP Midstream, LLC in 2008 under the Omnibus Agreement, primarily due to 2007 acquisitions.

Depreciation and amortization expense and net interest expense increased for the three and six months ended June 30, 2008, respectively, as compared to the same periods in 2007, primarily as a result of 2007 acquisitions and their related financing.

COMMODITY DERIVATIVE ACTIVITY

We utilize mark-to-market accounting treatment for our commodity derivative instruments. Mark-to-market accounting rules require companies to record currently in earnings the difference between their contracted derivative settlement prices and the forward prices of the underlying commodities. In the second quarter of 2008, we recorded a non-cash loss associated with our commodity derivative instruments of $170.4 million, as compared to a non-cash loss of $11.9 million for the second quarter of 2007. While our earnings will continue to fluctuate as a result of the volatility in the commodity markets, our derivative contracts yield us fixed prices and help to stabilize distributable cash flows.

DISTRIBUTION INCREASE

On July 24, 2008, the Partnership announced a $0.01 increase in the quarterly distribution to $0.60 per limited partner unit, or $2.40 per limited partner unit on an annualized basis. Distributable cash flow was $23.5 million for the three months ended June 30, 2008, providing 1.17 times the amount required to cover our current distribution to both the general and limited partners. For the six months ended June 30, 2008, our distributable cash flow of $55.6 million provided 1.40 times the amount required to cover our total distribution. Non-cash gains or losses associated with the mark-to-market accounting treatment of our commodity derivative instruments do not affect our distributable cash flow.

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Distributable cash flow, which is a non-GAAP financial measure, is explained in greater detail under “Non-GAAP Financial Information” below and is reconciled from net (loss) income and from net cash provided by operating activities, its most comparable GAAP financial measures, in “Reconciliation of Non-GAAP Measures” below.

OPERATING RESULTS BY BUSINESS SEGMENT

Natural Gas Services — Adjusted segment gross margin increased $1.3 million to $24.0 million for the three months ended June 30, 2008, from $22.7 million for the same period in 2007. Adjusted segment gross margin increased $12.7 million to $52.5 million for the six months ended June 30, 2008, from $39.8 million for the same period in 2007. The increases in margin are primarily due to the acquisitions closed in May and August of 2007, higher commodity prices in 2008 as compared to 2007 and changes in contract mix. These increases were partially offset by hedge settlements, of which $5.2 million and $8.1 million for the three and six months ended June 30, 2008, respectively, relate to our equity investments in East Texas and Discovery. Although results from East Texas and Discovery are pooled in our second quarter 2007 results in equity earnings, there were no hedge settlements for these two investments prior to the Partnership’s purchase of them on July 1, 2007.

We completed pipeline integrity testing at our Douglas system in the second quarter of 2008. Based on the results, we curtailed certain volumes and reduced pipeline operating pressures, reducing cash flows for the quarter. Over the next six months, we anticipate decreased operating revenues and increased operating costs as we address the results of the testing.

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Equity earnings representing our 25 percent interest in East Texas and 40 percent interest in Discovery increased by $7.1 million to $13.2 million, and by $17.7 million to $30.0 million, for the three and six months ended June 30, 2008, respectively, as compared to the same periods in 2007. The increase for East Texas is primarily due to increased commodity prices, fee-based revenue and volumes, and decreased general and administrative expenses, partially offset by increased operating expenses. The increase for Discovery is primarily due to increased processing volumes and margins and higher other income, net, partially offset by higher general and administrative expense.

Wholesale Propane Logistics— Adjusted segment gross margin decreased by $1.5 million to $2.6 million for the three months ended June 30, 2008, from $4.1 million for the same period in 2007. Adjusted segment gross margin decreased by $6.5 million to $8.5 million for the six months ended June 30, 2008, from $15.0 million for the same period of 2007. The decreases are primarily a result of lower unit margins and sales volumes. For the three and six months ended June 30, 2008, the decrease in sales volumes was driven primarily by supply disruptions and decreased demand as a result of higher propane prices. Unit margins for the six months ended June 30, 2007, were favorably impacted by the reversal of non-cash inventory adjustments taken in late 2006.

During the second quarter of 2008, we received $1.5 million from a supplier related to the early termination of its supply agreement. This agreement was set to expire in the second quarter of 2009. This termination payment was recorded to other operating income.

NGL Logistics— Segment gross margin increased $0.9 million and $1.5 million for the three and six months ended June 30, 2008, respectively, as compared to the same periods in 2007, primarily due to changes in product mix and increased throughput volumes on both our Seabreeze and Wilbreeze pipelines.

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Equity earnings from our 45 percent interest in the Black Lake pipeline remained relatively constant for the three and six months ended June 30, 2008, as compared to the same periods in 2007.

Segment gross margin and adjusted segment gross margin, which are non-GAAP financial measures, are explained in greater detail under “Non-GAAP Financial Information” below and are reconciled from segment net (loss) income, their most comparable GAAP financial measure, in “Reconciliation of Non-GAAP Measures” below.

ORGANIC GROWTH PROJECTS

Piceance Basin Gathering Expansion

The Partnership is finalizing agreements for Collbran Valley Gas Gathering (CVGG) to invest approximately $150 million over a multi-year period to construct a 24-inch diameter gathering pipeline with a capacity of 600 MMcf/d to support the increasing need for natural gas infrastructure in the Collbran Valley area of the Piceance Basin, located in western Colorado. The gathering system will be supported by long-term acreage dedications from Plains Exploration & Production (PXP), Delta Petroleum (Delta), and a long-term dedication from a subsidiary of Enterprise Products Partners L.P. (Enterprise) covering gas it has the right to gather from a specified, dedicated area within the Piceance Basin. The new CVGG gathering line will interconnect with a pipeline to be constructed by Enterprise, where it will be gathered into Enterprise’s Meeker gas processing facility. The Partnership owns a 70 percent interest in CVGG, PXP and OXY USA, Inc. together own 25 percent, and Delta owns 5 percent.

East Texas Pipeline Expansion

The Partnership, along with DCP Midstream, LLC, the owner of the Partnership’s general partner, recently announced a $56 million pipeline project which will extend their East Texas joint venture gathering footprint in southern Panola County and access volumes from the rapidly growing Minden field in Rusk County. The 30-mile, 20-inch diameter pipeline, with a designed capacity of 175 MMcf/d, will gather gas for processing at the joint venture’s East Texas complex. The gathering system is scheduled to be in-service during the second quarter of 2009. Upon completion, the pipeline will receive dedicated volumes from third parties and expand our reach into a new development area of East Texas. The Partnership owns 25 percent of the East Texas joint venture.

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Haynesville Connector Intrastate Pipeline

The Partnership and M2 Midstream LLC recently announced an agreement to pursue development of a new large diameter intrastate natural gas pipeline to help meet producers’ anticipated needs for pipeline infrastructure in the emerging Haynesville Shale play in North Louisiana. The Haynesville Connector would be an extension of the Partnership’s Pelico Intrastate Pipeline and would originate in western DeSoto Parish and span over 150 miles to Delhi, La., providing access to multiple takeaway pipelines in the area. If built, the Haynesville Connector would commence initial deliveries in the third quarter of 2009 and would offer an estimated 1.5 billion cubic feet per day of takeaway capacity by early 2010.

CAPITALIZATION

As of June 30, 2008, we had $440.0 million outstanding under the revolver portion and $220.0 million outstanding under the term loan portion of our $850.0 million credit facility. The term loan is fully collateralized by marketable securities, resulting in a net debt balance of $440.0 million and available capacity under our revolver of approximately $190.0 million. The term loan collateral may be used to fund organic growth projects or third party acquisitions.

We mitigate a portion of our interest rate risk with interest rate swaps which reduce our exposure to market rate fluctuations by converting variable interest rates to fixed interest rates. As of June 30, 2008, our weighted average cost of debt under our revolving credit facility was 5.16 percent.

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EARNINGS CALL

DCP Midstream Partners will hold a conference call to discuss second quarter results on Friday, August 8, 2008, at 11 a.m. ET. The dial-in number for the call is 800-860-2422 in the United States or 412-858-4600 outside the United States. A live Webcast of the call can be accessed on the investor information page of DCP Midstream Partners’ Web site at http://www.dcppartners.com. The call will be available for replay until Aug. 18, 2008, by dialing 877-344-7529, in the United States or 412-317-0088 outside the United States. The passcode is 421185. A replay and transcript of the broadcast will also be available on the Partnership’s Web site.

NON-GAAP FINANCIAL INFORMATION

This press release and the accompanying financial schedules include the non-GAAP financial measures of distributable cash flow, EBITDA, adjusted EBITDA, adjusted net income, adjusted net income per unit, gross margin, segment gross margin and adjusted segment gross margin. The accompanying schedules provide reconciliations of these non-GAAP financial measures to their most directly comparable financial measures calculated and presented in accordance with accounting principles generally accepted in the United States of America (“GAAP”). Our non-GAAP financial measures should not be considered an alternative to, or more meaningful than, net income, operating income, cash flows from operating activities or any other measure of liquidity or financial performance presented in accordance with GAAP as measures of operating performance, liquidity or ability to service debt obligations and make cash distributions to unitholders. Our distributable cash flow, EBITDA, adjusted EBITDA, adjusted net income, adjusted net income per unit, gross margin, segment gross margin and adjusted segment gross margin may not be comparable to a similarly titled measure of another company because other entities may not calculate these measures in the same manner.

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We define distributable cash flow as net cash provided by operating activities, less maintenance capital expenditures, net of reimbursable projects, plus or minus adjustments for non-cash mark-to-market of derivative instruments, net changes in operating assets and liabilities, and other adjustments to reconcile net cash provided by or used in operating activities. Maintenance capital expenditures are capital expenditures made where we add on to or improve capital assets owned, or acquire or construct new capital assets, if such expenditures are made to maintain, including over the long term, our operating capacity. Non-cash mark-to-market of derivative instruments is considered to be non-cash for the purpose of computing distributable cash flow because settlement will not occur until future periods, and will be impacted by future changes in commodity prices. Distributable cash flow is used as a supplemental liquidity measure by our management and by external users of our financial statements, such as investors, commercial banks, research analysts and others, to assess our ability to make cash distributions to our unitholders and our general partner.

We define EBITDA (earnings before interest, taxes, depreciation and amortization) as net (loss) income less interest income, plus interest expense, income tax expense and depreciation and amortization expense. We define adjusted EBITDA as EBITDA plus non-cash derivative losses, less non-cash derivative gains. These non-cash losses and gains result from the marking to market of certain financial derivatives used by the Partnership for risk management purposes that we do not account for under the hedge method of accounting. These non-cash losses or gains may or may not be realized in future periods when the derivative contracts are settled, due to fluctuating commodity prices.

EBITDA and adjusted EBITDA are used as supplemental liquidity measures by our management and by external users of our financial statements, such as investors, commercial banks, research analysts and others, to assess the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness, make cash distributions to our unitholders and general partner, and finance maintenance capital expenditures.

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EBITDA and adjusted EBITDA are also used as supplemental performance measures by our management and by external users of our financial statements, such as investors, commercial banks, research analysts and others, to assess:

·   financial performance of our assets without regard to financing methods, capital structure or historical cost basis;

·   our operating performance and return on capital as compared to those of other companies in the midstream energy industry, without regard to financing methods or capital structure; and

·   viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

We define adjusted net income as net (loss) income plus non-cash derivative losses, less non-cash derivative gains. These non-cash derivative losses and gains result from the marking to market of certain financial derivatives used by the Partnership for risk management purposes that we do not account for under the hedge method of accounting. Adjusted net income is provided to illustrate trends in income excluding these non-cash derivative losses or gains, which may or may not be realized in future periods when derivative contracts are settled, due to fluctuating commodity prices.

We define gross margin as total operating revenues less purchases of natural gas, propane and NGLs, and we define segment gross margin for each segment as total operating revenues for that segment less commodity purchases for that segment. Our gross margin equals the sum of our segment gross margins. We define adjusted segment gross margin as segment gross margin plus non-cash derivative losses, less non-cash derivative gains for that segment. Gross margin, segment gross margin and adjusted segment gross margin are primary performance measures used by management, as these measures represent the results of product sales and purchases, a key component of our operations.

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DCP Midstream Partners, LP (NYSE: DPM) is a midstream master limited partnership that gathers, processes, transports and markets natural gas and natural gas liquids and is a leading wholesale distributor of propane. DCP Midstream Partners, LP is managed by its general partner, DCP Midstream GP, LLC, which is wholly owned by DCP Midstream, LLC, a joint venture between Spectra Energy and ConocoPhillips. For more information, visit the DCP Midstream Partners, LP Web site at http://www.dcppartners.com.

This press release may contain or incorporate by reference forward-looking statements as defined under the federal securities laws regarding DCP Midstream Partners, LP, including projections, estimates, forecasts, plans and objectives. Although management believes that expectations reflected in such forward-looking statements are reasonable, no assurance can be given that such expectations will prove to be correct. In addition, these statements are subject to certain risks, uncertainties and other assumptions that are difficult to predict and may be beyond our control. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, the Partnership’s actual results may vary materially from what management anticipated, estimated, projected or expected. Among the key risk factors that may have a direct bearing on the Partnership’s results of operations and financial condition are:

·   the level and success of natural gas drilling around our assets and our ability to connect supplies to our gathering and processing systems in light of competition;

·   our ability to grow through acquisitions or organic growth projects, and the successful integration and future performance of such assets;

·   our ability to access the debt and equity markets;

·   fluctuations in oil, natural gas, propane and other NGL prices;

·   our ability to purchase propane from our principal suppliers for our wholesale propane logistics business; and

·   the credit worthiness of counterparties to our transactions.

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While DCP Midstream, LLC has indicated that it plans to make an offer to the Partnership regarding the sale of its 75 percent interest in the East Texas joint venture, DCP Midstream, LLC may ultimately elect not to offer these assets to the Partnership or to offer different assets to the Partnership. Additionally, even if DCP Midstream, LLC elects to offer the assets to the Partnership, the two parties may not agree upon mutually acceptable terms.

Investors are encouraged to closely consider the disclosures and risk factors contained in the Partnership’s annual and quarterly reports filed from time to time with the Securities and Exchange Commission. The Partnership undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. Information contained in this press release is unaudited, and is subject to change.

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DCP MIDSTREAM PARTNERS, LP

FINANCIAL RESULTS

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2008			2007			2008			2007
	(Millions, except per unit amounts)
Sales of natural gas, propane, NGLs and condensate	$	318.5		$	185.6		$	681.2		$	418.5
Transportation, processing and other		14.0			7.5			26.1			14.8
Losses from commodity derivative activity, net		(186.6	)		(12.0	)		(223.7	)		(15.0	)
Total operating revenues		145.9			181.1			483.6			418.3
Purchases of natural gas, propane and NGLs		287.8			165.2			617.5			376.1
Gross margin		(141.9	)		15.9			(133.9	)		42.2
Operating and maintenance expense		(11.0	)		(6.3	)		(21.6	)		(12.9	)
General and administrative expense		(5.3	)		(6.9	)		(10.8	)		(11.7	)
Other		1.5			—			1.5			—
Earnings from equity method investments		13.4			6.4			30.6			12.8
Non-controlling interest in income		(0.9	)		—			(1.5	)		—
EBITDA		(144.2	)		9.1			(135.7	)		30.4
Depreciation and amortization expense		(9.0	)		(4.5	)		(17.5	)		(7.9	)
Interest income		1.8			0.8			3.4			2.5
Interest expense		(7.9	)		(4.6	)		(16.0	)		(8.4	)
Net (loss) income	$	(159.3	)	$	0.8		$	(165.8	)	$	16.6
Less:
Net income attributable to predecessor operations		—			(0.3	)		—			(3.6	)
General partner interest in net income		(0.5	)		(0.3	)		(2.2	)		(0.6	)
Net (loss) income allocable to limited partners	$	(159.8	)	$	0.2		$	(168.0	)	$	12.4
Net (loss) income per limited partner unit—basic and diluted	$	(5.66	)	$	0.01		$	(6.33	)	$	0.60
Weighted-average limited partner units outstanding—basic and diluted		28.2			18.0			26.6			17.8

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DCP MIDSTREAM PARTNERS, LP

RECONCILIATION OF NON-GAAP MEASURES

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2008			2007			2008			2007
	(Millions, except per unit amounts)
Reconciliation of Non-GAAP Measures:
Net (loss) income	$	(159.3	)	$	0.8		$	(165.8	)	$	16.6
Interest income		(1.8	)		(0.8	)		(3.4	)		(2.5	)
Interest expense		7.9			4.6			16.0			8.4
Depreciation and amortization expense		9.0			4.5			17.5			7.9
EBITDA		(144.2	)		9.1			(135.7	)		30.4
Non-cash derivative mark-to-market		170.3			11.9			198.9			14.9
Adjusted EBITDA		26.1			21.0			63.2			45.3
Interest income		1.8			0.8			3.4			2.5
Interest expense		(7.9	)		(4.6	)		(16.0	)		(8.4	)
Depreciation and amortization expense		(9.0	)		(4.5	)		(17.5	)		(7.9	)
Adjusted net income		11.0			12.7			33.1			31.5
Maintenance capital expenditures, net of reimbursable projects		(1.4	)		(0.3	)		(1.9	)		(0.9	)
Earnings from equity method investments, net of distributions		4.9			6.5			6.9			5.7
Depreciation and amortization expense		9.0			4.5			17.5			7.9
Distributable cash flow	$	23.5		$	23.4		$	55.6		$	44.2
Adjusted net income	$	11.0		$	12.7		$	33.1		$	31.5
Less:
Net income attributable to predecessor operations		—			(0.3	)		—			(3.6	)
General partner interest in net income		(2.8	)		(0.5	)		(4.9	)		(0.9	)
Adjusted net income allocable to limited partners	$	8.2		$	11.9		$	28.2		$	27.0
Adjusted net income per unit	$	0.29		$	0.57		$	0.95		$	1.25
Net cash (used in) provided by operating activities	$	(12.4	)	$	20.0		$	12.7		$	39.8
Interest income		(1.8	)		(0.8	)		(3.4	)		(2.5	)
Interest expense		7.9			4.6			16.0			8.4
Earnings from equity method investments, net of distributions		(4.9	)		(6.5	)		(6.9	)		(5.7	)
Net changes in operating assets and liabilities		(132.4	)		(8.1	)		(153.4	)		(10.0	)
Other, net		(0.6	)		(0.1	)		(0.7	)		0.4
EBITDA		(144.2	)		9.1			(135.7	)		30.4
Non-cash derivative mark-to-market		170.3			11.9			198.9			14.9
Adjusted EBITDA		26.1			21.0			63.2			45.3
Interest income		1.8			0.8			3.4			2.5
Interest expense		(7.9	)		(4.6	)		(16.0	)		(8.4	)
Maintenance capital expenditures, net of reimbursable projects		(1.4	)		(0.3	)		(1.9	)		(0.9	)
Earnings from equity method investments, net of distributions		4.9			6.5			6.9			5.7
Distributable cash flow	$	23.5		$	23.4		$	55.6		$	44.2

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DCP MIDSTREAM PARTNERS, LP

SEGMENT FINANCIAL RESULTS AND OPERATING DATA

AND RECONCILIATION OF NON-GAAP MEASURES

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2008			2007			2008			2007
	(Millions, except as indicated)
Natural Gas Services Segment:
Financial results:
Segment net (loss) income	$	(150.4	)	$	9.5		$	(152.2	)	$	23.7
Operating and maintenance expense		8.1			3.9			15.8			7.2
Depreciation and amortization expense		8.4			3.8			16.2			6.7
Earnings from equity method investments		(13.2	)		(6.1	)		(30.0	)		(12.3	)
Non-controlling interest in income		0.9			—			1.5			—
Segment gross margin		(146.2	)		11.1			(148.7	)		25.3
Non-cash derivative mark-to-market		170.2			11.6			201.2			14.5
Adjusted segment gross margin	$	24.0		$	22.7		$	52.5		$	39.8
Operating data:
Natural gas throughput (MMcf/d)		835			733			831			716
NGL gross production (Bbls/d)		23,769			21,563			24,480			20,207
Wholesale Propane Logistics Segment:
Financial results:
Segment net income	$	0.9		$	1.5		$	6.5		$	8.9
Operating and maintenance expense		2.7			2.1			5.4			5.3
Depreciation and amortization expense		0.3			0.2			0.6			0.4
Other		(1.5	)		—			(1.5	)		—
Segment gross margin		2.4			3.8			11.0			14.6
Non-cash derivative mark-to-market		0.2			0.3			(2.5	)		0.4
Adjusted segment gross margin	$	2.6		$	4.1		$	8.5		$	15.0
Operating data:
Propane sales volume (Bbls/d)		14,442			16,179			24,178			25,715
NGL Logistics Segment:
Financial results:
Segment net income	$	1.6		$	0.5		$	3.3		$	1.6
Operating and maintenance expense		0.2			0.3			0.4			0.4
Depreciation and amortization expense		0.3			0.5			0.7			0.8
Earnings from equity method investments		(0.2	)		(0.3	)		(0.6	)		(0.5	)
Segment gross margin	$	1.9		$	1.0		$	3.8		$	2.3
Operating data:
NGL pipelines throughput (Bbls/d)		34,286			28,376			33,081			27,917

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