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DCP Midstream Partners, LP 10-Q 2010
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 September 30, 2010

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 November 4, 2010, there were outstanding 37,603,383 common units representing limited partner interests.

 

 

 


Table of Contents

 

DCP MIDSTREAM PARTNERS, LP

FORM 10-Q FOR THE QUARTER ENDED SEPTEMBER 30, 2010

TABLE OF CONTENTS

 

Item

        Page  
   PART I. FINANCIAL INFORMATION   

1.

  

Financial Statements (unaudited):

  
  

Condensed Consolidated Balance Sheets as of September 30, 2010 and December 31, 2009

     1   
  

Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2010 and 2009

     2   
  

Condensed Consolidated Statements of Comprehensive Income (Loss) for the Three and Nine Months Ended September 30, 2010 and 2009

     3   
  

Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2010 and 2009

     4   
  

Condensed Consolidated Statements of Changes in Equity for the Nine Months Ended September 30, 2010

     5   
  

Condensed Consolidated Statements of Changes in Equity for the Nine Months Ended September 30, 2009

     6   
  

Notes to the Condensed Consolidated Financial Statements

     7   

2.

  

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

     49   

3.

  

Quantitative and Qualitative Disclosures about Market Risk

     74   

4.

  

Controls and Procedures

     77   
   PART II. OTHER INFORMATION   

1.

  

Legal Proceedings

     78   

1A.

  

Risk Factors

     78   

6.

  

Exhibits

     81   
  

Signatures

     82   
  

Exhibit Index

     83   
  

Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes Oxley Act of 2002

  
  

Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes Oxley Act of 2002

  
  

Certification of Chief Executive Officer Pursuant to Section 906 of the Sarbanes Oxley Act of 2002

  
  

Certification of Chief Financial Officer Pursuant to Section 906 of the Sarbanes Oxley Act of 2002

  

 

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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

Bcf   

billion cubic feet

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

 

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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 fact, 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, 2009, 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 and producers’ access to capital 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 and quality 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, our ability to comply with the covenants to our credit agreement and our debt securities, as well as our ability to maintain our credit ratings;

 

   

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

 

   

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

 

   

additions and 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, including changes resulting from the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010.

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.

 

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Table of Contents

 

PART I. FINANCIAL INFORMATION

Item  1. Financial Statements

DCP MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

 

     September 30,
2010
    December 31,
2009
 
     (Millions)  

ASSETS

    

Current assets:

    

Cash and cash equivalents

   $ 11.8      $ 2.1   

Accounts receivable:

    

Trade, net of allowance for doubtful accounts of $0.7 million and $0.5 million, respectively

     48.0        78.7   

Affiliates

     55.1        73.8   

Inventories

     31.8        34.2   

Unrealized gains on derivative instruments

     1.7        7.3   

Assets held for sale

     7.9        —     

Other

     2.1        1.6   
                

Total current assets

     158.4        197.7   

Restricted investments

     —          10.0   

Property, plant and equipment, net

     1,042.5        1,000.1   

Goodwill

     99.7        92.1   

Intangible assets, net

     87.6        60.5   

Investments in unconsolidated affiliates

     103.6        114.6   

Unrealized gains on derivative instruments

     1.3        2.0   

Other long-term assets

     6.1        4.5   
                

Total assets

   $ 1,499.2      $ 1,481.5   
                

LIABILITIES AND EQUITY

    

Current liabilities:

    

Accounts payable:

    

Trade

   $ 57.8      $ 85.5   

Affiliates

     27.6        43.1   

Unrealized losses on derivative instruments

     36.1        41.5   

Other

     38.3        21.0   
                

Total current liabilities

     159.8        191.1   

Long-term debt

     612.8        613.0   

Unrealized losses on derivative instruments

     46.8        58.0   

Other long-term liabilities

     15.6        14.0   
                

Total liabilities

     835.0        876.1   
                

Commitments and contingent liabilities

    

Equity:

    

Common unitholders (37,603,383 and 34,608,183 units issued and outstanding, respectively)

     482.5        415.5   

General partner unitholders

     (6.1     (5.9

Accumulated other comprehensive loss

     (33.2     (31.9
                

Total partners’ equity

     443.2        377.7   

Noncontrolling interests

     221.0        227.7   
                

Total equity

     664.2        605.4   
                

Total liabilities and equity

   $ 1,499.2      $ 1,481.5   
                

See accompanying notes to condensed consolidated financial statements.

 

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DCP MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

 

     Three Months  Ended
September 30,
    Nine Months  Ended
September 30,
 
     2010     2009     2010     2009  
     (Millions, except per unit amounts)  

Operating revenues:

        

Sales of natural gas, propane, NGLs and condensate

   $ 102.8      $ 65.6      $ 431.4      $ 294.6   

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

     124.9        112.5        394.7        314.3   

Transportation, processing and other

     23.1        20.2        66.8        57.6   

Transportation, processing and other to affiliates

     5.6        4.0        16.2        11.1   

(Losses) gains from commodity derivative activity, net

     (15.8     4.4        13.0        (31.9

Losses from commodity derivative activity, net — affiliates

     (0.7     (1.0     (1.0     (3.6
                                

Total operating revenues

     239.9        205.7        921.1        642.1   
                                

Operating costs and expenses:

        

Purchases of natural gas, propane and NGLs

     155.2        112.4        524.8        360.8   

Purchases of natural gas, propane and NGLs from affiliates

     45.0        38.9        213.9        155.7   

Operating and maintenance expense

     19.2        19.0        58.8        52.3   

Depreciation and amortization expense

     19.2        16.4        55.7        47.3   

General and administrative expense

     3.3        2.9        10.4        8.1   

General and administrative expense — affiliates

     4.9        5.0        14.6        15.5   

Step acquisition — equity interest re-measurement gain

     (9.1     —          (9.1     —     

Other income

     (0.5     —          (1.0     —     

Other income — affiliates

     —          —          (3.0     —     
                                

Total operating costs and expenses

     237.2        194.6        865.1        639.7   
                                

Operating income

     2.7        11.1        56.0        2.4   

Interest income

     —          —          —          0.3   

Interest expense

     (7.5     (7.1     (22.0     (21.4

Earnings from unconsolidated affiliates

     4.1        8.4        18.6        11.0   
                                

(Loss) income before income taxes

     (0.7     12.4        52.6        (7.7

Income tax expense

     (0.1     —          (0.5     (0.1
                                

Net (loss) income

     (0.8     12.4        52.1        (7.8

Net income attributable to noncontrolling interests

     (3.3     (2.5     (4.4     (3.3
                                

Net (loss) income attributable to partners

     (4.1     9.9        47.7        (11.1

Net loss attributable to predecessor operations

     —          —          —          1.0   

General partner unitholders’ interest in net income or net loss

     (4.1     (3.4     (12.1     (9.3
                                

Net (loss) income allocable to limited partners

   $ (8.2   $ 6.5      $ 35.6      $ (19.4
                                

Net (loss) income per limited partner unit — basic

   $ (0.23   $ 0.21      $ 1.01      $ (0.63
                                

Net (loss) income per limited partner unit — diluted

   $ (0.23   $ 0.21      $ 1.01      $ (0.63
                                

Weighted-average limited partner units outstanding — basic and diluted

     36.0        31.7        35.1        30.6   

See accompanying notes to condensed consolidated financial statements.

 

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Table of Contents

DCP MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Unaudited)

 

     Three Months  Ended
September 30,
    Nine Months  Ended
September 30,
 
     2010     2009     2010     2009  
     (Millions)  

Net (loss) income

   $ (0.8   $ 12.4      $ 52.1      $ (7.8
                                

Other comprehensive income (loss):

        

Reclassification of cash flow hedge losses into earnings

     5.3        5.4        16.9        14.6   

Net unrealized losses on cash flow hedges

     (4.8     (8.3     (18.2     (8.0
                                

Total other comprehensive income (loss)

     0.5        (2.9     (1.3     6.6   
                                

Total comprehensive (loss) income

     (0.3     9.5        50.8        (1.2

Total comprehensive income attributable to noncontrolling interests

     (3.3     (2.5     (4.4     (3.3
                                

Total comprehensive (loss) income attributable to partners

   $ (3.6   $ 7.0      $ 46.4      $ (4.5
                                

See accompanying notes to condensed consolidated financial statements.

 

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DCP MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

 

     Nine Months Ended
September 30,
 
     2010     2009  
     (Millions)  

OPERATING ACTIVITIES:

    

Net income (loss)

   $ 52.1      $ (7.8

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

    

Depreciation and amortization expense

     55.7        47.3   

Earnings from unconsolidated affiliates

     (18.6     (11.0

Distributions from unconsolidated affiliates

     23.9        10.5   

Step acquisition — equity interest re-measurement gain

     (9.1     —     

Other, net

     (0.2     (0.4

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

    

Accounts receivable

     52.1        27.9   

Inventories

     19.0        (4.4

Net unrealized (gains) losses on derivative instruments

     (11.6     53.7   

Accounts payable

     (44.6     (22.8

Other current assets and liabilities

     10.7        1.5   

Other long-term assets and liabilities

     1.0        0.6   
                

Net cash provided by operating activities

     130.4        95.1   
                

INVESTING ACTIVITIES:

    

Capital expenditures

     (37.1     (143.0

Acquisitions, net of cash acquired

     (103.8     0.6   

Investments in unconsolidated affiliates

     (0.7     (5.8

Return of investment from unconsolidated affiliate

     1.2        —     

Proceeds from sale of assets

     1.7        0.3   

Purchases of available-for-sale securities

     —          (1.1

Proceeds from sales of available-for-sale securities

     10.1        51.1   
                

Net cash used in investing activities

     (128.6     (97.9
                

FINANCING ACTIVITIES:

    

Proceeds from debt

     658.2        113.7   

Payments of debt

     (658.4     (157.2

Payment of deferred financing costs

     (1.6     —     

Proceeds from issuance of common units, net of offering costs

     93.2        —     

Net change in advances to predecessor from DCP Midstream, LLC

     —          3.0   

Distributions to unitholders and general partner

     (74.4     (62.8

Distributions to noncontrolling interests

     (16.0     (15.4

Contributions from noncontrolling interests

     10.4        71.8   

Contributions from DCP Midstream, LLC

     —          0.7   

Purchase of additional interest in a subsidiary

     (3.5     —     
                

Net cash provided by (used in) financing activities

     7.9        (46.2
                

Net change in cash and cash equivalents

     9.7        (49.0

Cash and cash equivalents, beginning of period

     2.1        61.9   
                

Cash and cash equivalents, end of period

   $ 11.8      $ 12.9   
                

See accompanying notes to condensed consolidated financial statements.

 

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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
Unitholders
    Accumulated
Other
Comprehensive
(Loss) Income
    Noncontrolling
Interests
    Total
Equity
 
    (Millions)  

Balance, January 1, 2010

  $ —        $ 415.5      $ —        $ —        $ (5.9   $ (31.9   $ 227.7      $ 605.4   

Purchase of additional interest in a subsidiary

    —          1.0        —          —          —          —          (5.5     (4.5

Issuance of 2,990,000 common units

      93.1        —          —          —          —          —          93.1   

Equity based compensation

    —          0.2        —          —          —          —          —          0.2   

Distributions to unitholders and general partner

    —          (62.6     —          —          (11.8     —          —          (74.4

Distributions to noncontrolling interests

    —          —          —          —          —          —          (16.0     (16.0

Contributions from noncontrolling interests

    —          —          —          —          —          —          10.4        10.4   

Excess purchase price over acquired assets

    —          (0.8     —          —          —          —          —          (0.8
                                                               

Comprehensive income (loss):

               

Net income

    —          36.1        —          —          11.6        —          4.4        52.1   

Reclassification of cash flow hedges into earnings

    —          —          —          —          —          16.9        —          16.9   

Net unrealized losses on cash flow hedges

    —          —          —          —          —          (18.2     —          (18.2
                                                               

Total comprehensive income (loss)

    —          36.1        —          —          11.6        (1.3     4.4        50.8   
                                                               

Balance, September 30, 2010  

  $ —        $ 482.5      $ —        $ —        $ (6.1   $ (33.2   $ 221.0      $ 664.2   
                                                               

See accompanying notes to condensed consolidated financial statements.

 

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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
Unitholders
    Accumulated
Other
Comprehensive
(Loss) Income
    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

    —          (48.7     (2.1     (2.1     (9.9     —          —          (62.8

Distributions to noncontrolling interests

    —          —          —          —          —          —          (15.4     (15.4

Contributions from DCP Midstream, LLC

    —          0.7        —          —          —          —          —          0.7   

Contributions from noncontrolling interests

    —          —          —          —          —          —          71.8        71.8   

Issuance of 3,500,000 Class D units

    —          —          49.7        —          —          —          —          49.7   

Conversion of Class D units to common units

    —          66.8        (66.8     —          —          —          —          —     

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

    —          —          19.0        —          —          —          —          19.0   
                                                               

Comprehensive income (loss):

               

Net loss attributable to predecessor operations

    (1.0     —          —          —          —          —          —          (1.0

Net (loss) income

    —          (19.3     (4.4     4.6        9.0        —          3.3        (6.8

Reclassification of cash flow hedges into earnings

    —          —          —          —          —          14.6        —          14.6   

Net unrealized gains on cash flow hedges

    —          —          —          —          —          (8.0     —          (8.0
                                                               

Total comprehensive (loss) income

    (1.0     (19.3     (4.4     4.6        9.0        6.6        3.3        (1.2
                                                               

Balance, September 30, 2009

  $ —        $ 376.4      $ —        $ —        $ (5.7   $ (33.9   $ 227.4      $ 564.2   
                                                               

See accompanying notes to condensed consolidated financial statements.

 

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(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, storing and selling natural gas; producing, transporting, storing and selling propane; and producing, transporting and selling NGLs and condensate.

We are a Delaware 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 40% limited liability company interest in Discovery Producer Services LLC, or Discovery; our Wyoming system; a 75% interest in our Colorado system (of which 5% was acquired in February 2010); our 50.1% interest in our East Texas system (of which 25.1% was acquired in April 2009); our Michigan systems (of which certain assets were acquired in November 2009); our wholesale propane logistics business (which includes Atlantic Energy, acquired in July 2010); and our NGL transportation pipelines (including the Wattenberg pipeline acquired in January 2010 and our 100% interest in the Black Lake Pipeline Company, or Black Lake, 55% of which was acquired in July 2010, comprised of a 5% interest acquired from DCP Midstream, LLC, in a transaction among entities under common control, and an additional 50% interest acquired from an affiliate of BP PLC).

Our operations and activities are managed by our general partner, DCP Midstream GP, LP, which in turn is managed by its general partner, DCP Midstream GP, LLC, which we refer to as the General Partner, and is 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 32% of us.

The condensed consolidated financial statements include the accounts of the Partnership and all majority-owned subsidiaries where we have the ability to exercise control and undivided interests in jointly owned assets. Investments in greater than 20% owned affiliates that are not variable interest entities and where we do not have the ability to exercise control, and investments in less than 20% owned affiliates where we have the ability to exercise significant influence, are accounted for using the equity method. Intercompany balances and transactions have been eliminated.

The condensed consolidated financial statements include our accounts, which have been combined with the historical assets, liabilities and operations of our predecessor operations. We refer to the assets, liabilities and operations of DCP East Texas Holdings, LLC, or East Texas, prior to our acquisition of an additional 25.1% limited liability company interest from DCP Midstream, LLC in April 2009, and of Black Lake, prior to our acquisition of an additional 5% limited liability company interest from DCP Midstream, LLC in July 2010, collectively as our “predecessor.” Prior to our acquisition of an additional 25.1% limited liability company interest in East Texas, 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% limited liability company interest in East Texas, and account for East Texas as a consolidated subsidiary. Because the additional interest in East Texas and Black Lake were acquired from DCP Midstream, LLC, these transactions were considered to be among entities under common control. We recognize transfers of net assets between entities under common control at DCP Midstream, LLC’s basis in the net assets contributed. In addition, transfers of net assets 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 our financial information includes the historical results of our additional 25.1% interest in East Texas and our additional 5% interest in Black Lake for all periods presented. The amount of the purchase price in excess, or in deficit of DCP Midstream, LLC’s basis in the net assets, if any, is recognized as a reduction to, or an increase to partners’ equity, respectively. In addition, the results of operations of our Michigan systems, our Wattenberg pipeline, our additional 50% interest in Black Lake, and our acquisition of Atlantic Energy have been included in the condensed consolidated financial statements since their respective acquisition dates.

The condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP. Conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and notes. Although these estimates are based on management’s best available knowledge of current and expected future events, actual results could differ from those estimates. 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. All intercompany balances and transactions have been eliminated. Transactions between us and other DCP Midstream, LLC operations have been identified in the consolidated financial statements as transactions between affiliates.

 

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

 

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. Results of operations for the three and nine months ended September 30, 2010, are not necessarily indicative of the results that may be expected for the year ending December 31, 2010. 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 2009 Form 10-K.

Certain amounts in the prior period condensed consolidated financial statements have been reclassified to the current period presentation.

2. Recent Accounting Pronouncements

Financial Accounting Standards Board, or FASB, Accounting Standards Update, or ASU, 2010-06 “Fair Value Measurements and Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements,” or ASU 2010-06 — In January 2010, the FASB issued ASU 2010-06 which amended the Accounting Standards Codification, or ASC, Topic 820-10 “Fair Value Measurement and Disclosures—Overall.” ASU 2010-06 requires new disclosures regarding transfers in and out of assets and liabilities measured at fair value classified within the valuation hierarchy as either Level 1 or Level 2 and information about sales, issuances and settlements on a gross basis for assets and liabilities classified as Level 3. ASU 2010-06 clarifies existing disclosures on the level of disaggregation required and inputs and valuation techniques. The provisions of ASU 2010-06 became effective for us on January 1, 2010, except for disclosure of information about sales, issuances and settlements on a gross basis for assets and liabilities classified as Level 3, which is effective for us on January 1, 2011. The provisions of ASU 2010-06 impact only disclosures and we have disclosed information in accordance with the revised provisions of ASU 2010-06 within this filing.

ASU 2009-17 “Consolidation (Topic 810): Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities,” or ASU 2009-17 — In December 2009, the FASB issued ASU 2009-17 which amended ASC Topic 810 “Consolidation.” ASU 2009-17 requires entities to perform additional analysis of their variable interest entities and consolidation methods. This ASU became effective for us on January 1, 2010 and upon adoption we did not change our conclusions on which entities we consolidate in our condensed consolidated financial statements.

ASU 2009-13 “Revenue Recognition (Topic 605) Multiple-Deliverable Revenue Arrangements,” or ASU 2009-13 — In October 2009, the FASB issued ASU 2009-13 which amended ASC Topic 605 “Revenue Recognition.” The ASU addresses the accounting for multiple-deliverable arrangements, to enable vendors to account for products or services separately rather than as a combined unit. ASU 2009-13 is effective for us on January 1, 2011 and we are in the process of assessing the impact of ASU 2009-13 on our condensed consolidated results of operations, cash flows and financial position as a result of adoption.

3. Acquisitions

Gathering, Compression, Transportation, and Processing Assets

On July 30, 2010, we acquired Atlantic Energy, a wholly owned subsidiary of UGI Corporation, for $49.0 million plus propane inventory and other working capital of $17.3 million. We have incurred additional post-closing purchase price adjustments for net working capital of $1.9 million, which we have accrued in other current liabilities in our condensed consolidated balance sheet as of September 30, 2010. Atlantic Energy has a contractual agreement with Spectra Energy, the supplier of the acquired propane inventory, in which the final price of the acquired inventory will be determined based upon index rates at established future dates. Atlantic Energy’s sales agreements specify floating pricing terms in excess of the floating pricing terms established in the contractual agreement with Spectra. The acquisition was financed at closing with borrowings under our revolving credit facility. Atlantic Energy owns and operates a marine import terminal with 20 million gallons of above ground storage in the Port of Chesapeake, Virginia. The assets serve as a supply point for propane customers in the mid-Atlantic region, and will extend our existing northeast U.S. wholesale propane business into the mid-Atlantic. The results of Atlantic Energy’s assets are included prospectively from the date of acquisition in our Wholesale Propane Logistics segment.

 

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

 

The purchase price allocation is preliminary and is based on initial estimates of fair values at the date of the acquisition. We will continue to evaluate the initial purchase price allocation, which may be adjusted as additional information relative to the fair value of assets and liabilities becomes available. The preliminary purchase price allocation is as follows:

 

     (Millions)  

Cash consideration

   $ 66.3   

Payable to a subsidiary of UGI corporation

     1.9   
        

Aggregate consideration

   $ 68.2   
        

Cash

   $ 0.4   

Accounts receivable

     2.1   

Inventory

     16.6   

Property, plant and equipment

     15.2   

Intangible assets

     27.2   

Goodwill

     7.6   

Other liabilities

     (0.9
        

Total preliminary purchase price allocation

   $ 68.2   
        

On July 27, 2010, we acquired an additional 5% interest in Black Lake from DCP Midstream, LLC, in a transaction among entities under common control, for $1.5 million in cash, financed at closing with borrowings under our revolving credit facility. This transaction brought our ownership interest in Black Lake to 50%. The historical carrying value of DCP Midstream, LLC’s 5% interest in Black Lake was $0.7 million; accordingly we have recorded the $0.8 million excess purchase price over acquired assets as a decrease in common unitholders equity.

On July 30, 2010, we acquired an additional 50% interest in Black Lake from an affiliate of BP PLC, for $15.1 million in cash, financed at closing with borrowings under our revolving credit facility, bringing our ownership interest in Black Lake to 100%. Prior to our acquisition of an additional 50% interest in Black Lake, we accounted for Black Lake under the equity method of accounting. Subsequent to this transaction we account for Black Lake as a consolidated subsidiary. As a result of acquiring an additional 50% interest in Black Lake, we have remeasured our initial 50% interest in Black Lake to its fair value. Accordingly we recognized a gain of $9.1 million in step acquisition — equity interest re-measurement gain in our condensed consolidated statements of operations for the three and nine months ended September 30, 2010, which reflects the increase from the net assets historical carrying value, to the net assets fair value for our initial 50% interest. We have evaluated certain pre-acquisition contingencies arising from potential environmental issues that existed as of the acquisition date. We have determined that certain of these pre-acquisition contingencies are probable in nature and estimable as of the acquisition date and, accordingly, have recorded $0.9 million for these contingencies as a part of the purchase price allocation for Black Lake.

The results of our additional 50% interest in Black Lake are included prospectively from the date of acquisition in our NGL Logistics segment. Our calculation of the step acquisition — equity interest re-measurement gain is as follows:

 

     (Millions)  

Fair value of 50% equity interest in Black Lake

   $ 15.1   

Less: Carrying value of 50% equity interest in Black Lake

     6.0   
        

Step acquisition — equity interest re-measurement gain

   $ 9.1   
        

 

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

 

The purchase price is preliminary and is based on initial estimates of fair values at the date of the acquisition. We will continue to evaluate the initial purchase price allocation, which may be adjusted as additional information relative to the fair value of assets and liabilities becomes available. The preliminary purchase price allocation is as follows:

 

     (Millions)  

Cash consideration

   $ 15.1   
        

Cash

   $ 0.8   

Accounts receivable

     0.6   

Property, plant and equipment

     27.4   

Intangible assets

     2.7   

Other asset

     0.3   

Other liabilities

     (1.6
        

Fair value of 100% interest in Black Lake

     30.2   

Less:

  

Carrying value of initial 50% equity interest in Black Lake

     (6.0

Step acquisition — equity interest re-measurement gain

     (9.1
        

Total preliminary purchase price allocation

   $ 15.1   
        

On February 3, 2010, we acquired an additional 5% interest in Collbran Valley Gas Gathering LLC, or Collbran, from Delta Petroleum Company, or Delta, for $3.5 million in cash, bringing our total ownership in Collbran to 75%. In addition, as part of this transaction we paid Delta’s unpaid capital calls to Collbran of $2.4 million. We may pay an additional $2.0 million of contingent consideration to Delta depending on if Delta meets certain throughput volume thresholds by June 30, 2011, pursuant to a gathering agreement. As of March 31, 2010 we recognized the fair value of this contingent consideration of approximately $1.0 million, which we recorded to other current liabilities in our condensed consolidated balance sheet. Accordingly, we recognized a $5.5 million reduction in noncontrolling interest in equity, which represents the carrying value of Delta’s 5% interest in Collbran, and an increase of $1.0 million to common unitholders in equity, which represented the difference between the fair value of the consideration and the carrying value of Delta’s 5% interest. As of June 30, 2010, we reassessed the fair value of the contingent consideration and adjusted the fair value of the liability to approximately $0.5 million. As of September 30, 2010, we reassessed the fair value of the contingent consideration and adjusted the fair value of the liability to $0. Accordingly, we recognized $0.5 million and $1.0 million in other income in our condensed consolidated results of operations during the three and nine months ended September 30, 2010, respectively.

On January 28, 2010, we acquired an interstate natural gas liquids pipeline, or the Wattenberg pipeline, from Buckeye Partners, L.P., or Buckeye, for $22.0 million in cash, funded at closing with borrowings under our revolving credit facility. This transaction was accounted for as a business combination. The 350-mile pipeline originates in the Denver-Julesburg, or DJ Basin, in Colorado and terminates near the Conway hub in Bushton, Kansas. The pipeline is currently utilized by DCP Midstream, LLC as a market outlet for NGL production from certain of their plants in the DJ Basin. The results of the asset are included in our NGL Logistics segment prospectively, from the date of acquisition. The purchase price was allocated to property, plant and equipment.

 

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

 

Combined Financial Information

The following tables present the total operating revenues and net income attributable to partners, associated with the acquisition of the Wattenberg pipeline, Atlantic Energy, and an additional 50% interest in Black Lake, or the acquired assets, from their respective dates of acquisition through September 30, 2010. These amounts have been included in the condensed consolidated statement of operations.

 

     Three Months Ended September 30,
2010
 
     Wattenberg
Pipeline
     Atlantic
Energy
    Additional
50%
interest in
Black Lake
     Total  
     (Millions)  

Total operating revenues

   $ 1.8       $ 8.8      $ 1.1       $ 11.7   

Net income (loss) attributable to partners

   $ 1.2       $ (0.3   $ 0.2       $ 1.1   
     Nine Months Ended September 30,
2010
 
     Wattenberg
Pipeline
     Atlantic
Energy
    Additional
50%
interest in
Black Lake
     Total  
     (Millions)  

Total operating revenues

   $ 3.3       $ 8.8      $ 1.1       $ 13.2   

Net income (loss) attributable to partners

   $ 1.5       $ (0.3   $ 0.2       $ 1.4   

The following tables present unaudited pro forma information for the condensed consolidated statements of operations for the three and nine months ended September 30, 2010 and 2009, as if the acquisition of the acquired assets had occurred at the beginning of each period presented.

 

     Three Months Ended September 30,
2010
 
     DCP
Midstream
Partners, LP
    Acquisition
of the
Wattenberg
Pipeline
     Acquisition
of Atlantic
Energy
    Acquisition
of an
additional
50%
interest in
Black Lake
    DCP
Midstream
Partners, LP
Pro Forma
 
     (Millions, except per unit amounts)  

Total operating revenues

   $ 239.9      $ —         $ 3.2      $ 0.6      $ 243.7   

Net loss attributable to partners

   $ (4.1   $ —         $ (0.2   $ (0.1   $ (4.4

Less:

           

General partner unitholders interest in net income or loss

     (4.1     —           —          —          (4.1
                                         

Net loss allocable to limited partners

   $ (8.2   $ —         $ (0.2   $ (0.1   $ (8.5
                                         

Net loss per limited partner unit — basic and diluted

   $ (0.23   $ —         $ (0.01   $ —        $ (0.24

 

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

 

     Three Months Ended September 30,
2009
 
     DCP
Midstream
Partners, LP
    Acquisition
of the
Wattenberg
Pipeline
     Acquisition
of Atlantic
Energy
    Acquisition
of an
additional
50%
interest in
Black Lake
     DCP
Midstream
Partners, LP
Pro Forma
 
     (Millions, except per unit amounts)  

Total operating revenues

   $ 205.7      $ 1.7       $ 9.9      $ 1.9       $ 219.2   

Net income (loss) attributable to partners

   $ 9.9      $ 1.0       $ (0.6   $ 0.4       $ 10.7   

Less:

            

General partner unitholders interest in net income or loss

     (3.4     —           —          —           (3.4
                                          

Net income (loss) allocable to limited partners

   $ 6.5      $ 1.0       $ (0.6   $ 0.4       $ 7.3   
                                          

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

   $ 0.21      $ 0.03       $ (0.02   $ 0.01       $ 0.23   
     Nine Months Ended September 30,
2010
 
     DCP
Midstream
Partners, LP
    Acquisition
of the
Wattenberg
Pipeline
     Acquisition
of Atlantic
Energy
    Acquisition
of an
additional
50%
interest in
Black Lake
     DCP
Midstream
Partners, LP
Pro Forma
 
     (Millions, except per unit amounts)  

Total operating revenues

   $ 921.1      $ 0.2       $ 64.5      $ 4.1       $ 989.9   

Net income attributable to partners

   $ 47.7      $ 0.1       $ 1.1      $ 0.6       $ 49.5   

Less:

            

General partner unitholders interest in net income or loss

     (12.1     —           —          —           (12.1
                                          

Net income allocable to limited partners

   $ 35.6      $ 0.1       $ 1.1      $ 0.6       $ 37.4   
                                          

Net income per limited partner unit — basic and diluted

   $ 1.01      $ —         $ 0.03      $ 0.02       $ 1.06   

 

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

 

     Nine Months Ended September 30,
2009
 
     DCP
Midstream
Partners, LP
    Acquisition
of the
Wattenberg
Pipeline

(a)
    Acquisition
of Atlantic
Energy
     Acquisition
of an
additional
50%
interest in
Black Lake
     DCP
Midstream
Partners, LP
Pro Forma
 
     (Millions, except per unit amounts)  

Total operating revenues

   $ 642.1      $ 8.2      $ 41.2       $ 5.0       $ 696.5   

Net (loss) income attributable to partners

   $ (11.1   $ (67.6   $ 0.1       $ 1.2       $ (77.4

Less:

            

Net loss attributable to predecessor operations

     1.0        —          —           —           1.0   

General partner unitholders interest in net income or loss

     (9.3     (0.8     —           —           (10.1
                                          

Net (loss) income allocable to limited partners

   $ (19.4   $ (68.4   $ 0.1       $ 1.2       $ (86.5
                                          

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

   $ (0.63   $ (2.24   $ —         $ 0.04       $ (2.83

 

(a) During the second quarter of 2009, prior to our ownership, Buckeye received notification that several of its shippers on the Wattenberg pipeline intended to migrate to a competing pipeline that had recently been put into service. The notification by the shippers was accompanied by a significant decline in shipment volumes as compared to historical averages. As a result Buckeye recognized an impairment charge of $72.5 million in relation to the Wattenberg pipeline.

The pro forma information is not intended to reflect actual results that would have occurred if the assets had been combined during the periods presented, nor is it intended to be indicative of the results of operations that may be achieved by us in the future.

4. Agreements and Transactions with Affiliates

DCP Midstream, LLC

Omnibus Agreement and Other General and Administrative Charges

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. We incurred $2.5 million for three months ended September 30, 2010 and $2.5 million for the three months ended September 30, 2009, and $7.4 million and $7.3 million for the nine months ended September 30, 2010 and 2009, for all fees under the Omnibus Agreement.

East Texas incurs general and administrative expenses directly from DCP Midstream, LLC. East Texas incurred $2.0 million for each of the three months ended September 30, 2010 and 2009 and $5.9 million and $6.4 million for the nine months ended September 30, 2010 and 2009, respectively, for general and administrative expenses from DCP Midstream, LLC, which includes expenses for our predecessor operations.

In addition to the Omnibus Agreement and amounts incurred by East Texas, we incurred other fees with DCP Midstream, LLC of $0.3 million and $0.4 million for the three months ended September 30, 2010 and 2009, respectively and $1.1 million and $1.6 million for the nine months ended September 30, 2010 and 2009, respectively. These amounts include allocated expenses, including professional services, insurance and internal audit.

 

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

 

Other Agreements and Transactions with DCP Midstream, LLC

On September 16, 2010, we entered into an agreement with DCP Midstream, LLC to sell certain surplus equipment with a net book value of $6.3 million, for net proceeds of $3.6 million. The surplus equipment is the result of a consolidation of operations at our Anderson Gulch plant in Collbran. The net proceeds of $3.6 million have been distributed 75% to us and 25% to the noncontrolling interest in Collbran, based upon proportionate ownership. The title to the surplus equipment will pass to DCP Midstream, LLC upon removal of the equipment from our premises. As of September 30, 2010, the surplus equipment has been reclassified from property, plant and equipment, to current assets and classified as assets held for sale in our condensed consolidated balance sheets. In addition, we have recorded a deferred credit of $3.6 million in other current liabilities in our condensed consolidated balance sheets.

On June 30, 2010, we entered into an agreement with DCP Midstream, LLC to sell certain surplus equipment with a net book value of $1.6 million, for net proceeds of $2.2 million. The surplus equipment is the result of our integration efforts and synergies realized following our acquisition of certain companies that held natural gas gathering and treating assets from MichCon Pipeline Company in November 2009. The title to the surplus equipment will pass to DCP Midstream, LLC upon removal of the equipment from our premises. As of September 30, 2010, the surplus equipment has been reclassified from property, plant and equipment, to current assets and classified as assets held for sale in our condensed consolidated balance sheets. In addition, we have recorded a deferred credit of $2.2 million in other current liabilities in our condensed consolidated balance sheets.

In conjunction with our acquisition of a 50.1% limited liability company interest in East Texas from DCP Midstream, LLC, we entered into agreements with DCP Midstream, LLC whereby DCP Midstream, LLC will reimburse East Texas for certain expenditures on East Texas capital projects, as defined in the Contribution Agreements. These reimbursements are for certain capital projects which have commenced within three years from the respective acquisition dates. DCP Midstream, LLC made capital contributions to East Texas for capital projects of $10.4 million and $62.4 million for the nine months ended September 30, 2010 and 2009, respectively.

On February 11, 2009, our East Texas natural gas processing complex and natural gas delivery system known as the Carthage Hub, was 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 and East Texas filed a lawsuit in December 2009, to recover damages from the responsible third party. In the event we are unable to recover our costs and lost margin from the responsible third party, we have insurance covering property damage, net of applicable deductibles. Following this incident, DCP Midstream, LLC has agreed to reimburse to us twenty-five percent of any claims received as reimbursement of costs and lost margin, from the responsible third party or from insurance. DCP Midstream, LLC will pay seventy-five percent of costs related to the incident as a result of this agreement.

We sell a portion of our residue gas, NGLs and condensate to, purchase natural gas and other petroleum products from, and provide gathering and transportation services for, DCP Midstream, LLC. We anticipate continuing to purchase 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, included in our Northern Louisiana system, which is part of our Natural Gas Services segment, 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. We purchase natural gas from DCP Midstream, LLC upstream of Pelico and transport it to Pelico under a firm transportation agreement with an affiliate. Our purchases from DCP Midstream, LLC are at DCP Midstream, LLC’s actual acquisition cost plus any transportation service charges. Volumes that exceed our on-system demand and volumes supplying an industrial end user are sold to DCP Midstream, LLC at an index-based price, less contractually agreed to marketing fees. Revenues associated with these activities are reported gross in our condensed consolidated statements of operations as sales of natural gas, propane, NGLs and condensate to affiliates.

In April 2009, we entered into a thirteen year contractual arrangement with DCP Midstream, LLC in which we pay DCP Midstream, LLC a fee for processing services associated with the gas we gather on our Southern Oklahoma system, which is part of our Natural Gas Services segment. In addition, in February 2010, a contract was signed with DCP Midstream, LLC providing for adjustments to those fees based upon plant efficiencies related to our portion of volumes from our Southern Oklahoma system being processed at DCP Midstream, LLC’s plant through March 2022. We generally report fees associated with these activities in the condensed consolidated statements of operations as purchases of natural gas, propane, NGLs and condensate from affiliates. In addition, as part of this arrangement, DCP Midstream, LLC pays us a fee for certain gathering services. We generally report revenues associated with these activities in the condensed consolidated statements of operations as transportation, processing and other to affiliates.

 

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

 

In our NGL Logistics segment, we also have a contractual arrangement with a subsidiary of DCP Midstream, LLC that provides that DCP Midstream, LLC will pay us to transport NGLs over our Seabreeze and Wilbreeze pipelines, pursuant to fee-based rates that will be applied to the volumes transported. DCP Midstream, LLC is the sole shipper on these pipelines under the transportation agreements. We generally report revenues associated with these activities in the condensed consolidated statements of operations as transportation, processing and other to affiliates.

In conjunction with our acquisition of the Wattenberg pipeline, which is part of our NGL Logistics segment, we signed a transportation agreement with DCP Midstream, LLC pursuant to fee-based rates that will be applied to the volumes transported. The agreement is effective through November 2010, renewing on an evergreen basis thereafter. We generally report revenues associated with these activities in the condensed consolidated statements of operations as transportation, processing and other to affiliates.

DCP Midstream, LLC has issued parental guarantees, totaling $98.0 million as of September 30, 2010, in favor of certain counterparties to our commodity derivative instruments to mitigate a portion of our collateral requirements with those counterparties. We pay DCP Midstream, LLC interest of 0.5% per annum on $55.0 million of these outstanding guarantees.

DCP Midstream, LLC has issued parental guarantees for its 49.9% limited liability company interest in East Texas, totaling $5.5 million as of September 30, 2010, in favor of certain counterparties to processing and transportation agreements at East Texas. Concurrently, we have issued similar guarantees for our 50.1% interest.

DCP Midstream, LLC was a significant customer during the three and nine months ended September 30, 2010 and 2009.

Spectra Energy

We have a propane supply agreement with Spectra Energy, effective from May 1, 2008 through April 30, 2012, which provides us propane supply at our Providence marine terminal, which is included in our Wholesale Propane Logistics segment, for up to approximately 120 million gallons of propane annually. On June 15, 2010, we entered into an amendment to the supply agreement to shorten the term of the agreement by two years to April 30, 2012, which previously terminated on April 30, 2014. In consideration for shortening the term, Spectra Energy provided us with a cash payment of $3.0 million, which we recognized in other income — affiliates, in our Wholesale Propane Logistics segment, in the condensed consolidated statements of operations.

In conjunction with our acquisition of Atlantic Energy on July 30, 2010, we acquired a propane supply agreement with Spectra Energy, effective from May 1, 2010 to April 30, 2012, which provides us propane supply for our Chesapeake marine terminal, which is included in our Wholesale Propane Logistics segment, for up to approximately 65 million gallons of propane annually.

ConocoPhillips

We have multiple agreements with 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 $0.2 million and $0.7 million of capital reimbursements during the nine months ended September 30, 2010 and 2009, respectively.

 

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

 

Summary of Transactions with Affiliates

The following table summarizes transactions with affiliates:

 

     Three Months  Ended
September 30,
    Nine Months  Ended
September 30,
 
     2010     2009     2010     2009  
     (Millions)  

DCP Midstream, LLC:

        

Sales of natural gas, propane, NGLs and condensate

   $ 124.5      $ 110.1      $ 390.0      $ 311.2   

Transportation, processing and other

   $ 3.5      $ 2.0      $ 10.0      $ 4.6   

Purchases of natural gas, propane and NGLs

   $ 35.3      $ 21.3      $ 121.8      $ 83.7   

Losses from commodity derivative activity, net

   $ (0.7   $ (1.0   $ (1.0   $ (3.6

General and administrative expense

   $ 4.8      $ 4.9      $ 14.4      $ 15.3   

Interest expense

   $ —        $ 0.1      $ 0.2      $ 0.2   

Spectra Energy:

        

Transportation, processing and other

   $ —        $ —        $ 0.2      $ 0.2   

Purchases of natural gas, propane and NGLs

   $ 8.0      $ 14.2      $ 84.4      $ 62.3   

Other income

   $ —        $ —        $ 3.0      $ —     

ConocoPhillips:

        

Sales of natural gas, propane, NGLs and condensate

   $ 0.4      $ 2.4      $ 4.7      $ 3.1   

Transportation, processing and other

   $ 2.1      $ 2.0      $ 6.0      $ 6.3   

Purchases of natural gas, propane and NGLs

   $ 1.7      $ 3.4      $ 5.3      $ 9.3   

General and administrative expense

   $ 0.1      $ 0.1      $ 0.2      $ 0.2   

Unconsolidated affiliates:

        

Purchases of natural gas, propane and NGLs

   $ —        $ —        $ 2.4      $ 0.4   

 

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

 

We had balances with affiliates as follows:

 

     September 30,
2010
    December 31,
2009
 
     (Millions)  

DCP Midstream, LLC:

    

Accounts receivable

   $ 53.8      $ 71.5   

Accounts payable

   $ 25.4      $ 24.4   

Other current liabilities

   $ 5.8      $ —     

Unrealized gains on derivative instruments — current

   $ 0.7      $ 5.5   

Unrealized losses on derivative instruments — current

   $ (1.2   $ (5.4

Spectra Energy:

    

Accounts receivable

   $ 0.1      $ 0.1   

Accounts payable

   $ 1.7      $ 16.6   

ConocoPhillips:

    

Accounts receivable

   $ 1.2      $ 2.2   

Accounts payable

   $ 0.5      $ 2.1   

5. Property, Plant and Equipment

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

 

     Depreciable
Life
     September 30,
2010
    December 31,
2009
 
            (Millions)  

Gathering systems

     15 — 30 Years       $ 690.1      $ 683.0   

Processing plants

     25 — 30 Years         423.4        427.4   

Terminals

     25 — 30 Years         44.2        28.9   

Transportation

     25 — 30 Years         266.4        217.2   

General plant

     3 — 5 Years         15.3        15.2   

Other

     20 — 50 Years         0.1        0.1   

Construction work in progress

        49.5        21.8   
                   

Property, plant and equipment

        1,489.0        1,393.6   

Accumulated depreciation

        (446.5     (393.5
                   

Property, plant and equipment, net

      $ 1,042.5      $ 1,000.1   
                   

Interest capitalized on construction projects for the nine months ended September 30, 2010 was $0 and for the year ended December 31, 2009 was $1.3 million.

Depreciation expense was $18.0 million and $15.7 million for the three months ended September 30, 2010 and 2009, respectively and $53.0 million and $45.4 million for the nine months ended September 30, 2010 and 2009, respectively.

 

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

 

6. Goodwill and Intangible Assets

The change in the carrying amount of goodwill is as follows:

 

     September 30,
2010
    December 31,
2009
 
     (Millions)  

Beginning of period

   $ 92.1      $ 88.8   

Acquisitions

     7.6        3.3   
                

End of period

   $ 99.7      $ 92.1   
                

The carrying value of goodwill as of September 30, 2010 and December 31, 2009 was $62.8 million for our Natural Gas Services segment, and $36.9 million and $29.3 million, respectively, for our Wholesale Propane Logistics segment.

We performed our annual goodwill assessment during the quarter and concluded that the entire amount of goodwill on the balance sheet is recoverable. We used a discounted cash flow analysis supported by market valuation multiples to perform the assessment. Key assumptions in the analysis include the use of an appropriate discount rate, estimated future cash flows and an estimated run rate of operating and general and administrative costs. In estimating cash flows, we incorporate current market information, as well as historical and other factors, into our forecasted commodity prices. Our annual goodwill impairment tests indicated that our reporting units’ fair value exceeded the carrying or book value. If actual results are not consistent with our assumptions and estimates, or our assumptions and estimates change due to new information, we may be exposed to goodwill impairment charges, which would be recognized in the period in which the carrying value exceeds fair value.

Intangible assets consist of customer contracts, including commodity purchase, transportation and processing contracts, and related relationships. The gross carrying amount and accumulated amortization of these intangible assets are included in the accompanying consolidated balance sheets as intangible assets, net, and are as follows:

 

     September 30,
2010
    December 31,
2009
 
     (Millions)  

Gross carrying amount

   $ 96.1      $ 66.2   

Accumulated amortization

     (8.5     (5.7
                

Intangible assets, net

   $ 87.6      $ 60.5   
                

For the three and nine months ended September 30, 2010, we recorded amortization expense of $1.2 million and $2.7 million, respectively. For the three and nine months ended September 30, 2009, we recorded amortization expense of $0.7 million and $1.9 million respectively. As of September 30, 2010, the remaining amortization periods ranged from approximately 12 years to 24 years, with a weighted-average remaining period of approximately 18 years.

The weighted-average remaining amortization for both the $27.2 million of intangible assets acquired with our acquisition of Atlantic Energy on July 30, 2010, and the $2.7 million of intangible assets acquired with our acquisition of an additional 50% interest in Black Lake on July 30, 2010, is 15 years.

 

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

 

Estimated future amortization for these intangible assets is as follows:

 

Estimated Future Amortization

 
(Millions)  

2010 (remainder)

   $ 1.3   

2011

     5.2   

2012

     5.2   

2013

     5.2   

2014

     5.2   

Thereafter

     65.5   
        

Total

   $ 87.6   
        

7. Investments in Unconsolidated Affiliates

The following table summarizes our investments in unconsolidated affiliates:

 

    Percentage of
Ownership as of
September 30,  2010
and

December 31, 2009
    Carrying Value as of  
    September 30,
2010
    December 31,
2009
 
          (Millions)  

Discovery Producer Services LLC

    40%      $ 103.4      $ 108.2   

Black Lake Pipe Line Company (a)

    100% and 50%        N/A        6.2   

Other

    50%        0.2        0.2   
                 

Total investments in unconsolidated affiliates

    $ 103.6      $ 114.6   
                 

 

(a) On July 27, 2010 we acquired an additional 5% interest in Black Lake from DCP Midstream, LLC in a transaction among entities under common control, and on July 30, 2010, we acquired an additional 50% interest in Black Lake from an affiliate of BP PLC, bringing our ownership interest in Black Lake to 100%. Prior to our acquisition of an additional 50% interest in Black Lake, we accounted for Black Lake under the equity method of accounting. Subsequent to this transaction we account for Black Lake as a consolidated subsidiary.

There was a deficit between the carrying amount of the investment and the underlying equity of Discovery of $35.7 million and $37.6 million at September 30, 2010 and December 31, 2009, 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 $5.7 million at December 31, 2009, which was associated with, and was being accreted over, the life of the underlying long-lived assets of Black Lake.

 

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

 

Earnings from investments in unconsolidated affiliates were as follows:

 

     Three Months  Ended
September 30,
     Nine Months Ended
September 30,
 
     2010      2009      2010      2009  
     (Millions)  

Discovery Producer Services LLC

   $ 4.1       $ 7.9       $ 17.8       $ 9.7   

Black Lake Pipe Line Company and other (a)

     —           0.5         0.8         1.3   
                                   

Total earnings from unconsolidated affiliates

   $ 4.1       $ 8.4       $ 18.6       $ 11.0   
                                   

 

(a) On July 27, 2010 we acquired an additional 5% interest in Black Lake from DCP Midstream, LLC in a transaction among entities under common control, and on July 30, 2010, we acquired an additional 50% interest in Black Lake from an affiliate of BP PLC, bringing our ownership interest in Black Lake to 100%. Prior to our acquisition of an additional 50% interest in Black Lake, we accounted for Black Lake under the equity method of accounting. Subsequent to this transaction we account for Black Lake as a consolidated subsidiary.

The following summarizes financial information of our investments in unconsolidated affiliates:

 

     Three Months  Ended
September 30,
     Nine Months  Ended
September 30,
 
     2010 (a)      2009      2010 (a)      2009  
     (Millions)  

Statements of operations:

           

Operating revenue

   $ 42.7       $ 51.3       $ 154.8       $ 113.2   

Operating expenses

   $ 34.2       $ 32.4       $ 113.6       $ 91.2   

Net income

   $ 8.5       $ 19.0       $ 41.2       $ 21.9   

 

(a) Excludes the results of Black Lake from July 30, 2010.

 

     September 30,
2010 (a)
    December 31,
2009
 
     (Millions)  

Balance sheets:

    

Current assets

   $ 29.3      $ 41.8   

Long-term assets

     358.7        383.8   

Current liabilities

     (14.8     (17.4

Long-term liabilities

     (25.1     (23.6
                

Net assets

   $ 348.1      $ 384.6   
                

 

(a) On July 27, 2010 we acquired an additional 5% interest in Black Lake from DCP Midstream, LLC in a transaction among entities under common control, and on July 30, 2010, we acquired an additional 50% interest in Black Lake from an affiliate of BP PLC, bringing our ownership interest in Black Lake to 100%. Prior to our acquisition of an additional 50% interest in Black Lake, we accounted for Black Lake under the equity method of accounting. Subsequent to this transaction we account for Black Lake as a consolidated subsidiary.

 

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

 

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. If listed market prices or quotes are not available, we determine fair value based upon a market quote, adjusted by other market-based or independently sourced market data such as historical commodity volatilities, crude oil future yield curves, and/or counterparty specific considerations. These adjustments result in a fair value for each asset or liability under an “exit price” methodology, in line with how we believe a marketplace participant would value that asset or liability. These adjustments may include amounts to reflect counterparty credit quality, the effect of our own creditworthiness, the time value of money and/or the liquidity of the market.

 

   

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

 

   

Entity valuation adjustments are necessary to reflect the effect of our own credit quality on the fair value of our net liability 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 and liabilities. Although we take a portfolio approach to managing these assets/liabilities, in order to reflect the fair value of any one individual contract within the portfolio, we allocate all valuation adjustments down to the contract level, to the extent deemed necessary, based upon either the notional contract volume, or the contract value, whichever is more applicable.

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

Valuation Hierarchy

Our fair value measurements are grouped into a three-level valuation hierarchy. 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.

 

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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.

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

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

 

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

 

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 and restricted investment 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. Restricted investments have been used as collateral to secure the term loan portion of our credit facility. As of September 30, 2010, we held no short-term or restricted investments, as a result of the term loan facility being fully repaid during the first quarter of 2010.

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. Assets and liabilities acquired in business combinations are recorded at their fair value on the date of acquisition. The inputs used to determine such fair value are primarily based upon internally developed cash flow models and would generally be classified within Level 3, in the event that we were required to measure and record such assets at fair value within our consolidated financial statements. Additionally, we use fair value to determine the inception value of our asset retirement obligations. The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition, and would generally be classified within Level 3.

We utilize fair value on a recurring basis to measure our contingent consideration that is a result of certain acquisitions. The inputs used to determine such fair value are primarily based upon internally developed cash flow models and are classified within Level 3.

The following table presents the financial instruments carried at fair value as of September 30, 2010 and December 31, 2009, by consolidated balance sheet caption and by valuation hierarchy as described above:

 

     September 30, 2010     December 31, 2009  
     Level 1      Level 2     Level 3      Total
Carrying

Value
    Level 1      Level 2     Level 3     Total
Carrying

Value
 
     (Millions)  

Current assets:

                   

Short-term investments (a)

   $ —         $ —        $ —         $ —        $ —         $ 0.1      $ —        $ 0.1   

Commodity derivatives (b)

   $ —         $ 1.4      $ 0.3       $ 1.7      $ —         $ 6.9      $ 0.4      $ 7.3   

Long-term assets:

                   

Restricted investments

   $ —         $ —        $ —         $ —        $ —         $ 10.0      $ —        $ 10.0   

Commodity derivatives (c)

   $ —         $ 0.6      $ 0.7       $ 1.3      $ —         $ 1.8      $ 0.2      $ 2.0   

Current liabilities (d):

                   

Commodity derivatives

   $ —         $ (15.8   $ —         $ (15.8   $ —         $ (20.3   $ (0.8   $ (21.1

Interest rate derivatives

   $ —         $ (20.3   $ —         $ (20.3   $ —         $ (20.4   $ —        $ (20.4

Long-term liabilities (e):

                   

Commodity derivatives

   $ —         $ (33.5   $ —         $ (33.5   $ —         $ (46.0   $ (0.4   $ (46.4

Interest rate derivatives

   $ —         $ (13.3   $ —         $ (13.3   $ —         $ (11.6   $ —        $ (11.6

 

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

 

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

 

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 were movements to/from the classification of an instrument as Level 3, we would reflect such items in the table below within the “Transfers into Level 3” and “Transfers out of Level 3” captions.

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

 

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

Three months ended September 30, 2010:

  

Beginning balance

   $ 0.8      $ 1.8      $ (0.1   $ (0.2

Net realized and unrealized (losses) gains included in earnings

     (0.1     (1.1     0.1        0.2   

Transfers into Level 3 (a)

     —          —          —          —     

Transfers out of Level 3 (a)

     (0.4     —          —          —     

Purchases, Issuances and Settlements net

     —          —          —          —     
                                

Ending balance

   $ 0.3      $ 0.7      $ —        $ —     
                                

Net unrealized gains (losses) still held included in earnings (b)

   $ 0.2      $ (0.9   $ —        $ —     
                                

Three months ended September 30, 2009:

        

Beginning balance

   $ 1.2      $ —        $ (0.1   $ (0.9

Net realized and unrealized (losses) gains included in earnings

     (0.2     0.1        (0.6     (0.1

Net transfers in (out) of Level 3 (c)

     —          —          —          —     

Purchases, Issuances and Settlements net

     (0.6     —          (0.2     —     
                                

Ending balance

   $ 0.4      $ 0.1      $ (0.9   $ (1.0
                                

Net unrealized (losses) gains still held included in earnings (b)

   $ (0.8   $ 0.1      $ (0.6   $ (0.1
                                

 

(a) Amounts transferred in and amounts transferred out are reflected at fair value as of 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 or losses relating to assets and liabilities classified as Level 3 that are still held as of September 30, 2010 and 2009.
(c) 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.

 

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

 

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

Nine months ended September 30, 2010:

  

Beginning balance

   $ 0.4      $ 0.2      $ (0.8   $ (0.4

Net realized and unrealized gains included in earnings

     0.3        0.5        0.2        0.4   

Transfers into Level 3 (a)

     —          —          —          —     

Transfers out of Level 3 (a)

     (0.4     —          —          —     

Purchases, Issuances and Settlements net

     —          —          0.6        —     
                                

Ending balance

   $ 0.3      $ 0.7      $ —        $ —     
                                

Net unrealized gains still held included in earnings (b)

   $ 0.3      $ 0.5      $ —        $ —     
                                

Nine months ended September 30, 2009:

        

Beginning balance

   $ 0.3      $ 1.7      $ —        $ —     

Net realized and unrealized losses included in earnings

     (3.0     (1.6     (0.9     (1.0

Net transfers in (out) of Level 3 (c)

     —          —          —          —     

Purchases, Issuances and Settlements net

     3.1        —          —          —     
                                

Ending balance

   $ 0.4      $ 0.1      $ (0.9   $ (1.0
                                

Net unrealized gains (losses) still held included in earnings (b)

   $ 0.4      $ (1.6   $ (0.9   $ (1.0
                                

 

(a) Amounts transferred in and amounts transferred out are reflected at fair value as of 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 or losses relating to assets and liabilities classified as Level 3 that are still held as of September 30, 2010 and 2009.
(c) 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.

As of March 31, 2010, we recognized the fair value of our contingent consideration, which is classified as Level 3, in relation to our acquisition of an additional 5% interest in Collbran, from Delta, of approximately $1.0 million, which we recorded to other current liabilities in our condensed consolidated balance sheets. As of June 30, 2010, we reassessed the fair value of the contingent consideration and adjusted the fair value of the liability to approximately $0.5 million. As of September 30, 2010, we reassessed the fair value of the contingent consideration and adjusted the fair value of the liability to $0. Accordingly we recognized $0.5 million and $1.0 million in other income in our condensed consolidated results of operations during the three and nine months ended September 30, 2010, respectively.

During the three and nine months ended September 30, 2010, we had no significant transfers into and out of Levels 1, 2 and 3. To qualify as a transfer, the asset or liability must have existed in the previous reporting period and moved into a different level during the current period.

Estimated Fair Value of Financial Instruments

We have determined fair value amounts using available market information and appropriate valuation methodologies. However, considerable judgment is required in interpreting market data to develop the estimates of fair value. Accordingly, the estimates presented herein are not necessarily indicative of the amounts that we could realize in a current market exchange. The use of different market assumptions and/or estimation methods may have a material effect on the estimated fair value amounts.

 

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

 

The fair value of restricted investments, accounts receivable and accounts payable are not materially different from their carrying amounts because of the short term nature of these instruments or the stated rates approximating market rates. Unrealized gains and unrealized losses on derivative instruments are carried at fair value. The carrying and fair values of outstanding balances under our Credit Agreement are $363.0 million, and $353.3 million, respectively, as of September 30, 2010 and $613.0 million and $590.0 million, respectively, as of December 31, 2009. The carrying and fair values of our 3.25% Senior notes are $250.0 million and $252.0 million, respectively as of September 30, 2010. We determine the fair value of our credit facility borrowings based upon the discounted present value of expected future cash flows, taking into account the difference between the contractual borrowing spread and the spread for similar credit facilities available in the marketplace. Additionally, we have executed interest rate swap agreements on a portion of our interest rate exposure which swaps variable for fixed interest rates.

9. Debt

Long-term debt was as follows:

 

     September 30,
2010
    December 31,
2009
 
     (Millions)  

Credit Agreement

    

Revolving credit facility, weighted-average variable interest rate of 0.74% and 0.69%, respectively, and net effective interest rate of 5.09% and 4.41%, respectively, due June 21, 2012 (a)

   $ 363.0      $ 603.0   

Term loan facility, variable interest rate of 0.34%, due June 21, 2012 (b)

     —          10.0   
                

Total amounts outstanding under the Credit Agreement

     363.0        613.0   

Debt Securities

    

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

     250.0        —     

Unamortized discount

     (0.2     —     
                

Total long-term debt

   $ 612.8      $ 613.0   
                

 

(a) $350.0 million of debt has been swapped to a fixed rate obligation with effective fixed rates ranging from 3.97% to 5.19%, for a net effective rate of 5.09% on the $363.0 million of outstanding debt under our revolving credit facility as of September 30, 2010.
(b) The term loan facility was fully secured by restricted investments as of December 31, 2009. The term loan was repaid during the first quarter of 2010.

Credit Agreement

We have an $850.0 million revolving credit facility that matures June 21, 2012, or the Credit Agreement.

Effective June 28, 2010, we transferred both the funded and the unfunded portions of the former Lehman Brothers Commercial Bank commitment to Morgan Stanley. The transfer reinstated $25.4 million of available capacity to our revolving credit facility.

At September 30, 2010 and December 31, 2009, we had $0.5 million and $0.3 million, respectively, letters of credit issued under the Credit Agreement outstanding. As of December 31, 2009 we had outstanding term loan balances under the Credit Agreement, which were fully collateralized by investments in high-grade securities, classified as restricted investments in the accompanying condensed consolidated balance sheets as of December 31, 2009. As of September 30, 2010 the unused capacity under the revolving credit facility was $486.5 million.

 

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

 

Our borrowing capacity is limited at September 30, 2010, by the Credit Agreement’s financial covenant requirements. Except in the case of a default, amounts borrowed under our credit facility will not mature prior to the June 21, 2012 maturity date.

The Credit Agreement requires us to maintain a leverage ratio (the ratio of our consolidated indebtedness to our consolidated EBITDA, in each case as is defined by the Credit Agreement) of not more than 5.0 to 1.0, and on a temporary basis for not more than three consecutive quarters (including the quarter in which such acquisition is consummated) following the consummation of asset acquisitions in the midstream energy business of not more than 5.5 to 1.0.

Debt Securities

On September 30, 2010 we issued $250.0 million of our 3.25% Senior Notes due October 1, 2015. We received net proceeds, of $247.8 million net of underwriters’ fees, related expense and unamortized discounts of $1.5 million, $0.5 million and $0.2 million, respectively, which we used to repay funds borrowed under the revolver portion of our Credit Facility. Interest on the notes will be paid semi-annually on April 1 and October 1 of each year, commencing April 1, 2011. The notes will mature on October 1, 2015 unless redeemed prior to maturity.

We have incurred $2.0 million of underwriters’ fees and related expense with the issue of the notes, which we deferred in other long term assets in our condensed consolidated balance sheets. We will amortize these costs over the term of the notes.

The notes are senior unsecured obligations, ranking equally in right of payment with our existing unsecured indebtedness, including indebtedness under our Credit Facility. We are not required to make mandatory redemption or sinking fund payments with respect to these notes. The securities are redeemable at a premium at our option.

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

 

     Debt
Maturities
 
     (Millions)  

2010

   $ —     

2011

     —     

2012

     363.0   

2013

     —     

2014

     —     

Thereafter

     250.0   
        
     613.0   

Unamortized discount

     (0.2
        

Total

   $ 612.8   
        

Other Agreements

As of September 30, 2010 we had a contingent letter of credit facility for up to $10.0 million, on which we pay a fee of 0.50% per annum. This facility reduces the amount of cash we may be required to post as collateral. As of September 30, 2010, we have $0 letters of credit issued on this facility; we will pay a net fee of 1.75% per annum on letters of credit issued on this facility. This facility was issued directly by a financial institution and does not reduce the available capacity under our credit facility.

10. Risk Management and Hedging Activities

Our day to day operations expose us to a variety of risks including but not limited to changes in the prices of commodities that we buy or sell, changes in interest rates, and the creditworthiness of each of our counterparties. We manage certain of these exposures with both physical and financial transactions. 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.

 

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

 

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 a portion of the risk of weakening natural gas, NGL and condensate prices associated with our gathering, processing and sales activities, thereby stabilizing our cash flows. We have mitigated a portion of our expected commodity price risk associated with our gathering, processing and sales activities through 2015 with natural gas and crude oil derivative instruments. Additionally, given the limited depth of the NGL derivatives market, we primarily utilize crude oil swaps to mitigate a portion of our commodity price exposure for propane and heavier NGLs. Historically, prices of NGLs have been generally related to the price of crude oil, with some exceptions, notably in late 2008 to early 2009, when NGL pricing was at a greater discount to crude oil. Given the relationship and the lack of liquidity in the NGL financial market, we have historically used crude oil swaps to mitigate a portion of NGL price risks. When the relationship of NGL prices to crude oil prices is at a discount to historical ranges, we experience additional exposure as a result of the relationship. These transactions are primarily accomplished through the use of forward contracts, which are swap futures that effectively exchange our floating price risk for a fixed price. However, the type of instrument that we use to mitigate a portion of our risk may vary depending upon our risk management objective. These transactions are not designated as hedging instruments for accounting purposes and the change in fair value is reflected within our condensed consolidated statements of operations as a gain or a loss on commodity derivative activity.

With respect to our Pelico system, we may enter into financial derivatives to lock in transportation margins across the system, or to lock in margins around our leased storage facility 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 and any inventory is stated at lower of cost or market, 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 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 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 as a gain or loss on commodity derivative activity.

Our portfolio of commodity derivative activity is primarily accounted for using the mark-to-market method of accounting, whereby changes in fair value are recorded directly to the condensed consolidated statements of operations; however, depending upon our risk profile and objectives, in certain limited cases, we may execute transactions that qualify for the hedge method of accounting.

Commodity Cash Flow Hedges — Effective July 1, 2007, we elected to discontinue using the hedge method of accounting for derivatives that manage our commodity price risk. Prior to July 1, 2007, we used NGL, natural gas and crude oil swaps to mitigate a portion of the risk of market fluctuations in the price of NGLs, natural gas and condensate. Given our election to discontinue using the hedge method of accounting, the remaining net losses deferred in AOCI relative to cash flow hedges are reclassified to sales of natural gas, propane, NGLs and condensate, through December 2011, as the underlying transactions impact earnings.

 

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

 

Interest Rate Risk

We mitigate a portion of our interest rate risk on our revolving credit facility with interest rate swaps which convert a portion of the interest rate associated with the indebtedness outstanding under our revolving credit facility to a fixed rate obligation through June 2012, thereby reducing the exposure to market rate fluctuations.

On September 23, 2010 we filed a prospectus with the SEC relating to the issuance of $250.0 million of our 3.25% Senior Notes, the proceeds of which were used to pay down our revolving credit facility. As a result of our pay down of the revolving credit facility, effective September 23, 2010, we discontinued cash flow hedge accounting on $225.0 million of our interest rate swap agreements. Effective September 23, 2010, we account for $225.0 million of interest rate swaps using the mark-to-market method of accounting, whereby changes in fair value are recorded directly to the condensed consolidated statements of operations, in interest expense. The net losses deferred in AOCI as of September 23, 2010 will be reclassified into interest expense as the hedged transactions impact earnings. On October 1, 2010, we terminated $200.0 million of these swaps that would have matured in December 2010, for $1.3 million. We also exchanged $275.0 million of interest rate swaps with an effective date of December 2010 through June 2012 for $150.0 million of interest rate swaps effective December 2010 through June 2014. These swaps are accounted for under the mark-to-market method of accounting.

We have designated $350.0 million of our interest rate swap agreements 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.

As of September 30 2010, $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.

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 September 30, 2010, we are not a party to any agreements that would be subject to these provisions other than our Credit Agreement.

 

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Table of Contents

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

 

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

Depending upon the movement of commodity prices and interest rates, each of our individual contracts with counterparties to our commodity derivative instruments or to our interest rate swap instruments are in either a net asset or net liability position. As of September 30, 2010, we had $48.1 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 September 30, 2010 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 September 30, 2010, 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 $47.6 million.

As of September 30, 2010, our interest rate swaps were in a net liability position of approximately $33.6 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 September 30, 2010 we had a contingent letter of credit facility for up to $10.0 million, on which we have $0 letters of credit issued. DCP Midstream, LLC had issued and outstanding parental guarantees totaling $98.0 million in favor of certain counterparties to our commodity derivative instruments. This contingent letter of credit facility and the parental guarantees reduce the amount of cash we may be required to post as collateral. As of September 30, 2010, we had no cash collateral posted with counterparties to our commodity derivative instruments.

Summarized Derivative Information

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

 

     September 30,
2010
    December 31,
2009
 
     (Millions)  

Commodity cash flow hedges:

    

Net deferred losses in AOCI

   $ (0.5   $ (0.8

Interest rate cash flow hedges:

    

Net deferred losses in AOCI

     (32.7     (31.1
                

Total AOCI

   $ (33.2   $ (31.9
                

 

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Table of Contents

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

 

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

  September 30,
2010
    December 31,
2009
   

Balance Sheet Line Item

  September 30,
2010
    December 31,
2009
 
    (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

  $ (13.7   $ (20.4

Unrealized gains on derivative instruments — long-term

    —          —       

Unrealized losses on derivative instruments — long-term

    (8.9     (11.6
                                 
  $ —        $ —          $ (22.6   $ (32.0
                                 

Derivative Assets Not Designated as Hedging Instruments:

  

 

Derivative Liabilities Not Designated as Hedging Instruments:

  

Commodity derivatives:

     

Commodity derivatives:

   

Unrealized gains on derivative instruments — current

  $ 1.7      $ 7.3     

Unrealized losses on derivative instruments — current

  $ (15.8   $ (21.1

Unrealized gains on derivative instruments — long-term

    1.3        2.0     

Unrealized losses on derivative instruments — long-term

    (33.5     (46.4
                                 
  $ 3.0      $ 9.3        $ (49.3   $ (67.5
                                 

Interest rate derivatives:

     

Interest rate derivatives:

   

Unrealized gains on derivative instruments — current

  $ —        $ —       

Unrealized losses on derivative instruments — current

  $ (6.6   $ —     

Unrealized gains on derivative instruments — long-term

    —          —       

Unrealized losses on derivative instruments — long-term

    (4.4     —     
                                 
  $ —        $ —          $ (11.0   $ —     
                                 

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.

 

    Loss Recognized in
AOCI on Derivatives
— Effective  Portion
    (Loss) Gain
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 September 30,        
    2010     2009     2010     2009           2010     2009        
    (Millions)     (Millions)           (Millions)        

Interest rate derivatives

  $ (4.8   $ (8.3   $ (5.4   $ (5.3     (a   $ —        $ —          (a )(c) 

Commodity derivatives

  $ —        $ —        $ 0.1      $ (0.1     (b   $ —        $ —          (b )(c) 

 

(a) Included in interest expense in our condensed consolidated statements of operations.
(b) Included in sales of natural gas, propane, NGLs and condensate in our condensed consolidated statements of operations.
(c) For the three months ended September 30, 2010 and 2009, 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.

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

 

    Loss Recognized in
AOCI on Derivatives
— Effective  Portion
    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
 
    Nine Months Ended September 30,          
    2010     2009     2010     2009           2010     2009          
    (Millions)     (Millions)           (Millions)           (Millions)  

Interest rate derivatives

  $ (18.2   $ (8.0   $ (16.6   $ (13.9     (a   $ —        $ —          (a )(c)    $ (19.7

Commodity derivatives

  $ —        $ —        $ (0.3   $ (0.7     (b   $ —        $ —          (b )(c)    $ (0.3

 

(a) Included in interest expense in our condensed consolidated statements of operations.
(b) Included in sales of natural gas, propane, NGLs and condensate in our condensed consolidated statements of operations.
(c) For the nine months ended September 30, 2010 and 2009, 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: Statements of Operations Line Item

   Three Months Ended
September 30,
    Nine Months  Ended
September 30,
 
     2010     2009     2010     2009  
     (Millions)  

Third party:

        

Realized

   $ 2.6      $ 2.8      $ 0.5      $ 17.6   

Unrealized

     (18.4     1.6        12.5        (49.5
                                

Gains (losses) from commodity derivative activity, net

   $ (15.8   $ 4.4      $ 13.0      $ (31.9
                                

Affiliates:

        

Realized

   $ (0.5   $ 0.1      $ (0.4   $ (0.3

Unrealized

     (0.2     (1.1     (0.6     (3.3
                                

Losses from commodity derivative activity, net — affiliates

   $ (0.7   $ (1.0   $ (1.0   $ (3.6
                                

Interest Rate Derivatives: Statements of Operations Line Item

   Three Months Ended
September 30,
    Nine Months  Ended
September 30,
 
     2010     2009     2010     2009  
     (Millions)  

Third party:

        

Unrealized

   $ (0.1   $ —        $ (0.1   $ —     
                                

Interest expense

   $ (0.1   $ —        $ (0.1   $ —     
                                

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

 

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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. This table also presents our net long or short natural gas basis swap positions separately from our net long or short natural gas positions.

 

     September 30, 2010  
     Crude Oil     Natural Gas     Natural Gas
Liquids
    Natural Gas
Basis Swaps
 

Year of Expiration

   Net Long
(Short)
Position
(Bbls)
    Net Long
(Short)
Position
(MMBtu)
    Net Long
(Short)
Position
(Bbls)
    Net Long
(Short)
Position
(MMBtu)
 

2010

     (245,180     (593,300     (20,524     (31,000

2011

     (949,000     (365,000     6,810        —     

2012

     (777,750     (366,000     —          —     

2013

     (748,250     (365,000     —          —     

2014

     (547,500     (365,000     —          —     

2015

     (182,500     —          —          —     

We periodically enter into interest rate swap agreements to mitigate a portion of our floating rate interest exposure. As of September 30, 2010, we have swaps with a notional value between $25.0 million and $150.0 million, which, in aggregate, exchange up to $575.0 million of our floating rate obligation to a fixed rate obligation through June 2012. On October 1, 2010, we terminated $200.0 million of these swaps, that would have matured in December 2010, for $1.3 million. We also exchanged $275.0 million of interest rate swaps with an effective date of December 2010 through June 2012 for $150.0 million of interest rate swaps effective December 2010 through June 2014.

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 as defined below, to unitholders of record on the applicable record date, as determined by our general partner.

In September 2010, we issued 5,200 units, from our Long Term Incentive Plan, to non-employee directors as compensation for their service during 2010.

In August 2010, we issued 2,990,000 common units at $32.57 per unit. We received proceeds of $93.1 million, net of offering costs.

On May 26, 2010, we filed a universal shelf registration statement on Form S-3 with the SEC with a maximum aggregate offering price of $1.5 billion, to replace an existing shelf registration statement. The universal shelf registration statement will allow us to register and issue additional partnership units and debt securities.

In November 2009, we issued 2,500,000 common units at $25.40 per unit, and in December 2009 we issued an additional 375,000 common units to the underwriters upon exercise of their overallotment option. We received proceeds of $69.5 million, net of offering costs.

In April 2009, we issued 3,500,000 Class D units valued at $49.7 million. The Class D units were issued to DCP Midstream, LLC in consideration for an additional 25.1% interest in East Texas and a fixed price natural gas liquids derivative by NGL component for the period April 2009 to March 2010. The Class D units converted into our common units on a one-for-one basis on August 17, 2009.

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

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

 

   

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 September 30, 2010. 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.

Class D Units — All of the Class D units were held by DCP Midstream, LLC and converted into our common units on a one for one basis on August 17, 2009. The holders of the Class D units received the distribution for the second quarter of 2009, paid on August 14, 2009.

Subordinated Units — All of our subordinated units were held by DCP Midstream, LLC and were converted to common units by February 2009. 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. The board of directors of the General Partner 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 2010 and 2009:

 

Payment Date

   Per Unit
Distribution
     Total Cash
Distribution
 
            (Millions)  

August 13, 2010

   $ 0.610       $ 25.3   

May 14, 2010

   $ 0.600       $ 24.6   

February 12, 2010

   $ 0.600       $ 24.6   

November 13, 2009

   $ 0.600       $ 22.6   

August 14, 2009

   $ 0.600       $ 22.6   

May 15, 2009

   $ 0.600       $ 20.1   

February 13, 2009

   $ 0.600       $ 20.1   

 

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

 

12. 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 2009 Form 10-K for additional details.

Westfield — In July 2010 there was an explosion at a condominium complex in Norfolk, Massachusetts in which a worker at the condominium was killed. An investigation of the accident by the Massachusetts State Fire Marshall has indicated that the propane that exploded may have been unodorized. The investigation further indicated that the propane that exploded may have been supplied by our Westfield propane rail terminal to one of our customers. We are not responsible for odorization of the propane we supply to our customers. Rather, we receive the propane by rail which has been odorized by our suppliers. An attorney representing the estate of the deceased has put us on notice of an intent to bring legal action in this matter. We intend to vigorously defend any such legal action. It is not possible to predict whether we will incur any liability or to estimate the damages, if any, we might incur in connection with this matter. Management does not believe the ultimate resolution of this issue will have a material adverse effect on our consolidated results of operations, financial position or cash flows.

Driver — In August 2007, Driver Pipeline Company, Inc., or Driver, filed a lawsuit against DCP Midstream, LP, an affiliate of the owner of our general partner, in District Court, Jackson County, Texas. The litigation arose from a commercial dispute involving the construction of our Wilbreeze pipeline in 2006. Driver was the primary contractor for construction of the pipeline and the construction process was managed for us by DCP Midstream, LP. In June 2010, we settled this matter with Driver for $0.3 million, which we have recorded to general and administrative expense during the nine months ended September 30, 2010.

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. During the second quarter of 2009 we filed an appeal in the 14th Court of Appeals, Texas. El Paso filed an additional lawsuit in the District Court of Webster Parish, Louisiana, claiming damages for the same claims as the Texas matter, but for periods prior to our ownership of the Minden processing plant. The Louisiana court determined in August 2009 that El Paso’s Louisiana claims were barred by the doctrine of res judicata and dismissed the case with prejudice in Louisiana. In January 2010, we and DCP Midstream, LLC entered into a settlement agreement with El Paso to resolve all claims brought by El Paso regarding this matter in Texas and Louisiana. Under the terms of the settlement agreement, we paid El Paso approximately $2.2 million for our portion of the settlement, which is within the amount of our previously disclosed contingent liability. The cases have been dismissed in both Texas and Louisiana.

Insurance — We renewed our insurance policies in May, June and July 2010 for the 2010-2011 insurance year. We contract with third-party and affiliate insurers for: (1) automobile liability insurance for all owned, non-owned and hired vehicles; (2) general liability insurance; (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 real and personal property and includes business interruption/extra expense. These renewals have not resulted in any material change to the premiums we are contracted to pay in the 2010-2011 insurance year compared with the 2009-2010 insurance year. We are jointly insured with DCP Midstream, LLC for directors and officers insurance covering our directors and officers for acts related to our business activities. 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.

Our insurance on Discovery for the 2010-2011 insurance year covers onshore named windstorm property and business interruption insurance and onshore and offshore non-windstorm property and business interruption insurance. The availability of offshore named windstorm property and business interruption insurance has been significantly reduced over the past two years as a result of higher industry-wide damage claims. Additionally, the named windstorm property and business interruption insurance that is available comes at uneconomic premium levels, higher deductibles and lower coverage limits. Consequently, as with the 2009-2010 insurance year, Discovery elected to not purchase offshore named windstorm property and business interruption insurance coverage for the 2010-2011 insurance year.

 

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

 

Indemnification — DCP Midstream, LLC has agreed to indemnify 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 2009 Form 10-K for additional details.

13. 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 our Northern Louisiana system, our Southern Oklahoma system, our 40% limited liability company interest in Discovery, our 75% interest in our Colorado system, our Wyoming system, our 50.1% interest in our East Texas system, and our Michigan systems.

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

NGL Logistics — The NGL Logistics segment consists of the Seabreeze and Wilbreeze NGL transportation pipelines, the Wattenberg NGL transportation pipeline, and 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.

The following tables set forth our segment information:

Three Months Ended September 30, 2010

 

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

Total operating revenue

   $ 167.9      $ 65.9      $ 6.1      $ —        $ 239.9   
                                        

Gross margin (a)

   $ 32.8      $ 3.0      $ 3.9      $ —        $ 39.7   

Operating and maintenance expense

     (15.0     (3.1     (1.1     —          (19.2

Depreciation and amortization expense

     (17.3     (1.0     (0.8     (0.1     (19.2

General and administrative expense