DCP Midstream (DCP-PC) 10-Q 2016 Q2 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2016

or

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

For the transition period from                     to                     

Commission File Number: 001-32678

DCP MIDSTREAM PARTNERS, LP

(Exact name of registrant as specified in its charter)

Delaware	03-0567133
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
370 17th Street, Suite 2500 Denver, Colorado	80202
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code: (303) 595-3331

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes ý No ¨

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

Large accelerated filer	ý		Accelerated filer	¨
Non-accelerated filer	¨	(Do not check if a smaller reporting company)	Smaller reporting company	¨

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

As of July 29, 2016, there were outstanding 114,742,948 common units representing limited partner interests.

DCP MIDSTREAM PARTNERS, LP

FORM 10-Q FOR THE QUARTER ENDED JUNE 30, 2016

TABLE OF CONTENTS

Item		Page
	PART I. FINANCIAL INFORMATION
1.	Financial Statements (unaudited):
	Condensed Consolidated Balance Sheets as of June 30, 2016 and December 31, 2015	1
	Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2016 and 2015	2
	Condensed Consolidated Statements of Comprehensive Income for the Three and Six Months Ended June 30, 2016 and 2015	3
	Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2016 and 2015	4
	Condensed Consolidated Statement of Changes in Equity for the Six Months Ended June 30, 2016	5
	Condensed Consolidated Statement of Changes in Equity for the Six Months Ended June 30, 2015	6
	Notes to the Condensed Consolidated Financial Statements	7
2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	39
3.	Quantitative and Qualitative Disclosures about Market Risk	58
4.	Controls and Procedures	60
	PART II. OTHER INFORMATION
1.	Legal Proceedings	62
1A.	Risk Factors	62
6.	Exhibits	62
	Signatures	63
	Exhibit Index	64

i

GLOSSARY OF TERMS

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

Bbl	barrel
Bbls/d	barrels per day
Bcf	billion cubic feet
Bcf/d	billion cubic feet per day
Btu	British thermal unit, a measurement of energy
Fractionation	the process by which natural gas liquids are separated     into individual components
MBbls	thousand barrels
MBbls/d	thousand barrels per day
MMBtu	million Btus
MMBtu/d	million Btus per day
MMcf	million cubic feet
MMcf/d	million cubic feet per day
NGLs	natural gas liquids
Throughput	the volume of product transported or passing through a     pipeline or other facility

ii

CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

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

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

These forward-looking statements reflect our intentions, plans, expectations, assumptions and beliefs about future events and are subject to risks, uncertainties and other factors, many of which are outside our control. Important factors that could cause actual results to differ materially from the expectations expressed or implied in the forward-looking statements include known and unknown risks. Known risks and uncertainties include, but are not limited to, the risks set forth in Item 1A. "Risk Factors” in this Quarterly Report on Form 10-Q and in our Annual Report on Form 10-K for the year ended December 31, 2015, including the following risks and uncertainties:

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

• the demand for crude oil, residue gas and NGL products;

• the level and success of drilling and quality of production volumes around our assets and our ability to connect supplies to our gathering and processing systems, as well as our residue gas and NGL infrastructure;

• volatility in the price of our common units;

• our ability to hire, train, and retain qualified personnel and key management to execute our business strategy;

• general economic, market and business conditions;

• our ability to continue the safe and reliable operation of our assets;

• our ability to access the debt and equity markets and the resulting cost of capital, which will depend on general market conditions, our financial and operating results, inflation rates, interest rates, our ability to comply with the covenants in our loan agreements and the indentures governing our debt securities, as well as our ability to maintain our credit ratings;

• new, additions to, and changes in, laws and regulations, particularly with regard to taxes, safety and protection of the environment, including, but not limited to, climate change legislation, regulation of over-the-counter derivatives market and entities, and hydraulic fracturing regulations, or the increased regulation of our industry, and their impact on producers and customers served by our systems;

• the creditworthiness of our customers and the counterparties to our transactions;

• the amount of collateral we may be required to post from time to time in our transactions;

• industry changes, including the impact of bankruptcies, consolidations, alternative energy sources, technological advances and changes in competition.

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

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

• weather, weather-related conditions and other natural phenomena, including, but not limited to, their potential impact on demand for the commodities we sell and the operation of company-owned and third party-owned infrastructure;

• security threats such as military campaigns, terrorist attacks, and cybersecurity breaches, against, or otherwise impacting, our facilities and systems;

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

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

• the amount of gas we gather, compress, treat, process, transport, store and sell, or the NGLs we produce, fractionate, transport, store and sell, may be reduced if the pipelines and storage and fractionation facilities to which we deliver the natural gas or NGLs are capacity constrained and cannot, or will not, accept the gas or NGLs.

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

iii

PART I. FINANCIAL INFORMATION

Item 1.Financial Statements

DCP MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	June 30,   2016			December 31,   2015
	(Millions)
ASSETS
Current assets:
Cash and cash equivalents	$	1		$	2
Accounts receivable:
Trade, net of allowance for doubtful accounts of $1 million	53			73
Affiliates	86			81
Inventories	29			43
Unrealized gains on derivative instruments	29			105
Assets held for sale	118			—
Other	3			2
Total current assets	319			306
Property, plant and equipment, net	3,302			3,476
Goodwill	72			72
Intangible assets, net	108			112
Investments in unconsolidated affiliates	1,481			1,493
Unrealized gains on derivative instruments	5			9
Other long-term assets	15			9
Total assets	$	5,302		$	5,477
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable:
Trade	$	83		$	98
Affiliates	19			19
Unrealized losses on derivative instruments	20			18
Accrued interest	19			19
Accrued taxes	23			12
Liabilities held for sale	3			—
Other	45			34
Total current liabilities	212			200
Long-term debt	2,367			2,424
Unrealized losses on derivative instruments	—			1
Other long-term liabilities	45			47
Total liabilities	2,624			2,672
Commitments and contingent liabilities
Equity:
Limited partners (114,742,948 and 114,742,948 common units issued and outstanding, respectively)	2,637			2,762
General partner	18			18
Accumulated other comprehensive loss	(8		)	(8		)
Total partners’ equity	2,647			2,772
Noncontrolling interests	31			33
Total equity	2,678			2,805
Total liabilities and equity	$	5,302		$	5,477

See accompanying notes to condensed consolidated financial statements.

1

DCP MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
	(Millions, except per unit amounts)
Operating revenues:
Sales of natural gas, propane, NGLs and condensate	$	73		$	108		$	178		$	297
Sales of natural gas, propane, NGLs and condensate to affiliates	191			244			353			525
Transportation, processing and other	62			59			123			115
Transportation, processing and other to affiliates	42			25			84			48
Losses from commodity derivative activity, net	(8		)	(5		)	(4		)	—
(Losses) gains from commodity derivative activity, net — affiliates	(12		)	(1		)	(7		)	13
Total operating revenues	348			430			727			998
Operating costs and expenses:
Purchases of natural gas, propane and NGLs	210			277			418			644
Purchases of natural gas, propane and NGLs from affiliates	21			29			44			64
Operating and maintenance expense	45			51			93			98
Depreciation and amortization expense	30			29			62			58
General and administrative expense	3			3			5			6
General and administrative expense — affiliates	18			19			37			37
Goodwill impairment	—			49			—			49
Other expense, net	3			1			3			1
Total operating costs and expenses	330			458			662			957
Operating income (loss)	18			(28		)	65			41
Interest expense	(24		)	(22		)	(48		)	(44		)
Earnings from unconsolidated affiliates	53			44			102			67
Income (loss) before income taxes	47			(6		)	119			64
Income tax (expense) benefit	(1		)	4			(1		)	3
Net income (loss)	46			(2		)	118			67
Net income attributable to noncontrolling interests	(1		)	—			(1		)	—
Net income (loss) attributable to partners	45			(2		)	117			67
General partner’s interest in net income	(31		)	(31		)	(62		)	(62		)
Net income (loss) allocable to limited partners	$	14		$	(33	)	$	55		$	5
Net income (loss) per limited partner unit — basic and diluted	$	0.12		$	(0.29	)	$	0.48		$	0.04
Weighted-average limited partner units outstanding — basic and diluted	114.7			114.7			114.7			114.5

See accompanying notes to condensed consolidated financial statements.

2

DCP MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended June 30,						Six Months Ended   June 30,
	2016			2015			2016			2015
	(Millions)
Net income (loss)	$	46		$	(2	)	$	118		$	67
Other comprehensive income:
Reclassification of cash flow hedge losses into earnings	—			—			—			1
Total other comprehensive income	—			—			—			1
Total comprehensive income (loss)	46			(2		)	118			68
Total comprehensive income attributable to noncontrolling interests	(1		)	—			(1		)	—
Total comprehensive income (loss) attributable to partners	$	45		$	(2	)	$	117		$	68

See accompanying notes to condensed consolidated financial statements.

3

DCP MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Six Months Ended June 30,
	2016			2015
	(Millions)
OPERATING ACTIVITIES:
Net income	$	118		$	67
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	62			58
Earnings from unconsolidated affiliates	(102		)	(67		)
Distributions from unconsolidated affiliates	127			87
Net unrealized losses on derivative instruments	82			98
Goodwill impairment	—			49
Other, net	7			2
Change in operating assets and liabilities, which provided (used) cash, net of effects of acquisitions:
Accounts receivable	13			102
Inventories	12			24
Accounts payable	(12		)	(86		)
Other current assets and liabilities	13			12
Other long-term assets and liabilities	—			4
Net cash provided by operating activities	320			350
INVESTING ACTIVITIES:
Capital expenditures	(17		)	(194		)
Investments in unconsolidated affiliates, net	(16		)	(46		)
Deposit from assets held for sale	16			—
Net cash used in investing activities	(17		)	(240		)
FINANCING ACTIVITIES:
Proceeds from long-term debt	1,052			450
Payments of long-term debt	(1,111		)	(350		)
Proceeds from issuance of common units, net of offering costs	—			31
Distributions to limited partners and general partner	(242		)	(241		)
Distributions to noncontrolling interests	(3		)	(2		)
Contributions from DCP Midstream, LLC	—			1
Net cash used in financing activities	(304		)	(111		)
Net change in cash and cash equivalents	(1		)	(1		)
Cash and cash equivalents, beginning of period	2			25
Cash and cash equivalents, end of period	$	1		$	24

See accompanying notes to condensed consolidated financial statements.

4

DCP MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

(Unaudited)

		Partners’ Equity
		Limited Partners			General Partner			Accumulated Other Comprehensive Loss			Noncontrolling Interests			Total Equity
	(Millions)
Balance, January 1, 2016		$	2,762		$	18		$	(8	)	$	33		$	2,805
Net income		55			62			—			1			118
Distributions to limited partners and general partner		(180		)	(62		)	—			—			(242		)
Distributions to noncontrolling interests		—			—			—			(3		)	(3		)
Balance, June 30, 2016		$	2,637		$	18		$	(8	)	$	31		$	2,678

See accompanying notes to condensed consolidated financial statements.

5

DCP MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

(Unaudited)

	Partners’ Equity
	Limited  Partners			General  Partner			Accumulated  Other Comprehensive (Loss) Income			Noncontrolling Interests			Total Equity
	(Millions)
Balance, January 1, 2015	$	2,984		$	18		$	(9	)	$	33		$	3,026
Net income	5			62			—			—			67
Other comprehensive income	—			—			1			—			1
Issuance of 788,033 common units to the public	31			—			—			—			31
Distributions to limited partners and general partner	(179		)	(62		)	—			—			(241		)
Distributions to noncontrolling interests	—			—			—			(2		)	(2		)
Contributions from DCP Midstream, LLC	1			—			—			—			1
Balance, June 30, 2015	$	2,842		$	18		$	(8	)	$	31		$	2,883

See accompanying notes to condensed consolidated financial statements.

6

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Six Months Ended June 30, 2016 and 2015

(Unaudited)

1. Description of Business and Basis of Presentation

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

We are a Delaware limited partnership that was formed in August 2005. Our partnership includes our Natural Gas Services, NGL Logistics and Wholesale Propane Logistics segments. For additional information regarding these segments, see Note 14 - Business Segments.

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 100% owned by DCP Midstream, LLC. DCP Midstream, LLC and its subsidiaries and affiliates, collectively referred to as DCP Midstream, LLC, is owned 50% by Phillips 66 and 50% by Spectra Energy Corp and its affiliates, or Spectra Energy. DCP Midstream, LLC directs our business operations through its ownership and control of the General Partner. DCP Midstream, LLC’s employees provide administrative support to us and operate most of our assets. DCP Midstream, LLC owns approximately 21.4% of us, including limited partner and general partner interests.

The condensed consolidated financial statements include the accounts of the Partnership and all majority-owned subsidiaries where we have the ability to exercise control. 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.

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 condensed 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. All intercompany balances and transactions have been eliminated in consolidation. Transactions between us and other DCP Midstream, LLC operations have been included in the condensed consolidated financial statements as transactions between affiliates.

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 the SEC. Accordingly, these condensed consolidated financial statements reflect all adjustments, consisting of 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 note disclosures normally included in our annual financial statements prepared in accordance with GAAP have been condensed or omitted from these interim financial statements pursuant to such rules and regulations, although we believe that the disclosures made are adequate to make the information presented not misleading. Results of operations for the three and six months ended June 30, 2016 are not necessarily indicative of the results that may be expected for the year ending December 31, 2016. These unaudited condensed consolidated financial statements and other information included in this Quarterly Report on Form 10-Q should be read in conjunction with the 2015 audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2015.

2. New Accounting Pronouncements

Financial Accounting Standards Board, or FASB, Accounting Standards Update, or ASU, 2016-02 “Leases (Topic 842),” or ASU 2016-02 - In February 2016, the FASB issued ASU 2016-02, which requires lessees to recognize a lease liability on a discounted basis and the right of use of a specified asset at the commencement date for all leases. This ASU is effective for interim and annual reporting periods beginning after December 15, 2018, with the option to early adopt for financial statements that have not been issued. We are currently evaluating the potential impact this standard will have on our condensed consolidated financial statements and related disclosures.

7

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Six Months Ended June 30, 2016 and 2015 - (Continued)

(Unaudited)

FASB ASU, 2015-16 “Business Combinations (Topic 805),” or ASU 2015-16 - In September 2015, the FASB issued ASU 2015-16, which requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. This ASU is effective for interim and annual reporting periods beginning after December 15, 2016, with the option to early adopt for financial statements that have not been issued. The impact of this ASU will be evaluated upon the occurrence of future business combinations.

FASB ASU 2015-02 “Consolidation (Topic 810): Amendments to the Consolidation Analysis,” or ASU 2015-02 - In February 2015, the FASB issued ASU 2015-02, which changes the analysis that a reporting entity must perform to determine whether it should consolidate certain types of legal entities. This ASU is effective for annual reporting periods beginning after December 15, 2015. The adoption of this ASU has been implemented and did not have a material impact on our condensed consolidated results of operations, cash flows and financial position.

FASB ASU 2014-09 “Revenue from Contracts with Customers (Topic 606),” or ASU 2014-09 and related interpretations and amendments. - In May 2014, the FASB issued ASU 2014-09, which supersedes the revenue recognition requirements of Accounting Standards Codification Topic 605 “Revenue Recognition.” This ASU is effective for annual reporting periods beginning after December 15, 2017, with the option to adopt as early as December 15, 2016. We are currently assessing the impact of adoption of this ASU on our condensed consolidated results of operations, cash flows and financial position.

3. Assets Held for Sale

In May 2016, we entered into a purchase and sale agreement with a third party to sell our 100% interest in our Northern Louisiana system, which primarily consisted of certain gas processing plants and gathering systems, within our Natural Gas Services segment, for approximately $160 million. This transaction closed on July 1, 2016 and we expect to record a gain of approximately $45 million in the third quarter of 2016, subject to customary purchase price adjustments.

The transaction had not closed as of June 30, 2016, and we continued to classify the underlying assets and liabilities as held for sale. As a result, the associated assets and liabilities of the Northern Louisiana system were reclassified to current assets and current liabilities, respectively, in the condensed consolidated balance sheet as of June 30, 2016.

The following table summarizes the classes of assets and liabilities designated as held for sale in the condensed consolidated balance sheet as of June 30, 2016:

	June 30,
	2016
	(millions)
Assets held for sale:
Property, plant and equipment, net	$	116
Inventories	2
Total reclassified to current assets	$	118
Liabilities held for sale:
Other long-term liabilities	$	3
Total reclassified to current liabilities	$	3

4. Agreements and Transactions with Affiliates

DCP Midstream, LLC

Services Agreement and Other General and Administrative Charges

We have entered into a services agreement, as amended, or the Services Agreement, with DCP Midstream, LLC. Under the Services Agreement, we are required to reimburse DCP Midstream, LLC for salaries of operating personnel and employee benefits, as well as capital expenditures, maintenance and repair costs, taxes and other direct costs incurred by DCP Midstream, LLC on our behalf. We also pay DCP Midstream, LLC an annual fee under the Services Agreement for centralized corporate functions performed by DCP Midstream, LLC on our behalf, including legal, accounting, cash management, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human

8

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Six Months Ended June 30, 2016 and 2015 - (Continued)

(Unaudited)

resources, credit, payroll, taxes and engineering. Except with respect to the annual fee, there is no limit on the reimbursements we make to DCP Midstream, LLC under the Services Agreement for other expenses and expenditures incurred or payments made on our behalf. In the event we acquire assets or our business otherwise expands, the annual fee under the Services Agreement is subject to adjustment based on the nature and extent of general and administrative services performed by DCP Midstream, LLC, as well as an annual adjustment based on changes to the Consumer Price Index. Effective January 1, 2015, the annual fee payable under the Services Agreement is $71 million.

The following is a summary of the fees we incurred under the Services Agreement, as well as other fees paid to DCP Midstream, LLC:

	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
	(Millions)
Services Agreement	$	18	$	18	$	36	$	36
Other fees — DCP Midstream, LLC	—		1		1		1
Total — DCP Midstream, LLC	$	18	$	19	$	37	$	37

In addition to the fees paid pursuant to the Services Agreement, we incurred allocated expenses, including executive compensation, insurance and internal audit fees with DCP Midstream, LLC of less than $1 million and $1 million for the three months ended June 30, 2016 and 2015 respectively and $1 million for each of the six months ended June 30, 2016, and 2015, respectively.

Commodity Transactions - We sell a portion of our residue gas and NGLs to, purchase natural gas and other NGL products from, and provide gathering, transportation and other services to, DCP Midstream, LLC. Management anticipates continuing to purchase and sell commodities and provide services to DCP Midstream, LLC in the ordinary course of business. In addition, DCP Midstream, LLC conducts derivative activities on our behalf.

Spectra Energy

Commodity Transactions - We purchase natural gas and other NGL products from Spectra Energy. Management anticipates continuing to purchase and sell commodities and provide services to Spectra Energy in the ordinary course of business.

Summary of Transactions with Affiliates

The following table summarizes our transactions with affiliates:

	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
	(Millions)
DCP Midstream, LLC:
Sales of natural gas, propane, NGLs and condensate	$	191		$	244		$	353		$	525
Transportation, processing and other	$	42		$	25		$	84		$	48
Purchases of natural gas, propane and NGLs	$	13		$	17		$	27		$	42
(Losses) gains from commodity derivative activity, net	$	(12	)	$	(1	)	$	(7	)	$	13
General and administrative expense	$	18		$	19		$	37		$	37
Spectra Energy:
Purchases of natural gas, propane and NGLs	$	8		$	12		$	17		$	22

9

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Six Months Ended June 30, 2016 and 2015 - (Continued)

(Unaudited)

We had balances with affiliates as follows:

	June 30,   2016		December 31,   2015
	(Millions)
DCP Midstream, LLC:
Accounts receivable	$	86	$	81
Accounts payable	$	16	$	15
Unrealized gains on derivative instruments — current	$	10	$	32
Unrealized gains on derivative instruments — long-term	$	5	$	9
Unrealized losses on derivative instruments — current	$	20	$	18
Unrealized losses on derivative instruments — long-term	$	—	$	1
Spectra Energy:
Accounts payable	$	3	$	4

5. Inventories

Inventories were as follows:

	June 30,   2016		December 31,   2015
	(Millions)
Natural gas	$	21	$	29
NGLs	8		14
Total inventories	$	29	$	43

We recognize the lower of cost or market adjustments when the carrying value of our inventories exceeds their estimated market value. These non-cash charges are a component of purchases of natural gas, propane and NGLs in the condensed consolidated statements of operations. We recognized no lower of cost or market adjustments during the three months ended June 30, 2016 and $1 million during the three months ended June 30, 2015. We recognized $3 million and $5 million in lower of cost or market adjustments during the six months ended June 30, 2016, and 2015 respectively.

6. Property, Plant and Equipment

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

	Depreciable Life	June 30,   2016			December 31,   2015
		(Millions)
Gathering and transmission systems	20 — 50 Years	$	2,045		$	2,337
Processing, storage, and terminal facilities	35 — 60 Years	2,333			2,327
Other	3 —  30 Years	60			64
Construction work in progress		79			122
Property, plant and equipment		4,517			4,850
Accumulated depreciation		(1,215		)	(1,374		)
Property, plant and equipment, net		$	3,302		$	3,476

Interest capitalized on construction projects was less than $1 million and $2 million for the three months ended June 30, 2016 and 2015, respectively, and less than $1 million and $5 million for the six months ended June 30, 2016, and 2015, respectively.

10

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Six Months Ended June 30, 2016 and 2015 - (Continued)

(Unaudited)

Depreciation expense was $27 million for each of the three months ended June 30, 2016 and 2015, respectively, $57 million and $53 million for the six months ended June 30, 2016 and 2015, respectively.

In May 2016, the net carrying values of property, plant and equipment attributable to the Northern Louisiana system were reclassified to current assets as discussed in Note 3, Assets Held for Sale. As a result, we ceased depreciation of the underlying historical costs in May 2016. For both the three and six months ended June 30, 2016, we recognized $2 million in depreciation expense associated with these assets held for sale.

7. Investments in Unconsolidated Affiliates

The following table summarizes our investments in unconsolidated affiliates:

		Carrying Value as of
	Percentage Ownership	June 30,   2016		December 31,   2015
		(Millions)
DCP Sand Hills Pipeline, LLC	33.33%	$	448	$	441
Discovery Producer Services LLC	40%	392		406
DCP Southern Hills Pipeline, LLC	33.33%	318		318
Front Range Pipeline LLC	33.33%	169		170
Texas Express Pipeline LLC	10%	94		96
Mont Belvieu Enterprise Fractionator	12.5%	22		25
Panola Pipeline Company, LLC	15%	23		19
Mont Belvieu 1 Fractionator	20%	10		11
Other	Various	5		7
Total investments in unconsolidated affiliates		$	1,481	$	1,493

Earnings from investments in unconsolidated affiliates were as follows:

	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
	(Millions)
Discovery Producer Services LLC	$	16	$	16	$	31	$	14
DCP Sand Hills Pipeline, LLC	17		14		31		25
DCP Southern Hills Pipeline, LLC	6		4		13		7
Front Range Pipeline LLC	4		3		9		7
Mont Belvieu Enterprise Fractionator	4		4		8		8
Mont Belvieu 1 Fractionator	3		2		5		3
Texas Express Pipeline LLC	2		1		4		3
Panola Pipeline Company, LLC	1		—		1		—
Total earnings from unconsolidated affiliates	$	53	$	44	$	102	$	67

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Six Months Ended June 30, 2016 and 2015 - (Continued)

(Unaudited)

The following tables summarize the combined financial information of our investments in unconsolidated affiliates:

	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
	(Millions)
Statements of operations (a):
Operating revenue	$	323	$	300	$	631	$	533
Operating expenses	$	130	$	145	$	258	$	274
Net income	$	192	$	155	$	370	$	258

	June 30,   2016			December 31,   2015
	(Millions)
Balance sheets (a):
Current assets	$	193		$	182
Long-term assets	5,298			5,200
Current liabilities	(161		)	(170		)
Long-term liabilities	(211		)	(216		)
Net assets	$	5,119		$	4,996

(a) In accordance with the Panola joint venture agreement, earnings began to accrue on February 1, 2016. As a result, activity related to Panola is included in the tables above as of and for the three and six months ended June 30, 2016.

8. Fair Value Measurement

Determination of Fair Value

Below is a general description of our valuation methodologies for derivative financial assets and liabilities which are measured at fair value. Fair values are generally based upon quoted market prices or prices obtained through external sources, 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. Fair values are adjusted to reflect the credit risk inherent in the transaction as well as the potential impact of liquidating open positions in an orderly manner over a reasonable time period under current conditions. 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 positions 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.

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Six Months Ended June 30, 2016 and 2015 - (Continued)

(Unaudited)

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

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

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

Valuation Hierarchy

Our fair value measurements are grouped into a three-level valuation hierarchy and are categorized in their entirety in the same level of the fair value hierarchy as the lowest level input that is significant to the entire measurement. 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 level of judgment involved in the most significant input 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 within 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.

13

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Six Months Ended June 30, 2016 and 2015 - (Continued)

(Unaudited)

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, data obtained from third party pricing services, historical and future expected relationship of NGL prices to crude oil prices, the knowledge of expected supply sources coming on line, expected weather trends within certain regions of the United States, and the future expected demand for NGLs.

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

Interest Rate Derivative Assets and Liabilities

We may use interest rate swap agreements as part of our overall capital strategy. These instruments would effectively exchange a portion of our existing floating rate debt for fixed-rate debt. Historically, our swaps have been 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.

Nonfinancial Assets and Liabilities

We utilize fair value to perform impairment tests as required on our property, plant and equipment, goodwill, and other long-lived intangible assets. Assets and liabilities acquired in third party business combinations are recorded at their fair value as of 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 condensed 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.

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Six Months Ended June 30, 2016 and 2015 - (Continued)

(Unaudited)

The following table presents the financial instruments carried at fair value as of June 30, 2016 and December 31, 2015, by condensed consolidated balance sheet caption and by valuation hierarchy, as described above:

	June 30, 2016										December 31, 2015
	Level 1		Level 2			Level 3		Total Carrying Value			Level 1		Level 2			Level 3		Total Carrying Value
	(Millions)
Current assets:
Commodity derivatives (a)	$	—	$	29		$	—	$	29		$	—	$	83		$	22	$	105
Short-term investments (b)	$	—	$	—		$	—	$	—		$	2	$	—		$	—	$	2
Long-term assets:
Commodity derivatives (c)	$	—	$	5		$	—	$	5		$	—	$	9		$	—	$	9
Current liabilities:
Commodity derivatives (d)	$	—	$	(20	)	$	—	$	(20	)	$	—	$	(18	)	$	—	$	(18	)
Long-term liabilities:
Commodity derivatives (e)	$	—	$	—		$	—	$	—		$	—	$	(1	)	$	—	$	(1	)

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

(b) Includes short-term money market securities included in cash and cash equivalents 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 Levels 1 and 2 Fair Value Measurements

The determination to classify a financial instrument within Level 1 or Level 2 is based upon the availability of quoted prices for identical or similar assets and liabilities in active markets. Depending upon the information readily observable in the market, and/or the use of identical or similar quoted prices, which are significant to the overall valuation, the classification of any individual financial instrument may differ from one measurement date to the next. 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. In the event that there is a movement between the classification of an instrument as Level 1 or 2, the transfer would be reflected in a table as Transfers into or out of Level 1 and Level 2. During the three and six months ended June 30, 2016 and 2015, there were no transfers into or out of Level 1 and Level 2 of the fair value hierarchy.

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. 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. The significant unobservable inputs used in determining fair value include adjustments by other market-based or independently sourced market data such as historical commodity volatilities, crude oil future yield curves, and/or counterparty specific considerations. In the event that there is 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/out of Level 3” captions.

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

15

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Six Months Ended June 30, 2016 and 2015 - (Continued)

(Unaudited)

	Commodity Derivative Instruments
	Current Assets			Long- Term Assets		Current Liabilities		Long- Term Liabilities
	(Millions)
Three months ended June 30, 2016 (a):
Beginning balance	$	—		$	—	$	—	$	—
Net unrealized losses included in earnings (b)	—			—		—		—
Settlements	—			—		—		—
Ending balance	$	—		$	—	$	—	$	—
Net unrealized losses on derivatives still held included in earnings (b)	$	—		$	—	$	—	$	—
Three months ended June 30, 2015 (a):
Beginning balance	$	118		$	—	$	—	$	—
Net unrealized losses included in earnings (b)	(1		)	—		—		—
Settlements	(34		)	—		—		—
Ending balance	$	83		$	—	$	—	$	—
Net unrealized losses on derivatives still held included in earnings (b)	$	(1	)	$	—	$	—	$	—

	Commodity Derivative Instruments
	Current Assets			Long- Term Assets			Current Liabilities		Long- Term Liabilities
	(Millions)
Six months ended June 30, 2016 (a):
Beginning balance	$	22		$	—		$	—	$	—
Settlements	(22		)	—			—		—
Ending balance	$	—		$	—		$	—	$	—
Six months ended June 30, 2015 (a):
Beginning balance	$	138		$	18		$	—	$	—
Net unrealized gains (losses) included in earnings (b)	19			(18		)	—		—
Settlements	(74		)	—			—		—
Ending balance	$	83		$	—		$	—	$	—
Net unrealized gains (losses) on derivatives still held included in earnings (b)	$	19		$	(18	)	$	—	$	—

(a) There were no purchases, issuances or sales of derivatives or transfers into/out of Level 3 for the three and six months ended June 30, 2016 and 2015.

(b) Represents the amount of total gains or losses for the period, included in gains or losses from commodity derivative activity, net.

Estimated Fair Value of Financial Instruments

Valuation of a contract’s fair value is validated by an internal group independent of the marketing group. While common industry practices are used to develop valuation techniques, changes in pricing methodologies or the underlying assumptions could result in significantly different fair values and income recognition. When available, quoted market prices or prices obtained through external sources are used to determine a contract’s fair value. For contracts with a delivery location or duration for which quoted market prices are not available, fair value is determined based on pricing models developed primarily from historical and expected relationship with quoted market prices.

16

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Six Months Ended June 30, 2016 and 2015 - (Continued)

(Unaudited)

Values are adjusted to reflect the credit risk inherent in the transaction as well as the potential impact of liquidating open positions in an orderly manner over a reasonable time period under current conditions. Changes in market prices and management estimates directly affect the estimated fair value of these contracts. Accordingly, it is reasonably possible that such estimates may change in the near term.

The fair value of our interest rate swaps, if any, and commodity non-trading derivatives is based on prices supported by quoted market prices and other external sources and prices based on models and other valuation methods. The “prices supported by quoted market prices and other external sources” category includes our interest rate swaps, if any, our NGL and crude oil swaps and our NYMEX positions in natural gas. In addition, this category includes our forward positions in natural gas for which our forward price curves are obtained from a third party pricing service and then validated through an internal process which includes the use of independent broker quotes. This category also includes our forward positions in NGLs at points for which OTC broker quotes for similar assets or liabilities are available for the full term of the instrument. This category also includes “strip” transactions whose pricing inputs are directly or indirectly observable from external sources and then modeled to daily or monthly prices as appropriate. The “prices based on models and other valuation methods” category includes the value of transactions for which inputs to the fair value of the instrument are unobservable in the marketplace and are considered significant to the overall fair value of the instrument. The fair value of these instruments may be based upon an internally developed price curve, which was constructed as a result of the long dated nature of the transaction or the illiquidity of the specific market point.

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 accounts receivable, accounts payable and short-term borrowings are not materially different from their carrying amounts because of the short-term nature of these instruments or the stated rates approximating market rates. Derivative instruments are carried at fair value.

We determine the fair value of our fixed-rate Senior Notes based on quotes obtained from bond dealers. We determine the fair value of borrowings under our Amended and Restated Credit Agreement 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. We classify the fair values of our outstanding debt balances within Level 2 of the valuation hierarchy. As of June 30, 2016 and December 31, 2015, the carrying value and fair value of our long-term fixed-rate Senior Notes, including current maturities, and our Amended and Restated Credit Agreement were as follows:

		June 30, 2016				December 31, 2015
		Carrying Value (a)		Fair Value		Carrying Value (a)		Fair Value
	(Millions)
Senior Notes		$	2,064	$	1,941	$	2,063	$	1,650
Amended and Restated Credit Agreement		$	316	$	316	$	375	$	375

(a) Excludes unamortized issuance costs.

17

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Six Months Ended June 30, 2016 and 2015 - (Continued)

(Unaudited)

9. Debt

	June 30,   2016			December 31,   2015
	(Millions)
Amended and Restated Credit Agreement
Revolving credit facility, weighted-average variable interest rate of 1.74% and 1.57%, as of June 30, 2016 and December 31, 2015, respectively, due May 1, 2019	$	316		$	375
Debt Securities
Issued November 27, 2012, interest at 2.50% payable semi-annually, due December 1, 2017	500			500
Issued March 13, 2014, interest at 2.70% payable semi-annually, due April 1, 2019	325			325
Issued March 13, 2012, interest at 4.95% payable semi-annually, due April 1, 2022	350			350
Issued March 14, 2013, interest at 3.875% payable semi-annually, due March 15, 2023	500			500
Issued March 13, 2014, interest at 5.60% payable semi-annually, due April 1, 2044	400			400
Unamortized issuance costs	(13		)	(14		)
Unamortized discount	(11		)	(12		)
Total long-term debt	$	2,367		$	2,424

Amended and Restated Credit Agreement

On May 1, 2014, we entered into a $1.25 billion amended and restated senior unsecured revolving credit agreement that matures on May 1, 2019, or the Amended and Restated Credit Agreement. The Amended and Restated Credit Agreement is used for working capital requirements and other general partnership purposes including acquisitions.

Our cost of borrowing under the Amended and Restated Credit Agreement is determined by a ratings-based pricing grid. Indebtedness under the Amended and Restated Credit Agreement bears interest at either: (1) LIBOR, plus an applicable margin of 1.275% based on our current credit rating; or (2) (a) the base rate which shall be the higher of Wells Fargo Bank N.A.’s prime rate, the Federal Funds rate, plus 0.50% or the LIBOR Market Index rate, plus 1%, plus (b) an applicable margin of 0.275% based on our current credit rating. The Amended and Restated Credit Agreement incurs an annual facility fee of 0.225% based on our current credit rating. This fee is paid on drawn and undrawn portions of the $1.25 billion Amended and Restated Credit Agreement.

As of June 30, 2016, we had unused borrowing capacity of $933 million, net of letters of credit, under the Amended and Restated Credit Agreement, all of which was available for working capital and other general partnership purposes. Our borrowing capacity may be limited by financial covenants set forth in the Amended and Restated Credit Agreement. Except in the case of a default, amounts borrowed under our Amended and Restated Credit Agreement will not become due prior to the May 1, 2019 maturity date.

The Amended and Restated 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 Amended and Restated Credit Agreement) of not more than 5.0 to 1.0, and following the consummation of qualifying acquisitions, not more than 5.5 to 1.0, on a temporary basis for three consecutive quarters, including the quarter in which such acquisition is consummated.

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Six Months Ended June 30, 2016 and 2015 - (Continued)

(Unaudited)

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

	Debt Maturities
	(Millions)
2017	$	500
2018	—
2019	641
2020	—
2021	—
Thereafter	1,250
	2,391
Unamortized issuance costs	(13		)
Unamortized discount	(11		)
Total	$	2,367

10. Risk Management and Hedging Activities

Our day-to-day operations expose us to a variety of risks including but not limited to changes in the prices of commodities that we buy or sell, changes in interest rates, and the creditworthiness of each of our counterparties. We manage certain of these exposures with either physical or financial transactions. We have established a comprehensive 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 composed of senior executives who receive regular briefings on positions and exposures, credit exposures and overall risk management in the context of market activities. The Risk Management Committee is responsible for the overall management of credit risk and commodity price risk, including monitoring exposure limits. The following describes each of the risks that we manage.

Commodity Price Risk

Cash Flow Protection Activities — 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, processing and storage services, we may receive cash 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 2017 with commodity derivative instruments. Our commodity derivative instruments used for our hedging program are a combination of direct NGL product, crude oil, and natural gas hedges. Due to the limited liquidity and tenor of the NGL derivative market, we have used crude oil swaps to mitigate a portion of our commodity price exposure to NGLs. Historically, prices of NGLs have generally been related to crude oil prices; however, there are periods of time when NGL pricing may be at a greater discount to crude oil, resulting in additional exposure to NGL commodity prices. The relationship of NGLs to crude oil continues to be lower than historical relationships. When our crude oil swaps become short-term in nature, we have periodically converted certain crude oil derivatives to NGL derivatives by entering into offsetting crude oil swaps while adding NGL swaps. Our crude oil and NGL transactions are primarily accomplished through the use of forward contracts that effectively exchange our floating price risk for a fixed price. 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.

Our Wholesale Propane Logistics segment is generally designed with the intent 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, including fixed price sales. While the majority of our sales and purchases in this

19

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Six Months Ended June 30, 2016 and 2015 - (Continued)

(Unaudited)

segment are index-based, occasionally, we may enter into fixed price sales agreements in the event that a 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 use financial derivatives to manage the value of our propane inventories. These transactions are not designated as hedging instruments for accounting purposes and any change in fair 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.

Natural Gas Storage and Pipeline Asset Based Commodity Derivative Program — Our natural gas storage and pipeline assets are exposed to certain risks including changes in commodity prices. We manage commodity price risk related to our natural gas storage and pipeline assets through our commodity derivative program. The commercial activities related to our natural gas storage and pipeline assets primarily consist of the purchase and sale of gas and associated time spreads and basis spreads.

A time spread transaction is executed by establishing a long gas position at one point in time and establishing an equal short gas position at a different point in time. Time spread transactions allow us to lock in a margin supported by the injection, withdrawal, and storage capacity of our natural gas storage assets. We may execute basis spread transactions to mitigate the risk of sale and purchase price differentials across our system. A basis spread transaction allows us to lock in a margin on our physical purchases and sales of gas, including injections and withdrawals from storage. We typically use swaps to execute these transactions, which are not designated as hedging instruments and are recorded at fair value with changes in fair value recorded in the current period condensed consolidated statements of operations. While gas held in our storage locations is recorded at the lower of average cost or market, the derivative instruments that are used to manage our storage facilities are recorded at fair value and any changes in fair value are currently recorded in our condensed consolidated statements of operations. Even though we may have economically hedged our exposure and locked in a future margin, the use of lower-of-cost-or-market accounting for our physical inventory and the use of mark-to-market accounting for our derivative instruments may subject our earnings to market volatility.

Commodity Cash Flow Hedges — In order for storage facilities to remain operational, a minimum level of base gas must be maintained in each storage cavern, which is capitalized on our condensed consolidated balance sheets as a component of property, plant and equipment, net. During construction or expansion of our storage caverns, we may execute a series of derivative financial instruments to mitigate a portion of the risk associated with the forecasted purchase of natural gas when we bring the storage caverns to operation. These derivative financial instruments may be designated as cash flow hedges. While the cash paid upon settlement of these hedges economically fixes the cash required to purchase the base gas, the deferred losses or gains would remain in accumulated other comprehensive income, or AOCI, until the cavern is emptied and the base gas is sold. The balance in AOCI of our previously settled base gas cash flow hedges was in a loss position of $6 million as of June 30, 2016.

Interest Rate Risk

We enter into debt arrangements that have either fixed or floating rates, therefore we are exposed to market risks related to changes in interest rates. We periodically use interest rate swaps to convert our floating rate debt to fixed-rate debt or to convert our fixed-rate debt to floating rate debt. Our primary goals include: (1) maintaining an appropriate ratio of fixed-rate debt to floating-rate debt; (2) reducing volatility of earnings resulting from interest rate fluctuations; and (3) locking in attractive interest rates.

The balance in AOCI of our previously settled interest rate swap cash flow hedges was in a loss position of $3 million as of June 30, 2016.

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.

20

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Six Months Ended June 30, 2016 and 2015 - (Continued)

(Unaudited)

We have International Swaps and Derivatives 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 Amended and Restated 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.

• Our ISDA counterparties generally have collateral thresholds of zero, requiring us to fully collateralize any commodity contracts in a net liability position, when our credit rating is below investment grade.

• 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 other credit arrangements and the amount of the default is above certain predefined thresholds, which are significantly high and are generally consistent with the terms of our Amended and Restated Credit Agreement. As of June 30, 2016, we were not a party to any agreements that would trigger the cross-default provisions.

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

Depending upon the movement of commodity prices and interest rates, each of our individual contracts with counterparties to our commodity derivative instruments or to our interest rate swap instruments are in either a net asset or net liability position. As of June 30, 2016, all of our individual commodity derivative contracts that contain credit-risk related contingent features were in a net asset position. If we were required to net settle our position with an individual counterparty, due to a credit-risk related event, our ISDA contracts may 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 June 30, 2016, we were not required to post additional collateral or offset net liability contracts with contracts in a net asset position because all of our commodity derivative contracts that contain credit-risk related contingent features were in a net asset position.

Offsetting

Certain of our derivative instruments are subject to a master netting or similar arrangement, whereby we may elect to settle multiple positions with an individual counterparty through a single net payment. Each of our individual derivative instruments are presented on a gross basis on the condensed consolidated balance sheets, regardless of our ability to net settle our positions. Instruments that are governed by agreements that include net settle provisions allow final settlement, when presented with a termination event, of outstanding amounts by extinguishing the mutual debts owed between the parties in exchange for a net amount due. We have trade receivables and payables associated with derivative instruments, subject to master netting or similar agreements, which are not included in the table below. The following summarizes the gross and net amounts of our derivative instruments:

	June 30, 2016									December 31, 2015
	Gross Amounts of Assets and (Liabilities) Presented in the Balance Sheet			Amounts Not Offset in the Balance Sheet - Financial Instruments (a)			Net Amount			Gross Amounts of Assets and (Liabilities) Presented in the Balance Sheet			Amounts Not Offset in the Balance Sheet - Financial Instruments (a)			Net Amount
	(Millions)
Assets:
Commodity derivatives	$	34		$	(15	)	$	19		$	114		$	(19	)	$	95
Liabilities:
Commodity derivatives	$	(20	)	$	15		$	(5	)	$	(19	)	$	19		$	—

(a) There is no cash collateral pledged or received against these positions.

21

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Six Months Ended June 30, 2016 and 2015 - (Continued)

(Unaudited)

Summarized Derivative Information

The fair value of our derivative instruments 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 below. We have no derivative instruments that are designated as hedging instruments for accounting purposes as of June 30, 2016 and December 31, 2015.

Balance Sheet Line Item	June 30,   2016		December 31,   2015		Balance Sheet Line Item	June 30,   2016			December 31,   2015
	(Millions)					(Millions)
Derivative Assets Not Designated as Hedging Instruments:					Derivative Liabilities Not Designated as Hedging Instruments:
Commodity derivatives:					Commodity derivatives:
Unrealized gains on derivative instruments — current	$	29	$	105	Unrealized losses on derivative instruments — current	$	(20	)	$	(18	)
Unrealized gains on derivative instruments — long-term	5		9		Unrealized losses on derivative instruments — long-term	—			(1		)
Total	$	34	$	114	Total	$	(20	)	$	(19	)

The following summarizes the balance and activity within AOCI relative to our interest rate, commodity and foreign currency cash flow hedges as of and for the three months ended June 30, 2016:

	Interest Rate Cash Flow Hedges			Commodity Cash Flow Hedges			Foreign Currency Cash Flow Hedges (a)		Total
	(Millions)
Net deferred (losses) gains in AOCI (beginning balance)	$	(3	)	$	(6	)	$	1	$	(8	)
Net deferred (losses) gains in AOCI (ending balance)	$	(3	)	$	(6	)	$	1	$	(8	)
Deferred losses in AOCI expected to be reclassified into earnings over the next 12 months	$	(1	)	$	—		$	—	$	(1	)

The following summarizes the balance and activity within AOCI relative to our interest rate, commodity and foreign currency cash flow hedges as of and for the six months ended June 30, 2016:

	Interest Rate Cash Flow Hedges			Commodity Cash Flow Hedges			Foreign Currency Cash Flow Hedges (a)		Total
	(Millions)
Net deferred (losses) gains in AOCI (beginning balance)	$	(3	)	$	(6	)	$	1	$	(8	)
Net deferred (losses) gains in AOCI (ending balance)	$	(3	)	$	(6	)	$	1	$	(8	)

(a) Relates to Discovery, an unconsolidated affiliate.

For the three and six months ended June 30, 2016, no derivative losses attributable to the ineffective portion or to amounts excluded from effectiveness testing were recognized in gains or losses from commodity derivative activity, net or interest expense in our condensed consolidated statements of operations. For the three and six months ended June 30, 2016, no derivative losses were reclassified from AOCI to gains or losses from commodity derivative activity, net or interest expense as a result of the discontinuance of cash flow hedges related to certain forecasted transactions that are not probable of occurring.

22

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Six Months Ended June 30, 2016 and 2015 - (Continued)

(Unaudited)

The following summarizes the balance and activity within AOCI relative to our interest rate, commodity and foreign currency cash flow hedges as of and for the three months ended June 30, 2015:

	Interest Rate Cash Flow Hedges			Commodity Cash Flow Hedges			Foreign Currency Cash Flow Hedges (a)		Total
	(Millions)
Net deferred (losses) gains in AOCI (beginning balance)	$	(3	)	$	(6	)	$	1	$	(8	)
Net deferred (losses) gains in AOCI (ending balance)	$	(3	)	$	(6	)	$	1	$	(8	)

(a) Relates to Discovery, an unconsolidated affiliate.

The following summarizes the balance and activity within AOCI relative to our interest rate, commodity and foreign currency cash flow hedges as of and for the six months ended June 30, 2015:

	Interest Rate Cash Flow Hedges				Commodity Cash Flow Hedges			Foreign Currency Cash Flow Hedges (a)		Total
	(Millions)
Net deferred (losses) gains in AOCI (beginning balance)	$	(4	)		$	(6	)	$	1	$	(9	)
Losses reclassified from AOCI to earnings — effective portion	1			(b)	—			—		1
Net deferred (losses) gains in AOCI (ending balance)	$	(3	)		$	(6	)	$	1	$	(8	)

(a) Relates to Discovery, an unconsolidated affiliate.

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

For the three and six months ended June 30, 2015, no derivative losses attributable to the ineffective portion or to amounts excluded from effectiveness testing were recognized in gains or losses from commodity derivative activity, net or interest expense in our condensed consolidated statements of operations. For the three and six months ended June 30, 2015, no derivative losses were reclassified from AOCI to gains or losses from commodity derivative activity, net or interest expense as a result of the discontinuance of cash flow hedges related to certain forecasted transactions that are not probable of occurring.

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

Commodity Derivatives: Statements of Operations Line Item		Three Months Ended June 30,						Six Months Ended June 30,
		2016			2015			2016			2015
	(Millions)
Third party:
Realized gains		$	11		$	46		$	51		$	53
Unrealized losses		(19		)	(51		)	(55		)	(53		)
Losses from commodity derivative activity, net		$	(8	)	$	(5	)	$	(4	)	$	—
Affiliates:
Realized gains		$	6		$	3		$	20		$	57
Unrealized losses		(18		)	(4		)	(27		)	(44		)
(Losses) gains from commodity derivative activity, net —affiliates		$	(12	)	$	(1	)	$	(7	)	$	13

23

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Six Months Ended June 30, 2016 and 2015 - (Continued)

(Unaudited)

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

The following tables represent, 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 tables below.

	June 30, 2016
	Crude Oil		Natural Gas		Natural Gas Liquids		Natural Gas Basis Swaps
Year of Expiration	Net Short Position (Bbls)		Net Short Position (MMBtu)		Net (Short) long Position (Bbls)		Net Long Position (MMBtu)
2016	(736,000	)	(3,940,000	)	(150,000	)	1,522,500
2017	—		(15,917,500	)	15,000		1,800,000
	June 30, 2015
	Crude Oil		Natural Gas		Natural Gas Liquids		Natural Gas Basis Swaps
Year of Expiration	Net Short Position (Bbls)		Net Short Position (MMBtu)		Net Short Position (Bbls)		Net Long Position (MMBtu)
2015	(559,912	)	(13,985,860	)	(2,790,912	)	980,000
2016	(1,408,672	)	(7,823,564	)	(813,267	)	1,690,000
2017	—		(6,387,500	)	—		—

11. Partnership Equity and Distributions

During the six months ended June 30, 2016, we issued no common units pursuant to our 2014 equity distribution agreement. As of June 30, 2016, approximately $349 million of common units remained available for sale pursuant to our 2014 equity distribution agreement.

During the six months ended June 30, 2015, we issued 788,033 common units pursuant to our 2014 equity distribution agreement and received proceeds of $31 million, net of commissions and offering costs of less than $1 million.

The following table presents our cash distributions paid in 2016 and 2015:

Payment Date	Per Unit Distribution		Total Cash Distribution
			(Millions)
May 13, 2016	$	0.7800	$	121
February 12, 2016	$	0.7800	$	121
November 13, 2015	$	0.7800	$	120
August 14, 2015	$	0.7800	$	121
May 15, 2015	$	0.7800	$	121
February 13, 2015	$	0.7800	$	120

12. Net Income or Loss per Limited Partner Unit

Basic and diluted net income or loss per limited partner unit, or LPU, is calculated by dividing net income or loss allocable to limited partners, by the weighted-average number of outstanding LPUs during the period. Diluted net income or loss per LPU is computed based on the weighted average number of units plus the effect of dilutive potential units outstanding during the period using the two-class method. Dilutive potential units include outstanding awards under our Long-Term Incentive Plan. The dilutive effect of unit-based awards was 940 and 10,355 equivalent units during the three months ended June 30, 2016 and 2015, respectively, and 1,272 and 10,960 equivalent units during the six months ended June 30, 2016, and 2015 respectively.

24

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Six Months Ended June 30, 2016 and 2015 - (Continued)

(Unaudited)

13. Commitments and Contingent Liabilities

Litigation — We are not a party to any significant legal proceedings, but are a party to various 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 the foregoing 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 flow.

Environmental — The operation of pipelines, plants and other facilities for gathering, transporting, processing, treating, or storing natural gas, NGLs and other products is subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of these facilities, we must comply with laws and regulations at the federal, state and local levels that relate to air and water quality, hazardous and solid waste management and disposal, and other environmental matters. The cost of planning, designing, constructing and operating pipelines, plants, and other facilities incorporates compliance with environmental laws and regulations and safety standards. In addition, there is increasing focus (i) from city, state and federal regulatory officials and through litigation, on hydraulic fracturing and the real or perceived environmental impacts of this technique, which indirectly presents some risk to our available supply of natural gas, and (ii) from state and federal regulatory officials regarding the emission of greenhouse gases which could impose regulatory burdens and increase the cost of our operations. Failure to comply with these various health, safety and environmental laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures, including citizen suits, which can include the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of injunctions or restrictions on operation. Management believes that, based on currently known information, compliance with these laws and regulations will not have a material adverse effect on our condensed consolidated results of operations, financial position or cash flows.

14. Business Segments

Our operations are located in the United States and are organized into three reporting segments: Natural Gas Services; NGL Logistics; and Wholesale Propane Logistics. Our chief operating decision maker regularly reviews financial information about our operating segments, which are aggregated into the reporting units presented, in deciding how to allocate resources and evaluate performance.

Natural Gas Services — Our Natural Gas Services segment provides services that include gathering, compressing, treating, processing, transporting and storing natural gas, and fractionating NGLs. The segment consists of our Eagle Ford system, East Texas system, Southeast Texas system, Michigan system, Northern Louisiana system, Southern Oklahoma system, Wyoming system, DJ Basin system, 75% interest in the Piceance system and 40% interest in Discovery.

NGL Logistics — Our NGL Logistics segment provides services that include transportation, storage and fractionation of NGLs. The segment consists of our storage facility in Michigan, the DJ Basin fractionators, 12.5% interest in the Mont Belvieu Enterprise fractionator, 20% interest in the Mont Belvieu 1 fractionator, 10% interest in the Texas Express intrastate pipeline, 15% interest in the Panola intrastate pipeline, 33.33% interests in the Southern Hills, Sand Hills and Front Range pipelines, the Black Lake and Wattenberg interstate pipelines and the Seabreeze and Wilbreeze intrastate pipelines.

Wholesale Propane Logistics — Our Wholesale Propane Logistics segment provides services that include the receipt of propane and other liquefied petroleum gases by pipeline, rail or ship to our terminals that store and deliver the product to distributors. The segment consists of 6 rail terminals, one marine terminal, one pipeline terminal and access to several open-access pipeline terminals.

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 operations of each segment.

25

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Six Months Ended June 30, 2016 and 2015 - (Continued)

(Unaudited)

The following tables set forth our segment information:

Three Months Ended June 30, 2016

	Natural Gas Services			NGL Logistics			Wholesale Propane Logistics			Other			Total
	(Millions)
Total operating revenue	$	302		$	21		$	25		$	—		$	348
Gross margin (a)	$	91		$	21		$	5		$	—		$	117
Operating and maintenance expense	(39		)	(5		)	(1		)	—			(45		)
Depreciation and amortization expense	(28		)	(2		)	—			—			(30		)
General and administrative expense	—			—			—			(21		)	(21		)
Other expense	(3		)	—			—			—			(3		)
Earnings from unconsolidated affiliates	16			37			—			—			53
Interest expense	—			—			—			(24		)	(24		)
Income tax expense	—			—			—			(1		)	(1		)
Net income (loss)	$	37		$	51		$	4		$	(46	)	$	46
Net income attributable to noncontrolling interests	(1		)	—			—			—			(1		)
Net income (loss) attributable to partners	$	36		$	51		$	4		$	(46	)	$	45
Non-cash derivative mark-to-market (b)	$	(36	)	$	—		$	(1	)	$	—		$	(37	)

Three Months Ended June 30, 2015

	Natural Gas Services			NGL Logistics			Wholesale Propane Logistics			Other			Total
	(Millions)
Total operating revenue	$	380		$	21		$	29		$	—		$	430
Gross margin (a)	$	97		$	21		$	6		$	—		$	124
Operating and maintenance expense	(43		)	(6		)	(2		)	—			(51		)
Depreciation and amortization expense	(27		)	(2		)	—			—			(29		)
General and administrative expense	—			—			—			(22		)	(22		)
Goodwill impairment	(49		)	—			—			—			(49		)
Other expense	(1		)	—			—			—			(1		)
Earnings from unconsolidated affiliates	16			28			—			—			44
Interest expense	—			—			—			(22		)	(22		)
Income tax benefit	—			—			—			4			4
Net (loss) income	$	(7	)	$	41		$	4		$	(40	)	$	(2	)
Net income attributable to noncontrolling interests	—			—			—			—			—
Net (loss) income attributable to partners	$	(7	)	$	41		$	4		$	(40	)	$	(2	)
Non-cash derivative mark-to-market (b)	$	(55	)	$	—		$	—		$	—		$	(55	)
Non-cash lower of cost or market adjustments	$	—		$	—		$	1		$	—		$	1

26

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Six Months Ended June 30, 2016 and 2015 - (Continued)

(Unaudited)

Six Months Ended June 30, 2016:

	Natural Gas Services			NGL Logistics			Wholesale Propane Logistics			Other			Total
	(Millions)
Total operating revenue	$	607		$	42		$	78		$	—		$	727
Gross margin (a)	$	202		$	42		$	21		$	—		$	265
Operating and maintenance expense	(79		)	(10		)	(4		)	—			(93		)
Depreciation and amortization expense	(57		)	(4		)	(1		)	—			(62		)
General and administrative expense	—			—			—			(42		)	(42		)
Other expense	(3		)	—			—			—			(3		)
Earnings from unconsolidated affiliates	31			71			—			—			102
Interest expense	—			—			—			(48		)	(48		)
Income tax expense	—			—			—			(1		)	(1		)
Net income (loss)	$	94		$	99		$	16		$	(91	)	$	118
Net income attributable to noncontrolling interests	(1		)	—			—			—			(1		)
Net income (loss) attributable to partners	$	93		$	99		$	16		$	(91	)	$	117
Non-cash derivative mark-to-market (b)	$	(81	)	$	—		$	(1	)	$	—		$	(82	)
Non-cash lower of cost or market adjustments	$	3		$	—		$	—		$	—		$	3
Capital expenditures	$	14		$	2		$	1		$	—		$	17
Investments in unconsolidated affiliates, net	$	—		$	16		$	—		$	—		$	16

27

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Six Months Ended June 30, 2016 and 2015 - (Continued)

(Unaudited)

Six Months Ended June 30, 2015:

	Natural Gas Services			NGL Logistics			Wholesale Propane Logistics			Other			Total
	(Millions)
Total operating revenue	$	820		$	39		$	139		$	—		$	998
Gross margin (a)	$	216		$	39		$	35		$	—		$	290
Operating and maintenance expense	(83		)	(10		)	(5		)	—			(98		)
Depreciation and amortization expense	(53		)	(4		)	(1		)	—			(58		)
General and administrative expense	—			—			—			(43		)	(43		)
Goodwill impairment	(49		)	—			—			—			(49		)
Other expense	(1		)	—			—			—			(1		)
Earnings from unconsolidated affiliates	14			53			—			—			67
Interest expense	—			—			—			(44		)	(44		)
Income tax benefit	—			—			—			3			3
Net income (loss)	$	44		$	78		$	29		$	(84	)	$	67
Net income attributable to noncontrolling interests	—			—			—			—			—
Net income (loss) attributable to partners	$	44		$	78		$	29		$	(84	)	$	67
Non-cash derivative mark-to-market (b)	$	(100	)	$	—		$	3		$	(1	)	$	(98	)
Non-cash lower of cost or market adjustments	$	3		$	—		$	2		$	—		$	5
Capital expenditures	$	170		$	21		$	3		$	—		$	194
Investments in unconsolidated affiliates, net	$	12		$	34		$	—		$	—		$	46

	June 30,		December 31,
	2016		2015
	(Millions)
Segment long-term assets:
Natural Gas Services	$	4,177	$	4,362
NGL Logistics	674		679
Wholesale Propane Logistics	119		120
Other (c)	13		10
Total long-term assets	4,983		5,171
Current assets	319		306
Total assets	$	5,302	$	5,477

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

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

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

28

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Six Months Ended June 30, 2016 and 2015 - (Continued)

(Unaudited)

15. Supplemental Cash Flow Information

	Six Months Ended June 30,
	2016			2015
	(Millions)
Cash paid for interest:
Cash paid for interest, net of amounts capitalized	$	42		$	41
Cash paid for income taxes, net of income tax refunds	$	2		$	3
Non-cash investing and financing activities:
Property, plant and equipment acquired with accounts payable	$	2		$	33
Other non-cash changes in property, plant and equipment	$	(8	)	$	(1	)
Property, plant and equipment reclassified to assets held for sale, net of accumulated depreciation	$	(116	)	$	—

16. 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 100% 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 debt securities of the subsidiary issuer. For the purpose of the following financial information, investments in subsidiaries are reflected in accordance with the equity method of accounting. The financial information may not necessarily be indicative of results of operations, cash flows, or financial position had the subsidiaries operated as independent entities.

29

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Six Months Ended June 30, 2016 and 2015 - (Continued)

(Unaudited)

	Condensed Consolidating Balance Sheet
	June 30, 2016
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
ASSETS
Current assets:
Cash and cash equivalents	$	—	$	—		$	1		$	—		$	1
Accounts receivable, net	—		—			139			—			139
Inventories	—		—			29			—			29
Assets held for sale	—		—			118			—			118
Other	—		—			32			—			32
Total current assets	—		—			319			—			319
Property, plant and equipment, net	—		—			3,302			—			3,302
Goodwill and intangible assets, net	—		—			180			—			180
Advances receivable — consolidated subsidiaries	1,917		1,920			—			(3,837		)	—
Investments in consolidated subsidiaries	730		1,196			—			(1,926		)	—
Investments in unconsolidated affiliates	—		—			1,481			—			1,481
Other long-term assets	—		—			20			—			20
Total assets	$	2,647	$	3,116		$	5,302		$	(5,763	)	$	5,302
LIABILITIES AND EQUITY
Accounts payable and other current liabilities	$	—	$	19		$	190		$	—		$	209
Liabilities held for sale	—		—			3			—			3
Advances payable — consolidated subsidiaries	—		—			3,837			(3,837		)	—
Long-term debt	—		2,367			—			—			2,367
Other long-term liabilities	—		—			45			—			45
Total liabilities	—		2,386			4,075			(3,837		)	2,624
Commitments and contingent liabilities
Equity:
Partners’ equity:
Net equity	2,647		733			1,201			(1,926		)	2,655
Accumulated other comprehensive loss	—		(3		)	(5		)	—			(8		)
Total partners’ equity	2,647		730			1,196			(1,926		)	2,647
Noncontrolling interests	—		—			31			—			31
Total equity	2,647		730			1,227			(1,926		)	2,678
Total liabilities and equity	$	2,647	$	3,116		$	5,302		$	(5,763	)	$	5,302

30

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Six Months Ended June 30, 2016 and 2015 - (Continued)

(Unaudited)

	Condensed Consolidating Balance Sheet
	December 31, 2015
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
ASSETS
Current assets:
Cash and cash equivalents	$	—	$	—		$	2		$	—		$	2
Accounts receivable, net	—		—			154			—			154
Inventories	—		—			43			—			43
Other	—		—			107			—			107
Total current assets	—		—			306			—			306
Property, plant and equipment, net	—		—			3,476			—			3,476
Goodwill and intangible assets, net	—		—			184			—			184
Advances receivable — consolidated subsidiaries	2,159		2,023			—			(4,182		)	—
Investments in consolidated subsidiaries	613		1,033			—			(1,646		)	—
Investments in unconsolidated affiliates	—		—			1,493			—			1,493
Other long-term assets	—		—			18			—			18
Total assets	$	2,772	$	3,056		$	5,477		$	(5,828	)	$	5,477
LIABILITIES AND EQUITY
Accounts payable and other current liabilities	$	—	$	19		$	181		$	—		$	200
Advances payable — consolidated subsidiaries	—		—			4,182			(4,182		)	—
Long-term debt	—		2,424			—			—			2,424
Other long-term liabilities	—		—			48			—			48
Total liabilities	—		2,443			4,411			(4,182		)	2,672
Commitments and contingent liabilities
Equity:
Partners’ equity:
Net equity	2,772		616			1,038			(1,646		)	2,780
Accumulated other comprehensive loss	—		(3		)	(5		)	—			(8		)
Total partners’ equity	2,772		613			1,033			(1,646		)	2,772
Noncontrolling interests	—		—			33			—			33
Total equity	2,772		613			1,066			(1,646		)	2,805
Total liabilities and equity	$	2,772	$	3,056		$	5,477		$	(5,828	)	$	5,477

31

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Six Months Ended June 30, 2016 and 2015 - (Continued)

(Unaudited)

	Condensed Consolidating Statement of Operations
	Three Months Ended June 30, 2016
	Parent Guarantor		Subsidiary Issuer			Non- Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
Operating revenues:
Sales of natural gas, propane, NGLs and condensate	$	—	$	—		$	264		$	—		$	264
Transportation, processing and other	—		—			104			—			104
Gains from commodity derivative activity, net	—		—			(20		)	—			(20		)
Total operating revenues	—		—			348			—			348
Operating costs and expenses:
Purchases of natural gas, propane and NGLs	—		—			231			—			231
Operating and maintenance expense	—		—			45			—			45
Depreciation and amortization expense	—		—			30			—			30
General and administrative expense	—		—			21			—			21
Other expense	—		—			3			—			3
Total operating costs and expenses	—		—			330			—			330
Operating income	—		—			18			—			18
Interest expense, net	—		(24		)	—			—			(24		)
Income from consolidated subsidiaries	45		69			—			(114		)	—
Earnings from unconsolidated affiliates	—		—			53			—			53
Income before income taxes	45		45			71			(114		)	47
Income tax expense	—		—			(1		)	—			(1		)
Net income	45		45			70			(114		)	46
Net income attributable to noncontrolling interests	—		—			(1		)	—			(1		)
Net income attributable to partners	$	45	$	45		$	69		$	(114	)	$	45

	Condensed Consolidating Statement of Comprehensive Income
	Three Months Ended June 30, 2016
	Parent Guarantor		Subsidiary Issuer		Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
Net income	$	45	$	45	$	70		$	(114	)	$	46
Other comprehensive income:
Reclassification of cash flow hedge losses into earnings	—		—		—			—			—
Other comprehensive income from consolidated subsidiaries	—		—		—			—			—
Total other comprehensive income	—		—		—			—			—
Total comprehensive income	45		45		70			(114		)	46
Total comprehensive income attributable to noncontrolling interests	—		—		(1		)	—			(1		)
Total comprehensive income attributable to partners	$	45	$	45	$	69		$	(114	)	$	45

32

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Six Months Ended June 30, 2016 and 2015 - (Continued)

(Unaudited)

	Condensed Consolidating Statement of Operations
	Three Months Ended June 30, 2015
	Parent Guarantor			Subsidiary Issuer			Non- Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
Operating revenues:
Sales of natural gas, propane, NGLs and condensate	$	—		$	—		$	352		$	—		$	352
Transportation, processing and other	—			—			84			—			84
Gains from commodity derivative activity, net	—			—			(6		)	—			(6		)
Total operating revenues	—			—			430			—			430
Operating costs and expenses:
Purchases of natural gas, propane and NGLs	—			—			306			—			306
Operating and maintenance expense	—			—			51			—			51
Depreciation and amortization expense	—			—			29			—			29
General and administrative expense	—			—			22			—			22
Goodwill impairment	—			—			49			—			49
Other expense	—			—			1			—			1
Total operating costs and expenses	—			—			458			—			458
Operating income	—			—			(28		)	—			(28		)
Interest expense, net	—			(22		)	—			—			(22		)
Income from consolidated subsidiaries	(2		)	20			—			(18		)	—
Earnings from unconsolidated affiliates	—			—			44			—			44
Income (loss) before income taxes	(2		)	(2		)	16			(18		)	(6		)
Income tax expense	—			—			4			—			4
Net income (loss)	(2		)	(2		)	20			(18		)	(2		)
Net income attributable to noncontrolling interests	—			—			—			—			—
Net income (loss) attributable to partners	$	(2	)	$	(2	)	$	20		$	(18	)	$	(2	)

	Condensed Consolidating Statement of Comprehensive Income
	Three Months Ended June 30, 2015
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries		Consolidating Adjustments			Consolidated
	(Millions)
Net income (loss)	$	(2	)	$	(2	)	$	20	$	(18	)	$	(2	)
Other comprehensive income:
Reclassification of cash flow hedge losses into earnings	—			—			—		—			—
Other comprehensive income from consolidated subsidiaries	—			—			—		—			—
Total other comprehensive income	—			—			—		—			—
Total comprehensive income (loss)	(2		)	(2		)	20		(18		)	(2		)
Total comprehensive income attributable to noncontrolling interests	—			—			—		—			—
Total comprehensive income (loss) attributable to partners	$	(2	)	$	(2	)	$	20	$	(18	)	$	(2	)

33

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Six Months Ended June 30, 2016 and 2015 - (Continued)

(Unaudited)

	Condensed Consolidating Statement of Operations
	Six Months Ended June 30, 2016
	Parent Guarantor		Subsidiary Issuer			Non- Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
Operating revenues:
Sales of natural gas, propane, NGLs and condensate	$	—	$	—		$	531		$	—		$	531
Transportation, processing and other	—		—			207			—			207
Gains from commodity derivative activity, net	—		—			(11		)	—			(11		)
Total operating revenues	—		—			727			—			727
Operating costs and expenses:
Purchases of natural gas, propane and NGLs	—		—			462			—			462
Operating and maintenance expense	—		—			93			—			93
Depreciation and amortization expense	—		—			62			—			62
General and administrative expense	—		—			42			—			42
Other expense	—		—			3			—			3
Total operating costs and expenses	—		—			662			—			662
Operating income	—		—			65			—			65
Interest expense	—		(48		)	—			—			(48		)
Income from consolidated subsidiaries	117		165			—			(282		)	—
Earnings from unconsolidated affiliates	—		—			102			—			102
Income before income taxes	117		117			167			(282		)	119
Income tax expense	—		—			(1		)	—			(1		)
Net income	117		117			166			(282		)	118
Net income attributable to noncontrolling interests	—		—			(1		)	—			(1		)
Net income attributable to partners	$	117	$	117		$	165		$	(282	)	$	117

34

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Six Months Ended June 30, 2016 and 2015 - (Continued)

(Unaudited)

	Condensed Consolidating Statement of Comprehensive Income
	Six Months Ended June 30, 2016
	Parent Guarantor		Subsidiary Issuer		Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
Net income	$	117	$	117	$	166		$	(282	)	$	118
Other comprehensive income:
Reclassification of cash flow hedge losses into earnings	—		—		—			—			—
Other comprehensive income from consolidated subsidiaries	—		—		—			—			—
Total other comprehensive income	—		—		—			—			—
Total comprehensive income	117		117		166			(282		)	118
Total comprehensive income attributable to noncontrolling interests	—		—		(1		)	—			(1		)
Total comprehensive income attributable to partners	$	117	$	117	$	165		$	(282	)	$	117

35

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Six Months Ended June 30, 2016 and 2015 - (Continued)

(Unaudited)

	Condensed Consolidating Statement of Operations
	Six Months Ended June 30, 2015
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries		Consolidating Adjustments			Consolidated
	(Millions)
Operating revenues:
Sales of natural gas, propane, NGLs and condensate	$	—	$	—		$	822	$	—		$	822
Transportation, processing and other	—		—			163		—			163
Gains from commodity derivative activity, net	—		—			13		—			13
Total operating revenues	—		—			998		—			998
Operating costs and expenses:
Purchases of natural gas, propane and NGLs	—		—			708		—			708
Operating and maintenance expense	—		—			98		—			98
Depreciation and amortization expense	—		—			58		—			58
General and administrative expense	—		—			43		—			43
Goodwill impairment	—		—			49		—			49
Other expense	—		—			1		—			1
Total operating costs and expenses	—		—			957		—			957
Operating income	—		—			41		—			41
Interest expense, net	—		(44		)	—		—			(44		)
Income from consolidated subsidiaries	67		111			—		(178		)	—
Earnings from unconsolidated affiliates	—		—			67		—			67
Income before income taxes	67		67			108		(178		)	64
Income tax expense	—		—			3		—			3
Net income	67		67			111		(178		)	67
Net income attributable to noncontrolling interests	—		—			—		—			—
Net income attributable to partners	$	67	$	67		$	111	$	(178	)	$	67

36

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Six Months Ended June 30, 2016 and 2015 - (Continued)

(Unaudited)

	Condensed Consolidating Statement of Comprehensive Income
	Six Months Ended June 30, 2015
	Parent Guarantor		Subsidiary Issuer		Non-Guarantor Subsidiaries		Consolidating Adjustments			Consolidated
	(Millions)
Net income	$	67	$	67	$	111	$	(178	)	$	67
Other comprehensive income:
Reclassification of cash flow hedge losses into earnings	—		1		—		—			1
Other comprehensive income from consolidated subsidiaries	1		—		—		(1		)	—
Total other comprehensive income	1		1		—		(1		)	1
Total comprehensive income	68		68		111		(179		)	68
Total comprehensive income attributable to noncontrolling interests	—		—		—		—			—
Total comprehensive income attributable to partners	$	68	$	68	$	111	$	(179	)	$	68

	Condensed Consolidating Statement of Cash Flows
	Six Months Ended June 30, 2016
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
OPERATING ACTIVITIES
Net cash (used in) provided by operating activities	$	—		$	(44	)	$	364		$	—		$	320
INVESTING ACTIVITIES:
Intercompany transfers	242			103			—			(345		)	—
Capital expenditures	—			—			(17		)	—			(17		)
Investments in unconsolidated affiliates	—			—			(16		)	—			(16		)
Deposits from sales of assets	—			—			16			—			16
Net cash provided by (used in) investing activities	242			103			(17		)	(345		)	(17		)
FINANCING ACTIVITIES:
Intercompany transfers	—			—			(345		)	345			—
Proceeds from long-term debt	—			1,052			—			—			1,052
Payments of long-term debt	—			(1,111		)	—			—			(1,111		)
Distributions to limited partners and general partner	(242		)	—			—			—			(242		)
Distributions to noncontrolling interests	—			—			(3		)	—			(3		)
Net cash (used in) provided by financing activities	(242		)	(59		)	(348		)	345			(304		)
Net change in cash and cash equivalents	—			—			(1		)	—			(1		)
Cash and cash equivalents, beginning of period	—			—			2			—			2
Cash and cash equivalents, end of period	$	—		$	—		$	1		$	—		$	1

37

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three and Six Months Ended June 30, 2016 and 2015 - (Continued)

(Unaudited)

	Condensed Consolidating Statements of Cash Flows
	Six Months Ended June 30, 2015
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
OPERATING ACTIVITIES
Net cash (used in) provided by operating activities	$	—		$	(42	)	$	392		$	—		$	350
INVESTING ACTIVITIES:
Intercompany transfers	210			(62		)	—			(148		)	—
Capital expenditures	—			—			(194		)	—			(194		)
Investments in unconsolidated affiliates	—			—			(46		)	—			(46		)
Net cash provided by (used in) investing activities	210			(62		)	(240		)	(148		)	(240		)
FINANCING ACTIVITIES:
Intercompany transfers	—			—			(148		)	148			—
Proceeds from long-term debt	—			450			—			—			450
Payments of long-term debt	—			(350		)	—			—			(350		)
Proceeds from issuance of common units, net of offering costs	31			—			—			—			31
Distributions to limited partners and general partner	(241		)	—			—			—			(241		)
Distributions to noncontrolling interests	—			—			(2		)	—			(2		)
Contributions from DCP Midstream, LLC	—			—			1			—			1
Net cash (used in) provided by financing activities	(210		)	100			(149		)	148			(111		)
Net change in cash and cash equivalents	—			(4		)	3			—			(1		)
Cash and cash equivalents, beginning of period	—			24			1			—			25
Cash and cash equivalents, end of period	$	—		$	20		$	4		$	—		$	24

17. Subsequent Events

On July 26, 2016, we announced that the board of directors of the General Partner declared a quarterly distribution of $0.78 per unit. The distribution is payable on August 12, 2016 to unitholders of record on August 5, 2016.

The sale of our Northern Louisiana system closed on July 1, 2016. See Note 3 - Assets Held for Sale.

38

Item 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion analyzes our financial condition and results of operations. You should read the following discussion of our financial condition and results of operations in conjunction with our condensed consolidated financial statements and notes included elsewhere in this Quarterly Report on Form 10-Q and the consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2015.

Overview

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

Our business is impacted by commodity prices and volumes. We mitigate a portion of commodity price risk on an overall Partnership basis by growing our fee based assets and through a hedging program on volumes of throughput and sales of natural gas, NGLs and condensate. Various factors impact both commodity prices and volumes, and as indicated in Item 3. "Quantitative and Qualitative Disclosures about Market Risk," we have sensitivities to certain cash and non-cash changes in commodity prices. If commodity prices remain weak for a sustained period, our natural gas throughput and NGL volumes may be impacted, particularly as producers are curtailing or redirecting drilling. Drilling activity levels vary by geographic area, but in general, we have observed widespread decreases in drilling activity with lower commodity prices. The number of active oil and gas drilling rigs in the United States has significantly decreased, from 698 on December 31, 2015 to 430 on July 1, 2016 (Source: Baker Hughes). This decreased drilling activity has caused us to target our strategy in geographic areas where we expect producer activity to continue in the current commodity price environment.

A sustained decline in commodity prices has resulted in a decrease in exploration and development activities in certain fields served by our gas gathering and residue gas and NGL pipeline transportation systems, and our natural gas treating and processing plants, which could lead to reduced utilization of these assets. Although we have seen a number of recent bankruptcies by producers, we believe our contract structure with our producers protects us from a credit perspective since we generally hold the product, sell it and withhold our fees prior to remittance of payments to the producer. Currently our top 20 producers account for a majority of the total natural gas that we gather and process and of these top 20 producers, approximately half are investment grade and half are not investment grade. Despite current weakness, our long-term view is that commodity prices will be at levels that we believe will support growth in natural gas, condensate and NGL production. We believe that future commodity prices will be influenced by North American supply deliverability, the severity of winter and summer weather, the level of North American production and drilling activity by exploration and production companies and the balance of trade between imports and exports of liquid natural gas, NGLs and crude oil.

NGL prices are impacted by the demand from petrochemical and refining industries and export facilities. The petrochemical industry has been making significant investment in building and expanding facilities to convert chemical plants from a heavier oil-based feedstock to lighter NGL-based feedstocks, including ethane. This increased demand in future years should provide support for the increasing supply of ethane. Prior to those facilities commencing operations, ethane prices could remain weak with supply in excess of demand. In addition, export facilities are being expanded and built, which provide support for the increasing supply of NGLs. Although there can be, and has been, volatility in NGL prices, longer term we believe there will be sufficient demand in NGLs to support increasing supply.

In addition to the U.S. financial markets, many businesses and investors continue to monitor global economic conditions. Uncertainty abroad may contribute to volatility in domestic financial and commodity markets. In addition, we are experiencing a period of sustained lower commodity prices.

We plan for these cyclical downturns in commodity prices and we believe we are positioned to withstand current and future commodity price volatility as a result of the following:

• Our growing fee-based business represents a significant portion of our estimated margins.

• We have positive operating cash flow from our well-positioned and diversified assets.

• We have a well defined and targeted hedging program.

• We prudently manage our capital expenditures and focus on fee-based growth projects.

• We believe we have a strong capital structure and balance sheet.

• We believe we have access to sufficient capital.

39

Increased activity levels in liquids rich gas basins combined with access to capital markets at relatively low costs have historically enabled us to execute our growth strategy. Our targeted strategy may take numerous forms such as organic build opportunities within our footprint, dropdown opportunities from DCP Midstream, LLC, joint venture opportunities, and third-party acquisitions. Growth opportunities will be evaluated in cooperation with producers based on the expected level of drilling activity in these geographic regions and the impacts of higher costs of capital.

Some of our growth projects include the following:

• The Sand Hills pipeline mainline capacity expansion was placed into service during the second quarter of 2016.

• On February 1, 2016, we began to participate in earnings for our 15% interest in the Panola intrastate NGL pipeline which is currently undergoing an expansion that is expected to be completed in the third quarter of 2016.

• In the first quarter of 2016, we completed construction on our Grand Parkway gathering system in the DJ Basin.

As part of our ongoing effort to create efficiencies, reduce costs and transform our business, DCP Midstream, LLC, the operator of our assets, announced an approximate 10 percent headcount reduction in April 2016, which involved the elimination of certain operational and corporate positions. This will not impact the operation of our assets.

On April 28, 2016, the unitholders of the Partnership approved the DCP Midstream Partners, LP 2016 Long-Term Incentive Plan (the “2016 plan”), which replaced the 2005 long-term incentive plan that expired pursuant to its terms at the end of 2015 (the “2005 plan”).  Any outstanding awards under the 2005 plan will remain outstanding and settle according to the terms of such grant.  The 2016 plan authorizes up to 900,000 common units to be available for issuance under awards to employees, officers, and non-employee directors of the General Partner and its affiliates.  Awards under the 2016 plan include unit options, phantom units, restricted units, distribution equivalent rights, unit bonuses, common unit awards, and performance awards.  The 2016 plan will expire on the earlier of the date it is terminated by the board of directors of the General Partner or the date that all common units available under the plan have been paid or issued.  We believe the 2016 plan is an important tool to attract and retain qualified individuals who are essential to the future success of the Partnership. 

We announced a quarterly distribution of $0.78 per unit for the second quarter of 2016. This distribution remains unchanged from the previous quarter and the second quarter of 2015.

General Trends and Outlook

During 2016, our strategic objectives will continue to focus on maintaining stable distributable cash flows from our existing assets and executing on opportunities to sustain our long-term distributable cash flows. We believe the key elements to stable distributable cash flows are the diversity of our asset portfolio, our fee-based business which represents a significant portion of our estimated margins, plus our hedged commodity position, the objective of which is to protect against downside risk in our distributable cash flows.

We incur capital expenditures for our consolidated entities and our unconsolidated affiliates. Our 2016 plan includes maintenance capital expenditures of between $30 million and $45 million, and approved expansion capital expenditures between $75 million and $150 million, for the year ending December 31, 2016. For the six months ended June 30, 2016 our actual maintenance capital expenditures were $3 million, which were lower than our 2016 plan on an annualized basis. Expansion capital expenditures include the expansion of the Sand Hills pipeline, expansion of the Panola pipeline, which will be shown as an investment in unconsolidated affiliates in our condensed consolidated statements of cash flows and the completion of the construction of the Grand Parkway gathering project.

For an in-depth discussion of factors that may significantly affect our results, see Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Factors That May Significantly Affect Our Results” included in our Annual Report on Form 10-K for the year ended December 31, 2015.

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Critical Accounting Policies and Estimates

Our critical accounting policies and estimates are described in Critical Accounting Policies and Estimates within Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations" and Note 2 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” in our Annual Report on Form 10-K for the year ended December 31, 2015. The accounting policies and estimates used in preparing our interim condensed consolidated financial statements for the three and six months ended June 30, 2016 are the same as those described in our Annual Report on Form 10-K for the year ended December 31, 2015. Certain information and note disclosures normally included in our annual financial statements prepared in accordance with GAAP have been condensed or omitted from the interim financial statements included in this Quarterly Report on Form 10-Q pursuant to the rules and regulations of the SEC, although we believe that the disclosures made are adequate to make the information not misleading. The unaudited condensed consolidated financial statements and other information included in this Quarterly Report on Form 10-Q should be read in conjunction with the audited consolidated financial statements and notes thereto in our Annual Report on Form 10-K for the year ended December 31, 2015.

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Results of Operations

Consolidated Overview

The following table and discussion is a summary of our condensed consolidated results of operations for the three and six months ended June 30, 2016, and 2015. The results of operations by segment are discussed in further detail following this consolidated overview discussion.

		Three Months Ended June 30,						Six Months Ended June 30,						Variance Three Months 2016 vs. 2015					Variance Six Months 2016 vs. 2015
		2016			2015			2016			2015			Increase (Decrease)			Percent		Increase (Decrease)			Percent
	(Millions, except operating data)
Operating revenues (a):
Natural Gas Services		$	302		$	380		$	607		$	820		$	(78	)	(21	)%	$	(213	)	(26	)%
NGL Logistics		21			21			42			39			—			—	%	3			8	%
Wholesale Propane Logistics		25			29			78			139			(4		)	(14	)%	(61		)	(44	)%
Total operating revenues		348			430			727			998			(82		)	(19	)%	(271		)	(27	)%
Purchases:
Natural Gas Services		(211		)	(283		)	(405		)	(604		)	(72		)	(25	)%	(199		)	(33	)%
Wholesale Propane Logistics		(20		)	(23		)	(57		)	(104		)	(3		)	(13	)%	(47		)	(45	)%
Total purchases		(231		)	(306		)	(462		)	(708		)	(75		)	(25	)%	(246		)	(35	)%
Operating and maintenance expense		(45		)	(51		)	(93		)	(98		)	(6		)	(12	)%	(5		)	(5	)%
Depreciation and amortization expense		(30		)	(29		)	(62		)	(58		)	1			3	%	4			7	%
General and administrative expense		(21		)	(22		)	(42		)	(43		)	(1		)	(5	)%	(1		)	(2	)%
Goodwill impairment		—			(49		)	—			(49		)	(49		)	(100	)%	(49		)	(100	)%
Other expense		(3		)	(1		)	(3		)	(1		)	2			200	%	2			200	%
Earnings from unconsolidated affiliates (b)		53			44			102			67			9			20	%	35			52	%
Interest expense		(24		)	(22		)	(48		)	(44		)	2			9	%	4			9	%
Income tax (expense) benefit		(1		)	4			(1		)	3			(5		)	*		(4		)	*
Net income attributable to noncontrolling interests		(1		)	—			(1		)	—			1			100	%	1			100	%
Net income (loss) attributable to partners		$	45		$	(2	)	$	117		$	67		$	47		*		$	50		75	%
Other data:
Gross margin (c):
Natural Gas Services		$	91		$	97		$	202		$	216		$	(6	)	(6	)%	$	(14	)	(6	)%
NGL Logistics		21			21			42			39			$	—		—	%	$	3		8	%
Wholesale Propane Logistics		5			6			21			35			$	(1	)	(17	)%	$	(14	)	(40	)%
Total gross margin		$	117		$	124		$	265		$	290		$	(7	)	(6	)%	$	(25	)	(9	)%
Non-cash commodity derivative mark-to-market		$	(37	)	$	(55	)	$	(82	)	$	(97	)	$	(18	)	(33	)%	$	(15	)	(15	)%
Natural gas throughput (MMcf/d) (d)		2,640			2,679			2,683			2,655			(39		)	(1	)%	28			1	%
NGL gross production (Bbls/d) (d)		169,983			156,840			165,147			153,932			13,143			8	%	11,215			7	%
NGL pipelines throughput (Bbls/d) (d)		295,520			255,810			288,366			254,001			39,710			16	%	34,365			14	%
NGL fractionator throughput (Bbls/d) (d)		57,909			56,043			59,334			54,018			1,866			3	%	5,316			10	%
Propane sales volume (Bbls/d)		9,897			10,420			15,351			20,517			(523		)	(5	)%	(5,166		)	(25	)%

_________________        

* Percentage change is not meaningful.

(a) Operating revenues include the impact of commodity derivative activity.

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(b) Earnings for Discovery, Sand Hills, Southern Hills, Front Range, Mont Belvieu 1 and Texas Express include the amortization of the net difference between the carrying amount of the investments and the underlying equity of the entities.

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

(d) Includes our share, based on our ownership percentage, of the throughput volumes and NGL production.

Three months ended June 30, 2016 vs. Three months ended June 30, 2015

Total Operating Revenues — Total operating revenues decreased $82 million in 2016 compared to 2015 primarily as a result of the following:

• $78 million decrease for our Natural Gas Services segment primarily due to decreased commodity prices, lower gas and NGL sales volumes primarily related to our Eagle Ford and East Texas systems which impact both sales and purchases, lower prices and volumes at our natural gas storage and pipeline assets and unfavorable commodity derivative activity, partially offset by growth in our DJ Basin system; and

• $4 million decrease for our Wholesale Propane Logistics segment primarily due to lower propane prices and volumes.

Total Purchases — Total purchases decreased $75 million in 2016 compared to 2015 primarily as a result of the following:

• Purchases of natural gas and NGLs decreased $72 million in 2016 compared to 2015 as a result of decreased commodity prices and lower gas and NGL sales volumes, primarily related to our Eagle Ford and East Texas systems, which impact both sales and purchases; and

• Purchases of propane decreased in 2016 compared to 2015 primarily due to lower propane prices which impact both sales and purchases.

Operating and Maintenance Expense — Operating and maintenance expense decreased in 2016 compared to 2015 primarily as a result of improved operating efficiencies and other cost savings initiatives.

Goodwill impairment— Goodwill impairment expense in 2015 represents impairment of our Collbran, Michigan and Southeast Texas reporting units.

Earnings from Unconsolidated Affiliates — Earnings from unconsolidated affiliates increased in 2016 compared to 2015 primarily as a result of the completion of the Keathley Canyon project at Discovery in February 2015 in our Gas Services segment and increased volumes on our Sand Hills, Southern Hills and Front Range pipelines in our NGL Logistics segment.

Net Income Attributable to Partners — Net income attributable to partners increased in 2016 compared to 2015 for the reasons set forth above.

Gross Margin — Gross margin decreased $7 million in 2016 compared to 2015 primarily due to a $6 million decrease for our Natural Gas Services segment primarily related to lower commodity prices, unfavorable commodity derivative activity and lower gas and NGL volumes on our Eagle Ford and East Texas systems, partially offset by growth in our DJ Basin system related to Lucerne 2 being placed into service mid-2015.

Six months ended June 30, 2016 vs. Six months ended June 30, 2015

Total Operating Revenues — Total operating revenues decreased $271 million in 2016 compared to 2015 primarily as a result of the following:

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• $213 million decrease for our Natural Gas Services segment primarily due to decreased commodity prices, lower gas and NGL sales volumes primarily related to our Eagle Ford and East Texas systems which impact both sales and purchases, lower prices and volumes at our natural gas storage and pipeline assets and unfavorable commodity derivative activity, partially offset by growth in our DJ Basin system; and

• $61 million decrease for our Wholesale Propane Logistics segment primarily due to lower propane volumes and prices.

Total Purchases — Total purchases decreased $246 million in 2016 compared to 2015 primarily as a result of the following:

• Purchases of natural gas and NGLs decreased $199 million in 2016 compared to 2015 as a result of decreased commodity prices and lower gas and NGL sales volumes, primarily related to our Eagle Ford and East Texas systems, and decreased volumes at our natural gas storage and pipeline assets, which impact both sales and purchases; and

• Purchases of propane decreased in 2016 compared to 2015 primarily due to decreased volumes as discussed below under the heading "Propane Sales Volumes" and lower propane prices which impact both sales and purchases.

Operating and Maintenance Expense — Operating and maintenance expense decreased in 2016 compared to 2015 primarily as a result of improved operating efficiencies and other cost savings initiatives.

Goodwill impairment— Goodwill impairment expense in 2015 represents impairment of our Collbran, Michigan and Southeast Texas reporting units.

Earnings from Unconsolidated Affiliates — Earnings from unconsolidated affiliates increased in 2016 compared to 2015 primarily as a result of the completion of the Keathley Canyon project at Discovery in February 2015 in our Gas Services segment and increased volumes on our Sand Hills, Southern Hills and Front Range pipelines in our NGL Logistics segment.

Net Income Attributable to Partners — Net income attributable to partners increased in 2016 compared to 2015 for the reasons set forth above.

Gross Margin — Gross margin decreased $25 million in 2016 compared to 2015 primarily as a result of the following:

• $14 million decrease for our Natural Gas Services segment primarily related to lower commodity prices, unfavorable commodity derivative activity and lower gas and NGL volumes on our Eagle Ford and East Texas systems, partially offset by growth in our DJ Basin system related to Lucerne 2 being placed into service mid-2015; and

• $14 million decrease for our Wholesale Propane Logistics segment primarily due to lower volumes as discussed below under the heading "Propane Sales Volumes" and a partial recovery of lower of cost or market inventory adjustments during the first quarter of 2015.

Results of Operations — Natural Gas Services Segment

Operating Data
	Three Months Ended June 30, 2016 (a)		Six Months Ended June 30, 2016 (a)
System	Natural Gas Throughput (MMcf/d)	NGL Production (Bbls/d)	Natural Gas Throughput (MMcf/d)	NGL Production (Bbls/d)
Eagle Ford	808	75,342	841	73,322
East Texas	506	24,855	508	24,632
DJ Basin	401	48,173	388	45,901
Discovery (b)	216	7,717	217	7,311
Other	709	13,896	729	13,981
Total	2,640	169,983	2,683	165,147

(a) Includes our share, based on our ownership percentage, of the throughput volumes and NGL production.

(b) Represents an asset operated by a third party.

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The results of operations for our Natural Gas Services segment are as follows:

		Three Months Ended June 30,						Six Months Ended June 30,						Variance Three Months 2016 vs. 2015					Variance Six Months 2016 vs. 2015
		2016			2015			2016			2015			Increase (Decrease)			Percent		Increase (Decrease)			Percent
	(Millions, except operating data)
Operating revenues:
Sales of natural gas, NGLs and condensate		$	242		$	326		$	459		$	689		$	(84	)	(26	)%	$	(230	)	(33	)%
Transportation, processing and other		79			60			158			118			19			32	%	40			34	%
(Losses) gains from commodity derivative activity		(19		)	(6		)	(10		)	13			(13		)	(217	)%	(23		)	(177	)%
Total operating revenues		302			380			607			820			(78		)	(21	)%	(213		)	(26	)%
Purchases of natural gas and NGLs		(211		)	(283		)	(405		)	(604		)	(72		)	(25	)%	(199		)	(33	)%
Operating and maintenance expense		(39		)	(43		)	(79		)	(83		)	(4		)	(9	)%	(4		)	(5	)%
Depreciation and amortization expense		(28		)	(27		)	(57		)	(53		)	1			4	%	4			8	%
Goodwill impairment		—			(49		)	—			(49		)	(49		)	(100	)%	(49		)	(100	)%
Other expense		(3		)	(1		)	(3		)	(1		)	2			200	%	2			200	%
Earnings from unconsolidated affiliates (a)		16			16			31			14			—			—	%	17			121	%
Segment net income (loss)		37			(7		)	94			44			44			*		50			114	%
Segment net income attributable to noncontrolling interests		(1		)	—			(1		)	—			1			100	%	1			100	%
Segment net income (loss) attributable to partners		$	36		$	(7	)	$	93		$	44		$	43		*		$	49		111	%
Other data:
Segment gross margin (b)		$	91		$	97		$	202		$	216		$	(6	)	(6	)%	$	(14	)	(6	)%
Non-cash commodity derivative mark-to-market		$	(36	)	$	(55	)	$	(81	)	$	(100	)	$	19		35	%	$	19		19	%
Natural gas throughput (MMcf/d) (c)		2,640			2,679			2,683			2,655			(39		)	(1	)%	28			1	%
NGL gross production (Bbls/d) (c)		169,983			156,840			165,147			153,932			13,143			8	%	11,215			7	%

_________________        

* Percentage change is not meaningful.

(a) Includes our share, based on our ownership percentage, of the earnings of all unconsolidated affiliates which include our 40% ownership of Discovery. Earnings for Discovery include the amortization of the net difference between the carrying amount of our investment and the underlying equity of the entity.

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

(c) Includes our share, based on our ownership percentage, of the throughput volumes and NGL production.

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Three Months Ended June 30, 2016 vs. Three Months Ended June 30, 2015

Total Operating Revenues — Total operating revenues decreased $78 million in 2016 compared to 2015, primarily as a result of the following:

• $38 million decrease attributable to decreased commodity prices, which impact both sales and purchases, before the impact of commodity derivative activity;

• $36 million decrease attributable to lower gas and NGL sales volumes, primarily related to production declines in our Eagle Ford and East Texas systems, which impact both sales and purchases;

• $13 million decrease as a result of commodity derivative activity attributable to a $32 million decrease in realized cash settlement gains in 2016, partially offset by a decrease in unrealized commodity derivative losses of $19 million due to movements in forward prices of commodities. Both cash settlements gains and unrealized commodity derivative losses were significantly impacted by the expiration of a substantial portion of our direct commodity hedges at the end of the first quarter of 2016; and

• $11 million decrease attributable to decreased prices related to our natural gas storage and pipeline assets at our Southeast Texas and Northern Louisiana systems;

These decreases were partially offset by:

• $19 million increase primarily as a result of higher fee revenue in our DJ Basin system related to Lucerne 2 being placed into service in mid-2015 and Grand Parkway placed into service in January 2016.

• $1 million increase attributable to increased volumes related to our natural gas storage and pipeline assets at our Northern Louisiana system partially offset by decreased volumes at our Southeast Texas system which impacts both purchases and sales.

Purchases of Natural Gas and NGLs — Purchases of natural gas and NGLs decreased $72 million in 2016 compared to 2015 as a result of decreased commodity prices and lower gas and NGL sales volumes, primarily related to our Eagle Ford and East Texas systems, which impact both sales and purchases.

Operating and Maintenance Expense — Operating and maintenance expense decreased in 2016 compared to 2015 primarily as a result of improved operating efficiencies and other cost savings initiatives.

Depreciation and Amortization Expense — Depreciation and amortization expense increased in 2016 compared to 2015 primarily as a result of growth in our business including the completion of the Lucerne 2 plant in our DJ Basin system.

Goodwill impairment— Goodwill impairment expense in 2015 represents impairment of our Collbran, Michigan and Southeast Texas reporting units.

Net Income Attributable to Partners — Net income attributable to partners increased in 2016 compared to 2015 for the reasons set forth above.

Segment Gross Margin — Segment gross margin decreased $6 million in 2016 compared to 2015, primarily as a result of the following:

• $13 million decrease as a result of commodity derivative activity as discussed above;

• $9 million decrease as a result of lower commodity prices; and

• $3 million decrease as a result of production declines in our Eagle Ford, East Texas and Southeast Texas systems.

These decreases were partially offset by:

• $19 million increase primarily as a result of higher fee revenue in our DJ Basin system related to Lucerne 2 being placed into service in mid-2015, and Grand Parkway placed into service in January 2016.

Natural Gas Throughput — Natural gas throughput decreased in 2016 compared to 2015 primarily as a result of (i) lower volumes at our Eagle Ford and East Texas systems and (ii) producer downtime at Discovery, partially offset by the completion and ramp-up of the Lucerne 2 plant in our DJ Basin system which commenced operations in June 2015.

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NGL Gross Production — NGL production increased in 2016 compared to 2015 primarily as a result of the completion and ramp-up of the Lucerne 2 plant in our DJ Basin system which commenced operations in June 2015, partially offset by lower volumes at our Eagle Ford and East Texas systems.

Six Months Ended June 30, 2016 vs. Six Months Ended June 30, 2015

Total Operating Revenues — Total operating revenues decreased $213 million in 2016 compared to 2015, primarily as a result of the following:

• $114 million decrease attributable to decreased commodity prices, which impact both sales and purchases, before the impact of commodity derivative activity;

• $82 million decrease attributable to lower gas and NGL sales volumes, primarily related to production declines in our Eagle Ford and East Texas systems, which impact both sales and purchases;

• $27 million decrease attributable to decreased prices related to our natural gas storage and pipeline assets at our Southeast Texas and Northern Louisiana systems;

• $23 million decrease as a result of commodity derivative activity attributable to a $42 million decrease in realized cash settlement gains in 2016, partially offset by a decrease in unrealized commodity derivative losses of $19 million due to movements in forward prices of commodities. Both cash settlements gains and unrealized commodity derivative losses were significantly impacted by the expiration of a substantial portion of our direct commodity hedges at the end of the first quarter of 2016; and

• $7 million decrease attributable to decreased volumes related to our natural gas storage and pipeline assets at our Southeast Texas system partially offset by increased volumes at our Northern Louisiana system which impacts both purchases and sales.

These decreases were partially offset by:

• $40 million increase primarily as a result of higher fee revenue in our DJ Basin system related to Lucerne 2 being placed into service in mid-2015, and Grand Parkway placed into service in January 2016.

Purchases of Natural Gas and NGLs — Purchases of natural gas and NGLs decreased $199 million in 2016 compared to 2015 as a result of decreased commodity prices and lower gas and NGL sales volumes, primarily related to our Eagle Ford and East Texas systems, and decreased volumes at our natural gas storage and pipeline assets, which impact both sales and purchases.

Operating and Maintenance Expense — Operating and maintenance expense decreased in 2016 compared to 2015 primarily as a result of improved operating efficiencies and other cost savings initiatives.

Depreciation and Amortization Expense — Depreciation and amortization expense increased in 2016 compared to 2015 primarily as a result of growth in our business including the completion of the Lucerne 2 plant in our DJ Basin system.

Goodwill impairment— Goodwill impairment expense in 2015 represents impairment of our Collbran, Michigan and Southeast Texas reporting units.

Earnings from Unconsolidated Affiliates — Earnings from unconsolidated affiliates increased in 2016 compared to 2015 primarily as a result of the completion of the Keathley Canyon project at Discovery in February 2015.

Net Income Attributable to Partners — Net income attributable to partners increased in 2016 compared to 2015 for the reasons set forth above.

Segment Gross Margin — Segment gross margin decreased $14 million in 2016 compared to 2015, primarily as a result of the following:

• $24 million decrease as a result of lower commodity prices;

• $23 million decrease as a result of commodity derivative activity as discussed above; and

• $7 million decrease as a result of lower gas and NGL volumes primarily related to our Eagle Ford, East Texas and Southeast systems.

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These decreases were partially offset by:

• $40 million increase primarily as a result of higher fee revenue in our DJ Basin system related to Lucerne 2 being placed into service in mid-2015, and Grand Parkway placed into service in January 2016.

Natural Gas Throughput — Natural gas throughput remained flat reflecting higher volumes primarily from (i) the completion and ramp-up of the Lucerne 2 plant in our DJ Basin system which commenced operations in June 2015 and (ii) completion and ramp-up of the Keathley Canyon project at Discovery which commenced operations in February 2015, which were partially offset by lower volumes at our Eagle Ford and East Texas systems.

NGL Gross Production — NGL production increased in 2016 compared to 2015 primarily as a result of the completion and ramp-up of the Lucerne 2 plant in our DJ Basin system which commenced operations in June 2015, partially offset by lower volumes at our Eagle Ford and East Texas systems.

Results of Operations — NGL Logistics Segment

Operating Data
	Three Months Ended June 30, 2016 (a)		Six Months Ended June 30, 2016 (a)
System	Pipeline Throughput (MBbls/d)	Fractionator Throughput (MBbls/d)	Pipeline Throughput (MBbls/d)	Fractionator Throughput (MBbls/d)
Sand Hills pipeline	82	—	76	—
Southern Hills pipeline	33	—	33	—
Texas Express pipeline (b)	14	—	14	—
Wattenberg pipeline	21	—	20	—
Front Range pipeline (b)	34	—	33	—
Black Lake pipeline	52	—	55	—
Other pipelines (c)	60	—	57	—
Mont Belvieu Enterprise fractionator (b)	—	27	—	28
Mont Belvieu 1 fractionator (b)	—	20	—	20
DJ Basin fractionators	—	11	—	11
Total	296	58	288	59

(a) Includes our share, based on our ownership percentage, of the throughput volumes and NGL production.

(b) Represents an asset operated by a third party.

(c) Includes our 15% interest in Panola and our 100% interest in Seabreeze, and Wilbreeze NGL pipelines.

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The results of operations for our NGL Logistics segment are as follows:

		Three Months Ended June 30,						Six Months Ended June 30,						Variance Three Months  2016 vs. 2015					Variance Six Months 2016 vs. 2015
		2016			2015			2016			2015			Increase (Decrease)			Percent		Increase (Decrease)		Percent
	(Millions, except operating data)
Operating revenues:
Transportation, processing and other		$	21		$	21		$	42		$	39		$	—		—	%	$	3	8	%
Total operating revenues		21			21			42			39			—			—	%	3		8	%
Operating and maintenance expense		(5		)	(6		)	(10		)	(10		)	(1		)	(17	)%	—		—	%
Depreciation and amortization expense		(2		)	(2		)	(4		)	(4		)	—			—	%	—		—	%
Earnings from unconsolidated affiliates (a)		37			28			71			53			9			32	%	18		34	%
Segment net income attributable to partners		$	51		$	41		$	99		$	78		$	10		24	%	$	21	27	%
Other data:
Segment gross margin		$	21		$	21		$	42		$	39		$	—		—	%	$	3	8	%
NGL pipelines throughput (Bbls/d) (b)		295,520			255,810			288,366			254,001			39,710			16	%	34,365		14	%
NGL fractionator throughput (Bbls/d) (b)		57,909			56,043			59,334			54,018			1,866			3	%	5,316		10	%

(a) Includes our share, based on our ownership percentage, of the earnings of all unconsolidated affiliates which include our 33.33% ownership in each of the Sand Hills and Southern Hills pipelines, 33.33% ownership of the Front Range pipeline, 20% ownership of the Mont Belvieu 1 fractionator, 15% interest in the Panola intrastate pipeline, 12.5% ownership of the Mont Belvieu Enterprise fractionator and 10% ownership of the Texas Express pipeline. Earnings for Sand Hills, Southern Hills, Front Range, Mont Belvieu 1 and Texas Express include the amortization of the net difference between the carrying amount of our investments and the underlying equity of the entities.

(b) Includes our share, based on our ownership percentage, of the throughput volumes of unconsolidated affiliates.

Three Months Ended June 30, 2016 vs. Three Months Ended June 30, 2015

Operating and Maintenance Expense— Operating and maintenance expense decreased in 2016 compared to 2015 primarily as a result of major maintenance at our NGL storage facility in 2015.

Earnings from Unconsolidated Affiliates — Earnings from unconsolidated affiliates increased in 2016 compared to 2015 primarily as a result of higher pipeline throughput volumes on Southern Hills, Sand Hills and Front Range due to growth in NGL production from new plants placed into service in 2015, higher throughput volumes on Panola commencing February 2016 and higher fractionated volumes at both of our Mont Belvieu fractionators.

NGL Pipelines Throughput — NGL pipelines throughput increased in 2016 compared to 2015 primarily as a result of higher pipeline throughput volumes on Sand Hills, Southern Hills, and Front Range, due to growth in NGL production from new plants placed into service in 2015, higher throughput volumes on Panola commencing February 2016, partially offset by decreased Black Lake short haul volumes.

Six Months Ended June 30, 2016 vs. Six Months Ended June 30, 2015

Transportation, Processing and Other — Transportation processing and other increased in 2016 compared to 2015 as a result of new connections on certain of our NGL pipelines.

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Earnings from Unconsolidated Affiliates — Earnings from unconsolidated affiliates increased in 2016 compared to 2015 primarily as a result of higher pipeline throughput volumes on Southern Hills, Sand Hills, and Front Range due to growth in NGL production from new plants placed into service in 2015, higher throughput volumes on Panola commencing February 2016 and higher fractionated volumes at both of our Mont Belvieu fractionators.

NGL Pipelines Throughput — NGL pipelines throughput increased in 2016 compared to 2015 primarily as a result of higher throughput volumes on Sand Hills, Southern Hills, Front Range, and Texas Express due to growth in NGL production from new plants placed into service in 2015, higher throughput volumes on Panola commencing February 2016 partially offset by decreased Black Lake short haul volumes.

NGL Fractionators Throughput — NGL fractionators throughput increased in 2016 compared to 2015 as a result of higher volumes due to maintenance at our Mont Belvieu fractionators in the first quarter of 2015.

Results of Operations — Wholesale Propane Logistics Segment

The results of operations for our Wholesale Propane Logistics segment are as follows:

		Three Months Ended June 30,						Six Months Ended June 30,						Variance Three Months 2016 vs 2015					Variance Six Months 2016 vs. 2015
		2016			2015			2016			2015			Increase (Decrease)			Percent		Increase (Decrease)			Percent
	(Millions, except operating data)
Operating revenues:
Sales of propane		$	22		$	26		$	72		$	133		$	(4	)	(15	)%	$	(61	)	(46	)%
Storage, transportation and other		4			3			7			6			1			33	%	1			17	%
Losses from commodity derivative activity		(1		)	—			(1		)	—			(1		)	(100	)%	(1		)	(100	)%
Total operating revenues		25			29			78			139			(4		)	(14	)%	(61		)	(44	)%
Purchases of propane		(20		)	(23		)	(57		)	(104		)	(3		)	(13	)%	(47		)	(45	)%
Operating and maintenance expense		(1		)	(2		)	(4		)	(5		)	(1		)	(50	)%	(1		)	(20	)%
Depreciation and amortization expense		—			—			(1		)	(1		)	—			—	%	—			—	%
Segment net income attributable to partners		$	4		$	4		$	16		$	29		$	—		—	%	$	(13	)	(45	)%
Other data:
Segment gross margin (a)		$	5		$	6		$	21		$	35		$	(1	)	(17	)%	$	(14	)	(40	)%
Non-cash commodity derivative mark-to-market		$	(1	)	$	—		$	(1	)	$	3		$	(1	)	(100	)%	$	(4	)	*
Propane sales volume (Bbls/d)		9,897			10,420			15,351			20,517			(523		)	(5	)%	(5,166		)	(25	)%

_________________        

* Percentage change is not meaningful.

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

Three Months Ended June 30, 2016 vs. Three Months Ended June 30, 2015

Total Operating Revenues — Total operating revenues decreased by $4 million in 2016 compared to 2015, primarily as a result of the following:

• $2 million decrease attributable to lower propane prices which impact both sales and purchases;

• $1 million decrease attributable to decreased volumes; and

• $1 million decrease in commodity derivative activity attributable to an increase in unrealized commodity derivative losses of $1 million due to movements in forward prices of commodities.

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Purchases of Propane — Purchases of propane decreased in 2016 compared to 2015 primarily due to lower propane prices which impact both sales and purchases.

Net Income Attributable to Partners — Net income attributable to partners remained constant in 2016 compared to 2015 for the reasons set forth above.

Segment Gross Margin — Segment gross margin remained relatively flat in 2016 compared to 2015.

Six Months Ended June 30, 2016 vs. Six Months Ended June 30, 2015

Total Operating Revenues — Total operating revenues decreased by $61 million in 2016 compared to 2015, primarily as a result of the following:

• $35 million decrease attributable to decreased volumes as discussed below under the heading "Propane Sales Volumes"; and

• $25 million decrease attributable to lower propane prices which impact both sales and purchases.

• $1 million decrease as a result of commodity derivative activity attributable to a $3 million decrease in realized cash settlement losses in 2016, partially offset by a decrease in unrealized commodity derivative gains of $4 million due to movements in forward prices of commodities.

Purchases of Propane — Purchases of propane decreased in 2016 compared to 2015 primarily due to decreased volumes as discussed below under the heading "Propane Sales Volumes" and lower propane prices which impact both sales and purchases.

Net Income Attributable to Partners — Net income attributable to partners decreased in 2016 compared to 2015 for the reasons set forth above.

Segment Gross Margin — Segment gross margin decreased in 2016 compared to 2015 primarily due to higher 2015 volumes as discussed below under the heading "Propane Sales Volumes" and a partial recovery of lower of cost or market inventory adjustments during the first quarter of 2015.

Propane Sales Volumes — Propane sales volumes decreased in 2016 compared to 2015 primarily due to lower demand associated with warmer weather in 2016.

Liquidity and Capital Resources

We expect our sources of liquidity to include:

• cash generated from operations;

• cash distributions from our unconsolidated affiliates;

• borrowings under our Amended and Restated Credit Agreement;

• debt offerings;

• issuance of additional common units, including issuances we may make to DCP Midstream, LLC;

• borrowings under term loans; and

• letters of credit.

We anticipate our more significant uses of resources to include:

• quarterly distributions to our unitholders and general partner;

• growth capital expenditures;

• payments to service our debt;

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

• business and asset acquisitions, including transactions with DCP Midstream, LLC; and

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• collateral with counterparties to our swap contracts to secure potential exposure under these contracts, which may, at times, be significant depending on commodity price movements, and letters of credit we have posted.

We believe that cash generated from these sources will be sufficient to meet our short-term working capital requirements, long-term capital expenditure and acquisition requirements, and quarterly cash distributions for the next twelve months.

We routinely evaluate opportunities for strategic investments or acquisitions. Future material investments or acquisitions may require that we obtain additional capital, assume third party debt or incur other long-term obligations. We have the option to utilize both equity and debt instruments as vehicles for the long-term financing of our investment activities and acquisitions.

Based on current and anticipated levels of operations, we believe we have adequate committed financial resources to conduct our ongoing business, although deterioration in our operating environment could limit our borrowing capacity, further impact our credit ratings, raise our financing costs, as well as impact our compliance with our financial covenant requirements under the Amended and Restated Credit Agreement and the indentures governing our notes.

In May 2014, we entered into the Amended and Restated Credit Agreement, a $1.25 billion amended and restated senior unsecured revolving credit agreement that matures on May 1, 2019. Our borrowing capacity may be limited by the Amended and Restated Credit Agreement’s financial covenant requirements. Except in the case of a default, which would make the borrowings under the Amended and Restated Credit Agreement fully callable, amounts borrowed under the Amended and Restated Credit Agreement will not mature prior to the May 1, 2019 maturity date. Further, our cost of borrowing under the Amended and Restated Credit Agreement is determined by a ratings-based pricing grid. In the first quarter of 2015, our credit rating was lowered below investment grade. As a result of this ratings action, interest rates under the Amended and Restated Credit Agreement increased. As of June 30, 2016, there was $316 million outstanding on the revolving credit facility under the Amended and Restated Credit Agreement. We had unused revolver capacity of $933 million, net of letters of credit, under the Amended and Restated Credit Agreement, all of which was available for general working capital purposes. As of July 29, 2016, we had $125 million of outstanding borrowings on the revolving credit facility and had approximately $1,125 million of unused borrowing capacity under the Amended and Restated Credit Agreement.

In April 2015, we filed a new shelf registration statement with the SEC, that became effective upon filing, in order to replace an existing shelf registration statement that was set to expire. As with the prior shelf registration statement, the new shelf registration statement also allows us to issue an unlimited amount of common units and debt securities. We have issued no common units or debt securities under this registration statement.

During the six months ended June 30, 2016, we issued no common units pursuant to our 2014 equity distribution agreement. As of June 30, 2016, approximately $349 million of common units remained available for sale pursuant to our 2014 equity distribution agreement.

Changes in natural gas, NGL and condensate prices and the terms of our processing arrangements have a direct impact on our generation and use of cash from operations due to their impact on net income, along with the resulting changes in working capital. We have mitigated a portion of our anticipated commodity price risk associated with the equity volumes from our gathering and processing activities through 2017 with fixed price commodity swaps. For additional information regarding our derivative activities, please read Item 3. "Quantitative and Qualitative Disclosures about Market Risk" contained herein.

The counterparties to the majority of our commodity swap contracts are investment-grade rated financial institutions. Under these contracts, we may be required to provide collateral to the counterparties in the event that our potential payment exposure exceeds a predetermined collateral threshold. Collateral thresholds are set by us and each counterparty, as applicable, in the master contract that governs our financial transactions based on our and the counterparty’s assessment of creditworthiness. The assessment of our position with respect to the collateral thresholds are determined on a counterparty by counterparty basis, and are impacted by the representative forward price curves and notional quantities under our swap contracts. Due to the interrelation between the representative crude oil and natural gas forward price curves, it is not practical to determine a pricing point at which our swap contracts will meet the collateral thresholds as we may transact multiple commodities with the same counterparty. Depending on daily commodity prices, the amount of collateral posted can go up or down on a daily basis.

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

We had a working capital excess of $107 million and $106 million as of June 30, 2016 and December 31, 2015, respectively. The change in working capital is primarily attributable to the reclassification of assets held for sale, and the factors described above. We had net derivative working capital of $9 million as of June 30, 2016 as compared to $87 million as of December 31, 2015. We expect that our future working capital requirements will be impacted by these same recurring factors.

As of June 30, 2016, we had $1 million in cash and cash equivalents, all of which was held by consolidated subsidiaries we do not wholly own.

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

	Six Months Ended June 30,
	2016			2015
	(Millions)
Net cash provided by operating activities	$	320		$	350
Net cash used in investing activities	$	(17	)	$	(240	)
Net cash used in financing activities	$	(304	)	$	(111	)

Six Months Ended June 30, 2016 vs. Six Months Ended June 30, 2015

Operating Activities — Net cash provided by operating activities decreased $30 million in 2016 compared to 2015 primarily as a result of the following:

•$40 million decrease in cash attributable to higher net income in 2016, after adjusting our net income for non-cash items;

•$30 million decrease in cash attributable to the timing of cash receipts and disbursements related to operations; and

•$40 millionincrease in cash distributions from unconsolidated affiliates primarily due to increased earnings. For additional information regarding fluctuations in our earnings from unconsolidated affiliates, please read "Results of Operations".

Investing Activities — Net cash used in investing activities decreased $223 million in 2016 compared to 2015 primarily as a result of the following:

•$177 million decrease in capital expenditures attributable to the Lucerne 2 plant which started construction in April 2014 and was placed into service at the end of the second quarter of 2015, and the Grand Parkway gathering project which began construction in the first quarter of 2015 and was completed in the first quarter of 2016;

•$30 million decrease in cash contributions to our unconsolidated affiliates. In the six months ended June 30, 2015, we primarily made contributions to the Keathley Canyon project at Discovery and to the expansion projects at our Sand Hills pipeline. In the six months ended June 30, 2016, we primarily made contributions to the expansion projects at our Sand Hills pipeline and the construction of our Panola pipeline; and

•$16 million increase in deposits received from the sale of our Northern Louisiana system assets.

Financing Activities — Net cash used in financing activities increased $193 million in 2016 compared to 2015 primarily as a result of the following:

•$159 million decrease in net debt borrowings;

•$31 million decrease in proceeds from the issuance of common units to the public. We issued no common units to the public during the six months ended June 30, 2016 as compared to approximately 1 million common units that were issued during the six months ended June 30, 2015;

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•$1 million increase in net distributions to noncontrolling interests primarily due to Collbran.

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

• maintenance capital expenditures, which are cash expenditures to maintain our cash flows, operating or earnings capacity. These expenditures add on to or improve capital assets owned, including certain system integrity, compliance and safety improvements. Maintenance capital expenditures also include certain well connects, and may include the acquisition or construction of new capital assets; and

• expansion capital expenditures, which are cash expenditures to increase our cash flows, operating or earnings capacity. Expansion capital expenditures include acquisitions or capital improvements (where we add on to or improve the capital assets owned, or acquire or construct new gathering lines and well connects, treating facilities, processing plants, fractionation facilities, pipelines, terminals, docks, truck racks, tankage and other storage, distribution or transportation facilities and related or similar midstream assets).

We incur capital expenditures for our consolidated entities and our unconsolidated affiliates. We anticipate maintenance capital expenditures of between $30 million and $45 million, and approved expansion capital expenditures of between $75 million and $150 million, for the year ending December 31, 2016. Expansion capital expenditures include the expansion of the Sand Hills pipeline, expansion of the Panola pipeline, which will be shown as an investment in unconsolidated affiliates in our condensed consolidated statements of cash flows and the completion of the construction of the Grand Parkway gathering project.

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

	Six Months Ended June 30, 2016						Six Months Ended June 30, 2015
	Maintenance Capital Expenditures		Expansion Capital Expenditures		Total Consolidated Capital Expenditures		Maintenance Capital Expenditures		Expansion Capital Expenditures		Total Consolidated Capital Expenditures
	(Millions)
Our portion	$	3	$	14	$	17	$	15	$	178	$	193
Noncontrolling interest portion and reimbursable projects (a)	—		—		—		1		—		1
Total	$	3	$	14	$	17	$	16	$	178	$	194

(a) Represents the noncontrolling interest and reimbursable portion of our capital expenditures. We have entered into agreements with third parties whereby we will be reimbursed for certain expenditures. Depending on the timing of these payments, we may be reimbursed prior to incurring the capital expenditure.

In addition, we invested cash in unconsolidated affiliates of $16 million and $46 million during the six months ended June 30, 2016 and 2015, respectively, to fund our share of capital expansion projects.

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

We expect to fund future capital expenditures with funds generated from our operations, borrowings under our Amended and Restated Credit Agreement, the issuance of additional partnership units and the issuance of long-term debt.

Cash Distributions to Unitholders — Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all Available Cash, as defined in the partnership agreement. We made cash distributions to our unitholders and general partner of $242 million and $241 million during the six months ended June 30, 2016 and 2015, respectively. We intend to continue making quarterly distribution payments to our unitholders and general partner to the extent we have sufficient cash from operations after the establishment of reserves.

We expect to continue to use cash provided by operating activities for the payment of distributions to our unitholders and general partner. See Note 11. "Partnership Equity and Distributions" in the Notes to Consolidated Financial Statements in Item 1. “Financial Statements.”

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Total Contractual Cash Obligations and Off-Balance Sheet Obligations

A summary of our total contractual cash obligations as of June 30, 2016, is as follows:

	Payments Due by Period
	Total		Less than 1 year		1-3 years		3-5 years		Thereafter
	(Millions)
Debt (a)	$	3,302	$	80	$	1,283	$	118	$	1,821
Operating lease obligations (b)	82		17		30		21		14
Purchase obligations (c)	75		70		2		—		3
Other long-term liabilities (d)	35		—		1		4		30
Total	$	3,494	$	167	$	1,316	$	143	$	1,868

(a) Includes interest payments on debt securities that have been issued. These interest payments are $80 million, $142 million, $118 million, and $572 million for less than one year, one to three years, three to five years, and thereafter, respectively.

(b) Our operating lease obligations are contractual obligations and include railcar leases, which provide supply and storage infrastructure for our Wholesale Propane Logistics business, and natural gas storage in our Northern Louisiana system and a firm transportation commitment within our Natural Gas Services business.

(c) Our purchase obligations are contractual obligations and include purchase orders and non-cancelable construction agreements for capital expenditures, various non-cancelable commitments to purchase physical quantities of propane supply for our Wholesale Propane Logistics business and other items. For contracts where the price paid is based on an index or other market-based rates, the amount is based on the forward market prices or current market rates as of June 30, 2016. Purchase obligations exclude accounts payable, accrued interest payable and other current liabilities recognized in the condensed consolidated balance sheets. Purchase obligations also exclude current and long-term unrealized losses on derivative instruments included in the condensed consolidated balance sheet, which represent the current fair value of various derivative contracts and do not represent future cash purchase obligations. These contracts may be settled financially at the difference between the future market price and the contractual price and may result in cash payments or cash receipts in the future, but generally do not require delivery of physical quantities of the underlying commodity. In addition, many of our gas purchase contracts include short and long-term commitments to purchase produced gas at market prices. These contracts, which have no minimum quantities, are excluded from the table.

(d) Other long-term liabilities include $27 million of asset retirement obligations of which an insignificant amount may be settled within the next five years, $4 million of gas purchase liability, $3 million of right of way liability and $1 million of environmental reserves recognized in the June 30, 2016 condensed consolidated balance sheet. In addition, $8 million of deferred state income taxes were excluded from the table above as the amount and timing of any payments are not subject to reasonable estimation.

As of June 30, 2016, we have no items that were classified as off-balance sheet obligations.

Reconciliation of Non-GAAP Measures

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

We define gross margin as total operating revenues, including commodity derivative activity, less purchases of natural gas, propane and NGLs, and we define segment gross margin for each segment as total operating revenues, including commodity derivative activity, for that segment less commodity purchases for that segment. Our gross margin equals the sum of our segment gross margins. Gross margin and segment gross margin are primary performance measures used by management, as these measures represent the results of product sales and purchases, a key component of our operations. As an indicator of our operating performance, gross margin and segment gross margin should not be considered an alternative to, or more meaningful than, operating revenues, net income or loss, net income or loss attributable to partners, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with accounting principles generally accepted in the United States of America, or GAAP.

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Adjusted EBITDA — We define adjusted EBITDA as net income or loss attributable to partners less interest income, noncontrolling interest in depreciation and income tax expense and non-cash commodity derivative gains, plus interest expense, income tax expense, depreciation and amortization expense, non-cash commodity derivative losses and certain other items. Our adjusted EBITDA may not be comparable to a similarly titled measure of another company because other entities may not calculate this measure in the same manner.

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

Adjusted EBITDA is used as a supplemental liquidity and performance measure and adjusted segment EBITDA is used as a supplemental performance measure by our management and by external users of our financial statements, such as investors, commercial banks, research analysts and others to assess:

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

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

• viability and performance of acquisitions and capital expenditure projects and the overall rates of return on investment opportunities; and

• in the case of Adjusted EBITDA, the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness, make cash distributions to our unitholders and general partner, and finance maintenance capital expenditures.

Adjusted Segment EBITDA — We define adjusted segment EBITDA for each segment as segment net income or loss attributable to partners plus or minus adjustments for non-cash mark-to-market of commodity derivative instruments for that segment, plus depreciation and amortization expense and certain other items for that segment, adjusted for any noncontrolling interest portion of depreciation, amortization and income tax expense for that segment. Our adjusted segment EBITDA may not be comparable to similarly titled measures of other companies because they may not calculate adjusted segment EBITDA in the same manner.

Adjusted segment EBITDA should not be considered in isolation or as an alternative to our financial measures presented in accordance with GAAP, including operating revenues, net income or loss attributable to partners, or any other measure of performance presented in accordance with GAAP.

Our gross margin, segment gross margin, adjusted EBITDA and adjusted segment EBITDA may not be comparable to a similarly titled measure of another company because other entities may not calculate these measures in the same manner. The accompanying schedules provide reconciliations of gross margin, segment gross margin and adjusted segment EBITDA to its most directly comparable GAAP financial measure.

Distributable Cash Flow — We define Distributable Cash Flow as net cash provided by or used in operating activities, less maintenance capital expenditures, net of reimbursable projects, plus or minus adjustments for non-cash mark-to-market of derivative instruments, net income attributable to noncontrolling interest net of depreciation and income tax, net changes in operating assets and liabilities, other adjustments to reconcile net cash provided by or used in operating activities, and certain other items. Maintenance capital expenditures are cash expenditures made to maintain our cash flows, operating or earnings capacity. These expenditures add on to or improve capital assets owned, including certain system integrity, compliance and safety improvements. Maintenance capital expenditures also include certain well connects, and may include the acquisition or construction of new capital assets. Non-cash mark-to-market of derivative instruments is considered to be non-cash for the purpose of computing Distributable Cash Flow because settlement will not occur until future periods, and will be impacted by future changes in commodity prices and interest rates. We compare the distributable cash flow we generate to the cash distributions we expect to pay our partners. Using this metric, we compute our distribution coverage ratio. Distributable Cash Flow is used as a supplemental liquidity and performance measure by our management and by external users of our financial statements, such as investors, commercial banks, research analysts and others, to assess our ability to make cash distributions to our unitholders and our general partner.

Our Distributable Cash Flow may not be comparable to a similarly titled measure of another company because other entities may not calculate Distributable Cash Flow in the same manner.

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
Reconciliation of Non-GAAP Measures	(Millions)
Reconciliation of net income attributable to partners to gross margin:
Net income attributable to partners	$	45		$	(2	)	$	117		$	67
Interest expense	24			22			48			44
Income tax expense	1			(4		)	1			(3		)
Operating and maintenance expense	45			51			93			98
Depreciation and amortization expense	30			29			62			58
General and administrative expense	21			22			42			43
Goodwill impairment	—			49			—			49
Other expense	3			1			3			1
Earnings from unconsolidated affiliates	(53		)	(44		)	(102		)	(67		)
Net income attributable to noncontrolling interests	1			—			1			—
Gross margin	$	117		$	124		$	265		$	290
Non-cash commodity derivative mark-to-market (a)	$	(37	)	$	(55	)	$	(82	)	$	(97	)
Reconciliation of segment net income attributable to partners to segment gross margin:
Natural Gas Services segment:
Segment net income attributable to partners	$	36		$	(7	)	$	93		$	44
Operating and maintenance expense	39			43			79			83
Depreciation and amortization expense	28			27			57			53
Goodwill impairment	—			49			—			49
Other expense	3			1			3			1
Earnings from unconsolidated affiliates	(16		)	(16		)	(31		)	(14		)
Net income attributable to noncontrolling interests	1			—			1			—
Segment gross margin	$	91		$	97		$	202		$	216
Non-cash commodity derivative mark-to-market (a)	$	(36	)	$	(55	)	$	(81	)	$	(100	)
NGL Logistics segment:
Segment net income attributable to partners	$	51		$	41		$	99		$	78
Operating and maintenance expense	5			6			10			10
Depreciation and amortization expense	2			2			4			4
Earnings from unconsolidated affiliates	(37		)	(28		)	(71		)	(53		)
Segment gross margin	$	21		$	21		$	42		$	39
Wholesale Propane Logistics segment:
Segment net income attributable to partners	$	4		$	4		$	16		$	29
Operating and maintenance expense	1			2			4			5
Depreciation and amortization expense	—			—			1			1
Segment gross margin	$	5		$	6		$	21		$	35
Non-cash commodity derivative mark-to-market (a)	$	(1	)	$	—		$	(1	)	$	3

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

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	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
	(Millions)
Reconciliation of net income attributable to partners to adjusted segment EBITDA:
Natural Gas Services segment:
Segment net income attributable to partners (a)	$	36		$	(7	)	$	93		$	44
Non-cash commodity derivative mark-to-market	36			55			81			100
Depreciation and amortization expense	28			27			57			53
Goodwill impairment	—			49			—			49
Noncontrolling interest portion of depreciation and income tax	(1		)	—			(1		)	(1		)
Other charges	3			—			3			—
Adjusted segment EBITDA	$	102		$	124		$	233		$	245
NGL Logistics segment:
Segment net income attributable to partners	$	51		$	41		$	99		$	78
Depreciation and amortization expense	2			2			4			4
Adjusted segment EBITDA	$	53		$	43		$	103		$	82
Wholesale Propane Logistics segment:
Segment net income attributable to partners (b)	$	4		$	4		$	16		$	29
Non-cash commodity derivative mark-to-market	1			—			1			(3		)
Depreciation and amortization expense	—			—			1			1
Adjusted segment EBITDA	$	5		$	4		$	18		$	27

(a) There were no lower of cost or market adjustments for the three months ended June 30, 2016, and $3 million for the six months ended June 30, 2016. Includes $3 million in the lower of cost or market adjustments for both the three and six months ended June 30, 2015.

(b) Includes no lower of cost or market adjustments for the three and six months ended June 30, 2016, respectively, and $1 million and $2 million for the three and six months ended June 30, 2015, respectively.

Item 3.Quantitative and Qualitative Disclosures about Market Risk

For an in-depth discussion of our market risks, see "Item 7A. Quantitative and Qualitative Disclosures about Market Risk" in our Annual Report on Form 10-K for the year ended December 31, 2015.

The following tables set forth additional information about our fixed price swaps used to mitigate a portion of our natural gas and NGL price risk associated with our percent-of-proceeds arrangements and our condensate price risk associated with our gathering operations. Our positions as of July 29, 2016 were as follows:

Commodity Swaps

Period	Commodity	Notional Volume - Short Positions		Reference Price	Price Range
July 2016 — December 2016	Natural Gas	(5,000) MMBtu/d	(c)	NYMEX Final Settlement Price (b)	$4.18/MMBtu
January 2017 — December 2017	Natural Gas	(17,500) MMBtu/d	(c)	NYMEX Final Settlement Price (b)	$4.17 - $4.27/MMBtu
July 2016 — December 2016	Crude Oil	(4,000) Bbls/d	(d)	Asian-pricing of NYMEX crude oil futures (a)	$65.50 - $101.30/Bbl

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

(b) NYMEX final settlement price for natural gas futures contracts.

(c) Affiliate volumes.

(d) Third party volumes.

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Our sensitivities for 2016 as shown in the table below are estimated based on our average estimated commodity price exposure and commodity cash flow protection activities for the calendar year 2016, and exclude the impact from non-cash mark-to-market on our commodity derivatives. We utilize direct product crude oil, natural gas and NGL derivatives to mitigate a portion of our condensate, natural gas and NGL commodity price exposure. These sensitivities are associated with our unhedged condensate, natural gas and NGL volumes.

Commodity Sensitivities Excluding Non-Cash Mark-To-Market

	Per Unit Decrease		Unit of Measurement	Estimated Decrease in Annual Net Income Attributable to Partners
				(Millions)
Natural gas prices	$	0.10	MMBtu	$	1
Crude oil prices	$	1.00	Barrel	$	—
NGL prices	$	0.01	Gallon	$	1

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

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

We estimate the following non-cash sensitivities for 2016 related to the mark-to-market on our commodity derivatives associated with our commodity cash flow protection activities:

Non-Cash Mark-To-Market Commodity Sensitivities

	Per Unit Increase		Unit of Measurement	Estimated Mark-to- Market Impact (Decrease in Net Income Attributable to Partners)
				(Millions)
Natural gas prices	$	0.10	MMBtu	$	1
Crude oil prices	$	1.00	Barrel	$	1
NGL prices	$	0.01	Gallon	$	—

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

The midstream natural gas industry is cyclical, with the operating results of companies in the industry significantly affected by the prevailing price of NGLs, which in turn has been generally related to the price of crude oil. Although the prevailing price of residue natural gas has less short-term significance to our operating results than the price of NGLs, in the long-term the growth and sustainability of our business depends on natural gas prices being at levels sufficient to provide incentives and capital for producers to increase natural gas exploration and production. To minimize potential future commodity-based pricing and cash flow volatility, we have entered into a series of derivative financial instruments. As a result of these transactions, we have mitigated a portion of our expected commodity price risk relating to the equity volumes associated with our gathering and processing activities through 2017.

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

Natural Gas Storage and Pipeline Asset Based Commodity Derivative Program — Our natural gas storage and pipeline assets are exposed to certain risks including changes in commodity prices. We manage commodity price risk related to our natural gas storage and pipeline assets through our commodity derivative program. The commercial activities related to our natural gas storage and pipeline assets primarily consist of the purchase and sale of gas and associated time spreads and basis spreads.

A time spread transaction is executed by establishing a long gas position at one point in time and establishing an equal short gas position at a different point in time. Time spread transactions allow us to lock in a margin supported by the injection, withdrawal, and storage capacity of our natural gas storage assets. We may execute basis spread transactions to mitigate the risk of sale and purchase price differentials across our system. A basis spread transaction allows us to lock in a margin on our physical purchases and sales of gas, including injections and withdrawals from storage. We typically use swaps to execute these transactions, which are not designated as hedging instruments and are recorded at fair value with changes in fair value recorded in the current period condensed consolidated statements of operations. While gas held in our storage locations is recorded at the lower of average cost or market, the derivative instruments that are used to manage our storage facilities are recorded at fair value and any changes in fair value are currently recorded in our condensed consolidated statements of operations. Even though we may have economically hedged our exposure and locked in a future margin, the use of lower-of-cost-or-market accounting for our physical inventory and the use of mark-to-market accounting for our derivative instruments may subject our earnings to market volatility.

The following tables set forth additional information about our derivative instruments used to mitigate a portion of our natural gas price risk associated with our Southeast Texas storage operations as of June 30, 2016:

Inventory

Period ended	Commodity	Notional Volume -  Long Positions	Fair Value (millions)		Weighted Average Price
June 30, 2016	Natural Gas	11,607,460 MMBtu	$	21	$1.85/MMBtu

Commodity Swaps

Period	Commodity	Notional Volume  -(Short)/Long Positions	Fair Value (millions)			Price Range
July 2016-April 2017	Natural Gas	(30,560,000) MMBtu	$	(18	)	$2.02 - $3.34/MMBtu
July 2016-October 2017	Natural Gas	18,320,000 MMBtu	$	7		$2.08 - $3.23/MMBtu

Item 4.Controls and Procedures

Evaluation of Disclosure Controls and Procedures

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports that we file or submit to the SEC under the Securities Exchange Act of 1934, as amended, or the Exchange Act, is recorded, processed, summarized and reported within the time periods specified by the SEC’s rules and forms, and that information is accumulated and communicated to the management of our general partner, including our general partner’s principal executive and principal financial officers (whom we refer to as the "Certifying Officers"), as appropriate to allow timely decisions regarding required disclosure. The management of our general partner evaluated, with the participation of the

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Certifying Officers, the effectiveness of our disclosure controls and procedures as of June 30, 2016, pursuant to Rule 13a-15(b) under the Exchange Act. Based upon that evaluation, the Certifying Officers concluded that, as of June 30, 2016, our disclosure controls and procedures were effective at a reasonable assurance level.

Changes in Internal Control Over Financial Reporting

There were no changes in internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during the quarter ended June 30, 2016 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1.Legal Proceedings

The information required for this item is provided in “Commitments and Contingent Liabilities,” included in Note 17 in Item 8 of our Annual Report on Form 10-K for the year ended December 31, 2015 and Note 13 in Item 1 of this Quarterly Report on Form 10-Q.

Item 1A. Risk Factors

In addition to the other information set forth in this report, careful consideration should be given to the risk factors discussed in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2015. An investment in our securities involves various risks. When considering an investment in us, you should consider carefully all of the risk factors described below and in our Annual Report on Form 10-K for the year ended December 31, 2015.

Item 6. Exhibits

Exhibit Number		Description
3.1	*	Amended and Restated Limited Liability Company Agreement of DCP Midstream GP, LLC dated December 7, 2005, as amended by Amendment No. 1 dated January 20, 2009 (attached as Exhibit 3.1 to DCP Midstream Partners, LP’s Annual Report on Form 10-K (File No. 001-32678) filed with the SEC on March 5, 2009).
3.2	*	Amendment No. 2 to Amended and Restated Limited Liability Company Agreement of DCP Midstream GP, LLC dated February 14, 2013 (attached as Exhibit 3.1 to DCP Midstream Partners, LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC on February 21, 2013).
3.3	*	Amendment No. 3 to Amended and Restated Limited Liability Company Agreement of DCP Midstream GP, LLC dated November 6, 2013 (attached as Exhibit 3.3 to DCP Midstream Partners, LP’s Quarterly Report on Form 10-Q (File No. 001-32678) filed with the SEC on November 6, 2013).
3.4	*	First Amended and Restated Agreement of Limited Partnership of DCP Midstream GP, LP dated December 7, 2005 (attached as Exhibit 3.2 to DCP Midstream Partners, LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC on December 12, 2005).
3.5	*	Second Amended and Restated Agreement of Limited Partnership of DCP Midstream Partners, LP dated November 1, 2006 (attached as Exhibit 3.1 to DCP Midstream Partners, LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC on November 7, 2006).
3.6	*	Amendment No. 1 to Second Amended and Restated Agreement of Limited Partnership of DCP Midstream Partners, LP dated April 11, 2008 (attached as Exhibit 4.1 to DCP Midstream Partners, LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC on April 14, 2008).
3.7	*	Amendment No. 2 to Second Amended and Restated Agreement of Limited Partnership of DCP Midstream Partners, LP dated April 1, 2009 (attached as Exhibit 3.1 to DCP Midstream Partners, LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC on April 7, 2009).
10.1	*+	DCP Midstream Partners, LP 2016 Long-Term Incentive Plan dated April 28, 2016 (attached as Exhibit A to DCP Midstream Partners, LP's Definitive Proxy Statement on Schedule 14A (File No. 001-32678) filed with the SEC on March 15, 2016).
12.1		Computation of Ratio of Earnings to Fixed Charges.
31.1		Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1		Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2		Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101		Financial statements from the Quarterly Report on Form 10-Q of DCP Midstream Partners, LP for the three and six months ended June 30, 2016, formatted in XBRL: (i) the Condensed Consolidated Balance Sheets, (ii) the Condensed Consolidated Statements of Operations, (iii) the Condensed Consolidated Statements of Comprehensive Income, (iv) the Condensed Consolidated Statements of Cash Flows, (v) the Condensed Consolidated Statements of Changes in Equity, and (vi) the Notes to the Condensed Consolidated Financial Statements.

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

+    Denotes management contract or compensatory plan or arrangement.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	DCP Midstream Partners, LP
	By:	DCP Midstream GP, LP its General Partner
	By:	DCP Midstream GP, LLC its General Partner
Dated: August 4, 2016	By:	/s/ Wouter T. van Kempen
		Name:	Wouter T. van Kempen
		Title:	Chief Executive Officer and President
			(Principal Executive Officer)
Dated: August 4, 2016	By:	/s/ Sean P. O'Brien
		Name:	Sean P. O'Brien
		Title:	Group Vice President and Chief Financial Officer
			(Principal Financial Officer)

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EXHIBIT INDEX

Exhibit Number		Description
3.1	*	Amended and Restated Limited Liability Company Agreement of DCP Midstream GP, LLC dated December 7, 2005, as amended by Amendment No. 1 dated January 20, 2009 (attached as Exhibit 3.1 to DCP Midstream Partners, LP’s Annual Report on Form 10-K (File No. 001-32678) filed with the SEC on March 5, 2009).
3.2	*	Amendment No. 2 to Amended and Restated Limited Liability Company Agreement of DCP Midstream GP, LLC dated February 14, 2013 (attached as Exhibit 3.1 to DCP Midstream Partners, LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC on February 21, 2013).
3.3	*	Amendment No. 3 to Amended and Restated Limited Liability Company Agreement of DCP Midstream GP, LLC dated November 6, 2013 (attached as Exhibit 3.3 to DCP Midstream Partners, LP’s Quarterly Report on Form 10-Q (File No. 001-32678) filed with the SEC on November 6, 2013).
3.4	*	First Amended and Restated Agreement of Limited Partnership of DCP Midstream GP, LP dated December 7, 2005 (attached as Exhibit 3.2 to DCP Midstream Partners, LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC on December 12, 2005).
3.5	*	Second Amended and Restated Agreement of Limited Partnership of DCP Midstream Partners, LP dated November 1, 2006 (attached as Exhibit 3.1 to DCP Midstream Partners, LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC on November 7, 2006).
3.6	*	Amendment No. 1 to Second Amended and Restated Agreement of Limited Partnership of DCP Midstream Partners, LP dated April 11, 2008 (attached as Exhibit 4.1 to DCP Midstream Partners, LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC on April 14, 2008).
3.7	*	Amendment No. 2 to Second Amended and Restated Agreement of Limited Partnership of DCP Midstream Partners, LP dated April 1, 2009 (attached as Exhibit 3.1 to DCP Midstream Partners, LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC on April 7, 2009).
10.1	*+	DCP Midstream Partners, LP 2016 Long-Term Incentive Plan dated April 28, 2016 (attached as Exhibit A to DCP Midstream Partners, LP's Definitive Proxy Statement on Schedule 14A (File No. 001-32678) filed with the SEC on March 15, 2016).
12.1		Computation of Ratio of Earnings to Fixed Charges.
31.1		Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1		Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2		Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101		Financial statements from the Quarterly Report on Form 10-Q of DCP Midstream Partners, LP for the three and six months ended June 30, 2016, formatted in XBRL: (i) the Condensed Consolidated Balance Sheets, (ii) the Condensed Consolidated Statements of Operations, (iii) the Condensed Consolidated Statements of Comprehensive Income, (iv) the Condensed Consolidated Statements of Cash Flows, (v) the Condensed Consolidated Statements of Changes in Equity, and (vi) the Notes to the Condensed Consolidated Financial Statements.

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

+    Denotes management contract or compensatory plan or arrangement.

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