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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM 10-Q

 

 

(Mark One)

x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2010

or

 

¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                to                

Commission File Number: 001-32678

 

 

DCP MIDSTREAM PARTNERS, LP

(Exact name of registrant as specified in its charter)

 

 

 

Delaware		03-0567133
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
370 17th Street, Suite 2775 Denver, Colorado		80202
(Address of principal executive offices)		(Zip Code)

Registrant’s telephone number, including area code: (303) 633-2900

 

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ¨    No  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

Large accelerated filer		¨		Accelerated filer		x
Non-accelerated filer		¨		Smaller reporting company		¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  x

As of November 4, 2010, there were outstanding 37,603,383 common units representing limited partner interests.

 

 

 

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DCP MIDSTREAM PARTNERS, LP

FORM 10-Q FOR THE QUARTER ENDED SEPTEMBER 30, 2010

TABLE OF CONTENTS

 

Item				Page
		PART I. FINANCIAL INFORMATION
1.		Financial Statements (unaudited):
		Condensed Consolidated Balance Sheets as of September 30, 2010 and December 31, 2009			1
		Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2010 and 2009			2
		Condensed Consolidated Statements of Comprehensive Income (Loss) for the Three and Nine Months Ended September 30, 2010 and 2009			3
		Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2010 and 2009			4
		Condensed Consolidated Statements of Changes in Equity for the Nine Months Ended September 30, 2010			5
		Condensed Consolidated Statements of Changes in Equity for the Nine Months Ended September 30, 2009			6
		Notes to the Condensed Consolidated Financial Statements			7
2.		Management’s Discussion and Analysis of Financial Condition and Results of Operations			49
3.		Quantitative and Qualitative Disclosures about Market Risk			74
4.		Controls and Procedures			77
		PART II. OTHER INFORMATION
1.		Legal Proceedings			78
1A.		Risk Factors			78
6.		Exhibits			81
		Signatures			82
		Exhibit Index			83
		Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes Oxley Act of 2002
		Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes Oxley Act of 2002
		Certification of Chief Executive Officer Pursuant to Section 906 of the Sarbanes Oxley Act of 2002
		Certification of Chief Financial Officer Pursuant to Section 906 of the Sarbanes Oxley Act of 2002

 

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GLOSSARY OF TERMS

The following is a list of certain industry terms used throughout this report:

 

Bbls		barrels
Bbls/d		barrels per day
Btu		British thermal unit, a measurement of energy
Bcf		billion cubic feet
Frac spread		price differences, measured in energy units, between equivalent amounts of natural gas and natural gas liquids
Fractionation		the process by which natural gas liquids are separated into individual components
MMBtu		one million British thermal units, a measurement of energy
MMcf/d		one million cubic feet per day
NGLs		natural gas liquids
Throughput		the volume of product transported or passing through a pipeline or other facility

 

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CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

Our reports, filings and other public announcements may from time to time contain statements that do not directly or exclusively relate to historical facts. Such statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. You can typically identify forward-looking statements by the use of forward-looking words, such as “may,” “could,” “project,” “believe,” “anticipate,” “expect,” “estimate,” “potential,” “plan,” “forecast” and other similar words.

All statements that are not statements of historical fact, including statements regarding our future financial position, business strategy, budgets, projected costs and plans and objectives of management for future operations, are forward-looking statements.

These forward-looking statements reflect our intentions, plans, expectations, assumptions and beliefs about future events and are subject to risks, uncertainties and other factors, many of which are outside our control. Important factors that could cause actual results to differ materially from the expectations expressed or implied in the forward-looking statements include known and unknown risks. Known risks and uncertainties include, but are not limited to, the risks set forth in “Item 1A. Risk Factors” in this Quarterly Report on Form 10-Q and in our Annual Report on Form 10-K for the year ended December 31, 2009, as well as the following risks and uncertainties:

 

•

the extent of changes in commodity prices, our ability to effectively limit a portion of the adverse impact of potential changes in prices through derivative financial instruments, and the potential impact of price and producers’ access to capital on natural gas drilling, demand for our services, and the volume of NGLs and condensate extracted;

 

•

general economic, market and business conditions;

 

•

the level and success of natural gas drilling around our assets, the level and quality of gas production volumes 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, contributions from affiliates, or organic growth projects, and the successful integration and future performance of such assets;

 

•

our ability to access the debt and equity markets, which will depend on general market conditions, inflation rates, interest rates and our ability to effectively limit a portion of the adverse effects of potential changes in interest rates by entering into derivative financial instruments, our ability to comply with the covenants to our credit agreement and our debt securities, as well as our ability to maintain our credit ratings;

 

•

our ability to purchase propane from our principal suppliers and make associated profitable sales transactions for our wholesale propane logistics business;

 

•

our ability to construct facilities in a timely fashion, which is partially dependent on obtaining required construction, environmental and other permits issued by federal, state and municipal governments, or agencies thereof, the availability of specialized contractors and laborers, and the price of and demand for supplies;

 

•

the creditworthiness of counterparties to our transactions;

 

•

weather and other natural phenomena, including their potential impact on demand for the commodities we sell and the operation of company owned and third-party-owned infrastructure;

 

•

additions and changes in laws and regulations, particularly with regard to taxes, safety and protection of the environment, including climate change legislation, or the increased regulation of our industry;

 

•

our ability to obtain insurance on commercially reasonable terms, if at all, as well as the adequacy of the insurance to cover our losses;

 

•

industry changes, including the impact of consolidations, increased delivery of liquefied natural gas to the United States, alternative energy sources, technological advances and changes in competition; and

 

•

the amount of collateral we may be required to post from time to time in our transactions, including changes resulting from the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010.

In light of these risks, uncertainties and assumptions, the events described in the forward-looking statements might not occur or might occur to a different extent or at a different time than we have described. We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

 

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PART I. FINANCIAL INFORMATION

Item  1. Financial Statements

DCP MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

 

		September 30, 2010				December 31, 2009
		(Millions)
ASSETS
Current assets:
Cash and cash equivalents		$	11.8			$	2.1
Accounts receivable:
Trade, net of allowance for doubtful accounts of $0.7 million and $0.5 million, respectively			48.0				78.7
Affiliates			55.1				73.8
Inventories			31.8				34.2
Unrealized gains on derivative instruments			1.7				7.3
Assets held for sale			7.9				—
Other			2.1				1.6
Total current assets			158.4				197.7
Restricted investments			—				10.0
Property, plant and equipment, net			1,042.5				1,000.1
Goodwill			99.7				92.1
Intangible assets, net			87.6				60.5
Investments in unconsolidated affiliates			103.6				114.6
Unrealized gains on derivative instruments			1.3				2.0
Other long-term assets			6.1				4.5
Total assets		$	1,499.2			$	1,481.5
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable:
Trade		$	57.8			$	85.5
Affiliates			27.6				43.1
Unrealized losses on derivative instruments			36.1				41.5
Other			38.3				21.0
Total current liabilities			159.8				191.1
Long-term debt			612.8				613.0
Unrealized losses on derivative instruments			46.8				58.0
Other long-term liabilities			15.6				14.0
Total liabilities			835.0				876.1
Commitments and contingent liabilities
Equity:
Common unitholders (37,603,383 and 34,608,183 units issued and outstanding, respectively)			482.5				415.5
General partner unitholders			(6.1	)			(5.9	)
Accumulated other comprehensive loss			(33.2	)			(31.9	)
Total partners’ equity			443.2				377.7
Noncontrolling interests			221.0				227.7
Total equity			664.2				605.4
Total liabilities and equity		$	1,499.2			$	1,481.5

See accompanying notes to condensed consolidated financial statements.

 

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DCP MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

 

		Three Months  Ended September 30,								Nine Months  Ended September 30,
		2010				2009				2010				2009
		(Millions, except per unit amounts)
Operating revenues:
Sales of natural gas, propane, NGLs and condensate		$	102.8			$	65.6			$	431.4			$	294.6
Sales of natural gas, propane, NGLs and condensate to affiliates			124.9				112.5				394.7				314.3
Transportation, processing and other			23.1				20.2				66.8				57.6
Transportation, processing and other to affiliates			5.6				4.0				16.2				11.1
(Losses) gains from commodity derivative activity, net			(15.8	)			4.4				13.0				(31.9	)
Losses from commodity derivative activity, net — affiliates			(0.7	)			(1.0	)			(1.0	)			(3.6	)
Total operating revenues			239.9				205.7				921.1				642.1
Operating costs and expenses:
Purchases of natural gas, propane and NGLs			155.2				112.4				524.8				360.8
Purchases of natural gas, propane and NGLs from affiliates			45.0				38.9				213.9				155.7
Operating and maintenance expense			19.2				19.0				58.8				52.3
Depreciation and amortization expense			19.2				16.4				55.7				47.3
General and administrative expense			3.3				2.9				10.4				8.1
General and administrative expense — affiliates			4.9				5.0				14.6				15.5
Step acquisition — equity interest re-measurement gain			(9.1	)			—				(9.1	)			—
Other income			(0.5	)			—				(1.0	)			—
Other income — affiliates			—				—				(3.0	)			—
Total operating costs and expenses			237.2				194.6				865.1				639.7
Operating income			2.7				11.1				56.0				2.4
Interest income			—				—				—				0.3
Interest expense			(7.5	)			(7.1	)			(22.0	)			(21.4	)
Earnings from unconsolidated affiliates			4.1				8.4				18.6				11.0
(Loss) income before income taxes			(0.7	)			12.4				52.6				(7.7	)
Income tax expense			(0.1	)			—				(0.5	)			(0.1	)
Net (loss) income			(0.8	)			12.4				52.1				(7.8	)
Net income attributable to noncontrolling interests			(3.3	)			(2.5	)			(4.4	)			(3.3	)
Net (loss) income attributable to partners			(4.1	)			9.9				47.7				(11.1	)
Net loss attributable to predecessor operations			—				—				—				1.0
General partner unitholders’ interest in net income or net loss			(4.1	)			(3.4	)			(12.1	)			(9.3	)
Net (loss) income allocable to limited partners		$	(8.2	)		$	6.5			$	35.6			$	(19.4	)
Net (loss) income per limited partner unit — basic		$	(0.23	)		$	0.21			$	1.01			$	(0.63	)
Net (loss) income per limited partner unit — diluted		$	(0.23	)		$	0.21			$	1.01			$	(0.63	)
Weighted-average limited partner units outstanding — basic and diluted			36.0				31.7				35.1				30.6

See accompanying notes to condensed consolidated financial statements.

 

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DCP MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Unaudited)

 

		Three Months  Ended September 30,								Nine Months  Ended September 30,
		2010				2009				2010				2009
		(Millions)
Net (loss) income		$	(0.8	)		$	12.4			$	52.1			$	(7.8	)
Other comprehensive income (loss):
Reclassification of cash flow hedge losses into earnings			5.3				5.4				16.9				14.6
Net unrealized losses on cash flow hedges			(4.8	)			(8.3	)			(18.2	)			(8.0	)
Total other comprehensive income (loss)			0.5				(2.9	)			(1.3	)			6.6
Total comprehensive (loss) income			(0.3	)			9.5				50.8				(1.2	)
Total comprehensive income attributable to noncontrolling interests			(3.3	)			(2.5	)			(4.4	)			(3.3	)
Total comprehensive (loss) income attributable to partners		$	(3.6	)		$	7.0			$	46.4			$	(4.5	)

See accompanying notes to condensed consolidated financial statements.

 

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DCP MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

 

		Nine Months Ended September 30,
		2010				2009
		(Millions)
OPERATING ACTIVITIES:
Net income (loss)		$	52.1			$	(7.8	)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense			55.7				47.3
Earnings from unconsolidated affiliates			(18.6	)			(11.0	)
Distributions from unconsolidated affiliates			23.9				10.5
Step acquisition — equity interest re-measurement gain			(9.1	)			—
Other, net			(0.2	)			(0.4	)
Change in operating assets and liabilities, which provided (used) cash net of effects of acquisitions:
Accounts receivable			52.1				27.9
Inventories			19.0				(4.4	)
Net unrealized (gains) losses on derivative instruments			(11.6	)			53.7
Accounts payable			(44.6	)			(22.8	)
Other current assets and liabilities			10.7				1.5
Other long-term assets and liabilities			1.0				0.6
Net cash provided by operating activities			130.4				95.1
INVESTING ACTIVITIES:
Capital expenditures			(37.1	)			(143.0	)
Acquisitions, net of cash acquired			(103.8	)			0.6
Investments in unconsolidated affiliates			(0.7	)			(5.8	)
Return of investment from unconsolidated affiliate			1.2				—
Proceeds from sale of assets			1.7				0.3
Purchases of available-for-sale securities			—				(1.1	)
Proceeds from sales of available-for-sale securities			10.1				51.1
Net cash used in investing activities			(128.6	)			(97.9	)
FINANCING ACTIVITIES:
Proceeds from debt			658.2				113.7
Payments of debt			(658.4	)			(157.2	)
Payment of deferred financing costs			(1.6	)			—
Proceeds from issuance of common units, net of offering costs			93.2				—
Net change in advances to predecessor from DCP Midstream, LLC			—				3.0
Distributions to unitholders and general partner			(74.4	)			(62.8	)
Distributions to noncontrolling interests			(16.0	)			(15.4	)
Contributions from noncontrolling interests			10.4				71.8
Contributions from DCP Midstream, LLC			—				0.7
Purchase of additional interest in a subsidiary			(3.5	)			—
Net cash provided by (used in) financing activities			7.9				(46.2	)
Net change in cash and cash equivalents			9.7				(49.0	)
Cash and cash equivalents, beginning of period			2.1				61.9
Cash and cash equivalents, end of period		$	11.8			$	12.9

See accompanying notes to condensed consolidated financial statements.

 

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DCP MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(Unaudited)

 

		Partners’ Equity
		Predecessor Equity				Common Unitholders				Class D Unitholders				Subordinated Unitholders				General Partner Unitholders				Accumulated Other Comprehensive (Loss) Income				Noncontrolling Interests				Total Equity
		(Millions)
Balance, January 1, 2010		$	—			$	415.5			$	—			$	—			$	(5.9	)		$	(31.9	)		$	227.7			$	605.4
Purchase of additional interest in a subsidiary			—				1.0				—				—				—				—				(5.5	)			(4.5	)
Issuance of 2,990,000 common units							93.1				—				—				—				—				—				93.1
Equity based compensation			—				0.2				—				—				—				—				—				0.2
Distributions to unitholders and general partner			—				(62.6	)			—				—				(11.8	)			—				—				(74.4	)
Distributions to noncontrolling interests			—				—				—				—				—				—				(16.0	)			(16.0	)
Contributions from noncontrolling interests			—				—				—				—				—				—				10.4				10.4
Excess purchase price over acquired assets			—				(0.8	)			—				—				—				—				—				(0.8	)
Comprehensive income (loss):
Net income			—				36.1				—				—				11.6				—				4.4				52.1
Reclassification of cash flow hedges into earnings			—				—				—				—				—				16.9				—				16.9
Net unrealized losses on cash flow hedges			—				—				—				—				—				(18.2	)			—				(18.2	)
Total comprehensive income (loss)			—				36.1				—				—				11.6				(1.3	)			4.4				50.8
Balance, September 30, 2010		$	—			$	482.5			$	—			$	—			$	(6.1	)		$	(33.2	)		$	221.0			$	664.2

See accompanying notes to condensed consolidated financial statements.

 

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DCP MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(Unaudited)

 

		Partners’ Equity
		Predecessor Equity				Common Unitholders				Class D Unitholders				Subordinated Unitholders				General Partner Unitholders				Accumulated Other Comprehensive (Loss) Income				Noncontrolling Interests				Total Equity
		(Millions)
Balance, January 1, 2009		$	66.0			$	429.0			$	—			$	(54.6	)		$	(4.8	)		$	(40.5	)		$	167.7			$	562.8
Net change in parent advances			3.0				—								—				—				—				—				3.0
Conversion of subordinated units to common units			—				(52.1	)			—				52.1				—				—				—				—
Distributions to unitholders and general partner			—				(48.7	)			(2.1	)			(2.1	)			(9.9	)			—				—				(62.8	)
Distributions to noncontrolling interests			—				—				—				—				—				—				(15.4	)			(15.4	)
Contributions from DCP Midstream, LLC			—				0.7				—				—				—				—				—				0.7
Contributions from noncontrolling interests			—				—				—				—				—				—				71.8				71.8
Issuance of 3,500,000 Class D units			—				—				49.7				—				—				—				—				49.7
Conversion of Class D units to common units			—				66.8				(66.8	)			—				—				—				—				—
Acquisition of additional 25.1% interest in East Texas and the NGL Hedge			(68.0	)			—				4.6				—				—				—				—				(63.4	)
Deficit purchase price over acquired assets			—				—				19.0				—				—				—				—				19.0
Comprehensive income (loss):
Net loss attributable to predecessor operations			(1.0	)			—				—				—				—				—				—				(1.0	)
Net (loss) income			—				(19.3	)			(4.4	)			4.6				9.0				—				3.3				(6.8	)
Reclassification of cash flow hedges into earnings			—				—				—				—				—				14.6				—				14.6
Net unrealized gains on cash flow hedges			—				—				—				—				—				(8.0	)			—				(8.0	)
Total comprehensive (loss) income			(1.0	)			(19.3	)			(4.4	)			4.6				9.0				6.6				3.3				(1.2	)
Balance, September 30, 2009		$	—			$	376.4			$	—			$	—			$	(5.7	)		$	(33.9	)		$	227.4			$	564.2

See accompanying notes to condensed consolidated financial statements.

 

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Description of Business and Basis of Presentation

DCP Midstream Partners, LP, with its consolidated subsidiaries, or us, we or our, is engaged in the business of gathering, compressing, treating, processing, transporting, storing and selling natural gas; producing, transporting, storing and selling propane; and producing, transporting and selling NGLs and condensate.

We are a Delaware limited partnership that was formed in August 2005. We completed our initial public offering on December 7, 2005. Our partnership includes: our Northern Louisiana system; our Southern Oklahoma system; our 40% limited liability company interest in Discovery Producer Services LLC, or Discovery; our Wyoming system; a 75% interest in our Colorado system (of which 5% was acquired in February 2010); our 50.1% interest in our East Texas system (of which 25.1% was acquired in April 2009); our Michigan systems (of which certain assets were acquired in November 2009); our wholesale propane logistics business (which includes Atlantic Energy, acquired in July 2010); and our NGL transportation pipelines (including the Wattenberg pipeline acquired in January 2010 and our 100% interest in the Black Lake Pipeline Company, or Black Lake, 55% of which was acquired in July 2010, comprised of a 5% interest acquired from DCP Midstream, LLC, in a transaction among entities under common control, and an additional 50% interest acquired from an affiliate of BP PLC).

Our operations and activities are managed by our general partner, DCP Midstream GP, LP, which in turn is managed by its general partner, DCP Midstream GP, LLC, which we refer to as the General Partner, and is wholly-owned by DCP Midstream, LLC. DCP Midstream, LLC and its subsidiaries and affiliates, collectively referred to as DCP Midstream, LLC, is owned 50% by Spectra Energy Corp, or Spectra Energy, and 50% by ConocoPhillips. DCP Midstream, LLC directs our business operations through its ownership and control of the General Partner. DCP Midstream, LLC and its affiliates’ employees provide administrative support to us and operate our assets. DCP Midstream, LLC owns approximately 32% of us.

The condensed consolidated financial statements include the accounts of the Partnership and all majority-owned subsidiaries where we have the ability to exercise control and undivided interests in jointly owned assets. Investments in greater than 20% owned affiliates that are not variable interest entities and where we do not have the ability to exercise control, and investments in less than 20% owned affiliates where we have the ability to exercise significant influence, are accounted for using the equity method. Intercompany balances and transactions have been eliminated.

The condensed consolidated financial statements include our accounts, which have been combined with the historical assets, liabilities and operations of our predecessor operations. We refer to the assets, liabilities and operations of DCP East Texas Holdings, LLC, or East Texas, prior to our acquisition of an additional 25.1% limited liability company interest from DCP Midstream, LLC in April 2009, and of Black Lake, prior to our acquisition of an additional 5% limited liability company interest from DCP Midstream, LLC in July 2010, collectively as our “predecessor.” Prior to our acquisition of an additional 25.1% limited liability company interest in East Texas, we owned a 25.0% limited liability company interest in East Texas which we accounted for under the equity method of accounting. Subsequent to this transaction we own a 50.1% limited liability company interest in East Texas, and account for East Texas as a consolidated subsidiary. Because the additional interest in East Texas and Black Lake were acquired from DCP Midstream, LLC, these transactions were considered to be among entities under common control. We recognize transfers of net assets between entities under common control at DCP Midstream, LLC’s basis in the net assets contributed. In addition, transfers of net assets between entities under common control are accounted for as if the transfer occurred at the beginning of the period, and prior years are retroactively adjusted to furnish comparative information similar to the pooling method; accordingly our financial information includes the historical results of our additional 25.1% interest in East Texas and our additional 5% interest in Black Lake for all periods presented. The amount of the purchase price in excess, or in deficit of DCP Midstream, LLC’s basis in the net assets, if any, is recognized as a reduction to, or an increase to partners’ equity, respectively. In addition, the results of operations of our Michigan systems, our Wattenberg pipeline, our additional 50% interest in Black Lake, and our acquisition of Atlantic Energy have been included in the condensed consolidated financial statements since their respective acquisition dates.

The condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP. Conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and notes. Although these estimates are based on management’s best available knowledge of current and expected future events, actual results could differ from those estimates. The condensed consolidated financial statements of our predecessor have been prepared from the separate records maintained by DCP Midstream, LLC and may not necessarily be indicative of the conditions that would have existed or the results of operations if our predecessor had been operated as an unaffiliated entity. All intercompany balances and transactions have been eliminated. Transactions between us and other DCP Midstream, LLC operations have been identified in the consolidated financial statements as transactions between affiliates.

 

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

 

The accompanying unaudited condensed consolidated financial statements in this Quarterly Report on Form 10-Q have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission, or SEC. Accordingly, these condensed consolidated financial statements reflect all normal recurring adjustments that are, in the opinion of management, necessary to present fairly the financial position and results of operations for the respective interim periods. Certain information and notes normally included in our annual financial statements have been condensed or omitted from these interim financial statements pursuant to such rules and regulations. Results of operations for the three and nine months ended September 30, 2010, are not necessarily indicative of the results that may be expected for the year ending December 31, 2010. These condensed consolidated financial statements and other information included in this Quarterly Report on Form 10-Q should be read in conjunction with the consolidated financial statements and notes thereto included in our 2009 Form 10-K.

Certain amounts in the prior period condensed consolidated financial statements have been reclassified to the current period presentation.

2. Recent Accounting Pronouncements

Financial Accounting Standards Board, or FASB, Accounting Standards Update, or ASU, 2010-06 “Fair Value Measurements and Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements,” or ASU 2010-06 — In January 2010, the FASB issued ASU 2010-06 which amended the Accounting Standards Codification, or ASC, Topic 820-10 “Fair Value Measurement and Disclosures—Overall.” ASU 2010-06 requires new disclosures regarding transfers in and out of assets and liabilities measured at fair value classified within the valuation hierarchy as either Level 1 or Level 2 and information about sales, issuances and settlements on a gross basis for assets and liabilities classified as Level 3. ASU 2010-06 clarifies existing disclosures on the level of disaggregation required and inputs and valuation techniques. The provisions of ASU 2010-06 became effective for us on January 1, 2010, except for disclosure of information about sales, issuances and settlements on a gross basis for assets and liabilities classified as Level 3, which is effective for us on January 1, 2011. The provisions of ASU 2010-06 impact only disclosures and we have disclosed information in accordance with the revised provisions of ASU 2010-06 within this filing.

ASU 2009-17 “Consolidation (Topic 810): Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities,” or ASU 2009-17 — In December 2009, the FASB issued ASU 2009-17 which amended ASC Topic 810 “Consolidation.” ASU 2009-17 requires entities to perform additional analysis of their variable interest entities and consolidation methods. This ASU became effective for us on January 1, 2010 and upon adoption we did not change our conclusions on which entities we consolidate in our condensed consolidated financial statements.

ASU 2009-13 “Revenue Recognition (Topic 605) Multiple-Deliverable Revenue Arrangements,” or ASU 2009-13 — In October 2009, the FASB issued ASU 2009-13 which amended ASC Topic 605 “Revenue Recognition.” The ASU addresses the accounting for multiple-deliverable arrangements, to enable vendors to account for products or services separately rather than as a combined unit. ASU 2009-13 is effective for us on January 1, 2011 and we are in the process of assessing the impact of ASU 2009-13 on our condensed consolidated results of operations, cash flows and financial position as a result of adoption.

3. Acquisitions

Gathering, Compression, Transportation, and Processing Assets

On July 30, 2010, we acquired Atlantic Energy, a wholly owned subsidiary of UGI Corporation, for $49.0 million plus propane inventory and other working capital of $17.3 million. We have incurred additional post-closing purchase price adjustments for net working capital of $1.9 million, which we have accrued in other current liabilities in our condensed consolidated balance sheet as of September 30, 2010. Atlantic Energy has a contractual agreement with Spectra Energy, the supplier of the acquired propane inventory, in which the final price of the acquired inventory will be determined based upon index rates at established future dates. Atlantic Energy’s sales agreements specify floating pricing terms in excess of the floating pricing terms established in the contractual agreement with Spectra. The acquisition was financed at closing with borrowings under our revolving credit facility. Atlantic Energy owns and operates a marine import terminal with 20 million gallons of above ground storage in the Port of Chesapeake, Virginia. The assets serve as a supply point for propane customers in the mid-Atlantic region, and will extend our existing northeast U.S. wholesale propane business into the mid-Atlantic. The results of Atlantic Energy’s assets are included prospectively from the date of acquisition in our Wholesale Propane Logistics segment.

 

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

 

The purchase price allocation is preliminary and is based on initial estimates of fair values at the date of the acquisition. We will continue to evaluate the initial purchase price allocation, which may be adjusted as additional information relative to the fair value of assets and liabilities becomes available. The preliminary purchase price allocation is as follows:

 

		(Millions)
Cash consideration		$	66.3
Payable to a subsidiary of UGI corporation			1.9
Aggregate consideration		$	68.2
Cash		$	0.4
Accounts receivable			2.1
Inventory			16.6
Property, plant and equipment			15.2
Intangible assets			27.2
Goodwill			7.6
Other liabilities			(0.9	)
Total preliminary purchase price allocation		$	68.2

On July 27, 2010, we acquired an additional 5% interest in Black Lake from DCP Midstream, LLC, in a transaction among entities under common control, for $1.5 million in cash, financed at closing with borrowings under our revolving credit facility. This transaction brought our ownership interest in Black Lake to 50%. The historical carrying value of DCP Midstream, LLC’s 5% interest in Black Lake was $0.7 million; accordingly we have recorded the $0.8 million excess purchase price over acquired assets as a decrease in common unitholders equity.

On July 30, 2010, we acquired an additional 50% interest in Black Lake from an affiliate of BP PLC, for $15.1 million in cash, financed at closing with borrowings under our revolving credit facility, bringing our ownership interest in Black Lake to 100%. Prior to our acquisition of an additional 50% interest in Black Lake, we accounted for Black Lake under the equity method of accounting. Subsequent to this transaction we account for Black Lake as a consolidated subsidiary. As a result of acquiring an additional 50% interest in Black Lake, we have remeasured our initial 50% interest in Black Lake to its fair value. Accordingly we recognized a gain of $9.1 million in step acquisition — equity interest re-measurement gain in our condensed consolidated statements of operations for the three and nine months ended September 30, 2010, which reflects the increase from the net assets historical carrying value, to the net assets fair value for our initial 50% interest. We have evaluated certain pre-acquisition contingencies arising from potential environmental issues that existed as of the acquisition date. We have determined that certain of these pre-acquisition contingencies are probable in nature and estimable as of the acquisition date and, accordingly, have recorded $0.9 million for these contingencies as a part of the purchase price allocation for Black Lake.

The results of our additional 50% interest in Black Lake are included prospectively from the date of acquisition in our NGL Logistics segment. Our calculation of the step acquisition — equity interest re-measurement gain is as follows:

 

		(Millions)
Fair value of 50% equity interest in Black Lake		$	15.1
Less: Carrying value of 50% equity interest in Black Lake			6.0
Step acquisition — equity interest re-measurement gain		$	9.1

 

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

 

The purchase price is preliminary and is based on initial estimates of fair values at the date of the acquisition. We will continue to evaluate the initial purchase price allocation, which may be adjusted as additional information relative to the fair value of assets and liabilities becomes available. The preliminary purchase price allocation is as follows:

 

		(Millions)
Cash consideration		$	15.1
Cash		$	0.8
Accounts receivable			0.6
Property, plant and equipment			27.4
Intangible assets			2.7
Other asset			0.3
Other liabilities			(1.6	)
Fair value of 100% interest in Black Lake			30.2
Less:
Carrying value of initial 50% equity interest in Black Lake			(6.0	)
Step acquisition — equity interest re-measurement gain			(9.1	)
Total preliminary purchase price allocation		$	15.1

On February 3, 2010, we acquired an additional 5% interest in Collbran Valley Gas Gathering LLC, or Collbran, from Delta Petroleum Company, or Delta, for $3.5 million in cash, bringing our total ownership in Collbran to 75%. In addition, as part of this transaction we paid Delta’s unpaid capital calls to Collbran of $2.4 million. We may pay an additional $2.0 million of contingent consideration to Delta depending on if Delta meets certain throughput volume thresholds by June 30, 2011, pursuant to a gathering agreement. As of March 31, 2010 we recognized the fair value of this contingent consideration of approximately $1.0 million, which we recorded to other current liabilities in our condensed consolidated balance sheet. Accordingly, we recognized a $5.5 million reduction in noncontrolling interest in equity, which represents the carrying value of Delta’s 5% interest in Collbran, and an increase of $1.0 million to common unitholders in equity, which represented the difference between the fair value of the consideration and the carrying value of Delta’s 5% interest. As of June 30, 2010, we reassessed the fair value of the contingent consideration and adjusted the fair value of the liability to approximately $0.5 million. As of September 30, 2010, we reassessed the fair value of the contingent consideration and adjusted the fair value of the liability to $0. Accordingly, we recognized $0.5 million and $1.0 million in other income in our condensed consolidated results of operations during the three and nine months ended September 30, 2010, respectively.

On January 28, 2010, we acquired an interstate natural gas liquids pipeline, or the Wattenberg pipeline, from Buckeye Partners, L.P., or Buckeye, for $22.0 million in cash, funded at closing with borrowings under our revolving credit facility. This transaction was accounted for as a business combination. The 350-mile pipeline originates in the Denver-Julesburg, or DJ Basin, in Colorado and terminates near the Conway hub in Bushton, Kansas. The pipeline is currently utilized by DCP Midstream, LLC as a market outlet for NGL production from certain of their plants in the DJ Basin. The results of the asset are included in our NGL Logistics segment prospectively, from the date of acquisition. The purchase price was allocated to property, plant and equipment.

 

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

 

Combined Financial Information

The following tables present the total operating revenues and net income attributable to partners, associated with the acquisition of the Wattenberg pipeline, Atlantic Energy, and an additional 50% interest in Black Lake, or the acquired assets, from their respective dates of acquisition through September 30, 2010. These amounts have been included in the condensed consolidated statement of operations.

 

		Three Months Ended September 30, 2010
		Wattenberg Pipeline				Atlantic Energy				Additional 50% interest in Black Lake				Total
		(Millions)
Total operating revenues		$	1.8			$	8.8			$	1.1			$	11.7
Net income (loss) attributable to partners		$	1.2			$	(0.3	)		$	0.2			$	1.1
		Nine Months Ended September 30, 2010
		Wattenberg Pipeline				Atlantic Energy				Additional 50% interest in Black Lake				Total
		(Millions)
Total operating revenues		$	3.3			$	8.8			$	1.1			$	13.2
Net income (loss) attributable to partners		$	1.5			$	(0.3	)		$	0.2			$	1.4

The following tables present unaudited pro forma information for the condensed consolidated statements of operations for the three and nine months ended September 30, 2010 and 2009, as if the acquisition of the acquired assets had occurred at the beginning of each period presented.

 

		Three Months Ended September 30, 2010
		DCP Midstream Partners, LP				Acquisition of the Wattenberg Pipeline				Acquisition of Atlantic Energy				Acquisition of an additional 50% interest in Black Lake				DCP Midstream Partners, LP Pro Forma
		(Millions, except per unit amounts)
Total operating revenues		$	239.9			$	—			$	3.2			$	0.6			$	243.7
Net loss attributable to partners		$	(4.1	)		$	—			$	(0.2	)		$	(0.1	)		$	(4.4	)
Less:
General partner unitholders interest in net income or loss			(4.1	)			—				—				—				(4.1	)
Net loss allocable to limited partners		$	(8.2	)		$	—			$	(0.2	)		$	(0.1	)		$	(8.5	)
Net loss per limited partner unit — basic and diluted		$	(0.23	)		$	—			$	(0.01	)		$	—			$	(0.24	)

 

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

 

		Three Months Ended September 30, 2009
		DCP Midstream Partners, LP				Acquisition of the Wattenberg Pipeline				Acquisition of Atlantic Energy				Acquisition of an additional 50% interest in Black Lake				DCP Midstream Partners, LP Pro Forma
		(Millions, except per unit amounts)
Total operating revenues		$	205.7			$	1.7			$	9.9			$	1.9			$	219.2
Net income (loss) attributable to partners		$	9.9			$	1.0			$	(0.6	)		$	0.4			$	10.7
Less:
General partner unitholders interest in net income or loss			(3.4	)			—				—				—				(3.4	)
Net income (loss) allocable to limited partners		$	6.5			$	1.0			$	(0.6	)		$	0.4			$	7.3
Net income (loss) per limited partner unit — basic and diluted		$	0.21			$	0.03			$	(0.02	)		$	0.01			$	0.23
		Nine Months Ended September 30, 2010
		DCP Midstream Partners, LP				Acquisition of the Wattenberg Pipeline				Acquisition of Atlantic Energy				Acquisition of an additional 50% interest in Black Lake				DCP Midstream Partners, LP Pro Forma
		(Millions, except per unit amounts)
Total operating revenues		$	921.1			$	0.2			$	64.5			$	4.1			$	989.9
Net income attributable to partners		$	47.7			$	0.1			$	1.1			$	0.6			$	49.5
Less:
General partner unitholders interest in net income or loss			(12.1	)			—				—				—				(12.1	)
Net income allocable to limited partners		$	35.6			$	0.1			$	1.1			$	0.6			$	37.4
Net income per limited partner unit — basic and diluted		$	1.01			$	—			$	0.03			$	0.02			$	1.06

 

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

 

		Nine Months Ended September 30, 2009
		DCP Midstream Partners, LP				Acquisition of the Wattenberg Pipeline (a)				Acquisition of Atlantic Energy				Acquisition of an additional 50% interest in Black Lake				DCP Midstream Partners, LP Pro Forma
		(Millions, except per unit amounts)
Total operating revenues		$	642.1			$	8.2			$	41.2			$	5.0			$	696.5
Net (loss) income attributable to partners		$	(11.1	)		$	(67.6	)		$	0.1			$	1.2			$	(77.4	)
Less:
Net loss attributable to predecessor operations			1.0				—				—				—				1.0
General partner unitholders interest in net income or loss			(9.3	)			(0.8	)			—				—				(10.1	)
Net (loss) income allocable to limited partners		$	(19.4	)		$	(68.4	)		$	0.1			$	1.2			$	(86.5	)
Net (loss) income per limited partner unit — basic and diluted		$	(0.63	)		$	(2.24	)		$	—			$	0.04			$	(2.83	)

 

(a)

During the second quarter of 2009, prior to our ownership, Buckeye received notification that several of its shippers on the Wattenberg pipeline intended to migrate to a competing pipeline that had recently been put into service. The notification by the shippers was accompanied by a significant decline in shipment volumes as compared to historical averages. As a result Buckeye recognized an impairment charge of $72.5 million in relation to the Wattenberg pipeline.

The pro forma information is not intended to reflect actual results that would have occurred if the assets had been combined during the periods presented, nor is it intended to be indicative of the results of operations that may be achieved by us in the future.

4. Agreements and Transactions with Affiliates

DCP Midstream, LLC

Omnibus Agreement and Other General and Administrative Charges

We have entered into an omnibus agreement, as amended, or the Omnibus Agreement, with DCP Midstream, LLC. Under the Omnibus Agreement, we are required to reimburse DCP Midstream, LLC for certain costs incurred and centralized corporate functions performed by DCP Midstream, LLC on our behalf. We incurred $2.5 million for three months ended September 30, 2010 and $2.5 million for the three months ended September 30, 2009, and $7.4 million and $7.3 million for the nine months ended September 30, 2010 and 2009, for all fees under the Omnibus Agreement.

East Texas incurs general and administrative expenses directly from DCP Midstream, LLC. East Texas incurred $2.0 million for each of the three months ended September 30, 2010 and 2009 and $5.9 million and $6.4 million for the nine months ended September 30, 2010 and 2009, respectively, for general and administrative expenses from DCP Midstream, LLC, which includes expenses for our predecessor operations.

In addition to the Omnibus Agreement and amounts incurred by East Texas, we incurred other fees with DCP Midstream, LLC of $0.3 million and $0.4 million for the three months ended September 30, 2010 and 2009, respectively and $1.1 million and $1.6 million for the nine months ended September 30, 2010 and 2009, respectively. These amounts include allocated expenses, including professional services, insurance and internal audit.

 

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

 

Other Agreements and Transactions with DCP Midstream, LLC

On September 16, 2010, we entered into an agreement with DCP Midstream, LLC to sell certain surplus equipment with a net book value of $6.3 million, for net proceeds of $3.6 million. The surplus equipment is the result of a consolidation of operations at our Anderson Gulch plant in Collbran. The net proceeds of $3.6 million have been distributed 75% to us and 25% to the noncontrolling interest in Collbran, based upon proportionate ownership. The title to the surplus equipment will pass to DCP Midstream, LLC upon removal of the equipment from our premises. As of September 30, 2010, the surplus equipment has been reclassified from property, plant and equipment, to current assets and classified as assets held for sale in our condensed consolidated balance sheets. In addition, we have recorded a deferred credit of $3.6 million in other current liabilities in our condensed consolidated balance sheets.

On June 30, 2010, we entered into an agreement with DCP Midstream, LLC to sell certain surplus equipment with a net book value of $1.6 million, for net proceeds of $2.2 million. The surplus equipment is the result of our integration efforts and synergies realized following our acquisition of certain companies that held natural gas gathering and treating assets from MichCon Pipeline Company in November 2009. The title to the surplus equipment will pass to DCP Midstream, LLC upon removal of the equipment from our premises. As of September 30, 2010, the surplus equipment has been reclassified from property, plant and equipment, to current assets and classified as assets held for sale in our condensed consolidated balance sheets. In addition, we have recorded a deferred credit of $2.2 million in other current liabilities in our condensed consolidated balance sheets.

In conjunction with our acquisition of a 50.1% limited liability company interest in East Texas from DCP Midstream, LLC, we entered into agreements with DCP Midstream, LLC whereby DCP Midstream, LLC will reimburse East Texas for certain expenditures on East Texas capital projects, as defined in the Contribution Agreements. These reimbursements are for certain capital projects which have commenced within three years from the respective acquisition dates. DCP Midstream, LLC made capital contributions to East Texas for capital projects of $10.4 million and $62.4 million for the nine months ended September 30, 2010 and 2009, respectively.

On February 11, 2009, our East Texas natural gas processing complex and natural gas delivery system known as the Carthage Hub, was temporarily shut in following a fire that was caused by a third party underground pipeline outside of our property line that ruptured. We are actively pursuing full reimbursement of our costs and lost margin associated with the incident from the responsible third party and East Texas filed a lawsuit in December 2009, to recover damages from the responsible third party. In the event we are unable to recover our costs and lost margin from the responsible third party, we have insurance covering property damage, net of applicable deductibles. Following this incident, DCP Midstream, LLC has agreed to reimburse to us twenty-five percent of any claims received as reimbursement of costs and lost margin, from the responsible third party or from insurance. DCP Midstream, LLC will pay seventy-five percent of costs related to the incident as a result of this agreement.

We sell a portion of our residue gas, NGLs and condensate to, purchase natural gas and other petroleum products from, and provide gathering and transportation services for, DCP Midstream, LLC. We anticipate continuing to purchase from and sell commodities to DCP Midstream, LLC in the ordinary course of business. In addition, DCP Midstream, LLC conducts derivative activities on our behalf.

DCP Midstream, LLC owns certain assets and is party to certain contractual relationships around our Pelico system, included in our Northern Louisiana system, which is part of our Natural Gas Services segment, that are periodically used for the benefit of Pelico. DCP Midstream, LLC is able to source natural gas upstream of Pelico and deliver it to us and is able to take natural gas from the outlet of the Pelico system and market it downstream of Pelico. We purchase natural gas from DCP Midstream, LLC upstream of Pelico and transport it to Pelico under a firm transportation agreement with an affiliate. Our purchases from DCP Midstream, LLC are at DCP Midstream, LLC’s actual acquisition cost plus any transportation service charges. Volumes that exceed our on-system demand and volumes supplying an industrial end user are sold to DCP Midstream, LLC at an index-based price, less contractually agreed to marketing fees. Revenues associated with these activities are reported gross in our condensed consolidated statements of operations as sales of natural gas, propane, NGLs and condensate to affiliates.

In April 2009, we entered into a thirteen year contractual arrangement with DCP Midstream, LLC in which we pay DCP Midstream, LLC a fee for processing services associated with the gas we gather on our Southern Oklahoma system, which is part of our Natural Gas Services segment. In addition, in February 2010, a contract was signed with DCP Midstream, LLC providing for adjustments to those fees based upon plant efficiencies related to our portion of volumes from our Southern Oklahoma system being processed at DCP Midstream, LLC’s plant through March 2022. We generally report fees associated with these activities in the condensed consolidated statements of operations as purchases of natural gas, propane, NGLs and condensate from affiliates. In addition, as part of this arrangement, DCP Midstream, LLC pays us a fee for certain gathering services. We generally report revenues associated with these activities in the condensed consolidated statements of operations as transportation, processing and other to affiliates.

 

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

 

In our NGL Logistics segment, we also have a contractual arrangement with a subsidiary of DCP Midstream, LLC that provides that DCP Midstream, LLC will pay us to transport NGLs over our Seabreeze and Wilbreeze pipelines, pursuant to fee-based rates that will be applied to the volumes transported. DCP Midstream, LLC is the sole shipper on these pipelines under the transportation agreements. We generally report revenues associated with these activities in the condensed consolidated statements of operations as transportation, processing and other to affiliates.

In conjunction with our acquisition of the Wattenberg pipeline, which is part of our NGL Logistics segment, we signed a transportation agreement with DCP Midstream, LLC pursuant to fee-based rates that will be applied to the volumes transported. The agreement is effective through November 2010, renewing on an evergreen basis thereafter. We generally report revenues associated with these activities in the condensed consolidated statements of operations as transportation, processing and other to affiliates.

DCP Midstream, LLC has issued parental guarantees, totaling $98.0 million as of September 30, 2010, in favor of certain counterparties to our commodity derivative instruments to mitigate a portion of our collateral requirements with those counterparties. We pay DCP Midstream, LLC interest of 0.5% per annum on $55.0 million of these outstanding guarantees.

DCP Midstream, LLC has issued parental guarantees for its 49.9% limited liability company interest in East Texas, totaling $5.5 million as of September 30, 2010, in favor of certain counterparties to processing and transportation agreements at East Texas. Concurrently, we have issued similar guarantees for our 50.1% interest.

DCP Midstream, LLC was a significant customer during the three and nine months ended September 30, 2010 and 2009.

Spectra Energy

We have a propane supply agreement with Spectra Energy, effective from May 1, 2008 through April 30, 2012, which provides us propane supply at our Providence marine terminal, which is included in our Wholesale Propane Logistics segment, for up to approximately 120 million gallons of propane annually. On June 15, 2010, we entered into an amendment to the supply agreement to shorten the term of the agreement by two years to April 30, 2012, which previously terminated on April 30, 2014. In consideration for shortening the term, Spectra Energy provided us with a cash payment of $3.0 million, which we recognized in other income — affiliates, in our Wholesale Propane Logistics segment, in the condensed consolidated statements of operations.

In conjunction with our acquisition of Atlantic Energy on July 30, 2010, we acquired a propane supply agreement with Spectra Energy, effective from May 1, 2010 to April 30, 2012, which provides us propane supply for our Chesapeake marine terminal, which is included in our Wholesale Propane Logistics segment, for up to approximately 65 million gallons of propane annually.

ConocoPhillips

We have multiple agreements with ConocoPhillips and its affiliates. The agreements include fee-based and percent-of-proceeds gathering and processing arrangements, and gas purchase and gas sales agreements. We anticipate continuing to purchase from and sell these commodities to ConocoPhillips and its affiliates in the ordinary course of business. In addition, we may be reimbursed by ConocoPhillips for certain capital projects where the work is performed by us. We received $0.2 million and $0.7 million of capital reimbursements during the nine months ended September 30, 2010 and 2009, respectively.

 

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

 

Summary of Transactions with Affiliates

The following table summarizes transactions with affiliates:

 

		Three Months  Ended September 30,								Nine Months  Ended September 30,
		2010				2009				2010				2009
		(Millions)
DCP Midstream, LLC:
Sales of natural gas, propane, NGLs and condensate		$	124.5			$	110.1			$	390.0			$	311.2
Transportation, processing and other		$	3.5			$	2.0			$	10.0			$	4.6
Purchases of natural gas, propane and NGLs		$	35.3			$	21.3			$	121.8			$	83.7
Losses from commodity derivative activity, net		$	(0.7	)		$	(1.0	)		$	(1.0	)		$	(3.6	)
General and administrative expense		$	4.8			$	4.9			$	14.4			$	15.3
Interest expense		$	—			$	0.1			$	0.2			$	0.2
Spectra Energy:
Transportation, processing and other		$	—			$	—			$	0.2			$	0.2
Purchases of natural gas, propane and NGLs		$	8.0			$	14.2			$	84.4			$	62.3
Other income		$	—			$	—			$	3.0			$	—
ConocoPhillips:
Sales of natural gas, propane, NGLs and condensate		$	0.4			$	2.4			$	4.7			$	3.1
Transportation, processing and other		$	2.1			$	2.0			$	6.0			$	6.3
Purchases of natural gas, propane and NGLs		$	1.7			$	3.4			$	5.3			$	9.3
General and administrative expense		$	0.1			$	0.1			$	0.2			$	0.2
Unconsolidated affiliates:
Purchases of natural gas, propane and NGLs		$	—			$	—			$	2.4			$	0.4

 

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

 

We had balances with affiliates as follows:

 

		September 30, 2010				December 31, 2009
		(Millions)
DCP Midstream, LLC:
Accounts receivable		$	53.8			$	71.5
Accounts payable		$	25.4			$	24.4
Other current liabilities		$	5.8			$	—
Unrealized gains on derivative instruments — current		$	0.7			$	5.5
Unrealized losses on derivative instruments — current		$	(1.2	)		$	(5.4	)
Spectra Energy:
Accounts receivable		$	0.1			$	0.1
Accounts payable		$	1.7			$	16.6
ConocoPhillips:
Accounts receivable		$	1.2			$	2.2
Accounts payable		$	0.5			$	2.1

5. Property, Plant and Equipment

A summary of property, plant and equipment by classification is as follows:

 

		Depreciable Life				September 30, 2010				December 31, 2009
						(Millions)
Gathering systems			15 — 30 Years			$	690.1			$	683.0
Processing plants			25 — 30 Years				423.4				427.4
Terminals			25 — 30 Years				44.2				28.9
Transportation			25 — 30 Years				266.4				217.2
General plant			3 — 5 Years				15.3				15.2
Other			20 — 50 Years				0.1				0.1
Construction work in progress							49.5				21.8
Property, plant and equipment							1,489.0				1,393.6
Accumulated depreciation							(446.5	)			(393.5	)
Property, plant and equipment, net						$	1,042.5			$	1,000.1

Interest capitalized on construction projects for the nine months ended September 30, 2010 was $0 and for the year ended December 31, 2009 was $1.3 million.

Depreciation expense was $18.0 million and $15.7 million for the three months ended September 30, 2010 and 2009, respectively and $53.0 million and $45.4 million for the nine months ended September 30, 2010 and 2009, respectively.

 

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

 

6. Goodwill and Intangible Assets

The change in the carrying amount of goodwill is as follows:

 

		September 30, 2010				December 31, 2009
		(Millions)
Beginning of period		$	92.1			$	88.8
Acquisitions			7.6				3.3
End of period		$	99.7			$	92.1

The carrying value of goodwill as of September 30, 2010 and December 31, 2009 was $62.8 million for our Natural Gas Services segment, and $36.9 million and $29.3 million, respectively, for our Wholesale Propane Logistics segment.

We performed our annual goodwill assessment during the quarter and concluded that the entire amount of goodwill on the balance sheet is recoverable. We used a discounted cash flow analysis supported by market valuation multiples to perform the assessment. Key assumptions in the analysis include the use of an appropriate discount rate, estimated future cash flows and an estimated run rate of operating and general and administrative costs. In estimating cash flows, we incorporate current market information, as well as historical and other factors, into our forecasted commodity prices. Our annual goodwill impairment tests indicated that our reporting units’ fair value exceeded the carrying or book value. If actual results are not consistent with our assumptions and estimates, or our assumptions and estimates change due to new information, we may be exposed to goodwill impairment charges, which would be recognized in the period in which the carrying value exceeds fair value.

Intangible assets consist of customer contracts, including commodity purchase, transportation and processing contracts, and related relationships. The gross carrying amount and accumulated amortization of these intangible assets are included in the accompanying consolidated balance sheets as intangible assets, net, and are as follows:

 

		September 30, 2010				December 31, 2009
		(Millions)
Gross carrying amount		$	96.1			$	66.2
Accumulated amortization			(8.5	)			(5.7	)
Intangible assets, net		$	87.6			$	60.5

For the three and nine months ended September 30, 2010, we recorded amortization expense of $1.2 million and $2.7 million, respectively. For the three and nine months ended September 30, 2009, we recorded amortization expense of $0.7 million and $1.9 million respectively. As of September 30, 2010, the remaining amortization periods ranged from approximately 12 years to 24 years, with a weighted-average remaining period of approximately 18 years.

The weighted-average remaining amortization for both the $27.2 million of intangible assets acquired with our acquisition of Atlantic Energy on July 30, 2010, and the $2.7 million of intangible assets acquired with our acquisition of an additional 50% interest in Black Lake on July 30, 2010, is 15 years.

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

 

Estimated future amortization for these intangible assets is as follows:

 

Estimated Future Amortization
(Millions)
2010 (remainder)		$	1.3
2011			5.2
2012			5.2
2013			5.2
2014			5.2
Thereafter			65.5
Total		$	87.6

7. Investments in Unconsolidated Affiliates

The following table summarizes our investments in unconsolidated affiliates:

 

		Percentage of Ownership as of September 30,  2010 and December 31, 2009				Carrying Value as of
						September 30, 2010				December 31, 2009
						(Millions)
Discovery Producer Services LLC			40%			$	103.4			$	108.2
Black Lake Pipe Line Company (a)			100% and 50%				N/A				6.2
Other			50%				0.2				0.2
Total investments in unconsolidated affiliates						$	103.6			$	114.6

 

(a)

On July 27, 2010 we acquired an additional 5% interest in Black Lake from DCP Midstream, LLC in a transaction among entities under common control, and on July 30, 2010, we acquired an additional 50% interest in Black Lake from an affiliate of BP PLC, bringing our ownership interest in Black Lake to 100%. Prior to our acquisition of an additional 50% interest in Black Lake, we accounted for Black Lake under the equity method of accounting. Subsequent to this transaction we account for Black Lake as a consolidated subsidiary.

There was a deficit between the carrying amount of the investment and the underlying equity of Discovery of $35.7 million and $37.6 million at September 30, 2010 and December 31, 2009, respectively, which is associated with, and is being accreted over, the life of the underlying long-lived assets of Discovery.

There was a deficit between the carrying amount of the investment and the underlying equity of Black Lake of $5.7 million at December 31, 2009, which was associated with, and was being accreted over, the life of the underlying long-lived assets of Black Lake.

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

 

Earnings from investments in unconsolidated affiliates were as follows:

 

		Three Months  Ended September 30,								Nine Months Ended September 30,
		2010				2009				2010				2009
		(Millions)
Discovery Producer Services LLC		$	4.1			$	7.9			$	17.8			$	9.7
Black Lake Pipe Line Company and other (a)			—				0.5				0.8				1.3
Total earnings from unconsolidated affiliates		$	4.1			$	8.4			$	18.6			$	11.0

 

(a)

On July 27, 2010 we acquired an additional 5% interest in Black Lake from DCP Midstream, LLC in a transaction among entities under common control, and on July 30, 2010, we acquired an additional 50% interest in Black Lake from an affiliate of BP PLC, bringing our ownership interest in Black Lake to 100%. Prior to our acquisition of an additional 50% interest in Black Lake, we accounted for Black Lake under the equity method of accounting. Subsequent to this transaction we account for Black Lake as a consolidated subsidiary.

The following summarizes financial information of our investments in unconsolidated affiliates:

 

		Three Months  Ended September 30,								Nine Months  Ended September 30,
		2010 (a)				2009				2010 (a)				2009
		(Millions)
Statements of operations:
Operating revenue		$	42.7			$	51.3			$	154.8			$	113.2
Operating expenses		$	34.2			$	32.4			$	113.6			$	91.2
Net income		$	8.5			$	19.0			$	41.2			$	21.9

 

(a)	Excludes the results of Black Lake from July 30, 2010.

 

		September 30, 2010 (a)				December 31, 2009
		(Millions)
Balance sheets:
Current assets		$	29.3			$	41.8
Long-term assets			358.7				383.8
Current liabilities			(14.8	)			(17.4	)
Long-term liabilities			(25.1	)			(23.6	)
Net assets		$	348.1			$	384.6

 

(a)

On July 27, 2010 we acquired an additional 5% interest in Black Lake from DCP Midstream, LLC in a transaction among entities under common control, and on July 30, 2010, we acquired an additional 50% interest in Black Lake from an affiliate of BP PLC, bringing our ownership interest in Black Lake to 100%. Prior to our acquisition of an additional 50% interest in Black Lake, we accounted for Black Lake under the equity method of accounting. Subsequent to this transaction we account for Black Lake as a consolidated subsidiary.

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

 

8. Fair Value Measurement

Determination of Fair Value

Below is a general description of our valuation methodologies for derivative financial assets and liabilities, as well as short-term and restricted investments, which are measured at fair value. Fair values are generally based upon quoted market prices, where available. If listed market prices or quotes are not available, we determine fair value based upon a market quote, adjusted by other market-based or independently sourced market data such as historical commodity volatilities, crude oil future yield curves, and/or counterparty specific considerations. These adjustments result in a fair value for each asset or liability under an “exit price” methodology, in line with how we believe a marketplace participant would value that asset or liability. These adjustments may include amounts to reflect counterparty credit quality, the effect of our own creditworthiness, the time value of money and/or the liquidity of the market.

 

•

Counterparty credit valuation adjustments are necessary when the market price of an instrument is not indicative of the fair value as a result of the credit quality of the counterparty. Generally, market quotes assume that all counterparties have near zero, or low, default rates and have equal credit quality. Therefore, an adjustment may be necessary to reflect the credit quality of a specific counterparty to determine the fair value of the instrument. We record counterparty credit valuation adjustments on all derivatives that are in a net asset position as of the measurement date in accordance with our established counterparty credit policy, which takes into account any collateral margin that a counterparty may have posted with us as well as any letters of credit that they have provided.

 

•

Entity valuation adjustments are necessary to reflect the effect of our own credit quality on the fair value of our net liability position with each counterparty. This adjustment takes into account any credit enhancements, such as collateral margin we may have posted with a counterparty, as well as any letters of credit that we have provided. The methodology to determine this adjustment is consistent with how we evaluate counterparty credit risk, taking into account our own credit rating, current credit spreads, as well as any change in such spreads since the last measurement date.

 

•

Liquidity valuation adjustments are necessary when we are not able to observe a recent market price for financial instruments that trade in less active markets for the fair value to reflect the cost of exiting the position. Exchange traded contracts are valued at market value without making any additional valuation adjustments and, therefore, no liquidity reserve is applied. For contracts other than exchange traded instruments, we mark our positions to the midpoint of the bid/ask spread, and record a liquidity reserve based upon our total net position. We believe that such practice results in the most reliable fair value measurement as viewed by a market participant.

We manage our derivative instruments on a portfolio basis and the valuation adjustments described above are calculated on this basis. We believe that the portfolio level approach represents the highest and best use for these assets as there are benefits inherent in naturally offsetting positions within the portfolio at any given time, and this approach is consistent with how a market participant would view and value the assets and liabilities. Although we take a portfolio approach to managing these assets/liabilities, in order to reflect the fair value of any one individual contract within the portfolio, we allocate all valuation adjustments down to the contract level, to the extent deemed necessary, based upon either the notional contract volume, or the contract value, whichever is more applicable.

The methods described above may produce a fair value calculation that may not be indicative of net realizable value or reflective of future fair values. While we believe that our valuation methods are appropriate and consistent with other market participants, we recognize that the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different estimate of fair value at the reporting date. We review our fair value policies on a regular basis taking into consideration changes in the marketplace and, if necessary, will adjust our policies accordingly. See Note 10 Risk Management and Hedging Activities.

Valuation Hierarchy

Our fair value measurements are grouped into a three-level valuation hierarchy. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date. The three levels are defined as follows.

 

•

Level 1 — inputs are unadjusted quoted prices for identical assets or liabilities in active markets.

 

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•

Level 2 — inputs include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.

 

•

Level 3 — inputs are unobservable and considered significant to the fair value measurement.

A financial instrument’s categorization within the hierarchy is based upon the input that requires the highest degree of judgment in the determination of the instrument’s fair value. Following is a description of the valuation methodologies used as well as the general classification of such instruments pursuant to the hierarchy.

Commodity Derivative Assets and Liabilities

We enter into a variety of derivative financial instruments, which may include over the counter, or OTC, instruments, such as natural gas, crude oil or NGL contracts.

Within our Natural Gas Services segment we typically use OTC derivative contracts in order to mitigate a portion of our exposure to natural gas, NGL and condensate price changes. We also may enter into natural gas derivatives to lock in margin around our storage and transportation assets. These instruments are generally classified as Level 2. Depending upon market conditions and our strategy, we may enter into OTC derivative positions with a significant time horizon to maturity, and market prices for these OTC derivatives may only be readily observable for a portion of the duration of the instrument. In order to calculate the fair value of these instruments, readily observable market information is utilized to the extent that it is available; however, in the event that readily observable market data is not available, we may interpolate or extrapolate based upon observable data. In instances where we utilize an interpolated or extrapolated value, and it is considered significant to the valuation of the contract as a whole, we would classify the instrument within Level 3.

Within our Wholesale Propane Logistics segment, we may enter into a variety of financial instruments to either secure sales or purchase prices, or capture a variety of market opportunities. Since financial instruments for NGLs tend to be counterparty and location specific, we primarily use the OTC derivative instrument markets, which are not as active and liquid as exchange traded instruments. Market quotes for such contracts may only be available for short dated positions (up to six months), and an active market itself may not exist beyond such time horizon. Contracts entered into with a relatively short time horizon for which prices are readily observable in the OTC market are generally classified within Level 2. Contracts with a longer time horizon, for which we internally generate a forward curve to value such instruments, are generally classified within Level 3. The internally generated curve may utilize a variety of assumptions including, but not limited to, historical and future expected relationship of NGL prices to crude oil prices, the knowledge of expected supply sources coming on line, expected weather trends within certain regions of the United States, and the future expected demand for NGLs.

Each instrument is assigned to a level within the hierarchy at the end of each financial quarter depending upon the extent to which the valuation inputs are observable. Generally, an instrument will move toward a level within the hierarchy that requires a lower degree of judgment as the time to maturity approaches, and as the markets in which the asset trades will likely become more liquid and prices more readily available in the market, thus reducing the need to rely upon our internally developed assumptions. However, the level of a given instrument may change, in either direction, depending upon market conditions and the availability of market observable data.

Interest Rate Derivative Assets and Liabilities

We use interest rate swap agreements as part of our overall capital strategy. These instruments effectively exchange a portion of our floating rate debt for fixed rate debt. The swaps are generally priced based upon a London Interbank Offered Rate, or LIBOR, instrument with similar duration, adjusted by the credit spread between our company and the LIBOR instrument. Given that a portion of the swap value is derived from the credit spread, which may be observed by comparing similar assets in the market, these instruments are classified within Level 2. Default risk on either side of the swap transaction is also considered in the valuation. We record counterparty credit and entity valuation adjustments in the valuation of our interest rate swaps; however, these reserves are not considered to be a significant input to the overall valuation.

 

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(Unaudited)

 

 

Short-Term and Restricted Investments

We are required to post collateral to secure the term loan portion of our credit facility, and may elect to invest a portion of our available cash and restricted investment balances in various financial instruments such as commercial paper and money market instruments. The money market instruments are generally priced at acquisition cost, plus accreted interest at the stated rate, which approximates fair value, without any additional adjustments. Given that there is no observable exchange traded market for identical money market securities, we have classified these instruments within Level 2. Investments in commercial paper are priced using a yield curve for similarly rated instruments, and are classified within Level 2. Restricted investments have been used as collateral to secure the term loan portion of our credit facility. As of September 30, 2010, we held no short-term or restricted investments, as a result of the term loan facility being fully repaid during the first quarter of 2010.

Nonfinancial Assets and Liabilities

We utilize fair value on a non-recurring basis to perform impairment tests as required on our property, plant and equipment, goodwill and intangible assets. Assets and liabilities acquired in business combinations are recorded at their fair value on the date of acquisition. The inputs used to determine such fair value are primarily based upon internally developed cash flow models and would generally be classified within Level 3, in the event that we were required to measure and record such assets at fair value within our consolidated financial statements. Additionally, we use fair value to determine the inception value of our asset retirement obligations. The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition, and would generally be classified within Level 3.

We utilize fair value on a recurring basis to measure our contingent consideration that is a result of certain acquisitions. The inputs used to determine such fair value are primarily based upon internally developed cash flow models and are classified within Level 3.

The following table presents the financial instruments carried at fair value as of September 30, 2010 and December 31, 2009, by consolidated balance sheet caption and by valuation hierarchy as described above:

 

		September 30, 2010																December 31, 2009
		Level 1				Level 2				Level 3				Total Carrying Value				Level 1				Level 2				Level 3				Total Carrying Value
		(Millions)
Current assets:
Short-term investments (a)		$	—			$	—			$	—			$	—			$	—			$	0.1			$	—			$	0.1
Commodity derivatives (b)		$	—			$	1.4			$	0.3			$	1.7			$	—			$	6.9			$	0.4			$	7.3
Long-term assets:
Restricted investments		$	—			$	—			$	—			$	—			$	—			$	10.0			$	—			$	10.0
Commodity derivatives (c)		$	—			$	0.6			$	0.7			$	1.3			$	—			$	1.8			$	0.2			$	2.0
Current liabilities (d):
Commodity derivatives		$	—			$	(15.8	)		$	—			$	(15.8	)		$	—			$	(20.3	)		$	(0.8	)		$	(21.1	)
Interest rate derivatives		$	—			$	(20.3	)		$	—			$	(20.3	)		$	—			$	(20.4	)		$	—			$	(20.4	)
Long-term liabilities (e):
Commodity derivatives		$	—			$	(33.5	)		$	—			$	(33.5	)		$	—			$	(46.0	)		$	(0.4	)		$	(46.4	)
Interest rate derivatives		$	—			$	(13.3	)		$	—			$	(13.3	)		$	—			$	(11.6	)		$	—			$	(11.6	)

 

(a)	Included in other current assets in our condensed consolidated balance sheets.

(b)	Included in current unrealized gains on derivative instruments in our condensed consolidated balance sheets.

(c)	Included in long-term unrealized gains on derivative instruments in our condensed consolidated balance sheets.

(d)	Included in current unrealized losses on derivative instruments in our condensed consolidated balance sheets.

(e)	Included in long-term unrealized losses on derivative instruments in our condensed consolidated balance sheets.

 

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

 

Changes in Level 3 Fair Value Measurements

The tables below illustrate a rollforward of the amounts included in our condensed consolidated balance sheets for derivative financial instruments that we have classified within Level 3. The determination to classify a financial instrument within Level 3 is based upon the significance of the unobservable factors used in determining the overall fair value of the instrument. Since financial instruments classified as Level 3 typically include a combination of observable components (that is, components that are actively quoted and can be validated to external sources) and unobservable components, the gains and losses in the table below may include changes in fair value due in part to observable market factors, or changes to our assumptions on the unobservable components. Depending upon the information readily observable in the market, and/or the use of unobservable inputs, which are significant to the overall valuation, the classification of any individual financial instrument may differ from one measurement date to the next. In the event that there were movements to/from the classification of an instrument as Level 3, we would reflect such items in the table below within the “Transfers into Level 3” and “Transfers out of Level 3” captions.

We manage our overall risk at the portfolio level, and in the execution of our strategy, we may use a combination of financial instruments, which may be classified within any level. Since Level 1 and Level 2 risk management instruments are not included in the rollforward below, the gains or losses in the table do not reflect the effect of our total risk management activities.

 

		Commodity Derivative Instruments
		Current Assets				Long-Term Assets				Current Liabilities				Long-Term Liabilities
		(Millions)
Three months ended September 30, 2010:
Beginning balance		$	0.8			$	1.8			$	(0.1	)		$	(0.2	)
Net realized and unrealized (losses) gains included in earnings			(0.1	)			(1.1	)			0.1				0.2
Transfers into Level 3 (a)			—				—				—				—
Transfers out of Level 3 (a)			(0.4	)			—				—				—
Purchases, Issuances and Settlements net			—				—				—				—
Ending balance		$	0.3			$	0.7			$	—			$	—
Net unrealized gains (losses) still held included in earnings (b)		$	0.2			$	(0.9	)		$	—			$	—
Three months ended September 30, 2009:
Beginning balance		$	1.2			$	—			$	(0.1	)		$	(0.9	)
Net realized and unrealized (losses) gains included in earnings			(0.2	)			0.1				(0.6	)			(0.1	)
Net transfers in (out) of Level 3 (c)			—				—				—				—
Purchases, Issuances and Settlements net			(0.6	)			—				(0.2	)			—
Ending balance		$	0.4			$	0.1			$	(0.9	)		$	(1.0	)
Net unrealized (losses) gains still held included in earnings (b)		$	(0.8	)		$	0.1			$	(0.6	)		$	(0.1	)

 

(a)	Amounts transferred in and amounts transferred out are reflected at fair value as of the end of the period.

(b)	Represents the amount of total gains or losses for the period, included in gains or losses from commodity derivative activity, net, attributable to change in unrealized gains or losses relating to assets and liabilities classified as Level 3 that are still held as of September 30, 2010 and 2009.

(c)	Amounts transferred in are reflected at the fair value as of the beginning of the period and amounts transferred out are reflected at fair value at the end of the period.

 

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(Unaudited)

 

 

		Commodity Derivative Instruments
		Current Assets				Long-Term Assets				Current Liabilities				Long-Term Liabilities
		(Millions)
Nine months ended September 30, 2010:
Beginning balance		$	0.4			$	0.2			$	(0.8	)		$	(0.4	)
Net realized and unrealized gains included in earnings			0.3				0.5				0.2				0.4
Transfers into Level 3 (a)			—				—				—				—
Transfers out of Level 3 (a)			(0.4	)			—				—				—
Purchases, Issuances and Settlements net			—				—				0.6				—
Ending balance		$	0.3			$	0.7			$	—			$	—
Net unrealized gains still held included in earnings (b)		$	0.3			$	0.5			$	—			$	—
Nine months ended September 30, 2009:
Beginning balance		$	0.3			$	1.7			$	—			$	—
Net realized and unrealized losses included in earnings			(3.0	)			(1.6	)			(0.9	)			(1.0	)
Net transfers in (out) of Level 3 (c)			—				—				—				—
Purchases, Issuances and Settlements net			3.1				—				—				—
Ending balance		$	0.4			$	0.1			$	(0.9	)		$	(1.0	)
Net unrealized gains (losses) still held included in earnings (b)		$	0.4			$	(1.6	)		$	(0.9	)		$	(1.0	)

 

(a)	Amounts transferred in and amounts transferred out are reflected at fair value as of the end of the period.

(b)	Represents the amount of total gains or losses for the period, included in gains or losses from commodity derivative activity, net, attributable to change in unrealized gains or losses relating to assets and liabilities classified as Level 3 that are still held as of September 30, 2010 and 2009.

(c)	Amounts transferred in are reflected at the fair value as of the beginning of the period and amounts transferred out are reflected at fair value at the end of the period.

As of March 31, 2010, we recognized the fair value of our contingent consideration, which is classified as Level 3, in relation to our acquisition of an additional 5% interest in Collbran, from Delta, of approximately $1.0 million, which we recorded to other current liabilities in our condensed consolidated balance sheets. As of June 30, 2010, we reassessed the fair value of the contingent consideration and adjusted the fair value of the liability to approximately $0.5 million. As of September 30, 2010, we reassessed the fair value of the contingent consideration and adjusted the fair value of the liability to $0. Accordingly we recognized $0.5 million and $1.0 million in other income in our condensed consolidated results of operations during the three and nine months ended September 30, 2010, respectively.

During the three and nine months ended September 30, 2010, we had no significant transfers into and out of Levels 1, 2 and 3. To qualify as a transfer, the asset or liability must have existed in the previous reporting period and moved into a different level during the current period.

Estimated Fair Value of Financial Instruments

We have determined fair value amounts using available market information and appropriate valuation methodologies. However, considerable judgment is required in interpreting market data to develop the estimates of fair value. Accordingly, the estimates presented herein are not necessarily indicative of the amounts that we could realize in a current market exchange. The use of different market assumptions and/or estimation methods may have a material effect on the estimated fair value amounts.

 

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(Unaudited)

 

 

The fair value of restricted investments, accounts receivable and accounts payable are not materially different from their carrying amounts because of the short term nature of these instruments or the stated rates approximating market rates. Unrealized gains and unrealized losses on derivative instruments are carried at fair value. The carrying and fair values of outstanding balances under our Credit Agreement are $363.0 million, and $353.3 million, respectively, as of September 30, 2010 and $613.0 million and $590.0 million, respectively, as of December 31, 2009. The carrying and fair values of our 3.25% Senior notes are $250.0 million and $252.0 million, respectively as of September 30, 2010. We determine the fair value of our credit facility borrowings based upon the discounted present value of expected future cash flows, taking into account the difference between the contractual borrowing spread and the spread for similar credit facilities available in the marketplace. Additionally, we have executed interest rate swap agreements on a portion of our interest rate exposure which swaps variable for fixed interest rates.

9. Debt

Long-term debt was as follows:

 

		September 30, 2010				December 31, 2009
		(Millions)
Credit Agreement
Revolving credit facility, weighted-average variable interest rate of 0.74% and 0.69%, respectively, and net effective interest rate of 5.09% and 4.41%, respectively, due June 21, 2012 (a)		$	363.0			$	603.0
Term loan facility, variable interest rate of 0.34%, due June 21, 2012 (b)			—				10.0
Total amounts outstanding under the Credit Agreement			363.0				613.0
Debt Securities
Issued September 30, 2010, interest at 3.25% payable semi-annually, due October 1, 2015			250.0				—
Unamortized discount			(0.2	)			—
Total long-term debt		$	612.8			$	613.0

 

(a)	$350.0 million of debt has been swapped to a fixed rate obligation with effective fixed rates ranging from 3.97% to 5.19%, for a net effective rate of 5.09% on the $363.0 million of outstanding debt under our revolving credit facility as of September 30, 2010.

(b)	The term loan facility was fully secured by restricted investments as of December 31, 2009. The term loan was repaid during the first quarter of 2010.

Credit Agreement

We have an $850.0 million revolving credit facility that matures June 21, 2012, or the Credit Agreement.

Effective June 28, 2010, we transferred both the funded and the unfunded portions of the former Lehman Brothers Commercial Bank commitment to Morgan Stanley. The transfer reinstated $25.4 million of available capacity to our revolving credit facility.

At September 30, 2010 and December 31, 2009, we had $0.5 million and $0.3 million, respectively, letters of credit issued under the Credit Agreement outstanding. As of December 31, 2009 we had outstanding term loan balances under the Credit Agreement, which were fully collateralized by investments in high-grade securities, classified as restricted investments in the accompanying condensed consolidated balance sheets as of December 31, 2009. As of September 30, 2010 the unused capacity under the revolving credit facility was $486.5 million.

 

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Our borrowing capacity is limited at September 30, 2010, by the Credit Agreement’s financial covenant requirements. Except in the case of a default, amounts borrowed under our credit facility will not mature prior to the June 21, 2012 maturity date.

The Credit Agreement requires us to maintain a leverage ratio (the ratio of our consolidated indebtedness to our consolidated EBITDA, in each case as is defined by the Credit Agreement) of not more than 5.0 to 1.0, and on a temporary basis for not more than three consecutive quarters (including the quarter in which such acquisition is consummated) following the consummation of asset acquisitions in the midstream energy business of not more than 5.5 to 1.0.

Debt Securities

On September 30, 2010 we issued $250.0 million of our 3.25% Senior Notes due October 1, 2015. We received net proceeds, of $247.8 million net of underwriters’ fees, related expense and unamortized discounts of $1.5 million, $0.5 million and $0.2 million, respectively, which we used to repay funds borrowed under the revolver portion of our Credit Facility. Interest on the notes will be paid semi-annually on April 1 and October 1 of each year, commencing April 1, 2011. The notes will mature on October 1, 2015 unless redeemed prior to maturity.

We have incurred $2.0 million of underwriters’ fees and related expense with the issue of the notes, which we deferred in other long term assets in our condensed consolidated balance sheets. We will amortize these costs over the term of the notes.

The notes are senior unsecured obligations, ranking equally in right of payment with our existing unsecured indebtedness, including indebtedness under our Credit Facility. We are not required to make mandatory redemption or sinking fund payments with respect to these notes. The securities are redeemable at a premium at our option.

The future maturities of long-term debt in the year indicated are as follows:

 

		Debt Maturities
		(Millions)
2010		$	—
2011			—
2012			363.0
2013			—
2014			—
Thereafter			250.0
			613.0
Unamortized discount			(0.2	)
Total		$	612.8

Other Agreements

As of September 30, 2010 we had a contingent letter of credit facility for up to $10.0 million, on which we pay a fee of 0.50% per annum. This facility reduces the amount of cash we may be required to post as collateral. As of September 30, 2010, we have $0 letters of credit issued on this facility; we will pay a net fee of 1.75% per annum on letters of credit issued on this facility. This facility was issued directly by a financial institution and does not reduce the available capacity under our credit facility.

10. Risk Management and Hedging Activities

Our day to day operations expose us to a variety of risks including but not limited to changes in the prices of commodities that we buy or sell, changes in interest rates, and the creditworthiness of each of our counterparties. We manage certain of these exposures with both physical and financial transactions. We have established a comprehensive risk management policy, or Risk Management Policy, and a risk management committee, or the Risk Management Committee, to monitor and manage market risks associated with commodity prices and counterparty credit. The Risk Management Committee is responsible for the overall management of credit risk and commodity price risk, including monitoring exposure limits. The following briefly describes each of the risks that we manage.

 

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Commodity Price Risk

We are exposed to the impact of market fluctuations in the prices of natural gas, NGLs and condensate as a result of our gathering, processing, sales and storage activities. For gathering and processing services, we may receive fees or commodities as payment for these services, depending on the contract type. We enter into derivative financial instruments to mitigate a portion of the risk of weakening natural gas, NGL and condensate prices associated with our gathering, processing and sales activities, thereby stabilizing our cash flows. We have mitigated a portion of our expected commodity price risk associated with our gathering, processing and sales activities through 2015 with natural gas and crude oil derivative instruments. Additionally, given the limited depth of the NGL derivatives market, we primarily utilize crude oil swaps to mitigate a portion of our commodity price exposure for propane and heavier NGLs. Historically, prices of NGLs have been generally related to the price of crude oil, with some exceptions, notably in late 2008 to early 2009, when NGL pricing was at a greater discount to crude oil. Given the relationship and the lack of liquidity in the NGL financial market, we have historically used crude oil swaps to mitigate a portion of NGL price risks. When the relationship of NGL prices to crude oil prices is at a discount to historical ranges, we experience additional exposure as a result of the relationship. These transactions are primarily accomplished through the use of forward contracts, which are swap futures that effectively exchange our floating price risk for a fixed price. However, the type of instrument that we use to mitigate a portion of our risk may vary depending upon our risk management objective. These transactions are not designated as hedging instruments for accounting purposes and the change in fair value is reflected within our condensed consolidated statements of operations as a gain or a loss on commodity derivative activity.

With respect to our Pelico system, we may enter into financial derivatives to lock in transportation margins across the system, or to lock in margins around our leased storage facility to maximize value. This objective may be achieved through the use of physical purchases or sales of gas that are accounted for under accrual accounting. While the physical purchase or sale of gas transactions are accounted for under accrual accounting and any inventory is stated at lower of cost or market, the swaps are not designated as hedging instruments for accounting purposes and any change in fair value of these instruments is reflected within our condensed consolidated statements of operations.

Our Wholesale Propane Logistics segment is generally designed to establish stable margins by entering into supply arrangements that specify prices based on established floating price indices and by entering into sales agreements that provide for floating prices that are tied to our variable supply costs plus a margin. To the extent possible, we match the pricing of our supply portfolio to our sales portfolio in order to lock in value and reduce our overall commodity price risk. However, to the extent that we carry propane inventories or our sales and supply arrangements are not aligned, we are exposed to market variables and commodity price risk. We manage the commodity price risk of our supply portfolio and sales portfolio with both physical and financial transactions. While the majority of our sales and purchases in this segment are index-based, occasionally, we may enter into fixed price sales agreements in the event that a retail propane distributor desires to purchase propane from us on a fixed price basis. In such cases, we may manage this risk with derivatives that allow us to swap our fixed price risk to market index prices that are matched to our market index supply costs. In addition, we may on occasion use financial derivatives to manage the value of our propane inventories. These transactions are not designated as hedging instruments for accounting purposes and the change in value is reflected in the current period within our condensed consolidated statements of operations as a gain or loss on commodity derivative activity.

Our portfolio of commodity derivative activity is primarily accounted for using the mark-to-market method of accounting, whereby changes in fair value are recorded directly to the condensed consolidated statements of operations; however, depending upon our risk profile and objectives, in certain limited cases, we may execute transactions that qualify for the hedge method of accounting.

Commodity Cash Flow Hedges — Effective July 1, 2007, we elected to discontinue using the hedge method of accounting for derivatives that manage our commodity price risk. Prior to July 1, 2007, we used NGL, natural gas and crude oil swaps to mitigate a portion of the risk of market fluctuations in the price of NGLs, natural gas and condensate. Given our election to discontinue using the hedge method of accounting, the remaining net losses deferred in AOCI relative to cash flow hedges are reclassified to sales of natural gas, propane, NGLs and condensate, through December 2011, as the underlying transactions impact earnings.

 

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(Unaudited)

 

 

Interest Rate Risk

We mitigate a portion of our interest rate risk on our revolving credit facility with interest rate swaps which convert a portion of the interest rate associated with the indebtedness outstanding under our revolving credit facility to a fixed rate obligation through June 2012, thereby reducing the exposure to market rate fluctuations.

On September 23, 2010 we filed a prospectus with the SEC relating to the issuance of $250.0 million of our 3.25% Senior Notes, the proceeds of which were used to pay down our revolving credit facility. As a result of our pay down of the revolving credit facility, effective September 23, 2010, we discontinued cash flow hedge accounting on $225.0 million of our interest rate swap agreements. Effective September 23, 2010, we account for $225.0 million of interest rate swaps using the mark-to-market method of accounting, whereby changes in fair value are recorded directly to the condensed consolidated statements of operations, in interest expense. The net losses deferred in AOCI as of September 23, 2010 will be reclassified into interest expense as the hedged transactions impact earnings. On October 1, 2010, we terminated $200.0 million of these swaps that would have matured in December 2010, for $1.3 million. We also exchanged $275.0 million of interest rate swaps with an effective date of December 2010 through June 2012 for $150.0 million of interest rate swaps effective December 2010 through June 2014. These swaps are accounted for under the mark-to-market method of accounting.

We have designated $350.0 million of our interest rate swap agreements as cash flow hedges, and effectiveness is determined by matching the principal balance and terms with that of the specified obligation. The effective portions of changes in fair value are recognized in AOCI in the condensed consolidated balance sheets and are reclassified into earnings as the hedged transactions impact earnings. The effect that these swaps have on our condensed consolidated financial statements, as well as the effect that is expected over the upcoming 12 months is summarized in the charts below. However, due to the volatility of the interest rate markets, the corresponding value in AOCI is subject to change prior to its reclassification into earnings. Ineffective portions of changes in fair value are recognized in earnings.

As of September 30 2010, $425.0 million of the agreements reprice prospectively approximately every 90 days and the remaining $150.0 million of the agreements reprice prospectively approximately every 30 days. Under the terms of the interest rate swap agreements, we pay fixed rates ranging from 2.26% to 5.19%, and receive interest payments based on the three-month and one-month LIBOR. The differences to be paid or received under the interest rate swap agreements are recognized as an adjustment to interest expense.

Contingent Credit Features

Each of the above risks is managed through the execution of individual contracts with a variety of counterparties. Certain of our derivative contracts may contain credit-risk related contingent provisions that may require us to take certain actions in certain circumstances.

We have International Swap Dealers Association, or ISDA, contracts which are standardized master legal arrangements that establish key terms and conditions which govern certain derivative transactions. These ISDA contracts contain standard credit-risk related contingent provisions. Some of the provisions we are subject to are outlined below.

 

•

If we were to have an effective event of default under our Credit Agreement that occurs and is continuing, our ISDA counterparties may have the right to request early termination and net settlement of any outstanding derivative liability positions.

 

•

In the event that DCP Midstream, LLC was to be downgraded below investment grade by at least one of the major credit rating agencies, certain of our ISDA counterparties may have the right to reduce our collateral threshold to zero, potentially requiring us to fully collateralize any commodity contracts in a net liability position.

 

•

Additionally, in some cases, our ISDA contracts contain cross-default provisions that could constitute a credit-risk related contingent feature. These provisions apply if we default in making timely payments under those agreements and the amount of the default is above certain predefined thresholds, which are significantly high and are generally consistent with the terms of our Credit Agreement. As of September 30, 2010, we are not a party to any agreements that would be subject to these provisions other than our Credit Agreement.

 

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Our commodity derivative contracts that are not governed by ISDA contracts do not have any credit-risk related contingent features.

Depending upon the movement of commodity prices and interest rates, each of our individual contracts with counterparties to our commodity derivative instruments or to our interest rate swap instruments are in either a net asset or net liability position. As of September 30, 2010, we had $48.1 million of individual commodity derivative contracts that contain credit-risk related contingent features that were in a net liability position, and have not posted any cash collateral relative to such positions. If a credit-risk related event were to occur and we were required to net settle our position with an individual counterparty, our ISDA contracts permit us to net all outstanding contracts with that counterparty, whether in a net asset or net liability position, as well as any cash collateral already posted. As of September 30, 2010 if a credit-risk related event were to occur we may be required to post additional collateral. Additionally, although our commodity derivative contracts that contain credit-risk related contingent features were in a net liability position as of September 30, 2010, if a credit-risk related event were to occur, the net liability position would be partially offset by contracts in a net asset position reducing our net liability to $47.6 million.

As of September 30, 2010, our interest rate swaps were in a net liability position of approximately $33.6 million of which, the entire amount is subject to credit-risk related contingent features. If we were to have a default of any of our covenants to our Credit Agreement, that occurs and is continuing, the counterparties to our swap instruments may have the right to request that we net settle the instrument in the form of cash.

Collateral

As of September 30, 2010 we had a contingent letter of credit facility for up to $10.0 million, on which we have $0 letters of credit issued. DCP Midstream, LLC had issued and outstanding parental guarantees totaling $98.0 million in favor of certain counterparties to our commodity derivative instruments. This contingent letter of credit facility and the parental guarantees reduce the amount of cash we may be required to post as collateral. As of September 30, 2010, we had no cash collateral posted with counterparties to our commodity derivative instruments.

Summarized Derivative Information

The following summarizes the balance within AOCI relative to our commodity and interest rate cash flow hedges:

 

		September 30, 2010				December 31, 2009
		(Millions)
Commodity cash flow hedges:
Net deferred losses in AOCI		$	(0.5	)		$	(0.8	)
Interest rate cash flow hedges:
Net deferred losses in AOCI			(32.7	)			(31.1	)
Total AOCI		$	(33.2	)		$	(31.9	)

 

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(Unaudited)

 

 

The fair value of our derivative instruments that are designated as hedging instruments, those that are marked-to-market each period, as well as the location of each within our condensed consolidated balance sheets, by major category, is summarized as follows:

 

Balance Sheet Line Item		September 30, 2010				December 31, 2009				Balance Sheet Line Item		September 30, 2010				December 31, 2009
		(Millions)										(Millions)
Derivative Assets Designated as Hedging Instruments:										Derivative Liabilities Designated as Hedging Instruments:
Interest rate derivatives:										Interest rate derivatives:
Unrealized gains on derivative instruments — current		$	—			$	—			Unrealized losses on derivative instruments — current		$	(13.7	)		$	(20.4	)
Unrealized gains on derivative instruments — long-term			—				—			Unrealized losses on derivative instruments — long-term			(8.9	)			(11.6	)
		$	—			$	—					$	(22.6	)		$	(32.0	)
Derivative Assets Not Designated as Hedging Instruments:										Derivative Liabilities Not Designated as Hedging Instruments:
Commodity derivatives:										Commodity derivatives:
Unrealized gains on derivative instruments — current		$	1.7			$	7.3			Unrealized losses on derivative instruments — current		$	(15.8	)		$	(21.1	)
Unrealized gains on derivative instruments — long-term			1.3				2.0			Unrealized losses on derivative instruments — long-term			(33.5	)			(46.4	)
		$	3.0			$	9.3					$	(49.3	)		$	(67.5	)
Interest rate derivatives:										Interest rate derivatives:
Unrealized gains on derivative instruments — current		$	—			$	—			Unrealized losses on derivative instruments — current		$	(6.6	)		$	—
Unrealized gains on derivative instruments — long-term			—				—			Unrealized losses on derivative instruments — long-term			(4.4	)			—
		$	—			$	—					$	(11.0	)		$	—

The following table summarizes the impact on our condensed consolidated balance sheet and condensed consolidated statements of operations of our derivative instruments that are accounted for using the cash flow hedge method of accounting.

 

		Loss Recognized in AOCI on Derivatives — Effective  Portion								(Loss) Gain Reclassified From AOCI to Earnings — Effective Portion												Gain (Loss) Recognized in Income on Derivatives — Ineffective Portion and Amount Excluded From Effectiveness Testing
		Three Months Ended September 30,
		2010				2009				2010				2009								2010				2009
		(Millions)								(Millions)												(Millions)
Interest rate derivatives		$	(4.8	)		$	(8.3	)		$	(5.4	)		$	(5.3	)			(a	)		$	—			$	—				(a	)(c)
Commodity derivatives		$	—			$	—			$	0.1			$	(0.1	)			(b	)		$	—			$	—				(b	)(c)

 

(a)	Included in interest expense in our condensed consolidated statements of operations.

(b)	Included in sales of natural gas, propane, NGLs and condensate in our condensed consolidated statements of operations.

(c)	For the three months ended September 30, 2010 and 2009, no derivative gains or losses were reclassified from AOCI to current period earnings as a result of the discontinuance of cash flow hedges related to certain forecasted transactions that are not probable of occurring.

 

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		Loss Recognized in AOCI on Derivatives — Effective  Portion								Loss Reclassified From AOCI to Earnings — Effective Portion												Gain (Loss) Recognized in Income on Derivatives — Ineffective Portion and Amount Excluded From Effectiveness Testing												Deferred Losses in AOCI Expected to be Reclassified into Earnings Over the Next 12 Months
		Nine Months Ended September 30,
		2010				2009				2010				2009								2010				2009
		(Millions)								(Millions)												(Millions)												(Millions)
Interest rate derivatives		$	(18.2	)		$	(8.0	)		$	(16.6	)		$	(13.9	)			(a	)		$	—			$	—				(a	)(c)		$	(19.7	)
Commodity derivatives		$	—			$	—			$	(0.3	)		$	(0.7	)			(b	)		$	—			$	—				(b	)(c)		$	(0.3	)

 

(a)	Included in interest expense in our condensed consolidated statements of operations.

(b)	Included in sales of natural gas, propane, NGLs and condensate in our condensed consolidated statements of operations.

(c)	For the nine months ended September 30, 2010 and 2009, no derivative gains or losses were reclassified from AOCI to current period earnings as a result of the discontinuance of cash flow hedges related to certain forecasted transactions that are not probable of occurring.

Changes in value of derivative instruments, for which the hedge method of accounting has not been elected from one period to the next, are recorded in the condensed consolidated statements of operations. The following summarizes these amounts and the location within the condensed consolidated statements of operations that such amounts are reflected:

 

Commodity Derivatives: Statements of Operations Line Item		Three Months Ended September 30,								Nine Months  Ended September 30,
		2010				2009				2010				2009
		(Millions)
Third party:
Realized		$	2.6			$	2.8			$	0.5			$	17.6
Unrealized			(18.4	)			1.6				12.5				(49.5	)
Gains (losses) from commodity derivative activity, net		$	(15.8	)		$	4.4			$	13.0			$	(31.9	)
Affiliates:
Realized		$	(0.5	)		$	0.1			$	(0.4	)		$	(0.3	)
Unrealized			(0.2	)			(1.1	)			(0.6	)			(3.3	)
Losses from commodity derivative activity, net — affiliates		$	(0.7	)		$	(1.0	)		$	(1.0	)		$	(3.6	)
Interest Rate Derivatives: Statements of Operations Line Item		Three Months Ended September 30,								Nine Months  Ended September 30,
		2010				2009				2010				2009
		(Millions)
Third party:
Unrealized		$	(0.1	)		$	—			$	(0.1	)		$	—
Interest expense		$	(0.1	)		$	—			$	(0.1	)		$	—

We do not have any derivative financial instruments that qualify as a hedge of a net investment.

 

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The following table represents, by commodity type, our net long or short positions that are expected to partially or entirely settle in each respective year. To the extent that we have long dated derivative positions that span multiple calendar years, the contract will appear in more than one line item in the table below. This table also presents our net long or short natural gas basis swap positions separately from our net long or short natural gas positions.

 

		September 30, 2010
		Crude Oil				Natural Gas				Natural Gas Liquids				Natural Gas Basis Swaps
Year of Expiration		Net Long (Short) Position (Bbls)				Net Long (Short) Position (MMBtu)				Net Long (Short) Position (Bbls)				Net Long (Short) Position (MMBtu)
2010			(245,180	)			(593,300	)			(20,524	)			(31,000	)
2011			(949,000	)			(365,000	)			6,810				—
2012			(777,750	)			(366,000	)			—				—
2013			(748,250	)			(365,000	)			—				—
2014			(547,500	)			(365,000	)			—				—
2015			(182,500	)			—				—				—

We periodically enter into interest rate swap agreements to mitigate a portion of our floating rate interest exposure. As of September 30, 2010, we have swaps with a notional value between $25.0 million and $150.0 million, which, in aggregate, exchange up to $575.0 million of our floating rate obligation to a fixed rate obligation through June 2012. On October 1, 2010, we terminated $200.0 million of these swaps, that would have matured in December 2010, for $1.3 million. We also exchanged $275.0 million of interest rate swaps with an effective date of December 2010 through June 2012 for $150.0 million of interest rate swaps effective December 2010 through June 2014.

11. Partnership Equity and Distributions

General — Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our Available Cash as defined below, to unitholders of record on the applicable record date, as determined by our general partner.

In September 2010, we issued 5,200 units, from our Long Term Incentive Plan, to non-employee directors as compensation for their service during 2010.

In August 2010, we issued 2,990,000 common units at $32.57 per unit. We received proceeds of $93.1 million, net of offering costs.

On May 26, 2010, we filed a universal shelf registration statement on Form S-3 with the SEC with a maximum aggregate offering price of $1.5 billion, to replace an existing shelf registration statement. The universal shelf registration statement will allow us to register and issue additional partnership units and debt securities.

In November 2009, we issued 2,500,000 common units at $25.40 per unit, and in December 2009 we issued an additional 375,000 common units to the underwriters upon exercise of their overallotment option. We received proceeds of $69.5 million, net of offering costs.

In April 2009, we issued 3,500,000 Class D units valued at $49.7 million. The Class D units were issued to DCP Midstream, LLC in consideration for an additional 25.1% interest in East Texas and a fixed price natural gas liquids derivative by NGL component for the period April 2009 to March 2010. The Class D units converted into our common units on a one-for-one basis on August 17, 2009.

Definition of Available Cash — Available Cash, for any quarter, consists of all cash and cash equivalents on hand at the end of that quarter:

 

•

less the amount of cash reserves established by the general partner to:

 

•

provide for the proper conduct of our business;

 

•

comply with applicable law, any of our debt instruments or other agreements; and

 

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•

provide funds for distributions to the unitholders and to our general partner for any one or more of the next four quarters;

 

•

plus, if our general partner so determines, all or a portion of cash and cash equivalents on hand on the date of determination of Available Cash for the quarter.

General Partner Interest and Incentive Distribution Rights — The general partner is entitled to a percentage of all quarterly distributions equal to its general partner interest of approximately 1% and limited partner interest of 1% as of September 30, 2010. The general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its current general partner interest.

The incentive distribution rights held by the general partner entitle it to receive an increasing share of Available Cash when pre-defined distribution targets are achieved. Currently, our distribution to our general partner related to its incentive distribution rights is at the highest level. The general partner’s incentive distribution rights were not reduced as a result of our common limited partner unit issuances, and will not be reduced if we issue additional units in the future and the general partner does not contribute a proportionate amount of capital to us to maintain its current general partner interest. Please read the Distributions of Available Cash after the Subordination Period section below for more details about the distribution targets and their impact on the general partner’s incentive distribution rights.

Class D Units — All of the Class D units were held by DCP Midstream, LLC and converted into our common units on a one for one basis on August 17, 2009. The holders of the Class D units received the distribution for the second quarter of 2009, paid on August 14, 2009.

Subordinated Units — All of our subordinated units were held by DCP Midstream, LLC and were converted to common units by February 2009. The subordination period had an early termination provision that permitted 50% of the subordinated units, or 3,571,428 units, to convert into common units on a one-to-one basis in February 2008 and permitted the other 50% of the subordinated units, or 3,571,429 units, to convert into common units on a one-to-one basis in February 2009, following the satisfactory completion of the tests for ending the subordination period contained in our partnership agreement. The board of directors of the General Partner certified that all conditions for early conversion were satisfied.

Distributions of Available Cash after the Subordination Period — Our partnership agreement, after adjustment for the general partner’s relative ownership level, requires that we make distributions of Available Cash from operating surplus for any quarter after the subordination period, which ended in February 2009, in the following manner:

 

•

first, to all unitholders and the general partner, in accordance with their pro rata interest, until each unitholder receives a total of $0.4025 per unit for that quarter;

 

•

second, 13% to the general partner, plus the general partner’s pro rata interest, and the remainder to all unitholders pro rata until each unitholder receives a total of $0.4375 per unit for that quarter;

 

•

third, 23% to the general partner, plus the general partner’s pro rata interest, and the remainder to all unitholders pro rata until each unitholder receives a total of $0.525 per unit for that quarter; and

 

•

thereafter, 48% to the general partner, plus the general partner’s pro rata interest, and the remainder to all unitholders.

The following table presents our cash distributions paid in 2010 and 2009:

 

Payment Date		Per Unit Distribution				Total Cash Distribution
						(Millions)
August 13, 2010		$	0.610			$	25.3
May 14, 2010		$	0.600			$	24.6
February 12, 2010		$	0.600			$	24.6
November 13, 2009		$	0.600			$	22.6
August 14, 2009		$	0.600			$	22.6
May 15, 2009		$	0.600			$	20.1
February 13, 2009		$	0.600			$	20.1

 

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12. Commitments and Contingent Liabilities

Litigation — We are a party to various legal proceedings, as well as administrative and regulatory proceedings and commercial disputes that have arisen in the ordinary course of our business. Management currently believes that the ultimate resolution of these matters, taken as a whole, and after consideration of amounts accrued, insurance coverage or other indemnification arrangements, will not have a material adverse effect on our condensed consolidated results of operations, financial position, or cash flows. See Note 17 in Item 8 of our 2009 Form 10-K for additional details.

Westfield — In July 2010 there was an explosion at a condominium complex in Norfolk, Massachusetts in which a worker at the condominium was killed. An investigation of the accident by the Massachusetts State Fire Marshall has indicated that the propane that exploded may have been unodorized. The investigation further indicated that the propane that exploded may have been supplied by our Westfield propane rail terminal to one of our customers. We are not responsible for odorization of the propane we supply to our customers. Rather, we receive the propane by rail which has been odorized by our suppliers. An attorney representing the estate of the deceased has put us on notice of an intent to bring legal action in this matter. We intend to vigorously defend any such legal action. It is not possible to predict whether we will incur any liability or to estimate the damages, if any, we might incur in connection with this matter. Management does not believe the ultimate resolution of this issue will have a material adverse effect on our consolidated results of operations, financial position or cash flows.

Driver — In August 2007, Driver Pipeline Company, Inc., or Driver, filed a lawsuit against DCP Midstream, LP, an affiliate of the owner of our general partner, in District Court, Jackson County, Texas. The litigation arose from a commercial dispute involving the construction of our Wilbreeze pipeline in 2006. Driver was the primary contractor for construction of the pipeline and the construction process was managed for us by DCP Midstream, LP. In June 2010, we settled this matter with Driver for $0.3 million, which we have recorded to general and administrative expense during the nine months ended September 30, 2010.

El Paso — On February 27, 2009, a jury in the District Court, Harris County, Texas rendered a verdict in favor of El Paso E&P Company, L.P., or El Paso, and against one of our subsidiaries and DCP Midstream, LLC. As previously disclosed, the lawsuit, filed in December 2006, stems from an ongoing commercial dispute involving our Minden processing plant that dates back to August 2000. During the second quarter of 2009 we filed an appeal in the 14th Court of Appeals, Texas. El Paso filed an additional lawsuit in the District Court of Webster Parish, Louisiana, claiming damages for the same claims as the Texas matter, but for periods prior to our ownership of the Minden processing plant. The Louisiana court determined in August 2009 that El Paso’s Louisiana claims were barred by the doctrine of res judicata and dismissed the case with prejudice in Louisiana. In January 2010, we and DCP Midstream, LLC entered into a settlement agreement with El Paso to resolve all claims brought by El Paso regarding this matter in Texas and Louisiana. Under the terms of the settlement agreement, we paid El Paso approximately $2.2 million for our portion of the settlement, which is within the amount of our previously disclosed contingent liability. The cases have been dismissed in both Texas and Louisiana.

Insurance — We renewed our insurance policies in May, June and July 2010 for the 2010-2011 insurance year. We contract with third-party and affiliate insurers for: (1) automobile liability insurance for all owned, non-owned and hired vehicles; (2) general liability insurance; (3) excess liability insurance above the established primary limits for general liability and automobile liability insurance; and (4) property insurance, which covers replacement value of real and personal property and includes business interruption/extra expense. These renewals have not resulted in any material change to the premiums we are contracted to pay in the 2010-2011 insurance year compared with the 2009-2010 insurance year. We are jointly insured with DCP Midstream, LLC for directors and officers insurance covering our directors and officers for acts related to our business activities. All coverage is subject to certain limits and deductibles, the terms and conditions of which are common for companies that are of similar size to us and with similar types of operations.

Our insurance on Discovery for the 2010-2011 insurance year covers onshore named windstorm property and business interruption insurance and onshore and offshore non-windstorm property and business interruption insurance. The availability of offshore named windstorm property and business interruption insurance has been significantly reduced over the past two years as a result of higher industry-wide damage claims. Additionally, the named windstorm property and business interruption insurance that is available comes at uneconomic premium levels, higher deductibles and lower coverage limits. Consequently, as with the 2009-2010 insurance year, Discovery elected to not purchase offshore named windstorm property and business interruption insurance coverage for the 2010-2011 insurance year.

 

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Indemnification — DCP Midstream, LLC has agreed to indemnify us for certain potential environmental claims, losses and expenses associated with the operation of the assets of certain of our predecessors. See the “Indemnification” section of Note 5 in Item 8 of our 2009 Form 10-K for additional details.

13. Business Segments

Our operations are located in the United States and are organized into three reporting segments: (1) Natural Gas Services; (2) Wholesale Propane Logistics; and (3) NGL Logistics.

Natural Gas Services — The Natural Gas Services segment consists of our Northern Louisiana system, our Southern Oklahoma system, our 40% limited liability company interest in Discovery, our 75% interest in our Colorado system, our Wyoming system, our 50.1% interest in our East Texas system, and our Michigan systems.

Wholesale Propane Logistics — The Wholesale Propane Logistics segment consists of five owned and operated rail terminals, one owned marine import terminal, one leased marine terminal, one pipeline terminal and access to several open-access pipeline terminals.

NGL Logistics — The NGL Logistics segment consists of the Seabreeze and Wilbreeze NGL transportation pipelines, the Wattenberg NGL transportation pipeline, and the Black Lake interstate NGL pipeline.

These segments are monitored separately by management for performance against our internal forecast and are consistent with internal financial reporting. These segments have been identified based on the differing products and services, regulatory environment and the expertise required for these operations. Gross margin is a performance measure utilized by management to monitor the business of each segment.

The following tables set forth our segment information:

Three Months Ended September 30, 2010

 

		Natural  Gas Services				Wholesale Propane Logistics				NGL Logistics				Other				Total
		(Millions)
Total operating revenue		$	167.9			$	65.9			$	6.1			$	—			$	239.9
Gross margin (a)		$	32.8			$	3.0			$	3.9			$	—			$	39.7
Operating and maintenance expense			(15.0	)			(3.1	)			(1.1	)			—				(19.2	)
Depreciation and amortization expense			(17.3	)			(1.0	)			(0.8	)			(0.1	)			(19.2	)
General and administrative expense			—				—				—				(8.2	)			(8.2	)
Step acquisition — equity interest re-measurement gain			—				—				9.1				—				9.1
Other income			0.5				—				—				—				0.5
Earnings from unconsolidated affiliates			4.1				—				—				—				4.1
Interest expense			—				—				—				(7.5	)			(7.5	)
Income tax expense (b)			—				—				—				(0.1	)			(0.1	)
Net income (loss)			5.1				(1.1	)			11.1				(15.9	)			(0.8	)
Net income attributable to noncontrolling interests			(3.3	)			—				—				—				(3.3	)
Net income (loss) attributable to partners		$	1.8			$	(1.1	)		$	11.1			$	(15.9	)		$	(4.1	)
Non-cash derivative mark-to-market (c)		$	(18.0	)		$	(0.5	)		$	—			$	(0.2	)		$	(18.7	)
Capital expenditures		$	8.8			$	0.3			$	2.6			$	—			$	11.7
Acquisitions net of cash acquired		$	—			$	66.0			$	15.8			$	—			$	81.8

 

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Three Months Ended September 30, 2009

 

		Natural  Gas Services				Wholesale Propane Logistics				NGL Logistics				Other				Total
		(Millions)
Total operating revenue		$	154.1			$	48.5			$	3.1			$	—			$	205.7
Gross margin (a)		$	47.3			$	5.2			$	1.9			$	—			$	54.4
Operating and maintenance expense			(16.1	)			(2.5	)			(0.4	)			—				(19.0	)
Depreciation and amortization expense			(15.8	)			(0.3	)			(0.3	)			—				(16.4	)
General and administrative expense			—				—				—				(7.9	)			(7.9	)
Earnings from unconsolidated affiliates			7.9				—				0.5				—				8.4
Interest expense			—				—				—				(7.1	)			(7.1	)
Income tax expense (b)			—				—				—				—				—
Net income (loss)			23.3				2.4				1.7				(15.0	)			12.4
Net income attributable to noncontrolling interests			(2.5	)			—				—				—				(2.5	)
Net income (loss) attributable to partners		$	20.8			$	2.4			$	1.7			$	(15.0	)		$	9.9
Non-cash derivative mark-to-market (c)		$	(0.3	)		$	0.6			$	—			$	—			$	0.3
Capital expenditures		$	24.6			$	—			$	—			$	—			$	24.6
Acquisitions, net of cash acquired		$	(0.7	)		$	—			$	—			$	—			$	(0.7	)

Nine Months Ended September 30, 2010

 

		Natural  Gas Services				Wholesale Propane Logistics				NGL Logistics				Other				Total
		(Millions)
Total operating revenue		$	597.7			$	308.9			$	14.5			$	—			$	921.1
Gross margin (a)		$	156.8			$	15.8			$	9.8			$	—			$	182.4
Operating and maintenance expense			(48.2	)			(8.3	)			(2.3	)			—				(58.8	)
Depreciation and amortization expense			(52.1	)			(1.6	)			(1.9	)			(0.1	)			(55.7	)
General and administrative expense			—				—				—				(25.0	)			(25.0	)
Step acquisition — equity interest re-measurement gain			—				—				9.1				—				9.1
Other income			1.0				—				—				—				1.0
Other income — affiliates			—				3.0				—				—				3.0
Earnings from unconsolidated affiliates			17.8				—				0.8				—				18.6
Interest expense			—				—				—				(22.0	)			(22.0	)
Income tax expense (b)			—				—				—				(0.5	)			(0.5	)
Net income (loss)			75.3				8.9				15.5				(47.6	)			52.1
Net income attributable to noncontrolling interests			(4.4	)			—				—				—				(4.4	)
Net income (loss) attributable to partners		$	70.9			$	8.9			$	15.5			$	(47.6	)		$	47.7
Non-cash derivative mark-to-market (c)		$	12.7			$	(1.1	)		$	—			$	—			$	11.6
Capital expenditures		$	32.1			$	0.3			$	4.7			$	—			$	37.1
Acquisitions, net of cash acquired		$	—			$	66.0			$	37.8			$	—			$	103.8
Investments in unconsolidated affiliates		$	0.7			$	—			$	—			$	—			$	0.7

 

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Nine Months Ended September 30, 2009

 

		Natural  Gas Services				Wholesale Propane Logistics				NGL Logistics				Other				Total
		(Millions)
Total operating revenue		$	407.2			$	228.2			$	6.7			$	—			$	642.1
Gross margin (a)		$	84.3			$	36.8			$	4.5			$	—			$	125.6
Operating and maintenance expense			(43.8	)			(7.6	)			(0.9	)			—				(52.3	)
Depreciation and amortization expense			(45.1	)			(1.0	)			(1.1	)			(0.1	)			(47.3	)
General and administrative expense			—				—				—				(23.6	)			(23.6	)
Earnings from unconsolidated affiliates			9.7				—				1.3				—				11.0
Interest income			—				—				—				0.3				0.3
Interest expense			—				—				—				(21.4	)			(21.4	)
Income tax expense (b)			—				—				—				(0.1	)			(0.1	)
Net income (loss)			5.1				28.2				3.8				(44.9	)			(7.8	)
Net income attributable to noncontrolling interests			(3.3	)			—				—				—				(3.3	)
Net income (loss) attributable to partners		$	1.8			$	28.2			$	3.8			$	(44.9	)		$	(11.1	)
Non-cash derivative mark-to-market (c)		$	(54.2	)		$	0.7			$	—			$	(0.2	)		$	(53.7	)
Capital expenditures		$	142.6			$	0.4			$	—			$	—			$	143.0
Acquisitions, net of cash acquired		$	(0.6	)		$	—			$	—			$	—			$	(0.6	)
Investments in unconsolidated affiliates		$	5.8			$	—			$	—			$	—			$	5.8

 

		September 30, 2010				December 31, 2009
		(Millions)
Segment long-term assets:
Natural Gas Services		$	1,150.5			$	1,185.2
Wholesale Propane Logistics (d)			101.6				53.2
NGL Logistics (d)			84.7				32.3
Other (e)			4.0				13.1
Total long-term assets			1,340.8				1,283.8
Current assets			158.4				197.7
Total assets		$	1,499.2			$	1,481.5

 

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(a)

Gross margin consists of total operating revenues, including commodity derivative activity, less purchases of natural gas, propane and NGLs. Gross margin is viewed as a non-GAAP measure under the rules of the SEC, but is included as a supplemental disclosure because it is a primary performance measure used by management as it represents the results of product sales versus product purchases. As an indicator of our operating performance, gross margin should not be considered an alternative to, or more meaningful than, net income or cash flow as determined in accordance with GAAP. Our gross margin may not be comparable to a similarly titled measure of another company because other entities may not calculate gross margin in the same manner.

(b)	Income tax expense relates primarily to the Texas margin tax and the Michigan business tax.

(c)	Non-cash commodity derivative mark-to-market is included in segment gross margin, along with cash settlements for our derivative contracts.

(d)	Long-term assets for our Wholesale Propane Logistics segment increased in 2010 as a result of our purchase of Atlantic Energy.

Long-term assets for our NGL Logistics segment increased in 2010 as a result of (1) the Wattenberg pipeline acquisition, and (2) an additional 50% interest in Black Lake from an affiliate of BP PLC, bringing our ownership interest in Black Lake to 100%. Prior to our acquisition of an additional 50% interest in Black Lake, we accounted for Black Lake under the equity method of accounting. Subsequent to this transaction we account for Black Lake as a consolidated subsidiary.

(e)	Other long-term assets not allocable to segments consist of restricted investments, unrealized gains on derivative instruments, corporate leasehold improvements and other long-term assets.

14. Supplemental Cash Flow Information

 

		Nine Months Ended September 30,
		2010				2009
		(Millions)
Cash paid for interest, net of amounts capitalized		$	6.7			$	7.8
Cash paid for income taxes, net of income tax refunds		$	0.5			$	0.5
Non-cash investing and financing activities:
Property, plant and equipment acquired with accounts payable		$	7.0			$	11.5
Other non-cash additions of property plant and equipment		$	0.5			$	2.3
Accounts payable related to acquisitions		$	1.9			$	—
Accounts payable related to equity issuance costs		$	0.1			$	—
Accounts payable related to debt issuance costs		$	0.4			$	—
Acquisition related contingent consideration		$	1.0			$	—

15. Supplementary Information — Condensed Consolidating Financial Information

The following condensed consolidating financial information presents the results of operations, financial position and cash flows of DCP Midstream Partners, LP, or parent guarantor, DCP Midstream Operating LP, or subsidiary issuer, which is a wholly owned subsidiary, and non-guarantor subsidiaries, as well as the consolidating adjustments necessary to present DCP Midstream Partners, LP’s results on a consolidated basis. In conjunction with the universal shelf registration statement on Form S-3 filed with the SEC on May 26, 2010, the parent guarantor has agreed to fully and unconditionally guarantee securities of the subsidiary issuer. For the purpose of the following financial information, investments in subsidiaries are reflected in accordance with the equity method of accounting. The financial information may not necessarily be indicative of results of operations, cash flows, or financial position had the subsidiaries operated as independent entities.

 

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		Condensed Consolidating Balance Sheets September 30, 2010
		Parent Guarantor				Subsidiary Issuer				Non-Guarantor Subsidiaries				Consolidating Adjustments				Consolidated
		(Millions)
ASSETS
Current assets:
Cash and cash equivalents		$	—			$	10.9			$	5.3			$	(4.4	)		$	11.8
Accounts receivable			—				—				103.1				—				103.1
Inventories			—				—				31.8				—				31.8
Other			—				—				11.7				—				11.7
Total current assets			—				10.9				151.9				(4.4	)			158.4
Property, plant and equipment, net			—				—				1,042.5				—				1,042.5
Goodwill and intangible assets, net			—				—				187.3				—				187.3
Advances receivable — consolidated subsidiaries			264.8				497.3				—				(762.1	)			—
Investments in consolidated subsidiaries			178.6				315.7				—				(494.3	)			—
Investments in unconsolidated affiliates			—				—				103.6				—				103.6
Other long term assets			—				2.0				5.4				—				7.4
Total assets		$	443.4			$	825.9			$	1,490.7			$	(1,260.8	)		$	1,499.2
LIABILITIES AND EQUITY
Accounts payable and other current liabilities		$	0.2			$	21.2			$	142.8			$	(4.4	)		$	159.8
Advances payable — consolidated subsidiaries			—				—				762.1				(762.1	)			—
Long-term debt			—				612.8				—				—				612.8
Other long-term liabilities			—				13.3				49.1				—				62.4
Total liabilities			0.2				647.3				954.0				(766.5	)			835.0
Commitments and contingent liabilities
Equity:
Partners’ equity
Net equity			443.2				211.3				316.2				(494.3	)			476.4
Accumulated other comprehensive loss			—				(32.7	)			(0.5	)			—				(33.2	)
Total partners’ equity			443.2				178.6				315.7				(494.3	)			443.2
Noncontrolling interests			—				—				221.0				—				221.0
Total equity			443.2				178.6				536.7				(494.3	)			664.2
Total liabilities and equity		$	443.4			$	825.9			$	1,490.7			$	(1,260.8	)		$	1,499.2

 

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		Condensed Consolidating Balance Sheets December 31, 2009
		Parent Guarantor				Subsidiary Issuer				Non-Guarantor Subsidiaries				Consolidating Adjustments				Consolidated
		(Millions)
ASSETS
Current assets:
Cash and cash equivalents		$	—			$	1.6			$	1.3			$	(0.8	)		$	2.1
Accounts receivable			—				—				152.5				—				152.5
Inventories			—				—				34.2				—				34.2
Other			—				0.1				8.8				—				8.9
Total current assets			—				1.7				196.8				(0.8	)			197.7
Restricted investments			—				10.0				—				—				10.0
Property, plant and equipment, net			—				—				1,000.1				—				1,000.1
Goodwill and intangible assets, net			—				—				152.6				—				152.6
Advances receivable — consolidated subsidiaries			245.8				520.0				—				(765.8	)			—
Investments in consolidated subsidiaries			131.9				245.3				—				(377.2	)			—
Investments in unconsolidated affiliates			—				—				114.6				—				114.6
Other long-term assets			—				0.6				5.9				—				6.5
Total assets		$	377.7			$	777.6			$	1,470.0			$	(1,143.8	)		$	1,481.5
LIABILITIES AND EQUITY
Accounts payable and other current liabilities		$	—			$	21.1			$	170.8			$	(0.8	)		$	191.1
Advances payable — consolidated subsidiaries			—				—				765.8				(765.8	)			—
Long-term debt			—				613.0				—				—				613.0
Other long-term liabilities			—				11.6				60.4				—				72.0
Total liabilities			—				645.7				997.0				(766.6	)			876.1
Commitments and contingent liabilities
Equity:
Partners’ equity
Net equity			377.7				163.0				246.1				(377.2	)			409.6
Accumulated other comprehensive loss			—				(31.1	)			(0.8	)			—				(31.9	)
Total partners’ equity			377.7				131.9				245.3				(377.2	)			377.7
Noncontrolling interests			—				—				227.7				—				227.7
Total equity			377.7				131.9				473.0				(377.2	)			605.4
Total liabilities and equity		$	377.7			$	777.6			$	1,470.0			$	(1,143.8	)		$	1,481.5

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

 

		Condensed Consolidating Statements of Operations Three Months Ended September 30, 2010
		Parent Guarantor				Subsidiary Issuer				Non-Guarantor Subsidiaries				Consolidating Adjustments				Consolidated
		(Millions)
Operating revenues:
Sales of natural gas, propane, NGLs and condensate		$	—			$	—			$	227.7			$	—			$	227.7
Transportation, processing and other			—				—				28.7				—				28.7
Losses from commodity derivative activity, net			—				—				(16.5	)			—				(16.5	)
Total operating revenues			—				—				239.9				—				239.9
Operating costs and expenses:
Purchases of natural gas, propane and NGLs			—				—				(200.2	)			—				(200.2	)
Operating and maintenance expense			—				—				(19.2	)			—				(19.2	)
Depreciation and amortization expense			—				—				(19.2	)			—				(19.2	)
General and administrative expense			—				(0.2	)			(8.0	)			—				(8.2	)
Step acquisition — equity interest re-measurement gain			—				—				9.1				—				9.1
Other income			—				—				0.5				—				0.5
Other income — affiliates			—				—				—				—				—
Total operating costs and expenses			—				(0.2	)			(237.0	)			—				(237.2	)
Operating (loss) income			—				(0.2	)			2.9				—				2.7
Interest expense, net			—				(7.5	)			—				—				(7.5	)
(Losses) income from consolidated subsidiaries			(4.1	)			3.6				—				0.5				—
Earnings from unconsolidated affiliates			—				—				4.1				—				4.1
(Losses) income before income taxes			(4.1	)			(4.1	)			7.0				0.5				(0.7	)
Income tax expense			—				—				(0.1	)			—				(0.1	)
Net (loss) income			(4.1	)			(4.1	)			6.9				0.5				(0.8	)
Net income attributable to noncontrolling interests			—				—				(3.3	)			—				(3.3	)
Net (loss) income attributable to partners		$	(4.1	)		$	(4.1	)		$	3.6			$	0.5			$	(4.1	)

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

 

		Condensed Consolidating Statements of Operations Three Months Ended September 30, 2009
		Parent Guarantor				Subsidiary Issuer				Non-Guarantor Subsidiaries				Consolidating Adjustments				Consolidated
		(Millions)
Operating revenues:
Sales of natural gas, propane, NGLs and condensate		$	—			$	—			$	178.1			$	—			$	178.1
Transportation, processing and other			—				—				24.2				—				24.2
Gains from commodity derivative activity, net			—				—				3.4				—				3.4
Total operating revenues			—				—				205.7				—				205.7
Operating costs and expenses:
Purchases of natural gas, propane and NGLs			—				—				(151.3	)			—				(151.3	)
Operating and maintenance expense			—				—				(19.0	)			—				(19.0	)
Depreciation and amortization expense			—				—				(16.4	)			—				(16.4	)
General and administrative expense			—				—				(7.9	)			—				(7.9	)
Total operating costs and expenses			—				—				(194.6	)			—				(194.6	)
Operating income			—				—				11.1				—				11.1
Interest expense, net			—				(7.0	)			(0.1	)			—				(7.1	)
Earnings from consolidated subsidiaries			9.9				16.9				—				(26.8	)			—
Earnings from unconsolidated affiliates			—				—				8.4				—				8.4
Net income			9.9				9.9				19.4				(26.8	)			12.4
Net income attributable to noncontrolling interests			—				—				(2.5	)			—				(2.5	)
Net income attributable to partners		$	9.9			$	9.9			$	16.9			$	(26.8	)		$	9.9

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

 

		Condensed Consolidating Statements of Operations Nine Months Ended September 30, 2010
		Parent Guarantor				Subsidiary Issuer				Non-Guarantor Subsidiaries				Consolidating Adjustments				Consolidated
		(Millions)
Operating revenues:
Sales of natural gas, propane, NGLs and condensate		$	—			$	—			$	826.1			$	—			$	826.1
Transportation, processing and other			—				—				83.0				—				83.0
Gains from commodity derivative activity, net			—				—				12.0				—				12.0
Total operating revenues			—				—				921.1				—				921.1
Operating costs and expenses:
Purchases of natural gas, propane and NGLs			—				—				(738.7	)			—				(738.7	)
Operating and maintenance expense			—				—				(58.8	)			—				(58.8	)
Depreciation and amortization expense			—				—				(55.7	)			—				(55.7	)
General and administrative expense			—				(0.2	)			(24.8	)			—				(25.0	)
Step acquisition — equity interest re-measurement gain			—				—				9.1				—				9.1
Other income			—				—				1.0				—				1.0
Other income — affiliates			—				—				3.0				—				3.0
Total operating costs and expenses			—				(0.2	)			(864.9	)			—				(865.1	)
Operating (loss) income			—				(0.2	)			56.2				—				56.0
Interest expense, net			—				(21.9	)			(0.1	)			—				(22.0	)
Earnings from consolidated subsidiaries			47.7				69.8				—				(117.5	)			—
Earnings from unconsolidated affiliates			—				—				18.6				—				18.6
Income before income taxes			47.7				47.7				74.7				(117.5	)			52.6
Income tax expense			—				—				(0.5	)			—				(0.5	)
Net income			47.7				47.7				74.2				(117.5	)			52.1
Net income attributable to noncontrolling interests			—				—				(4.4	)			—				(4.4	)
Net income attributable to partners		$	47.7			$	47.7			$	69.8			$	(117.5	)		$	47.7

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

 

		Condensed Consolidating Statements of Operations Nine Months Ended September 30, 2009
		Parent Guarantor				Subsidiary Issuer				Non-Guarantor Subsidiaries				Consolidating Adjustments				Consolidated
		(Millions)
Operating revenues:
Sales of natural gas, propane, NGLs and condensate		$	—			$	—			$	608.9			$	—			$	608.9
Transportation, processing and other			—				—				68.7				—				68.7
Losses from commodity derivative activity, net			—				—				(35.5	)			—				(35.5	)
Total operating revenues			—				—				642.1				—				642.1
Operating costs and expenses:
Purchases of natural gas, propane and NGLs			—				—				(516.5	)			—				(516.5	)
Operating and maintenance expense			—				—				(52.3	)			—				(52.3	)
Depreciation and amortization expense			—				—				(47.3	)			—				(47.3	)
General and administrative expense			—				—				(23.6	)			—				(23.6	)
Total operating costs and expenses			—				—				(639.7	)			—				(639.7	)
Operating income			—				—				2.4				—				2.4
Interest expense, net			—				(20.9	)			(0.2	)			—				(21.1	)
(Losses) earnings from consolidated subsidiaries			(11.1	)			9.8				—				1.3				—
Earnings from unconsolidated affiliates			—				—				11.0				—				11.0
(Loss) income before income taxes			(11.1	)			(11.1	)			13.2				1.3				(7.7	)
Income tax expense			—				—				(0.1	)			—				(0.1	)
Net (loss) income			(11.1	)			(11.1	)			13.1				1.3				(7.8	)
Net income attributable to noncontrolling interests			—				—				(3.3	)			—				(3.3	)
Net (loss) income attributable to partners		$	(11.1	)		$	(11.1	)		$	9.8			$	1.3			$	(11.1	)

 

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(Unaudited)

 

 

		Condensed Consolidating Statements of Cash Flows Nine Months Ended September 30, 2010
		Parent Guarantor				Subsidiary Issuer				Non-Guarantor Subsidiaries				Consolidating Adjustments				Consolidated
		(Millions)
OPERATING ACTIVITIES
Net cash (used in) provided by operating activities		$	(18.8	)		$	1.0			$	151.8			$	(3.6	)		$	130.4
INVESTING ACTIVITIES:
Capital expenditures			—				—				(37.1	)			—				(37.1	)
Acquisitions, net of cash acquired			—				—				(103.8	)			—				(103.8	)
Investments in unconsolidated affiliates			—				—				(0.7	)			—				(0.7	)
Proceeds from sale of assets			—				—				1.7				—				1.7
Return of investment from unconsolidated affiliate			—				—				1.2				—				1.2
Proceeds from sales of available-for-sale securities			—				10.1				—				—				10.1
Net cash provided by (used in) investing activities			—				10.1				(138.7	)			—				(128.6	)
FINANCING ACTIVITIES:
Proceeds from debt			—				658.2				—				—				658.2
Payments of debt			—				(658.4	)			—				—				(658.4	)
Payment of deferred financing costs			—				(1.6	)			—				—				(1.6	)
Proceeds from issuance of common units, net of offering costs			93.2				—				—				—				93.2
Distributions to unitholders and general partner			(74.4	)			—				—				—				(74.4	)
Distributions to noncontrolling interests			—				—				(16.0	)			—				(16.0	)
Contributions from noncontrolling interests			—				—				10.4				—				10.4
Purchase of additional interest in a subsidiary			—				—				(3.5	)			—				(3.5	)
Net cash provided by (used in) financing activities			18.8				(1.8	)			(9.1	)			—				7.9
Net change in cash and cash equivalents			—				9.3				4.0				(3.6	)			9.7
Cash and cash equivalents, beginning of period			—				1.6				1.3				(0.8	)			2.1
Cash and cash equivalents, end of period		$	—			$	10.9			$	5.3			$	(4.4	)		$	11.8

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

 

		Condensed Consolidating Statements of Cash Flows Nine Months Ended September 30, 2009
		Parent Guarantor				Subsidiary Issuer				Non-Guarantor Subsidiaries				Consolidating Adjustments				Consolidated
		(Millions)
OPERATING ACTIVITIES
Net cash provided by (used in) operating activities		$	62.8			$	(30.5	)		$	63.1			$	(0.3	)		$	95.1
INVESTING ACTIVITIES:
Capital expenditures			—				—				(143.0	)			—				(143.0	)
Acquisitions, net of cash acquired			—				—				0.6				—				0.6
Investments in unconsolidated affiliates			—				—				(5.8	)			—				(5.8	)
Proceeds from sale of assets			—				—				0.3				—				0.3
Purchase of available-for-sale securities			—				(1.1	)			—				—				(1.1	)
Proceeds from sales of available-for-sale securities			—				51.1				—				—				51.1
Net cash provided by (used in) investing activities			—				50.0				(147.9	)			—				(97.9	)
FINANCING ACTIVITIES:
Proceeds from debt			—				113.7				—				—				113.7
Payments of debt			—				(157.2	)			—				—				(157.2	)
Net change in advances to predecessor from DCP Midstream, LLC			—				—				3.0				—				3.0
Distributions to unitholders and general partner			(62.8	)			—				—				—				(62.8	)
Distributions to noncontrolling interests			—				—				(15.4	)			—				(15.4	)
Contributions from noncontrolling interests			—				—				71.8				—				71.8
Contributions from DCP Midstream, LLC			—				—				0.7				—				0.7
Net cash (used in) provided by financing activities			(62.8	)			(43.5	)			60.1				—				(46.2	)
Net change in cash and cash equivalents			—				(24.0	)			(24.7	)			(0.3	)			(49.0	)
Cash and cash equivalents, beginning of period			—				26.6				35.6				(0.3	)			61.9
Cash and cash equivalents, end of period		$	—			$	2.6			$	10.9			$	(0.6	)		$	12.9

 

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16. Subsequent Events

On November 4, 2010, we entered into agreements with DCP Midstream, LLC, to acquire a 33.33% interest in the DCP Southeast Texas business for $150 million. The DCP Southeast Texas business is a fully integrated midstream business which includes: 675 miles of natural gas pipelines; three natural gas processing plants totaling 350 MMcf/d of processing capacity; natural gas storage assets with 9 Bcf of existing storage capacity; and NGL market deliveries direct to Exxon Mobil and to Mont Belvieu via our Black Lake NGL pipeline. The terms of the joint venture agreement provide that distributions to us for the first seven years related to storage and transportation gross margin will be pursuant to a fee-based arrangement, based on storage capacity and tailgate volumes. Distributions related to the gathering and processing business, along with reductions for all expenditures, will be pursuant to our and DCP Midstream, LLC’s respective ownership interests in the DCP Southeast Texas business. This acquisition is expected to close in January 2011.

On October 26, 2010, the board of directors of the General Partner declared a quarterly distribution of $0.61 per unit, payable on November 12, 2010 to unitholders of record on November 5, 2010.

 

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Item 2.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion analyzes our financial condition and results of operations. You should read the following discussion of our financial condition and results of operations in conjunction with our condensed consolidated financial statements and notes included elsewhere in this Form 10-Q and the consolidated financial statements and notes thereto included in our 2009 Form 10-K.

Overview

We are a Delaware limited partnership formed by DCP Midstream, LLC to own, operate, acquire and develop a diversified portfolio of complementary midstream energy assets. Our operations are organized into three business segments; Natural Gas Services, Wholesale Propane Logistics and NGL Logistics.

The financial information contained herein includes, for each period presented, our accounts, and the assets, liabilities and operations of our additional 25.1% limited liability company interest in East Texas acquired from DCP Midstream, LLC in April 2009, and of Black Lake, prior to our acquisition of an additional 5% limited liability company interest from DCP Midstream, LLC in July 2010, in transactions among entities under common control, which we refer to collectively as our “predecessor.” Transfers of net assets between entities under common control are accounted for as if the transfer occurred at the beginning of the period, and prior years are retroactively adjusted to furnish comparative information similar to the pooling method. Prior to our acquisition of an additional 25.1% limited liability company interest in East Texas from DCP Midstream, LLC in April 2009, we owned a 25% limited liability company interest in East Texas, which we accounted for under the equity method of accounting. Subsequent to this transaction we own a 50.1% limited liability interest in East Texas, and account for East Texas as a consolidated subsidiary. Accordingly, our financial information includes the historical results of our predecessor for all periods presented.

In 2010 we have continued to experience improvements in the business environment compared to our experience in 2009. Crude oil and NGL prices have generally remained at favorable levels, although natural gas prices continue to decline and remain lower than recent historical prices. With the exception of certain emerging gas shale regions where drilling activity remains high, the lower natural gas prices are resulting in significantly reduced drilling activity in areas where the gas has a relatively lower liquid content. Gas production in regions with low liquid content receive less price uplift from the relatively higher crude and NGL prices.

During January and February, we experienced near record cold weather, causing operating challenges at our East Texas and North Louisiana plants, creating periods of low NGL recoveries and volume curtailments due to plant shut downs and producer wellhead freeze offs.

During the second and third quarters we had an extended planned outage related to an inspection at our Providence wholesale propane terminal, with lower unit margins resulting from the associated logistics of shifting inventory and sales volumes to our other terminals. Providence is scheduled to resume the distribution of propane during the fourth quarter of 2010. Earlier in the year warmer weather and an early spring, tempered propane sales volumes. This was partially offset by the cash payment we received in conjunction with an amendment to an existing propane supply contract.

Improvements in the business environment along with opportunities in the market enabled us to continue to execute on our growth objectives in 2010 through a series of fee-based acquisitions and capital projects around our existing footprint. In January, we completed an acquisition of our Wattenberg fee-based NGL pipeline and announced a related expansion capital project. In July we acquired an additional 55% interest in our Black Lake fee-based NGL pipeline, bringing our ownership interest in Black Lake to 100%. In July, we also closed on an acquisition which expanded our existing northeast U.S. wholesale propane logistics business into the mid-Atlantic region through the addition of a marine import terminal and storage facility in the Port of Chesapeake, Virginia.

On November 4, 2010, we entered into agreements with DCP Midstream, LLC, to acquire a 33.33% interest in the DCP Southeast Texas business for $150 million. The DCP Southeast Texas business is a fully integrated midstream business which includes: 675 miles of natural gas pipelines; three natural gas processing plants totaling 350 MMcf/d of processing capacity; natural gas storage assets with 9 Bcf of existing storage capacity; and NGL market deliveries direct to Exxon Mobil and to Mont Belvieu via our Black Lake NGL pipeline. The terms of the joint venture agreement provide that distributions to us for the first seven years related to storage and transportation gross margin will be pursuant to a fee-based arrangement, based on storage capacity and tailgate volumes. Distributions related to the gathering and processing business, along with reductions for all expenditures, will be pursuant to our and DCP Midstream, LLC’s respective ownership interests in the DCP Southeast Texas business. This acquisition is expected to close in January 2011. The transaction is consistent with our growth strategy and provides additional diversification of our asset portfolio, geography and resource exposure.

 

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In conjunction with our general partner, DCP Midstream, LLC, in May 2010, we signed a non-binding letter of intent with EQT Corporation, or EQT, to create a natural gas processing and related NGL infrastructure joint venture to serve EQT and third party producers in the Marcellus and Huron shale areas of the Appalachian basin. Since that time, DCP Midstream, LLC, we and EQT have evaluated a number of alternative transaction structures in addition to the originally proposed joint venture structure, to address EQT’s processing needs. The parties are currently discussing possible terms associated with alternative transaction structures. There can be no assurance that we will be able to consummate a transaction with EQT.

We are continuing to integrate the Michigan gathering and treating system we acquired in November 2009, the Wattenberg NGL pipeline acquisition, the Atlantic Energy acquisition and our acquisition of an additional 55% interest in Black Lake. Our integration efforts are progressing according to plan. The Wattenberg capital expansion project, which we expect to complete in early 2011, is also progressing on plan.

Results for the first three quarters of the year were in line with our previously provided 2010 forecast. In October 2010, we announced a quarterly distribution of $0.61 per limited partner unit. The distribution reflects our business results as well as our recent execution on growth opportunities.

General Trends and Outlook

In 2010, our strategic objectives will continue to focus on maintaining stable distributable cash flows from our existing assets and executing on growth opportunities to increase our distributable cash flows. We believe the key elements to stable distributable cash flows are the diversity of our asset portfolio, our significant fee-based business representing over 50% of our estimated margins, and our highly hedged commodity position, the objective of which is to protect downside risk in our distributable cash flows.

We incur capital expenditures for our consolidated entities and our unconsolidated affiliates. We anticipate maintenance capital expenditures of between $5 million and $10 million, and expenditures for expansion capital improvements of between $25 million and $30 million, including expenditures associated with the recently acquired Wattenberg pipeline, for the year ending December 31, 2010. The board of directors may approve additional growth capital during the year, at their discretion. This capital does not include any acquisitions or additional investment opportunities that may be identified throughout the course of the year and approved by our management and our board of directors.

During the remainder of 2010, and into 2011 we expect to continue to pursue a multi-faceted growth strategy, including executing on organic opportunities around our footprint, third party acquisitions, and periodic dropdowns from our sponsors in order to grow our distributable cash flows. We also plan to continue to integrate our recent acquisitions and execute on the Wattenberg pipeline expansion project.

We anticipate our business to continue to be affected by the following key trends. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about or interpretations of available information prove to be incorrect, our actual results may vary materially from our expected results.

Natural Gas Gathering and Processing Margins — Except for our fee-based contracts, which may be impacted by throughput volumes, our natural gas gathering and processing profitability is dependent upon commodity prices, natural gas supply, and demand for natural gas, NGLs and condensate. Commodity prices, which are impacted by the balance between supply and demand, have historically been volatile. Throughput volumes could decline further should natural gas prices and drilling levels continue to experience weakness. Our long-term view is that as economic conditions improve, natural gas prices should return to a level that would support continued natural gas production in the United States. During the first three quarters of 2010, petrochemical demand remained strong for NGLs as NGLs are a lower cost feedstock when compared to crude oil derived feedstocks.

 

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Wholesale Propane Supply and Demand — Due to our multiple propane supply sources, propane supply contractual arrangements, significant storage capabilities, and multiple terminal locations for wholesale propane delivery, we are generally able to provide our retail propane distribution customers with reliable supplies of propane during peak demand periods of tight supply, usually in the winter months when their retail customers consume the most propane for home heating. We expect propane demand to continue to be negatively impacted during the remainder of 2010 from the current recessionary environment. During the second and third quarters we had an extended planned outage related to an inspection at our Providence wholesale propane terminal, with lower unit margins resulting from the associated logistics of shifting inventory and sales volumes to our other terminals. Providence is scheduled to resume the distribution of propane during the fourth quarter of 2010.

For an in-depth discussion of factors that may significantly affect our results, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Factors That May Significantly Affect Our Results” in our 2009 Form 10-K.

Recent Events

On November 4, 2010, we entered into agreements with DCP Midstream, LLC, to acquire a 33.33% interest in the DCP Southeast Texas business for $150 million. The DCP Southeast Texas business is a fully integrated midstream business which includes: 675 miles of natural gas pipelines; three natural gas processing plants totaling 350 MMcf/d of processing capacity; natural gas storage assets with 9 Bcf of existing storage capacity; and NGL market deliveries direct to Exxon Mobil and to Mont Belvieu via our Black Lake NGL pipeline. The terms of the joint venture agreement provide that distributions to us for the first seven years related to storage and transportation gross margin will be pursuant to a fee-based arrangement, based on storage capacity and tailgate volumes. Distributions related to the gathering and processing business, along with reductions for all expenditures, will be pursuant to our and DCP Midstream, LLC’s respective ownership interests in the DCP Southeast Texas business. This acquisition is expected to close in January 2011. The transaction is consistent with our growth strategy and provides additional diversification of our asset portfolio, geography and resource exposure. The acquisition is subject to customary closing conditions and there is no assurance that it will be completed or that the anticipated benefits of the acquisition will be realized.

On October 26, 2010, the board of directors of the General Partner declared a quarterly distribution of $0.61 per unit, payable on November 12, 2010 to unitholders of record on November 5, 2010.

On September 30, 2010, we issued $250 million of our 3.25% Senior Notes due October 1, 2015. We received net proceeds, after deducting underwriting discounts and estimated offering expenses, of $247.8 million, which we used to repay funds borrowed under the revolver portion of our Credit Facility. Interest on the notes will be paid semi-annually on April 1 and October 1 of each year, commencing April 1, 2011. The notes will mature on October 1, 2015 unless redeemed prior to maturity.

Our Westfield, Massachusetts propane facility, or the Westfield facility, was temporarily closed as a result of a Cease and Desist order issued by the Commonwealth of Massachusetts Fire Marshal Office on August 31, 2010. The Cease and Desist order was issued in connection with an investigation into the presence and levels of odorant in propane supplies received by and distributed from the Westfield facility that was commenced following a propane tank explosion that resulted in one fatality. The propane involved may have been supplied from the Westfield facility. The Cease and Desist order was lifted on September 20, 2010 and the Westfield facility resumed operations. The investigation by the Massachusetts Attorney General’s office has concluded. An independent investigator found that there was no direct evidence that any propane containing an insufficient quantity of odorant was shipped from the Westfield facility. An attorney representing the estate of the deceased has put us on notice of an intent to bring legal action in the explosion. We intend to vigorously defend any such legal action. It is not possible to predict whether we will incur any liability or to estimate the damages, if any, we might incur in connection with this matter. Management does not believe the ultimate resolution of this issue will have a material adverse effect on our consolidated results of operations, financial position or cash flows.

In September 2010, Magnum Hunter Resources Corporation’s, or Magnum Hunter’s, wholly owned subsidiary, Eureka Hunter Pipeline, LLC, or Eureka Hunter Pipeline, and we, along with DCP Midstream, LLC, had entered into a non-binding letter of intent to create a natural gas gathering joint venture between Eureka Hunter Pipeline, DCP Midstream, LLC and us for the gathering of natural gas in the West Virginia and Ohio regions of the Marcellus Shale. The proposed gathering joint venture will construct, own and operate certain natural gas gathering assets for natural gas produced in Western West Virginia and Eastern Ohio. The gas gathering capacity of the initial facilities is expected to be approximately 200 MMcf/d. Magnum Hunter will own 50% of the proposed gathering joint venture and DCP Midstream, LLC and we will own the other 50% of the proposed gathering joint venture.

In August 2010, we issued 2,990,000 common units at $32.57 per unit. We received proceeds of $93.1 million, net of offering costs.

 

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On July 30, 2010, we acquired Atlantic Energy, a wholly owned subsidiary of UGI Corporation, for $49.0 million plus propane inventory and other working capital of $17.3 million. We have incurred post-closing purchase price adjustments for net working capital of $1.9 million, which we have accrued in other current liabilities in our condensed consolidated balance sheet as of September 30, 2010. Atlantic Energy has a contractual agreement with Spectra Energy, the supplier of the acquired propane inventory, in which the final price of the acquired inventory will be determined based upon index rates at established future dates. Atlantic Energy’s sales agreements specify floating pricing terms in excess of the floating pricing terms established in the contractual agreement with Spectra. The acquisition was financed with borrowings under our revolving credit facility. Atlantic Energy owns and operates a marine import terminal with 20 million gallons of above ground storage in the Port of Chesapeake, Virginia. The assets serve as a supply point for propane customers in the mid-Atlantic region, and will extend our existing northeast U.S. wholesale propane business into the mid-Atlantic. This acquisition provides us with an excellent opportunity to expand our existing market position as one of the largest wholesale propane suppliers in the northeast. One of the keys to our success in the wholesale propane business has been the breadth of our supply options. The addition of the Chesapeake assets will build on our supply and logistics capabilities and help in continuing to ensure reliable deliveries to our customers.

On July 30, 2010, we acquired an additional 50% interest in Black Lake from an affiliate of BP PLC, for $15.1 million in cash, financed with borrowings under our revolving credit facility, bringing our ownership interest in Black Lake to 100%. Prior to our acquisition of an additional 50% interest in Black Lake from an affiliate of BP PLC, we accounted for Black Lake under the equity method of accounting. Subsequent to this transaction we account for Black Lake as a consolidated subsidiary.

On July 27, 2010, we acquired an additional 5% interest in Black Lake from DCP Midstream, LLC for $1.5 million in cash, financed with borrowings under our revolving credit facility, in a transaction among entities under common control.

On May 27, 2010, we announced along with EQT and DCP Midstream, LLC that we have signed a non-binding letter of intent, to create a natural gas processing and related natural gas liquid, or NGL, joint venture to serve EQT and third party producers in the Marcellus and Huron shale areas of the Appalachian basin, two of the country’s most active shale plays. Since that time, DCP Midstream, LLC, we and EQT have evaluated a number of alternative transaction structures in addition to the originally proposed joint venture structure, to address EQT’s processing needs. The parties are currently discussing possible terms associated with alternative transaction structures. There can be no assurance that we will be able to consummate a transaction with EQT.

In January 2010, we acquired the Wattenberg pipeline from Buckeye Partners, L.P., for $22.0 million in cash, funded with borrowings under our revolving credit facility. The 350-mile pipeline originates in the Denver-Julesburg, or DJ, Basin in Colorado and terminates near the Conway hub in Bushton, Kansas. The pipeline is currently utilized by DCP Midstream, LLC as a market outlet for NGL production from certain of their plants in the DJ Basin. We expect to spend approximately $18.0 million during 2010 in expansion capital improvements to connect and integrate the acquired pipeline with DCP Midstream, LLC’s facilities, with cash flow contributions commencing in early 2011. In conjunction with our acquisition of the Wattenberg pipeline, we signed a transportation agreement with DCP Midstream, LLC pursuant to fee-based rates that will be applied to the volumes transported. The agreement is effective through November 2010, renewing on an evergreen basis thereafter. We have also agreed to the terms of an additional ten-year transportation agreement with DCP Midstream, LLC. The acquired pipeline will generate 100 percent fee-based revenues, with the results of the assets being included in our NGL logistics segment prospectively, from the date of acquisition.

Reconciliation of Non-GAAP Measures

Gross Margin, Segment Gross Margin and Adjusted Segment Gross Margin — We view our gross margin as an important performance measure of the core profitability of our operations. We review our gross margin monthly for consistency and trend analysis.

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. As an indicator of our operating performance, gross margin, segment gross margin and adjusted segment gross margin should not be considered an alternative to, or more meaningful than, net income or loss, net income or loss attributable to partners, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP.

 

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Our 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. The following table sets forth our reconciliation of certain non-GAAP measures:

 

		Three Months  Ended September 30,								Nine Months  Ended September 30,
		2010				2009				2010				2009
		(Millions)
Reconciliation of Non-GAAP Measures
Reconciliation of net (loss) income attributable to partners to gross margin:
Net (loss) income attributable to partners		$	(4.1	)		$	9.9			$	47.7			$	(11.1	)
Interest expense			7.5				7.1				22.0				21.4
Income tax expense			0.1				—				0.5				0.1
Operating and maintenance expense			19.2				19.0				58.8				52.3
Depreciation and amortization expense			19.2				16.4				55.7				47.3
General and administrative expense			8.2				7.9				25.0				23.6
Step acquisition — equity interest re-measurement gain			(9.1	)			—				(9.1	)			—
Other income			(0.5	)			—				(1.0	)			—
Other income — affiliates			—				—				(3.0	)			—
Interest income			—				—				—				(0.3	)
Earnings from unconsolidated affiliates			(4.1	)			(8.4	)			(18.6	)			(11.0	)
Net income attributable to noncontrolling interests			3.3				2.5				4.4				3.3
Gross margin		$	39.7			$	54.4			$	182.4			$	125.6
Non-cash commodity derivative mark-to-market (a)		$	(18.5	)		$	0.3			$	11.6			$	(53.5	)

 

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		Three Months  Ended September 30,								Nine Months  Ended September 30,
		2010				2009				2010				2009
		(Millions)
Reconciliation of Non-GAAP Measures
Reconciliation of segment net income (loss) attributable to partners to segment gross margin:
Natural Gas Services segment:
Segment net income attributable to partners		$	1.8			$	20.8			$	70.9			$	1.8
Operating and maintenance expense			15.0				16.1				48.2				43.8
Depreciation and amortization expense			17.3				15.8				52.1				45.1
Other income			(0.5	)			—				(1.0	)			—
Earnings from unconsolidated affiliates			(4.1	)			(7.9	)			(17.8	)			(9.7	)
Net income attributable to noncontrolling interests			3.3				2.5				4.4				3.3
Segment gross margin		$	32.8			$	47.3			$	156.8			$	84.3
Non-cash commodity derivative mark-to-market (a)		$	(18.0	)		$	(0.3	)		$	12.7			$	(54.2	)
Wholesale Propane Logistics segment:
Segment net (loss) income attributable to partners		$	(1.1	)		$	2.4			$	8.9			$	28.2
Operating and maintenance expense			3.1				2.5				8.3				7.6
Depreciation and amortization expense			1.0				0.3				1.6				1.0
Other income — affiliates			—				—				(3.0	)			—
Segment gross margin		$	3.0			$	5.2			$	15.8			$	36.8
Non-cash commodity derivative mark-to-market (a)		$	(0.5	)		$	0.6			$	(1.1	)		$	0.7
NGL Logistics segment:
Segment net income attributable to partners		$	11.1			$	1.7			$	15.5			$	3.8
Operating and maintenance expense			1.1				0.4				2.3				0.9
Depreciation and amortization expense			0.8				0.3				1.9				1.1
Step acquisition — equity interest re-measurement gain			(9.1	)			—				(9.1	)			—
Earnings from unconsolidated affiliates			—				(0.5	)			(0.8	)			(1.3	)
Segment gross margin		$	3.9			$	1.9			$	9.8			$	4.5

 

(a)	Non-cash commodity derivative mark-to-market is included in segment gross margin, along with cash settlements for our derivative contracts.

Adjusted EBITDA and Distributable Cash Flow — We define adjusted EBITDA as net income or loss attributable to partners less interest income, noncontrolling interest in depreciation and income tax expense and non-cash commodity derivative gains, plus interest expense, income tax expense, depreciation and amortization expense and non-cash commodity derivative losses. Adjusted EBITDA is used as a supplemental liquidity and performance measure 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;

 

•

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.

Our adjusted EBITDA may not be comparable to a similarly titled measure of another company because other entities may not calculate this measure in the same manner.

 

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Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income or loss, net income or loss attributable to partners, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP as measures of operating performance, liquidity or ability to service debt obligations.

We define Distributable Cash Flow as net cash provided by or used in operating activities, less maintenance capital expenditures, net of reimbursable projects, plus or minus adjustments for non-cash mark-to-market of derivative instruments, proceeds from divestiture of assets, net income attributable to noncontrolling interest net of depreciation and income tax, net changes in operating assets and liabilities, and other adjustments to reconcile net cash provided by or used in operating activities (see “— Liquidity and Capital Resources” for further definition of maintenance capital expenditures). 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 or revenues. 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 and performance 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. Our Distributable Cash Flow may not be comparable to a similarly titled measure of another company because other entities may not calculate Distributable Cash Flow in the same manner.

Critical Accounting Policies and Estimates

Our critical accounting policies and estimates are described in Item 7 in our 2009 Form 10-K. The accounting policies and estimates used in preparing our interim condensed consolidated financial statements for the three and nine months ended September 30, 2010 are the same as those described in our 2009 Form 10-K.

 

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Results of Operations

Consolidated Overview

The following table and discussion is a summary of our consolidated results of operations for the three and nine months ended September 30, 2010 and 2009. The results of operations by segment are discussed in further detail following this consolidated overview discussion:

 

		Three Months Ended September 30,								Nine Months Ended September 30,								Variance Three Months 2010 vs. 2009								Variance Nine Months 2010 vs. 2009
																		Increase								Increase
		2010 (a)(b)				2009 (b)				2010 (a)(b)				2009 (b)				(Decrease)				Percent				(Decrease)				Percent
		(Millions, except as indicated)
Operating revenues:
Natural Gas Services (c)		$	167.9			$	154.1			$	597.7			$	407.2			$	13.8				9	%		$	190.5				47	%
Wholesale Propane Logistics			65.9				48.5				308.9				228.2				17.4				36	%			80.7				35	%
NGL Logistics			6.1				3.1				14.5				6.7				3.0				97	%			7.8				116	%
Total operating revenues			239.9				205.7				921.1				642.1				34.2				17	%			279.0				43	%
Gross margin (d):
Natural Gas Services			32.8				47.3				156.8				84.3				(14.5	)			(31	)%			72.5				86	%
Wholesale Propane Logistics			3.0				5.2				15.8				36.8				(2.2	)			(42	)%			(21.0	)			(57	)%
NGL Logistics			3.9				1.9				9.8				4.5				2.0				105	%			5.3				118	%
Total gross margin			39.7				54.4				182.4				125.6				(14.7	)			(27	)%			56.8				45	%
Operating and maintenance expense			(19.2	)			(19.0	)			(58.8	)			(52.3	)			0.2				1	%			6.5				12	%
Depreciation and amortization expense			(19.2	)			(16.4	)			(55.7	)			(47.3	)			2.8				17	%			8.4				18	%
General and administrative expense			(8.2	)			(7.9	)			(25.0	)			(23.6	)			0.3				4	%			1.4				6	%
Step acquisition — equity interest re-measurement gain			9.1				—				9.1				—				9.1				100	%			9.1				100	%
Other income			0.5				—				1.0				—				0.5				100	%			1.0				100	%
Other income — affiliates			—				—				3.0				—				—				—	%			3.0				100	%
Earnings from unconsolidated affiliates (e)			4.1				8.4				18.6				11.0				(4.3	)			(51	)%			7.6				69	%
Interest income			—				—				—				0.3				—				—	%			(0.3	)			(100	)%
Interest expense			(7.5	)			(7.1	)			(22.0	)			(21.4	)			0.4				6	%			0.6				3	%
Income tax expense			(0.1	)			—				(0.5	)			(0.1	)			0.1				100	%			0.4				400	%
Net income attributable to noncontrolling interests			(3.3	)			(2.5	)			(4.4	)			(3.3	)			0.8				32	%			1.1				33	%
Net (loss) income attributable to partners		$	(4.1	)		$	9.9			$	47.7			$	(11.1	)		$	(14.0	)			*			$	58.8				*
Other data:
Non-cash commodity derivative mark-to-market		$	(18.5	)		$	0.3			$	11.6			$	(53.5	)		$	(18.8	)			*			$	65.1				*
Natural gas throughput (MMcf/d) (e)			1,168				1,111				1,164				1,071				57				5	%			93				9	%
NGL gross production (Bbls/d) (e)			32,882				30,843				33,200				27,086				2,039				7	%			6,114				23	%
Propane sales volume (Bbls/d)			14,086				12,435				20,165				21,146				1,651				13	%			(981	)			(5	)%
NGL pipelines throughput (Bbls/d) (e)			41,392				32,417				39,004				27,745				8,975				28	%			11,259				41	%

 

*	Percentage change is not meaningful.

 

(a)

Includes the results of certain companies that held natural gas gathering and treating assets purchased from MichCon Pipeline Company since November 24, 2009, the date of acquisition, in our Natural Gas Services segment.

Includes the results of Atlantic Energy, since July 30, 2010, the date of acquisition, in our Wholesale Propane Logistics segment.

 

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Includes the results of our Wattenberg pipeline acquired from Buckeye Partners, L.P, since January 28, 2010, the date of acquisition, and an additional 50% interest in Black Lake acquired from an affiliate of BP PLC, since July 30, the date of acquisition, in our NGL Logistics segment. The acquisition of an additional 50% interest in Black Lake brought our ownership interest in Black Lake to 100%. Prior to our acquisition of an additional 50% interest in Black Lake, we accounted for Black Lake under the equity method of accounting. Subsequent to this transaction we account for Black Lake as a consolidated subsidiary.

 

(b)

We utilize commodity derivative instruments to provide stability to distributable cash flows for our proportionate ownership in East Texas as well as all other natural gas services assets, the portion of East Texas owned by DCP Midstream, LLC is unhedged. As such, our consolidated results depict 75% of East Texas unhedged in all periods prior to the second quarter of 2009 and 49.9% of East Texas unhedged for all periods subsequent to the first quarter of 2009.

 

(c)

Includes the effect of the acquisition of the NGL Hedge, contributed by DCP Midstream, LLC in April 2009. The NGL Hedge is a fixed price natural gas liquids derivative by NGL component, which commenced in April 2009 and expired in March 2010.

 

(d)

Gross margin consists of total operating revenues, including commodity derivative activity, less purchases of natural gas, propane and NGLs, and segment gross margin for each segment consists of total operating revenues for that segment, less commodity purchases for that segment. Please read “Reconciliation of Non-GAAP Measures” above.

 

(e)

Includes our proportionate share of the throughput volumes and NGL production of Collbran, Jackson Pipeline Company, or Jackson, East Texas, and Discovery and our proportionate earnings of Discovery. Earnings for Discovery include the accretion of the net difference between the carrying amount of the investment and the underlying equity of the investment.

For periods prior to July 30, 2010, includes our 50% share of the throughput volumes and earnings for Black Lake. Black Lake’s earnings included the accretion of the net difference between the carrying amount of the investment and the underlying equity of the investment.

Three Months Ended September 30, 2010 vs. Three Months Ended September 30, 2009

Total Operating Revenues — Total operating revenues increased in 2010 compared to 2009, primarily as a result of the following:

 

•

$30.0 million increase primarily attributable to higher commodity prices, which impact both sales and purchases, partially offset by changes in contract mix, increased fuel consumption and differences in gas quality at certain of our assets for our Natural Gas Services segment;

 

•

$18.8 million increase primarily attributable to increased propane sales volumes, primarily as a result of the Atlantic Energy acquisition, as well as higher propane prices, which impact both sales and purchases for our Wholesale Propane Logistics segment; and

 

•

$4.5 million increase in transportation, processing and other revenue, which represents our fee-based revenues, primarily as a result of increased throughput volumes due to our Michigan and Wattenberg pipeline acquisitions, as well as our acquisition of an additional 50% interest in Black Lake.

These increases were partially offset by:

 

•

$19.9 million decrease related to commodity derivative activity. This decrease includes an increase in unrealized losses of $19.1 million due to movements in forward prices of commodities, and a decrease in realized cash settlement gains of $0.8 million due to generally higher average prices of commodities in 2010.

Gross Margin — Gross margin decreased in 2010 compared to 2009, primarily as a result of the following:

 

•

$14.5 million decrease for our Natural Gas Services segment, primarily related to commodity derivative activity as explained in the operating revenues section above, reduced natural gas basis spreads, increased fuel consumption and differences in gas quality at certain of our assets. These decreases were partially offset by higher commodity prices and increased fee-based throughput volumes resulting from the Michigan acquisition; and

 

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•

$2.2 million decrease for our Wholesale Propane Logistics segment, primarily as a result of our planned outage related to our Providence terminal inspection, as well as commodity derivative activity, partially offset by increased volumes from our acquisition of Atlantic Energy.

These decreases were partially offset by:

 

•

$2.0 million increase for our NGL Logistics segment, primarily as a result of higher volumes from the Wattenberg pipeline acquisition, as well as our acquisition of an additional 50% interest in Black Lake.

Operating and Maintenance Expense — Operating and maintenance expense increased in 2010 compared to 2009, primarily as a result of our Michigan acquisition, our Wattenberg pipeline acquisition, as well as our acquisition of an additional 50% interest in Black Lake, partially offset by timing of expenditures.

Depreciation and Amortization Expense — Depreciation and amortization expense increased in 2010 compared to 2009, primarily as a result of our capital projects completed in 2009, our Atlantic Energy acquisition, our Michigan acquisition, our Wattenberg pipeline acquisition and our acquisition of an additional 50% interest in Black Lake.

Step acquisition — equity interest re-measurement gain — Step acquisition — equity interest re-measurement gain results from our acquisition of an additional 50% interest in Black Lake, bringing our ownership interest in Black Lake to 100% in our NGL Logistics segment. Prior to our acquisition of an additional 50% interest in Black Lake, we accounted for Black Lake under the equity method of accounting. Subsequent to this transaction we account for Black Lake as a consolidated subsidiary. As a result of acquiring an additional 50% interest in Black Lake, we remeasured our initial 50% equity interest in Black Lake to its fair value, and recognized a gain of $9.1 million.

Earnings from Unconsolidated Affiliates — Earnings from unconsolidated affiliates decreased in 2010 compared to 2009, primarily as a result of decreased earnings from Discovery. Settlements related to our commodity derivatives on our unconsolidated affiliates are included in segment gross margin.

Net income attributable to noncontrolling interests — Net income attributable to noncontrolling interests includes the impact of organic growth from our Piceance Basin expansion project, partially offset by increased fuel consumption and differences in gas quality at East Texas in 2010.

Nine Months Ended September 30, 2010 vs. Nine Months Ended September 30, 2009

Total Operating Revenues — Total operating revenues increased in 2010 compared to 2009, primarily as a result of the following:

 

•

$132.4 million increase primarily attributable to higher commodity prices, which impact both sales and purchases, and an increase in NGL production, partially offset by changes in contract mix, increased fuel consumption, differences in gas quality, the impact of volume curtailments due to plant shutdowns and producer wellhead freeze offs as a result of near record cold weather at East Texas and North Louisiana in the first quarter, as well as a decrease in natural gas sales volumes across certain assets. 2009 results include the first quarter impact of a third party owned pipeline rupture, resulting in a fire at East Texas and our Wyoming pipeline integrity and system enhancement project;

 

•

$82.0 million increase primarily attributable to higher propane prices, which impact both sales and purchases, partially offset by decreased sales volumes for our Wholesale Propane Logistics segment;

 

•

$47.5 million increase related to commodity derivative activity. This increase includes an increase in unrealized gains of $64.7 million due to movements in forward prices of commodities, partially offset by a decrease in realized cash settlement gains of $17.2 million due to generally higher average prices of commodities in 2010; and

 

•

$14.3 million increase in transportation, processing and other revenue, which represents our fee-based revenues, primarily as a result of increased throughput volumes due to our Michigan and Wattenberg acquisitions, our acquisition of an additional 50% interest in Black Lake, as well as changes in contract mix.

 

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Gross Margin — Gross margin increased in 2010 compared to 2009, primarily as a result of the following:

 

•

$72.5 million increase for our Natural Gas Services segment, primarily related to commodity derivative activity as explained in the operating revenue section above, higher commodity prices, increased fee-based throughput volumes resulting from the Michigan acquisition and changes in contract mix, partially offset by reduced natural gas basis spreads, increased fuel consumption, decreased natural gas volumes and differences in gas quality across certain of our assets, as well as the impact of volume curtailments due to plant shutdowns and producer wellhead freeze offs as a result of near record cold weather at East Texas and North Louisiana in the first quarter. 2009 results include the first quarter impact of a third party owned pipeline rupture, resulting in a fire at East Texas and operational downtime; and

 

•

$5.3 million increase for our NGL Logistics segment as a result of higher volumes from our Wattenberg pipeline acquisition and our acquisition of an additional 50% interest in Black Lake.

These increases were partially offset by:

 

•

$21.0 million decrease for our Wholesale Propane Logistics segment. 2010 results reflect a planned outage related to our Providence terminal inspection and reduced demand as a result of an early spring and warmer weather. 2009 results reflect increased spot sales volumes and significantly higher per unit margins, approximately $6.0 million of which was attributable to the sale of inventory that was written down at the end of the fourth quarter of 2008.

Operating and Maintenance Expense — Operating and maintenance expense increased in 2010 compared to 2009 primarily as a result of our Michigan acquisition and integration costs, turnaround activities at certain assets, our Wattenberg pipeline acquisition and our acquisition of an additional 50% interest in Black Lake.

Depreciation and Amortization Expense — Depreciation and amortization expense increased in 2010 compared to 2009, primarily as a result of our capital projects completed in 2009, our Michigan acquisition, our Atlantic Energy acquisition, our Wattenberg pipeline acquisition and our acquisition of an additional 50% interest in Black Lake.

Step acquisition — equity interest re-measurement gain — Step acquisition — equity interest re-measurement gain results from our acquisition of an additional 50% interest in Black Lake, bringing our ownership interest in Black Lake to 100% in our NGL Logistics segment. Prior to our acquisition of an additional 50% interest in Black Lake, we accounted for Black Lake under the equity method of accounting. Subsequent to this transaction we account for Black Lake as a consolidated subsidiary. As a result of acquiring an additional 50% interest in Black Lake, we remeasured our initial 50% equity interest in Black Lake to its fair value, and recognized a gain of $9.1 million.

Other income — affiliates — Other income — affiliates increased due to a $3.0 million payment received in the second quarter of 2010 from Spectra Energy, a supplier for our Wholesale Propane Logistics segment, related to an amendment of a supply agreement to shorten the term of the agreement by two years.

Earnings from Unconsolidated Affiliates — Earnings from unconsolidated affiliates increased in 2010 compared to 2009, primarily as a result of increased earnings from Discovery. Settlements related to our commodity derivatives on our unconsolidated affiliates are included in segment gross margin.

Net income attributable to noncontrolling interests — Net income attributable to noncontrolling interests includes the impact of organic growth from our Piceance Basin expansion project, offset by volume curtailments due to plant shutdowns and producer wellhead freeze offs as a result of near record cold weather in the first quarter, increased fuel consumption and differences in gas quality at East Texas in 2010. 2009 results include the first quarter impact of a third party owned pipeline rupture, resulting in a fire at East Texas.

 

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Results of Operations — Natural Gas Services Segment

This segment consists of our Northern Louisiana system, the Southern Oklahoma system, a 40% limited liability company interest in Discovery, our Colorado and Wyoming systems, our East Texas systems, and our Michigan systems.

 

		Three Months Ended September 30,								Nine Months Ended September 30,								Variance Three Months 2010 vs. 2009								Variance Nine Months 2010 vs. 2009
																		Increase								Increase
		2010 (a)(b)				2009 (b)				2010 (a)(b)				2009 (b)				(Decrease)				Percent				(Decrease)				Percent
		(Millions, except as indicated)
Operating revenues:
Sales of natural gas, NGLs and condensate		$	159.2			$	129.1			$	512.0			$	379.3			$	30.1				23	%		$	132.7				35	%
Transportation, processing and other			24.4				22.2				72.9				63.9				2.2				10	%			9.0				14	%
(Losses) gains from commodity derivative activity (c)			(15.7	)			2.8				12.8				(36.0	)			(18.5	)			*				48.8				*
Total operating revenues			167.9				154.1				597.7				407.2				13.8				9	%			190.5				47	%
Purchases of natural gas and NGLs			135.1				106.8				440.9				322.9				28.3				26	%			118.0				37	%
Segment gross margin (d)			32.8				47.3				156.8				84.3				(14.5	)			(31	)%			72.5				86	%
Operating and maintenance expense			(15.0	)			(16.1	)			(48.2	)			(43.8	)			(1.1	)			(7	)%			4.4				10	%
Depreciation and amortization expense			(17.3	)			(15.8	)			(52.1	)			(45.1	)			1.5				9	%			7.0				16	%
Other income			0.5				—				1.0				—				0.5				100	%			1.0				100	%
Earnings from unconsolidated affiliates (e)			4.1				7.9				17.8				9.7				(3.8	)			(48	)%			8.1				84	%
Segment net income			5.1				23.3				75.3				5.1				(18.2	)			(78	)%			70.2				1,376	%
Segment net income attributable to noncontrolling interests			(3.3	)			(2.5	)			(4.4	)			(3.3	)			0.8				32	%			1.1				33	%
Segment net income attributable to partners		$	1.8			$	20.8			$	70.9			$	1.8			$	(19.0	)			(91	)%		$	69.1				3,839	%
Other data:
Non-cash commodity derivative mark-to-market		$	(18.0	)		$	(0.3	)		$	12.7			$	(54.2	)		$	(17.7	)			5,900	%		$	66.9				*
Natural gas throughput (MMcf/d) (e)			1,168				1,111				1,164				1,071				57				5	%			93				9	%
NGL gross production (Bbls/d) (e)			32,882				30,843				33,200				27,086				2,039				7	%			6,114				23	%

 

*	Percentage change is not meaningful.

 

(a)

Includes the results of certain companies that held natural gas gathering and treating assets purchased from MichCon Pipeline Company since November 24, 2009, the date of acquisition.

 

(b)

We utilize commodity derivative instruments to provide stability to distributable cash flows for our ownership in East Texas as well as all other natural gas services assets, the portion of East Texas owned by DCP Midstream, LLC is unhedged. As such, our consolidated results depict 75% of East Texas unhedged in all periods prior to the second quarter of 2009 and 49.9% of East Texas unhedged for all periods subsequent to the first quarter of 2009.

 

(c)

Includes the effect of the acquisition of the NGL Hedge, contributed by DCP Midstream, LLC in April 2009. The NGL Hedge is a fixed price natural gas liquids derivative by NGL component, which commenced in April 2009 and expired in March 2010.

 

(d)

Segment gross margin consists of total operating revenues, including commodity derivative activity, less purchases of natural gas and NGLs. Please read “Reconciliation of Non-GAAP Measures” above.

 

(e)

Includes our proportionate share of the throughput volumes and NGL production of Collbran, Jackson, East Texas and Discovery and our proportionate share of the earnings of Discovery for each period presented. Earnings for Discovery include the accretion of the net difference between the carrying amount of the investment and the underlying equity of the investment.

 

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Three Months Ended September 30, 2010 vs. Three Months Ended September 30, 2009

Total Operating Revenues — Total operating revenues increased in 2010 compared to 2009, primarily as a result of the following:

 

•

$35.5 million increase attributable to increased commodity prices, which impact both sales and purchases; and

 

•

$2.2 million increase primarily as a result of increased fee-based throughput volumes resulting from the Michigan acquisition, partially offset by decreases across certain other assets.

These increases were partially offset by:

 

•

$18.5 million decrease related to commodity derivative activity. This decrease includes an increase in unrealized losses of $17.9 million due to movements in forward prices of commodities, and a decrease in realized cash settlement gains of $0.6 million due to generally higher average prices of commodities in 2010; and

 

•

$5.5 million decrease due primarily to changes in contract mix, increased fuel consumption and differences in gas quality at certain of our assets. These decreases were partially offset by a change to a contract with an affiliate in the Piceance Basin, such that certain revenues changed from a net presentation in transportation, processing and other to a gross presentation in sales of natural gas, NGLs and condensate.

Purchases of Natural Gas and NGLs — Purchases of natural gas and NGLs increased in 2010 compared to 2009, primarily as a result of increased commodity prices, which impact both sales and purchases, as well as a change to a contract with an affiliate in the Piceance Basin, such that certain purchases changed from a net presentation in transportation, processing and other to a gross presentation in purchases of natural gas and NGLs.

Segment Gross Margin — Segment gross margin decreased in 2010 compared to 2009, primarily as a result of the following:

 

•

$18.5 million decrease related to commodity derivative activities as discussed in the Operating Revenues section above; and

 

•

$3.1 million decrease attributable to increased fuel consumption and differences in gas quality at certain of our assets.

These decreases were partially offset by:

 

•

$4.8 million increase as a result of higher commodity prices; and

 

•

$2.2 million increase as a result of increased fee-based throughput volumes resulting from the Michigan acquisition, partially offset by decreases across certain other assets.

Operating and Maintenance Expense — Operating and maintenance expense decreased in 2010 compared to 2009 primarily as a result of timing of expenditures, partially offset by our Michigan acquisition.

Depreciation and Amortization Expense — Depreciation and amortization expense increased in 2010 compared to 2009 primarily as a result of our capital projects completed in 2009 and the Michigan acquisition.

Other income — Other income relates to our reassessment of the fair value of contingent consideration for our acquisition of an additional 5% interest in Collbran Valley Gas Gathering, LLC, or Collbran, from Delta Petroleum Company, or Delta, in February 2010.

Earnings from Unconsolidated Affiliates — Earnings from unconsolidated affiliates, representing our 40% ownership of Discovery, decreased in 2010 compared to 2009, due primarily to decreases in volumes as a result of downtime related to a plant turnaround, as well as differences in gas quality. Settlements related to our commodity derivatives on our unconsolidated affiliates are included in segment gross margin.

 

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Segment net income attributable to noncontrolling interests — Segment net income attributable to noncontrolling interests includes the impact of organic growth from our Piceance Basin expansion project, partially offset by increased fuel consumption and differences in gas quality at East Texas in 2010.

Natural Gas Throughput — Natural gas transported, processed and/or treated in 2010 remained relatively constant compared to 2009. 2010 results include increased fee-based throughput volumes from our Michigan acquisition, offset by decreased volumes across certain assets.

NGL Gross Production — NGL production increased in 2010 compared to 2009 due primarily to increased NGL production from our Piceance Basin expansion project, partially offset by decreased volumes across certain assets.

Nine Months Ended September 30, 2010 vs. Nine Months Ended September 30, 2009

Total Operating Revenues — Total operating revenues increased in 2010 compared to 2009, primarily as a result of the following:

 

•

$131.0 million increase attributable to increased commodity prices, which impact both sales and purchases;

 

•

$48.8 million increase related to commodity derivative activity. This increase includes an increase in unrealized gains of $66.6 million due to movements in forward prices of commodities, partially offset by a decrease in realized cash settlement gains of $17.8 million due to generally higher average prices of commodities in 2010.

 

•

$9.0 million increase as a result of increased fee-based throughput volumes resulting from the Michigan acquisition; and

 

•

$34.3 million increase as a result of increased NGL production and a change to a contract with an affiliate in the Piceance Basin, such that certain revenues changed from a net presentation in transportation, processing and other to a gross presentation in sales of natural gas, NGLs and condensate.

These increases were partially offset by:

 

•

$32.9 million decrease due primarily to the impact of changes in contract mix, increased fuel consumption, differences in gas quality, a decrease in natural gas sales volumes across certain assets, as well as volume curtailments due to plant shutdowns and producer wellhead freeze offs as a result of near record cold weather at East Texas and North Louisiana in the first quarter. 2009 results include the first quarter impact of a third party owned pipeline rupture, resulting in a fire at East Texas and our Wyoming pipeline integrity and system enhancement project.

Purchases of Natural Gas and NGLs — Purchases of natural gas and NGLs increased in 2010 compared to 2009, primarily as a result of increased commodity prices, which impact both sales and purchases, as well as a change to a contract with an affiliate in the Piceance Basin, such that certain purchases changed from a net presentation in transportation, processing and other to a gross presentation in purchases of natural gas and NGLs.

Segment Gross Margin — Segment gross margin increased in 2010 compared to 2009, primarily as a result of the following:

 

•

$48.8 million increase related to commodity derivative activities as discussed in the Operating Revenues section above;

 

•

$28.1 million increase as a result of higher commodity prices; and

 

•

$9.0 million increase as a result of increased fee-based throughput volumes resulting from the Michigan acquisition and changes in contract mix.

These increases were partially offset by:

 

•

$13.7 million decrease attributable to reduced natural gas basis spreads, increased fuel consumption, differences in gas quality, the impact of volume curtailment due to plant shutdowns and producer wellhead freeze offs as a result of near record cold weather at East Texas and North Louisiana in the first quarter and other natural gas volume reductions across certain of our assets. These decreases were partially offset by increased throughput volumes from our organic growth project in the Piceance Basin. 2009 results include the first quarter impact of a third party owned pipeline rupture, resulting in a fire at East Texas and our Wyoming pipeline integrity and system enhancement project.

 

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Operating and Maintenance Expense — Operating and maintenance expense increased in 2010 compared to 2009 primarily as a result of our Michigan acquisition and integration costs, turnaround activities at certain assets, repairs as a result of near record cold weather and efficiency projects.

Depreciation and Amortization Expense — Depreciation and amortization expense increased in 2010 compared to 2009 primarily as a result of our capital projects completed in 2009 and the Michigan acquisition.

Other income — Other income relates to our reassessment of the fair value of contingent consideration for our acquisition of an additional 5% interest in Collbran from Delta in February 2010.

Earnings from Unconsolidated Affiliates — Earnings from unconsolidated affiliates, representing our 40% ownership of Discovery, increased in 2010 compared to 2009, primarily due to higher prices and increased NGL production, partially offset by differences in gas quality, higher costs and downtime related to turnarounds. Settlements related to our commodity derivatives on our unconsolidated affiliates are included in segment gross margin.

Segment net income attributable to noncontrolling interests — Segment net income attributable to noncontrolling interests includes the impact of organic growth from our Piceance Basin expansion project, offset by volume curtailments due to plant shutdowns and producer wellhead freeze offs as a result of near record cold weather in the first quarter, increased fuel consumption, differences in gas quality and turnarounds at East Texas in 2010. 2009 results include the first quarter impact of a third party owned pipeline rupture, resulting in a fire at East Texas.

Natural Gas Throughput — Natural gas transported, processed and/or treated increased in 2010 compared to 2009, as a result of increased fee-based throughput volumes from our Michigan acquisition, and increased volumes at Discovery, partially offset by decreased volumes across certain assets. 2010 results include the impact of volume curtailment due to plant shutdowns and producer wellhead freeze offs as a result of near record cold weather at East Texas and North Louisiana in the first quarter. 2009 results include the first quarter impact of operational downtime following the hurricanes, a fire at East Texas and our Wyoming pipeline integrity and system enhancement project.

NGL Gross Production — NGL production increased in 2010 compared to 2009, due primarily to increased NGL production at Discovery and increased volumes from our Piceance Basin expansion project. 2010 results include the impact of volume curtailment due to plant shutdowns and producer wellhead freeze offs as a result of near record cold weather at East Texas and North Louisiana in the first quarter. 2009 results include the first quarter impact of operational downtime following the hurricanes, a fire at East Texas and our Wyoming pipeline integrity and system enhancement project.

 

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Results of Operations — Wholesale Propane Logistics Segment

This segment includes our propane transportation facilities, which includes five owned and operated rail terminals, one owned marine import terminal, one leased marine terminal, one pipeline terminal and access to several open-access propane pipeline terminals.

 

		Three Months Ended September 30,								Nine Months Ended September 30,								Variance Three Months 2010 vs. 2009								Variance Nine Months 2010 vs. 2009
																		Increase								Increase
		2010 (a)				2009				2010				2009				(Decrease)				Percent				(Decrease)				Percent
		(Millions, except as indicated)
Operating revenues:
Sales of propane		$	66.7			$	47.9			$	309.5			$	227.5			$	18.8				39	%		$	82.0				36	%
Other			—				—				0.2				0.2				—				—	%			—				—	%
(Losses) gains from commodity derivative activity			(0.8	)			0.6				(0.8	)			0.5				(1.4	)			*				(1.3	)			*
Total operating revenues			65.9				48.5				308.9				228.2				17.4				36	%			80.7				35	%
Purchases of propane			62.9				43.3				293.1				191.4				19.6				45	%			101.7				53	%
Segment gross margin (b)			3.0				5.2				15.8				36.8				(2.2	)			(42	)%			(21.0	)			(57	)%
Operating and maintenance expense			(3.1	)			(2.5	)			(8.3	)			(7.6	)			0.6				24	%			0.7				9	%
Depreciation and amortization expense			(1.0	)			(0.3	)			(1.6	)			(1.0	)			0.7				233	%			0.6				60	%
Other income — affiliates			—				—				3.0				—				—				—	%			3.0				100	%
Segment net (loss) income attributable to partners		$	(1.1	)		$	2.4			$	8.9			$	28.2			$	(3.5	)			*			$	(19.3	)			(68	)%
Other data:
Non-cash commodity derivative mark-to-market		$	(0.5	)		$	0.6			$	(1.1	)		$	0.7			$	(1.1	)			*			$	(1.8	)			*
Propane sales volume (Bbls/d)			14,086				12,435				20,165				21,146				1,651				13	%			(981	)			(5	)%

 

*	Percentage change is not meaningful.

 

(a)

Includes the results of Atlantic Energy, since July 30, 2010, the date of acquisition.

 

(b)

Segment gross margin consists of total operating revenues, including commodity derivative activity, less purchases of propane. Please read “Reconciliation of Non-GAAP Measures” above.

Three Months Ended September 30, 2010 vs. Three Months Ended September 30, 2009

Total Operating Revenues — Total operating revenues increased in 2010 compared to 2009, primarily as a result of the following:

 

•

$9.4 million increase attributable to increased propane sales volumes, primarily as a result of our acquisition of Atlantic Energy; and

 

•

$9.4 million increase attributable to higher propane prices, which impact both sales and purchases.

These increases were partially offset by:

 

•

$1.4 million decrease related to commodity derivative activity.

Purchases of Propane — Purchases of propane increased in 2010 compared to 2009, due to higher propane prices which impact both sales and purchases and increased volumes, primarily as a result of our acquisition of Atlantic Energy.

 

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Segment Gross Margin — Segment gross margin decreased in 2010 compared to 2009, primarily as a result of our planned outage related to our Providence terminal inspection and commodity derivative activity, partially offset by increased volumes from our acquisition of Atlantic Energy.

Propane Sales Volume — Propane sales volumes increased in 2010 compared to 2009, primarily as a result of our acquisition of Atlantic Energy.

Nine Months Ended September 30, 2010 vs. Nine Months Ended September 30, 2009

Total Operating Revenues — Total operating revenues increased in 2010 compared to 2009, primarily as a result of the following:

 

•

$86.5 million increase attributable to higher propane prices, which impact both sales and purchases.

This increase was partially offset by:

 

•

$4.5 million decrease attributable to decreased propane sales volumes; and

 

•

$1.3 million decrease due to commodity derivative activity.

Purchases of Propane — Purchases of propane increased in 2010 compared to 2009, as a result of higher propane prices, which impact both sales and purchases, partially offset by decreased propane sales volumes.

Segment Gross Margin — Segment gross margin decreased in 2010 compared to 2009. 2010 results reflect a planned outage related to our Providence terminal inspection and reduced demand as a result of an early spring and warmer weather. 2009 results reflect a late winter, increased spot sales volumes and significantly higher per unit margins, approximately $6.0 million of which was attributable to the sale of inventory that was written down at the end of the fourth quarter of 2008.

Other income — affiliates — Other income — affiliates increased due to a $3.0 million payment received in the second quarter of 2010 from Spectra Energy, related to an amendment of a supply agreement to shorten the term of the agreement by two years.

Propane Sales Volume — Propane sales volumes decreased in 2010 compared to 2009. 2010 results reflect a planned outage related to our Providence terminal inspection and reduced demand as a result of an early spring and warmer weather, partially offset by our acquisition of Atlantic Energy. 2009 results reflect a late winter and increase in spot sales volumes.

 

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Results of Operations — NGL Logistics Segment

This segment includes our Seabreeze, Wilbreeze and Wattenberg NGL and Black Lake transportation pipelines:

 

		Three Months Ended September 30,								Nine Months Ended September 30,								Variance Three Months 2010 vs. 2009								Variance Nine Months 2010 vs. 2009
																		Increase								Increase
		2010 (a)				2009				2010 (a)				2009				(Decrease)						Percent		(Decrease)				Percent
		(Millions, except as indicated)
Operating revenues:
Sales of NGLs		$	1.8			$	1.1			$	4.6			$	2.1			$	0.7			64%				$	2.5				119	%
Transportation, processing and other			4.3				2.0				9.9				4.6				2.3			115%					5.3				115	%
Total operating revenues			6.1				3.1				14.5				6.7				3.0			97%					7.8				116	%
Purchases of NGLs			2.2				1.2				4.7				2.2				1.0			83%					2.5				114	%
Segment gross margin (b)			3.9				1.9				9.8				4.5				2.0			105%					5.3				118	%
Operating and maintenance expense			(1.1	)			(0.4	)			(2.3	)			(0.9	)			0.7			175%					1.4				156	%
Depreciation and amortization expense			(0.8	)			(0.3	)			(1.9	)			(1.1	)			0.5			167%					0.8				73	%
Step acquisition — equity interest re-measurement gain			9.1				—				9.1				—				9.1			100%					9.1				100	%
Earnings from unconsolidated affiliates (c)			—				0.5				0.8				1.3				(0.5	)		(100)%					(0.5	)			(38	)%
Segment net income attributable to partners		$	11.1			$	1.7			$	15.5			$	3.8			$	9.4			553%					11.7				308	%
Other data:
NGL pipelines throughput (Bbls/d) (c)			41,392				32,417				39,004				27,745				8,975			28%					11,259				41	%

 

(a)	Includes the results of our Wattenberg pipeline acquired from Buckeye Partners, L.P, since January 28, 2010, the date of acquisition, and an additional 50% interest in Black Lake acquired from an affiliate of BP PLC, since July 30, the date of acquisition.

The acquisition of an additional 50% interest in Black Lake brought our ownership interest in Black Lake to 100%. Prior to our acquisition of an additional 50% interest in Black Lake, we accounted for Black Lake under the equity method of accounting. Subsequent to this transaction we account for Black Lake as a consolidated subsidiary.

(b)	Segment gross margin consists of total operating revenues less purchases of NGLs. Please read “Reconciliation of Non-GAAP Measures” above.

(c)	For periods prior to July 30, 2010, includes our 50% share of the throughput volumes and earnings for Black Lake. Black Lake’s earnings included the accretion of the net difference between the carrying amount of the investment and the underlying equity of the investment.

Three Months Ended September 30, 2010 vs. Three Months Ended September 30, 2009

Total Operating Revenues — Total operating revenues increased in 2010 compared to 2009, primarily as a result of increased throughput volumes from our acquisition of an additional 50% interest in Black Lake and the Wattenberg pipeline acquisition , as well as higher per unit margins.

Segment Gross Margin — Segment gross margin increased in 2010 compared to 2009, as a result of increased volumes from our acquisition of an additional 50% interest in Black Lake, the Wattenberg pipeline acquisition and higher per unit margins.

Operating and Maintenance Expense — Operating and maintenance expense increased in 2010 compared to 2009, primarily as a result of our acquisition of an additional 50% interest in Black Lake and the Wattenberg pipeline acquisition.

 

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Depreciation and Amortization Expense — Depreciation and amortization expense increased in 2010 compared to 2009, primarily as a result of our acquisition of an additional 50% interest in Black Lake and the Wattenberg pipeline acquisition.

Step acquisition — equity interest re-measurement gain — Step acquisition — equity interest re-measurement gain results from our acquisition of an additional 50% interest in Black Lake bringing our ownership interest in Black Lake to 100%. Prior to our acquisition of an additional 50% interest in Black Lake, we accounted for Black Lake under the equity method of accounting. Subsequent to this transaction we account for Black Lake as a consolidated subsidiary. As a result of acquiring an additional 50% interest in Black Lake, we remeasured our initial 50% equity interest in Black Lake to its fair value, and recognized a gain of $9.1 million.

NGL Pipelines Throughput — NGL pipelines throughput increased in 2010 compared to 2009, as a result the Wattenberg pipeline acquisition and our acquisition of an additional 50% interest in Black Lake.

Nine Months Ended September 30, 2010 vs. Nine Months Ended September 30, 2009

Total Operating Revenues — Total operating revenues increased in 2010 compared to 2009, primarily as a result of the Wattenberg pipeline acquisition, a market opportunity early in the year at Seabreeze, our acquisition of an additional 50% interest in Black Lake, as well as higher per unit margins. 2009 results include the first quarter impact of decreased throughput volumes resulting from ethane rejection and lower volumes at certain connected processing plants.

Segment Gross Margin — Segment gross margin increased in 2010 compared to 2009, as a result of higher volumes from the Wattenberg pipeline acquisition and our acquisition of an additional 50% interest in Black Lake, as well as higher per unit margins.

Operating and Maintenance Expense — Operating and maintenance expense increased in 2010 compared to 2009, primarily as a result of the Wattenberg pipeline acquisition and our acquisition of an additional 50% interest in Black Lake.

Depreciation and Amortization Expense — Depreciation and amortization expense increased in 2010 compared to 2009, primarily as a result of the Wattenberg pipeline acquisition and our acquisition of an additional 50% interest in Black Lake.

Step acquisition — equity interest re-measurement gain — Step acquisition — equity interest re-measurement gain results from our acquisition of an additional 50% interest in Black Lake bringing our ownership interest in Black Lake to 100%. Prior to our acquisition of an additional 50% interest in Black Lake, we accounted for Black Lake under the equity method of accounting. Subsequent to this transaction we account for Black Lake as a consolidated subsidiary. As a result of acquiring an additional 50% interest in Black Lake, we remeasured our initial 50% equity interest in Black Lake to its fair value, and recognized a gain of $9.1 million.

NGL Pipelines Throughput — NGL pipelines throughput increased in 2010 compared to 2009, as a result of increased volumes from a market opportunity early in the year at Seabreeze, the Wattenberg pipeline acquisition and our acquisition of an additional 50% interest in Black Lake. 2009 results include the first quarter impact of ethane rejection and lower volumes at certain connected processing plants.

Liquidity and Capital Resources

We expect our sources of liquidity to include:

 

•

cash generated from operations;

 

•

cash distributions from our unconsolidated affiliates;

 

•

borrowings under our revolving credit facility;

 

•

issuance of additional partnership units;

 

•

debt offerings;

 

•

guarantees issued by DCP Midstream, LLC, which reduce the amount of collateral we may be required to post with certain counterparties to our commodity derivative instruments; and

 

•

letters of credit.

 

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We anticipate our more significant uses of resources to include:

 

•

capital expenditures;

 

•

quarterly distributions to our unitholders;

 

•

contributions to our unconsolidated affiliates to finance our share of their capital expenditures;

 

•

business and asset acquisitions; and

 

•

collateral with counterparties to our swap contracts to secure potential exposure under these contracts, which may, at times, be significant depending on commodity price movements, and which is required to the extent we exceed certain guarantees issued by DCP Midstream, LLC and letters of credit we have posted.

We believe that cash generated from these sources will be sufficient to meet our short-term working capital requirements, long-term capital expenditure and acquisition requirements, and quarterly cash distributions for the next twelve months. In the event these sources are not sufficient, we would reduce our discretionary spending.

We routinely evaluate opportunities for strategic investments or acquisitions. Future material investments or acquisitions may require that we obtain additional capital, assume third party debt or incur other long-term obligations. In November 2010, we signed agreements with DCP Midstream, LLC, to acquire a 33.33% interest in the DCP Southeast Texas business for $150 million.

Based on current and anticipated levels of operations, we believe we have adequate committed financial resources to conduct our business, although deterioration in our operating environment could limit our borrowing capacity, raise our financing costs, as well as impact our compliance with our financial covenant requirements under our Credit Agreement. Our sources of funding could include additional borrowings under our Credit Agreement, the placement of public and private debt, and the issuance of our common units.

Changes in natural gas, NGL and condensate prices and the terms of our processing arrangements have a direct impact on our generation and use of cash from operations due to their impact on net income, along with the resulting changes in working capital. We have mitigated a portion of our anticipated commodity price risk associated with the equity volumes from our gathering and processing activities through 2015 with fixed price natural gas and crude oil swaps. For additional information regarding our derivative activities, please read “Item7A. Quantitative and Qualitative Disclosures about Market Risk” in our 2009 Form 10-K and “Item 3. Quantitative and Qualitative Disclosures about Market Risk” in this Quarterly Report on Form 10-Q.

We have an $850.0 million revolving credit facility that matures June 21, 2012, or the Credit Agreement. Effective June 28, 2010, we transferred both the funded and the unfunded portions of the former Lehman Brothers Commercial Bank’s commitment to Morgan Stanley. The transfer reinstated $25.4 million of available capacity to our revolving credit facility.

Our borrowing capacity is currently limited by the Credit Agreement’s financial covenant requirements. Except in the case of a default, which would make the borrowings under the Credit Agreement fully callable, amounts borrowed under the Credit Agreement will not mature prior to the June 21, 2012 maturity date. As of November 4, 2010, we had approximately $499.5 million of unused capacity under the Credit Agreement.

On September 30, 2010 we issued $250 million of our 3.25% Senior Notes due October 1, 2015. We received net proceeds, after deducting underwriting discounts and offering expenses, of $247.8 million, which we used to repay funds borrowed under the revolver portion of our Credit Facility.

        The counterparties to each of our commodity swap contracts are investment-grade rated financial institutions. Under these contracts, we may be required to provide collateral to the counterparties in the event that our potential payment exposure exceeds a predetermined collateral threshold. Collateral thresholds are set by us and each counterparty, as applicable, in the master contract that governs our financial transactions based on our and the counterparty’s assessment of creditworthiness. The assessment of our position with respect to the collateral thresholds are determined on a counterparty by counterparty basis, and are impacted by the representative forward price curves and notional quantities under our swap contracts. Due to the interrelation between the representative crude oil and natural gas forward price curves, it is not practical to determine a single pricing point at which our swap contracts will meet the collateral thresholds as we may transact multiple commodities with the same counterparty. As of November 4, 2010, DCP Midstream, LLC had issued and outstanding parental guarantees totaling $98.0 million in favor of certain counterparties to our commodity derivative instruments to mitigate a portion of our collateral requirements with these counterparties. We pay DCP Midstream, LLC a fee of 0.50% per annum on $55.0 million of these guarantees. As of November 4, 2010, we had a contingent letter of credit facility for up to $10.0 million, on which we pay a fee of 0.50% per annum. As of November 4, 2010, we have $0 letters of credit issued on this facility; we will pay a net fee of 1.75% per annum on letters of credit issued on this facility. These parental guarantees and contingent issuance letter of credit facility reduce the amount of cash we may be required to post as collateral. This contingent issuance letter of credit facility was issued directly by a financial institution and does not reduce the available capacity under our credit facility. As of November 4, 2010, we had no cash collateral posted with counterparties. Depending on daily commodity prices, the amount of collateral posted can go up or down on a daily basis. Predetermined collateral thresholds for commodity derivative instruments guaranteed by DCP Midstream, LLC are generally dependent on DCP Midstream, LLC’s credit rating and the thresholds would be reduced to $0 in the event DCP Midstream, LLC’s credit rating were to fall below investment grade.

 

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Working Capital — Working capital is the amount by which current assets exceed current liabilities. Current assets are reduced by our quarterly distributions, which are required under the terms of our partnership agreement based on Available Cash, as defined in the partnership agreement. In general, our working capital is impacted by changes in the prices of commodities that we buy and sell, inventory levels, and other business factors that affect our net income and cash flows. Our working capital is also impacted by the timing of operating cash receipts and disbursements, borrowings of and payments on debt, capital expenditures, and increases or decreases in restricted investments and other long-term assets.

As of September 30, 2010, we had $11.8 million in cash and cash equivalents. Of this balance, as of September 30, 2010, $1.5 million was held by subsidiaries we do not wholly own, which we consolidate in our financial results. Other than the cash held by these subsidiaries, this cash balance was available for general corporate purposes. Congress recently passed the Dodd-Frank Wall Street Reform and Consumer Protection Act, which has the potential to impact our cash collateral requirements for our trading activities and derivative positions depending on the final regulations adopted by the United States Commodity Futures Trading Commission and the SEC.

We had a working capital deficit of $1.4 million and working capital of $6.6 million as of September 30, 2010 and December 31, 2009, respectively. Excluding net derivative working capital liabilities of $34.4 million and $34.2 million, working capital would be $33.0 million and $40.8 million as of September 30, 2010 and December 31, 2009, respectively. The change in working capital is primarily attributable to the factors described above. We expect that our future working capital requirements will be impacted by these same factors.

Cash Flow — Operating, investing and financing activities was as follows:

 

		Nine Months Ended September 30,
		2010				2009
		(Millions)
Net cash provided by operating activities		$	130.4			$	95.1
Net cash used in investing activities		$	(128.6	)		$	(97.9	)
Net cash provided by (used in) financing activities		$	7.9			$	(46.2	)

Net Cash Provided by Operating Activities — The changes in net cash provided by operating activities are attributable to our net income adjusted for non-cash charges as presented in the condensed consolidated statements of cash flows and changes in working capital as discussed above.

We received net cash for settlement of our commodity derivative instruments of $0.1 million for the nine months ended September 30, 2010, approximately $5.9 million of which was associated with rebalancing our portfolio, and received cash for settlement of our commodity derivative instruments for the nine months ended September 30, 2009 of $17.3 million, approximately $4.8 million of which was associated with rebalancing our portfolio. In addition we received $5.8 million from DCP Midstream, LLC, related to the sale of surplus equipment as of September 30, 2010, which we have treated as an operating cash flow, due to the title to the equipment not transferring to DCP Midstream, LLC as of the balance sheet date.

We received cash distributions from unconsolidated affiliates of $23.9 million and $10.5 million during the nine months ended September 30, 2010 and 2009, respectively. Distributions exceeded earnings by $5.3 million for the nine months ended September 30, 2010. Earnings exceeded distributions by $0.5 million for the nine months ended September 30, 2009.

 

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Net Cash Used in Investing Activities — Net cash used in investing activities during the nine months ended September 30, 2010 was comprised of: (1) acquisition expenditures of $103.8 million related to our acquisition of Atlantic Energy, the Wattenberg NGL pipeline and an additional 55% interest in Black Lake; (2) capital expenditures of $37.1 million (our portion of which was $23.9 million and the noncontrolling interest holders’ portion was $13.2 million); and (3) investments in Discovery of $0.7 million; partially offset by (4) net proceeds from sale of available-for-sale securities of $10.1 million; (5) proceeds from sale of assets of $1.7 million; and (6) a return of investment from Discovery of $1.2 million.

Net cash used in investing activities during the nine months ended September 30, 2009 was comprised of: (1) capital expenditures of $143.0 million (our portion of which was $66.3 million and the noncontrolling interest holders’ portion was $76.7 million), which primarily consisted of expenditures for expansion of our Collbran system and East Texas systems and completion of the pipeline integrity system upgrades to our Wyoming system; and (2) investments in Discovery of $5.8 million; partially offset by (3) net proceeds from sale of available-for-sale securities of $50.0 million; (4) net receipts of $0.6 million relating to acquisitions, consisting of a $0.7 million net working capital adjustment for our acquisition of an additional 25.1% interest in East Texas in April 2009, partially offset by a net payment of $0.1 million related to our acquisition of Michigan Pipeline & Processing, LLC in October 2008; and (5) proceeds from sale of assets of $0.3 million.

Net Cash Provided by (Used in) Financing Activities — Net cash provided by financing activities during the nine months ended September 30, 2010 was comprised of: (1) proceeds from the issuance of common units net of offering costs of $93.2 million; and (2) contributions from noncontrolling interests of $10.4 million; partially offset by (3) distributions to our unitholders and general partner of $74.4 million; (4) distributions to noncontrolling interests of $16.0 million; (5) purchase of additional interest in a subsidiary of $3.5 million; (6) payment of deferred financing costs of $1.6 million; and (7) net repayment of debt of $0.2 million.

Net cash used in financing activities during the nine months ended September 30, 2009 was comprised of (1) distributions to our unitholders and general partner of $62.8 million; (2) net repayments of debt of $43.5 million; and (3) distributions to noncontrolling interests of $15.4 million; partially offset by (4) contributions from non controlling interests of $71.8 million; (5) net changes in advances to predecessor from DCP Midstream, LLC of $3.0 million; and (6) contributions from DCP Midstream, LLC of $0.7 million.

During the nine months ended September 30, 2010, total outstanding indebtedness under our $850.0 million Credit Agreement, which includes borrowings under our revolving credit facility, our term loan facility and letters of credit issued under the Credit Agreement, was not less than $363.5 million and did not exceed $722.4 million. The weighted-average indebtedness outstanding for the nine months ended September 30, 2010 was $627.7 million.

We had liquidity, which is available commitments under the Credit Agreement, of $486.5 million as of September 30, 2010.

During the nine months ended September 30, 2010, we had the following net movements on our revolving credit facility:

 

•

$247.8 million repayment financed by the issue of $250 million of our 3.25% Senior Notes due October 1, 2015;

 

•

$93.1 million repayment financed by the issue of 2,990,000 common units in August 2010; and

 

•

$14.0 million net repayments; partially offset by

 

•

$66.3 million borrowing to fund the acquisition of Atlantic Energy, which includes $17.3 million for propane inventory and working capital;

 

•

$22.0 million borrowing to fund the acquisition of the Wattenberg pipeline;

 

•

$16.6 million borrowing to fund the acquisition of an additional 55% interest in Black Lake; and

 

•

$10.0 million borrowing to fund repayment of our term loan facility.

During the nine months ended September 30, 2010, we had a repayment of $10.0 million on our term loan facility and released $10.0 million of restricted investments which were required as collateral for the facility.

 

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During the nine months ended September 30, 2009, we had the following net movements on our revolving credit facility:

 

•

$50.0 million borrowings to fund repayment of our term loan facility; partially offset by

 

•

$43.5 million net repayments.

During the nine months ended September 30, 2009, we had a repayment of $50.0 million on our term loan facility and released $50.0 million of restricted investments which were required as collateral for the facility.

We expect to continue to use cash in financing activities for the payment of distributions to our unitholders and general partner. See Note 11 of the Notes to Condensed Consolidated Financial Statements in Item 1. “Financial Statements.”

Capital Requirements — The midstream energy business can be capital intensive, requiring significant investment to maintain and upgrade existing operations. Our capital requirements have consisted primarily of, and we anticipate will continue to consist of the following:

 

•

maintenance capital expenditures, which are cash expenditures where we add on to or improve capital assets owned, including certain system integrity and safety improvements, or acquire or construct new capital assets if such expenditures are made to maintain, including over the long term, our operating capacity or revenues; and

 

•

expansion capital expenditures, which are cash expenditures for acquisitions or capital improvements (where we add on to or improve the capital assets owned, or acquire or construct new gathering lines, treating facilities, processing plants, fractionation facilities, pipelines, terminals, docks, truck racks, tankage and other storage, distribution or transportation facilities and related or similar midstream assets) in each case if such addition, improvement, acquisition or construction is made to increase our operating capacity or revenues.

We incur capital expenditures for our consolidated entities and our unconsolidated affiliates. We anticipate maintenance capital expenditures of between $5 million and $10 million, and expenditures for expansion capital improvements of between $25 million and $30 million for the year ending December 31, 2010. The board of directors may approve additional growth capital during the year, at their discretion.

Our expansion capital improvements forecast of between $25 million and $30 million for the year ended December 31, 2010, includes expenditures for capital improvements related to our January 2010 Wattenberg pipeline acquisition, of which we have invested $4.5 million as of September 30, 2010. Given the timing of the Wattenberg capital project, which we forecast to be completed in early 2011, some of the $18 million total capital expenditures for this project will be included in 2011.

The following table summarizes our maintenance and expansion capital expenditures for our consolidated entities.

 

		Nine Months Ended September 30, 2010												Nine Months Ended September 30, 2009
		Maintenance Capital Expenditures				Expansion Capital Expenditures				Total Consolidated Capital Expenditures				Maintenance Capital Expenditures				Expansion Capital Expenditures				Total Consolidated Capital Expenditures
		(Millions)												(Millions)
Our portion		$	4.1			$	19.8			$	23.9			$	9.9			$	56.4			$	66.3
Noncontrolling interest portion			4.9				8.3				13.2				19.6				57.1				76.7
Total		$	9.0			$	28.1			$	37.1			$	29.5			$	113.5			$	143.0

In addition, we invested cash in unconsolidated affiliates of $0.7 million and $5.8 million during the nine months ended September 30, 2010 and 2009, respectively, of which $0.7 million and $1.6 million, respectively, was to fund our share of capital expansion projects, and $4.2 million in 2009 was to fund repairs to Discovery following damage caused by Hurricane Ike in 2008 (of which $1.2 million and $2.2 million was returned to us by Discovery in the second quarter of 2010 and the fourth quarter of 2009, respectively).

We intend to make cash distributions to our unitholders and our general partner. Due to our cash distribution policy, we expect that we will distribute to our unitholders most of the cash generated by our operations. As a result, we expect that we will rely upon external financing sources, which could include debt and common unit issuances, to fund our acquisition and expansion capital expenditures.

 

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We expect to fund future capital expenditures with funds generated from our operations, borrowings under our credit facility and the issuance of additional partnership units or debt. If these sources are not sufficient, we will reduce our discretionary spending.

Cash Distributions to Unitholders — Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all Available Cash, as defined in the partnership agreement. We made cash distributions to our unitholders and general partner of $74.4 million during the nine months ended September 30, 2010, as compared to $62.8 million for the same period in 2009. We intend to continue making quarterly distribution payments to our unitholders and general partner to the extent we have sufficient cash from operations after the establishment of reserves.

Description of the Credit Agreement — The Credit Agreement consists of an $850.0 million revolving credit facility at September 30, 2010. The Credit Agreement matures on June 21, 2012. As of September 30, 2010, the outstanding balance on the revolving credit facility was $363.0 million. The term loan was repaid during the first quarter of 2010.

Our obligations under the revolving credit facility are unsecured. The term loan facility, which was repaid during the first quarter of 2010, was secured at all times by high-grade securities, which we classified as restricted investments in the accompanying condensed consolidated balance sheets, in an amount equal to or greater than the outstanding principal amount of the term loan. Any portion of the term loan balance may be repaid at any time, and we would then have access to a corresponding amount of the collateral securities. Upon any prepayment of term loan borrowings, the amount of our revolving credit facility will automatically increase to the extent that the repayment of our term loan facility is made in connection with an acquisition or construction of assets in the midstream energy business. The unused portion of the revolving credit facility may be used for letters of credit. At September 30, 2010 and December 31, 2009, we had $0.5 million and $0.3 million, respectively, outstanding letters of credit issued under the Credit Agreement.

As of September 30, 2010, the weighted-average interest rate on our revolving credit facility was 0.74% per annum.

Description of Debt Securities

On September 30, 2010, we issued $250 million of our 3.25% Senior Notes due October 1, 2015. We received net proceeds of $247.8 million, net of underwriters’ fees, related expense and unamortized discounts of $1.5 million, $0.5 million and $0.2 million, respectively which we used to repay funds borrowed under the revolver portion of our Credit Facility. Interest on the notes will be paid semi-annually on April 1 and October 1 of each year, commencing April 1, 2011. The notes will mature on October 1, 2015 unless redeemed prior to maturity.

We have incurred $2.0 million of underwriters’ fees and related expense with the issue of the notes, which we deferred in other long term assets in our condensed consolidated balance sheets. We will amortize these costs over the term of the notes.

The notes are senior unsecured obligations, ranking equally in right of payment with our existing unsecured indebtedness, including indebtedness under our Credit Facility. We are not required to make mandatory redemption or sinking fund payments with respect to these notes. The securities are redeemable at a premium at our option.

 

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Total Contractual Cash Obligations and Off-Balance Sheet Obligations

A summary of our total contractual cash obligations as of September 30, 2010, is as follows:

 

		Payments Due by Period
		Total				Less than 1 year				1-3 years				3-5 years				Thereafter
		(Millions)
Long-term debt (a)		$	696.4			$	23.5			$	402.3			$	16.5			$	254.1
Operating lease obligations (b)			44.3				14.7				21.3				7.2				1.1
Purchase obligations (c)			672.4				331.7				217.7				63.4				59.6
Other long-term liabilities (d)			10.0				—				0.8				0.3				8.9
Total		$	1,423.1			$	369.9			$	642.1			$	87.4			$	323.7

 

(a)

Includes interest payments on long-term debt that has been hedged and on debt securities that have been issued. Interest payments on long-term debt that has not been hedged are not included as these payments are based on floating interest rates and we cannot determine with accuracy the periodic repayment dates or the amounts of the interest payments.

(b)

Our operating lease obligations are contractual obligations, and primarily consist of our leased marine propane terminal and railcar leases, both of which provide supply and storage infrastructure for our Wholesale Propane Logistics business. Operating lease obligations also include firm transportation arrangements and natural gas storage for our Pelico system. The firm transportation arrangements supply off-system natural gas to Pelico and the natural gas storage arrangement enables us to maximize the value between the current price of natural gas and the futures market price of natural gas.

(c)

Our purchase obligations are contractual obligations and include $5.4 million of purchase orders for capital expenditures and $667.0 million of various non-cancelable commitments to purchase physical quantities of propane supply for our Wholesale Propane Logistics business. For contracts where the price paid is based on an index, the amount is based on the forward market prices at September 30, 2010. Purchase obligations exclude accounts payable, accrued interest payable and other current liabilities recognized in the condensed consolidated balance sheets. Purchase obligations also exclude current and long-term unrealized losses on derivative instruments included in the condensed consolidated balance sheet, which represent the current fair value of various derivative contracts and do not represent future cash purchase obligations. These contracts may be settled financially at the difference between the future market price and the contractual price and may result in cash payments or cash receipts in the future, but generally do not require delivery of physical quantities of the underlying commodity. In addition, many of our gas purchase contracts include short and long term commitments to purchase produced gas at market prices. These contracts, which have no minimum quantities, are excluded from the table.

(d)	Other long-term liabilities include $8.9 million of asset retirement obligations and $1.1 million of environmental reserves recognized in the September 30, 2010 condensed consolidated balance sheet.

We have no items that are classified as off balance sheet obligations.

Recent Accounting Pronouncements

Financial Accounting Standards Board, or FASB, Accounting Standards Update, or ASU, 2010-06 “Fair Value Measurements and Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements,” or ASU 2010-06 — In January 2010, the FASB issued ASU 2010-06 which amended the Accounting Standards Codification, or ASC, Topic 820-10 “Fair Value Measurement and Disclosures — Overall.” ASU 2010-06 requires new disclosures regarding transfers in and out of assets and liabilities measured at fair value classified within the valuation hierarchy as either Level 1 or Level 2 and information about sales, issuances and settlements on a gross basis for assets and liabilities classified as Level 3. ASU 2010-06 clarifies existing disclosures on the level of disaggregation required and inputs and valuation techniques. The provisions of ASU 2010-06 became effective for us on January 1, 2010, except for disclosure of information about sales, issuances and settlements on a gross basis for assets and liabilities classified as Level 3, which is effective for us on January 1, 2011. The provisions of ASU 2010-06 impact only disclosures and we have disclosed information in accordance with the revised provisions of ASU 2010-06 within this filing.

 

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ASU 2009-17 “Consolidation (Topic 810): Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities,” or ASU 2009-17 — In December 2009, the FASB issued ASU 2009-17 which amended ASC Topic 810 “Consolidation.” ASU 2009-17 requires entities to perform additional analysis of their variable interest entities and consolidation methods. This ASU became effective for us on January 1, 2010 and upon adoption we did not change our conclusions on which entities we consolidate in our condensed consolidated financial statements.

ASU 2009-13 “Revenue Recognition (Topic 605) Multiple-Deliverable Revenue Arrangements,” or ASU 2009-13 — In October 2009, the FASB issued ASU 2009-13 which amended ASC Topic 605 “Revenue Recognition.” The ASU addresses the accounting for multiple-deliverable arrangements, to enable vendors to account for products or services separately rather than as a combined unit. ASU 2009-13 is effective for us on January 1, 2011 and we are in the process of assessing the impact of ASU 2009-13 on our condensed consolidated results of operations, cash flows and financial position as a result of adoption.

 

Item 3.

Quantitative and Qualitative Disclosures about Market Risk

For an in-depth discussion of our market risks, see “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” in our 2009 Form 10-K.

Credit Risk

Our principal customers in the Natural Gas Services segment are large, natural gas marketing servicers and industrial end-users. Our principal customers in the Wholesale Propane Logistics segment are primarily retail propane distributors. In the NGL Logistics Segment, our principal customers include an affiliate of DCP Midstream, LLC, producers and marketing companies. Substantially all of our natural gas, propane and NGL sales are made at market-based prices. This concentration of credit risk may affect our overall credit risk, as these customers may be similarly affected by changes in economic, regulatory or other factors. Where exposed to credit risk, we analyze the counterparties’ financial condition prior to entering into an agreement, establish credit limits, and monitor the appropriateness of these limits on an ongoing basis. We operate under DCP Midstream, LLC’s corporate credit policy. DCP Midstream, LLC’s corporate credit policy, as well as the standard terms and conditions of our agreements, prescribe the use of financial responsibility and reasonable grounds for adequate assurances. These provisions allow our credit department to request that a counterparty remedy credit limit violations by posting cash or letters of credit for exposure in excess of an established credit line. The credit line represents an open credit limit, determined in accordance with DCP Midstream, LLC’s credit policy. Our standard agreements also provide that the inability of a counterparty to post collateral is sufficient cause to terminate a contract and liquidate all positions. The adequate assurance provisions also allow us to suspend deliveries, cancel agreements or continue deliveries to the buyer after the buyer provides security for payment to us in a satisfactory form.

Interest Rate Risk

Interest rates on future credit facility draws and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. Although this could limit our ability to raise funds in the debt capital markets, we expect to remain competitive with respect to acquisitions and capital projects, as our competitors would face similar circumstances.

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. These interest rate swap agreements convert the interest rate associated with the indebtedness outstanding under our revolving credit facility to a fixed rate obligation, thereby reducing the exposure to market rate fluctuations. On September 23, 2010 we filed a prospectus with the Securities and Exchange Commission, or SEC, relating to the issuance of $250.0 million of our 3.25% Senior Notes, the proceeds of which were used to pay down our revolving credit facility. As a result of our pay down of the revolving credit facility, effective September 23, 2010, we discontinued cash flow hedge accounting on $225.0 million of our interest rate swap agreements.

 

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Effective September 23, 2010, we account for $225.0 million of interest rate swaps using the mark-to-market method of accounting, whereby changes in fair value are recorded directly to the condensed consolidated statements of operations, in interest expense. On October 1, 2010, we terminated $200.0 million of these swaps that would have matured in December 2010, for $1.3 million. We also exchanged $275.0 million of interest rate swaps with an effective date of December 2010 through June 2012 for $150.0 million of interest rate swaps effective December 2010 through June 2014. These swaps are accounted for under the mark-to-market method of accounting.

We have $350.0 million of the interest rate swap agreements that have been designated as cash flow hedges, and effectiveness is determined by matching the principal balance and terms with that of the specified obligation.

At September 30, 2010, the effective weighted-average interest rate on our $363.0 million of outstanding revolver debt was 5.09%, taking into account the $350.0 million of indebtedness with designated interest rate swaps.

Based on the annualized unhedged borrowings under our credit facility of $13.0 million as of September 30, 2010, a 0.5% movement in the base rate or LIBOR rate would result in an approximately $0.1 million annualized increase or decrease in interest expense.

Commodity Price Risk

We are exposed to the impact of market fluctuations in the prices of natural gas, NGLs and condensate as a result of our gathering, processing, sales and storage activities. For gathering services, we receive fees or commodities from producers to bring the natural gas from the wellhead to the processing plant. For processing services, we either receive fees or commodities as payment for these services, depending on the types of contracts. We employ established policies and procedures to manage our risks associated with these market fluctuations using various commodity derivatives, including forward contracts, swaps and futures.

Commodity Cash Flow Protection Activities — We closely monitor the risks associated with commodity price changes on our future operations and, where appropriate, use various commodity instruments such as fixed price natural gas, crude oil and NGL contracts to mitigate a portion of the effect pricing fluctuations may have on the value of our assets and operations. Depending on our risk management objectives, we may periodically settle a portion of these instruments prior to their maturity.

We enter into derivative financial instruments to mitigate a portion of the cash flow risk of decreased natural gas, NGL and condensate prices associated with our percent-of-proceeds arrangements and gathering operations. We also may enter into natural gas derivatives to lock in margin around our transportation or leased storage assets. Historically, there has been a strong relationship between NGL prices and crude oil prices, with some exceptions, notably in late 2008 and early 2009, and lack of liquidity in the NGL financial market; therefore we have historically used crude oil swaps to mitigate a portion of NGL price risk. When the relationship of NGL prices to crude oil prices is at a discount to historical ranges, we experience additional exposure as a result of the relationship. As a result of these transactions, we have mitigated a portion of our expected natural gas, NGL and condensate commodity price risk through 2015.

The derivative financial instruments we have entered into are typically referred to as “swap” contracts. These swap contracts entitle us to receive payment at settlement from the counterparty to the contract to the extent that the reference price is below the swap price stated in the contract, and we are required to make payment at settlement to the counterparty to the extent that the reference price is higher than the swap price stated in the contract.

We are using the mark-to-market method of accounting for all commodity derivative instruments, which has significantly increased the volatility of our results of operations as we recognize, in current earnings, all non-cash gains and losses from the mark-to-market on derivative activity.

 

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The following table sets forth additional information about our fixed price natural gas and crude oil swaps used to mitigate a portion of our natural gas and NGL price risk associated with our percent-of-proceeds arrangements and our condensate price risk associated with our gathering operations as of November 4, 2010:

 

Period		Commodity		Notional Volume		Reference Price		Swap Price Range
October 2010 — December 2010		Natural Gas		1,634 MMBtu/d		IFERC Monthly Index Price for Colorado Interstate Gas Pipeline (a)		$3.94/MMBtu
January 2011 — December 2014		Natural Gas		1,000 MMBtu/d		IFERC Monthly Index Price for Colorado Interstate Gas Pipeline (a)		$5.06/MMBtu
October 2010 — December 2010		Natural Gas		1,900 MMBtu/d		Texas Gas Transmission Price (b)		$6.41 - $9.20/MMBtu
January 2011 — December 2014		Natural Gas		500 MMBtu/d		Texas Gas Transmission Price (b)		$4.87/MMBtu
October 2010 — December 2010		Crude Oil		2,415 Bbls/d		Asian-pricing of NYMEX crude oil futures (c)		$63.05 - $87.25/Bbl
October 2010 — December 2011		Crude Oil		250 Bbls/d		Asian-pricing of NYMEX crude oil futures (c)		$56.75 - $59.30/Bbl
January 2011 — December 2011		Crude Oil		2,350 Bbls/d		Asian-pricing of NYMEX crude oil futures (c)		$66.72 - $83.80/Bbl
January 2012 — December 2012		Crude Oil		2,125 Bbls/d		Asian-pricing of NYMEX crude oil futures (c)		$66.72 - $90.00/Bbl
January 2013 — December 2013		Crude Oil		2,050 Bbls/d		Asian-pricing of NYMEX crude oil futures (c)		$67.60 - $83.00/Bbl
January 2014 — December 2014		Crude Oil		1,500 Bbls/d		Asian-pricing of NYMEX crude oil futures (c)		$74.90 - $96.08/Bbl
January 2015 — December 2015		Crude Oil		500 Bbls/d		Asian-pricing of NYMEX crude oil futures (c)		$92.00/Bbl

 

(a)	The Inside FERC index price for natural gas delivered into the Colorado Interstate Gas (CIG) pipeline.

(b)	The Inside FERC index price for natural gas delivered into the Texas Gas Transmission pipeline in the North Louisiana area.

(c)	Monthly average of the daily close prices for the prompt month NYMEX light, sweet crude oil futures contract (CL).

Our annual sensitivities for 2010 as shown in the table below, exclude the impact from non-cash mark-to-market on our commodity derivatives. We utilize crude oil derivatives to mitigate a portion of our commodity price exposure for NGLs, and show our sensitivity to changes in the relationship between the pricing of NGLs and crude oil. For fixed price natural gas and crude oil, the sensitivities are associated with our unhedged volumes. For our NGL to crude oil price relationship, the sensitivity is associated with both hedged and unhedged equity volumes.

Commodity Sensitivities Excluding Non-Cash Mark-To-Market

 

		Per Unit Decrease				Unit of Measurement		Estimated Decrease in Annual Net Income Attributable to Partners
								(Millions)
Natural gas prices		$	1.00			MMBtu		$	0.2
Crude oil prices (a)		$	5.00			Barrel		$	1.3
NGL to crude oil price relationship (b)			5 percentage point change			Barrel		$	5.6

 

(a)	Assuming 60% NGL to crude oil price relationship.

(b)

Assuming 60% NGL to crude oil price relationship and $70.00/Bbl crude oil price. Generally, this sensitivity changes by $1.6 million for each $20.00/Bbl change in the price of crude oil. As crude oil prices increase from $70.00/Bbl, we become slightly more sensitive to the change in the relationship of NGL prices to crude oil prices. As crude oil prices decrease from $70.00/Bbl, we become less sensitive to the change in the relationship of NGL prices to crude oil prices.

In addition to the linear relationships in our commodity sensitivities above, additional factors cause us to be less sensitive to commodity price declines. A portion of our net income is derived from fee-based contracts and a certain percentage of liquids processing arrangements that contain minimum fee clauses in which our processing margins convert to fee-based arrangements as NGL prices decline.

 

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The above sensitivities exclude the impact from arrangements where producers on a monthly basis may elect to not process their natural gas in which case we retain a portion of the customers’ natural gas in lieu of NGLs as a fee. The above sensitivities also exclude certain related processing arrangements where we control the processing or by-pass of the production based upon individual economic processing conditions. Under each of these types of arrangements, our processing of the natural gas would yield favorable processing margins. Less than 10% of our gas throughput is associated with these arrangements.

We estimate the following non-cash sensitivities in 2010 related to the mark-to-market on our commodity derivatives associated with our commodity cash flow protection activities:

Non-Cash Mark-To-Market Commodity Sensitivities

 

		Per Unit Increase				Unit of Measurement		Estimated Mark-to- Market  Impact (Decrease in Net Income Attributable to Partners)
								(Millions)
Natural gas prices		$	1.00			MMBtu		$	2.9
Crude oil prices		$	5.00			Barrel		$	20.1
NGL prices		$	0.10			Gallon		$	0.3

While the above commodity price sensitivities are indicative of the impact that changes in commodity prices may have on our annualized net income, changes during certain periods of extreme price volatility and market conditions or changes in the relationship of the price of NGLs and crude oil may cause our commodity price sensitivities to vary significantly from these estimates.

The midstream natural gas industry is cyclical, with the operating results of companies in the industry significantly affected by the prevailing price of NGLs, which in turn has been generally related to the price of crude oil, with some exceptions, notably in late 2008 and early 2009, when NGL pricing was at a greater discount to crude oil pricing. Although the prevailing price of residue natural gas has less short-term significance to our operating results than the price of NGLs, in the long term, the growth and sustainability of our business depends on natural gas prices being at levels sufficient to provide incentives and capital, for producers to increase natural gas exploration and production. To minimize potential future commodity-based pricing and cash flow volatility, we have entered into a series of derivative financial instruments. As a result of these transactions, we have mitigated a portion of our expected natural gas, NGL and condensate commodity price risk relating to the equity volumes associated with our gathering and processing activities through 2015. Given the historical relationship between NGL prices and crude oil prices and the lack of liquidity in the NGL financial market, we have generally used crude oil swaps to mitigate a portion of NGL price risk. When the relationship of NGL prices to crude oil prices is at a discount to historical ranges, we experience additional exposure as a result of the relationship.

Based on historical trends, we generally expect NGL prices to directionally follow changes in crude oil prices over the long term. However, the pricing relationship between NGLs and crude oil may vary, as we believe crude oil prices will in large part be determined by the level of production from major crude oil exporting countries and the demand generated by growth in the world economy, whereas NGL prices are more correlated to supply and U.S. petrochemical demand. We believe that future natural gas prices will be influenced by North American supply deliverability, the severity of winter and summer weather, the level of North American production and drilling activity of exploration and production companies and imports of liquid natural gas, or LNG, from foreign locations. Drilling activity can be adversely affected as natural gas prices decrease. Energy market uncertainty could also further reduce North American drilling activity. Limited access to capital could also decrease drilling. Lower drilling levels over a sustained period would reduce natural gas volumes gathered and processed, but could increase commodity prices, if supply were to fall below demand levels.

 

Item 4.

Controls and Procedures

Evaluation of Disclosure Controls and Procedures

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports that we file or submit to the Securities and Exchange Commission under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified by the Commission’s rules and forms, and that information is accumulated and communicated to the management of our general partner, including our general partner’s principal executive and principal financial officers (whom we refer to as the Certifying Officers), as appropriate to allow timely decisions regarding required disclosure. The management of our general partner evaluated, with the participation of the Certifying Officers, the effectiveness of our disclosure controls and procedures as of September 30, 2010, pursuant to Rule 13a-15(b) under the Exchange Act. Based upon that evaluation, the Certifying Officers concluded that, as of September 30, 2010, our disclosure controls and procedures were effective.

 

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Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting that occurred during the quarter ended September 30, 2010 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

 

Item 1.

Legal Proceedings

Except for the matter noted below, the information required for this item is provided in Note 17, “Commitments and Contingent Liabilities,” included in Item 8 of our 2009 Form 10-K, which information is incorporated by reference into this item.

Driver — In August 2007, Driver Pipeline Company, Inc., or Driver, filed a lawsuit against DCP Midstream, LP, an affiliate of the owner of our general partner, in District Court, Jackson County, Texas. The litigation arose from a commercial dispute involving the construction of our Wilbreeze pipeline in 2006. Driver was the primary contractor for construction of the pipeline and the construction process was managed for us by DCP Midstream, LP. In June 2010 we settled this matter with Driver for $0.3 million.

 

Item 1A.

Risk Factors

In addition to the other information set forth in this report, careful consideration should be given to the risk factors discussed in Part I, “Item 1A. Risk Factors” in our 2009 Form 10-K. An investment in our securities involves various risks. When considering an investment in us, you should consider carefully all of the risk factors described in our 2009 Form 10-K. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial may also materially adversely affect our condensed consolidated results of operations, financial condition and cash flows

The following are new or modified risk factors that should be read in conjunction with the risk factors disclosed in our 2009 Form 10-K:

Our rates for treating natural gas may be subject to regulation, reduction and refund in response to a customer complaint before the Michigan Public Service Commission.

On August 25, 2010, a complaint was filed with the Michigan Public Service Commission (“MPSC”) against MichCon Gathering Company and DCP Midstream, LLC. The complaint was filed by certain producers/shippers that receive natural gas transportation and treatment services from MichCon Gathering Company for gas transported through its AEP pipeline. MichCon Gathering Company in turn has entered into a capacity agreement with DCP Antrim Gas LLC (“DCP Antrim”) for carbon dioxide treatment services through DCP Antrim’s South Chester Treating Facility. MichCon Gathering Company’s transportation services are regulated by the MPSC. The complaint alleges that the rates charged by MichCon Gathering Company and, indirectly, DCP Midstream, LLC, for treating services are excessive, and seeks unspecified reductions in such rates. The complaint requests that the MPSC assert jurisdiction over the carbon dioxide treating services, order MichCon Gathering Company and DCP Midstream, LLC to file tariffs setting forth the rates, terms, and conditions of service, and collect such rates under bond and subject to refund until such charges can be reviewed and approved by the MPSC. The filing of the complaint comes at a time when the initial service agreements for combined transportation and treating service entered into with MichCon Gathering Company are expiring and new transportation and treating services agreements are being separately negotiated by producers with MichCon Gathering Company and DCP Antrim, respectively. We cannot predict which producer/shippers will agree to continue to have their gas treated by DCP Midstream, LLC, whether jurisdiction will be assumed by the MPSC, or what the ultimate rate for treating services might be, or the amount of any potential refunds to be paid to producers/ shippers.

 

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Recent spills and their aftermath could lead to additional governmental regulation of the offshore exploration and production industry, which may result in substantial cost increases or delays in our offshore natural gas gathering activities.

In April 2010, a deepwater exploration well located in the Gulf of Mexico, owned and operated by companies unrelated to us, sustained a blowout and subsequent explosion leading to the leaking of hydrocarbons. In response to this event, certain federal agencies and governmental officials ordered additional inspections of deepwater operations in the Gulf of Mexico. On May 28, 2010, a six-month federal moratorium was implemented on all offshore deepwater drilling projects. On October 12, 2010, the Department of the Interior announced it was lifting the deepwater drilling moratorium. Despite the fact that the drilling moratorium was lifted, this spill and its aftermath is likely to lead to additional governmental regulation of the offshore exploration and production industry and delays in the issuance of drilling permits, which may result in volume impacts, cost increases or delays in our offshore natural gas gathering activities, which could materially impact our business, financial condition and results of operations. We cannot predict with any certainty what form any additional regulation or limitations would take.

Recent federal legislation could affect our ability to use derivative instruments to reduce the effect of commodity price and interest rate risks associated with our business.

We hedge both our commodity risk and our interest rate risk. The recently adopted comprehensive financial reform legislation establishes federal oversight and regulation of the over-the-counter derivatives and swaps markets and entities that participate in those markets. Regulations stemming from this new legislation may impose new requirements related to trade-execution and reporting of over-the-counter derivatives and swaps. The new legislation and any new regulations could increase the cost of derivative contracts (including through requirements to post collateral), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and its cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures and fund unitholder distributions. Any of these consequences could have a material adverse effect on us, our financial condition, and results of operations.

Our outstanding notes are senior unsecured obligations of our operating subsidiary, DCP Midstream Operating, LP, or DCP Operating, and are not guaranteed by any of our subsidiaries. As a result, our notes are effectively junior to DCP Operating’s existing and future secured debt and to all debt and other liabilities of its subsidiaries.

Our 3.25% Senior Notes Due 2015, or our notes, are senior unsecured obligations of our indirect wholly owned subsidiary, DCP Operating, and rank equally in right of payment with all of its other existing and future senior unsecured debt. All of our operating assets are owned by our subsidiaries, and none of these subsidiaries guarantee DCP Operating’s obligations with respect to the notes. Creditors of DCP Operating’s subsidiaries may have claims with respect to the assets of those subsidiaries that rank effectively senior to the notes. In the event of any distribution or payment of assets of such subsidiaries in any dissolution, winding up, liquidation, reorganization or bankruptcy proceeding, the claims of those creditors would be satisfied prior to making any such distribution or payment to DCP Operating in respect of its direct or indirect equity interests in such subsidiaries. Consequently, after satisfaction of the claims of such creditors, there may be little or no amounts left available to make payments in respect of our notes. As of September 30, 2010, DCP Operating’s subsidiaries had no debt for borrowed money owing to any unaffiliated third parties. However, such subsidiaries are not prohibited under the indenture governing the notes from incurring indebtedness in the future.

In addition, because our notes and our guarantee of our notes are unsecured, holders of any secured indebtedness of us would have claims with respect to the assets constituting collateral for such indebtedness that are senior to the claims of the holders of our notes. Currently, we do not have any secured indebtedness. Although the indenture governing our notes places some limitations on our ability to create liens securing debt, there are significant exceptions to these limitations that will allow us to secure significant amounts of indebtedness without equally and ratably securing the notes. If we incur secured indebtedness and such indebtedness is either accelerated or becomes subject to a bankruptcy, liquidation or reorganization, our assets would be used to satisfy obligations with respect to the indebtedness secured thereby before any payment could be made on our notes. Consequently, any such secured indebtedness would effectively be senior to our notes and our guarantee of our notes, to the extent of the value of the collateral securing the secured indebtedness. In that event, noteholders may not be able to recover all the principal or interest due under our notes.

 

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Our significant indebtedness and the restrictions in our debt agreements may adversely affect our future financial and operating flexibility.

As of September 30, 2010, our consolidated indebtedness was $612.8 million. Our substantial indebtedness and the additional debt we may incur in the future for potential acquisitions may adversely affect our liquidity and therefore our ability to make interest payments on our notes.

Among other things, our significant indebtedness may be viewed negatively by credit rating agencies, which could result in increased costs for us to access the capital markets. Any future downgrade of the debt issued by us or our subsidiaries could significantly increase our capital costs or adversely affect our ability to raise capital in the future.

Debt service obligations and restrictive covenants in our credit facility and the indenture governing our notes may adversely affect our ability to finance future operations, pursue acquisitions and fund other capital needs as well as our ability to make cash distributions unitholders. In addition, this leverage may make our results of operations more susceptible to adverse economic or operating conditions by limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate and may place us at a competitive disadvantage as compared to our competitors that have less debt.

If we incur any additional indebtedness, including trade payables, that ranks equally with our notes, the holders of that debt will be entitled to share ratably with the holders of our notes in any proceeds distributed in connection with any insolvency, liquidation, reorganization, dissolution or other winding up of us or DCP Operating. This may have the effect of reducing the amount of proceeds paid to noteholders. If new debt is added to our current debt levels, the related risks that we now face could intensify.

We have a holding company structure in which our subsidiaries conduct our operations and own our operating assets.

We are a holding company, and our subsidiaries conduct all of our operations and own all of our operating assets. We do not have significant assets other than equity in our subsidiaries and equity investees. As a result, our ability to make required payments on our notes depends on the performance of our subsidiaries and their ability to distribute funds to us. The ability of our subsidiaries to make distributions to us may be restricted by, among other things, credit instruments, applicable state business organization laws and other laws and regulations. If our subsidiaries are prevented from distributing funds to us, we may be unable to pay all the principal and interest on the notes when due.

 

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Item 6.

Exhibits

Exhibits

 

Exhibit Number		Description
3.1*		First Amended and Restated Agreement of Limited Partnership of DCP Midstream GP, LP (attached as Exhibit 3.4 to DCP Midstream Partners, LP’s Amendment No. 2 to Registration Statement on Form S-1 (File No. 333-128378) filed with the SEC on November 18, 2005).
3.2*		First Amended and Restated Limited Liability Company Agreement of DCP Midstream GP, LLC (attached as Exhibit 3.6 to DCP Midstream Partners, LP’s Amendment No. 2 to Registration Statement on Form S-1 (File No. 333-128378) filed with the SEC on November 18, 2005).
3.3*		Second Amended and Restated Agreement of Limited Partnership of DCP Midstream Partners, LP (attached as Exhibit 3.1 to DCP Midstream Partners, LP’s Form 8-K (File No. 001-32678) filed with the SEC on November 7, 2006).
3.4*		Amendment No. 1 to Amended and Restated Limited Liability Company Agreement of DCP Midstream GP, LLC dated as of January 20, 2009 and Amended and Restated Limited Liability Company Agreement of DCP Midstream GP, LLC dated December 7, 2005 (attached as Exhibit 3.1 to DCP Midstream Partners, LP’s Form 10-K (File No. 001-32678) filed with the SEC on March 5, 2009).
3.5*		Amendment No. 1 to Second Amended and Restated Agreement of Limited Partnership of DCP Midstream Partners, LP, dated as of April 11, 2008 (attached as Exhibit 4.1 to DCP Midstream Partners, LP’s Form 8-K (File No. 001-32678) filed with the SEC on April 14, 2008).
3.6*		Amendment No. 2 to the Second Amended and Restated Agreement of Limited Partnership of DCP Midstream Partners, LP (attached as Exhibit 3.1 to DCP Midstream Partners, LP’s Form 8-K (File No. 001-32678) filed with the SEC on April 7, 2009).
10.1		Amended and Restated Credit Agreement, dated June 21, 2007.
12.1		Ratio of Earnings to Fixed Charges.
31.1		Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1		Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2		Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

 

*	Such exhibit has heretofore been filed with the SEC as part of the filing indicated and is incorporated herein by reference.

 

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Denver, State of Colorado, on November 09, 2010.

 

 

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EXHIBIT INDEX

 

Exhibit Number		Description
3.1*		First Amended and Restated Agreement of Limited Partnership of DCP Midstream GP, LP (attached as Exhibit 3.4 to DCP Midstream Partners, LP’s Amendment No. 2 to Registration Statement on Form S-1 (File No. 333-128378) filed with the SEC on November 18, 2005).
3.2*		First Amended and Restated Limited Liability Company Agreement of DCP Midstream GP, LLC (attached as Exhibit 3.6 to DCP Midstream Partners, LP’s Amendment No. 2 to Registration Statement on Form S-1 (File No. 333-128378) filed with the SEC on November 18, 2005).
3.3*		Second Amended and Restated Agreement of Limited Partnership of DCP Midstream Partners, LP (attached as Exhibit 3.1 to DCP Midstream Partners, LP’s Form 8-K (File No. 001-32678) filed with the SEC on November 7, 2006).
3.4*		Amendment No. 1 to Amended and Restated Limited Liability Company Agreement of DCP Midstream GP, LLC dated as of January 20, 2009 and Amended and Restated Limited Liability Company Agreement of DCP Midstream GP, LLC dated December 7, 2005 (attached as Exhibit 3.1 to DCP Midstream Partners, LP’s Form 10-K (File No. 001-32678) filed with the SEC on March 5, 2009).
3.5*		Amendment No. 1 to Second Amended and Restated Agreement of Limited Partnership of DCP Midstream Partners, LP, dated as of April 11, 2008 (attached as Exhibit 4.1 to DCP Midstream Partners, LP’s Form 8-K (File No. 001-32678) filed with the SEC on April 14, 2008).
3.6*		Amendment No. 2 to the Second Amended and Restated Agreement of Limited Partnership of DCP Midstream Partners, LP (attached as Exhibit 3.1 to DCP Midstream Partners, LP’s Form 8-K (File No. 001-32678) filed with the SEC on April 7, 2009).
10.1		Amended and Restated Credit Agreement, dated June 21, 2007.
12.1		Ratio of Earnings to Fixed Charges.
31.1		Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1		Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2		Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

 

*	Such exhibit has heretofore been filed with the SEC as part of the filing indicated and is incorporated herein by reference.

 

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