Attached files

file filename
EX-31.2 - EXHIBIT 31.2 - DCP Midstream, LPdpm-20150630xexhibit312.htm
EX-12.1 - EXHIBIT 12.1 - DCP Midstream, LPdpm-20150630xexhibit121.htm
EX-32.2 - EXHIBIT 32.2 - DCP Midstream, LPdpm-20150630xexhibit322.htm
EX-31.1 - EXHIBIT 31.1 - DCP Midstream, LPdpm-20150630xexhibit311.htm
EX-32.1 - EXHIBIT 32.1 - DCP Midstream, LPdpm-20150630xexhibit321.htm
XML - IDEA: XBRL DOCUMENT - DCP Midstream, LPR9999.htm
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, 2015
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) 633-2900 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. 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
¨
 
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 31, 2015, there were outstanding 114,738,148 common units representing limited partner interests.





DCP MIDSTREAM PARTNERS, LP
FORM 10-Q FOR THE QUARTER ENDED JUNE 30, 2015
TABLE OF CONTENTS
 
 
 
 
Item
 
Page
 
PART I. FINANCIAL INFORMATION
 
1.
Financial Statements (unaudited):
 
 
Condensed Consolidated Balance Sheets as of June 30, 2015 and December 31, 2014
 
Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2015 and 2014
 
Condensed Consolidated Statements of Comprehensive Income for the Three and Six Months Ended June 30, 2015 and 2014
 
Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2015 and 2014
 
Condensed Consolidated Statement of Changes in Equity for the Six Months Ended June 30, 2015
 
Condensed Consolidated Statement of Changes in Equity for the Six Months Ended June 30, 2014
 
Notes to the Condensed Consolidated Financial Statements
2.
Management's Discussion and Analysis of Financial Condition and Results of Operations
3.
Quantitative and Qualitative Disclosures about Market Risk
4.
Controls and Procedures
 
PART II. OTHER INFORMATION
 
1.
Legal Proceedings
1A.
Risk Factors
6.
Exhibits
 
Signatures
 
Exhibit Index
 


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, 2014, 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;
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 our debt securities, as well as our ability to maintain our credit ratings;
the amount of collateral we may be required to post from time to time in our transactions;
volatility in the price of our common units;
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;
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 execute our risk management programs to continue the safe and reliable operation of our assets;
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;
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;
the creditworthiness of our customers and the counterparties to our transactions;
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;
the amount of gas we gather, compress, treat, process, transport, sell and store, or the NGLs we produce, fractionate, transport and store, 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; and
industry changes, including the impact of consolidations, alternative energy sources, technological advances and changes in competition.
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, 
 2015
 
December 31, 
 2014
 
(Millions)
ASSETS
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
24

 
$
25

Accounts receivable:
 
 
 
Trade, net of allowance for doubtful accounts of $1 million
74

 
106

Affiliates
91

 
164

Inventories
39

 
63

Unrealized gains on derivative instruments
131

 
230

Other
2

 
2

Total current assets
361

 
590

Property, plant and equipment, net
3,474

 
3,347

Goodwill
105

 
154

Intangible assets, net
115

 
120

Investments in unconsolidated affiliates
1,485

 
1,459

Unrealized gains on derivative instruments
15

 
39

Other long-term assets
28

 
30

Total assets
$
5,583

 
$
5,739

LIABILITIES AND EQUITY
 
 
 
Current liabilities:
 
 
 
Accounts payable:
 
 
 
Trade
109

 
$
196

Affiliates
19

 
27

Current maturities of long-term debt
250

 
250

Unrealized losses on derivative instruments
18

 
43

Other
94

 
85

Total current liabilities
490

 
601

Long-term debt
2,162

 
2,061

Other long-term liabilities
48

 
51

Total liabilities
2,700

 
2,713

Commitments and contingent liabilities

 

Equity:
 
 
 
Limited partners (114,738,148 and 113,949,868 common units issued and outstanding, respectively)
2,842

 
2,984

General partner
18

 
18

Accumulated other comprehensive loss
(8
)
 
(9
)
Total partners’ equity
2,852

 
2,993

Noncontrolling interests
31

 
33

Total equity
2,883

 
3,026

Total liabilities and equity
$
5,583

 
$
5,739

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,
 
2015
 
2014
 
2015
 
2014
 
(Millions, except per unit amounts)
Operating revenues:
 
 
 
 
 
 
 
Sales of natural gas, propane, NGLs and condensate
$
108

 
$
206

 
$
297

 
$
577

Sales of natural gas, propane, NGLs and condensate to affiliates
244

 
548

 
525

 
1,190

Transportation, processing and other
59

 
55

 
115

 
106

Transportation, processing and other to affiliates
25

 
25

 
48

 
57

Losses from commodity derivative activity, net
(5
)
 
(11
)
 

 
(14
)
(Losses) gains from commodity derivative activity, net — affiliates
(1
)
 
(11
)
 
13

 
(23
)
Total operating revenues
430

 
812

 
998

 
1,893

Operating costs and expenses:
 
 
 
 
 
 
 
Purchases of natural gas, propane and NGLs
277

 
622

 
644

 
1,407

Purchases of natural gas, propane and NGLs from affiliates
29

 
54

 
64

 
154

Operating and maintenance expense
51

 
56

 
98

 
101

Depreciation and amortization expense
29

 
28

 
58

 
54

General and administrative expense
3

 
3

 
6

 
8

General and administrative expense — affiliates
19

 
12

 
37

 
23

Goodwill impairment
49

 

 
49

 

Other expense
1

 

 
1

 
1

Total operating costs and expenses
458

 
775

 
957

 
1,748

Operating (loss) income
(28
)
 
37

 
41

 
145

Interest expense
(22
)
 
(23
)
 
(44
)
 
(42
)
Earnings from unconsolidated affiliates
44

 
16

 
67

 
19

(Loss) income before income taxes
(6
)
 
30

 
64

 
122

Income tax benefit (expense)
4

 
(1
)
 
3

 
(4
)
Net (loss) income
(2
)
 
29

 
67

 
118

Net income attributable to noncontrolling interests

 

 

 
(10
)
Net (loss) income attributable to partners
(2
)
 
29

 
67

 
108

Net income attributable to predecessor operations

 

 

 
(6
)
General partner’s interest in net income
(31
)
 
(27
)
 
(62
)
 
(53
)
Net (loss) income allocable to limited partners
$
(33
)
 
$
2

 
$
5

 
$
49

Net (loss) income per limited partner unit — basic and diluted
$
(0.29
)
 
$
0.02

 
$
0.04

 
$
0.49

Weighted-average limited partner units outstanding — basic and diluted
114.7

 
108.4

 
114.5

 
100.9

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,
 
2015
 
2014
 
2015
 
2014
 
(Millions)
Net (loss) income
$
(2
)
 
$
29

 
$
67

 
$
118

Other comprehensive income:
 
 
 
 
 
 
 
Reclassification of cash flow hedge losses into earnings

 

 
1

 
2

Total other comprehensive income

 

 
1

 
2

Total comprehensive (loss) income
(2
)
 
29

 
68

 
120

Total comprehensive income attributable to noncontrolling interests

 

 

 
(10
)
Total comprehensive (loss) income attributable to partners
$
(2
)
 
$
29

 
$
68

 
$
110

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,
 
2015
 
2014
 
(Millions)
OPERATING ACTIVITIES:
 
 
 
Net income
$
67

 
$
118

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Depreciation and amortization expense
58

 
54

Earnings from unconsolidated affiliates
(67
)
 
(19
)
Distributions from unconsolidated affiliates
87

 
40

Net unrealized losses on derivative instruments
98

 
43

Goodwill impairment
49

 

Other, net
2

 
7

Change in operating assets and liabilities, which provided (used) cash, net of effects of acquisitions:
 
 
 
Accounts receivable
102

 
26

Inventories
24

 
35

Accounts payable
(86
)
 
(19
)
Accrued interest

 
9

Other current assets and liabilities
12

 
7

Other long-term assets and liabilities
4

 
(1
)
Net cash provided by operating activities
350

 
300

INVESTING ACTIVITIES:
 
 
 
Capital expenditures
(194
)
 
(151
)
Acquisitions, net of cash acquired

 
(102
)
Acquisition of unconsolidated affiliates

 
(669
)
Investments in unconsolidated affiliates
(46
)
 
(93
)
Proceeds from sales of assets

 
17

Net cash used in investing activities
(240
)
 
(998
)
FINANCING ACTIVITIES:
 
 
 
Proceeds from long-term debt
450

 
719

Payments of long-term debt
(350
)
 

Payments of commercial paper, net

 
(335
)
Payments of deferred financing costs

 
(9
)
Excess purchase price over acquired interests

 
(15
)
Proceeds from issuance of common units, net of offering costs
31

 
787

Net change in advances to predecessor from DCP Midstream, LLC

 
(6
)
Distributions to limited partners and general partner
(241
)
 
(192
)
Distributions to noncontrolling interests
(2
)
 
(11
)
Purchase of additional interest in a subsidiary

 
(198
)
Contributions from noncontrolling interests

 
3

Contributions from DCP Midstream, LLC
1

 

Net cash (used in) provided by financing activities
(111
)
 
743

Net change in cash and cash equivalents
(1
)
 
45

Cash and cash equivalents, beginning of period
25

 
12

Cash and cash equivalents, end of period
$
24

 
$
57

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) 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.


5


DCP MIDSTREAM PARTNERS, LP
CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
(Unaudited)
 
Partners’ Equity
 
 
 
 
 
Predecessor
Equity
 
Limited 
Partners
 
General 
Partner
 
Accumulated 
Other
Comprehensive
(Loss) Income
 
Noncontrolling
Interests
 
Total
Equity
 
(Millions)
Balance, January 1, 2014
$
40

 
$
1,948

 
$
8

 
$
(11
)
 
$
228

 
$
2,213

Net income
6

 
49

 
53

 

 
10

 
118

Other comprehensive income

 

 

 
2

 

 
2

Net change in parent advances
(6
)
 

 

 

 

 
(6
)
Acquisition of Lucerne 1 plant
(40
)
 

 

 

 

 
(40
)
Issuance of 4,497,158 units to DCP Midstream, LLC and affiliates

 
225

 

 

 

 
225

Excess purchase price over carrying value of interests acquired in March 2014 Transactions

 
(170
)
 

 

 

 
(170
)
Issuance of 16,386,000 common units to the public

 
787

 

 

 

 
787

Distributions to limited partners and general partner

 
(145
)
 
(47
)
 

 

 
(192
)
Distributions to noncontrolling interests

 

 

 

 
(11
)
 
(11
)
Contributions from noncontrolling interests

 

 

 

 
3

 
3

Purchase of additional interest in a subsidiary

 

 

 

 
(198
)
 
(198
)
Balance, June 30, 2014
$

 
$
2,694

 
$
14

 
$
(9
)
 
$
32

 
$
2,731

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, 2015 and 2014
(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 15 - 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. 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 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 not misleading. Results of operations for the three and six months ended June 30, 2015 are not necessarily indicative of the results that may be expected for the year ending December 31, 2015. 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 2014 audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2014.

2. New Accounting Pronouncements

Financial Accounting Standards Board, or FASB, Accounting Standards Update, or ASU, 2015-11 “Inventory (Topic 330): Simplifying the Measurement of Inventory,” or ASU 2015-11 - In July 2015, the FASB issued ASU 2015-11, which requires an entity to measure in scope inventory at the lower of cost and net realizable value. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. The amendments apply to inventory that is measured using first-in, first-out (FIFO) or average cost. This ASU is effective for interim and annual reporting periods beginning after December 15, 2016, with the option to early adopt as of the beginning of an annual or interim period. We do not expect the adoption of this ASU to have a significant impact on our financial position, results of operations and cash flows.


7

DCP MIDSTREAM PARTNERS, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three and Six Months Ended June 30, 2015 and 2014 - (Continued)
(Unaudited)

Financial Accounting Standards Board, or FASB, Accounting Standards Update, or ASU, 2015-06 “Earnings Per Share (Topic 260): Effects on Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions,” or ASU 2015-06 - In April 2015, the FASB issued ASU 2015-06, which specifies that for purposes of calculating historical earnings per unit under the two-class method, the earnings or losses of a transferred business before the date of a dropdown transaction should be allocated entirely to the general partner. In that circumstance, the previously reported earnings per unit of the limited partners, which is typically the earnings per unit measure presented in the financial statements, would not change as a result of the dropdown transaction. This ASU is effective for annual and interim reporting periods beginning after December 15, 2015 and is required to be applied retrospectively. The adoption of this ASU will have no impact on our condensed consolidated results of operations as we have not historically changed previously reported earnings per limited partner unit as a result of dropdown transactions.

FASB ASU 2015-03 “Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Cost,” or ASU 2015-03 - In April 2015, the FASB issued ASU 2015-03, which requires debt issuance costs to be presented in the balance sheet as a direct deduction from the associated debt liability. This ASU is effective for annual reporting periods beginning after December 15, 2015, after which we will present debt issuance costs as a direct reduction from debt on our condensed consolidated balance sheets for all periods presented. The adoption of this ASU will have no impact on our condensed consolidated results of operations and cash flows.

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 and we are currently assessing the impact of adoption of this ASU 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 - In May 2014, the FASB issued ASU 2014-09, which supersedes the revenue recognition requirements of Accounting Standards Codification, or ASC, 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. Acquisitions
On January 1, 2015, we entered into an agreement with an affiliate of Enterprise Products Partners L.P., or Enterprise, to acquire a 15% ownership interest in Panola Pipeline Company, LLC, or Panola. At closing, we paid $1 million for our interest in the joint venture. The anticipated total consideration of approximately $26 million includes our proportionate share in construction costs for an anticipated expansion of the existing Panola NGL pipeline. The Panola NGL pipeline originates in Carthage, Texas and extends approximately 180 miles to Mont Belvieu, Texas. The expansion will extend the Panola NGL pipeline approximately 60 miles and increase capacity from approximately 50 MBbls/d to 100 MBbls/d. We, WGR Asset Holding Company LLC, which is an affiliate of Anadarko Petroleum Corporation, and MarkWest Panola Pipeline L.L.C. will each own a 15% interest in Panola. Enterprise will own a 55% interest in Panola and will construct the expansion and operate the pipeline. In accordance with the joint venture agreement, we will not participate in the earnings of the Panola pipeline until the expansion is complete, which is expected to be in service in the first quarter of 2016.
 
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 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

8

DCP MIDSTREAM PARTNERS, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three and Six Months Ended June 30, 2015 and 2014 - (Continued)
(Unaudited)

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.
On February 23, 2015, the annual fee payable under the Services Agreement was increased by approximately $25 million to $71 million, following approval of the increase by the special committee of the board of directors of the General Partner. Our growth, both from organic growth and acquisitions, has resulted in the Partnership becoming a much larger portion of the business of DCP Midstream, LLC. Additionally, our expansion into downstream logistics has required DCP Midstream, LLC to expand its capabilities and provide us with a broader range of services than what was previously provided. As a result, DCP Midstream, LLC initiated a comprehensive review of its costs and the methodology for allocating general and administrative services. The result of this review reflects the level and cost of general and administrative services provided to us by DCP Midstream, LLC as the operator of our assets. The annual fee was effective starting January 1, 2015.

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,
 
 
2015
 
2014
 
2015
 
2014
 
 
(Millions)
Services Agreement
 
$
18

 
$
12

 
$
36

 
$
19

Other fees — DCP Midstream, LLC
 
1

 

 
1

 
4

Total — DCP Midstream, LLC
 
$
19

 
$
12

 
$
37

 
$
23

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 $1 million for each of the three and six months ended June 30, 2015, and less than $1 million for the three months ended June 30, 2014. The Eagle Ford system incurred $4 million in general and administrative expenses directly from DCP Midstream, LLC for the six months ended June 30, 2014, before the reallocation of the Eagle Ford system to the Services Agreement on March 31, 2014.
Other Agreements and Transactions with DCP Midstream, LLC
As a result of assets contributed to us by DCP Midstream, LLC, we have previously entered into derivative transactions directly with DCP Midstream, LLC whereby DCP Midstream, LLC was the counterparty. In March 2015, DCP Midstream, LLC novated those fixed price derivatives and our counterparty is now one of the financial institutions associated with our credit facility. Accordingly, the counterparties to the majority of our commodity swap contracts are investment-grade rated financial institutions.
In conjunction with our acquisition of the O'Connor and Lucerne 1 plants, we entered into long-term fee-based processing agreements with DCP Midstream, LLC pursuant to which DCP Midstream, LLC agreed to pay us (i) a fixed demand charge on a portion of the plants' capacities, and (ii) a throughput fee on all volumes processed for DCP Midstream, LLC at the plants. We report revenues associated with these activities in the condensed consolidated statements of operations as transportation, processing and other to affiliates. Under these agreements in our DJ Basin system we received fees of $13 million and $25 million during the three and six months ended June 30, 2015, respectively, and $12 million and $19 million during the three and six months ended June 30, 2014, respectively.

Spectra Energy

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

9

DCP MIDSTREAM PARTNERS, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three and Six Months Ended June 30, 2015 and 2014 - (Continued)
(Unaudited)

Summary of Transactions with Affiliates
The following table summarizes our transactions with affiliates:
 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
 
2015
 
2014
 
2015
 
2014
 
 
(Millions)
DCP Midstream, LLC:
 
 
 
 
 
 
 
 
Sales of natural gas, propane, NGLs and condensate
 
$
244

 
$
548

 
$
525

 
$
1,190

Transportation, processing and other
 
$
25

 
$
25

 
$
48

 
$
43

Purchases of natural gas, propane and NGLs
 
$
17

 
$
32

 
$
42

 
$
112

(Losses) gains from commodity derivative activity, net
 
$
(1
)
 
$
(11
)
 
$
13

 
$
(23
)
General and administrative expense
 
$
19

 
$
12

 
$
37

 
$
23

Spectra Energy:
 
 
 
 
 
 
 
 
Purchases of natural gas, propane and NGLs
 
$
12

 
$
22

 
$
22

 
$
42

Transportation, processing and other
 
$

 
$

 
$

 
$
14

 
We had balances with affiliates as follows:
 
June 30, 
 2015
 
December 31, 
 2014
 
(Millions)
DCP Midstream, LLC:
 
 
 
Accounts receivable
$
91

 
$
163

Accounts payable
$
15

 
$
24

Unrealized gains on derivative instruments — current
$
14

 
$
207

Unrealized gains on derivative instruments — long-term
$
6

 
$
25

Unrealized losses on derivative instruments — current
$
18

 
$
43

Spectra Energy:
 
 
 
Accounts receivable
$

 
$
1

Accounts payable
$
4

 
$
3


5. Inventories
Inventories were as follows: 
 
June 30, 
 2015
 
December 31, 
 2014
 
(Millions)
Natural gas
$
31

 
$
36

NGLs
8

 
27

Total inventories
$
39

 
$
63

We recognize 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 $1 million and $5 million in lower of cost or market adjustments during the three and six months ended June 30, 2015, respectively. We recognized no lower of cost or market adjustments during the three months ended June 30, 2014, and $3 million in lower of cost or market adjustments during the six months ended June 30, 2014.

10

DCP MIDSTREAM PARTNERS, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three and Six Months Ended June 30, 2015 and 2014 - (Continued)
(Unaudited)

6. Property, Plant and Equipment
A summary of property, plant and equipment by classification is as follows:
 
Depreciable
Life
 
June 30, 
 2015
 
December 31, 
 2014
 
 
 
(Millions)
Gathering and transmission systems
20 — 50 Years
 
$
2,270

 
$
2,209

Processing, storage, and terminal facilities
35 — 60 Years
 
2,296

 
2,071

Other
3 —  30 Years
 
56

 
50

Construction work in progress
 
 
169

 
281

Property, plant and equipment
 
 
4,791

 
4,611

Accumulated depreciation
 
 
(1,317
)
 
(1,264
)
Property, plant and equipment, net
 
 
$
3,474

 
$
3,347

Interest capitalized on construction projects for each of the three months ended June 30, 2015 and 2014 was $2 million and for the six months ended June 30, 2015 and 2014 was $5 million and $3 million, respectively.
Depreciation expense was $27 million and $26 million for the three months ended June 30, 2015 and 2014, respectively, and $53 million and $50 million for the six months ended June 30, 2015 and 2014, respectively.

7. Goodwill
Goodwill is the cost of an acquisition less the fair value of the net assets of the acquired business. We perform an annual impairment test of goodwill in the third quarter, and update the test during interim periods when we believe events or changes in circumstances indicate that we may not be able to recover the carrying value of a reporting unit. During the three months ended June 30, 2015, we determined that continued weak commodity prices caused a change in circumstances warranting an interim impairment test.
We perform our goodwill assessment at the reporting unit level. We primarily used a discounted cash flow analysis, supplemented by a market approach analysis, to perform the assessment. Key assumptions in the analysis include the use of an appropriate discount rate, volume forecasts, terminal year multiples, and estimated future cash flows including an estimate of operating and general and administrative costs. In estimating cash flows, we incorporate current market information, as well as historical and other factors, into our forecasted commodity prices.
Using the fair value approaches described above, in step one of the goodwill impairment test, we determined that the estimated fair value of our Collbran, Michigan and Southeast Texas reporting units was less than their carrying amount, primarily due to changes in assumptions related to commodity prices and discount rate.
The second step of the goodwill impairment test involves allocating the estimated fair value of the reporting unit among all of the assets and liabilities of the reporting unit in a hypothetical purchase price allocation. We will complete the second step of the goodwill impairment test in the third quarter of 2015 due to the timing of completing the hypothetical purchase price allocation. However, we consider a goodwill impairment loss probable for our Collbran, Michigan and Southeast Texas reporting units, all of which are included in our Natural Gas Services reporting segment, and have therefore recorded our best estimate of the impairment during the three months ended June 30, 2015, totaling $49 million, which is included in goodwill impairment in the condensed consolidated statements of operations. Upon completion of the second step of the goodwill impairment test during the third quarter, any adjustment to the estimated impairment will be recognized.
We concluded that the fair value of goodwill of our remaining reporting units exceeded their carrying value, and the entire amount of goodwill disclosed on the condensed consolidated balance sheet associated with these remaining reporting units is recoverable, therefore, no other goodwill impairments were identified or recorded for the remaining reporting units as a result of our interim goodwill assessment.
Our impairment determinations involved significant assumptions and judgments, as discussed above. Differing assumptions regarding any of these inputs could have a significant effect on the various valuations. If actual results are not consistent with our assumptions and estimates, or our assumptions and estimates change due to new information, we may be exposed to additional goodwill impairment charges, which would be recognized in the period in which the carrying value exceeds fair value. A continuing prolonged period of lower commodity prices may adversely affect our estimate of future

11

DCP MIDSTREAM PARTNERS, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three and Six Months Ended June 30, 2015 and 2014 - (Continued)
(Unaudited)

operating results, which could result in future goodwill impairment charges for other reporting units due to the potential impact on our operations and cash flows.
The change in carrying amount of goodwill in each of our reporting segments is as follows:
 
 
Three Months Ended June 30,
 
 
2015
 
2014
 
 
Gas Services
 
NGL Logistics
 
Wholesale Propane Logistics
 
Gas Services
 
NGL Logistics
 
Wholesale Propane Logistics
 
 
(Millions)
Balance, beginning of period
 
$
82

 
$
35

 
$
37

 
$
82

 
$
35

 
$
37

Impairment
 
(49
)
 

 

 

 

 

Balance, end of period
 
$
33

 
$
35

 
$
37

 
$
82

 
$
35

 
$
37

 
 
Six Months Ended June 30,
 
 
2015
 
2014
 
 
Gas Services
 
NGL Logistics
 
Wholesale Propane Logistics
 
Gas Services
 
NGL Logistics
 
Wholesale Propane Logistics
 
 
(Millions)
Balance, beginning of period
 
$
82

 
$
35

 
$
37

 
$
82

 
$
35

 
$
37

Impairment
 
(49
)
 

 

 

 

 

Balance, end of period
 
$
33

 
$
35

 
$
37

 
$
82

 
$
35

 
$
37



8. Investments in Unconsolidated Affiliates
The following table summarizes our investments in unconsolidated affiliates:
 
 
 
 
Carrying Value as of
 
Percentage
Ownership
 
June 30, 
 2015
 
December 31, 
 2014
 
 
 
(Millions)
DCP Sand Hills Pipeline, LLC
33.33%
 
$
442

 
$
413

Discovery Producer Services LLC
40%
 
403

 
406

DCP Southern Hills Pipeline, LLC
33.33%
 
323

 
329

Front Range Pipeline LLC
33.33%
 
170

 
169

Texas Express Pipeline LLC
10%
 
97

 
98

Mont Belvieu Enterprise Fractionator
12.5%
 
23

 
23

Mont Belvieu 1 Fractionator
20%
 
12

 
14

Other
Various
 
15

 
7

Total investments in unconsolidated affiliates
 
 
$
1,485

 
$
1,459


12

DCP MIDSTREAM PARTNERS, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three and Six Months Ended June 30, 2015 and 2014 - (Continued)
(Unaudited)

Earnings (losses) from investments in unconsolidated affiliates were as follows:
 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2015
 
2014
 
2015
 
2014
 
(Millions)
DCP Sand Hills Pipeline, LLC
$
14

 
$
6

 
$
25

 
$
6

Discovery Producer Services LLC
16

 

 
14

 
(1
)
Front Range Pipeline LLC
3

 
(1
)
 
7

 
(2
)
Mont Belvieu Enterprise Fractionator
4

 
4

 
8

 
8

DCP Southern Hills Pipeline, LLC
4

 
4

 
7

 
4

Texas Express Pipeline LLC
1

 

 
3

 

Mont Belvieu 1 Fractionator
2

 
3

 
3

 
4

Total earnings from unconsolidated affiliates
$
44

 
$
16

 
$
67

 
$
19

The following tables summarize the combined financial information of our investments in unconsolidated affiliates:
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2015
 
2014
 
2015
 
2014
 
(Millions)
Statements of operations (a):
 
 
 
 
 
 
 
Operating revenue
$
300

 
$
208

 
$
533

 
$
319

Operating expenses
$
145

 
$
132

 
$
274

 
$
214

Net income
$
155

 
$
76

 
$
258

 
$
105

 
 
June 30, 
 2015
 
December 31, 
 2014
 
(Millions)
Balance sheets (a):
 
 
 
Current assets
$
199

 
$
207

Long-term assets
5,277

 
5,157

Current liabilities
(204
)
 
(200
)
Long-term liabilities
(242
)
 
(164
)
Net assets
$
5,030

 
$
5,000

(a) In accordance with the Panola joint venture agreement, earnings do not accrue to our interest until the expansion of the pipeline is complete. Accordingly, we will not include activity related to Panola in the above tables until the period in which the expansion is complete and earnings accrue to our interest.

9. 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.

13

DCP MIDSTREAM PARTNERS, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three and Six Months Ended June 30, 2015 and 2014 - (Continued)
(Unaudited)

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.
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 11 - Risk Management and Hedging Activities.
Valuation Hierarchy
Our fair value measurements are grouped into a three-level valuation hierarchy. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date. The three levels are defined as follows.
Level 1 — inputs are unadjusted quoted prices for identical assets or liabilities in active markets.
Level 2 — inputs include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.
Level 3 — inputs are unobservable and considered significant to the fair value measurement.
A financial instrument’s categorization within the hierarchy is based upon the 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.

14

DCP MIDSTREAM PARTNERS, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three and Six Months Ended June 30, 2015 and 2014 - (Continued)
(Unaudited)

Within our Natural Gas Services segment, we typically use OTC derivative contracts in order to mitigate a portion of our exposure to natural gas, NGL and condensate price changes. We also may enter into natural gas derivatives to lock in margin around our storage and transportation assets. These instruments are generally classified as Level 2. Depending upon market conditions and our strategy, we may enter into OTC derivative positions with a significant time horizon to maturity, and market prices for these OTC derivatives may only be readily observable for a portion of the duration of the instrument. In order to calculate the fair value of these instruments, readily observable market information is utilized to the extent that it is available; however, in the event that readily observable market data is not available, we may interpolate or extrapolate based upon observable data. In instances where we utilize an interpolated or extrapolated value, and it is considered significant to the valuation of the contract as a whole, we would classify the instrument within Level 3.
Within our Wholesale Propane Logistics segment, we may enter into a variety of financial instruments to either secure sales or purchase prices, or capture a variety of market opportunities. Since financial instruments for NGLs tend to be counterparty and location specific, we primarily use the OTC derivative instrument markets, which are not as active and liquid as exchange traded instruments. Market quotes for such contracts may only be available for short dated positions (up to six months), and an active market itself may not exist beyond such time horizon. Contracts entered into with a relatively short time horizon for which prices are readily observable in the OTC market are generally classified within Level 2. Contracts with a longer time horizon, for which we internally generate a forward curve to value such instruments, are generally classified within Level 3. The internally generated curve may utilize a variety of assumptions including, but not limited to, 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 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.
During the three months ended June 30, 2015, we recognized a goodwill impairment of $49 million in our condensed consolidated statements of operations. Our impairment determinations involved significant assumptions and judgments. Differing assumptions regarding any of these inputs could have a significant effect on the various valuations. As such, the fair value measurements utilized within these models are classified as non-recurring Level 3 measurements in the fair value hierarchy because they are not observable from objective sources.


15

DCP MIDSTREAM PARTNERS, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three and Six Months Ended June 30, 2015 and 2014 - (Continued)
(Unaudited)

The following table presents the financial instruments carried at fair value as of June 30, 2015 and December 31, 2014, by condensed consolidated balance sheet caption and by valuation hierarchy, as described above:
 
 
June 30, 2015
 
December 31, 2014
 
Level 1
 
Level 2
 
Level 3
 
Total
Carrying
Value
 
Level 1
 
Level 2
 
Level 3
 
Total
Carrying
Value
 
(Millions)
Current assets:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity derivatives (a)
$

 
$
48

 
$
83

 
$
131

 
$

 
$
92

 
$
138

 
$
230

Short-term investments (b)
$
20

 
$

 
$

 
$
20

 
$
24

 
$

 
$

 
$
24

Long-term assets (c):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity derivatives
$

 
$
15

 
$

 
$
15

 
$

 
$
21

 
$
18

 
$
39

Current liabilities (d):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity derivatives
$

 
$
(18
)
 
$

 
$
(18
)
 
$

 
$
(43
)
 
$

 
$
(43
)
 
(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.
 
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, 2015 and 2014, 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.


16

DCP MIDSTREAM PARTNERS, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three and Six Months Ended June 30, 2015 and 2014 - (Continued)
(Unaudited)

 
Commodity Derivative Instruments
 
Current
Assets
 
Long-
Term
Assets
 
Current
Liabilities
 
Long-
Term
Liabilities
 
(Millions)
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
)
 
$

 
$

 
$

Three months ended June 30, 2014 (a):
 
 
 
 
 
 
 
Beginning balance
$
70

 
$
60

 
$
(1
)
 
$

Net unrealized gains (losses) included in earnings (b)
13

 
(22
)
 

 

Settlements
(18
)
 

 
1

 

Ending balance
$
65

 
$
38

 
$

 
$

Net unrealized gains (losses) on derivatives still held included in earnings (b)
$
13

 
$
(22
)
 
$

 
$


 
Commodity Derivative Instruments
 
Current
Assets
 
Long-
Term
Assets
 
Current
Liabilities
 
Long-
Term
Liabilities
 
(Millions)
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
)
 
$

 
$

Six months ended June 30, 2014 (a):
 
 
 
 
 
 
 
Beginning balance
$
65

 
$
75

 
$

 
$

Net unrealized gains (losses) included in earnings (b)
29

 
(37
)
 

 

Settlements
(29
)
 

 

 

Ending balance
$
65

 
$
38

 
$

 
$

Net unrealized gains (losses) on derivatives still held included in earnings (b)
$
31

 
$
(37
)
 
$

 
$

 
(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, 2015 and 2014.
(b)
Represents the amount of total gains or losses for the period, included in gains or losses from commodity derivative activity, net.

17

DCP MIDSTREAM PARTNERS, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three and Six Months Ended June 30, 2015 and 2014 - (Continued)
(Unaudited)

Quantitative Information and Fair Value Sensitivities Related to Level 3 Unobservable Inputs
We utilize the market approach to measure the fair value of our commodity contracts. The significant unobservable inputs used in this approach to fair value are longer dated price quotes. Our sensitivity to these longer dated forward curve prices are presented in the table below. Significant changes in any of those inputs in isolation would result in significantly different fair value measurements, depending on our short or long position in contracts.
 
 
June 30, 2015
 
 
Product Group
Fair Value
 
Forward
Curve Range
 
 
 
(Millions)
 
 
Assets
 
 
 
 
 
NGLs
$
83

 
$0.20-$1.26
 
Per gallon


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.
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, 2015 and December 31, 2014, 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:

18

DCP MIDSTREAM PARTNERS, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three and Six Months Ended June 30, 2015 and 2014 - (Continued)
(Unaudited)

 
 
June 30, 2015
 
December 31, 2014
 
 
Carrying Value
 
Fair Value
 
Carrying Value
 
Fair Value
 
(Millions)
 
 
 
 
 
 
 
 
 
Senior Notes
 
$
2,312

 
$
2,207

 
$
2,311

 
$
2,334

Amended and Restated Credit Agreement
 
$
100

 
$
100

 
$

 
$

10. Debt
 
June 30, 
 2015
 
December 31, 
 2014
 
(Millions)
Amended and Restated Credit Agreement
 
 
 
Revolving credit facility, weighted-average variable interest rate of 1.64%, as of June 30, 2015, due May 1, 2019
$
100

 
$

Debt Securities
 
 
 
Issued September 30, 2010, interest at 3.25% payable semi-annually, due October 1, 2015
250

 
250

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 discount
(13
)
 
(14
)
Total debt
2,412

 
2,311

Current maturities of long-term debt
(250
)
 
(250
)
Total long-term debt
$
2,162

 
$
2,061

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 will be 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 1.45% 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 0.45% based on our current credit rating. The Amended and Restated Credit Agreement incurs an annual facility fee of 0.30% 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, 2015, we had unused capacity of $1,149 million, net of letters of credit, under the Amended and Restated Credit Agreement, all of which was available for general working capital purposes. Our borrowing capacity may be limited by financial covenant requirements 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.

19

DCP MIDSTREAM PARTNERS, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three and Six Months Ended June 30, 2015 and 2014 - (Continued)
(Unaudited)

The future maturities of long-term debt in the year indicated are as follows:
 
Debt
Maturities
 
(Millions)
2016
$

2017
500

2018

2019
425

2020

Thereafter
1,250

 
2,175

Unamortized discount
(13
)
Total
$
2,162


11. 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, with the majority of our positions settling through the first quarter of 2016. 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 and costless collars 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; however, a significant amount of our NGL hedges from 2015 through 2016 are direct product hedges. 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. We also utilize crude oil costless collars that minimize our floating price risk by establishing a fixed price floor and a fixed price ceiling. However, the type of instrument that we use to mitigate a portion of our risk may vary depending upon our risk management objective. These transactions are not designated as hedging instruments for accounting purposes and the change in fair value is reflected within our condensed consolidated statements of operations as a gain or a loss on commodity derivative activity.
 
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

20

DCP MIDSTREAM PARTNERS, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three and Six Months Ended June 30, 2015 and 2014 - (Continued)
(Unaudited)

with both physical and financial transactions, including fixed price sales. While the majority of our sales and purchases in this segment are index-based, occasionally, we may enter into fixed price sales agreements in the event that a 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.
As a result of assets contributed to us by DCP Midstream, LLC, we have previously entered into derivative transactions directly with DCP Midstream, LLC whereby DCP Midstream, LLC was the counterparty. In March 2015, DCP Midstream, LLC novated those fixed price derivatives and our counterparty is now one of the financial institutions associated with our credit facility. Accordingly, the counterparties to the majority of our commodity swap contracts are investment-grade rated financial institutions.
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, 2015.

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.
In conjunction with the issuance of our 4.95% Senior Notes in March 2012, we entered into forward-starting interest rate swap agreements to reduce our exposure to market rate fluctuations prior to issuance. These derivative financial instruments

21

DCP MIDSTREAM PARTNERS, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three and Six Months Ended June 30, 2015 and 2014 - (Continued)
(Unaudited)

were designated as cash flow hedges. While the cash paid upon settlement of these hedges economically fixed the rate we would pay on a portion of our 4.95% Senior Notes, the deferred loss in AOCI will be amortized into interest expense through the maturity of the notes in 2022. The balance in AOCI of these cash flow hedges was in a loss position of $3 million as of June 30, 2015.
Contingent Credit Features
Each of the above risks is managed through the execution of individual contracts with a variety of counterparties. Certain of our derivative contracts may contain credit-risk related contingent provisions that may require us to take certain actions in certain circumstances.
We have International 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.
Certain of our ISDA counterparties would have the right to reduce our collateral threshold to zero, potentially 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, 2015, 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, 2015, 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, 2015, 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:
 

22

DCP MIDSTREAM PARTNERS, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three and Six Months Ended June 30, 2015 and 2014 - (Continued)
(Unaudited)

 
June 30, 2015
 
December 31, 2014
 
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
$
146

 
$
(13
)
 
$
133

 
$
269

 
$
(42
)
 
$
227

Liabilities:
 
 
 
 
 
 
 
 
 
 
 
Commodity derivatives
$
(18
)
 
$
13

 
$
(5
)
 
$
(43
)
 
$
42

 
$
(1
)
 
(a)
There is no cash collateral pledged or received against these positions.
 
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, 2015 and December 31, 2014.
 
Balance Sheet Line Item
June 30, 
 2015
 
December 31, 
 2014
 
Balance Sheet Line Item
 
June 30, 
 2015
 
December 31, 
 2014
 
(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
$
131

 
$
230

 
Unrealized losses on derivative instruments — current
 
$
(18
)
 
$
(43
)
Unrealized gains on derivative instruments — long-term
15

 
39

 
Unrealized losses on derivative instruments — long-term
 

 

 
$
146

 
$
269

 
 
 
$
(18
)
 
$
(43
)

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
)
Losses reclassified from AOCI to earnings — effective portion

 
 
 

 

 

Net deferred (losses) gains in AOCI (ending balance)
$
(3
)
 
 
 
$
(6
)
 
$
1

 
$
(8
)
(a)
Relates to Discovery, our unconsolidated affiliate.






23

DCP MIDSTREAM PARTNERS, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three and Six Months Ended June 30, 2015 and 2014 - (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 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
)
Deferred losses in AOCI expected to be reclassified into earnings over the next 12 months
$
(1
)
 
 
 
$

 
$

 
$
(1
)
(a)
Relates to Discovery, our 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.

24

DCP MIDSTREAM PARTNERS, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three and Six Months Ended June 30, 2015 and 2014 - (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, 2014:
 
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
$

 
(b) (c)
 
$

 
$

 
$

Net deferred (losses) gains in AOCI (ending balance)
$
(4
)
 
 
 
$
(6
)
 
$
1

 
$
(9
)

(a)
Relates to Discovery, our unconsolidated affiliate.
(b)
Included in interest expense in our condensed consolidated statements of operations.
(c)
For the three months ended June 30, 2014, no derivative losses were reclassified from AOCI to interest expense as a result of the discontinuance of cash flow hedges related to certain forecasted transactions that are not probable of occurring.

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, 2014:
 
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)
$
(6
)
 
 
 
$
(6
)
 
$
1

 
$
(11
)
Losses reclassified from AOCI to earnings — effective portion
$
2

 
(b) (c)
 
$

 
$

 
$
2

Net deferred (losses) gains in AOCI (ending balance)
$