UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington D.C. 20549

 

 

FORM 8-K

 

 

CURRENT REPORT

Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

Date of report (date of earliest event reported): May 26, 2010

 

 

DCP MIDSTREAM PARTNERS, LP

(Exact name of registrant as specified in its charter)

 

 

 

Delaware		001-32678		03-0567133
(State or other jurisdiction of incorporation)		(Commission File No.)		(IRS Employer Identification No.)

 

370 17th Street, Suite 2775, Denver, Colorado		80202
(Address of principal executive offices)		(Zip Code)

(303) 633-2900

(Registrant’s telephone number, including area code)

Not Applicable

(Former name or former address, if changed since last report)

 

 

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the Registrant under any of the following provisions:

 

¨	Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

 

¨	Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

 

¨	Pre-commencement communications pursuant to Rule 14d-2(b) under Exchange Act (17 CFR 240.14d-2(b))

 

¨	Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

 

 

 

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Item 8.01.

Other Events.

DCP Midstream Partners, LP, (the “Partnership”) is filing this Current Report on Form 8-K (this “Report”) in connection with the anticipated filing with the Securities and Exchange Commission (“SEC”) of a shelf registration statement on Form S-3 relating to the offering of securities (the “Securities”) of the Partnership and its subsidiary, DCP Midstream Operating, LP (“DCP Operating”). The new shelf registration statement will replace the Partnership’s existing shelf registration statement that expires in November 2010. The Securities, including debt securities of DCP Operating that will be unconditionally guaranteed by the Partnership, may be offered for sale from time to time. This Report adds Note 14 to the Partnership’s unaudited condensed consolidated financial statements included within Part I, Item 1 of the Partnership’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2010 (the “First Quarter 2010 Form 10-Q”), filed with the SEC on May 10, 2010.

The Partnership is providing the additional note to the Partnership’s financial statements to provide condensed consolidating financial information in accordance with Rule 3-10(c) of Regulation S-X promulgated by the SEC because the debt securities may be fully and unconditionally guaranteed by the Partnership. To reflect the addition of Note 14 to the Partnership’s First Quarter 2010 Form 10-Q, Part 1, Item 1 of the First Quarter 2010 Form 10-Q is being amended in its entirety and is attached as Exhibit 99.1 hereto and is incorporated by reference herein.

Because this Current Report is being filed only for the purposes described above, and only affects the Item specified above, the other information contained in the First Quarter 2010 Form 10-Q remains unchanged. No attempt has been made in this Current Report nor in the Exhibit hereto to modify or update disclosures in the First Quarter 2010 Form 10-Q except as described above. Accordingly, this Current Report should be read in conjunction with the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2009 (the “2009 Form 10-K”) and the Partnership’s filings with the SEC subsequent to the filing of the 2009 Form 10-K, including the First Quarter 2010 Form 10-Q.

 

Item 9.01.

Financial Statements and Exhibits.

(d) Exhibits.

 

Exhibit Number		Description
Exhibit 99.1		Update to the Partnership’s First Quarter 2010 Form 10-Q. Part I, Item 1. Financial Statements.

 

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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 hereunto duly authorized.

 

May 26, 2010

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EXHIBIT INDEX

 

Exhibit Number		Description
Exhibit 99.1		Update to the Partnership’s First Quarter 2010 Form 10-Q. Part I, Item 1. Financial Statements.

Exhibit 99.1

PART I. FINANCIAL INFORMATION

 

Item 1.

Financial Statements

DCP MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

 

		March 31, 2010				December 31, 2009
		(Millions)
ASSETS
Current assets:
Cash and cash equivalents		$	2.6			$	2.1
Accounts receivable:
Trade, net of allowance for doubtful accounts of $0.6 million and $0.5 million, respectively			59.6				78.7
Affiliates			60.9				73.8
Inventories			43.1				34.2
Unrealized gains on derivative instruments			6.9				7.3
Other			0.8				1.6
Total current assets			173.9				197.7
Restricted investments			—				10.0
Property, plant and equipment, net			1,017.0				1,000.1
Goodwill			92.1				92.1
Intangible assets, net			59.7				60.5
Investments in unconsolidated affiliates			113.5				114.6
Unrealized gains on derivative instruments			3.6				2.0
Other long-term assets			4.4				4.5
Total assets		$	1,464.2			$	1,481.5
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable:
Trade		$	67.8			$	85.5
Affiliates			52.1				43.1
Unrealized losses on derivative instruments			41.5				41.5
Accrued interest payable			0.7				0.7
Other			19.0				20.3
Total current liabilities			181.1				191.1
Long-term debt			615.0				613.0
Unrealized losses on derivative instruments			53.0				58.0
Other long-term liabilities			14.3				14.0
Total liabilities			863.4				876.1
Commitments and contingent liabilities
Equity:
Common unitholders (34,608,183 units issued and outstanding)			417.6				415.5
General partner unitholders			(5.8	)			(5.9	)
Accumulated other comprehensive loss			(33.5	)			(31.9	)
Total partners’ equity			378.3				377.7
Noncontrolling interests			222.5				227.7
Total equity			600.8				605.4
Total liabilities and equity		$	1,464.2			$	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 March  31,
		2010				2009
		(Millions, except per unit amounts)
Operating revenues:
Sales of natural gas, propane, NGLs and condensate		$	235.4			$	157.2
Sales of natural gas, propane, NGLs and condensate to affiliates			135.0				99.9
Transportation, processing and other			21.6				16.7
Transportation, processing and other to affiliates			5.7				3.6
Gains from commodity derivative activity, net			6.0				7.7
Losses from commodity derivative activity, net — affiliates			—				(0.7	)
Total operating revenues			403.7				284.4
Operating costs and expenses:
Purchases of natural gas, propane and NGLs			191.5				137.8
Purchases of natural gas, propane and NGLs from affiliates			141.3				79.1
Operating and maintenance expense			19.0				16.2
Depreciation and amortization expense			17.8				14.6
General and administrative expense			3.7				3.2
General and administrative expense — affiliates			4.9				5.4
Total operating costs and expenses			378.2				256.3
Operating income			25.5				28.1
Interest income			—				0.2
Interest expense			(7.2	)			(7.3	)
Earnings (losses) from unconsolidated affiliates			7.9				(1.1	)
Income before income taxes			26.2				19.9
Income tax expense			(0.3	)			(0.1	)
Net income			25.9				19.8
Net (income) loss attributable to noncontrolling interests			(0.1	)			1.3
Net income attributable to partners			25.8				21.1
Net loss attributable to predecessor operations			—				1.0
General partner unitholders’ interest in net income			(3.8	)			(3.2	)
Net income allocable to limited partners		$	22.0			$	18.9
Net income per limited partner unit — basic and diluted		$	0.64			$	0.67
Weighted-average limited partner units outstanding — basic and diluted			34.6				28.2

See accompanying notes to condensed consolidated financial statements.

 

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DCP MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

 

		Three Months Ended March  31,
		2010				2009
		(Millions)
Net income		$	25.9			$	19.8
Other comprehensive loss:
Reclassification of cash flow hedge losses into earnings			6.0				4.5
Net unrealized losses on cash flow hedges			(7.6	)			(4.5	)
Total other comprehensive loss			(1.6	)			—
Total comprehensive income			24.3				19.8
Total comprehensive (income) loss attributable to noncontrolling interests			(0.1	)			1.3
Total comprehensive income attributable to partners		$	24.2			$	21.1

See accompanying notes to condensed consolidated financial statements.

 

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DCP MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

 

		Three Months Ended March  31,
		2010				2009
		(Millions)
OPERATING ACTIVITIES:
Net income		$	25.9			$	19.8
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense			17.8				14.6
(Earnings) losses from unconsolidated affiliates			(7.9	)			1.1
Distributions from unconsolidated affiliates			9.8				0.5
Other, net			0.5				0.5
Change in operating assets and liabilities, which provided (used) cash net of effects of acquisitions:
Accounts receivable			31.9				14.0
Inventories			(8.9	)			2.9
Net unrealized gains on derivative instruments			(7.8	)			(0.2	)
Accounts payable			(9.3	)			(20.2	)
Accrued interest			—				(0.4	)
Other current assets and liabilities			(0.9	)			(2.5	)
Other long-term assets and liabilities			(0.1	)			0.4
Net cash provided by operating activities			51.0				30.5
INVESTING ACTIVITIES:
Capital expenditures			(12.2	)			(55.9	)
Acquisitions, net of cash acquired			(22.0	)			(0.3	)
Investments in unconsolidated affiliates			(0.7	)			(0.2	)
Proceeds from sale of assets			0.2				—
Purchases of available-for-sale securities			—				(1.0	)
Proceeds from sales of available-for-sale securities			10.1				0.8
Net cash used in investing activities			(24.6	)			(56.6	)
FINANCING ACTIVITIES:
Proceeds from debt			116.6				—
Payments of debt			(114.6	)			(11.5	)
Net change in advances to predecessor from DCP Midstream, LLC			—				3.0
Distributions to unitholders and general partner			(24.6	)			(20.1	)
Distributions to noncontrolling interests			(3.7	)			(3.9	)
Contributions from noncontrolling interests			3.9				8.7
Purchase of additional interest in a subsidiary			(3.5	)			—
Net cash used in financing activities			(25.9	)			(23.8	)
Net change in cash and cash equivalents			0.5				(49.9	)
Cash and cash equivalents, beginning of period			2.1				61.9
Cash and cash equivalents, end of period		$	2.6			$	12.0

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				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	)
Distributions			—				(20.8	)			—				(3.8	)			—				(3.7	)			(28.3	)
Contributions			—				—				—				—				—				3.9				3.9
Comprehensive income (loss):
Net income			—				21.9				—				3.9				—				0.1				25.9
Reclassification of cash flow hedge losses into earnings			—				—				—				—				6.0				—				6.0
Net unrealized losses on cash flow hedges			—				—				—				—				(7.6	)			—				(7.6	)
Total comprehensive income (loss)			—				21.9				—				3.9				(1.6	)			0.1				24.3
Balance, March 31, 2010		$	—			$	417.6			$	—			$	(5.8	)		$	(33.5	)		$	222.5			$	600.8
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
Distributions			—				(14.8	)			(2.1	)			(3.2	)			—				(3.9	)			(24.0	)
Conversion of subordinated units to common units			—				(52.1	)			52.1				—				—				—				—
Contributions			—				—				—				—				—				8.7				8.7
Comprehensive income (loss):
Net loss attributable to predecessor operations			(1.0	)			—				—				—				—				—				(1.0	)
Net income (loss)			—				14.3				4.6				3.2				—				(1.3	)			20.8
Reclassification of cash flow hedge losses into earnings			—				—				—				—				4.5				—				4.5
Net unrealized losses on cash flow hedges			—				—				—				—				(4.5	)			—				(4.5	)
Total comprehensive (loss) income			(1.0	)			14.3				4.6				3.2				—				(1.3	)			19.8
Balance, March 31, 2009		$	68.0			$	376.4			$	—			$	(4.8	)		$	(40.5	)		$	171.2			$	570.3

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 and selling natural gas, producing, transporting, storing and selling propane and 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 and 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; and our NGL transportation pipelines (which includes our Wattenberg pipeline acquired in January 2010).

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 35% of our partnership.

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, 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. This transaction was 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 East Texas 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 and our Wattenberg pipeline 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 months ended March 31, 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 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 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%. We may pay an additional $2.0 million of contingent consideration to Delta, depending on volumes Delta delivers, by June 30, 2011, pursuant to a processing agreement. As of March 31, 2010, we have recognized the fair value of this contingent consideration of approximately $1.0 million, which we have recorded to other current liabilities in our condensed consolidated balance sheet. In addition, as part of this transaction we assumed Delta’s unpaid capital calls to Collbran of $2.4 million, which have been paid as of March 31, 2010. Accordingly we have 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 represents the difference between the fair value of the consideration and the carrying value of Delta’s 5% interest.

 

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

On January 28, 2010 we acquired an interstate natural gas liquids pipeline, or the Wattenberg pipeline, from Buckeye Partners, L.P., for $22.0 million in cash, funded 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.

On April 1, 2009, we acquired an additional 25.1% interest in East Texas, and a fixed price natural gas liquids derivative by NGL component for the period of April 2009 to March 2010, or NGL Hedge, from DCP Midstream, LLC, for aggregate consideration of 3,500,000 Class D units, valued at $49.7 million. This transaction was among entities under common control. Prior to this transaction we owned a 25.0% interest in East Texas, which we accounted for under the equity method of accounting. Subsequent to this transaction we own a 50.1% interest in East Texas, and account for East Texas as a consolidated subsidiary.

Combined Financial Information

The following table presents the impact on the condensed consolidated statements of operations, adjusted for the acquisition of an additional 25.1% interest in East Texas, from DCP Midstream, LLC, for the three months ended March 31, 2009.

Three Months Ended March 31, 2009

 

		DCP Midstream Partners,  LP (As previously reported)				Consolidate East Texas				Remove East Texas Equity Losses			Combined DCP Midstream Partners, LP
		(a)				(b)				(c)
		(Millions)
Operating revenues:
Sales of natural gas, propane, NGLs and condensate		$	217.7			$	39.4			$	—		$	257.1
Transportation, processing and other			15.9				4.4				—			20.3
Gains from commodity derivative activity, net			7.0				—				—			7.0
Total operating revenues			240.6				43.8				—			284.4
Operating costs and expenses:
Purchases of natural gas, propane and NGLs			182.8				34.1				—			216.9
Operating and maintenance expense			9.2				7.0				—			16.2
Depreciation and amortization expense			10.4				4.2				—			14.6
General and administrative expense			5.8				2.8				—			8.6
Total operating costs and expenses			208.2				48.1				—			256.3
Operating income (loss)			32.4				(4.3	)			—			28.1
Interest expense, net			(7.1	)			—				—			(7.1	)
Losses from unconsolidated affiliates			(2.2	)			—				1.1			(1.1	)
Income (loss) before income taxes			23.1				(4.3	)			1.1			19.9
Income tax expense			(0.1	)			—				—			(0.1	)
Net income (loss)			23.0				(4.3	)			1.1			19.8
Net (income) loss attributable to noncontrolling interests			(0.9	)			2.2				—			1.3
Net income (loss) attributable to partners		$	22.1			$	(2.1	)		$	1.1		$	21.1

 

(a)	Amounts as previously reported with 25% of East Texas’ results presented as losses from unconsolidated affiliates.

(b)	Adjustments to present East Texas on a consolidated basis at 100%, with noncontrolling interest of 49.9%.

(c)	Adjustments to remove East Texas equity losses at 25%.

 

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

The following table presents unaudited pro forma information for the condensed consolidated statements of operations for the three months ended March 31, 2010 and 2009, as if the acquisition of the Wattenberg pipeline had occurred at the beginning of each period presented. Revenues of $0.6 million and net income attributable to partners of $0.3 million, associated with the acquired assets, from the date of acquisition through March 31, 2010 have been included in the Condensed Consolidated Statement of Operations.

 

		Three Months Ended March 31, 2010											Three Months Ended March 31, 2009
		DCP Midstream Partners, LP				Acquisition of the Wattenberg Pipeline			DCP Midstream Partners, LP Pro Forma				DCP Midstream Partners, LP				Acquisition of the Wattenberg Pipeline			DCP Midstream Partners, LP Pro Forma
		(Millions, except per unit amounts)
Total operating revenues		$	403.7			$	0.2		$	403.9			$	284.4			$	3.3		$	287.7
Net income attributable to partners		$	25.8			$	0.1		$	25.9			$	21.1			$	2.0		$	23.1
Less:
Net loss attributable to predecessor operations			—				—			—				1.0				—			1.0
General partner unitholders interest in net income			(3.8	)			—			(3.8	)			(3.2	)			—			(3.2	)
Net income allocable to limited partners		$	22.0			$	0.1		$	22.1			$	18.9			$	2.0		$	20.9
Net income per limited partner unit – basic and diluted		$	0.64			$	—		$	0.64			$	0.67			$	0.07		$	0.74

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 and $2.4 million, respectively, for the three months ended March 31, 2010 and 2009, for all fees under the Omnibus Agreement.

East Texas incurs general and administrative expenses directly from DCP Midstream, LLC. During the three months ended March 31, 2010 and 2009 East Texas incurred $2.0 million and $2.2 million, respectively, for general and administrative expenses from DCP Midstream, LLC, which includes expenses for our predecessor operations.

Outside of the Omnibus Agreement and amounts incurred by East Texas, we incurred other fees with DCP Midstream, LLC of $0.3 million and $0.7 million for the three months ended March 31, 2010 and 2009, respectively. These amounts include allocated expenses, including professional services, insurance and internal audit.

Other Agreements and Transactions with DCP Midstream, LLC

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 generally report revenues associated with these activities in the condensed consolidated statements of operations as transportation, processing and other to affiliates.

 

9

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

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 amounts of East Texas capital projects as defined in the Contribution Agreements. These reimbursements are for a period not to exceed three years from the respective acquisition dates. DCP Midstream, LLC made capital contributions to East Texas for capital projects of $3.8 million and $10.9 million for the three months ended March 31, 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, 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 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 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 Lindsay 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 Lindsay 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.

DCP Midstream, LLC has issued parental guarantees, totaling $103.0 million as of March 31, 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 $60.0 million of these outstanding guarantees.

DCP Midstream, LLC was a significant customer during the three months ended March 31, 2010 and 2009.

 

10

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

Spectra Energy

We entered into a propane supply agreement with Spectra Energy, effective May 1, 2008 and terminating April 30, 2014, which provides us propane supply at our marine terminal, which is included in our Wholesale Propane Logistics segment, for up to approximately 120 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 and $0.2 million of capital reimbursements during the three months ended March 31, 2010 and 2009, respectively.

Summary of Transactions with Affiliates

The following table summarizes the transactions with affiliates:

 

		Three Months Ended March  31,
		2010			2009
		(Millions)
DCP Midstream, LLC:
Sales of natural gas, propane, NGLs and condensate		$	133.6		$	99.8
Transportation, processing and other		$	3.8		$	1.2
Purchases of natural gas, propane and NGLs		$	62.8		$	43.1
Losses from commodity derivative activity, net		$	—		$	(0.7	)
General and administrative expense		$	4.8		$	5.3
Interest expense		$	0.1		$	0.1
Spectra Energy:
Purchases of natural gas, propane and NGLs		$	74.1		$	33.7
ConocoPhillips:
Sales of natural gas, propane, NGLs and condensate		$	1.4		$	0.1
Transportation, processing and other		$	1.9		$	2.4
Purchases of natural gas, propane and NGLs		$	2.0		$	1.9
General and administrative expense		$	0.1		$	0.1
Unconsolidated affiliates:
Purchases of natural gas, propane and NGLs		$	2.4		$	0.4

 

11

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

We had balances with affiliates as follows:

 

		March 31, 2010				December 31, 2009
		(Millions)
DCP Midstream, LLC:
Accounts receivable		$	58.1			$	71.5
Accounts payable		$	25.3			$	24.4
Unrealized gains on derivative instruments—current		$	4.0			$	5.5
Unrealized losses on derivative instruments—current		$	(3.8	)		$	(5.4	)
Spectra Energy:
Accounts receivable		$	0.7			$	0.1
Accounts payable		$	23.8			$	16.6
ConocoPhillips:
Accounts receivable		$	2.1			$	2.2
Accounts payable		$	0.6			$	2.1
Unconsolidated affiliates:
Accounts payable		$	2.4			$	—

5. Property, Plant and Equipment

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

 

		Depreciable Life		March 31, 2010				December 31, 2009
				(Millions)
Gathering systems		15 — 30 Years		$	687.7			$	683.0
Processing plants		25 — 30 Years			431.8				427.4
Terminals		25 — 30 Years			29.0				28.9
Transportation		25 — 30 Years			239.1				217.2
General plant		3 — 5 Years			15.6				15.2
Other		20 — 50 Years			0.1				0.1
Construction work in progress					24.2				21.8
Property, plant and equipment					1,427.5				1,393.6
Accumulated depreciation					(410.5	)			(393.5	)
Property, plant and equipment, net				$	1,017.0			$	1,000.1

The above amounts include accrued capital expenditures of $3.2 million and $3.8 million as of March 31, 2010 and December 31, 2009, respectively, which are included in other current liabilities in the condensed consolidated balance sheets. Interest capitalized on construction projects for the three months ended March 31, 2010 was $0 and for the year ended December 31, 2009 was $1.3 million.

Depreciation expense was $17.0 million and $14.0 million for the three months ended March 31, 2010 and 2009, respectively.

 

12

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

6. Investments in Unconsolidated Affiliates

The following table summarizes our investments in unconsolidated affiliates:

 

		Percentage of Ownership as of			Carrying Value as of
		March 31, 2010 and December 31, 2009			March 31, 2010			December 31, 2009
					(Millions)
Discovery Producer Services LLC		40	%		$	106.9		$	108.2
Black Lake Pipe Line Company		45	%			6.4			6.2
Other		50	%			0.2			0.2
Total investments in unconsolidated affiliates					$	113.5		$	114.6

There was a deficit between the carrying amount of the investment and the underlying equity of Discovery of $37.0 million and $37.6 million at March 31, 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 $5.6 million and $5.7 million at March 31, 2010 and December 31, 2009, respectively, which is associated with, and is being accreted over, the life of the underlying long-lived assets of Black Lake.

Earnings (losses) from investments in unconsolidated affiliates were as follows:

 

		Three Months Ended March  31,
		2010			2009
		(Millions)
Discovery Producer Services LLC		$	7.4		$	(1.5	)
Black Lake Pipe Line Company and other			0.5			0.4
Total earnings (losses) from unconsolidated affiliates		$	7.9		$	(1.1	)

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

 

		Three Months Ended March  31,
		2010			2009
		(Millions)
Statements of operations:
Operating revenue		$	61.6		$	21.5
Operating expenses		$	43.5		$	25.9
Net income (loss)		$	18.0		$	(4.6	)

 

13

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

		March 31, 2010				December 31, 2009
		(Millions)
Balance sheets:
Current assets		$	41.9			$	41.8
Long-term assets			380.2				383.8
Current liabilities			(18.1	)			(17.4	)
Long-term liabilities			(24.0	)			(23.6	)
Net assets		$	380.0			$	384.6

7. 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.

 

14

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

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 9 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.

 

•

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.

 

15

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

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.

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. As of March 31, 2010, we held no short-term or restricted investments.

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.

 

16

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

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

 

		March 31, 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)		$	—		$	5.4			$	1.5			$	6.9			$	—		$	6.9			$	0.4			$	7.3
Long-term assets:
Restricted investments		$	—		$	—			$	—			$	—			$	—		$	10.0			$	—			$	10.0
Commodity derivatives (c)		$	—		$	2.4			$	1.2			$	3.6			$	—		$	1.8			$	0.2			$	2.0
Current liabilities (d):
Commodity derivatives		$	—		$	(20.7	)		$	(0.3	)		$	(21.0	)		$	—		$	(20.3	)		$	(0.8	)		$	(21.1	)
Interest rate derivatives		$	—		$	(20.5	)		$	—			$	(20.5	)		$	—		$	(20.4	)		$	—			$	(20.4	)
Long-term liabilities (e):
Commodity derivatives		$	—		$	(39.1	)		$	(0.4	)		$	(39.5	)		$	—		$	(46.0	)		$	(0.4	)		$	(46.4	)
Interest rate derivatives		$	—		$	(13.5	)		$	—			$	(13.5	)		$	—		$	(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.

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 a movement 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.

 

17

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

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 March 31, 2010:
Beginning balance		$	0.4			$	0.2		$	(0.8	)		$	(0.4	)
Net realized and unrealized gains (losses) included in earnings			1.2				1.0			(0.1	)			—
Transfers into Level 3 (a)			—				—			—				—
Transfers out of Level 3 (a)			—				—			—				—
Purchases, Issuances and Settlements net			(0.1	)			—			0.6				—
Ending balance		$	1.5			$	1.2		$	(0.3	)		$	(0.4	)
Net unrealized gains still held included in earnings (b)		$	1.2			$	1.0		$	0.4			$	—
Three months ended March 31, 2009:
Beginning balance		$	0.3			$	1.7		$	—			$	—
Net realized and unrealized gains (losses) included in earnings			0.8				—			—				(0.3	)
Net transfers in (out) of Level 3 (c)			—				—			—				—
Purchases, Issuances and Settlements net			(0.1	)			—			—				—
Ending balance		$	1.0			$	1.7		$	—			$	(0.3	)
Net unrealized gains (losses) still held included in earnings (b)		$	0.8			$	—		$	—			$	(0.3	)

 

(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 March 31, 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.

During the three months ended March 31, 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.

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 $615.0 million, and $593.9 million, respectively, as of March 31, 2010 and $613.0 million and $590.0 million, respectively, as of December 31, 2009. 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.

 

18

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

8. Debt

Long-term debt was as follows:

 

		March 31, 2010			December 31, 2009
		(Millions)
Revolving credit facility, weighted-average variable interest rate of 0.70% and 0.69%, respectively, and net effective interest rate of 4.33% and 4.41%, respectively, due June 21, 2012 (a)		$	615.0		$	603.0
Term loan facility, variable interest rate of 0.34%, due June 21, 2012 (b)			—			10.0
Total long-term debt		$	615.0		$	613.0

 

(a)	$575.0 million of debt has been swapped to a fixed rate obligation with effective fixed rates ranging from 2.26% to 5.19%, for a net effective rate of 4.33% on the $615.0 million of outstanding debt under our revolving credit facility as of March 31, 2010.

(b)	The term loan facility is fully secured by restricted investments.

Credit Agreement

We have an $824.6 million revolving credit facility that matures June 21, 2012, or the Credit Agreement.

At March 31, 2010 and December 31, 2009, we had $0.3 million of 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 March 31, 2010 the available capacity under the revolving credit facility was $209.3 million, which is net of non-participation by Lehman Brothers Commercial Bank.

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. Prior to our credit rating that we received on December 7, 2009 from Standard & Poor’s Ratings Group, the Credit Agreement also required us to maintain an interest coverage ratio (the ratio of our consolidated EBITDA to our consolidated interest expense, in each case as is defined by the Credit Agreement) of equal or greater than 2.5 to 1.0 determined as of the last day of each quarter for the four-quarter period ending on the date of determination. As a result of our credit rating, we are no longer required to maintain this interest coverage ratio.

Our borrowing capacity may be limited 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.

Other Agreements

As of March 31, 2010, we had an outstanding letter of credit with a counterparty to our commodity derivative instruments of $10.0 million, which reduces the amount of cash we may be required to post as collateral. We pay a fee of 0.75% per annum on this letter of credit. This letter of credit was issued directly by a financial institution and does not reduce the available capacity under our credit facility.

 

19

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

9. 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.

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, including derivative instruments entered into subsequent to the balance sheet date. 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 outside of 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 rate price risk for a fixed rate. 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.

 

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

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.

Interest Rate Risk

Interest Rate Cash Flow Hedges — 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 an aggregate of $575.0 million of the indebtedness outstanding under our revolving credit facility to a fixed rate obligation, thereby reducing the exposure to market rate fluctuations. All interest rate swap agreements have been designated 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. $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 March 31, 2010, we are not a party to any agreements that would be subject to these provisions other than our Credit Agreement.

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.

 

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

As of March 31, 2010, we had $56.8 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 March 31, 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 March 31, 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 $52.3 million.

As of March 31, 2010 our interest rate swaps were in a net liability position of approximately $34.0 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 March 31, 2010, we had an outstanding letter of credit with a counterparty to our commodity derivative instruments of $10.0 million and DCP Midstream, LLC had issued and outstanding parental guarantees totaling $103.0 million in favor of certain counterparties to our commodity derivative instruments. This letter of credit and the parental guarantees reduce the amount of cash we may be required to post as collateral. As of March 31, 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:

 

		March 31, 2010				December 31, 2009
		(Millions)
Commodity cash flow hedges:
Net deferred losses in AOCI		$	(0.4	)		$	(0.8	)
Interest rate cash flow hedges:
Net deferred losses in AOCI			(33.1	)			(31.1	)
Total AOCI		$	(33.5	)		$	(31.9	)

 

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(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		March 31, 2010			December 31, 2009			Balance Sheet Line Item		March 31, 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		$	(20.5	)		$	(20.4	)
Unrealized gains on derivative instruments – long term			—			—		Unrealized losses on derivative instruments – long term			(13.5	)			(11.6	)
		$	—		$	—				$	(34.0	)		$	(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		$	6.9		$	7.3		Unrealized losses on derivative instruments – current		$	(21.0	)		$	(21.1	)
Unrealized gains on derivative instruments – long term			3.6			2.0		Unrealized losses on derivative instruments – long term			(39.5	)			(46.4	)
		$	10.5		$	9.3				$	(60.5	)		$	(67.5	)

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.

 

		Gain (Loss) Recognized in AOCI on Derivatives — Effective Portion								Gain (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
		Three Months Ended March 31,																							Over the Next
		2010				2009				2010				2009				2010			2009				12 Months
		(Millions)								(Millions)								(Millions)							(Millions)
Interest rate derivatives		$	(7.6	)		$	(4.5	)		$	(5.6	)		$	(4.0	)(a)		$	—		$	—	(a)(c)		$	(19.7	)
Commodity derivatives		$	—			$	—			$	(0.4	)		$	(0.5	)(b)		$	—		$	—	(b)(c)		$	(0.2	)

 

(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 March 31, 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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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

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 March 31,
		2010				2009
		(Millions)
Third party:
Realized		$	(2.1	)		$	6.9
Unrealized			8.1				0.8
Gains from commodity derivative activity, net		$	6.0			$	7.7
Affiliates:
Realized		$	(0.1	)		$	(0.7	)
Unrealized			0.1				—
Losses from commodity derivative activity, net — affiliates		$	—			$	(0.7	)

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

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.

 

		March 31, 2010
		Crude Oil			Natural Gas			Natural Gas Liquids
Year of Expiration		Net Long (Short) Position (Bbls)			Net Long (Short) Position (MMBtu)			Net Long (Short) Position (Bbls)
2010		(732,875	)		(1,840,000	)		(440,000	)
2011		(949,000	)		(1,496,500	)		—
2012		(777,750	)		(1,500,600	)		—
2013		(748,250	)		(730,000	)		—
2014		(365,000	)		—			—

We periodically enter into interest rate swap agreements to mitigate a portion of our floating rate interest exposure. As of March 31, 2010 we have swaps with a notional value between $25.0 million and $150.0 million, which, in aggregate, exchange $575.0 million of our floating rate obligation to a fixed rate obligation through June 2012.

10. 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 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 who exercised 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 LP Holdings, LP and DCP Midstream GP, LP in consideration for an additional 25.1% interest in East Texas and the NGL Hedge. The Class D units converted into our common units on a one-for-one basis on August 17, 2009.

 

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

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

 

•

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 March 31, 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. 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.

 

25

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

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

 

Payment Date		Per Unit Distribution			Total Cash Distribution
					(Millions)
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

11. 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.

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 2009 for the 2009-2010 insurance year. Previously, we carried insurance jointly with DCP Midstream, LLC. Following our 2009 renewals, we now contract with a third-party insurer separately from DCP Midstream, LLC for: (1) automobile liability insurance for all owned, non-owned and hired vehicles; (2) excess liability insurance above the established primary limits for general liability and automobile liability insurance; and (3) property insurance, which covers replacement value of all real and personal property and includes business interruption/extra expense. However, we are still jointly insured with DCP Midstream, LLC for directors and officers insurance covering our directors and officers for acts related to our business activities. As a result of separating the excess liability insurance, we have reduced the limits of insurance to match the type and size of exposure covered by this insurance. These changes have not resulted in any material change to the premiums we contracted to pay in the 2009-2010 insurance year. 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 2009-2010 insurance year covers onshore and offshore property, onshore named windstorm and onshore and offshore business interruption insurance. The availability of named windstorm insurance has been significantly reduced as a result of higher industry-wide damage claims in past years. Additionally, the named windstorm insurance that is available comes at significantly higher premium amounts, higher deductibles and lower coverage limits. Consequently, Discovery elected to not purchase offshore named windstorm insurance coverage for the 2009-2010 insurance year.

Indemnification — DCP Midstream, LLC has indemnified 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.

 

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

12. 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 (1) our Northern Louisiana system; (2) our Southern Oklahoma system; (3) our 40% limited liability company interest in Discovery; (4) our 75% interest in our Colorado system; (5) our Wyoming system; (6) our 50.1% interest in our East Texas system; and (7) our Michigan systems.

Wholesale Propane Logistics — The Wholesale Propane Logistics segment consists of five owned and operated rail terminals, 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 a non-operated 45% equity interest in 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 March 31, 2010

 

		Natural  Gas Services				Wholesale Propane Logistics				NGL Logistics				Other				Total
		(Millions)
Total operating revenue		$	218.1			$	180.8			$	4.8			$	—			$	403.7
Gross margin (a)		$	53.8			$	13.7			$	3.4			$	—			$	70.9
Operating and maintenance expense			(16.2	)			(2.6	)			(0.2	)			—				(19.0	)
Depreciation and amortization expense			(17.0	)			(0.3	)			(0.5	)			—				(17.8	)
General and administrative expense			—				—				—				(8.6	)			(8.6	)
Earnings from unconsolidated affiliates			7.4				—				0.5				—				7.9
Interest expense			—				—				—				(7.2	)			(7.2	)
Income tax expense (b)			—				—				—				(0.3	)			(0.3	)
Net income (loss)			28.0				10.8				3.2				(16.1	)			25.9
Net income attributable to noncontrolling interests			(0.1	)			—				—				—				(0.1	)
Net income (loss) attributable to partners		$	27.9			$	10.8			$	3.2			$	(16.1	)		$	25.8
Non-cash derivative mark-to-market (c)		$	8.4			$	(0.6	)		$	—			$	—			$	7.8
Capital expenditures		$	12.1			$	—			$	0.1			$	—			$	12.2
Acquisition expenditures		$	—			$	—			$	22.0			$	—			$	22.0
Investments in unconsolidated affiliates		$	0.7			$	—			$	—			$	—			$	0.7

 

27

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

Three Months Ended March 31, 2009

 

		Natural  Gas Services				Wholesale Propane Logistics				NGL Logistics				Other				Total
		(Millions)
Total operating revenue		$	149.8			$	132.8			$	1.8			$	—			$	284.4
Gross margin (a)		$	40.4			$	25.8			$	1.3			$	—			$	67.5
Operating and maintenance expense			(13.2	)			(2.7	)			(0.3	)			—				(16.2	)
Depreciation and amortization expense			(13.9	)			(0.3	)			(0.4	)			—				(14.6	)
General and administrative expense			—				—				—				(8.6	)			(8.6	)
(Losses) earnings from unconsolidated affiliates			(1.5	)			—				0.4				—				(1.1	)
Interest income			—				—				—				0.2				0.2
Interest expense			—				—				—				(7.3	)			(7.3	)
Income tax expense (b)			—				—				—				(0.1	)			(0.1	)
Net income (loss)			11.8				22.8				1.0				(15.8	)			19.8
Net loss attributable to noncontrolling interests			1.3				—				—				—				1.3
Net income (loss) attributable to partners		$	13.1			$	22.8			$	1.0			$	(15.8	)		$	21.1
Non-cash derivative mark-to-market (c)		$	0.1			$	0.2			$	—			$	(0.1	)		$	0.2
Capital expenditures		$	55.8			$	0.1			$	—			$	—			$	55.9
Acquisition expenditures		$	0.3			$	—			$	—			$	—			$	0.3
Investments in unconsolidated affiliates		$	0.2			$	—			$	—			$	—			$	0.2

 

		March 31, 2010			December 31, 2009
		(Millions)
Segment long-term assets:
Natural Gas Services		$	1,178.8		$	1,185.2
Wholesale Propane Logistics			52.9			53.2
NGL Logistics (d)			54.0			32.3
Other (e)			4.6			13.1
Total long-term assets			1,290.3			1,283.8
Current assets			173.9			197.7
Total assets		$	1,464.2		$	1,481.5

 

(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.

 

28

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

(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 NGL Logistics segment increased in 2010 as a result of the Wattenberg pipeline acquisition for $22.0 million.

(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.

13. Supplemental Cash Flow Information

 

		Three Months Ended March  31,
		2010			2009
		(Millions)
Cash paid for interest, net of amounts capitalized		$	1.6		$	3.7
Cash paid for income taxes, net of income tax refunds		$	—		$	0.4
Non-cash investing and financing activities:
Property, plant and equipment acquired with accounts payable		$	3.9		$	27.7
Other non-cash additions of property plant and equipment		$	0.2		$	0.9
Contingent consideration for the purchase of additional interest in a subsidiary		$	1.0		$	—

 

29

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

14. 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. The parent guarantor has agreed to fully and unconditionally guarantee securities of the subsidiary issuer that may be issued in future periods. 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.

 

		March 31, 2010
		Parent Guarantor			Subsidiary Issuer				Non-Guarantor Subsidiaries				Consolidating Adjustments				Consolidated
		(Millions)
ASSETS
Current assets:
Cash and cash equivalents		$	—		$	1.7			$	2.6			$	(1.7	)		$	2.6
Accounts receivable			—			—				120.5				—				120.5
Inventories			—			—				43.1				—				43.1
Other			—			—				7.7				—				7.7
Total current assets			—			1.7				173.9				(1.7	)			173.9
Property, plant and equipment, net			—			—				1,017.0				—				1,017.0
Goodwill and intangible assets, net			—			—				151.8				—				151.8
Advances receivable — consolidated subsidiaries			221.2			525.0				—				(746.2	)			—
Investments in consolidated subsidiaries			157.1			279.7				—				(436.8	)			—
Investments in unconsolidated affiliates			—			—				113.5				—				113.5
Other long-term assets			—			0.5				7.5				—				8.0
Total assets		$	378.3		$	806.9			$	1,463.7			$	(1,184.7	)		$	1,464.2
LIABILITIES AND EQUITY
Accounts payable and other current liabilities		$	—		$	21.3			$	161.5			$	(1.7	)		$	181.1
Advances payable — consolidated subsidiaries			—			—				746.2				(746.2	)			—
Long-term debt			—			615.0				—				—				615.0
Other long-term liabilities			—			13.5				53.8				—				67.3
Total liabilities			—			649.8				961.5				(747.9	)			863.4
Commitments and contingent liabilities
Equity:
Partners’ equity:
Net equity			378.3			190.2				280.1				(436.8	)			411.8
Accumulated other comprehensive loss			—			(33.1	)			(0.4	)			—				(33.5	)
Total partners’ equity			378.3			157.1				279.7				(436.8	)			378.3
Noncontrolling interests			—			—				222.5				—				222.5
Total equity			378.3			157.1				502.2				(436.8	)			600.8
Total liabilities and equity		$	378.3		$	806.9			$	1,463.7			$	(1,184.7	)		$	1,464.2

 

30

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

 

		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

 

31

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

		Three Months Ended March 31, 2010
		Parent Guarantor			Subsidiary Issuer				Non-Guarantor Subsidiaries				Consolidating Adjustments				Consolidated
		(Millions)
Operating revenues:
Sales of natural gas, propane, NGLs and condensate		$	—		$	—			$	370.4			$	—			$	370.4
Transportation, processing and other			—			—				27.3				—				27.3
Gains from commodity derivative activity, net			—			—				6.0				—				6.0
Total operating revenues			—			—				403.7				—				403.7
Operating costs and expenses:
Purchases of natural gas, propane and NGLs			—			—				(332.8	)			—				(332.8	)
Operating and maintenance expense			—			—				(19.0	)			—				(19.0	)
Depreciation and amortization expense			—			—				(17.8	)			—				(17.8	)
General and administrative expense			—			—				(8.6	)			—				(8.6	)
Total operating costs and expenses			—			—				(378.2	)			—				(378.2	)
Operating income			—			—				25.5				—				25.5
Interest expense, net			—			(7.1	)			(0.1	)			—				(7.2	)
Earnings from consolidated subsidiaries			25.8			32.9				—				(58.7	)			—
Earnings from unconsolidated affiliates			—			—				7.9				—				7.9
Income before income taxes			25.8			25.8				33.3				(58.7	)			26.2
Income tax expense			—			—				(0.3	)			—				(0.3	)
Net income			25.8			25.8				33.0				(58.7	)			25.9
Net income attributable to noncontrolling interests			—			—				(0.1	)			—				(0.1	)
Net income attributable to partners		$	25.8		$	25.8			$	32.9			$	(58.7	)		$	25.8

 

32

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

		Three Months Ended March 31, 2009
		Parent Guarantor			Subsidiary Issuer				Non-Guarantor Subsidiaries				Consolidating Adjustments				Consolidated
		(Millions)
Operating revenues:
Sales of natural gas, propane, NGLs and condensate		$	—		$	—			$	257.1			$	—			$	257.1
Transportation, processing and other			—			—				20.3				—				20.3
Gains from commodity derivative activity, net			—			—				7.0				—				7.0
Total operating revenues			—			—				284.4				—				284.4
Operating costs and expenses:
Purchases of natural gas, propane and NGLs			—			—				(216.9	)			—				(216.9	)
Operating and maintenance expense			—			—				(16.2	)			—				(16.2	)
Depreciation and amortization expense			—			—				(14.6	)			—				(14.6	)
General and administrative expense			—			—				(8.6	)			—				(8.6	)
Total operating costs and expenses			—			—				(256.3	)			—				(256.3	)
Operating income			—			—				28.1				—				28.1
Interest expense, net			—			(7.0	)			(0.1	)			—				(7.1	)
Earnings from consolidated subsidiaries			21.1			28.1				—				(49.2	)			—
Losses from unconsolidated affiliates			—			—				(1.1	)			—				(1.1	)
Income before income taxes			21.1			21.1				26.9				(49.2	)			19.9
Income tax expense			—			—				(0.1	)			—				(0.1	)
Net income			21.1			21.1				26.8				(49.2	)			19.8
Net loss attributable to noncontrolling interests			—			—				1.3				—				1.3
Net income attributable to partners		$	21.1		$	21.1			$	28.1			$	(49.2	)		$	21.1

 

33

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

		Three Months Ended March 31, 2010
		Parent Guarantor				Subsidiary Issuer				Non-Guarantor Subsidiaries				Consolidating Adjustments				Consolidated
		(Millions)
OPERATING ACTIVITIES:
Net cash provided by (used in) operating activities		$	24.6			$	(12.0	)		$	39.3			$	(0.9	)		$	51.0
INVESTING ACTIVITIES:
Capital expenditures			—				—				(12.2	)			—				(12.2	)
Acquisitions, net of cash acquired			—				—				(22.0	)			—				(22.0	)
Investments in unconsolidated affiliates			—				—				(0.7	)			—				(0.7	)
Proceeds from sale of assets			—				—				0.2				—				0.2
Proceeds from sales of available-for-sale securities			—				10.1				—				—				10.1
Net cash provided by (used in) investing activities			—				10.1				(34.7	)			—				(24.6	)
FINANCING ACTIVITIES:
Proceeds from debt			—				116.6				—				—				116.6
Payments of debt			—				(114.6	)			—				—				(114.6	)
Distributions to unitholders and general partner			(24.6	)			—				—				—				(24.6	)
Distributions to noncontrolling interests			—				—				(3.7	)			—				(3.7	)
Contributions from noncontrolling interests			—				—				3.9				—				3.9
Purchase of additional interest in a subsidiary							—				(3.5	)			—				(3.5	)
Net cash provided by (used in) financing activities			(24.6	)			2.0				(3.3	)			—				(25.9	)
Net change in cash and cash equivalents			—				0.1				1.3				(0.9	)			0.5
Cash and cash equivalents, beginning of period			—				1.6				1.3				(0.8	)			2.1
Cash and cash equivalents, end of period		$	—			$	1.7			$	2.6			$	(1.7	)		$	2.6

 

34

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

		Three Months Ended March 31, 2009
		Parent Guarantor				Subsidiary Issuer				Non-Guarantor Subsidiaries				Consolidating Adjustments				Consolidated
		(Millions)
OPERATING ACTIVITIES:
Net cash provided by (used in) operating activities		$	20.1			$	(3.2	)		$	14.1			$	(0.5	)		$	30.5
INVESTING ACTIVITIES:
Capital expenditures			—				—				(55.9	)			—				(55.9	)
Acquisitions, net of cash acquired			—				—				(0.3	)			—				(0.3	)
Investments in unconsolidated affiliates			—				—				(0.2	)			—				(0.2	)
Purchase of available-for-sale securities			—				(1.0	)			—				—				(1.0	)
Proceeds from sales of available-for-sale securities			—				0.8				—				—				0.8
Net cash used in investing activities			—				(0.2	)			(56.4	)			—				(56.6	)
FINANCING ACTIVITIES:
Payments of debt			—				(11.5	)			—				—				(11.5	)
Net change in advances to predecessor from DCP Midstream, LLC			—				—				3.0				—				3.0
Distributions to unitholders and general partner			(20.1	)			—				—				—				(20.1	)
Distributions to noncontrolling interests			—				—				(3.9	)			—				(3.9	)
Contributions from noncontrolling interests			—				—				8.7				—				8.7
Net cash provided by (used in) financing activities			(20.1	)			(11.5	)			7.8				—				(23.8	)
Net change in cash and cash equivalents			—				(14.9	)			(34.5	)			(0.5	)			(49.9	)
Cash and cash equivalents, beginning of period			—				26.6				35.6				(0.3	)			61.9
Cash and cash equivalents, end of period		$	—			$	11.7			$	1.1			$	(0.8	)		$	12.0

15. Subsequent Events

On April 27, 2010, the board of directors of the General Partner declared a quarterly distribution of $0.60 per unit, payable on May 14, 2010 to unitholders of record on May 7, 2010.

 

35