Annual Reports

 
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  • 10-Q (Nov 9, 2017)
  • 10-Q (Nov 8, 2017)
  • 10-Q (Aug 9, 2017)
  • 10-Q (May 10, 2017)
  • 10-Q (Nov 3, 2016)
  • 10-Q (Aug 4, 2016)

 
8-K

 
Other

DCP Midstream Partners, LP 10-Q 2016

Documents found in this filing:

  1. 10-Q
  2. Ex-12.1
  3. Ex-31.1
  4. Ex-31.2
  5. Ex-32.1
  6. Ex-32.2
  7. Ex-32.2
10-Q
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 March 31, 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 April 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 MARCH 31, 2016
TABLE OF CONTENTS
 
 
 
 
Item
 
Page
 
PART I. FINANCIAL INFORMATION
 
1.
Financial Statements (unaudited):
 
 
Condensed Consolidated Balance Sheets as of March 31, 2016 and December 31, 2015
 
Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2016 and 2015
 
Condensed Consolidated Statements of Comprehensive Income for the Three Months Ended March 31, 2016 and 2015
 
Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2016 and 2015
 
Condensed Consolidated Statement of Changes in Equity for the Three Months Ended March 31, 2016
 
Condensed Consolidated Statement of Changes in Equity for the Three Months Ended March 31, 2015
 
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, 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 execute our risk management programs 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)
 
March 31, 
 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
64

 
73

Affiliates
72

 
81

Inventories
37

 
43

Unrealized gains on derivative instruments
48

 
105

Other
1

 
2

Total current assets
223

 
306

Property, plant and equipment, net
3,446

 
3,476

Goodwill
72

 
72

Intangible assets, net
110

 
112

Investments in unconsolidated affiliates
1,486

 
1,493

Unrealized gains on derivative instruments
7

 
9

Other long-term assets
10

 
9

Total assets
$
5,354

 
$
5,477

LIABILITIES AND EQUITY
 
 
 
Current liabilities:
 
 
 
Accounts payable:
 
 
 
Trade
$
85

 
$
98

Affiliates
20

 
19

Unrealized losses on derivative instruments
5

 
18

Accrued interest
30

 
19

Accrued taxes
18

 
12

Other
17

 
34

Total current liabilities
175

 
200

Long-term debt
2,377

 
2,424

Unrealized losses on derivative instruments

 
1

Other long-term liabilities
48

 
47

Total liabilities
2,600

 
2,672

Commitments and contingent liabilities

 

Equity:
 
 
 
Limited partners (114,742,948 and 114,742,948 common units issued and outstanding, respectively)
2,713

 
2,762

General partner
18

 
18

Accumulated other comprehensive loss
(8
)
 
(8
)
Total partners’ equity
2,723

 
2,772

Noncontrolling interests
31

 
33

Total equity
2,754

 
2,805

Total liabilities and equity
$
5,354

 
$
5,477

See accompanying notes to condensed consolidated financial statements.

1


DCP MIDSTREAM PARTNERS, LP
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
 
Three Months Ended March 31,
 
2016
 
2015
 
(Millions, except per unit amounts)
Operating revenues:
 
 
 
Sales of natural gas, propane, NGLs and condensate
$
105

 
$
189

Sales of natural gas, propane, NGLs and condensate to affiliates
162

 
281

Transportation, processing and other
61

 
56

Transportation, processing and other to affiliates
42

 
23

Gains from commodity derivative activity, net
4

 
5

Gains from commodity derivative activity, net — affiliates
5

 
14

Total operating revenues
379

 
568

Operating costs and expenses:
 
 
 
Purchases of natural gas, propane and NGLs
208

 
367

Purchases of natural gas, propane and NGLs from affiliates
23

 
35

Operating and maintenance expense
48

 
47

Depreciation and amortization expense
32

 
29

General and administrative expense
2

 
3

General and administrative expense — affiliates
19

 
18

Total operating costs and expenses
332

 
499

Operating income
47

 
69

Interest expense
(24
)
 
(22
)
Earnings from unconsolidated affiliates
49

 
23

Income before income taxes
72

 
70

Income tax expense

 
(1
)
Net income
72

 
69

Net income attributable to noncontrolling interests

 

Net income attributable to partners
72

 
69

General partner’s interest in net income
(31
)
 
(31
)
Net income allocable to limited partners
$
41

 
$
38

Net income per limited partner unit — basic and diluted
$
0.36

 
$
0.33

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

 
114.2

See accompanying notes to condensed consolidated financial statements.


2


DCP MIDSTREAM PARTNERS, LP
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
 
 
Three Months Ended 
 March 31,
 
2016
 
2015
 
(Millions)
Net income
$
72

 
$
69

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

 
1

Total other comprehensive income

 
1

Total comprehensive income attributable to partners
$
72

 
$
70

See accompanying notes to condensed consolidated financial statements.


3


DCP MIDSTREAM PARTNERS, LP
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
 
Three Months Ended March 31,
 
2016
 
2015
 
(Millions)
OPERATING ACTIVITIES:
 
 
 
Net income
$
72

 
$
69

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Depreciation and amortization expense
32

 
29

Earnings from unconsolidated affiliates
(49
)
 
(23
)
Distributions from unconsolidated affiliates
63

 
26

Net unrealized losses on derivative instruments
45

 
43

Other, net
2

 
2

Change in operating assets and liabilities, which provided (used) cash, net of effects of acquisitions:
 
 
 
Accounts receivable
19

 
61

Inventories
6

 
27

Accounts payable
(10
)
 
(59
)
Accrued interest
10

 
12

Other current assets and liabilities
(2
)
 
(3
)
Other long-term assets and liabilities

 
4

Net cash provided by operating activities
188

 
188

INVESTING ACTIVITIES:
 
 
 
Capital expenditures
(10
)
 
(65
)
Investments in unconsolidated affiliates, net
(8
)
 
(25
)
Net cash used in investing activities
(18
)
 
(90
)
FINANCING ACTIVITIES:
 
 
 
Proceeds from long-term debt
394

 
162

Payments of long-term debt
(442
)
 
(162
)
Proceeds from issuance of common units, net of offering costs

 
31

Distributions to limited partners and general partner
(121
)
 
(120
)
Distributions to noncontrolling interests
(2
)
 
(1
)
Net cash used in financing activities
(171
)
 
(90
)
Net change in cash and cash equivalents
(1
)
 
8

Cash and cash equivalents, beginning of period
2

 
25

Cash and cash equivalents, end of period
$
1

 
$
33

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
 
41

 
31

 

 

 
72

Distributions to limited partners and general partner
 
(90
)
 
(31
)
 

 

 
(121
)
Distributions to noncontrolling interests
 

 

 

 
(2
)
 
(2
)
Balance, March 31, 2016
 
$
2,713

 
$
18

 
$
(8
)
 
$
31

 
$
2,754

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
38

 
31

 

 

 
69

Other comprehensive income

 

 
1

 

 
1

Issuance of 788,033 common units to the public
31

 

 

 

 
31

Distributions to limited partners and general partner
(89
)
 
(31
)
 

 

 
(120
)
Distributions to noncontrolling interests

 

 

 
(1
)
 
(1
)
Balance, March 31, 2015
$
2,964

 
$
18

 
$
(8
)
 
$
32

 
$
3,006

See accompanying notes to condensed consolidated financial statements.



6


DCP MIDSTREAM PARTNERS, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three Months Ended March 31, 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 13 - 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 months ended March 31, 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, 2016-08 “Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations,” or ASU 2016-08 - In March 2016, the FASB issued ASU 2016-08, which amends certain implementation guidance of FASB ASU 2014-09 “Revenue from Contracts with Customers (Topic 606)”, as discussed below. This ASU is effective for interim and annual reporting periods beginning after December 15, 2017, 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 Months Ended March 31, 2016 and 2015 - (Continued)
(Unaudited)

FASB 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.

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 - 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. 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 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 March 31,
 
 
2016
 
2015
 
 
(Millions)
Services Agreement
 
$
18

 
$
18

Other fees — DCP Midstream, LLC
 
1

 

Total — DCP Midstream, LLC
 
$
19

 
$
18

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, and less than $1 million, for the three months ended March 31, 2016, and 2015, respectively.

8

DCP MIDSTREAM PARTNERS, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three Months Ended March 31, 2016 and 2015 - (Continued)
(Unaudited)


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 March 31,
 
 
2016
 
2015
 
 
(Millions)
DCP Midstream, LLC:
 
 
 
 
Sales of natural gas, propane, NGLs and condensate
 
$
162

 
$
281

Transportation, processing and other
 
$
42

 
$
23

Purchases of natural gas, propane and NGLs
 
$
14

 
$
25

Gains from commodity derivative activity, net
 
$
5

 
$
14

General and administrative expense
 
$
19

 
$
18

Spectra Energy:
 
 
 
 
Purchases of natural gas, propane and NGLs
 
$
9

 
$
10

 We had balances with affiliates as follows:
 
March 31, 
 2016
 
December 31, 
 2015
 
(Millions)
DCP Midstream, LLC:
 
 
 
Accounts receivable
$
72

 
$
81

Accounts payable
$
16

 
$
15

Unrealized gains on derivative instruments — current
$
12

 
$
32

Unrealized gains on derivative instruments — long-term
$
7

 
$
9

Unrealized losses on derivative instruments — current
$
5

 
$
18

Unrealized losses on derivative instruments — long-term
$

 
$
1

Spectra Energy:
 
 
 
Accounts payable
$
4

 
$
4


4. Inventories
Inventories were as follows: 
 
March 31, 
 2016
 
December 31, 
 2015
 
(Millions)
Natural gas
$
23

 
$
29

NGLs
14

 
14

Total inventories
$
37

 
$
43


9

DCP MIDSTREAM PARTNERS, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three Months Ended March 31, 2016 and 2015 - (Continued)
(Unaudited)

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 $3 million and $4 million in the lower of cost or market adjustments during the three months ended March 31, 2016, and 2015 respectively.
5. Property, Plant and Equipment
A summary of property, plant and equipment by classification is as follows:
 
Depreciable
Life
 
March 31, 
 2016
 
December 31, 
 2015
 
 
 
(Millions)
Gathering and transmission systems
20 — 50 Years
 
$
2,340

 
$
2,337

Processing, storage, and terminal facilities
35 — 60 Years
 
2,362

 
2,327

Other
3 —  30 Years
 
66

 
64

Construction work in progress
 
 
82

 
122

Property, plant and equipment
 
 
4,850

 
4,850

Accumulated depreciation
 
 
(1,404
)
 
(1,374
)
Property, plant and equipment, net
 
 
$
3,446

 
$
3,476

Interest capitalized on construction projects was less than $1 million and $3 million for the three months ended March 31, 2016, and 2015, respectively.
Depreciation expense was $30 million and $26 million for the three months ended March 31, 2016 and 2015, respectively.

6. Investments in Unconsolidated Affiliates
The following table summarizes our investments in unconsolidated affiliates:
 
 
 
 
Carrying Value as of
 
Percentage
Ownership
 
March 31, 
 2016
 
December 31, 
 2015
 
 
 
(Millions)
DCP Sand Hills Pipeline, LLC
33.33%
 
$
442

 
$
441

Discovery Producer Services LLC
40%
 
397

 
406

DCP Southern Hills Pipeline, LLC
33.33%
 
317

 
318

Front Range Pipeline LLC
33.33%
 
170

 
170

Texas Express Pipeline LLC
10%
 
95

 
96

Mont Belvieu Enterprise Fractionator
12.5%
 
23

 
25

Panola Pipeline Company, LLC
15%
 
24

 
19

Mont Belvieu 1 Fractionator
20%
 
11

 
11

Other
Various
 
7

 
7

Total investments in unconsolidated affiliates
 
 
$
1,486

 
$
1,493


10

DCP MIDSTREAM PARTNERS, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three Months Ended March 31, 2016 and 2015 - (Continued)
(Unaudited)

Earnings (losses) from investments in unconsolidated affiliates were as follows:
 
 
 
Three Months Ended March 31,
 
 
2016
 
2015
 
(Millions)
Discovery Producer Services LLC
 
15

 
(2
)
DCP Sand Hills Pipeline, LLC
 
14

 
11

DCP Southern Hills Pipeline, LLC
 
7

 
3

Front Range Pipeline LLC
 
5

 
4

Mont Belvieu Enterprise Fractionator
 
4

 
4

Mont Belvieu 1 Fractionator
 
2

 
1

Texas Express Pipeline LLC
 
2

 
2

Total earnings from unconsolidated affiliates
 
$
49

 
$
23

The following tables summarize the combined financial information of our investments in unconsolidated affiliates:
 
 
Three Months Ended March 31,
 
 
2016
 
2015
 
(Millions)
Statements of operations (a):
 
 
 
 
Operating revenue
 
$
308

 
$
233

Operating expenses
 
$
128

 
$
129

Net income
 
$
178

 
$
103

 
 
March 31, 
 2016
 
December 31, 
 2015
 
(Millions)
Balance sheets (a):
 
 
 
Current assets
$
176

 
$
182

Long-term assets
5,183

 
5,200

Current liabilities
(140
)
 
(170
)
Long-term liabilities
(231
)
 
(216
)
Net assets
$
4,988

 
$
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.

7. 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

11

DCP MIDSTREAM PARTNERS, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three Months Ended March 31, 2016 and 2015 - (Continued)
(Unaudited)

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

12

DCP MIDSTREAM PARTNERS, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three Months Ended March 31, 2016 and 2015 - (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 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.
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.


13

DCP MIDSTREAM PARTNERS, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three Months Ended March 31, 2016 and 2015 - (Continued)
(Unaudited)

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

 
$
48

 
$

 
$
48

 
$

 
$
83

 
$
22

 
$
105

Short-term investments (b)
$
1

 
$

 
$

 
$
1

 
$
2

 
$

 
$

 
$
2

Long-term assets:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity derivatives (c)
$

 
$
7

 
$

 
$
7

 
$

 
$
9

 
$

 
$
9

Current liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity derivatives (d)
$

 
$
(5
)
 
$

 
$
(5
)
 
$

 
$
(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 months ended March 31, 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.
 

14

DCP MIDSTREAM PARTNERS, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three Months Ended March 31, 2016 and 2015 - (Continued)
(Unaudited)


 
Commodity Derivative Instruments
 
Current
Assets
 
Long-
Term
Assets
 
Current
Liabilities
 
Long-
Term
Liabilities
 
(Millions)
Three months ended March 31, 2016 (a):
 
 
 
 
 
 
 
Beginning balance
$
22

 
$

 
$

 
$

Settlements
(22
)
 

 

 

Ending balance
$

 
$

 
$

 
$

Three months ended March 31, 2015 (a):
 
 
 
 
 
 
 
Beginning balance
$
138

 
$
18

 
$

 
$

Net unrealized gains (losses) included in earnings (b)
20

 
(18
)
 

 

Settlements
(40
)
 

 

 

Ending balance
$
118

 
$

 
$

 
$

Net unrealized gains (losses) on derivatives still held included in earnings (b)
$
20

 
$
(18
)
 
$

 
$

 
(a)
There were no purchases, issuances or sales of derivatives or transfers into/out of Level 3 for the three months ended March 31, 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.
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

15

DCP MIDSTREAM PARTNERS, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three Months Ended March 31, 2016 and 2015 - (Continued)
(Unaudited)

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 March 31, 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:
 
 
March 31, 2016
 
December 31, 2015
 
 
Carrying Value (a)
 
Fair Value
 
Carrying Value (a)
 
Fair Value
 
(Millions)
 
 
 
 
 
 
 
 
 
Senior Notes
 
$
2,064

 
$
1,770

 
$
2,063

 
$
1,650

Amended and Restated Credit Agreement
 
$
327

 
$
327

 
$
375

 
$
375

(a) Excludes unamortized issuance costs.
8. Debt
 
March 31, 
 2016
 
December 31, 
 2015
 
(Millions)
Amended and Restated Credit Agreement
 
 
 
Revolving credit facility, weighted-average variable interest rate of 1.72% and 1.57%, as of March 31, 2016 and December 31, 2015, respectively, due May 1, 2019
$
327

 
$
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
(14
)
 
(14
)
Unamortized discount
(11
)
 
(12
)
Total long-term debt
$
2,377

 
$
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.

16

DCP MIDSTREAM PARTNERS, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three Months Ended March 31, 2016 and 2015 - (Continued)
(Unaudited)

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 March 31, 2016, we had unused borrowing capacity of $922 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.

The future maturities of long-term debt in the year indicated are as follows:
 
Debt
Maturities
 
(Millions)
2017
$
500

2018

2019
652

2020

2021

Thereafter
1,250

 
2,402

Unamortized issuance costs
(14
)
Unamortized discount
(11
)
Total
$
2,377


9. Risk Management and Hedging Activities
Our day-to-day operations expose us to a variety of risks including but not limited to changes in the prices of commodities that we buy or sell, changes in interest rates, and the creditworthiness of each of our counterparties. We manage certain of these exposures with 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

17

DCP MIDSTREAM PARTNERS, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three Months Ended March 31, 2016 and 2015 - (Continued)
(Unaudited)

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 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.

18

DCP MIDSTREAM PARTNERS, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three Months Ended March 31, 2016 and 2015 - (Continued)
(Unaudited)

The balance in AOCI of our previously settled base gas cash flow hedges was in a loss position of $6 million as of March 31, 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 March 31, 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.
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 March 31, 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 March 31, 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 March 31, 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:
 

19

DCP MIDSTREAM PARTNERS, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three Months Ended March 31, 2016 and 2015 - (Continued)
(Unaudited)

 
March 31, 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
$
55

 
$
(5
)
 
$
50

 
$
114

 
$
(19
)
 
$
95

Liabilities:
 
 
 
 
 
 
 
 
 
 
 
Commodity derivatives
$
(5
)
 
$
5

 
$

 
$
(19
)
 
$
19

 
$

 
(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 March 31, 2016 and December 31, 2015.
 
Balance Sheet Line Item
March 31, 
 2016
 
December 31, 
 2015
 
Balance Sheet Line Item
 
March 31, 
 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
$
48

 
$
105

 
Unrealized losses on derivative instruments — current
 
$
(5
)
 
$
(18
)
Unrealized gains on derivative instruments — long-term
7

 
9

 
Unrealized losses on derivative instruments — long-term
 

 
(1
)
Total
$
55

 
$
114

 
Total
 
$
(5
)
 
$
(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 March 31, 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 months ended March 31, 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 months ended March 31, 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.

20

DCP MIDSTREAM PARTNERS, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three Months Ended March 31, 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 March 31, 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 months ended March 31, 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 months ended March 31, 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 March 31,
 
 
2016
 
2015
 
(Millions)
Third party:
 
 
 
 
Realized gains
 
$
40

 
$
7

Unrealized losses
 
(36
)
 
(2
)
Gains from commodity derivative activity, net
 
$
4

 
$
5

Affiliates:
 
 
 
 
Realized gains
 
$
14

 
$
54

Unrealized losses
 
(9
)
 
(40
)
Gains from commodity derivative activity, net —affiliates
 
$
5

 
$
14

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. 

21

DCP MIDSTREAM PARTNERS, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three Months Ended March 31, 2016 and 2015 - (Continued)
(Unaudited)

 
March 31, 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
Position
(Bbls)
 
Net Long Position
(MMBtu)
2016
(1,100,000
)
 
(9,282,500
)
 
(180,000
)
 
2,060,000

2017

 
(12,817,500
)
 

 
1,800,000

 
 
 
 
 
 
 
 
 
March 31, 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
(561,825
)
 
(12,429,125
)
 
(4,231,200
)
 
2,675,000

2016
(561,922
)
 
(5,668,564
)
 
(813,267
)
 
1,690,000

2017

 
(6,387,500
)
 

 

10. Partnership Equity and Distributions
During the three months ended March 31, 2016, we issued no common units pursuant to our 2014 equity distribution agreement. As of March 31, 2016, approximately $349 million of common units remained available for sale pursuant to our 2014 equity distribution agreement.
During the three months ended March 31, 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)
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

11. 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 1,604 and 11,573 equivalent units during the three months ended March 31, 2016, and 2015 respectively.
12. 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.
EnvironmentalThe 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,

22

DCP MIDSTREAM PARTNERS, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three Months Ended March 31, 2016 and 2015 - (Continued)
(Unaudited)

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.


13. 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.

The following tables set forth our segment information: 
 
 
 

23

DCP MIDSTREAM PARTNERS, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three Months Ended March 31, 2016 and 2015 - (Continued)
(Unaudited)

Three Months Ended March 31, 2016:
 
 
Natural Gas
Services
 
NGL
Logistics
 
Wholesale
Propane
Logistics
 
Other
 
Total
 
(Millions)
Total operating revenue
$
305

 
$
21

 
$
53

 
$

 
$
379

Gross margin (a)
$
111

 
$
21

 
$
16

 
$

 
$
148

Operating and maintenance expense
(40
)
 
(5
)
 
(3
)
 

 
(48
)
Depreciation and amortization expense
(29
)
 
(2
)
 
(1
)
 

 
(32
)
General and administrative expense

 

 

 
(21
)
 
(21
)
Earnings from unconsolidated affiliates
15

 
34

 

 

 
49

Interest expense

 

 

 
(24
)
 
(24
)
Net income (loss)
$
57

 
$
48

 
$
12

 
$
(45
)
 
$
72

Net income attributable to noncontrolling interests

 

 

 

 

Net income (loss) attributable to partners
$
57

 
$
48

 
$
12

 
$
(45
)
 
$
72

Non-cash derivative mark-to-market (b)
$
(45
)
 
$

 
$

 
$

 
$
(45
)
Non-cash lower of cost or market adjustments
$
3

 
$

 
$

 
$

 
$
3

Capital expenditures
$
9

 
$

 
$
1

 
$

 
$
10

Investments in unconsolidated affiliates, net
$

 
$
8

 
$

 
$

 
$
8


24

DCP MIDSTREAM PARTNERS, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three Months Ended March 31, 2016 and 2015 - (Continued)
(Unaudited)

Three Months Ended March 31, 2015:
 
Natural Gas
Services
 
NGL
Logistics
 
Wholesale
Propane
Logistics
 
Other
 
Total
 
(Millions)
Total operating revenue
$
440

 
$
18

 
$
110

 
$

 
$
568

Gross margin (a)
$
119

 
$
18

 
$
29

 
$

 
$
166

Operating and maintenance expense
(40
)
 
(4
)
 
(3
)
 

 
(47
)
Depreciation and amortization expense
(26
)
 
(2
)
 
(1
)
 

 
(29
)
General and administrative expense

 

 

 
(21
)
 
(21
)
Earnings from unconsolidated affiliates
(2
)
 
25

 

 

 
23

Interest expense

 

 

 
(22
)
 
(22
)
Income tax expense

 

 

 
(1
)
 
(1
)
Net income (loss)
$
51

 
$
37

 
$
25

 
$
(44
)
 
$
69

Net income attributable to noncontrolling interests

 

 

 

 

Net income (loss) attributable to partners
$
51

 
$
37

 
$
25

 
$
(44
)
 
$
69

Non-cash derivative mark-to-market (b)
$
(45
)
 
$

 
$
3

 
$
(1
)
 
$
(43
)
Non-cash lower of cost or market adjustments
$
3

 
$

 
$
1

 
$