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DCP Midstream Partners, LP 10-Q 2017
Document
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, 2017
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, 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, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer”, “smaller reporting company” and "emerging growth company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer
ý
 
Accelerated filer
¨

Emerging growth company
¨
Non-accelerated filer
¨

(Do not check if a smaller reporting company)
Smaller reporting company
¨

 
 

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a)
of the Exchange Act. ¨

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 May 5, 2017, there were 143,302,328 common units representing limited partner interests outstanding.




DCP MIDSTREAM, LP
FORM 10-Q FOR THE QUARTER ENDED MARCH 31, 2017
TABLE OF CONTENTS
 
 
 
 
Item
 
Page
 
PART I. FINANCIAL INFORMATION
 
1.
Financial Statements (unaudited):
 
 
Condensed Consolidated Balance Sheets as of March 31, 2017 and December 31, 2016
 
Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2017 and 2016
 
Condensed Consolidated Statements of Comprehensive Income for the Three Months Ended March 31, 2017 and 2016
 
Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2017 and 2016
 
Condensed Consolidated Statement of Changes in Equity for the Three Months Ended March 31, 2017
 
Condensed Consolidated Statement of Changes in Equity for the Three Months Ended March 31, 2016
 
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, 2016, 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;
general economic, market and business conditions;
our ability to continue the safe and reliable operation of our 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;
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 credit agreement and the indentures governing our notes, as well as our ability to maintain our credit ratings;
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, or acquisitions, and the successful integration and future performance of such assets;
our ability to hire, train, and retain qualified personnel and key management to execute our business strategy;
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;
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 obtain insurance on commercially reasonable terms, if at all, as well as the adequacy of insurance to cover our losses; and
the amount of natural 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 natural 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, except as required by applicable securities laws.


iii


Item 1. Financial Statements

DCP MIDSTREAM, LP
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
 
March 31, 
 2017
 
December 31, 
 2016
 
(Millions)
ASSETS
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
176

 
$
1

Accounts receivable:
 
 
 
Trade, net of allowance for doubtful accounts of $4 million
541

 
652

Affiliates
104

 
134

Other
6

 
6

Inventories
64

 
72

Unrealized gains on derivative instruments
31

 
42

Other
58

 
87

Total current assets
980

 
994

Property, plant and equipment, net
9,047

 
9,069

Goodwill
236

 
236

Intangible assets, net
135

 
137

Investments in unconsolidated affiliates
2,988

 
2,969

Unrealized gains on derivative instruments
4

 
5

Other long-term assets
189

 
201

Total assets
$
13,579

 
$
13,611

LIABILITIES AND EQUITY
 
 
 
Current liabilities:
 
 
 
Accounts payable:
 
 
 
Trade
$
546

 
$
677

Affiliates
51

 
48

       Other
14

 
10

Current maturities of long-term debt
500

 
500

Unrealized losses on derivative instruments
36

 
91

Accrued interest
57

 
72

Accrued taxes
68

 
49

Accrued wages and benefits
25

 
72

Capital spending accrual
20

 
20

Other
73

 
84

Total current liabilities
1,390

 
1,623

Long-term debt
4,709

 
4,907

Unrealized losses on derivative instruments
7

 
1

Deferred income taxes
28

 
28

Other long-term liabilities
195

 
199

Total liabilities
6,329

 
6,758

Commitments and contingent liabilities

 

Equity:
 
 
 
Predecessor equity

 
4,220

Limited partners (143,302,328 and 114,749,848 common units issued and outstanding, respectively)
7,108

 
2,591

General partner
121

 
18

Accumulated other comprehensive loss
(9
)
 
(8
)
Total partners’ equity
7,220

 
6,821

Noncontrolling interests
30

 
32

Total equity
7,250

 
6,853

Total liabilities and equity
$
13,579

 
$
13,611

See accompanying notes to condensed consolidated financial statements.

1


DCP MIDSTREAM, LP
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
 
Three Months Ended March 31,
 
2017
 
2016
 
(Millions, except per unit amounts)
Operating revenues:
 
 
 
Sales of natural gas, NGLs and condensate
$
1,644

 
$
1,119

Sales of natural gas, NGLs and condensate to affiliates
289

 
175

Transportation, processing and other
157

 
152

Trading and marketing gains, net
31

 
18

Total operating revenues
2,121

 
1,464

Operating costs and expenses:
 
 
 
Purchases of natural gas and NGLs
1,559

 
1,032

Purchases of natural gas and NGLs from affiliates
128

 
103

Operating and maintenance expense
167

 
179

Depreciation and amortization expense
94

 
95

General and administrative expense
62

 
62

Other expense (income), net
10

 
(87
)
Total operating costs and expenses
2,020

 
1,384

Operating income
101

 
80

Earnings from unconsolidated affiliates
74

 
66

Interest expense, net
(73
)
 
(79
)
Income before income taxes
102

 
67

Income tax expense
(1
)
 
(2
)
Net income
101

 
65

Net income attributable to noncontrolling interests

 

Net income attributable to partners
101

 
65

Net loss attributable to predecessor operations

 
7

General partner’s interest in net income
(42
)
 
(31
)
Net income allocable to limited partners
$
59

 
$
41

Net income per limited partner unit — basic and diluted
$
0.41

 
$
0.36

Weighted-average limited partner units outstanding — basic and diluted
143.3

 
114.7

See accompanying notes to condensed consolidated financial statements.


2


DCP MIDSTREAM, LP
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
 
 
Three Months Ended 
 March 31,
 
2017
 
2016
 
(Millions)
Net income
$
101

 
$
65

Other comprehensive income:
 
 
 
Reclassification of cash flow hedge losses into earnings
1

 

Total other comprehensive income
1

 

Total comprehensive income
102

 
65

Total comprehensive income attributable to noncontrolling interests

 

Total comprehensive income attributable to partners
$
102

 
$
65

See accompanying notes to condensed consolidated financial statements.


3


DCP MIDSTREAM, LP
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
 
Three Months Ended March 31,
 
2017
 
2016
 
(Millions)
OPERATING ACTIVITIES:
 
 
 
Net income
$
101

 
$
65

Adjustments to reconcile net income to net cash provided by operating activities:

 

Depreciation and amortization expense
94

 
95

Earnings from unconsolidated affiliates
(74
)
 
(66
)
Distributions from unconsolidated affiliates
76

 
87

Net unrealized (gains) losses on derivative instruments
(36
)
 
45

Deferred income tax, net

 
1

Other, net
13

 
4

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

Accounts receivable
138

 
1

Inventories
8

 
8

Accounts payable
(144
)
 
(55
)
Accrued interest
(15
)
 
(15
)
Other current assets and liabilities
(20
)
 
(19
)
Other long-term assets and liabilities
3

 

Net cash provided by operating activities
144

 
151

INVESTING ACTIVITIES:
 
 
 
Capital expenditures
(48
)
 
(57
)
Change in restricted cash

 
(7
)
Investments in unconsolidated affiliates, net
(20
)
 
(12
)
Net cash used in investing activities
(68
)
 
(76
)
FINANCING ACTIVITIES:
 
 
 
Proceeds from long-term debt

 
892

Payments of long-term debt
(195
)
 
(896
)
Net change in advances to predecessor from DCP Midstream, LLC
418

 
50

Distributions to limited partners and general partner
(121
)
 
(121
)
Distributions to noncontrolling interests
(2
)
 
(2
)
Other
(1
)
 

Net cash provided by (used in) financing activities
99

 
(77
)
Net change in cash and cash equivalents
175

 
(2
)
Cash and cash equivalents, beginning of period
1

 
3

Cash and cash equivalents, end of period
$
176

 
$
1

See accompanying notes to condensed consolidated financial statements.

4


DCP MIDSTREAM, LP
CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
(Unaudited)
 
 
 
 
Partners’ Equity
 
 
 
 
 
Predecessor
Equity
 
Limited 
Partners
 
General 
Partner
 
Accumulated Other
Comprehensive
Loss
 
Noncontrolling
Interests
 
Total
Equity
 
(Millions)
Balance, January 1, 2017
$
4,220

 
$
2,591

 
$
18

 
$
(8
)
 
$
32

 
$
6,853

Net income

 
59

 
42

 

 

 
101

Other comprehensive income

 

 

 
1

 

 
1

Net change in parent advances

 
418

 

 

 

 
418

Acquisition of the DCP Midstream Business
(4,220
)
 

 

 

 

 
(4,220
)
Deficit purchase price under carrying value of the Transaction

 
3,097

 

 
(2
)
 

 
3,095

Issuance of 28,552,480 common units and 2,550,644 general partner units to DCP Midstream, LLC and affiliates

 
1,033

 
92

 

 

 
1,125

Distributions to limited partners and general partner

 
(90
)
 
(31
)
 

 

 
(121
)
Distributions to noncontrolling interests

 

 

 

 
(2
)
 
(2
)
Balance, March 31, 2017
$

 
$
7,108

 
$
121

 
$
(9
)
 
$
30

 
$
7,250

See accompanying notes to condensed consolidated financial statements.


5


DCP MIDSTREAM, LP
CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
(Unaudited)

 
Partners’ Equity
 
 
 
 
 
Predecessor
Equity
 
Limited 
Partners
 
General 
Partner
 
Accumulated 
Other
Comprehensive
Loss
 
Noncontrolling
Interests
 
Total
Equity
 
(Millions)
Balance, January 1, 2016
$
4,287

 
$
2,762

 
$
18

 
$
(8
)
 
$
33

 
$
7,092

Net (loss) income
(7
)
 
41

 
31

 

 

 
65

Net change in parent advances
50

 

 

 

 

 
50

Distributions to limited partners and general partner

 
(90
)
 
(31
)
 

 

 
(121
)
Distributions to noncontrolling interests

 

 

 

 
(2
)
 
(2
)
Balance, March 31, 2016
$
4,330

 
$
2,713

 
$
18

 
$
(8
)
 
$
31

 
$
7,084


See accompanying notes to condensed consolidated financial statements.


6


DCP MIDSTREAM, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three Months Ended March 31, 2017 and 2016
(Unaudited)
1. Description of Business and Basis of Presentation

DCP Midstream, LP, with its consolidated subsidiaries, or "us", "we", "our" or the "Partnership" is a Delaware limited partnership formed in 2005 by DCP Midstream, LLC to own, operate, acquire and develop a diversified portfolio of complementary midstream energy assets.
Our Partnership includes our Gathering and Processing and Logistics and Marketing segments. For additional information regarding these segments, see Note 18 - 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 Enbridge, Inc and its affiliates, or Enbridge. Spectra Energy Corp owned 50% of DCP Midstream, LLC prior to the completion of their merger with Enbridge in the first quarter of 2017. DCP Midstream, LLC directs our business operations through its ownership and control of the General Partner. As of March 31, 2017, DCP Midstream, LLC owned approximately 38.1% of us, including limited partner and general partner interests.
On December 30, 2016, we entered into a Contribution Agreement (the “Contribution Agreement”) with DCP Midstream, LLC and DCP Midstream Operating, LP (the “Operating Partnership”), a 100% owned subsidiary of the Partnership. The transactions and documents contemplated by the Contribution Agreement are collectively referred to hereafter as the “Transaction.” The Transaction closed effective January 1, 2017. Our predecessor results consist of all of the ownership interests of DCP Midstream, LLC in all of its subsidiaries that owned operating assets ("The DCP Midstream Business"), which we acquired from DCP Midstream, LLC on January 1, 2017. This transfer of net assets between entities under common control was accounted for as if the transfer occurred at the beginning of the period, and prior years were retrospectively adjusted to furnish comparative information, similar to the pooling method. Accordingly, our condensed consolidated financial statements include the historical results of The DCP Midstream Business for all periods presented. We recognize transfers of net assets between entities under common control at DCP Midstream, LLC’s basis in the net assets contributed. The amount of the purchase price in deficit of DCP Midstream, LLC’s basis in the net assets is recognized as an addition to limited partners’ equity. The financial statements of our predecessor have been prepared from the separate records maintained by DCP Midstream, LLC and may not necessarily be indicative of the conditions that would have existed or the results of operations if our predecessor had been operated as an unaffiliated entity. For additional information regarding the Transaction, see Note 3 - Acquisitions.
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.
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, 2017 are not necessarily indicative of the results that may be expected for the year ending December 31, 2017. 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 2016 audited consolidated financial statements

7

DCP MIDSTREAM, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three Months Ended March 31, 2017 and 2016 - (Continued)
(Unaudited)

and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2016.

2. New Accounting Pronouncements

Financial Accounting Standards Board, or FASB, Accounting Standards Update, or ASU, 2016-15 “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments,” or ASU 2016-15 - In August 2016, the FASB issued ASU 2016-15, which amends certain cash flow statement classification guidance. 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 statement of cash flows.

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. The company has adopted the ASU and it did not have any impact on our condensed consolidated results of operations, cash flows and financial position.

FASB ASU 2014-09 “Revenue from Contracts with Customers (Topic 606),” or ASU 2014-09 and related interpretations and amendments - In May 2014, the FASB issued ASU 2014-09, which supersedes the revenue recognition requirements of Accounting Standards Codification Topic 605 “Revenue Recognition.” This ASU is effective for annual reporting periods beginning after December 15, 2017, with the option to adopt as early as annual reporting periods beginning after December 15, 2016. We plan to adopt this ASU using the modified retrospective method. The initial cumulative effect will be recognized at the date of adoption. Our evaluation of ASU 2014-09 is ongoing and not complete. The FASB has issued and may issue in the future, interpretative guidance, which may cause our evaluation to change. Accordingly, at this time we cannot estimate the impact upon adoption.

3. Acquisitions
On January 1, 2017, DCP Midstream, LLC contributed to us: (i) its ownership interests in all of its subsidiaries owning operating assets, and (ii) $424 million of cash (together the “Contributions”). In consideration of the Partnership’s receipt of the Contributions, (i) the Partnership issued 28,552,480 common units to DCP Midstream, LLC and 2,550,644 general partner units to the General Partner in a private placement and (ii) the Operating Partnership assumed $3,150 million of DCP Midstream, LLC’s debt. This represents a transaction between entities under common control and a change in reporting entity.

Pursuant to the Contribution Agreement, DCP Midstream, LLC agreed to cause the General Partner to enter into Amendment No. 3 (the “Third Amendment to the Partnership Agreement”) to the Second Amended and Restated Agreement of Limited Partnership of the Partnership, dated November 1, 2006, as amended (the “Partnership Agreement”). On January 1, 2017, the General Partner, in its capacity as the general partner of the Partnership, entered into the Third Amendment to the Partnership Agreement. The Third Amendment to the Partnership Agreement includes terms that amend the Partnership Agreement to cause the incentive distributions payable to the holders of the Partnership’s incentive distribution rights with respect to the fiscal years 2017, 2018 and 2019 to, in certain circumstances, be reduced in an amount up to $100 million per fiscal year as necessary to provide that the distributable cash flow of the Partnership (as adjusted) during such year meets or exceeds the amount of distributions made by the Partnership (as adjusted) to the partners of the Partnership with respect to such year.







8

DCP MIDSTREAM, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three Months Ended March 31, 2017 and 2016 - (Continued)
(Unaudited)

4. Agreements and Transactions with Affiliates
DCP Midstream, LLC
Services Agreement and Other General and Administrative Charges
Pursuant to the Contribution Agreement, on January 1, 2017, the Partnership entered into the Services and Employee Secondment Agreement (the “Services Agreement”), which replaced the services agreement between the Partnership and DCP Midstream, LLC, dated February 14, 2013, as amended. Under the Services Agreement, we are required to reimburse DCP Midstream, LLC for costs, expenses, and expenditures incurred or payments made on our behalf for general and administrative functions including, but not limited to, legal, accounting, compliance, treasury, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, benefit plan maintenance and administration, credit, payroll, internal audit, taxes and engineering, as well as salaries and benefits of seconded employees, insurance coverage and claims, capital expenditures, maintenance and repair costs and taxes. There is no limit on the reimbursements we make to DCP Midstream, LLC under the Services Agreement for costs, expenses and expenditures incurred or payments made on our behalf.

Phillips 66 and CPChem

We sell a portion of our NGLs to Phillips 66 and Chevron Phillips Chemical LLC, or CPChem. In addition, we purchase NGLs from CPChem. CPChem is owned 50% by Phillips 66, and is considered a related party. Approximately 26% of our NGL production was committed to Phillips 66 and CPChem as of March 31, 2017. The primary production commitment on certain contracts began a ratable wind down period in December 2014 and expires in January 2019. We anticipate continuing to purchase and sell commodities with Phillips 66 and CPChem in the ordinary course of business.

Enbridge and its Affiliates including Spectra Energy Corp

We sell a portion of our natural gas and NGLs to Enbridge. In addition, we purchase natural gas and NGL products from Enbridge. We anticipate continuing to purchase commodities and provide services to Enbridge in the ordinary course of business.

Unconsolidated Affiliates

We, along with other third party shippers, have entered into 15-year transportation agreements, with Sand Hills Pipeline, LLC, or Sand Hills, Southern Hills Pipeline, LLC, or Southern Hills, Front Range Pipeline LLC, or Front Range, and Texas Express Pipeline LLC, or Texas Express. Under the terms of these 15-year agreements, which commenced at each of the pipelines’ respective in-service dates and expire in 2028 and 2029, we have committed to transport minimum throughput volumes at rates defined in each of the pipelines’ respective tariffs.

Under the terms of the Sand Hills LLC Agreement and the Southern Hills LLC Agreement, or the Sand Hills and Southern Hills LLC Agreements, Sand Hills and Southern Hills are required to reimburse us for any direct costs or expenses (other than general and administration services) which we incur on behalf of Sand Hills and Southern Hills. Additionally, Sand Hills and Southern Hills each pay us an annual service fee of $5 million, for centralized corporate functions provided by us as operator of Sand Hills and Southern Hills, 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 service fee, there is no limit on the reimbursements Sand Hills and Southern Hills make to us under the Sand Hills and Southern Hills LLC Agreements for other expenses and expenditures which we incur on behalf of Sand Hills or Southern Hills.

We also sell a portion of our residue gas and NGLs to, purchase natural gas and other NGL products from, and provide gathering and transportation services to other unconsolidated affiliates. We anticipate continuing to purchase and sell commodities and provide services to unconsolidated affiliates in the ordinary course of business.



9

DCP MIDSTREAM, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three Months Ended March 31, 2017 and 2016 - (Continued)
(Unaudited)

Summary of Transactions with Affiliates
The following table summarizes our transactions with affiliates:
 
 
Three Months Ended March 31,
 
 
2017
 
2016
 
 
(Millions)
Phillips 66 (including CPChem):
 
 
 
 
Sales of natural gas and NGLs
 
$
274

 
$
171

Purchases of natural gas and NGLs
 
$
7

 
$

Operating and maintenance
 
$
1

 
$

Enbridge (including Spectra Energy Corp):
 
 
 
 
Sales of natural gas and NGLs
 
$
5

 
$

Purchases of natural gas and NGLs
 
$
8

 
$
10

Operating and maintenance
 
$
1

 
$
1

Unconsolidated affiliates:
 
 
 
 
Sales of natural gas and NGLs
 
$
10

 
$
4

Purchases of natural gas and NGLs
 
$
113

 
$
93

Transportation, processing and other
 
$
1

 
$
1


 We had balances with affiliates as follows:
 
March 31, 
 2017
 
December 31, 
 2016
 
(Millions)
Phillips 66 (including CPChem):
 
 
 
Accounts receivable
$
85

 
$
115

Accounts payable
$
4

 
$
4

Other assets
$

 
$
2

Enbridge (including Spectra Energy Corp):
 
 
 
Accounts receivable
$
5

 
$
1

Accounts payable
$
3

 
$
3

Other assets
$

 
$
1

Other liabilities
$
2

 
$
1

Unconsolidated affiliates:
 
 
 
Accounts receivable
$
14

 
$
18

Accounts payable
$
44

 
$
41

Other assets
$
3

 
$
5


5. Inventories
Inventories were as follows: 
 
March 31, 
 2017
 
December 31, 
 2016
 
(Millions)
Natural gas
$
32

 
$
28

NGLs
32

 
44

Total inventories
$
64

 
$
72

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 and NGLs in the condensed consolidated

10

DCP MIDSTREAM, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three Months Ended March 31, 2017 and 2016 - (Continued)
(Unaudited)

statements of operations. We recognized no lower of cost or market adjustments during the three months ended March 31, 2017 and $3 million during the three months ended March 31, 2016.
6. Property, Plant and Equipment
A summary of property, plant and equipment by classification is as follows:
 
Depreciable
Life
 
March 31, 
 2017
 
December 31, 
 2016
 
 
 
(Millions)
Gathering and transmission systems
20 — 50 Years
 
$
8,568

 
$
8,560

Processing, storage and terminal facilities
35 — 60 Years
 
5,144

 
5,134

Other
3 —  30 Years
 
506

 
502

Construction work in progress
 
 
216

 
171

Property, plant and equipment
 
 
14,434

 
14,367

Accumulated depreciation
 
 
(5,387
)
 
(5,298
)
Property, plant and equipment, net
 
 
$
9,047

 
$
9,069

Interest capitalized on construction projects was $1 million and less than $1 million for the three months ended March 31, 2017 and 2016, respectively.
Depreciation expense was $92 million and $92 million for the three months ended March 31, 2017 and 2016, respectively.
Asset Retirement Obligations - As of March 31, 2017 and December 31, 2016, we had asset retirement obligations of $126 million and $124 million, respectively, included in other long-term liabilities in the condensed consolidated balance sheets. Accretion expense was $2 million for the three months ended March 31, 2017 and 2016, respectively.

We identified various assets as having an indeterminate life, for which there is no requirement to establish a fair value for future retirement obligations associated with such assets. These assets include certain pipelines, gathering systems and processing facilities. A liability for these asset retirement obligations will be recorded only if and when a future retirement obligation with a determinable life is identified. These assets have an indeterminate life because they are owned and will operate for an indeterminate future period when properly maintained. Additionally, if the portion of an owned plant containing asbestos were to be modified or dismantled, we would be legally required to remove the asbestos. We currently have no plans to take actions that would require the removal of the asbestos in these assets. Accordingly, the fair value of the asset retirement obligation related to this asbestos cannot be estimated and no obligation has been recorded.



11

DCP MIDSTREAM, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three Months Ended March 31, 2017 and 2016 - (Continued)
(Unaudited)

7. Goodwill and Intangible Assets

The carrying amount of goodwill in each of our reporting segments was as follows:
 
Three Months Ended March 31,
 
2017
 
(millions)
 
Gathering and Processing
 
Logistics and Marketing
 
Total
Balance, beginning of period
$
164

 
$
72

 
$
236

Balance, end of period
$
164

 
$
72

 
$
236


We will perform our annual goodwill assessment during the third quarter of 2017 at the reporting unit level, which is identified by assessing whether the components of our operating segments constitute businesses for which discrete financial information is available, whether management regularly reviews the operating results of those components and whether the economic and regulatory characteristics are similar.

Intangible assets consist of customer contracts, including commodity purchase, transportation and processing contracts and related relationships. The gross carrying amount and accumulated amortization of these intangible assets are included in the accompanying combined balance sheets as intangible assets, net, and are as follows:
 
March 31,
 
December 31,
 
2017
 
2016
 
(millions)
Gross carrying amount
$
410

 
$
410

Accumulated amortization
(153
)
 
(151
)
Accumulated impairment
(122
)
 
(122
)
    Intangible assets, net
$
135

 
$
137


For the three months ended March 31, 2017 and 2016, we recorded amortization expense of $2 million and $3 million, respectively. As of March 31, 2017, the remaining amortization periods ranged from approximately 1 years to approximately 18 years, with a weighted-average remaining period of approximately 14 years.

Estimated future amortization for these intangible assets is as follows:
Estimated Future Amortization
(millions)
2017
 
$
8

2018
 
11

2019
 
11

2020
 
11

2021
 
11

Thereafter
 
83

Total
 
$
135



12

DCP MIDSTREAM, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three Months Ended March 31, 2017 and 2016 - (Continued)
(Unaudited)

8. Investments in Unconsolidated Affiliates
The following table summarizes our investments in unconsolidated affiliates:
 
 
 
Carrying Value as of
 
Percentage
Ownership
 
March 31, 
 2017
 
December 31, 
 2016
 
 
 
(Millions)
DCP Sand Hills Pipeline, LLC
66.67%
 
$
1,531

 
$
1,507

Discovery Producer Services LLC
40.00%
 
381

 
385

DCP Southern Hills Pipeline, LLC
66.67%
 
753

 
754

Front Range Pipeline LLC
33.33%
 
166

 
165

Texas Express Pipeline LLC
10.00%
 
93

 
93

Panola Pipeline Company, LLC
15.00%
 
24

 
25

Mont Belvieu Enterprise Fractionator
12.50%
 
22

 
23

Mont Belvieu 1 Fractionator
20.00%
 
10

 
10

Other
Various
 
8

 
7

Total investments in unconsolidated affiliates
 
 
$
2,988

 
$
2,969

Earnings from investments in unconsolidated affiliates were as follows:
 
 

Three Months Ended March 31,
 

2017

2016
 

(Millions)
DCP Sand Hills Pipeline, LLC

$
31


$
25

Discovery Producer Services LLC

20


15

DCP Southern Hills Pipeline, LLC

11


12

Front Range Pipeline LLC

4


5

Texas Express Pipeline LLC

2


2

Mont Belvieu Enterprise Fractionator

3


4

Mont Belvieu 1 Fractionator

1


3

Other

2



Total earnings from unconsolidated affiliates

$
74


$
66




13

DCP MIDSTREAM, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three Months Ended March 31, 2017 and 2016 - (Continued)
(Unaudited)

The following tables summarize the combined financial information of our investments in unconsolidated affiliates:
 
 
Three Months Ended March 31,
 
 
2017
 
2016
 
 
(Millions)
Statements of operations:
 
 
 
 
Operating revenue
 
$
337

 
$
307

Operating expenses
 
$
148

 
$
119

Net income
 
$
188

 
$
186

 
 
March 31, 
 2017
 
December 31, 
 2016
 
(Millions)
Balance sheets:
 
 
 
Current assets
$
200

 
$
232

Long-term assets
5,256

 
5,274

Current liabilities
(134
)
 
(156
)
Long-term liabilities
(202
)
 
(205
)
Net assets
$
5,120

 
$
5,145


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, and/or the liquidity of the market.
Counterparty credit valuation adjustments are necessary when the market price of an instrument is not indicative of the fair value as a result of the credit quality of the counterparty. Generally, market quotes assume that all counterparties have near zero, or low, default rates and have equal credit quality. Therefore, an adjustment may be necessary to reflect the credit quality of a specific counterparty to determine the fair value of the instrument. We record counterparty credit valuation adjustments on all derivatives that are in a net asset position as of the measurement date in accordance with our established counterparty credit policy, which takes into account any collateral margin that a counterparty may have posted with us as well as any letters of credit that they have provided.
Entity valuation adjustments are necessary to reflect the effect of our own credit quality on the fair value of our net liability positions with each counterparty. This adjustment takes into account any credit enhancements, such as collateral margin we may have posted with a counterparty, as well as any letters of credit that we have provided. The methodology to determine this adjustment is consistent with how we evaluate counterparty credit risk, taking into account our own credit rating, current credit spreads, as well as any change in such spreads since the last measurement date.

14

DCP MIDSTREAM, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three Months Ended March 31, 2017 and 2016 - (Continued)
(Unaudited)

Liquidity valuation adjustments are necessary when we are not able to observe a recent market price for financial instruments that trade in less active markets for the fair value to reflect the cost of exiting the position. Exchange traded contracts are valued at market value without making any additional valuation adjustments and, therefore, no liquidity reserve is applied. For contracts other than exchange traded instruments, we mark our positions to the midpoint of the bid/ask spread, and record a liquidity reserve based upon our total net position. We believe that such practice results in the most reliable fair value measurement as viewed by a market participant.
We manage our derivative instruments on a portfolio basis and the valuation adjustments described above are calculated on this basis. We believe that the portfolio level approach represents the highest and best use for these assets as there are benefits inherent in naturally offsetting positions within the portfolio at any given time, and this approach is consistent with how a market participant would view and value the assets and liabilities. Although we take a portfolio approach to managing these assets/liabilities, in order to reflect the fair value of any one individual contract within the portfolio, we allocate all valuation adjustments down to the contract level, to the extent deemed necessary, based upon either the notional contract volume, or the contract value, whichever is more applicable.
 
The methods described above may produce a fair value calculation that may not be indicative of net realizable value or reflective of future fair values. While we believe that our valuation methods are appropriate and consistent with other market participants, we recognize that the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different estimate of fair value at the reporting date. We review our fair value policies on a regular basis taking into consideration changes in the marketplace and, if necessary, will adjust our policies accordingly. See Note 11 - Risk Management and Hedging Activities.
Valuation Hierarchy
Our fair value measurements are grouped into a three-level valuation hierarchy and are categorized in their entirety in the same level of the fair value hierarchy as the lowest level input that is significant to the entire measurement. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date. The three levels are defined as follows.
Level 1 — inputs are unadjusted quoted prices for identical assets or liabilities in active markets.
Level 2 — inputs include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.
Level 3 — inputs are unobservable and considered significant to the fair value measurement.
A financial instrument’s categorization within the hierarchy is based upon the level of judgment involved in the most significant input in the determination of the instrument’s fair value. Following is a description of the valuation methodologies used as well as the general classification of such instruments pursuant to the hierarchy.
Commodity Derivative Assets and Liabilities

We enter into a variety of derivative financial instruments, which may include exchange traded instruments (such as New York Mercantile Exchange, or NYMEX, crude oil or natural gas futures) or over-the-counter, or OTC, instruments (such as natural gas contracts, crude oil or NGL swaps). The exchange traded instruments are generally executed with a highly rated broker dealer serving as the clearinghouse for individual transactions.

Our activities expose us to varying degrees of commodity price risk. To mitigate a portion of this risk and to manage commodity price risk related primarily to owned natural gas storage and pipeline assets, we engage in natural gas asset based trading and marketing, and we may enter into natural gas and crude oil derivatives to lock in a specific margin when market conditions are favorable. A portion of this may be accomplished through the use of exchange traded derivative contracts. Such instruments are generally classified as Level 1 since the value is equal to the quoted market price of the exchange traded instrument as of our balance sheet date, and no adjustments are required. Depending upon market conditions and our strategy we may enter into exchange traded derivative positions with a significant time horizon to maturity. Although such instruments are exchange traded, market prices 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 it is available; however, in the event that readily observable market data is not available, we may interpolate or extrapolate based upon

15

DCP MIDSTREAM, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three Months Ended March 31, 2017 and 2016 - (Continued)
(Unaudited)

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.

We also engage in the business of trading energy related products and services, which exposes us to market variables and commodity price risk. We may enter into physical contracts or financial instruments with the objective of realizing a positive margin from the purchase and sale of these commodity-based instruments. We may enter into derivative instruments for NGLs or other energy related products, primarily using 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 periodically use interest rate swap agreements as part of our overall capital strategy. These instruments effectively exchange a portion of our fixed-rate debt for floating rate debt or floating rate debt for fixed-rate debt. The swaps are generally priced based upon a London Interbank Offered Rate, or LIBOR, instrument with similar duration, adjusted by the credit spread between our company and the LIBOR instrument. Given that a portion of the swap value is derived from the credit spread, which may be observed by comparing similar assets in the market, these instruments are classified within Level 2. Default risk on either side of the swap transaction is also considered in the valuation. We record counterparty credit and entity valuation adjustments in the valuation of interest rate swaps; however, these reserves are not considered to be a significant input to the overall valuation.
Nonfinancial Assets and Liabilities
We utilize fair value to perform impairment tests as required on our property, plant and equipment, goodwill, and other long-lived intangible assets. Assets and liabilities acquired in third party business combinations are recorded at their fair value as of the date of acquisition. The inputs used to determine such fair value are primarily based upon internally developed cash flow models and would generally be classified within Level 3 in the event that we were required to measure and record such assets at fair value within our condensed consolidated financial statements. Additionally, we use fair value to determine the inception value of our asset retirement obligations. The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition, and would generally be classified within Level 3.




16

DCP MIDSTREAM, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three Months Ended March 31, 2017 and 2016 - (Continued)
(Unaudited)

The following table presents the financial instruments carried at fair value as of March 31, 2017 and December 31, 2016, by condensed consolidated balance sheet caption and by valuation hierarchy, as described above:
 
 
March 31, 2017
 
December 31, 2016
 
Level 1
 
Level 2
 
Level 3
 
Total
Carrying
Value
 
Level 1
 
Level 2
 
Level 3
 
Total
Carrying
Value
 
(Millions)
Current assets:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity derivatives (a)
$
8

 
$
15

 
$
8

 
$
31

 
$
5

 
$
28

 
$
9

 
$
42

Short-term investments (b)
$
175

 
$

 
$

 
$
175

 
$

 
$

 
$

 
$

Long-term assets:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity derivatives (c)
$
1

 
$
1

 
$
2

 
$
4

 
$

 
$

 
$
5

 
$
5

Current liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity derivatives (d)
$
(7
)
 
$
(21
)
 
$
(8
)
 
$
(36
)
 
$
(11
)
 
$
(57
)
 
$
(23
)
 
$
(91
)
Long-term liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity derivatives (e)
$

 
$
(4
)
 
$
(3
)
 
$
(7
)
 
$
(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, 2017 and 2016, 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.


17

DCP MIDSTREAM, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three Months Ended March 31, 2017 and 2016 - (Continued)
(Unaudited)

 
Commodity Derivative Instruments
 
Current
Assets
 
Long-
Term
Assets
 
Current
Liabilities
 
Long-
Term
Liabilities
 
(Millions)
Three months ended March 31, 2017 (a):
 
 
 
 
 
 
 
Beginning balance
$
9

 
$
5

 
$
(23
)
 
$

Net unrealized gains (losses) included in earnings (b)
2

 
(3
)
 
8

 
(3
)
Settlements
(3
)
 

 
7

 

Ending balance
$
8

 
$
2

 
$
(8
)
 
$
(3
)
Net unrealized gains (losses) on derivatives still held included in earnings (b)
$
2

 
$
(2
)
 
$
8

 
$
(3
)
Three months ended March 31, 2016 (a):
 
 
 
 
 
 
 
Beginning balance
$
35

 
$
4

 
$
(23
)
 
$
(6
)
Net unrealized gains (losses) included in earnings (b)
1

 
(2
)
 

 
3

Settlements
(27
)
 

 
6

 

Ending balance
$
9

 
$
2

 
$
(17
)
 
$
(3
)
Net unrealized (losses) gains on derivatives still held included in earnings (b)
$

 
$
(2
)
 
$

 
$
3

 
(a)
There were no purchases, issuances or sales of derivatives or transfers into/out of Level 3 for the three months ended March 31, 2017 and 2016.
(b)
Represents the amount of total gains or losses for the period, included in trading and marketing gains (losses), net.
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.
 
March 31, 2017
 
 
Product Group
Fair Value
 
Forward
Curve Range
 
 
 
(Millions)
 
 
Assets
 
 
 
 
 
NGLs
$
9

 
$0.25-$1.15
 
Per gallon
Natural gas
$
1

 
$2.61-$2.87
 
Per MMBtu
Liabilities
 
 
 
 
 
NGLs
$
(8
)
 
$0.20-$1.15
 
Per gallon
Natural gas
$
(3
)
 
$2.09-$2.72
 
Per MMBtu
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

18

DCP MIDSTREAM, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three Months Ended March 31, 2017 and 2016 - (Continued)
(Unaudited)

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 and junior subordinated notes based on quotes obtained from bond dealers. We determine the fair value of borrowings under our revolving credit facility 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, 2017 and December 31, 2016, the carrying value and fair value of our total debt, including current maturities, were as follows:
 
 
March 31, 2017
 
December 31, 2016
 
 
Carrying Value (a)
 
Fair Value
 
Carrying Value (a)
 
Fair Value
 
(Millions)
 
 
 
 
 
 
 
 
 
Total debt
 
$
5,235

 
$
5,307

 
$
5,430

 
$
5,395

(a) Excludes unamortized issuance costs.

19

DCP MIDSTREAM, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three Months Ended March 31, 2017 and 2016 - (Continued)
(Unaudited)

10. Debt
 
March 31, 
 2017
 
December 31, 
 2016
 
(Millions)
Senior notes:
 
 
 
Issued November 2012, interest at 2.500% payable semi-annually, due December 2017
$
500

 
$
500

Issued February 2009, interest at 9.750% payable semiannually, due March 2019 (a)
450

 
450

Issued March 2014, interest at 2.700% payable semi-annually, due April 2019
325

 
325

Issued March 2010, interest at 5.350% payable semiannually, due March 2020 (a)
600

 
600

Issued September 2011, interest at 4.750% payable semiannually, due September 2021
500

 
500

Issued March 2012, interest at 4.950% payable semi-annually, due April 2022
350

 
350

Issued March 2013, interest at 3.875% payable semi-annually, due March 2023
500

 
500

Issued August 2000, interest at 8.125% payable semi-annually, due August 2030 (a)
300

 
300

Issued October 2006, interest at 6.450% payable semi-annually, due November 2036
300

 
300

Issued September 2007, interest at 6.750% payable semi-annually, due September 2037
450

 
450

Issued March 2014, interest at 5.600% payable semi-annually, due April 2044
400

 
400

Junior subordinated notes:
 
 
 
Issued May 2013, interest at 5.850% payable semi-annually, due May 2043
550

 
550

Credit facility with financial institutions:
 
 
 
Revolving credit facility, weighted-average variable interest rate of 2.010%, as of December 31, 2016, due May 2019

 
195

Fair value adjustments related to interest rate swap fair value hedges (a)
24

 
24

Unamortized issuance costs
(26
)
 
(23
)
Unamortized discount
(14
)
 
(14
)
Total debt
5,209

 
5,407

Current maturities of long-term debt
500

 
500

Total long-term debt
$
4,709

 
$
4,907

(a) The swaps associated with this debt were previously terminated. The remaining long-term fair value of approximately
$24 million related to the swaps is being amortized as a reduction to interest expense through 2019, 2020 and 2030, the original maturity dates of the debt.
Credit Facility with Financial Institutions
In February 2017, we further amended our $1.25 billion senior unsecured revolving credit agreement that matures on May 1, 2019, or the Credit Agreement, to increase the aggregate commitments under the unsecured revolving credit facility to approximately $1.4 billion. The Credit Agreement is used for working capital requirements and other general partnership purposes including acquisitions.

The Credit Agreement allows for unrestricted cash and cash equivalents to be netted against consolidated indebtedness for purposes of calculating the Partnership’s Consolidated Leverage Ratio (as defined in the Credit Agreement). Additionally, under the Credit Agreement, the maximum Consolidated Leverage Ratio of the Partnership as of the end of any fiscal quarter shall not exceed: (a) 5.75 to 1.0 for the quarters ending March 31, 2017 through December 31, 2017, (b) 5.50 to 1.0 for the quarter ending March 31, 2018, (c) 5.25 to 1.0 for the quarter ending June 30, 2018, and (d) 5.00 to 1.0 for the quarters thereafter; provided that, if there is a Qualified Acquisition (as defined in the Credit Agreement) during any fiscal quarter ending June 30, 2018 or thereafter, the maximum Consolidated Leverage Ratio shall not exceed 5.50 to 1.0 at the end of such quarter and at the end of the two fiscal quarters immediately thereafter.

20

DCP MIDSTREAM, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three Months Ended March 31, 2017 and 2016 - (Continued)
(Unaudited)

Our cost of borrowing under the Credit Agreement is determined by a ratings-based pricing grid. Indebtedness under the 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 the 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 Credit Agreement incurs an annual facility fee of 0.3% based on our current credit rating. This fee is paid on drawn and undrawn portions of the approximately $1.4 billion revolving credit facility.
As of March 31, 2017, we had unused borrowing capacity of $1,374 million, net of $24 million of letters of credit, under the Credit Agreement. Our borrowing capacity may be limited by financial covenants set forth in the Credit Agreement. The financial covenants set forth in the Credit Agreement limit the Partnership's ability to incur incremental debt by $1,106 million as of March 31, 2017. Except in the case of a default, amounts borrowed under our Credit Agreement will not become due prior to the May 1, 2019 maturity date.

Senior Notes and Junior Subordinated Notes

Our senior notes and junior subordinated notes, collectively referred to as our debt securities, mature and become payable on the respective due dates, and are not subject to any sinking fund or mandatory redemption provisions. The senior notes are senior unsecured obligations that are guaranteed by the Partnership and rank equally in a right of payment with our other senior unsecured indebtedness, including indebtedness under our credit agreement, and the junior subordinated notes are unsecured and rank subordinate in right of payment to all of our existing and future senior indebtedness. The debt securities include an optional redemption whereby we may elect to redeem the notes, in whole or in part from time-to-time for a premium. Additionally, we may defer the payment of all or part of the interest on the junior subordinated notes for one or more periods up to five consecutive years. The underwriters’ fees and related expenses are recorded in our condensed consolidated balance sheets within the carrying amount of long-term debt and will be amortized over the term of the notes.

 
Debt
Maturities
 
(Millions)
2018
$

2019
775

2020
600

2021
500

2022
350

Thereafter
2,500

Total
$
4,725


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

Our portfolio of commodity derivative activity is primarily accounted for using the mark-to-market method of accounting; however, depending upon our risk profile and objectives, in certain limited cases, we may execute transactions that qualify for the hedge method of accounting. The risks, strategies and instruments used to mitigate such risks, as well as the method of accounting are discussed and summarized below.



21

DCP MIDSTREAM, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three Months Ended March 31, 2017 and 2016 - (Continued)
(Unaudited)

Natural Gas Asset Based Trading and Marketing

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 our natural gas storage facility 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 into 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 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 March 31, 2017.

Commodity 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 may 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. Our derivative financial instruments used to mitigate a portion of the risk of weakening natural gas, NGL and condensate prices extend through the first quarter of 2018. The commodity derivative instruments used for our hedging programs 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 may use crude oil swaps to mitigate a portion of the commodity price risk exposure for 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, certain crude oil derivatives may be converted to NGL derivatives by entering into offsetting crude oil swaps while adding NGL swaps. Crude oil and NGL transactions are primarily accomplished through the use of forward contracts that effectively exchange floating price risk for a fixed price. The type of instrument used to mitigate a portion of the risk may vary depending on our risk management objectives. These transactions are not designated as hedging instruments for accounting purposes and the change in fair value is reflected in the current period within our condensed consolidated statements of operations as trading and marketing gains, net.

22

DCP MIDSTREAM, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three Months Ended March 31, 2017 and 2016 - (Continued)
(Unaudited)


NGL Proprietary Trading

Our NGL proprietary trading activity includes trading energy related products and services. We undertake these activities through the use of fixed forward sales and purchases, basis and spread trades, storage opportunities, put/call options, term contracts and spot market trading. These energy trading operations are exposed to market variables and commodity price risk with respect to these products and services, and these operations may enter into physical contracts and financial instruments with the objective of realizing a positive margin from the purchase and sale of commodity-based instruments. These physical and financial instruments 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.

We employ established risk limits, policies and procedures to manage risks associated with our natural gas asset based trading and marketing and NGL proprietary trading.

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.

We previously had interest rate cash flow hedges and fair value hedges in place that were terminated. As the underlying transactions impact earnings, the remaining net loss deferred in AOCI relative to these cash flow hedges will be reclassified to interest expense, net from 2022 through 2030 and the remaining net loss included in long-term debt relative to these fair value hedges will be reclassified to interest expense, net from 2019 through 2030, the original maturity dates of the debt.

Credit Risk

Our principal customers range from large, natural gas marketers to industrial end-users for our natural gas products and services, as well as large multi-national petrochemical and refining companies, to small regional propane distributors for our NGL products and services. Substantially all of our natural gas and NGL sales are made at market-based prices. Approximately 26% of our NGL production was committed to Phillips 66 and CPChem as of March 31, 2017. This concentration of credit risk may affect our overall credit risk, in that these customers may be similarly affected by changes in economic, regulatory or other factors. Where exposed to credit risk, we analyze the counterparties’ financial condition prior to entering into an agreement, establish credit limits and monitor the appropriateness of these limits on an ongoing basis. We may use various master agreements that include language giving us the right to request collateral to mitigate credit exposure. The collateral language provides for a counterparty to post cash or letters of credit for exposure in excess of the established threshold. The threshold amount represents an open credit limit, determined in accordance with our credit policy. The collateral language also provides that the inability to post collateral is sufficient cause to terminate a contract and liquidate all positions. In addition, our master agreements and our standard gas and NGL sales contracts contain adequate assurance provisions, which allow us to suspend deliveries and cancel agreements, or continue deliveries to the buyer after the buyer provides security for payment in a satisfactory form.
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 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.

23

DCP MIDSTREAM, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three Months Ended March 31, 2017 and 2016 - (Continued)
(Unaudited)

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 Credit Agreement. As of March 31, 2017, 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, 2017, 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, 2017, 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.
Collateral
As of March 31, 2017, we had cash deposits of $38 million, included in other current assets in our condensed consolidated balance sheets, and letters of credit of $13 million with counterparties to secure our obligations to provide future services or to perform under financial contracts. Additionally, as of March 31, 2017, we held cash of $5 million, included in other current liabilities in our condensed consolidated balance sheet, related to cash postings by third parties and letters of credit of $31 million from counterparties to secure their future performance under financial or physical contracts. Collateral amounts held or posted may be fixed or may vary, depending on the value of the underlying contracts, and could cover normal purchases and sales, services, trading and hedging contracts. In many cases, we and our counterparties have publicly disclosed credit ratings, which may impact the amounts of collateral requirements.
Physical forward contracts and financial derivatives are generally cash settled at the expiration of the contract term. These transactions are generally subject to specific credit provisions within the contracts that would allow the seller, at its discretion, to suspend deliveries, cancel agreements or continue deliveries to the buyer after the buyer provides security for payment satisfactory to the seller.
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:
 

24

DCP MIDSTREAM, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three Months Ended March 31, 2017 and 2016 - (Continued)
(Unaudited)

 
March 31, 2017
 
December 31, 2016
 
Gross Amounts
of Assets and
(Liabilities)
Presented in the
Balance Sheet
 
Amounts Not
Offset in the
Balance Sheet -
Financial
Instruments
 
Net
Amount
 
Gross Amounts
of Assets and
(Liabilities)
Presented in the
Balance Sheet
 
Amounts Not
Offset in the
Balance Sheet -
Financial
Instruments
 
Net
Amount
 
(Millions)
Assets:
 
 
 
 
 
 
 
 
 
 
 
Commodity derivatives
$
35

 
$

 
$
35

 
$
47

 
$

 
$
47

Liabilities:
 
 
 
 
 
 
 
 
 
 
 
Commodity derivatives
$
(43
)
 
$

 
$
(43
)
 
$
(92
)
 
$

 
$
(92
)
 
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, 2017 and December 31, 2016.
 
Balance Sheet Line Item
March 31, 
 2017
 
December 31, 
 2016
 
Balance Sheet Line Item
 
March 31, 
 2017
 
December 31, 
 2016
 
(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
$
31

 
$
42

 
Unrealized losses on derivative instruments — current
 
$
(36
)
 
$
(91
)
Unrealized gains on derivative instruments — long-term
4

 
5

 
Unrealized losses on derivative instruments — long-term
 
(7
)
 
(1
)
Total
$
35

 
$
47

 
Total
 
$
(43
)
 
$
(92
)
 
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, 2017:
 
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
1

 

 

 

 
1

Deficit purchase price under carrying value of the Transaction
$
(2
)
 
 
 
$

 
$

 
$
(2
)
Net deferred (losses) gains in AOCI (ending balance)
$
(4
)
 
 
 
$
(6
)
 
$
1

 
$
(9
)
(a)
Relates to Discovery, an unconsolidated affiliate.

For the three months ended March 31, 2017, no derivative losses attributable to the ineffective portion or to amounts excluded from effectiveness testing were recognized in trading and marketing gains, net or interest expense in our condensed consolidated statements of operations. For the three months ended March 31, 2017, no derivative losses were reclassified from

25

DCP MIDSTREAM, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three Months Ended March 31, 2017 and 2016 - (Continued)
(Unaudited)

AOCI to trading and marketing gains, 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.


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 trading and marketing gains or losses, 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 trading and marketing gains or losses, 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 the 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,
 
 
2017
 
2016
 
(Millions)
Realized (losses) gains
 
$
(5
)
 
$
63

Unrealized gains (losses)
 
36

 
(45
)
Trading and marketing gains, net
 
$
31

 
$
18

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. 

26

DCP MIDSTREAM, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three Months Ended March 31, 2017 and 2016 - (Continued)
(Unaudited)

 
March 31, 2017
 
Crude Oil
 
Natural Gas
 
Natural Gas
Liquids
 
Natural Gas
Basis Swaps
Year of Expiration
Net Short
Position
(Bbls)
 
Net (Short) Long
Position
(MMBtu)
 
Net (Short) Long
Position
(Bbls)
 
Net Long
Position
(MMBtu)
2017
(1,004,000
)
 
(48,928,700
)
 
(16,786,124
)
 
5,662,500

2018
(416,000
)
 
50,000

 
(156,537
)
 
3,192,500

2019
(40,000
)
 

 
(2,203
)
 

2020
(50,000
)
 

 
240,000

 

 
 
 
 
 
 
 
 
 
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) Long
Position
(Bbls)
 
Net (Short) Long
Position
(MMBtu)
2016
(1,060,000
)
 
(20,743,700
)
 
(18,260,483
)
 
(1,750,000
)
2017
(292,000
)
 
(13,717,500
)
 
(2,467,393
)
 
5,670,000

2018

 

 
145,500

 

12. Partnership Equity and Distributions
In January 2017, we issued 28,552,480 common units to DCP Midstream, LLC and 2,550,644 general partner units to the General Partner in a private placement as consideration for the Transaction that closed on January 1, 2017. For additional information regarding the Transaction, see Note 3 - Acquisitions.
During the three months ended March 31, 2017 and 2016, we issued no common units pursuant to our 2014 equity distribution agreement. As of March 31, 2017, approximately $349 million of common units remained available for sale pursuant to our 2014 equity distribution agreement.
The following table presents our cash distributions paid in 2017 and 2016:
Payment Date
Per Unit
Distribution
 
Total Cash
Distribution
 
 
 
(Millions)
February 14, 2017
$
0.78

 
$
121

November 14, 2016
$
0.78

 
$
120

August 12, 2016
$
0.78

 
$
121

May 13, 2016
$
0.78

 
$