Annual Reports

 
Quarterly Reports

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

 
8-K

 
Other

DCP Midstream Partners, LP 10-Q 2009
Form 10-Q
Table of Contents

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM 10-Q

 

 

(Mark One)

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

For the quarterly period ended June 30, 2009

or

 

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

For the transition period from              to             

Commission File Number: 001-32678

 

 

DCP MIDSTREAM PARTNERS, LP

(Exact name of registrant as specified in its charter)

 

 

 

Delaware   03-0567133

(State or other jurisdiction of

incorporation or organization)

 

(I.R.S. Employer

Identification No.)

 

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

Registrant’s telephone number, including area code: (303) 633-2900

 

 

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

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

 

Large accelerated filer   ¨    Accelerated filer   x
Non-accelerated filer   ¨    Smaller reporting company   ¨

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

As of August 3, 2009, there were outstanding 28,233,183 common limited partner units and 3,500,000 Class D units.

 

 

 


Table of Contents

DCP MIDSTREAM PARTNERS, LP

FORM 10-Q FOR THE QUARTER ENDED JUNE 30, 2009

TABLE OF CONTENTS

 

Item

        Page
   PART I. FINANCIAL INFORMATION   

1.

   Financial Statements (unaudited):   
  

Condensed Consolidated Balance Sheets as of June 30, 2009 and December 31, 2008

   1
  

Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2009 and 2008

   2
  

Condensed Consolidated Statements of Comprehensive Loss for the Three and Six Months Ended June 30, 2009 and 2008

   3
  

Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2009 and 2008

   4
  

Condensed Consolidated Statements of Changes in Equity for the Six Months Ended June 30, 2009 and 2008

   5
  

Notes to the Condensed Consolidated Financial Statements

   6

2.

   Management’s Discussion and Analysis of Financial Condition and Results of Operations    34

3.

   Quantitative and Qualitative Disclosures about Market Risk    61

4.

   Controls and Procedures    64
   PART II. OTHER INFORMATION   

1.

   Legal Proceedings    65

1A.

   Risk Factors    65

6.

   Exhibits    68
   Signatures    71
   Exhibit Index    72
   Certification of Chief Executive Officer Pursuant to Section 302   
   Certification of Chief Financial Officer Pursuant to Section 302   
   Certification of Chief Executive Officer Pursuant to Section 906   
   Certification of Chief Financial Officer Pursuant to Section 906   

 

i


Table of Contents

GLOSSARY OF TERMS

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

 

Bbls     

barrels

Bbls/d     

barrels per day

Btu     

British thermal unit, a measurement of energy

Frac spread     

price differences, measured in energy units, between equivalent amounts of natural gas and natural gas liquids

Fractionation     

the process by which natural gas liquids are separated into individual components

MMBtu     

one million British thermal units, a measurement of energy

MMcf/d     

one million cubic feet per day

NGLs     

natural gas liquids

Throughput     

the volume of product transported or passing through a pipeline or other facility

 

ii


Table of Contents

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,” “project,” “believe,” “anticipate,” “expect,” “estimate,” “potential,” “plan,” “forecast” and other similar words.

All statements that are not statements of historical facts, including 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, 2008, as well as the following risks and uncertainties:

 

   

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

 

   

general economic, market and business conditions;

 

   

the level and success of natural gas drilling around our assets, the level of gas production volumes around our assets and our ability to connect supplies to our gathering and processing systems in light of competition;

 

   

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

 

   

our ability to access the debt and equity markets, which will depend on general market conditions, inflation rates, interest rates and our ability to effectively limit a portion of the adverse effects of potential changes in interest rates by entering into derivative financial instruments, and our ability to comply with the covenants to our credit agreement;

 

   

our ability to purchase propane from our principal suppliers for our wholesale propane logistics business;

 

   

our ability to construct facilities in a timely fashion, which is partially dependent on obtaining required building, 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 supplies;

 

   

the creditworthiness of counterparties to our transactions;

 

   

weather and other natural phenomena, including their potential impact on demand for the commodities we sell and the operation of company owned and third-party-owned infrastructure;

 

   

changes in laws and regulations, particularly with regard to taxes, safety and protection of the environment, including climate change legislation, or the increased regulation of our industry;

 

   

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

 

   

industry changes, including the impact of consolidations, increased delivery of liquefied natural gas to the United States, alternative energy sources, technological advances and changes in competition; and

 

   

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

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. We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

 

iii


Table of Contents

PART I. FINANCIAL INFORMATION

 

Item 1. Financial Statements

DCP MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

 

     June 30,
2009
    December 31,
2008
 
     (Millions)  
ASSETS     

Current assets:

    

Cash and cash equivalents

   $ 4.6      $ 61.9   

Accounts receivable:

    

Trade, net of allowance for doubtful accounts of $0.8 million and $1.0 million, respectively

     35.2        58.8   

Affiliates

     57.6        57.5   

Inventories

     16.9        20.9   

Unrealized gains on derivative instruments

     5.9        15.4   

Other

     1.7        0.9   
                

Total current assets

     121.9        215.4   

Restricted investments

     35.1        60.2   

Property, plant and equipment, net

     973.9        882.7   

Goodwill

     89.1        88.8   

Intangible assets, net

     46.0        47.7   

Equity method investments

     117.0        111.5   

Unrealized gains on derivative instruments

     3.8        8.6   

Other long-term assets

     4.6        4.8   
                

Total assets

   $ 1,391.4      $ 1,419.7   
                
LIABILITIES AND EQUITY     

Current liabilities:

    

Accounts payable:

    

Trade

   $ 57.3      $ 71.6   

Affiliates

     13.4        36.0   

Unrealized losses on derivative instruments

     25.7        17.7   

Accrued interest payable

     0.8        1.3   

Other

     33.3        36.6   
                

Total current liabilities

     130.5        163.2   

Long-term debt

     638.0        656.5   

Unrealized losses on derivative instruments

     43.6        26.0   

Other long-term liabilities

     13.8        11.2   
                

Total liabilities

     825.9        856.9   
                

Commitments and contingent liabilities

    

Equity:

    

Predecessor equity

     —          66.0   

Common unitholders (28,233,183 and 24,661,754 units issued and outstanding, respectively)

     320.5        429.0   

Class D unitholders (3,500,000 and 0 units issued and outstanding, respectively)

     67.7        —     

Subordinated unitholders (0 and 3,571,429 convertible units issued and outstanding, respectively)

     —          (54.6

General partner interest

     (5.6     (4.8

Accumulated other comprehensive loss

     (31.0     (40.5
                

Total partners’ equity

     351.6        395.1   

Noncontrolling interests

     213.9        167.7   
                

Total equity

     565.5        562.8   
                

Total liabilities and equity

   $ 1,391.4      $ 1,419.7   
                

See accompanying notes to condensed consolidated financial statements.

 

1


Table of Contents

DCP MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

 

     Three Months Ended
June 30,
    Six Months Ended
June 30,
 
     2009     2008     2009     2008  
     (Millions, except per unit amounts)  

Operating revenues:

        

Sales of natural gas, propane, NGLs and condensate

   $ 71.8      $ 236.2      $ 229.0      $ 532.3   

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

     101.9        274.6        201.8        475.7   

Transportation, processing and other

     20.7        9.5        37.4        22.4   

Transportation, processing and other to affiliates

     3.5        11.3        7.1        17.6   

Losses from commodity derivative activity, net

     (44.0     (184.9     (36.3     (222.7

Losses from commodity derivative activity, net — affiliates

     (1.9     (2.4     (2.6     (1.7
                                

Total operating revenues

     152.0        344.3        436.4        823.6   
                                

Operating costs and expenses:

        

Purchases of natural gas, propane and NGLs

     110.6        397.5        248.4        746.8   

Purchases of natural gas, propane and NGLs from affiliates

     37.7        48.9        116.8        130.8   

Operating and maintenance expense

     17.1        19.3        33.3        37.3   

Depreciation and amortization expense

     16.3        13.0        30.9        25.7   

General and administrative expense

     2.0        3.0        5.2        5.5   

General and administrative expense — affiliates

     5.1        4.8        10.5        9.9   

Other, net

     —          (1.5     —          (1.5
                                

Total operating costs and expenses

     188.8        485.0        445.1        954.5   
                                

Operating loss

     (36.8     (140.7     (8.7     (130.9

Interest income

     0.1        2.0        0.3        3.7   

Interest expense

     (7.0     (7.9     (14.3     (16.0

Earnings from equity method investments

     3.7        7.1        2.6        17.8   
                                

Loss before income taxes

     (40.0     (139.5     (20.1     (125.4

Income tax expense

     —          (0.3     (0.1     (0.6
                                

Net loss

     (40.0     (139.8     (20.2     (126.0

Net (income) loss attributable to noncontrolling interests

     (2.1     (13.3     (0.8     (27.0
                                

Net loss attributable to partners

     (42.1     (153.1     (21.0     (153.0

Net (income) loss attributable to predecessor operations

     —          (6.2     1.0        (12.8

General partner interest in net income or net loss

     (2.7     (0.7     (5.9     (3.4
                                

Net loss allocable to limited partners

   $ (44.8   $ (160.0   $ (25.9   $ (169.2
                                

Net loss per limited partner unit — basic and diluted

   $ (1.41   $ (5.67   $ (0.86   $ (6.36
                                

Weighted-average limited partner units outstanding — basic and diluted

     31.7        28.2        30.0        26.6   

See accompanying notes to condensed consolidated financial statements.

 

2


Table of Contents

DCP MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS

(Unaudited)

 

     Three Months Ended
June 30,
    Six Months Ended
June 30,
 
     2009     2008     2009     2008  
     (Millions)  

Net loss

   $ (40.0   $ (139.8   $ (20.2   $ (126.0
                                

Other comprehensive income:

        

Reclassification of cash flow hedges into earnings

     4.7        2.3        9.2        2.7   

Net unrealized gains (losses) on cash flow hedges

     4.8        12.6        0.3        (1.1
                                

Total other comprehensive income

     9.5        14.9        9.5        1.6   
                                

Total comprehensive loss

     (30.5     (124.9     (10.7     (124.4

Total comprehensive income attributable to noncontrolling interests

     (2.1     (13.3     (0.8     (27.0
                                

Total comprehensive loss attributable to partners

   $ (32.6   $ (138.2   $ (11.5   $ (151.4
                                

See accompanying notes to condensed consolidated financial statements.

 

3


Table of Contents

DCP MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

 

     Six Months Ended
June 30,
 
     2009     2008  
     (Millions)  

OPERATING ACTIVITIES:

    

Net loss

   $ (20.2   $ (126.0

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

    

Depreciation and amortization expense

     30.9        25.7   

Earnings from equity method investments, net of distributions

     0.4        4.0   

Other, net

     (0.2     (1.0

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

    

Accounts receivable

     22.8        (23.0

Inventories

     4.0        (2.0

Net unrealized losses on derivative instruments

     54.0        198.9   

Accounts payable

     (38.0     16.7   

Accrued interest

     (0.5     (0.8

Other current assets and liabilities

     (2.3     (21.4

Other long-term assets and liabilities

     0.4        (0.3
                

Net cash provided by operating activities

     51.3        70.8   
                

INVESTING ACTIVITIES:

    

Capital expenditures

     (118.4     (31.2

Acquisition of Michigan Pipeline & Processing, LLC

     (0.1     —     

Acquisition of subsidiaries of Momentum Energy Group, Inc

     —          (10.9

Investments in equity method investments

     (5.8     (1.9

Proceeds from sale of assets

     0.3        —     

Purchases of available-for-sale securities

     (1.1     (461.9

Proceeds from sales of available-for-sale securities

     26.1        341.9   
                

Net cash used in investing activities

     (99.0     (164.0
                

FINANCING ACTIVITIES:

    

Proceeds from debt

     68.3        432.0   

Payments of debt

     (86.8     (402.0

Proceeds from issuance of common units, net of offering costs

     —          132.1   

Net change in advances to predecessor from DCP Midstream, LLC

     3.0        (12.6

Distributions to unitholders and general partner

     (40.2     (35.8

Distributions to noncontrolling interests

     (4.9     (34.6

Contributions from noncontrolling interests

     50.3        9.3   

Contributions from DCP Midstream, LLC

     0.7        1.9   
                

Net cash (used in) provided by financing activities

     (9.6     90.3   
                

Net change in cash and cash equivalents

     (57.3     (2.9

Cash and cash equivalents, beginning of period

     61.9        29.3   
                

Cash and cash equivalents, end of period

   $ 4.6      $ 26.4   
                

See accompanying notes to condensed consolidated financial statements.

 

4


Table of Contents

DCP MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(Unaudited)

 

    Partners’ Equity              
    Predecessor
Equity
    Common
Unitholders
    Class D
Unitholders
    Subordinated
Unitholders
    General
Partner
Interest
    Accumulated
Other
Comprehensive
Income (Loss)
    Noncontrolling
Interests
    Total
Equity
 
    (Millions)  

Balance, January 1, 2009

  $ 66.0      $ 429.0      $ —        $ (54.6   $ (4.8   $ (40.5   $ 167.7      $ 562.8   

Net change in parent advances

    3.0        —          —          —          —          —          —          3.0   

Conversion of subordinated units to common units

    —          (52.1     —          52.1        —          —          —          —     

Distributions to unitholders and general partner

    —          (31.7     —          (2.1     (6.4     —          —          (40.2

Distributions to noncontrolling interests

    —          —          —          —          —          —          (4.9     (4.9

Contributions from DCP Midstream, LLC

    —          0.7        —          —          —          —          —          0.7   

Contributions from noncontrolling interests

    —          —          —          —          —          —          50.3        50.3   

Other

    —          (0.1     —          —          —          —          —          (0.1

Issuance of 3,500,000 Class D units

    —          —          49.7        —          —          —          —          49.7   

Acquisition of additional 25.1% interest in East Texas and the NGL Hedge

    (68.0     —          4.6        —          —          —          —          (63.4

Deficit purchase price over acquired assets

    —          —          18.3        —          —          —          —          18.3   
                                                               

Comprehensive income:

               

Net loss attributable to predecessor operations

    (1.0     —          —          —          —          —          —          (1.0

Net (loss) income

    —          (25.3     (4.9     4.6        5.6        —          0.8        (19.2

Reclassification of cash flow hedges into earnings

    —          —          —          —          —          9.2        —          9.2   

Net unrealized gains on cash flow hedges

    —          —          —          —          —          0.3        —          0.3   
                                                               

Total comprehensive (loss) income

    (1.0     (25.3     (4.9     4.6        5.6        9.5        0.8        (10.7
                                                               

Balance, June 30, 2009

  $ —        $ 320.5      $ 67.7      $ —        $ (5.6   $ (31.0   $ 213.9      $ 565.5   
                                                               

Balance, January 1, 2008

  $ 64.0      $ 308.8      $ —        $ (120.1   $ (5.4   $ (14.9   $  155.1      $ 387.5   

Net change in parent advances

    (12.6     —          —          —          —          —          —          (12.6

Conversion of subordinated units to common units

    —          (66.4     —          66.4        —          —          —          —     

Distributions to unitholders and general partner

    —          (24.2     —          (6.2     (4.9     —          —          (35.3

Distributions to noncontrolling interests

    —          —          —          —          —          —          (34.6     (34.6

Contributions from DCP Midstream, LLC

    —          1.8        —          —          —          —          —          1.8   

Contributions from noncontrolling interests

    —          —          —          —          —          —          9.3        9.3   

Equity-based compensation

    —          0.1        —          —          —          —          —          0.1   

Issuance of 4,250,000 common units

    —          132.1        —          —          —          —          —          132.1   
                                                               

Comprehensive income:

               

Net income attributable to predecessor operations

    12.8        —          —          —          —          —          —          12.8   

Net (loss) income

    —          (142.0     —          (26.0     2.2        —          27.0        (138.8

Reclassification of cash flow hedges into earnings

    —          —          —          —          —          2.7        —          2.7   

Net unrealized losses on cash flow hedges

    —          —          —          —          —          (1.1     —          (1.1
                                                               

Total comprehensive (loss) income

    12.8        (142.0     —          (26.0     2.2        1.6        27.0        (124.4
                                                               

Balance, June 30, 2008

  $ 64.2      $ 210.2      $ —        $ (85.9   $ (8.1   $ (13.3   $ 156.8      $ 323.9   
                                                               

See accompanying notes to condensed consolidated financial statements.

 

5


Table of Contents

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

1. Description of Business and Basis of Presentation

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

We are a Delaware master limited partnership that was formed in August 2005. We completed our initial public offering on December 7, 2005. Our partnership includes: our Northern Louisiana system; our Southern Oklahoma system; our limited liability company interest in Discovery Producer Services LLC, or Discovery; our Wyoming system and a 70% interest in our Colorado system; our 50.1% interest in our East Texas system; our Michigan systems (acquired in October 2008); our wholesale propane logistics business; and our NGL transportation pipelines.

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, which is wholly-owned by DCP Midstream, LLC. DCP Midstream, LLC and its subsidiaries and affiliates, collectively referred to as DCP Midstream, LLC, is owned 50% by Spectra Energy Corp, or Spectra Energy, and 50% by ConocoPhillips. DCP Midstream, LLC directs our business operations through its ownership and control of the General Partner. DCP Midstream, LLC and its affiliates’ employees provide administrative support to us and operate our assets. DCP Midstream, LLC owns approximately 38% of our partnership.

In April 2009, we acquired an additional 25.1% interest in DCP East Texas Holdings, LLC, or East Texas, and a fixed price natural gas liquids derivative by NGL component for the period of April 2009 to March 2010, or NGL Hedge, from DCP Midstream, LLC, in a transaction among entities under common control. Our East Texas system includes a natural gas processing complex with a total capacity of 780 MMcf/d and an NGL fractionator, which serves as the processing facility for our 900-mile gathering system, as well as third party gathering systems. The complex is adjacent to our Carthage Hub, which delivers gas to interstate and intrastate pipelines. The Carthage Hub, with an aggregate delivery capacity of 1.5 billion cubic feet per day, acts as a key exchange point for the purchase and sale of residue gas. Transfers of net assets or exchanges of units between entities under common control are accounted for as if the transfer occurred at the beginning of the period, and prior years are retroactively adjusted to furnish comparative information similar to the pooling method. Accordingly, these condensed consolidated financial statements include the historical results of East Texas for all periods presented. The NGL Hedge was entered into on the date of the transaction. Accordingly these condensed consolidated financial statements include the results of the NGL Hedge prospectively from April 1, 2009. Prior to this transaction we owned a 25.0% limited liability company interest in East Texas, which we accounted for under the equity method of accounting. Subsequent to this transaction we own a 50.1% interest in East Texas, and account for East Texas as a consolidated subsidiary. The $18.3 million deficit purchase price under the historical basis of the net acquired assets was recorded as an increase in partners’ equity, and the $49.7 million of Class D units issued as consideration for this transaction was recorded as an increase in partners’ equity. The Class D units will convert into the Partnership’s Common units on a one for one basis on August 17, 2009.

The results of operations of our Michigan systems have been included in the condensed consolidated financial statements since October 1, 2008, the date of acquisition.

The condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP. We refer to the assets, liabilities and operations of East Texas prior to our acquisition of an additional 25.1% from DCP Midstream, LLC in April 2009, collectively as our “predecessor.” The condensed consolidated financial statements of our predecessor have been prepared from the separate records maintained by DCP Midstream, LLC and may not necessarily be indicative of the conditions that would have existed or the results of operations if our predecessor had been operated as an unaffiliated entity.

The accompanying unaudited condensed consolidated financial statements in this Quarterly Report on Form 10-Q have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission, or SEC. Accordingly, these condensed consolidated financial statements reflect all normal recurring adjustments that are, in the opinion of management, necessary to present fairly the financial position and results of operations for the respective interim periods. Certain information and notes normally included in our annual financial statements have been condensed or omitted from these interim financial statements pursuant to such rules and regulations. These condensed consolidated financial statements and other information included in this Quarterly Report on Form 10-Q should be read in conjunction with the consolidated financial statements and notes thereto included in our 2008 Form 10-K.

 

6


Table of Contents

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

2. Summary of Significant Accounting Policies

Noncontrolling Interest Noncontrolling interest represents (1) the noncontrolling interest holders’ ownership interest in the net assets of Collbran Valley Gas Gathering, a joint venture acquired in August 2007; (2) the noncontrolling interest holders’ ownership interest in the net assets of Jackson Pipeline Company, a partnership we acquired in October 2008; and (3) DCP Midstream, LLC’s ownership interest in the net assets of East Texas. For financial reporting purposes, the assets and liabilities of these entities are consolidated with those of our own, with any third party or affiliate interest in our consolidated balance sheet amounts shown as noncontrolling interest in equity. Distributions to and contributions from noncontrolling interests represent cash payments to and cash contributions from, respectively, such third party and affiliate investors.

3. Recent Accounting Pronouncements

Financial Accounting Standards Board, or FASB, Statement of Financial Accounting Standards, or SFAS, No. 168 “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles – a Replacement of FASB Statement No. 162,” or SFAS 168 — In June 2009, the FASB issued SFAS 168, which establishes the FASB Accounting Standards Codification, or the Codification, as the source of authoritative U.S. Generally Accepted Accounting Principles, or GAAP. The Codification supersedes all existing non-SEC accounting and reporting standards. This SFAS becomes effective for us for annual and interim periods beginning after September 15, 2009 and will not affect our condensed consolidated results of operations, cash flows and financial position as a result of adoption.

SFAS No. 167 “Amendments to FASB Interpretation No. 46(R),” or SFAS 167 — In June 2009, the FASB issued SFAS 167, which requires entities to perform additional analysis of their variable interest entities and consolidation methods. This SFAS becomes effective for us on January 1, 2010 and we are in the process of assessing the impact of this guidance on our condensed consolidated results of operations, cash flows and financial position.

SFAS No. 165 “Subsequent Events,” or SFAS 165 — In May 2009, the FASB issued SFAS 165, which sets forth the recognition and disclosure requirements for events that occur after the balance sheet date, but before financial statements are issued or are available to be issued. We adopted SFAS 165 effective June 30, 2009, and there was no effect on our condensed consolidated results of operations, cash flows or financial position as a result of adoption. All appropriate disclosure of subsequent events is made within the footnotes.

SFAS No. 161 “Disclosures about Derivative Instruments and Hedging Activities — an Amendment of FASB Statement No. 133,” or SFAS 161 — In March 2008, the FASB issued SFAS 161, which requires disclosures of how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for and how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. We adopted the provisions of SFAS 161 effective January 1, 2009, and have included all required disclosures in this filing. SFAS 161 impacts only disclosures so there was no effect on our condensed consolidated results of operations, cash flows or financial position as a result of adoption.

SFAS No. 160 “Noncontrolling Interests in Consolidated Financial Statements — an Amendment of Accounting Research Bulletin No. 51,” or SFAS 160 — In December 2007, the FASB issued SFAS 160, which establishes accounting and reporting standards for ownership interests in subsidiaries held by parties other than the parent, the amount of consolidated net income attributable to the parent and to the noncontrolling interest, changes in a parent’s ownership interest and the valuation of retained noncontrolling equity investments when a subsidiary is deconsolidated. SFAS 160 also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners. We adopted SFAS 160 effective January 1, 2009, which required retrospective restatement of our condensed consolidated financial statements for all periods presented in this filing. As a result of adoption, we have reclassified our noncontrolling interest on our condensed consolidated balance sheets, from a component of liabilities to a component of equity and have also reclassified net income attributable to noncontrolling interest on our condensed consolidated statements of operations, to below net income for all periods presented. Furthermore, we have displayed the portion of other comprehensive income that is attributable to the noncontrolling interest within our condensed consolidated statements of comprehensive income. We also added a rollforward of the noncontrolling interest within our condensed consolidated statements of changes in partners’ equity and will present this financial statement on a quarterly basis.

 

7


Table of Contents

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

SFAS No. 141(R) “Business Combinations (revised 2007),” or SFAS 141(R) — In December 2007, the FASB issued SFAS 141(R), which requires the acquiring entity in a business combination subsequent to January 1, 2009 to recognize all (and only) the assets acquired and liabilities assumed in the transaction; establishes the acquisition-date fair value as the measurement objective for all assets acquired and liabilities assumed; and requires the acquirer to disclose to investors and other users all of the information they need to evaluate and understand the nature and financial effect of the business combination. We adopted SFAS 141(R) effective January 1, 2009, and will account for all transactions with closing dates subsequent to adoption in accordance with the provisions of this standard.

SFAS No. 157 “Fair Value Measurements,” or SFAS 157 — In September 2006, the FASB issued SFAS 157, which we adopted on January 1, 2008 for all financial assets and liabilities. Pursuant to FASB Staff Position, or FSP, 157-2, the FASB issued a partial deferral, ending on December 31, 2008, of the implementation of SFAS 157 as it relates to all nonfinancial assets and liabilities where fair value is the required measurement attribute by other accounting standards. Effective January 1, 2009, we adopted SFAS 157 for all nonfinancial assets and liabilities. There was no effect on our condensed consolidated results of operations, cash flows, or financial position, and we have included all required disclosures as a result of the adoption of this standard relative to nonfinancial assets and liabilities. The provisions of SFAS 157 will be applied at such time a fair value measurement of a nonfinancial asset or nonfinancial liability is required, which may result in a fair value that is different than would have been calculated prior to the adoption of SFAS 157.

FSP No. SFAS 142-3 “Determination of the Useful Life of Intangible Assets,” or FSP 142-3 — In April 2008, the FASB issued FSP 142-3, which amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of an intangible asset. We adopted FSP 142-3 on January 1, 2009. As a result of acquisitions, we have intangible assets for customer contracts and related relationships in our condensed consolidated balance sheets. Generally, costs to renew or extend such contracts are not significant, and are expensed to the condensed consolidated statements of operations as incurred. During the current quarter, there were no contracts that were recognized as intangible assets that were renewed or extended.

FSP No. SFAS 157-4 “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly,” or FSP 157-4 — In April 2009, the FASB issued FSP 157-4, which provides additional guidance on the valuation of assets or liabilities that are held in markets that have seen a significant decline in activity. While this FSP does not change the overall objective of determining fair value, it emphasizes that in markets with significantly decreased activity and the appearance of non-orderly transactions, an entity may employ multiple valuation techniques, to which significant adjustments may be required, to determine the most appropriate fair value. Certain of the markets in which we transact have seen a decrease in overall volume; however, we believe that these markets continue to provide sufficient liquidity such that transactions are executed in an orderly manner at fair value. We have adopted this FSP as of June 30, 2009 and there was no impact on our condensed consolidated results of operations, cash flows or financial position.

FSP No. SFAS 141(R)-1 “Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies,” or FSP 141(R)-1 — In April 2009, the FASB issued FSP 141(R)-1, which provides additional guidance on the valuation of assets and liabilities assumed in a business combination that arise from contingencies, which would otherwise be subject to the provisions of SFAS No. 5 “Accounting for Contingencies,” or SFAS 5. This FSP emphasizes the guidance set forth in SFAS 141(R) that assets and liabilities assumed in a business combination that have an estimated fair value should be recorded at the time of acquisition. Assets and liabilities where the fair value may not be determinable during the measurement period will continue to be recognized pursuant to SFAS 5. This FSP becomes effective for us for business combinations with closing dates subsequent to January 1, 2009. During the first two quarters of 2009 we did not have any transactions that were accounted for as business combinations. We will account for any business combinations with closing dates subsequent to the effective date in accordance with this new guidance.

FSP No. SFAS 107-1 and APB 28-1 “Interim Disclosures about Fair Value of Financial Instruments” — This FSP was issued in April 2009, and requires disclosure of summarized financial information for financial instruments accounted for under SFAS No. 107 “Disclosures about Fair Value of Financial Instruments,” or SFAS 107. We have instruments that are subject to the fair value disclosure requirements of SFAS 107, and are subject to the revised disclosure provisions of this FSP. We have adopted this FSP as of June 30, 2009 and there was no impact on our condensed consolidated results of operations, cash flows or financial position.

 

8


Table of Contents

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

FSP No. SFAS 115-2 and SFAS 124-2 “Recognition and Presentation of Other-Than-Temporary Impairments” — This FSP was issued in April 2009, and amends the other-than-temporary impairment guidance for debt securities to make the guidance more operational and to improve the presentation and disclosure of other-than-temporary impairments on debt and equity securities in the financial statements. We have adopted this FSP as of June 30, 2009 and there was no impact on our condensed consolidated results of operations, cash flows or financial position.

Emerging Issues Task Force, or EITF, 08-6 “Equity Method Investment Accounting Considerations,” or EITF 08-6 — In November 2008 the EITF issued EITF 08-6. Although the issuance of SFAS 141(R) and SFAS 160 were not intended to reconsider the accounting for equity method investments, the application of the equity method is affected by the issuance of these standards. This issue addresses a) how the initial carrying value of an equity method investment should be determined; b) how impairment assessment of an underlying indefinite-lived intangible asset of an equity method investment should be performed; c) how an equity method investee’s issuance of shares should be accounted for; and d) how to account for a change in an investment from the equity method to the cost method. This issue became effective for us on January 1, 2009, and although it has not impacted the manner in which we apply equity method accounting, this guidance will be considered on a prospective basis to transactions with equity method investees.

EITF 07-4 “Application of the Two-Class Method under FASB Statement No. 128 to Master Limited Partnerships” or EITF 07-4 — In March 2008, the EITF issued EITF 07-4. This issue seeks to improve the comparability of earnings per unit, or EPU, calculations for master limited partnerships with incentive distribution rights in accordance with FASB Statement No. 128 and its related interpretations. We adopted EITF 07-4 effective January 1, 2009. As a result of adopting EITF 07-4, undistributed earnings or losses are reduced or increased, respectively, by the amount of available cash that was generated during the current period, and undistributed earnings are no longer allocated to our general partner with respect to its incentive distribution rights, as our partnership agreement specifically limits incentive distributions to available cash. EITF 07-4 is applied retrospectively for all periods. We have retrospectively restated our previously disclosed net income (loss) per limited partner unit, or LPU, and related disclosures, within this filing. As a result of adoption, net loss per LPU increased from $(5.66) per unit to $(5.67) per unit and from $(6.33) per unit to $(6.36) per unit for the three and six months ended June 30, 2008, respectively.

4. Acquisitions

Gathering Compression and Processing Assets

On April 1, 2009, we acquired an additional 25.1% interest in East Texas and the NGL Hedge from DCP Midstream, LLC, for aggregate consideration of 3,500,000 Class D units valued at $49.7 million.

 

9


Table of Contents

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

Combined Financial Information

The following table presents the impact on the condensed consolidated balance sheet as of December 31, 2008, adjusted for the acquisition of an additional 25.1% interest in East Texas, from DCP Midstream, LLC.

 

     DCP
Midstream
Partners, LP
    Consolidate
East Texas
   Remove
East Texas
Equity
Investment
    Combined
DCP
Midstream
Partners, LP
 
     (a)     (b)    (c)        
     (Millions)  

ASSETS

         

Current assets:

         

Cash and cash equivalents

   $ 48.0      $ 13.9    $ —        $ 61.9   

Accounts receivable

     80.4        35.9      —          116.3   

Inventories

     20.9        —        —          20.9   

Other

     15.9        0.4      —          16.3   
                               

Total current assets

     165.2        50.2      —          215.4   

Restricted investments

     60.2        —        —          60.2   

Property, plant and equipment, net

     629.3        253.4      —          882.7   

Goodwill and intangible assets, net

     136.5        —        —          136.5   

Equity method investments

     175.4        —        (63.9     111.5   

Other non-current assets

     13.4        —        —          13.4   
                               

Total assets

   $ 1,180.0      $ 303.6    $ (63.9   $ 1,419.7   
                               

LIABILITIES AND EQUITY

         

Accounts payable and other current liabilities

   $ 124.8      $ 38.4    $ —        $ 163.2   

Long-term debt

     656.5        —        —          656.5   

Other long-term liabilities

     34.9        2.3      —          37.2   
                               

Total liabilities

     816.2        40.7      —          856.9   
                               

Commitments and contingent liabilities

         

Equity:

         

Partners’ equity

         

Net equity

     369.6        129.9      (63.9     435.6   

Accumulated other comprehensive income

     (40.5     —        —          (40.5
                               

Total partners’ equity

     329.1        129.9      (63.9     395.1   

Noncontrolling interests

     34.7        133.0      —          167.7   
                               

Total equity

     363.8        262.9      (63.9     562.8   
                               

Total liabilities and equity

   $ 1,180.0      $ 303.6    $ (63.9   $ 1,419.7   
                               

 

10


Table of Contents

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

The following tables present the impact on the condensed consolidated statements of operations, adjusted for the acquisition of an additional 25.1% interest in East Texas, from DCP Midstream, LLC, for the three and six months ended June 30, 2008.

Three Months Ended June 30, 2008

 

     DCP
Midstream
Partners, LP
    Consolidate
East Texas
    Remove East
Texas Equity
Earnings
    Combined
DCP
Midstream
Partners, LP
 
     (a)     (b)     (c)        
     (Millions)  

Operating revenues:

        

Sales of natural gas, propane, NGLs and condensate

   $ 318.5      $ 192.3      $ —        $ 510.8   

Transportation, processing and other

     14.0        6.8        —          20.8   

Losses from commodity derivative activity, net

     (186.6     (0.7     —          (187.3
                                

Total operating revenues

     145.9        198.4        —          344.3   
                                

Operating costs and expenses:

        

Purchases of natural gas, propane and NGLs

     287.8        158.6        —          446.4   

Operating and maintenance expense

     11.0        8.3        —          19.3   

Depreciation and amortization expense

     9.0        4.0        —          13.0   

General and administrative expense and other

     3.8        2.5        —          6.3   
                                

Total operating costs and expenses

     311.6        173.4        —          485.0   
                                

Operating (loss) income

     (165.7     25.0        —          (140.7

Interest expense, net

     (6.1     0.2        —          (5.9

Earnings from equity method investments

     13.4        —          (6.3     7.1   
                                

(Loss) income before income taxes

     (158.4     25.2        (6.3     (139.5

Income tax expense

     —          (0.3     —          (0.3
                                

Net (loss) income

     (158.4     24.9        (6.3     (139.8

Net income attributable to noncontrolling interests

     (0.9     (12.4     —          (13.3
                                

Net (loss) income attributable to partners

   $ (159.3   $ 12.5      $ (6.3   $ (153.1
                                

Six Months Ended June 30, 2008

        
     DCP
Midstream
Partners, LP
    Consolidate
East Texas
    Remove East
Texas Equity
Earnings
    Combined
DCP
Midstream
Partners, LP
 
     (a)     (b)     (c)        
           (Millions)        

Operating revenues:

        

Sales of natural gas, propane, NGLs and condensate

   $ 681.2      $ 326.8      $ —        $ 1,008.0   

Transportation, processing and other

     26.1        13.9        —          40.0   

Losses from commodity derivative activity, net

     (223.7     (0.7     —          (224.4
                                

Total operating revenues

     483.6        340.0        —          823.6   
                                

Operating costs and expenses:

        

Purchases of natural gas, propane and NGLs

     617.5        260.1        —          877.6   

Operating and maintenance expense

     21.6        15.7        —          37.3   

Depreciation and amortization expense

     17.5        8.2        —          25.7   

General and administrative expense and other

     9.3        4.6        —          13.9   
                                

Total operating costs and expenses

     665.9        288.6        —          954.5   
                                

Operating (loss) income

     (182.3     51.4        —          (130.9

Interest expense, net

     (12.6     0.3        —          (12.3

Earnings from equity method investments

     30.6        —          (12.8     17.8   
                                

(Loss) income before income taxes

     (164.3     51.7        (12.8     (125.4

Income tax expense

     —          (0.6     —          (0.6
                                

Net (loss) income

     (164.3     51.1        (12.8     (126.0

Net income attributable to noncontrolling interests

     (1.5     (25.5     —          (27.0
                                

Net (loss) income attributable to partners

   $ (165.8   $ 25.6      $ (12.8   $ (153.0
                                

 

(a) Amounts as previously reported with 25% of East Texas’ results presented as earnings from equity method investments.
(b) Adjustments to present East Texas on a consolidated basis at 100%, with noncontrolling interest of 49.9%.
(c) Adjustments to remove East Texas equity earnings at 25%.

 

11


Table of Contents

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

On October 1, 2008, we acquired Michigan Pipeline & Processing, LLC, or MPP, a privately held company engaged in natural gas gathering and treating services for natural gas produced from the Antrim Shale of northern Michigan and natural gas transportation within Michigan. The results of MPP’s operations have been included in the condensed consolidated financial statements, within the Natural Gas Services segment, since that date. Under the terms of the acquisition, we paid a purchase price of $145.0 million, plus net working capital and other adjustments of $3.4 million. We may pay up to an additional $15.0 million to the sellers depending on the earnings of the assets after a three-year period. We financed the acquisition through utilization of our credit facility. In addition, we entered into a separate agreement that provides the seller with available treating capacity on certain Michigan assets. The seller agreed to pay up to $1.5 million annually for up to nine years if they do not meet certain criteria, including providing additional volumes for treatment. These payments may reduce goodwill as a return of purchase price. This agreement may be terminated earlier if certain performance criteria of Michigan assets are satisfied. Certain of these performance criteria were satisfied and, as a result, the amount was reduced to approximately $0.8 million per year as of June 30, 2009. We initially held a $25.0 million letter of credit to secure the seller’s performance under this agreement and to secure the seller’s indemnification obligation under the acquisition agreement; however as a result of the satisfaction of certain performance conditions, this amount was reduced to approximately $20.0 million as of June 30, 2009. The fees under our omnibus agreement with DCP Midstream, LLC increased $0.4 million per year effective October 1, 2008, in connection with the acquisition.

Under the purchase method of accounting, the assets and liabilities of MPP were recorded at their respective fair values as of the date of the acquisition, and we recorded goodwill of approximately $7.0 million. The goodwill amount recognized relates primarily to projected growth from new customers. The values of certain assets and liabilities are preliminary, and are subject to adjustment as additional information is obtained, which when finalized may result in material adjustments. The purchase price allocation is as follows:

 

     (Millions)  

Cash

   $ 1.7   

Accounts receivable

     2.1   

Other assets

     0.1   

Other long term assets

     3.9   

Property, plant and equipment

     116.1   

Goodwill

     7.0   

Intangible assets

     19.6   

Other liabilities

     (0.5

Noncontrolling interest in joint venture

     (1.6
        

Total purchase price allocation

   $ 148.4   
        

5. Agreements and Transactions with Affiliates

DCP Midstream, LLC

Predecessor

DCP Midstream, LLC provided centralized corporate functions on behalf of our predecessor operations, including legal, accounting, cash management, insurance administration and claims processing, risk management, health safety and environmental, information technology, human resources, credit, payroll, internal audit, taxes and engineering.

Omnibus Agreement

We have entered into an omnibus agreement, as amended, or the Omnibus Agreement, with DCP Midstream, LLC. Under the Omnibus Agreement, we are required to reimburse DCP Midstream, LLC for certain costs incurred and centralized corporate functions performed by DCP Midstream, LLC on our behalf. Under the Omnibus Agreement, DCP Midstream, LLC has issued parental guarantees, totaling $43.0 million at June 30, 2009, to certain counterparties to our commodity derivative instruments.

 

12


Table of Contents

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

During the three months ended June 30, 2009 and 2008, we incurred $2.4 million and $2.5 million, respectively for all fees under the Omnibus Agreement and incurred other fees with DCP Midstream, LLC of $2.7 million and $2.3 million, respectively. During the six months ended June 30, 2009 and 2008, we incurred $4.8 million and $4.9 million, respectively, for all fees under the Omnibus Agreement and incurred other fees with DCP Midstream, LLC of $5.6 million and $5.0 million, respectively.

Other Agreements and Transactions with DCP Midstream, LLC

In conjunction with our acquisition of an additional 25.1% limited liability company interest in East Texas from DCP Midstream, LLC in April 2009, we entered into an agreement with DCP Midstream, LLC whereby DCP Midstream, LLC will reimburse East Texas for certain East Texas capital projects as defined in the Contribution Agreement from April 1, 2009 for a period not to exceed three years. DCP Midstream, LLC made additional capital contributions of $11.5 million during the three months ended June 30, 2009 to East Texas for these capital projects.

On February 11, 2009, we announced that our East Texas natural gas processing complex and natural gas delivery system known as the Carthage Hub, had been temporarily shut in following a fire that was caused by a third party underground pipeline outside of our property line that ruptured. We are actively pursuing full reimbursement of our costs and lost margin associated with the incident from the responsible third party. We also have insurance covering these amounts, net of applicable deductibles. Following this incident, DCP Midstream, LLC has agreed to reimburse us 25% of any claims received as reimbursement of costs and lost margin, from the responsible third party. DCP Midstream, LLC will pay 75% of costs related to the incident.

On February 25, 2009, we entered into a Contribution Agreement with DCP Midstream, LLC, whereby DCP Midstream, LLC contributed an additional 25.1% interest in East Texas and the NGL Hedge to us in exchange for 3,500,000 Class D units, providing us with a 50.1% interest in East Texas. This transaction closed in April 2009. Subsequent to this transaction we consolidate our 50.1% interest in East Texas and consequently no longer account for East Texas as an equity method investment.

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

DCP Midstream, LLC owns certain assets and is party to certain contractual relationships around our Pelico system that are periodically used for the benefit of Pelico. DCP Midstream, LLC is able to source natural gas upstream of Pelico and deliver it to us and is able to take natural gas from the outlet of the Pelico system and market it downstream of Pelico. Pelico has certain contractual relationships that define how natural gas is bought and sold between us and DCP Midstream, LLC.

In January 2009, we amended our Pelico gas purchase and sales agreement with DCP Midstream, LLC. As a result of the amendment, our purchases from DCP Midstream, LLC occur upstream of Pelico, rather than at the inlet of Pelico. We assumed from DCP Midstream, LLC a firm transportation agreement with an affiliate to transport our natural gas purchases from DCP Midstream, LLC to Pelico. In addition, historically, the sales price of a portion of the natural gas we sold to DCP Midstream, LLC was determined based on the price at which we purchased the natural gas from DCP Midstream, LLC plus a portion of the index differential between upstream sources to certain downstream indices with a maximum and minimum differential. The pricing methodology has changed as described below:

 

   

DCP Midstream, LLC will supply Pelico’s system requirements that exceed its on-system supply. Accordingly, DCP Midstream, LLC purchases natural gas and we buy the gas from DCP Midstream, LLC at the actual acquisition cost plus transportation service charges incurred. We generally report purchases associated with these activities gross in the condensed consolidated statements of operations as purchases of natural gas, propane, NGLs and condensate from affiliates.

 

   

For volumes supplied to certain industrial end users and any volumes in excess of the on-system demand, DCP Midstream, LLC will purchase natural gas from us and sell it to certain industrial end users, or transport it to sales points at an index-based price, less contractually agreed-to marketing fees. We generally report revenues associated with these activities gross in the condensed consolidated statements of operations as sales of natural gas, propane, NGLs and condensate to affiliates.

 

13


Table of Contents

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

DCP Midstream, LLC was a significant customer during the three and six months ended June 30, 2009 and 2008.

In conjunction with our acquisition of a 40% limited liability company interest in Discovery from DCP Midstream, LLC in July 2007, we entered into a letter agreement with DCP Midstream, LLC whereby DCP Midstream, LLC will make capital contributions to us as reimbursement for certain Discovery capital projects. DCP Midstream, LLC made capital contributions to us during the six months ended June 30, 2009 and 2008 of $0.7 million and $1.6 million, respectively, to reimburse us for these capital projects.

In conjunction with our acquisition of East Texas and Discovery in July 2007 we entered into an agreement with DCP Midstream, LLC whereby DCP Midstream, LLC will reimburse East Texas for 25% of certain East Texas capital expenditures, defined in the agreement, from July 1, 2007, through completion of the capital projects for a period not to exceed three years. DCP Midstream, LLC made additional capital contributions to East Texas for these capital projects of $6.2 million and $1.5 million during the six months ended June 30, 2009 and 2008, respectively.

DCP Midstream, LLC has issued additional parental guarantees outside of the Omnibus Agreement, totaling $40.0 million at June 30, 2009, to certain counterparties to our commodity derivative instruments to mitigate a portion of our collateral requirements with those counterparties. We pay DCP Midstream, LLC a fee of 0.5% per annum on these outstanding guarantees.

Spectra Energy

We purchase a portion of our propane from and market propane on behalf of Spectra Energy. We anticipate continuing to purchase propane from and market propane on behalf of Spectra Energy in the ordinary course of business.

During the second quarter of 2008, we entered into a propane supply agreement with Spectra Energy. This agreement, effective May 1, 2008 and terminating April 30, 2014, provides us propane supply at our marine terminal, which is included in our Wholesale Propane Logistics segment, for up to approximately 120 million gallons of propane annually. This contract replaces the supply provided under a contract with a third party that was terminated for non-performance during the first quarter of 2008.

ConocoPhillips

We have multiple agreements whereby we provide a variety of services for ConocoPhillips and its affiliates. The agreements include fee-based and percent-of-proceeds gathering and processing arrangements, and gas purchase and gas sales agreements. We anticipate continuing to purchase from and sell these commodities to ConocoPhillips and its affiliates in the ordinary course of business. In addition, we may be reimbursed by ConocoPhillips for certain capital projects where the work is performed by us. We received $0.7 million and $1.3 million of capital reimbursements during the six months ended June 30, 2009 and 2008, respectively.

 

14


Table of Contents

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

Summary of Transactions with Affiliates

The following table summarizes the transactions with affiliates:

 

     Three Months Ended
June 30,
    Six Months Ended
June 30,
 
     2009     2008     2009     2008  
     (Millions)  

DCP Midstream, LLC:

        

Sales of natural gas, propane, NGLs and condensate

   $ 101.3      $ 257.3      $ 201.1      $ 455.6   

Transportation, processing and other

   $ 1.4      $ 6.2      $ 2.6      $ 11.7   

Purchases of natural gas, propane and NGLs

   $ 19.3      $ 28.1      $ 62.4      $ 103.4   

(Losses) gains from commodity derivative activity, net

   $ (1.9   $ (2.4   $ (2.6   $ (1.7

General and administrative expense

   $ 5.1      $ 4.8      $ 10.4      $ 9.9   

Interest expense

   $ —        $ —        $ 0.1      $ —     

Spectra Energy:

        

Sales of natural gas, propane, NGLs and condensate

   $ —        $ —        $ —        $ 0.2   

Transportation, processing and other

   $ 0.2      $ 0.1      $ 0.2      $ 0.1   

Purchases of natural gas, propane and NGLs

   $ 14.5      $ 4.4      $ 48.1      $ 4.4   

ConocoPhillips:

        

Sales of natural gas, propane, NGLs and condensate

   $ 0.6      $ 17.3      $ 0.7      $ 19.9   

Transportation, processing and other

   $ 1.9      $ 5.0      $ 4.3      $ 5.8   

Purchases of natural gas, propane and NGLs

   $ 3.9      $ 16.4      $ 5.9      $ 23.0   

General and administrative expense

   $ —        $ —        $ 0.1      $ —     

Unconsolidated affiliates:

        

Purchases of natural gas, propane and NGLs

   $ —        $ —        $ 0.4      $ —     

We had balances with affiliates as follows:

 

     June 30,
2009
    December 31,
2008
 
     (Millions)  

DCP Midstream, LLC:

    

Accounts receivable

   $ 55.0      $ 51.0   

Accounts payable

   $ 11.6      $ 30.3   

Unrealized gains on derivative instruments—current

   $ 1.0      $ —     

Unrealized losses on derivative instruments—current

   $ (1.0   $ (1.2

Spectra Energy:

    

Accounts receivable

   $ 1.2      $ 4.0   

Accounts payable

   $ 1.3      $ 5.3   

ConocoPhillips:

    

Accounts receivable

   $ 1.4      $ 2.5   

Accounts payable

   $ 0.5      $ 0.4   

 

15


Table of Contents

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

6. Property, Plant and Equipment

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

 

     Depreciable
Life
   June 30,
2009
    December 31,
2008
 
          (Millions)  

Gathering systems

   15 — 30 Years    $ 576.5      $ 497.7   

Processing plants

   25 — 30 Years      407.6        383.2   

Terminals

   25 — 30 Years      28.9        28.5   

Transportation

   25 — 30 Years      217.5        216.6   

Underground storage

   20 — 50 Years      0.1        0.1   

General plant

   3 — 5 Years      15.0        13.9   

Construction work in progress

        89.1        73.9   
                   

Property, plant and equipment

        1,334.7        1,213.9   

Accumulated depreciation

        (360.8     (331.2
                   

Property, plant and equipment, net

      $ 973.9      $ 882.7   
                   

The above amounts include accrued capital expenditures of $18.7 million and $17.4 million as of June 30, 2009 and December 31, 2008, respectively, which are included in other current liabilities in the condensed consolidated balance sheets.

7. Equity Method Investments

The following table summarizes our equity method investments:

 

     Percentage of
Ownership as of
June 30, 2009 and
December 31, 2008
          
       Carrying Value as of
       June 30,
2009
   December 31,
2008
           (Millions)

Discovery Producer Services LLC

   40   $ 110.3    $ 105.0

Black Lake Pipe Line Company

   45     6.5      6.3

Other

   50     0.2      0.2
               

Total equity method investments

     $ 117.0    $ 111.5
               

There was a deficit between the carrying amount of the investment and the underlying equity of Discovery of $38.5 million and $39.7 million at June 30, 2009 and December 31, 2008, respectively, which is associated with, and is being accreted over, the life of the underlying long-lived assets of Discovery.

There was a deficit between the carrying amount of the investment and the underlying equity of Black Lake of $5.9 million and $6.0 million at June 30, 2009 and December 31, 2008, respectively, which is associated with, and is being accreted over, the life of the underlying long-lived assets of Black Lake.

In the second quarter of 2009, Discovery’s LLC agreement was amended to calculate available cash based on cash on hand at the end of the month preceding the end of each calendar quarter (e.g. May 31 for the second quarter) and to require distribution of available cash by the end of each calendar quarter. Prior to this amendment, Discovery calculated available cash based on cash on hand at the end of each calendar quarter and made the related distribution within 30 days of the end of each calendar quarter.

 

16


Table of Contents

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

Earnings and distributions from equity method investments were as follows:

 

     Three Months Ended
June 30,
   Six Months Ended
June 30,
     2009     2008    2009    2008
     (Millions)

Discovery Producer Services LLC

   $ 3.3      $ 6.9    $ 1.8    $ 17.2

Black Lake Pipe Line Company and other

     0.4        0.2      0.8      0.6
                            

Total earnings from equity method investments

   $ 3.7      $ 7.1    $ 2.6    $ 17.8
                            

Distributions from equity method investments

   $ 2.5      $ 10.4    $ 3.0    $ 21.8
                            

Distributions from equity method investments, net of earnings

   $ (1.2   $ 3.3    $ 0.4    $ 4.0
                            

The following summarizes financial information of our equity method investments:

 

     Three Months Ended
June 30,
   Six Months Ended
June 30,
     2009    2008    2009    2008
     (Millions)

Statements of operations:

           

Operating revenue

   $ 40.4    $ 84.4    $ 61.9    $ 173.3

Operating expenses

   $ 32.9    $ 70.1    $ 58.8    $ 139.5

Net income

   $ 7.5    $ 14.5    $ 2.9    $ 37.9

 

     June 30,
2009
    December 31,
2008
 
     (Millions)  

Balance sheets:

    

Current assets

   $ 66.5      $ 54.1   

Long-term assets

     389.5        392.9   

Current liabilities

     (40.1     (46.0

Long-term liabilities

     (22.1     (20.1
                

Net assets

   $ 393.8      $ 380.9   
                

8. Fair Value Measurement

Determination of Fair Value

Below is a general description of our valuation methodologies for derivative financial assets and liabilities, as well as short-term and restricted investments, which are measured at fair value. Fair values are generally based upon quoted market prices, where available. In the event that listed market prices or quotes are not available, we determine fair value based upon a market quote, adjusted by other market-based or independently sourced market data such as historical commodity volatilities, crude oil future yield curves, and/or counterparty specific considerations. These adjustments result in a fair value for each asset or liability under an “exit price” methodology, in line with how we believe a marketplace participant would value that asset or liability. These adjustments may include amounts to reflect counterparty credit quality, the effect of our own creditworthiness, the time value of money and/or the liquidity of the market.

 

17


Table of Contents

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

   

Counterparty credit valuation adjustments are necessary when the market price of an instrument is not indicative of the fair value as a result of the credit quality of the counterparty. Generally, market quotes assume that all counterparties have near zero, or low, default rates and have equal credit quality. Therefore, an adjustment may be necessary to reflect the credit quality of a specific counterparty to determine the fair value of the instrument. We record counterparty credit valuation adjustments on all derivatives that are in a net asset position as of the measurement date in accordance with our established counterparty credit policy, which takes into account any collateral margin that a counterparty may have posted with us.

 

   

Entity valuation adjustments are necessary to reflect the effect of our own credit quality on the fair value of our net liability position with each counterparty. This adjustment takes into account any credit enhancements, such as collateral margin we may have posted with a counterparty, as well as any letters of credit that we have provided. The methodology to determine this adjustment is consistent with how we evaluate counterparty credit risk, taking into account our own credit rating, current credit spreads, as well as any change in such spreads since the last measurement date.

 

   

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

We manage our derivative instruments on a portfolio basis and the valuation adjustments described above are calculated on this basis. We believe that the portfolio level approach represents the highest and best use for these assets as there are benefits inherent in naturally offsetting positions within the portfolio at any given time, and this approach is consistent with how a market participant would view and value the assets. 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 marketplace 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.

Valuation Hierarchy

Our fair value measurements are grouped into a three-level valuation hierarchy. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date. The three levels are defined as follows.

 

   

Level 1 — inputs are unadjusted quoted prices for identical assets or liabilities in active markets.

 

   

Level 2 — inputs include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.

 

   

Level 3 — inputs are unobservable and considered significant to the fair value measurement.

A financial instrument’s categorization within the hierarchy is based upon the input that requires the highest degree of judgment in the determination of the instrument’s fair value. Following is a description of the valuation methodologies used as well as the general classification of such instruments pursuant to the hierarchy.

Commodity Derivative Assets and Liabilities

We enter into a variety of derivative financial instruments, which may include over the counter, or OTC, instruments, such as natural gas, crude oil or NGL contracts.

 

18


Table of Contents

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

Within our Natural Gas Services segment we typically use OTC derivative contracts in order to mitigate a portion of our exposure to natural gas, NGL and condensate price changes. These instruments are generally classified as Level 2. Depending upon market conditions and our strategy, we may enter into OTC derivative positions with a significant time horizon to maturity, and market prices for these OTC derivatives may only be readily observable for a portion of the duration of the instrument. In order to calculate the fair value of these instruments, readily observable market information is utilized to the extent that it is available; however, in the event that readily observable market data is not available, we may interpolate or extrapolate based upon observable data. In instances where we utilize an interpolated or extrapolated value, and it is considered significant to the valuation of the contract as a whole, we would classify the instrument within Level 3.

Within our Wholesale Propane Logistics segment, we may enter into a variety of financial instruments to either secure sales or purchase prices, or capture a variety of market opportunities. Since financial instruments for NGLs tend to be counterparty and location specific, we primarily use the OTC derivative instrument markets, which are not as active and liquid as exchange traded instruments. Market quotes for such contracts may only be available for short dated positions (up to six months), and a market itself may not exist beyond such time horizon. Contracts entered into with a relatively short time horizon for which prices are readily observable in the OTC market are generally classified within Level 2. Contracts with a longer time horizon, for which we internally generate a forward curve to value such instruments, are generally classified within Level 3. The internally generated curve may utilize a variety of assumptions including, but not limited to, historical and future expected relationship of NGL prices to crude oil prices, the knowledge of expected supply sources coming on line, expected weather trends within certain regions of the United States, and the future expected demand for NGLs.

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

Interest Rate Derivative Assets and Liabilities

We have interest rate swap agreements as part of our overall capital strategy. These instruments effectively exchange a portion of our floating rate debt for fixed rate debt. The swaps are generally priced based upon a London Interbank Offered Rate, or LIBOR, instrument with similar duration, adjusted by the credit spread between our company and the LIBOR instrument. Given that a significant portion of the swap value is derived from the credit spread, which may be observed by comparing similar assets in the market, these instruments are classified within Level 2. Default risk on either side of the swap transaction is also considered in the valuation. We record counterparty credit and entity valuation adjustments in the valuation of our interest rate swaps; however, these reserves are not considered to be a significant input to the overall valuation.

Short-Term and Restricted Investments

We are required to post collateral to secure the term loan portion of our credit facility, and may elect to invest a portion of our available cash balances in various financial instruments such as commercial paper and money market instruments. The money market instruments are generally priced at acquisition cost, plus accreted interest at the stated rate, which approximates fair value, without any additional adjustments. Given that there is no observable exchange traded market for identical money market securities, we have classified these instruments within Level 2. Investments in commercial paper are priced using a yield curve for similarly rated instruments, and are classified within Level 2. As of June 30, 2009, nearly all of our short-term and restricted investments were held in the form of money market securities. By virtue of our balances in these funds on September 19, 2008, all of these investments are eligible for, and the funds are participating in, the U.S. Treasury Department’s Temporary Guarantee Program for Money Market Funds.

Nonfinancial Assets and Liabilities

We utilize fair value on a non-recurring basis to perform impairment tests as required on our property, plant and equipment, goodwill and intangible assets. The inputs used to determine such fair value are primarily based upon internally developed cash flow models and would generally be classified within Level 3, in the event that we were required to measure and record such assets at fair value within our consolidated financial statements. Additionally, we use fair value to determine the inception value

 

19


Table of Contents

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

of our asset retirement obligations on our leased property, plant and equipment. 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.

The following table presents the financial instruments carried at fair value as of June 30, 2009 and December 31, 2008:

 

     June 30, 2009     December 31, 2008  
     Level 1    Level 2     Level 3     Total
Carrying
Value
    Level 1    Level 2     Level 3    Total
Carrying
Value
 
     (Millions)  

Current assets:

                   

Commodity derivatives (a)

   $ —      $ 4.7      $ 1.2      $ 5.9      $ —      $ 15.1      $ 0.3    $ 15.4   

Long-term assets:

                   

Restricted investments

   $ —      $ 35.1      $ —        $ 35.1      $ —      $ 60.2      $ —      $ 60.2   

Commodity derivatives (b)

   $ —      $ 2.9      $ —        $ 2.9      $ —      $ 6.9      $ 1.7    $ 8.6   

Interest rate derivatives (b)

   $ —      $ 0.9      $ —        $ 0.9      $ —      $ —        $ —      $ —     

Current liabilities (c):

                   

Commodity derivatives

   $ —      $ (6.9   $ (0.1   $ (7.0   $ —      $ (1.2   $ —      $ (1.2

Interest rate derivatives

   $ —      $ (18.7   $ —        $ (18.7   $ —      $ (16.5   $ —      $ (16.5

Long-term liabilities (d):

                   

Commodity derivatives

   $ —      $ (29.9   $ (0.9   $ (30.8   $ —      $ (3.2   $ —      $ (3.2

Interest rate derivatives

   $ —      $ (12.8   $ —        $ (12.8   $ —      $ (22.8   $ —      $ (22.8

 

(a) Included in current unrealized gains on derivative instruments in our condensed consolidated balance sheets.
(b) Included in long-term unrealized gains on derivative instruments in our condensed consolidated balance sheets.
(c) Included in current unrealized losses on derivative instruments in our condensed consolidated balance sheets.
(d) Included in long-term unrealized losses on derivative instruments in our condensed consolidated balance sheets.

Changes in Level 3 Fair Value Measurements

The tables below illustrate a rollforward of the amounts included in our condensed consolidated balance sheets for derivative financial instruments that we have classified within Level 3. The determination to classify a financial instrument within Level 3 is based upon the significance of the unobservable factors used in determining the overall fair value of the instrument. Since financial instruments classified as Level 3 typically include a combination of observable components (that is, components that are actively quoted and can be validated to external sources) and unobservable components, the gains and losses in the table below may include changes in fair value due in part to observable market factors, or changes to our assumptions on the unobservable components. Depending upon the information readily observable in the market, and/or the use of unobservable inputs, which are significant to the overall valuation, the classification of any individual financial instrument may differ from one measurement date to the next. In the event that there is a movement to/from the classification of an instrument as Level 3, we have reflected such items in the table below within the “Transfers In/Out of Level 3” caption.

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.

 

20


Table of Contents

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

     Beginning
Balance
    Net Realized and
Unrealized
Gains (Losses)
Included in
Earnings
    Transfers
In/Out of
Level 3 (a)
    Purchases,
Issuances and
Settlements,
Net
    Ending
Balance
    Net
Unrealized
Gains (Losses)
Still Held
Included in
Earnings (b)
 
     (millions)  

Three months ended June 30, 2009:

            

Commodity derivative instruments:

            

Current assets

   $ 1.0      $ (3.3   $ —        $ 3.5      $ 1.2      $ (2.6

Long-term assets

   $ 1.7      $ (1.7   $ —        $ —        $ —        $ (1.7

Current liabilities

   $ —        $ (0.1   $ —        $ —        $ (0.1   $ (0.1

Long-term liabilities

   $ (0.3   $ (0.6   $ —        $ —        $ (0.9   $ (0.6

Three months ended June 30, 2008:

  

Commodity derivative instruments:

            

Current assets

   $ —        $ —        $ 1.0      $ —        $ 1.0      $ —     

Long-term assets

   $ 1.2      $ (1.1   $ 1.5      $ —        $ 1.6      $ (1.1

Current liabilities

   $ (1.3   $ (1.9   $ (5.3   $ 1.0      $ (7.5   $ (1.6

Long-term liabilities

   $ —        $ (3.1   $ (4.6   $ —        $ (7.7   $ (3.1

Six months ended June 30, 2009:

            

Commodity derivative instruments:

            

Current assets

   $ 0.3      $ (2.7   $ —        $ 3.6      $ 1.2      $ (2.0

Long-term assets

   $ 1.7      $ (1.7   $ —        $ —        $ —        $ (1.7

Current liabilities

   $ —        $ (0.1   $ —        $ —        $ (0.1   $ (0.1

Long-term liabilities

   $ —        $ (0.9   $ —        $ —        $ (0.9   $ (0.9

Six months ended June 30, 2008:

            

Commodity derivative instruments:

            

Current assets

   $ 0.2      $ 1.0      $ —        $ (0.2   $ 1.0      $ 0.8   

Long-term assets

   $ 1.5      $ 0.1      $ —        $ —        $ 1.6      $ 0.1   

Current liabilities

   $ (1.6   $ (2.7   $ (5.0   $ 1.8      $ (7.5   $ (2.4

Long-term liabilities

   $ (0.2   $ (2.9   $ (4.6   $ —        $ (7.7   $ (2.9

 

(a) Amounts transferred in are reflected at the fair value as of the beginning of the period and amounts transferred out are reflected at fair value at the end of the period.
(b) Represents the amount of total gains or losses for the period, included in gains or losses from commodity derivative activity, net, attributable to change in unrealized gains (losses) relating to assets and liabilities classified as Level 3 that are still held at June 30, 2009 and 2008.

9. Debt

Long-term debt was as follows:

 

     June 30,
2009
   December 31,
2008
     (Millions)

Revolving credit facility, weighted-average interest rate of 1.03% and 2.08%, respectively, due June 21, 2012 (a)

   $ 603.0    $ 596.5

Term loan facility, interest rate of 0.42% and 1.54%, respectively, due June 21, 2012 (b)

     35.0      60.0
             

Total long-term debt

   $ 638.0    $ 656.5
             

 

     
  (a) $575.0 million of debt has been swapped to a fixed rate obligation with effective fixed rates ranging from 2.26% to 5.19%, for a net effective rate of 4.47% on the $603.0 million of outstanding debt under our revolving credit facility as of June 30, 2009.
  (b) The term loan facility is fully secured by restricted investments.

 

21


Table of Contents

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

Credit Agreement

We have an $824.6 million 5-year credit agreement that matures June 21, 2012, or the Credit Agreement, which consists of:

 

   

a $789.6 million revolving credit facility; and

 

   

a $35.0 million term loan facility.

The above amounts are net of non-participation by Lehman Brothers Commercial Bank. At June 30, 2009 and December 31, 2008, we had $0.3 million of letters of credit outstanding under the Credit Agreement. Outstanding balances under the term loan facility are fully collateralized by investments in high-grade securities, which are classified as restricted investments in the accompanying condensed consolidated balance sheets. As of June 30, 2009 the available capacity under the revolving credit facility was $188.5 million.

Other Agreements

As of June 30, 2009, we had an outstanding letter of credit with a counterparty to our commodity derivative instruments of $10.0 million, which reduces the amount of cash we may be required to post as collateral. We pay a fee of 0.8% per annum on this letter of credit. This letter of credit was issued directly by a financial institution and does not reduce the available capacity under the Credit Agreement.

10. Risk Management and Hedging Activities

Our day to day operations expose us to a variety of risks including but not limited to changes in the prices of commodities that we buy or sell, changes in interest rates, and the creditworthiness of each of our counterparties. We manage certain of these exposures by using physical and financial derivative instruments. We have established a comprehensive risk management policy, or Risk Management Policy, and a risk management committee, or the Risk Management Committee, to monitor and manage market risks associated with commodity prices and counterparty credit. The Risk Management Committee is responsible for the overall management of credit risk and commodity price risk, including monitoring exposure limits. The following briefly describes each of the risks that we manage.

Commodity Price Risk

We are exposed to the impact of market fluctuations in the prices of natural gas, NGLs and condensate as a result of our gathering, processing, sales and storage activities. For gathering and processing services, we may receive fees or commodities as payment for these services, depending on the contract type. We enter into derivative financial instruments to mitigate the risk of weakening natural gas, NGL and condensate prices associated with our gathering, processing and sales activities, thereby stabilizing our cash flows. Additionally, given the limited depth of the NGL derivatives market, we primarily utilize crude oil swaps and following our acquisition of the NGL Hedge on April 1, 2009, NGL derivatives to mitigate a significant portion of our commodity price exposure for propane and heavier NGLs. Historically, there has been a relationship between NGL prices and crude oil prices and lack of liquidity in the NGL financial market; therefore we have historically used crude oil swaps to mitigate a portion of NGL price risks. As a result of the current movements in the relationship of NGL prices to crude oil prices outside of recent historical ranges, we have additional exposure to changes in the relationship. We have mitigated a portion of our expected commodity price risk associated with our gathering, processing and sales activities through 2014 with natural gas, crude oil and NGL derivative instruments. These transactions are primarily accomplished through the use of forward contracts, swap futures that effectively exchange our floating rate price risk for a fixed rate, but the type of instrument that we use to mitigate our risk may vary depending upon our risk management objective. These transactions are not designated as hedging instruments for accounting purposes and the change in fair value is reflected within our condensed consolidated statements of operations.

Our Wholesale Propane Logistics segment is generally designed to establish stable margins by entering into supply arrangements that specify prices based on established floating price indices and by entering into sales agreements that provide for floating prices that are tied to our variable supply costs plus a margin. To the extent possible, we match the pricing of our supply portfolio to our sales portfolio in order to lock in value and reduce our overall commodity price risk. However, to the extent that we carry propane inventories or our sales and supply arrangements are not aligned, we are exposed to market variables and commodity price risk. We manage the commodity price risk of our supply portfolio and sales portfolio with both physical and

 

22


Table of Contents

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

financial transactions. While the majority of our sales and purchases in this segment are index-based, occasionally, we may enter into fixed price sales agreements in the event that a retail propane distributor desires to purchase propane from us on a fixed price basis. In such cases, we may manage this risk with derivatives that allow us to swap our fixed price risk to market index prices that are matched to our market index supply costs. In addition, we may on occasion use financial derivatives to manage the value of our propane inventories. These transactions are not designated as hedging instruments for accounting purposes and the change in value is reflected in the current period within our condensed consolidated statements of operations.

Furthermore, with respect to our Pelico system, we may enter into financial derivatives to lock in price differentials across the system and connected storage to maximize value. This objective may be achieved through the use of physical purchases or sales of gas that are accounted for under accrual accounting. While the physical purchase or sale of gas transactions are accounted for under accrual accounting, the swaps are not designated as hedging instruments for accounting purposes and any change in fair value of these instruments is reflected within our condensed consolidated statements of operations.

Our 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. Effective July 1, 2007, we elected to discontinue using the hedge method of accounting for derivatives that manage our commodity price risk. We have used the mark-to-market method of accounting for all derivatives that manage our commodity price risk since July 2007, thus changes in fair value are recorded directly to the condensed consolidated statements of operations. Derivative contracts that were put in place prior to this date may have been designated as cash flow or fair value hedges, and are described below.

Commodity Cash Flow Hedges — We used NGL, natural gas and crude oil swaps to mitigate the risk of market fluctuations in the price of NGLs, natural gas and condensate. Prior to July 1, 2007, the effective portion of the change in fair value of a derivative designated as a cash flow hedge was recorded in accumulated other comprehensive income, or AOCI. During the period in which the hedged transaction impacted earnings, amounts in AOCI associated with the hedged transaction were reclassified to the condensed consolidated statements of operations in the same accounts as the item being hedged.

Given our election to discontinue using the hedge method of accounting, the remaining net loss deferred in AOCI relative to these cash flow hedges will be reclassified to sales of natural gas, propane, NGLs and condensate, through December 2011, as the underlying transactions impact earnings. Subsequent to July 1, 2007, the changes in fair value of financial derivatives are included in gains and losses from commodity derivative activity in the condensed consolidated statements of operations.

Commodity Fair Value Hedges — Historically, we used fair value hedges to mitigate risk to changes in the fair value of an asset or a liability, or an identified portion thereof, that is attributable to fixed price risk. As described above relative to our Wholesale Propane Logistics segment, we may have hedged producer price locks, or fixed price gas purchases, to reduce our cash flow exposure to fixed price risk by swapping the fixed price risk for a floating price position linked to the New York Mercantile Exchange or an index-based position.

Interest Rate Risk

Interest Rate Cash Flow Hedges — We mitigate a portion of our interest rate risk with interest rate swaps, which reduce our exposure to market rate fluctuations by converting variable interest rates to fixed interest rates. These interest rate swap agreements convert the interest rate associated with an aggregate of $575.0 million of the indebtedness outstanding under our revolving credit facility to a fixed rate obligation, thereby reducing the exposure to market rate fluctuations. All interest rate swap agreements have been designated as cash flow hedges, and effectiveness is determined by matching the principal balance and terms with that of the specified obligation. The effective portions of changes in fair value are recognized in AOCI in the condensed consolidated balance sheets and are reclassified into earnings as the hedged transactions impact earnings. The effect that these swaps have on our condensed consolidated financial statements, as well as the effect that is expected over the upcoming 12 months is summarized in the charts below. However, due to the volatility of the interest rate markets, the corresponding value in AOCI is subject to change prior to its reclassification into earnings. Ineffective portions of changes in fair value are recognized in earnings. $425.0 million of the agreements reprice prospectively approximately every 90 days and the remaining $150.0 million of the agreements reprice prospectively approximately every 30 days. Under the terms of the interest rate swap agreements, we pay fixed rates ranging from 2.26% to 5.19%, and receive interest payments based on the three-month and one-month LIBOR. The differences to be paid or received under the interest rate swap agreements are recognized as an adjustment to interest expense.

 

23


Table of Contents

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

Contingent Credit Features

Each of the above risks is managed through the execution of individual contracts with a variety of counterparties. Certain of our derivative contracts may contain credit-risk related contingent provisions that may require us to take certain actions in certain circumstances.

We have International Swap Dealers Association, or ISDA, contracts which are standardized master legal arrangements that establish key terms and conditions which govern certain derivative transactions. These ISDA contracts contain standard credit-risk related contingent provisions. Some of the provisions we are subject to are outlined below.

 

   

If we were to have an effective event of default under our credit agreement that occurs and is continuing, our ISDA counterparties may have the right to request early termination and net settlement of any outstanding derivative liability positions.

 

   

In the event that DCP Midstream, LLC was to be downgraded below investment grade by at least one of the major credit rating agencies, certain of our ISDA counterparties may have the right to reduce our collateral threshold to zero, potentially requiring us to fully collateralize any commodity contracts in a net liability position.

 

   

Additionally, in some cases, our ISDA contracts contain cross-default provisions that could constitute a credit-risk related contingent feature. These provisions apply if we default in making timely payments under those agreements and the amount of the default is above certain predefined thresholds, which are significantly high, and are generally consistent with the terms of our credit agreement. As of June 30, 2009, we are not a party to any agreements that would be subject to these provisions other than our credit agreement.

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

Depending upon the movement of commodity prices, each of our individual contracts with counterparties to our commodity derivative instruments are in either a net asset or net liability position. As of June 30, 2009, we had approximately $36.7 million of individual commodity derivative contracts that contain credit-risk related contingent features that were in a net liability position, and have not posted any cash collateral relative to such positions. If a credit-risk related event were to occur and we were required to net settle our position with an individual counterparty, our ISDA contracts permit us to net all outstanding contracts with that counterparty, whether in a net asset or net liability position, as well as any cash collateral already posted. As of June 30, 2009 if a credit-risk related event were to occur we may be required to post additional collateral. Additionally, although our commodity derivative contracts that contain credit-risk related contingent features were in a net liability position as of June 30, 2009, if a credit-risk related event were to occur, the net liability position would be partially offset by contracts in a net asset position reducing our net liability to $28.9 million.

As of June 30, 2009 our interest rate swaps were in a net liability position of approximately $30.6 million, of which, the entire amount is subject to credit-risk related contingent features. If we were to have a default of any of our covenants to our credit agreement, that occurs and is continuing, the counterparties to our swap instruments may have the right to request that we net settle the instrument in the form of cash.

Collateral

As of June 30, 2009, we had an outstanding letter of credit with a counterparty to our commodity derivative instruments of $10.0 million. This letter of credit reduces the amount of cash we may be required to post as collateral. As of June 30, 2009, we had no cash collateral posted with counterparties to our commodity derivative instruments.

 

24


Table of Contents

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

Summarized Derivative Information

The following summarizes the balance within AOCI relative to our commodity and interest rate cash flow hedges:

 

     June 30,
2009
    December 31,
2008
 
     (Millions)  

Commodity cash flow hedges:

    

Net deferred losses in AOCI

   $ (1.2   $ (1.8

Interest rate cash flow hedges:

    

Net deferred losses in AOCI

     (29.8     (38.7
                

Total AOCI

   $ (31.0   $ (40.5
                

The fair value of our derivative instruments that are designated as hedging instruments, those that are marked to market each period, as well as the location of each within our condensed consolidated balance sheets, by major category, is summarized as follows:

 

Balance Sheet Line Item

   June 30,
2009
   December 31,
2008
  

Balance Sheet Line Item

   June 30,
2009
    December 31,
2008
 
     (Millions)         (Millions)  
Derivative Assets Designated as Hedging Instruments:    Derivative Liabilities Designated as Hedging Instruments:   

Interest rate derivatives:

        

Interest rate derivatives:

    

Unrealized gains on derivative instruments – current

   $ —      $ —     

Unrealized losses on derivative instruments – current

   $ (18.7   $ (16.5

Unrealized gains on derivative instruments – long term

     0.9      —     

Unrealized losses on derivative instruments – long term

     (12.8     (22.8
                                 
   $ 0.9    $ —         $ (31.5   $ (39.3
                                 

Derivative Assets Not Designated as Hedging Instruments:

  

Derivative Liabilities Not Designated as Hedging Instruments:

   

Commodity derivatives:

        

Commodity derivatives:

    

Unrealized gains on derivative instruments – current

   $ 5.9    $ 15.4   

Unrealized losses on derivative instruments – current

   $ (7.0   $ (1.2

Unrealized gains on derivative instruments – long term

     2.9      8.6   

Unrealized losses on derivative instruments – long term

     (30.8     (3.2
                                 
   $ 8.8    $ 24.0       $ (37.8   $ (4.4
                                 

The following table summarizes the impact on our condensed consolidated balance sheet and condensed consolidated statements of operations of our derivative instruments that are accounted for using the cash flow hedge method of accounting.

 

     Gain (Loss)
Recognized in AOCI
on Derivatives —
Effective Portion
   Gain (Loss)
Reclassified From
AOCI to Earnings —
Effective Portion
    Gain (Loss)
Recognized in
Income on
Derivatives —
Ineffective Portion
and Amount
Excluded From
Effectiveness Testing
 
     Three Months Ended June 30,  
     2009    2008    2009     2008     2009    2008  
     (Millions)    (Millions)     (Millions)  

Interest rate derivatives

   $ 4.8    $ 12.6    $ (4.6   $ (2.2 )(b)    $ —      $ —   (b)(c) 

Commodity derivatives

   $ —      $ —      $ (0.1   $ (0.1 )(a)    $ —      $ —   (a)(c) 

 

25


Table of Contents

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

     Gain (Loss)
Recognized in AOCI
on Derivatives —
Effective Portion
    Gain (Loss)
Reclassified From
AOCI to Earnings —
Effective Portion
    Gain (Loss)
Recognized in
Income on
Derivatives —
Ineffective Portion
and Amount
Excluded From
Effectiveness Testing
    Deferred Losses in
AOCI Expected to
be Reclassified
into Earnings
Over the Next
12 Months
 
     Six Months Ended June 30,    
     2009    2008     2009     2008     2009    2008    
     (Millions)     (Millions)     (Millions)     (Millions)  

Interest rate derivatives

   $ 0.3    $ (1.1   $ (8.6   $ (2.3 )(b)    $ —      $ —   (b)(c)    $ (17.9

Commodity derivatives

   $ —      $ —        $ (0.6   $ (0.4 )(a)    $ —      $ —   (a)(c)    $ (0.7

 

  (a) Included in sales of natural gas, propane, NGLs and condensate in our condensed consolidated statements of operations.
  (b) Included in interest expense in our condensed consolidated statements of operations.
  (c) For the three and six months ended June 30, 2009 and 2008, no derivative gains or losses were reclassified from AOCI to current period earnings as a result of the discontinuance of cash flow hedges related to certain forecasted transactions that are not probable of occurring.

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

 

Commodity Derivatives    Three Months Ended
June 30,
    Six Months Ended
June 30,
 

Statements of Operations Line Item

   2009     2008     2009     2008  
     (Millions)  

Third party:

        

Realized

   $ 7.9      $ (14.4   $ 14.8      $ (21.4

Unrealized

     (51.9     (170.5     (51.1     (201.3
                                

Losses from commodity derivative activity, net

   $ (44.0   $ (184.9   $ (36.3   $ (222.7
                                

Affiliates:

        

Realized

   $ 0.3      $ (2.6   $ (0.4   $ (4.7

Unrealized

     (2.2     0.2        (2.2     3.0   
                                

Losses from commodity derivative activity, net — affiliates

   $ (1.9   $ (2.4   $ (2.6   $ (1.7
                                

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

 

26


Table of Contents

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

The following table represents, by commodity type, our net long or short positions that are expected to partially or entirely settle in each respective year. To the extent that we have long dated derivative positions that span multiple calendar years, the contract will appear in more than one line item in the table below.

 

     June 30, 2009  
     Crude Oil     Natural Gas     Natural Gas
Liquids
 

Year of Expiration

   Net Long
(Short)
Position
(Bbls)
    Net Long
(Short)
position
(MMbtu)
    Net Long
(Short)
Position
(Bbls)
 

2009

   (450,800   (1,350,000   (111,621

2010

   (950,225   (2,023,500   (74,001

2011

   (949,000   (1,314,000   —     

2012

   (777,750   (1,317,600   —     

2013

   (748,250   (730,000   —     

2014

   (365,000   —        —     

We periodically enter into interest rate swap agreements to mitigate our floating rate interest exposure. As of June 30, 2009 we have swaps with a notional value between $25.0 million and $150.0 million, which, in aggregate, exchange $575.0 million of our floating rate obligation to a fixed rate obligation.

11. Partnership Equity and Distributions

General — Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our Available Cash (defined below) to unitholders of record on the applicable record date, as determined by our general partner.

In April 2009, we issued 3,500,000 Class D units valued at $49.7 million. The Class D units were issued to DCP LP Holdings, LP and DCP Midstream GP, LP in consideration for an additional 25.1% interest in East Texas and the NGL Hedge. The Class D units represent limited partnership interests in the partnership.

In March 2008, we issued 4,250,000 common limited partner units at $32.44 per unit, and received proceeds of $132.1 million, net of offering costs.

Definition of Available Cash — Available Cash, for any quarter, consists of all cash and cash equivalents on hand at the end of that quarter:

 

   

less the amount of cash reserves established by the general partner to:

 

   

provide for the proper conduct of our business;

 

   

comply with applicable law, any of our debt instruments or other agreements; and

 

   

provide funds for distributions to the unitholders and to our general partner for any one or more of the next four quarters;

 

   

plus, if our general partner so determines, all or a portion of cash and cash equivalents on hand on the date of determination of Available Cash for the quarter.

General Partner Interest and Incentive Distribution Rights — The general partner is entitled to a percentage of all quarterly distributions equal to its general partner interest of approximately 1% and limited partner interest of 1% as of June 30, 2009. The general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its current general partner interest.

The incentive distribution rights held by the general partner entitle it to receive an increasing share of Available Cash when pre-defined distribution targets are achieved. Currently, our distribution to our general partner related to its incentive distribution rights is at the highest level. The general partner’s incentive distribution rights were not reduced as a result of our common limited partner unit issuances, and will not be reduced if we issue additional units in the future and the general partner does not contribute a proportionate amount of capital to us to maintain its current general partner interest. Please read the Distributions of Available Cash after the Subordination Period section below for more details about the distribution targets and their impact on the general partner’s incentive distribution rights.

 

27


Table of Contents

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

Class D Units — The Class D Units will be eligible to receive distributions of Available Cash in August 2009, including the payment of the second quarter distribution. The Class D Units otherwise generally have the same rights as the Partnership’s outstanding Common Units and will convert into the Partnership’s Common Units on a one for one basis on August 17, 2009.

Subordinated Units — All of our subordinated units were held by DCP Midstream, LLC. The subordination period had an early termination provision that permitted 50% of the subordinated units, or 3,571,428 units, to convert into common units on a one-to-one basis in February 2008 and permitted the other 50% of the subordinated units, or 3,571,429 units, to convert into common units on a one-to-one basis in February 2009, following the satisfactory completion of the tests for ending the subordination period contained in our partnership agreement. Our board of directors certified that all conditions for early conversion were satisfied.

Distributions of Available Cash after the Subordination Period — Our partnership agreement, after adjustment for the general partner’s relative ownership level, requires that we make distributions of Available Cash from operating surplus for any quarter after the subordination period, which ended in February 2009, in the following manner:

 

   

first, to all unitholders and the general partner, in accordance with their pro rata interest, until each unitholder receives a total of $0.4025 per unit for that quarter;

 

   

second, 13% to the general partner, plus the general partner’s pro rata interest, and the remainder to all unitholders pro rata until each unitholder receives a total of $0.4375 per unit for that quarter;

 

   

third, 23% to the general partner, plus the general partner’s pro rata interest, and the remainder to all unitholders pro rata until each unitholder receives a total of $0.525 per unit for that quarter; and

 

   

thereafter, 48% to the general partner, plus the general partner’s pro rata interest, and the remainder to all unitholders.

The following table presents our cash distributions paid in 2009 and 2008:

 

Payment Date

   Per Unit
Distribution
   Total Cash
Distribution
          (Millions)

May 15, 2009

   $ 0.600    $ 20.1

February 13, 2009

     0.600      20.1

November 14, 2008

     0.600      20.1

August 14, 2008

     0.600      20.1

May 15, 2008

     0.590      19.6

February 14, 2008

     0.570      15.7

12. Net Income or Loss per Limited Partner Unit

Our net income or loss is allocated to the general partner and the limited partners, including the holders of the subordinated units, through the date of subordinated conversion, in accordance with their respective ownership percentages, after allocating Available Cash generated during the period in accordance with our partnership agreement.

Securities that meet the definition of a participating security are required to be considered for inclusion in the computation of basic earnings per unit using the two-class method. Under the two-class method, earnings per unit is calculated as if all of the earnings for the period were distributed under the terms of the partnership agreement, regardless of whether the general partner has discretion over the amount of distributions to be made in any particular period, whether those earnings would actually be distributed during a particular period from an economic or practical perspective, or whether the general partner has other legal or contractual limitations on its ability to pay distributions that would prevent it from distributing all of the earnings for a particular period.

These required disclosures do not impact our overall net income or loss, or other financial results; however, in periods in which aggregate net income exceeds our Available Cash it will have the impact of reducing net income per LPU. During the three and six months ended June 30, 2009 and 2008, no additional earnings were allocated to the general partner.

 

28


Table of Contents

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

Basic and diluted net income or loss per LPU is calculated by dividing limited partners’ interest in net income or loss, less pro forma additional earnings allocated to the general as described above, by the weighted-average number of outstanding LPUs during the period.

The following table illustrates our calculation of net income (loss) per LPU:

 

     Three Months Ended
June 30,
    Six Months Ended
June 30,
 
     2009     2008     2009     2008  
     (Millions)  

Net loss attributable to partners

   $ (42.1   $ (153.1   $ (21.0   $ (153.0

Net (income) loss attributable to predecessor operations

     —          (6.2     1.0        (12.8
                                

Net loss attributable to the partnership

     (42.1     (159.3     (20.0     (165.8

General partner interest in net income or net loss

     (2.7     (0.7     (5.9     (3.4
                                

Net loss available to limited partners

   $ (44.8   $ (160.0   $ (25.9   $ (169.2
                                

Net loss per LPU — basic and diluted

   $ (1.41   $ (5.67   $ (0.86   $ (6.36
                                

13. Commitments and Contingent Liabilities

Litigation — We are a party to various legal proceedings, as well as administrative and regulatory proceedings and commercial disputes that have arisen in the ordinary course of our business. Management currently believes that the ultimate resolution of these matters, taken as a whole, and after consideration of amounts accrued, insurance coverage or other indemnification arrangements, will not have a material adverse effect on our condensed consolidated results of operations, financial position, or cash flows. See Note 17 in Item 8 of our 2008 Form 10-K for additional details.

Anderson Gulch — In February 2009, the Colorado Department of Public Health and Environment, or CDPHE, issued a Notice of Violation that alleges violations of the environmental permit at our Anderson Gulch gas plant in 2008. The Anderson Gulch gas plant is owned by Collbran Valley Gas Gathering, LLC, our 70% owned joint venture in western Colorado. We have negotiated a resolution of this matter with the CDPHE for approximately $186,000, which will consist of a monetary penalty and an agreement to perform a supplemental environmental project.

El Paso — On February 27, 2009, a jury in the District Court, Harris County, Texas rendered a verdict in favor of El Paso E&P Company, L.P., or El Paso, and against one of our subsidiaries and DCP Midstream, LLC. As previously disclosed, the lawsuit, filed in December 2006, stems from an ongoing commercial dispute involving our Minden processing plant that dates back to August 2000, which includes periods of time prior to our ownership of this asset. Our responsibility for this judgment will be limited to the time period after we acquired the asset from DCP Midstream, LLC in December 2005. During the second quarter of 2009 we filed an appeal in the 14th Court of Appeals, Texas and will continue to defend ourselves vigorously against this claim. El Paso has filed an additional lawsuit in Louisiana, claiming damages for the same claims as the Texas matter, but for periods prior to our ownership of the asset. We intend to file motions to remove us from the Louisiana matter. As a result of the jury verdict, we recorded a contingent liability of $2.5 million in the fourth quarter of 2008 for this matter, which is included in other long-term liabilities in the condensed consolidated balance sheets as of June 30, 2009 and in other current liabilities in the condensed consolidated balance sheets as of December 31, 2008.

Indemnification — DCP Midstream, LLC has indemnified us for certain potential environmental claims, losses and expenses associated with the operation of the assets of certain of our predecessors. See the “Indemnification” section of Note 5 in Item 8 of our 2008 Form 10-K for additional details.

Insurance — We renewed our insurance policies in June and July 2009 for the 2009-2010 insurance year. Previously, we carried insurance jointly with DCP Midstream, LLC. Following our 2009 renewals, we now contract with a third party insurer separately from DCP Midstream for: (1) statutory workers’ compensation insurance; (2) automobile liability insurance for all owned, non-owned and hired vehicles; (3) excess liability insurance above the established primary limits for general liability and automobile liability insurance; and (4) property insurance, which covers replacement value of all real and personal property and

 

29


Table of Contents

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

includes business interruption/extra expense. However, we are still jointly insured with DCP Midstream, LLC for directors and officers insurance covering our directors and officers for acts related to our business activities. As a result of separating this insurance, we have reduced the excess liability and property limits to match the type and size of assets covered by this insurance. These changes have not resulted in any material change to the premiums we will pay in the 2009-2010 insurance year. All coverage is subject to certain limits and deductibles, the terms and conditions of which are common for companies that are of similar size to us and with similar types of operations.

Discovery’s previous property insurance policy expired in June 2009. Our insurance on Discovery for the 2009-2010 insurance year covers onshore and offshore property, onshore named windstorm and onshore business interruption insurance. The availability of named windstorm insurance has been significantly reduced as a result of higher industry-wide damage claims in past years. Additionally, the named windstorm insurance that is available comes at significantly higher premium amounts, higher deductibles and lower coverage limits. Consequently, Discovery elected to not purchase offshore named windstorm insurance coverage for the 2009-2010 insurance year.

14. Business Segments

Our operations are located in the United States and are organized into three reporting segments: (1) Natural Gas Services; (2) Wholesale Propane Logistics; and (3) NGL Logistics.

Natural Gas Services — The Natural Gas Services segment consists of (1) our Northern Louisiana system; (2) our Southern Oklahoma system; (3) our 40% limited liability company interest in Discovery; (4) our Colorado and Wyoming systems; (5) our East Texas system; and (6) our Michigan systems (acquired in October 2008).

Wholesale Propane Logistics — The Wholesale Propane Logistics segment consists of five owned and operated rail terminals, one leased marine terminal, one pipeline terminal and access to several open-access pipeline terminals.

NGL Logistics — The NGL Logistics segment consists of our Seabreeze and Wilbreeze NGL transportation pipelines, and a non-operated 45% equity interest in the Black Lake interstate NGL pipeline.

These segments are monitored separately by management for performance against our internal forecast and are consistent with internal financial reporting. These segments have been identified based on the differing products and services, regulatory environment and the expertise required for these operations. Gross margin is a performance measure utilized by management to monitor the business of each segment.

 

30


Table of Contents

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

The following tables set forth our segment information:

Three Months Ended June 30, 2009

 

     Natural Gas
Services
    Wholesale
Propane
Logistics
    NGL
Logistics
    Other     Total  
     (Millions)  

Total operating revenues

   $ 103.3      $ 46.9      $ 1.8      $ —        $ 152.0   
                                        

Gross margin (a)

   $ (3.4   $ 5.8      $ 1.3      $ —        $ 3.7   

Operating and maintenance expense

     (14.5     (2.4     (0.2     —          (17.1

Depreciation and amortization expense

     (15.4     (0.4     (0.4     (0.1     (16.3

General and administrative expense

     —          —          —          (7.1     (7.1

Earnings from equity method investments

     3.3        —          0.4        —          3.7   

Interest income

     —          —          —          0.1        0.1   

Interest expense

     —          —          —          (7.0     (7.0

Income tax expense (b)

     —          —          —          —          —     
                                        

Net (loss) income

     (30.0     3.0        1.1        (14.1     (40.0

Net income attributable to noncontrolling interests

     (2.1     —          —          —          (2.1
                                        

Net (loss) income attributable to partners

   $ (32.1   $ 3.0      $ 1.1      $ (14.1   $ (42.1
                                        

Non-cash derivative mark-to-market (c)

   $ (54.0   $ (0.1   $ —        $ (0.1   $ (54.2
                                        

Capital expenditures

   $ 62.1      $ 0.3      $ —        $ —        $ 62.4   
                                        
Three Months Ended June 30, 2008           
     Natural Gas
Services
    Wholesale
Propane
Logistics
    NGL
Logistics
    Other     Total  
     (Millions)  

Total operating revenues

   $ 247.3      $ 94.3      $ 2.7      $ —        $ 344.3   
                                        

Gross margin (a)

   $ (106.4   $ 2.4      $ 1.9      $ —        $ (102.1

Operating and maintenance expense

     (16.4     (2.7     (0.2     —          (19.3

Depreciation and amortization expense

     (12.4     (0.3     (0.3     —          (13.0

General and administrative expense

     —          —          —          (7.8     (7.8

Other

     —          1.5        —          —          1.5   

Earnings from equity method investments

     6.9        —          0.2        —          7.1   

Interest income

     —          —          —          2.0        2.0   

Interest expense

     —          —          —          (7.9     (7.9

Income tax expense (b)

     —          —          —          (0.3     (0.3
                                        

Net (loss) income

     (128.3     0.9        1.6        (14.0     (139.8

Net income attributable to noncontrolling interests

     (13.3     —          —          —          (13.3
                                        

Net (loss) income attributable to partners

   $ (141.6   $ 0.9      $ 1.6      $ (14.0   $ (153.1
                                        

Non-cash derivative mark-to-market (c)

   $ (170.2   $ (0.2   $ —        $ 0.1      $ (170.3
                                        

Capital expenditures

   $ 14.4      $ 1.2      $ 0.1      $ —        $ 15.7   
                                        

 

31


Table of Contents

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

Six Months Ended June 30, 2009

 

     Natural Gas
Services
    Wholesale
Propane
Logistics
    NGL
Logistics
    Other     Total  
     (Millions)  

Total operating revenues

   $ 253.1      $ 179.7      $ 3.6      $ —        $ 436.4   
                                        

Gross margin (a)

   $ 37.0      $ 31.6      $ 2.6      $ —        $ 71.2   

Operating and maintenance expense

     (27.7     (5.1     (0.5     —          (33.3

Depreciation and amortization expense

     (29.3     (0.7     (0.8     (0.1     (30.9

General and administrative expense

     —          —          —          (15.7     (15.7

Earnings from equity method investments

     1.8        —          0.8        —          2.6   

Interest income

     —          —          —          0.3        0.3   

Interest expense

     —          —          —          (14.3     (14.3

Income tax expense (b)

     —          —          —          (0.1     (0.1
                                        

Net (loss) income

     (18.2     25.8        2.1        (29.9     (20.2

Net income attributable to noncontrolling interests

     (0.8     —          —          —          (0.8
                                        

Net (loss) income attributable to partners

   $ (19.0   $ 25.8      $ 2.1      $ (29.9   $ (21.0
                                        

Non-cash derivative mark-to-market (c)

   $ (53.9   $ 0.1      $ —        $ (0.2   $ (54.0
                                        

Capital expenditures

   $ 118.0      $ 0.4      $ —        $ —        $ 118.4   
                                        
Six Months Ended June 30, 2008           
     Natural Gas
Services
    Wholesale
Propane
Logistics
    NGL
Logistics
    Other     Total  
     (Millions)  

Total operating revenues

   $ 522.3      $ 296.0      $ 5.3      $ —        $ 823.6   
                                        

Gross margin (a)

   $ (68.8   $ 11.0      $ 3.8      $ —        $ (54.0

Operating and maintenance expense

     (31.5     (5.4     (0.4     —          (37.3

Depreciation and amortization expense

     (24.4     (0.6     (0.7     —          (25.7

General and administrative expense

     —          —          —          (15.4     (15.4

Other

     —          1.5        —          —          1.5   

Earnings from equity method investments

     17.2        —          0.6