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DCP Midstream Partners, LP 10-Q 2012

Documents found in this filing:

  1. 10-Q
  2. Ex-12.1
  3. Ex-31.1
  4. Ex-31.2
  5. Ex-32.1
  6. Ex-32.2
  7. Ex-32.2
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, 2012

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

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

As of November 2, 2012, there were outstanding 61,091,793 common units representing limited partner interests.

 

 

 


Table of Contents

DCP MIDSTREAM PARTNERS, LP

FORM 10-Q FOR THE QUARTER ENDED SEPTEMBER 30, 2012

TABLE OF CONTENTS

 

Item

       Page  
  PART I. FINANCIAL INFORMATION   

1.

  Financial Statements (unaudited):   
 

Condensed Consolidated Balance Sheets as of September 30, 2012 and December 31, 2011

     1   
 

Condensed Consolidated Statements of Operations for the Three and Nine Months Ended
September 30, 2012 and 2011

     2   
 

Condensed Consolidated Statements of Comprehensive Income for the Three and Nine Months Ended
September 30, 2012 and 2011

     3   
 

Condensed Consolidated Statements of Cash Flows for the Nine Months Ended
September 30, 2012 and 2011

     4   
 

Condensed Consolidated Statements of Changes in Equity for the Nine Months Ended
September 30, 2012

     5   
 

Condensed Consolidated Statements of Changes in Equity for the Nine Months Ended
September 30, 2011

     6   
 

Notes to the Condensed Consolidated Financial Statements

     7   

2.

  Management’s Discussion and Analysis of Financial Condition and Results of Operations      61   

3.

  Quantitative and Qualitative Disclosures about Market Risk      87   

4.

  Controls and Procedures      92   
  PART II. OTHER INFORMATION   

1.

  Legal Proceedings      92   

1A.

  Risk Factors      92   

6.

  Exhibits      95   
  Signatures      96   
  Exhibit Index      97   
  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:

 

Bbl

  barrel

Bbls/d

  barrels per day

Bcf

  one billion cubic feet

Bcf/d

  one billion cubic feet per day

Btu

  British thermal unit, a measurement of energy

Fractionation

 

the process by which natural gas liquids are separated into

    individual components

Frac spread

 

price differences, measured in energy units, between

    equivalent amounts of natural gas and NGLs

MBbls

  one thousand barrels

MMBbls

  one million barrels

MBbls/d

  one thousand barrels per day

MMBtu

  one million Btus

MMBtu/d

  one million Btus per day

MMcf

  one million cubic feet

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 facts, including statements regarding our future financial position, business strategy, budgets, projected costs and plans and objectives of management for future operations, are forward-looking statements.

These forward-looking statements reflect our intentions, plans, expectations, assumptions and beliefs about future events and are subject to risks, uncertainties and other factors, many of which are outside our control. Important factors that could cause actual results to differ materially from the expectations expressed or implied in the forward-looking statements include known and unknown risks. Known risks and uncertainties include, but are not limited to, the risks set forth in “Item 1A. Risk Factors” in this Quarterly Report on Form 10-Q and in our Annual Report on Form 10-K for the year ended December 31, 2011, as well as the following risks and uncertainties:

 

   

the extent of changes in commodity prices and the demand for our products and services, our ability to effectively limit a portion of the adverse impact of potential changes in 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 contributions from affiliates, acquisitions, or organic growth projects, and the successful integration and future performance of such assets;

 

   

our ability to access the debt and equity markets and the resulting cost of capital, which will depend on general market conditions, our financial and operating results, inflation rates, interest rates 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 in our loan agreements and our debt securities, as well as our ability to maintain our credit ratings;

 

   

the demand for NGL products by the petrochemical, refining or other industries;

 

   

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

 

   

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

 

   

the creditworthiness of 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;

 

   

new, additions to and changes in laws and regulations, particularly with regard to taxes, safety and protection of the environment, including climate change legislation and hydraulic fracturing regulations, or the increased regulation of our industry, and their impact on producers and customers served by our systems;

 

   

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

 

   

the amount of gas we gather, compress, treat, process, transport, sell and store, or the NGLs we produce, fractionate, transport and store, may be reduced if the pipelines and storage and fractionation facilities to which we deliver the natural gas or NGLs are capacity constrained and cannot, or will not, accept the gas or NGLs;

 

   

industry changes, including the impact of consolidations, 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.

In light of these risks, uncertainties and assumptions, the events described in the forward-looking statements might not occur or might occur to a different extent or at a different time than we have described. The forward-looking statements in this report speak as of the filing date of this report. We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

 

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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,
2012
    December 31,
2011
 
     (Millions)  
ASSETS     

Current assets:

    

Cash and cash equivalents

   $ 8.4      $ 7.6   

Accounts receivable:

    

Trade, net of allowance for doubtful accounts of $0.5 million and $0.3 million, respectively

     72.6        108.6   

Affiliates

     67.8        106.2   

Inventories

     71.6        87.9   

Unrealized gains on derivative instruments

     47.3        41.2   

Other

     2.9        2.2   
  

 

 

   

 

 

 

Total current assets

     270.6        353.7   

Property, plant and equipment, net

     1,673.8        1,499.4   

Goodwill

     153.8        153.8   

Intangible assets, net

     139.0        145.3   

Investments in unconsolidated affiliates

     229.0        107.1   

Unrealized gains on derivative instruments

     37.2        6.4   

Other long-term assets

     14.0        11.7   
  

 

 

   

 

 

 

Total assets

   $ 2,517.4      $ 2,277.4   
  

 

 

   

 

 

 
LIABILITIES AND EQUITY     

Current liabilities:

    

Accounts payable:

    

Trade

   $ 170.0      $ 231.7   

Affiliates

     14.1        46.8   

Unrealized losses on derivative instruments

     43.4        59.9   

Other

     68.2        42.1   
  

 

 

   

 

 

 

Total current liabilities

     295.7        380.5   

Long-term debt

     1,038.3        746.8   

Unrealized losses on derivative instruments

     13.6        32.8   

Other long-term liabilities

     28.3        19.0   
  

 

 

   

 

 

 

Total liabilities

     1,375.9        1,179.1   
  

 

 

   

 

 

 

Commitments and contingent liabilities

    

Equity:

    

Predecessor equity

     —          257.4   

Common unitholders (59,179,130 and 44,848,703 units issued and outstanding, respectively)

     1,124.2        654.4   

General partner

     (1.0     (4.7

Accumulated other comprehensive loss

     (15.5     (21.2
  

 

 

   

 

 

 

Total partners’ equity

     1,107.7        885.9   

Noncontrolling interests

     33.8        212.4   
  

 

 

   

 

 

 

Total equity

     1,141.5        1,098.3   
  

 

 

   

 

 

 

Total liabilities and equity

   $ 2,517.4      $ 2,277.4   
  

 

 

   

 

 

 

See accompanying notes to condensed consolidated financial statements.

 

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Table of Contents

DCP MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

 

     Three Months Ended
September 30,
    Nine Months Ended
September 30,
 
     2012     2011     2012     2011  
     (Millions, except per unit amounts)  

Operating revenues:

        

Sales of natural gas, propane, NGLs and condensate

   $ 144.4      $ 227.8      $ 540.3      $ 801.7   

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

     161.4        268.3        549.1        851.0   

Transportation, processing and other

     36.2        33.1        102.5        99.2   

Transportation, processing and other to affiliates

     8.8        9.7        28.2        23.0   

(Losses) gains from commodity derivative activity, net

     (11.1     54.1        17.0        29.0   

(Losses) gains from commodity derivative activity, net — affiliates

     (8.8     0.6        33.1        (0.8
  

 

 

   

 

 

   

 

 

   

 

 

 

Total operating revenues

     330.9        593.6        1,270.2        1,803.1   
  

 

 

   

 

 

   

 

 

   

 

 

 

Operating costs and expenses:

        

Purchases of natural gas, propane and NGLs

     247.9        372.0        761.0        1,150.3   

Purchases of natural gas, propane and NGLs from affiliates

     20.1        77.0        212.4        314.0   

Operating and maintenance expense

     35.7        36.7        91.7        91.3   

Depreciation and amortization expense

     14.8        25.9        49.6        74.9   

General and administrative expense

     3.7        4.7        11.9        13.2   

General and administrative expense — affiliates

     7.4        7.3        22.1        22.0   

Other income

     (0.1     (0.2     (0.4     (0.4
  

 

 

   

 

 

   

 

 

   

 

 

 

Total operating costs and expenses

     329.5        523.4        1,148.3        1,665.3   
  

 

 

   

 

 

   

 

 

   

 

 

 

Operating income

     1.4        70.2        121.9        137.8   

Interest expense

     (8.1     (8.6     (31.8     (25.0

Earnings from unconsolidated affiliates

     8.9        6.9        16.6        17.1   
  

 

 

   

 

 

   

 

 

   

 

 

 

Income before income taxes

     2.2        68.5        106.7        129.9   

Income tax expense

     (0.3     (0.4     (1.0     (0.9
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income

     1.9        68.1        105.7        129.0   

Net (income) loss attributable to noncontrolling interests

     (0.6     0.4        (2.0     (12.8
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income attributable to partners

     1.3        68.5        103.7        116.2   

Net income attributable to predecessor operations

     —          (2.2     (2.6     (14.3

General partner’s interest in net income

     (10.8     (6.8     (29.4     (18.5
  

 

 

   

 

 

   

 

 

   

 

 

 

Net (loss) income allocable to limited partners

   $ (9.5   $ 59.5      $ 71.7      $ 83.4   
  

 

 

   

 

 

   

 

 

   

 

 

 

Net (loss) income per limited partner unit — basic

   $ (0.16   $ 1.35      $ 1.37      $ 1.93   
  

 

 

   

 

 

   

 

 

   

 

 

 

Net (loss) income per limited partner unit — diluted

   $ (0.16   $ 1.35      $ 1.36      $ 1.93   
  

 

 

   

 

 

   

 

 

   

 

 

 

Weighted-average limited partner units outstanding — basic

     58.7        44.1        52.5        43.2   

Weighted-average limited partner units outstanding — diluted

     58.7        44.2        52.6        43.2   

See accompanying notes to condensed consolidated financial statements.

 

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DCP MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

 

     Three Months Ended
September 30,
    Nine Months Ended
September 30,
 
     2012     2011     2012     2011  
     (Millions)  

Net income

   $ 1.9      $ 68.1      $ 105.7      $ 129.0   
  

 

 

   

 

 

   

 

 

   

 

 

 

Other comprehensive income (loss):

        

Reclassification of cash flow hedge losses into earnings

     0.6        5.2        9.9        15.6   

Net unrealized gains (losses) on cash flow hedges

     0.7        (5.5     —          (9.8

Net unrealized losses on cash flow hedges - predecessor

     —          (0.3     (0.6     (0.7
  

 

 

   

 

 

   

 

 

   

 

 

 

Total other comprehensive income (loss)

     1.3        (0.6     9.3        5.1   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total comprehensive income

     3.2        67.5        115.0        134.1   

Total comprehensive (income) loss attributable to noncontrolling interests

     (0.6     0.4        (2.0     (12.8
  

 

 

   

 

 

   

 

 

   

 

 

 

Total comprehensive income attributable to partners

   $ 2.6      $ 67.9      $ 113.0      $ 121.3   
  

 

 

   

 

 

   

 

 

   

 

 

 

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,
 
     2012     2011  
     (Millions)  

OPERATING ACTIVITIES:

    

Net income

   $ 105.7      $ 129.0   

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

    

Depreciation and amortization expense

     49.6        74.9   

Earnings from unconsolidated affiliates

     (16.6     (17.1

Distributions from unconsolidated affiliates

     15.9        19.8   

Net unrealized gains on derivative instruments

     (18.9     (47.3

Other, net

     1.5        3.2   

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

    

Accounts receivable

     83.4        53.2   

Inventories

     16.3        (2.8

Accounts payable

     (95.7     (26.2

Accrued interest

     11.6        2.2   

Other current assets and liabilities

     7.4        (5.3

Other long-term assets and liabilities

     (1.4     (2.6
  

 

 

   

 

 

 

Net cash provided by operating activities

     158.8        181.0   
  

 

 

   

 

 

 

INVESTING ACTIVITIES:

    

Capital expenditures

     (152.5     (98.5

Acquisitions, net of cash acquired

     (375.4     (60.6

Acquisition of unconsolidated affiliate

     (29.8     (114.3

Investments in unconsolidated affiliates

     (86.3     (6.8

Return of investment from unconsolidated affiliate

     1.0        1.6   

Proceeds from sale of assets

     0.2        0.2   
  

 

 

   

 

 

 

Net cash used in investing activities

     (642.8     (278.4
  

 

 

   

 

 

 

FINANCING ACTIVITIES:

    

Proceeds from debt

     1,353.4        832.0   

Payments of debt

     (1,062.0     (754.0

Payment of deferred financing costs

     (3.5     (0.1

Excess purchase price over acquired assets

     (110.2     (35.7

Proceeds from issuance of common units, net of offering costs

     445.2        152.0   

Net change in advances to predecessor from DCP Midstream, LLC

     (11.5     14.6   

Distributions to unitholders and general partner

     (128.7     (97.5

Distributions to noncontrolling interests

     (4.8     (26.8

Contributions from DCP Midstream, LLC

     6.9        9.1   
  

 

 

   

 

 

 

Net cash provided by financing activities

     484.8        93.6   
  

 

 

   

 

 

 

Net change in cash and cash equivalents

     0.8        (3.8

Cash and cash equivalents, beginning of period

     7.6        6.7   
  

 

 

   

 

 

 

Cash and cash equivalents, end of period

   $ 8.4      $ 2.9   
  

 

 

   

 

 

 

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

Balance, January 1, 2012

   $ 257.4      $ 654.4      $ (4.7   $ (21.2   $ 212.4      $ 1,098.3   

Net change in parent advances

     (11.5     —          —          —          —          (11.5

Acquisition of additional 66.67% interest in Southeast Texas and NGL Hedge

     (247.9     39.5        —          —          —          (208.4

Acquisition of additional 49.9% interest in East Texas

     —          —          —          —          (175.8     (175.8

Issuance of units for Southeast Texas

     —          48.0        —          —          —          48.0   

Issuance of units for East Texas

     —          33.0        —          —          —          33.0   

Issuance of units for Mont Belvieu fractionators

     —          60.0        —          —          —          60.0   

Deficit purchase price under carrying value of acquired net assets for Southeast Texas and East Texas

     —          35.8        —          (4.2     —          31.6   

Excess purchase price over carrying value of acquired net assets for Mont Belvieu fractionators

     —          (170.2     —          —          —          (170.2

Issuance of 11,031,691 common units

     —          445.2        —          —          —          445.2   

Equity-based compensation

     —          (0.4     —          —          —          (0.4

Distributions to unitholders and general partner

     —          (103.0     (25.7     —          —          (128.7

Distributions to noncontrolling interests

     —          —          —          —          (4.8     (4.8

Contributions from DCP Midstream, LLC

     —          10.2        —          —          —          10.2   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Comprehensive income:

            

Net income attributable to predecessor operations

     2.6        —          —          —          —          2.6   

Net income

     —          71.7        29.4        —          2.0        103.1   

Reclassification of cash flow hedges into earnings

     —          —          —          9.9        —          9.9   

Net unrealized losses on cash flow hedges

     (0.6     —          —          —          —          (0.6
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total comprehensive income

     2.0        71.7        29.4        9.9        2.0        115.0   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance, September 30, 2012

   $ —        $ 1,124.2      $ (1.0   $ (15.5   $ 33.8      $ 1,141.5   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

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DCP MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(Unaudited)

 

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

Balance, January 1, 2011

   $ 337.8      $ 552.2      $ (6.4   $ (27.7   $ 220.1      $ 1,076.0   

Net change in parent advances

     19.0        —          —          —          —          19.0   

Acquisition of Southeast Texas

     (114.3     —          —          —          —          (114.3

Excess purchase price over acquired assets

     —          (34.8     —          (0.9     —          (35.7

Issuance of 3,941,667 common units

     —          152.2        —          —          —          152.2   

Equity-based compensation

     —          2.9        —          —          —          2.9   

Distributions to DCP Midstream, LLC

     —          (2.6     —          —          —          (2.6

Distributions to unitholders and general partner

     —          (80.5     (17.0     —          —          (97.5

Distributions to noncontrolling interests

     —          —          —          —          (26.8     (26.8

Contributions from DCP Midstream, LLC

     —          —          —          —          9.1        9.1   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Comprehensive income:

            

Net income attributable to predecessor operations

     14.3        —          —          —          —          14.3   

Net income

     —          83.4        18.5        —          12.8        114.7   

Reclassification of cash flow hedges into earnings

     —          —          —          15.6        —          15.6   

Net unrealized losses on cash flow hedges

     (0.7     —          —          (9.8     —          (10.5
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total comprehensive income

     13.6        83.4        18.5        5.8        12.8        134.1   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance, September 30, 2011

   $ 256.1      $ 672.8      $ (4.9   $ (22.8   $ 215.2      $ 1,116.4   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

See accompanying notes to condensed consolidated financial statements.

 

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Table of Contents

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 or the Partnership, is engaged in the business of gathering, compressing, treating, processing, transporting, storing and selling natural gas; and producing, fractionating, transporting, storing 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 natural gas services business (which includes our Northern Louisiana system; our Southern Oklahoma system; our 40% interest in Discovery Producer Services LLC, or Discovery; our Wyoming system; a 75% interest in Collbran Valley Gas Gathering, LLC, or Collbran or our Colorado system; our East Texas system (of which the remaining 49.9% was acquired in January 2012, and the Crossroads system was acquired in July 2012)); our Michigan system; our Southeast Texas system (of which 33.33% and 66.67% were acquired in January 2011 and March 2012, respectively), our NGL logistics business (which includes the Seabreeze and Wilbreeze intrastate NGL pipelines, the Wattenberg and Black Lake interstate NGL pipelines, our 10% interest in the Texas Express NGL pipeline, the NGL storage facility in Michigan, the DJ Basin NGL fractionators and our minority ownership interests in the Mont Belvieu fractionators acquired in July 2012), and our wholesale propane logistics business.

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 Phillips 66. 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 most of our assets. DCP Midstream, LLC owns approximately 26% of us.

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

Our predecessor operations consist of our initial 33.33% interest in Southeast Texas, which we acquired from DCP Midstream, LLC in January 2011, and the remaining 66.67% interest in Southeast Texas and commodity derivative instruments related to the Southeast Texas storage business, which we acquired from DCP Midstream, LLC in March 2012. Prior to our acquisition of the remaining 66.67% interest in Southeast Texas, we accounted for our initial 33.33% interest as an unconsolidated affiliate using the equity method. Subsequent to this transaction, we own 100% of Southeast Texas which we account for as a consolidated subsidiary. These transfers of net assets between entities under common control were accounted for as if the transfer occurred at the beginning of the period, and prior years were retrospectively adjusted to furnish comparative information similar to the pooling method. Accordingly, our consolidated financial statements include the historical results of our 100% interest in Southeast Texas and the natural gas commodity derivatives associated with the storage business for all periods presented. We recognize transfers of net assets between entities under common control at DCP Midstream, LLC’s basis in the net assets contributed. The amount of the purchase price in excess or in deficit of DCP Midstream, LLC’s basis in the net assets is recognized as a reduction or an addition to partners’ equity. The financial statements of our predecessor have been prepared from the separate records maintained by DCP Midstream, LLC and may not necessarily be indicative of the conditions that would have existed or the results of operations if our predecessor had been operated as an unaffiliated entity.

 

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

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

The accompanying unaudited condensed consolidated financial statements in this Quarterly Report on Form 10-Q have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission, or SEC. Accordingly, these condensed consolidated financial statements reflect all adjustments, consisting only of normal recurring adjustments, that are, in the opinion of management, necessary to present fairly the financial position and results of operations for the respective interim periods. Certain information and 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, 2012 are not necessarily indicative of the results that may be expected for the year ending December 31, 2012. 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 in our 2011 Annual Report included as Exhibit 99.3 to our Current Report on Form 8-K filed on June 14, 2012.

 

2. Recent Accounting Pronouncements

Financial Accounting Standards Board, or FASB, Accounting Standards Update, or ASU, 2011-04 “Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs”, or ASU 2011-04 — In May 2011, the FASB issued ASU 2011-04 which amends Accounting Standards Codification, Topic 820 “Fair Value Measurements and Disclosures” to change the wording used to describe many of the requirements in U.S. GAAP for measuring fair value and for disclosing information about fair value measurements, clarify the FASB’s intent about the application of existing fair value measurement requirements, and change a particular principle or requirement for measuring fair value or for disclosing information about fair value measurements. The provisions of ASU 2011-04 became effective for us for interim and annual periods beginning after December 15, 2011. The provisions of ASU 2011-04 impact only disclosures, and we have disclosed information in accordance with the provisions of ASU 2011-04 within this filing.

 

3. Acquisitions

On July 3, 2012, we acquired the Crossroads processing plant and associated gathering system from Penn Virginia Resource Partners, L.P. for $63.0 million. The acquisition was financed at closing with borrowings under our revolving credit facility. The Crossroads system, located in the southeastern portion of Harrison County in East Texas, includes approximately 8 miles of gas gathering pipeline, an 80 MMcf/d cryogenic processing plant, approximately 20 miles of NGL pipeline and a 50% ownership interest in an approximately 11-mile residue gas pipeline, or CrossPoint Pipeline, LLC, which we have accounted for as an unconsolidated affiliate using the equity method.

 

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Table of Contents

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

We have accounted for the Crossroads business combination based on estimates of the fair value of assets acquired and liabilities assumed, including: property, plant and equipment; the equity investment in CrossPoint Pipeline, LLC; a liability for a firm transportation agreement which expires in 2015; and a gas purchase agreement under which a portion of those firm transportation payments are recoverable. Expected cash payments and receipts have been recorded at their estimated fair value and are included in other current liabilities, other long-term liabilities, and accounts receivable in our September 30, 2012 condensed consolidated balance sheet. The purchase price allocation is preliminary and is based on initial estimates of fair values at the date of the acquisition. We are currently evaluating the preliminary purchase price allocation, which will be adjusted as additional information relative to the fair value of assets and liabilities becomes available. This allocation may change in subsequent financial statements pending the final estimates of fair value. The preliminary purchase price allocation as of September 30, 2012 is as follows:

 

     September 30,
2012
 
     (Millions)  

Aggregate consideration

   $ 63.0   
  

 

 

 

Accounts receivable

   $ 4.2   

Property, plant and equipment

     63.1   

Investments in unconsolidated affiliates

     6.1   

Other current liabilities

     (4.1

Other long-term liabilities

     (6.3
  

 

 

 

Total preliminary purchase price allocation

   $ 63.0   
  

 

 

 

The results of operations for acquisitions accounted for as a business combination are included in our results subsequent to the date of acquisition. Accordingly, for the three and nine months ended September 30, 2012 total operating revenues of $8.5 million and net income attributable to the Partnership of $0.8 million associated with Crossroads, are included in the condensed consolidated statement of operations. Pro forma information is presented for comparative periods prior to the date of acquisition; however, comparative periods in the condensed consolidated financial statements are not adjusted to include the results of the acquisition.

The following tables present unaudited pro forma information for the condensed consolidated statement of operations for the nine months ended September 30, 2012 and 2011 and the three months ended September 30, 2011, as if the acquisition of Crossroads had occurred at the beginning of the earliest period presented.

 

     Nine Months Ended September 30, 2012  
     DCP
Midstream
Partners, LP
    Acquisition of
Crossroads  (a)
     DCP
Midstream
Partners, LP
Pro Forma
 
     (Millions)  

Total operating revenues

   $ 1,270.2      $ 27.0       $ 1,297.2   

Net income attributable to partners

   $ 103.7      $ 1.6       $ 105.3   

Less:

       

Net income attributable to predecessor operations

     (2.6     —           (2.6

General partner unitholders interest in net income

     (29.4     —           (29.4
  

 

 

   

 

 

    

 

 

 

Net income allocable to limited partners

   $ 71.7      $ 1.6       $ 73.3   
  

 

 

   

 

 

    

 

 

 

Net income per limited partner unit — basic

   $ 1.37      $ 0.03       $ 1.40   

Net income per limited partner unit — diluted

   $ 1.36      $ 0.03       $ 1.39   

 

(a) The nine months ended September 30, 2012, includes the financial results of Crossroads for the period from January 1, 2012 through July 2, 2012.

 

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Table of Contents

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

     Nine Months Ended September 30, 2011  
     DCP
Midstream
Partners,
LP
    Acquisition
of

Crossroads
     DCP
Midstream
Partners,
LP Pro
Forma
 
     (Millions)  

Total operating revenues

   $ 1,803.1      $ 91.3       $ 1,894.4   

Net income attributable to partners

   $ 116.2      $ 3.4       $ 119.6   

Less:

       

Net income attributable to predecessor operations

     (14.3     —           (14.3

General partner unitholders interest in net income

     (18.5     —           (18.5
  

 

 

   

 

 

    

 

 

 

Net income allocable to limited partners

   $ 83.4      $ 3.4       $ 86.8   
  

 

 

   

 

 

    

 

 

 

Net income per limited partner unit — basic and diluted

   $ 1.93      $ 0.08       $ 2.01   

 

     Three Months Ended September 30, 2011  
     DCP
Midstream
Partners,
LP
    Acquisition
of

Crossroads
     DCP
Midstream
Partners,
LP Pro
Forma
 
     (Millions)  

Total operating revenues

   $ 593.6      $ 28.0       $ 621.6   

Net income attributable to partners

   $ 68.5      $ 0.7       $ 69.2   

Less:

       

Net income attributable to predecessor operations

     (2.2     —           (2.2

General partner unitholders interest in net income

     (6.8     —           (6.8
  

 

 

   

 

 

    

 

 

 

Net income allocable to limited partners

   $ 59.5      $ 0.7       $ 60.2   
  

 

 

   

 

 

    

 

 

 

Net income per limited partner unit — basic and diluted

   $ 1.35      $ 0.02       $ 1.37   

The supplemental pro forma total operating revenues for the nine months ended September 30, 2012 was adjusted to eliminate $5.4 million related to a contractual gas processing arrangement between us and Crossroads during the period.

The pro forma information is not intended to reflect actual results that would have occurred if the acquired business 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.

On July 2, 2012, we acquired the minority ownership interests in two non-operated Mont Belvieu fractionators, or the Mont Belvieu fractionators, from DCP Midstream, LLC for aggregate consideration of $200.0 million. $60.0 million of the aggregate consideration was financed by the issuance at closing of 1,536,098 of our common units to DCP Midstream, LLC. We entered into a 2-year Term Loan Agreement to fund the remaining $140.0 million. The $170.2 million excess purchase price over the historical basis of the net assets acquired was recorded as a decrease in common unitholders’ equity. The minority ownership interests include a 12.5% interest in the Enterprise fractionator, which is operated by Enterprise Products Partners L.P., and a 20% interest in the Mont Belvieu 1 fractionator, which is operated by ONEOK Partners. Accordingly, we have accounted for the results of the minority ownership interests in the Mont Belvieu fractionators prospectively from the date of acquisition. The Mont Belvieu fractionators are accounted for as unconsolidated affiliates using the equity method.

 

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Table of Contents

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

On April 12, 2012, we acquired a 10% ownership interest in the Texas Express Pipeline joint venture from the operator, Enterprise Products Partners, L.P., or Enterprise, representing an approximate investment of $85.0 million in the joint venture. At closing, we paid $10.9 million for our 10% ownership interest in the Texas Express Pipeline joint venture, representing our proportionate share of the investment through the closing date, and will be responsible for spending an approximate $75.0 million for our share of the remaining construction costs of the pipeline. Originating near Skellytown in Carson County, Texas, the 20-inch diameter Texas Express Pipeline will extend approximately 580 miles to Enterprise’s natural gas liquids fractionation and storage complex at Mont Belvieu, Texas, and will provide access to other third party facilities in the area. The Texas Express Pipeline will have an initial capacity of approximately 280 MBbls/d and as of September 30, 2012, has long-term, fee-based, ship-or-pay transportation commitments of 252 MBbls/d, including a commitment from DCP Midstream, LLC of 20 MBbls/d. The pipeline is expected to be completed by the second quarter of 2013.

On March 30, 2012, we acquired the remaining 66.67% interest in Southeast Texas, and commodity derivative instruments related to the Southeast Texas storage business, for consideration of $240.0 million plus $20.7 million in working capital and other customary purchase price adjustments. $192.0 million of the consideration was financed with a portion of the net proceeds from our 4.95% 10-year Senior Notes offering. The remaining $48.0 million consideration was financed by the issuance at closing of an aggregate of 1,000,417 of our common units to DCP Midstream, LLC. DCP Midstream, LLC also provided fixed price NGL commodity derivatives, valued at $39.5 million, for the three year period subsequent to closing the newly acquired interest. The $8.9 million deficit purchase price under the historical basis of the net assets acquired and the $48.0 million of common units issued as consideration for this acquisition were recorded as an increase in common unitholders equity. Prior to the acquisition of the additional interest in Southeast Texas, we owned a 33.33% interest which we accounted for as an unconsolidated affiliate using the equity method. Certain of the NGL commodity derivatives were valued at $24.6 million and represent consideration for the termination of a fee-based storage arrangement we had with DCP Midstream, LLC in conjunction with our initial 33.33% interest in Southeast Texas; the remaining portion of the commodity derivatives, valued at $14.9 million, mitigate a portion of our currently anticipated commodity price risk associated with the gathering and processing portion of the 66.67% interest in Southeast Texas acquired on March 30, 2012. The acquisition of the remaining 66.67% interest in Southeast Texas represents a transaction between entities under common control and a change in reporting entity. Accordingly, our consolidated financial statements have been adjusted to retrospectively include the historical results of our 100% interest in Southeast Texas and the natural gas commodity derivatives associated with the storage business for all periods presented, similar to the pooling method.

 

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Table of Contents

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

Combined Financial Information

The results of our 100% interest in Southeast Texas are included in the condensed consolidated balance sheets as of September 30, 2012 and December 31, 2011. The following table presents the previously reported December 31, 2011 condensed consolidated balance sheet, adjusted for the acquisition of the remaining 66.67% interest in Southeast Texas from DCP Midstream, LLC:

As of December 31, 2011

 

     DCP Midstream
Partners, LP

(As previously
reported) (a)
    Consolidate
Southeast
Texas (b)
    Remove Southeast
Texas Investment
in Unconsolidated
Affiliate (c)
    Combined DCP
Midstream
Partners, LP
(As currently
reported)
 
     (Millions)  
ASSETS         

Current assets:

        

Cash and cash equivalents

   $ 6.7      $ 0.9      $ —        $ 7.6   

Accounts receivable

     161.4        53.4        —          214.8   

Inventories

     64.7        23.2        —          87.9   

Other

     7.1        36.3        —          43.4   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total current assets

     239.9        113.8        —          353.7   

Property, plant and equipment, net

     1,181.8        317.6        —          1,499.4   

Goodwill and intangible assets, net

     255.8        43.3        —          299.1   

Investments in unconsolidated affiliates

     208.7        —          (101.6     107.1   

Other non-current assets

     17.4        0.7        —          18.1   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total assets

   $ 1,903.6      $ 475.4      $ (101.6   $ 2,277.4   
  

 

 

   

 

 

   

 

 

   

 

 

 
LIABILITIES AND EQUITY         

Accounts payable and other current liabilities

   $ 269.2      $ 111.3      $ —        $ 380.5   

Long-term debt

     746.8        —          —          746.8   

Other long-term liabilities

     46.7        5.1        —          51.8   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total liabilities

     1,062.7        116.4        —          1,179.1   
  

 

 

   

 

 

   

 

 

   

 

 

 

Commitments and contingent liabilities

        

Equity:

        

Partners’ equity

        

Net equity

     649.7        360.8        (103.4     907.1   

Accumulated other comprehensive loss

     (21.2     (1.8     1.8        (21.2
  

 

 

   

 

 

   

 

 

   

 

 

 

Total partners’ equity

     628.5        359.0        (101.6     885.9   

Noncontrolling interests

     212.4        —          —          212.4   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total equity

     840.9        359.0        (101.6     1,098.3   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total liabilities and equity

   $ 1,903.6      $ 475.4      $ (101.6   $ 2,277.4   
  

 

 

   

 

 

   

 

 

   

 

 

 

 

(a) Amounts as previously reported with 33.33% of Southeast Texas’ results presented as investments in unconsolidated affiliates.
(b) Adjustments to present Southeast Texas on a consolidated basis at 100% ownership, including commodity derivatives.
(c) Adjustments to remove Southeast Texas 33.33% investment in unconsolidated affiliates.

 

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Table of Contents

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

The results of our 100% interest in Southeast Texas are included in the condensed consolidated statements of operations for the three and nine months ended September 30, 2012 and 2011. The following tables presents the previously reported condensed consolidated statements of operations for the three and nine months ended September 30, 2011, adjusted for the acquisition of the remaining 66.67% interest in Southeast Texas from DCP Midstream, LLC:

Three Months Ended September 30, 2011

 

     DCP Midstream
Partners, LP
(As previously
reported) (a)
    Consolidate
Southeast
Texas (b)
    Remove
Southeast
Texas
Equity
Earnings (c)
    Combined
DCP
Midstream
Partners,
LP (As
currently
reported)
 
     (Millions)  

Operating revenues:

        

Sales of natural gas, propane, NGLs and condensate

   $ 290.4      $ 205.7      $ —        $ 496.1   

Transportation, processing and other

     40.8        2.0        —          42.8   

Gains from commodity derivative activity, net

     52.1        2.6        —          54.7   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total operating revenues

     383.3        210.3        —          593.6   
  

 

 

   

 

 

   

 

 

   

 

 

 

Operating costs and expenses:

        

Purchases of natural gas, propane and NGLs

     257.3        191.7        —          449.0   

Operating and maintenance expense

     31.5        5.2        —          36.7   

Depreciation and amortization expense

     20.6        5.3        —          25.9   

General and administrative expense

     9.4        2.6        —          12.0   

Other income

     (0.2     —          —          (0.2
  

 

 

   

 

 

   

 

 

   

 

 

 

Total operating costs and expenses

     318.6        204.8        —          523.4   
  

 

 

   

 

 

   

 

 

   

 

 

 

Operating income

     64.7        5.5        —          70.2   

Interest expense, net

     (8.6     —          —          (8.6

Earnings from unconsolidated affiliates

     10.0        —          (3.1     6.9   
  

 

 

   

 

 

   

 

 

   

 

 

 

Income before income taxes

     66.1        5.5        (3.1     68.5   

Income tax expense

     (0.2     (0.2     —          (0.4
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income

     65.9        5.3        (3.1     68.1   

Net loss attributable to noncontrolling interests

     0.4        —          —          0.4   
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income attributable to partners

   $ 66.3      $ 5.3      $ (3.1   $ 68.5   
  

 

 

   

 

 

   

 

 

   

 

 

 

 

(a) Amounts as previously reported with 33.33% of Southeast Texas’ results presented as earnings from unconsolidated affiliates.
(b) Adjustments to present Southeast Texas on a consolidated basis at 100% ownership, including commodity derivatives.
(c) Adjustments to remove Southeast Texas equity earnings at 33.33%.

 

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Table of Contents

DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

Nine Months Ended September 30, 2011

 

     DCP
Midstream
Partners,
LP (As
previously
reported) (a)
    Consolidate
Southeast
Texas (b)
    Remove
Southeast
Texas
Equity
Earnings (c)
    Combined
DCP
Midstream
Partners,
LP (As
currently
reported)
 
     (Millions)  

Operating revenues:

        

Sales of natural gas, propane, NGLs and condensate

   $ 1,043.2      $ 609.5      $ —        $ 1,652.7   

Transportation, processing and other

     114.9        7.3        —          122.2   

Gains from commodity derivative activity, net

     24.5        3.7        —          28.2   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total operating revenues

     1,182.6        620.5        —          1,803.1   
  

 

 

   

 

 

   

 

 

   

 

 

 

Operating costs and expenses:

        

Purchases of natural gas, propane and NGLs

     906.6        557.7        —          1,464.3   

Operating and maintenance expense

     77.3        14.0        —          91.3   

Depreciation and amortization expense

     60.6        14.3        —          74.9   

General and administrative expense

     27.0        8.2        —          35.2   

Other income

     (0.4     —          —          (0.4
  

 

 

   

 

 

   

 

 

   

 

 

 

Total operating costs and expenses

     1,071.1        594.2        —          1,665.3   
  

 

 

   

 

 

   

 

 

   

 

 

 

Operating income

     111.5        26.3        —          137.8   

Interest expense, net

     (25.0     —          —          (25.0

Earnings from unconsolidated affiliates

     28.6        —          (11.5     17.1   
  

 

 

   

 

 

   

 

 

   

 

 

 

Income before income taxes

     115.1        26.3        (11.5     129.9   

Income tax expense

     (0.4     (0.5     —          (0.9
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income

     114.7        25.8        (11.5     129.0   

Net income attributable to noncontrolling interests

     (12.8     —          —          (12.8
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income attributable to partners

   $ 101.9      $ 25.8      $ (11.5   $ 116.2   
  

 

 

   

 

 

   

 

 

   

 

 

 

 

(a) Amounts as previously reported with 33.33% of Southeast Texas’ results presented as earnings from unconsolidated affiliates.
(b) Adjustments to present Southeast Texas on a consolidated basis at 100% ownership, including commodity derivatives.
(c) Adjustments to remove Southeast Texas equity earnings at 33.33%.

The currently reported results are not intended to reflect actual results that would have occurred if the acquired business had been combined during the period presented, nor is it intended to be indicative of the results of operations that may be achieved by us in the future.

On January 3, 2012, we acquired the remaining 49.9% interest in East Texas from DCP Midstream, LLC for consideration of $165.0 million, less $2.5 million in working capital and other customary purchase price adjustments, for a net purchase price of $162.5 million. $132.0 million of the consideration was financed with proceeds from our January 3, 2012 Term Loan Agreement. The remaining $33.0 million consideration was financed by the issuance at closing of an aggregate of 727,520 of our common units to DCP Midstream, LLC. The $22.7 million deficit purchase price under the historical basis of the net assets acquired and the $33.0 million of common units issued as consideration for this acquisition were recorded as an increase in common unitholders equity. Prior to the contribution of the additional interest in East Texas, we owned a 50.1% interest which we accounted for as a consolidated subsidiary. The contribution of the remaining 49.9% interest in East Texas represents a transaction between entities under common control, but does not represent a change in reporting entity. Accordingly, we have included the results of the remaining 49.9% interest in East Texas prospectively from the date of contribution.

 

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

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. In January 2012, in conjunction with our acquisition of the remaining 49.9% interest in East Texas, we increased the annual fee we pay to DCP Midstream, LLC by $7.4 million. In March 2012, in conjunction with our acquisition of the remaining 66.67% interest in Southeast Texas, we increased the annual fee we pay to DCP Midstream, LLC by $10.3 million, prorated for the remainder of the calendar year. These fees were previously allocated to East Texas and Southeast Texas. In July 2012, in conjunction with our acquisition of the minority interests in the Mont Belvieu fractionators, we increased the annual fee we pay to DCP Midstream, LLC by $0.2 million. As a result of these transactions, the annual fee we pay to DCP Midstream, LLC will be $28.1 million.

Following is a summary of the fees we incurred under the Omnibus Agreement as well as other fees paid to DCP Midstream, LLC:

 

     Three Months  Ended
September 30,
     Nine Months  Ended
September 30,
 
     2012      2011      2012      2011  
     (Millions)  

Omnibus Agreement

   $ 7.0       $ 2.6       $ 18.4       $ 7.6   

Other fees — DCP Midstream, LLC

     0.3         4.7         3.5         14.2   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total — DCP Midstream, LLC

   $ 7.3       $ 7.3       $ 21.9       $ 21.8   
  

 

 

    

 

 

    

 

 

    

 

 

 

In addition to the Omnibus Agreement, we incurred other general and administrative fees with DCP Midstream, LLC of $0.3 million for each of the three months ended September 30, 2012 and 2011, and $1.0 million for each of the nine months ended September 30, 2012 and 2011. These amounts include allocated expenses, including professional services, insurance and internal audit. For the nine months ended September 30, 2012, Southeast Texas incurred $2.5 million in general and administrative expenses directly from DCP Midstream, LLC, before the addition of Southeast Texas to the Omnibus Agreement in March 2012. For the three and nine months ended September 30, 2011, Southeast Texas incurred $2.5 million and $7.5 million, respectively, in general and administrative expenses directly from DCP Midstream, LLC. For the three and nine months ended September 30, 2011, East Texas incurred $1.9 million and $5.7 million, respectively, in general and administrative expenses directly from DCP Midstream, LLC.

Other Agreements and Transactions with DCP Midstream, LLC

DCP Midstream, LLC was a significant customer during the three and nine months ended September 30, 2012 and 2011.

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 and services to DCP Midstream, LLC in the ordinary course of business. In addition, DCP Midstream, LLC conducts derivative activities on our behalf. We have and may continue to enter into derivative transactions directly with DCP Midstream, LLC, whereby DCP Midstream is the counterparty.

We have a contractual arrangement with DCP Midstream, LLC, through March 2022, 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 the 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)

 

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 an interruptible 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 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 conjunction with our acquisitions of our East Texas and Southeast Texas systems, which are part of our Natural Gas Services segment, we entered into agreements with DCP Midstream, LLC whereby DCP Midstream, LLC will reimburse us for certain expenditures on East Texas and Southeast Texas capital projects. These reimbursements are for specific 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 $1.2 million and $3.5 million for the three months ended September 30, 2012 and 2011, respectively, and $6.4 million and $9.1 million for the nine months ended September 30, 2012 and 2011, respectively. DCP Midstream, LLC made capital contributions to Southeast Texas for capital projects of $2.1 million and $3.7 million for the three and nine months ended September 30, 2012. As of September 30, 2012, $1.2 million and $2.1 million of the contributions to East Texas and Southeast Texas, respectively, are recorded as receivables from affiliates in the condensed consolidated balance sheet.

In our Natural Gas Services segment, we sell NGLs processed at certain of our plants, and sell condensate removed from the gas gathering systems that deliver to certain of our systems under contracts to a subsidiary of DCP Midstream, LLC equal to that subsidiary’s net weighted-average sales price, adjusted for transportation, processing and other charges from the tailgate of the respective asset.

As a result of a downstream outage, certain of our assets were required to curtail NGL production during 2012. DCP Midstream, LLC has reimbursed us for the impact of the curtailment and accordingly, we have recorded $2.5 million to sales of natural gas, propane, NGLs and condensate to affiliates and $0.2 million to transportation, processing and other to affiliates in the condensed consolidated statements of operations for the three and nine months ended September 30, 2012.

In our NGL Logistics segment, we also have a contractual arrangement with a subsidiary of DCP Midstream, LLC which provides that DCP Midstream, LLC will pay us to transport NGLs on 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.

With respect to our Wattenberg pipeline, effective January 1, 2011, we entered into a 10-year dedication and transportation agreement with a subsidiary of DCP Midstream, LLC whereby certain NGL volumes produced at several of DCP Midstream, LLC’s processing facilities are dedicated for transportation on the Wattenberg pipeline. We collect fee-based transportation revenues under our tariff. We generally report revenues associated with these activities in the condensed consolidated statements of operations as transportation, processing and other to affiliates.

We pay a fee to DCP Midstream, LLC to operate our DJ Basin NGL fractionators and receive fees for the processing of DCP Midstream, LLC’s committed NGLs produced by them in Weld County, Colorado at our DJ Basin NGL fractionators under agreements that are effective through March 2018. We incurred fees of $0.2 million and $0.7 million during the three and nine months ended September 30, 2012, respectively, and $0.1 million and $0.3 million during the three and nine months ended September 30, 2011, which are included in operating and maintenance expense in the condensed consolidated statements of operations.

DCP Midstream, LLC has issued parental guarantees, totaling $25.0 million as of September 30, 2012, 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 a fee of 0.5% per annum on these outstanding guarantees.

 

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

Spectra Energy

We had propane supply agreements with Spectra Energy that expired April 2012, which provided us propane supply at our marine terminals, included in our Wholesale Propane Logistics segment, for up to approximately 185 million gallons of propane annually.

ConocoPhillips and Phillips 66

Prior to May 2012, DCP Midstream, LLC and its subsidiaries and affiliates, collectively referred to as DCP Midstream, LLC, was owned 50% by Spectra Energy Corp, or Spectra Energy, and 50% by ConocoPhillips. In May 2012, ConocoPhillips separated its business into two stand-alone publicly traded companies. As a result of this transaction, DCP Midstream, LLC is no longer owned 50% by ConocoPhillips. ConocoPhillips’ 50% ownership interest in DCP Midstream, LLC has been transferred to the new downstream company, Phillips 66.

We have multiple agreements with Phillips 66 and its affiliates, and anticipate continuing to sell to Phillips 66 and its affiliates in the ordinary course of business. Prior to ConocoPhillips’ separation in May 2012, these agreements were with ConocoPhillips. We continue to have agreements with ConocoPhillips, including fee-based and percent-of-proceeds gathering and processing arrangements, and gas purchase and gas sales agreements; however, we do not consider ConocoPhillips to be a related party effective May 1, 2012.

Summary of Transactions with Affiliates

The following table summarizes transactions with affiliates:

 

     Three Months  Ended
September 30,
     Nine Months Ended
September 30,
 
     2012     2011      2012      2011  
     (Millions)  

DCP Midstream, LLC:

          

Sales of natural gas, propane, NGLs and condensate

   $ 161.3      $ 258.0       $ 539.9       $ 809.5   

Transportation, processing and other

   $ 8.8      $ 7.9       $ 25.9       $ 17.4   

Purchases of natural gas, propane and NGLs

   $ 20.1      $ 33.6       $ 95.6       $ 132.2   

(Losses) gains from commodity derivative activity, net

   $ (8.8   $ 0.6       $ 33.1       $ (0.8

General and administrative expense

   $ 7.3      $ 7.3       $ 21.9       $ 21.8   

Spectra Energy:

          

Purchases of natural gas, propane and NGLs

   $ —        $ 41.8       $ 113.1       $ 173.5   

ConocoPhillips (a):

          

Sales of natural gas, propane, NGLs and condensate

   $ —        $ 10.3       $ 9.0       $ 41.5   

Transportation, processing and other

   $ —        $ 1.8       $ 2.3       $ 5.6   

Purchases of natural gas, propane and NGLs

   $ —        $ 1.6       $ 1.3       $ 5.2   

General and administrative expense

   $ —        $ —         $ 0.1       $ 0.2   

Phillips 66 (a):

          

Sales of natural gas, propane, NGLs and condensate

   $ 0.1      $ —         $ 0.2       $ —     

General and administrative expense

   $ 0.1      $ —         $ 0.1       $ —     

Unconsolidated affiliates:

          

Purchases of natural gas, propane and NGLs

   $ —        $ —         $ 2.4       $ 3.1   

 

(a) In connection with the Phillips 66 separation, ConocoPhillips is not considered to be a related party for periods after April 30, 2012 and Phillips 66 is considered a related party for periods starting May 1, 2012.

 

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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,
2012
    December 31,
2011
 
     (Millions)  

DCP Midstream, LLC:

    

Accounts receivable

   $ 67.4      $ 100.0   

Accounts payable

   $ 14.1      $ 22.6   

Unrealized gains on derivative instruments — current

   $ 44.8      $ 0.6   

Unrealized gains on derivative instruments — long-term

   $ 30.9      $ —     

Unrealized losses on derivative instruments — current

   $ (21.5   $ (0.6

Unrealized losses on derivative instruments — long-term

   $ (1.1   $ —     

Spectra Energy:

    

Accounts receivable

   $ 0.3      $ 0.1   

Accounts payable

   $ —        $ 21.4   

ConocoPhillips (a):

    

Accounts receivable

   $ —        $ 6.1   

Accounts payable

   $ —        $ 0.4   

Unrealized gains on derivative instruments — current

   $ —        $ 2.5   

Unrealized losses on derivative instruments — current

   $ —        $ (2.0

Phillips 66 (a):

    

Accounts receivable

   $ 0.1      $ —     

Unconsolidated affiliates:

    

Accounts payable

   $ —        $ 2.4   

 

(a) In connection with the Phillips 66 separation, ConocoPhillips is not considered to be a related party for periods after April 30, 2012 and Phillips 66 is considered a related party for periods starting May 1, 2012.

 

5. Inventories

Inventories were as follows:

 

     September 30,
2012
     December 31,
2011
 
     (Millions)  

Natural gas

   $ 15.7       $ 25.6   

NGLs

     55.9         62.3   
  

 

 

    

 

 

 

Total inventories

   $ 71.6       $ 87.9   
  

 

 

    

 

 

 

We recognize lower of cost or market adjustments when the carrying value of our inventories exceeds their estimated market value. These non-cash charges are a component of purchases of natural gas, propane and NGLs in the condensed consolidated statements of operations. We recognized $0.2 million and $19.3 million in lower of cost or market adjustments during the three and nine months ended September 30, 2012, respectively. We recognized $1.9 million and $2.5 million in lower of cost or market adjustments during the three and nine months ended September 30, 2011, respectively.

 

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

6. Property, Plant and Equipment

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

 

     Depreciable      September 30,     December 31,  
     Life      2012     2011  
            (Millions)  

Gathering and transmission systems

     20 — 50 Years       $ 1,307.5      $ 1,211.9   

Processing, storage, and terminal facilities

     35 — 60 Years         820.1        742.8   

Other

     3 — 30 Years         24.4        23.1   

Construction work in progress

        261.7        218.3   
     

 

 

   

 

 

 

Property, plant and equipment

        2,413.7        2,196.1   

Accumulated depreciation

        (739.9     (696.7
     

 

 

   

 

 

 

Property, plant and equipment, net

      $ 1,673.8      $ 1,499.4   
     

 

 

   

 

 

 

Interest capitalized on construction projects for the three months ended September 30, 2012 and 2011 was $1.9 million and $0.2 million, respectively, and for the nine months ended September 30, 2012 and 2011 was $4.9 million and $0.7 million, respectively.

We revised the depreciable lives for our gathering and transmission systems, processing, storage and terminal facilities, and other assets effective April 1, 2012. The key contributing factors to the change in depreciable lives is an increase in the estimated remaining economically recoverable reserves resulting from the development of techniques that improve commodity production in the regions our assets serve. Advances in extraction processes, along with better technology used to locate commodity reserves, is giving producers greater access to unconventional commodities. Based on our property, plant and equipment as of April 1, 2012, the new remaining depreciable lives resulted in an approximate $11.9 million and $23.8 million reduction in depreciation expense for the three and nine months ended September 30, 2012, respectively, and will result in an estimated reduction in depreciation expense of $36.0 million for the year ended December 31, 2012. This change in our estimated depreciable lives increased net income per limited partner unit by $0.20 and $0.45 for the three and nine months ended September 30, 2012, respectively.

In connection with our evaluation of useful lives, we corrected the classification for certain assets within the presentation of our major classes of property, plant and equipment as of December 31, 2011.

Depreciation expense was $12.7 million and $23.8 million for the three months ended September 30, 2012 and 2011, respectively, and $43.3 million and $68.6 million for the nine months ended September 30, 2012 and 2011, respectively.

Asset Retirement Obligations — As of September 30, 2012, we had asset retirement obligations of $16.6 million included in other long-term liabilities in the condensed consolidated balance sheets. As of December 31, 2011, we had asset retirement obligations of $12.4 million included in other long-term liabilities in the condensed consolidated balance sheets. During the first quarter of 2012, we recorded a change in estimate to increase our asset retirement obligations by approximately $4.3 million. The change in estimate was primarily attributable to a reassessment of anticipated timing of settlements and of the original asset retirement obligation estimated amounts. For the three months ended September 30, 2012, accretion expense was $0.3 million, and for the nine months ended September 30, 2012, accretion benefit was $0.1 million. For the three and nine months ended September 30, 2011, accretion expense was $0.2 million and $0.5 million, respectively.

 

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

7. Goodwill and Intangible Assets

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

 

     Nine Months  Ended
September 30, 2012
     Year Ended
December 31, 2011
 
     (Millions)  

Beginning of period

   $ 153.8       $ 151.2   

Acquisitions

     —           2.6   
  

 

 

    

 

 

 

End of period

   $ 153.8       $ 153.8   
  

 

 

    

 

 

 

The carrying value of goodwill as of September 30, 2012 and December 31, 2011 was $82.2 million for each of the periods for our Natural Gas Services segment, $34.7 million for each of the periods for our NGL logistics segment, and $36.9 million for each of the periods for our Wholesale Propane Logistics segment.

We performed our annual goodwill assessment during the quarter at the reporting unit level, which is identified by assessing whether the components of our operating segments constitute businesses for which discrete financial information is available, whether segment management regularly reviews the operating results of those components and whether the economic and regulatory characteristics are similar. As a result of our assessment, we concluded that the entire amount of goodwill disclosed on the condensed consolidated balance sheet is recoverable. We primarily used a discounted cash flow analysis to perform the assessment. Key assumptions in the analysis include the use of an appropriate discount rate, estimated future cash flows and an estimate of operating and general and administrative costs. In estimating cash flows, we incorporate current market information, as well as historical and other factors, into our forecasted commodity prices. 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 were as follows:

 

     September 30,
2012
    December 31,
2011
 
     (Millions)  

Gross carrying amount

   $ 164.3      $ 164.3   

Accumulated amortization

     (25.3     (19.0
  

 

 

   

 

 

 

Intangible assets, net

   $ 139.0      $ 145.3   
  

 

 

   

 

 

 

We recorded amortization expense of $2.1 million for each of the three months ended September 30, 2012 and 2011, and $6.3 million for each of the nine months ended September 30, 2012 and 2011, respectively. As of September 30, 2012, the remaining amortization periods ranged from approximately 10 years to 23 years, with a weighted-average remaining period of approximately 18 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)  

Remainder of 2012

   $ 2.1   

2013

     8.4   

2014

     8.4   

2015

     8.4   

2016

     8.4   

Thereafter

     103.3   
  

 

 

 

Total

   $ 139.0   
  

 

 

 

 

8. Investments in Unconsolidated Affiliates

The following table summarizes our investments in unconsolidated affiliates:

 

           Carrying Value as of  
     Percentage
Ownership
    September 30,
2012
     December 31,
2011
 
           (Millions)  

Discovery Producer Services LLC

     40   $ 159.5       $ 106.9   

Texas Express Pipeline

     10     33.0         —     

Mont Belvieu Enterprise Fractionator

     12.5     16.0         —     

Mont Belvieu 1 Fractionator

     20     14.0         —     

CrossPoint Pipeline, LLC

     50     6.3         —     

Other

     50     0.2         0.2   
    

 

 

    

 

 

 

Total investments in unconsolidated affiliates

     $ 229.0       $ 107.1   
    

 

 

    

 

 

 

There was a deficit between the carrying amount of the investment and the underlying equity of Discovery of $30.8 million and $32.6 million at September 30, 2012 and December 31, 2011, 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 Mont Belvieu 1 of $5.7 million at September 30, 2012, which is associated with, and is being accreted over, the life of the underlying long-lived assets of Mont Belvieu 1.

Earnings from investments in unconsolidated affiliates were as follows:

 

     Three Months  Ended
September 30,
     Nine Months  Ended
September 30,
 
     2012      2011      2012      2011  
     (Millions)  

Discovery Producer Services LLC

   $ 3.8       $ 6.9       $ 11.5       $ 17.1   

Mont Belvieu Enterprise Fractionator

     2.7         —           2.7         —     

Mont Belvieu 1 Fractionator

     2.3         —           2.3         —     

CrossPoint Pipeline, LLC

     0.1         —           0.1         —     
  

 

 

    

 

 

    

 

 

    

 

 

 

Total earnings from unconsolidated affiliates

   $ 8.9       $ 6.9       $ 16.6       $ 17.1   
  

 

 

    

 

 

    

 

 

    

 

 

 

 

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DCP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

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

 

     Three Months  Ended
September 30,
     Nine Months  Ended
September 30,
 
     2012      2011      2012      2011  
     (Millions)  

Statements of operations:

           

Operating revenue

   $ 90.8       $ 55.2       $ 173.9       $ 158.7   

Operating expenses

   $ 48.6       $ 39.5       $ 115.0       $ 120.5   

Net income

   $ 42.2       $ 15.7       $ 58.4       $ 38.2   

 

     September 30,
2012
    December 31,
2011
 
     (Millions)  

Balance sheets:

    

Current assets

   $ 90.9      $ 38.1   

Long-term assets

     1,043.7        359.9   

Current liabilities

     (148.3     (20.4

Long-term liabilities

     (42.5     (28.5
  

 

 

   

 

 

 

Net assets

   $ 943.8      $ 349.1   
  

 

 

   

 

 

 

 

9. Fair Value Measurement

Determination of Fair Value

Below is a general description of our valuation methodologies for derivative financial assets and liabilities which are measured at fair value. Fair values are generally based upon quoted market prices or prices obtained through external sources, where available. If listed market prices or quotes are not available, we determine fair value based upon a market quote, adjusted by other market-based or independently sourced market data such as historical commodity volatilities, crude oil future yield curves, and/or counterparty specific considerations. These adjustments result in a fair value for each asset or liability under an “exit price” methodology, in line with how we believe a marketplace participant would value that asset or liability. Fair values are adjusted to reflect the credit risk inherent in the transaction as well as the potential impact of liquidating open positions in an orderly manner over a reasonable time period under current conditions. These adjustments may include amounts to reflect counterparty credit quality, the effect of our own creditworthiness, the time value of money and/or the liquidity of the market.

 

   

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

 

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contracts are valued at market value without making any additional valuation adjustments and, therefore, no liquidity reserve is applied. For contracts other than exchange traded instruments, we mark our positions to the midpoint of the bid/ask spread, and record a liquidity reserve based upon our total net position. We believe that such practice results in the most reliable fair value measurement as viewed by a market participant.

We manage our derivative instruments on a portfolio basis and the valuation adjustments described above are calculated on this basis. We believe that the portfolio level approach represents the highest and best use for these assets as there are benefits inherent in naturally offsetting positions within the portfolio at any given time, and this approach is consistent with how a market participant would view and value the assets and liabilities. Although we take a portfolio approach to managing these assets/liabilities, in order to reflect the fair value of any one individual contract within the portfolio, we allocate all valuation adjustments down to the contract level, to the extent deemed necessary, based upon either the notional contract volume, or the contract value, whichever is more applicable.

The methods described above may produce a fair value calculation that may not be indicative of net realizable value or reflective of future fair values. While we believe that our valuation methods are appropriate and consistent with other market participants, we recognize that the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different estimate of fair value at the reporting date. We review our fair value policies on a regular basis taking into consideration changes in the marketplace and, if necessary, will adjust our policies accordingly. See Note 11 Risk Management and Hedging Activities.

Valuation Hierarchy

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

 

   

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

 

   

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

 

   

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

A financial instrument’s categorization within the hierarchy is based upon the 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

 

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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 existing floating rate debt for fixed-rate debt. Our 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.

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

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.

 

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The following table presents the financial instruments carried at fair value as of September 30, 2012 and December 31, 2011, by consolidated balance sheet caption and by valuation hierarchy as described above:

 

     September 30, 2012     December 31, 2011  
     Level 1      Level 2     Level 3     Total
Carrying

Value
    Level 1      Level 2     Level 3     Total
Carrying

Value
 
     (Millions)  

Current assets:

                  

Commodity derivatives (a)

   $ —         $ 26.1      $ 21.2      $ 47.3      $ —         $ 40.1      $ 1.1      $ 41.2   

Long-term assets:

                  

Commodity derivatives (b)

   $ —         $ 7.9      $ 29.3      $ 37.2      $ —         $ 5.4      $ 1.0      $ 6.4   

Current liabilities (c):

                  

Commodity derivatives

   $ —         $ (39.1   $ (0.2   $ (39.3   $ —         $ (43.1   $ (0.7   $ (43.8

Interest rate derivatives

   $ —         $ (4.1   $ —        $ (4.1   $ —         $ (16.1   $ —        $ (16.1

Long-term liabilities (d):

                  

Commodity derivatives

   $ —         $ (10.5   $ (0.2   $ (10.7   $ —         $ (27.5   $ (0.3   $ (27.8

Interest rate derivatives

   $ —         $ (2.9   $ —        $ (2.9   $ —         $ (5.0   $ —        $ (5.0

 

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

Changes in Levels 1 and 2 Fair Value Measurements

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. 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. The determination to classify a financial instrument within Level 1 or Level 2 is based upon the availability of quoted prices for identical or similar assets and liabilities in active markets. Depending upon the information readily observable in the market, and/or the use of identical or similar quoted prices, which are significant to the overall valuation, the classification of any individual financial instrument may differ from one measurement date to the next. To qualify as a transfer, the asset or liability must have existed in the previous reporting period and moved into a different level during the current period. In the event that there is a movement between the classification of an instrument as Level 1 or 2, the transfer between Level 1 and Level 2 would be reflected in a table as Transfers in/out of Level 1/Level 2. During the nine months ended September 30, 2012, there were no transfers between Level 1 and Level 2 of the fair value hierarchy.

 

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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. The significant unobservable inputs used in determining fair value include adjustments by other market-based or independently sourced market data such as historical commodity volatilities, crude oil future yield curves, and/or counterparty specific considerations. In the event that there is a movement to/from the classification of an instrument as Level 3, we have reflected such items in the table below within the “Transfers in/out of Level 3” caption.

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

 

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

Three months ended September 30, 2012 (a):

  

Beginning balance

   $ 43.6      $ 35.5      $ (0.4   $ (0.3

Net realized and unrealized (losses) gains included in earnings (d)

     (2.2     (6.2     0.1        0.1   

Transfers into Level 3 (c)

     —          —          —          —     

Transfers out of Level 3 (c)

     (13.3     —          —          —     

Settlements

     (6.9     —          0.1        —     
  

 

 

   

 

 

   

 

 

   

 

 

 

Ending balance

   $ 21.2      $ 29.3      $ (0.2   $ (0.2
  

 

 

   

 

 

   

 

 

   

 

 

 

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

   $ 2.6      $ (6.2   $ (0.1   $ 0.1   
  

 

 

   

 

 

   

 

 

   

 

 

 

Three months ended September 30, 2011 (b):

        

Beginning balance

   $ 0.6      $ 0.3      $ (1.2   $ (0.3

Net realized and unrealized gains (losses) included in earnings (d)

     1.2        2.4        (2.1     0.3   

Transfers into Level 3 (c)

     —          —          —          —     

Transfers out of Level 3 (c)

     —          (2.5     —          —     

Settlements

     (0.4     —          2.6        —     
  

 

 

   

 

 

   

 

 

   

 

 

 

Ending balance

   $ 1.4      $ 0.2      $ (0.7   $ —     
  

 

 

   

 

 

   

 

 

   

 

 

 

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

   $ 1.0      $ —        $ (0.3   $ 0.3   
  

 

 

   

 

 

   

 

 

   

 

 

 

 

(a) There were no purchases, issuances and sales of derivatives for the three months ended September 30, 2012.
(b) There were no purchases, issuances and sales of derivatives for the three months ended September 30, 2011.
(c) Amounts transferred in and amounts transferred out are reflected at fair value as of the end of the period.
(d) Represents the amount of total gains or losses for the period, included in gains or losses from commodity derivative activity, net, attributable to changes in unrealized gains or losses relating to assets and liabilities classified as Level 3.

 

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

Nine months ended September 30, 2012 (a):

  

Beginning balance

   $ 1.1      $ 1.0      $ (0.7   $ (0.3

Net realized and unrealized gains included in earnings (d)

     9.2        1.6        0.8        0.1   

Transfers into Level 3 (c)

     —          —          —          —     

Transfers out of Level 3 (c)

     —          —          —          —     

Settlements

     (1.9     —          0.4        —     

Purchases

     12.8        26.7        (0.7     —     
  

 

 

   

 

 

   

 

 

   

 

 

 

Ending balance

   $ 21.2      $ 29.3      $ (0.2   $ (0.2
  

 

 

   

 

 

   

 

 

   

 

 

 

Net unrealized gains still held included in earnings (d)

   $ 8.2      $ 1.6      $ 0.5      $ 0.1   
  

 

 

   

 

 

   

 

 

   

 

 

 

Nine months ended September 30, 2011 (b):

        

Beginning balance

   $ 0.3      $ 0.3      $ (0.1   $ (0.5

Net realized and unrealized gains (losses) included in earnings (d)

     1.4        1.0        (0.7     0.5   

Transfers into Level 3 (c)

     —          —          —          —     

Transfers out of Level 3 (c)

     —          (1.1     —          —     

Settlements

     (0.3     —          0.1        —     
  

 

 

   

 

 

   

 

 

   

 

 

 

Ending balance

   $ 1.4      $ 0.2      $ (0.7   $ —     
  

 

 

   

 

 

   

 

 

   

 

 

 

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

   $ 1.4      $ (0.1   $ (0.7   $ 0.3   
  

 

 

   

 

 

   

 

 

   

 

 

 

 

(a) There were no issuances and sales of derivatives for the nine months ended September 30, 2012.
(b) There were no purchases, issuances and sales of derivatives for the nine months ended September 30, 2011.
(c) Amounts transferred in and amounts transferred out are reflected at fair value as of the end of the period.
(d) Represents the amount of total gains or losses for the period, included in gains or losses from commodity derivative activity, net, attributable to changes in unrealized gains or losses relating to assets and liabilities classified as Level 3.

Quantitative Information and Fair Value Sensitivities Related to Level 3 Unobservable Inputs

We utilize the market approach to measure the fair value of our commodity contracts. The significant unobservable inputs used in this approach to fair value are longer dated price quotes. Our sensitivity to these longer dated forward curve prices are presented in the table below. Significant changes in any of those inputs in isolation would result in significantly different fair value measurements, depending on our short or long position in contracts.

 

Product Group

   Fair Value     Forward
Curve Range

Assets

   (Millions)      

NGLs

   $ 49.1      $ 0.34-$2.02       Per gallon

Natural Gas

   $ 1.4      $ 3.74-$4.39       Per MMBtu

Liabilities

          

NGLs

   $ —        $ —         Per gallon

Natural Gas

   $ (0.4   $ 3.90-$4.39       Per MMBtu

 

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Estimated Fair Value of Financial Instruments

Valuation of a contract’s fair value is validated by an internal group independent of the marketing group. While common industry practices are used to develop valuation techniques, changes in pricing methodologies or the underlying assumptions could result in significantly different fair values and income recognition. When available, quoted market prices or prices obtained through external sources are used to determine a contract’s fair value. For contracts with a delivery location or duration for which quoted market prices are not available, fair value is determined based on pricing models developed primarily from historical and expected relationship with quoted market prices.

Values are adjusted to reflect the credit risk inherent in the transaction as well as the potential impact of liquidating open positions in an orderly manner over a reasonable time period under current conditions. Changes in market prices and management estimates directly affect the estimated fair value of these contracts. Accordingly, it is reasonably possible that such estimates may change in the near term.

The fair value of our interest rate swaps and commodity non-trading derivatives is based on prices supported by quoted market prices and other external sources and prices based on models and other valuation methods. The “prices supported by quoted market prices and other external sources” category includes our interest rate swaps, our NGL and crude oil swaps, and our NYMEX positions in natural gas. In addition, this category includes our forward positions in natural gas for which our forward price curves are obtained from a third party pricing service and then validated through an internal process which includes the use of independent broker quotes. This category also includes our forward positions in NGLs at points for which over-the-counter, or OTC, broker quotes for similar assets or liabilities are available for the full term of the instrument. This category also includes “strip” transactions whose pricing inputs are directly or indirectly observable from external sources and then modeled to daily or monthly prices as appropriate. The “prices based on models and other valuation methods” category includes the value of transactions for which inputs to the fair value of the instrument are unobservable in the marketplace and are considered significant to the overall fair value of the instrument. The fair value of these instruments may be based upon an internally developed price curve, which was constructed as a result of the long dated nature of the transaction or the illiquidity of the market point.

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

The fair value of accounts receivable 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. Each of the carrying and fair values of outstanding balances under our Credit Agreement are $300.0 million as of September 30, 2012, and $497.0 million as of December 31, 2011. The carrying and fair values of the 4.95% Senior Notes are $350.0 million and $371.6 million, respectively, as of September 30, 2012. The carrying and fair values of the 3.25% Senior Notes are $250.0 million and $257.9 million, respectively, as of September 30, 2012. The carrying value of the 3.25% Senior Notes as of December 31, 2011 was $250.0 million, which approximated fair value. Each of the carrying and fair values of the term loan facility are $140.0 million as of September 30, 2012. 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. We determine the fair value of our fixed-rate debt based on quotes obtained from bond dealers. We classify the fair values of our outstanding debt balances within Level 2 of the valuation hierarchy.

 

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10. Debt

Long-term debt was as follows:

 

     September 30,
2012
    December 31,
2011
 
     (Millions)  

Credit Agreement

    

Revolving credit facility, weighted-average variable interest rate of 1.48% and 1.69%, respectively, due November 10, 2016 (a)

   $ 300.0      $ 497.0   

Term Loan Agreement

    

Term loan facility, variable interest rate of 1.62%, due July 2, 2014

     140.0        —     

Debt Securities

    

Issued March 13, 2012, interest at 4.95% payable semi-annually, due April 1, 2022

     350.0        —     

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

     250.0        250.0   

Unamortized discount

     (1.7     (0.2
  

 

 

   

 

 

 

Total long-term debt

   $ 1,038.3      $ 746.8   
  

 

 

   

 

 

 

 

(a) $150.0 million has been swapped to a fixed rate obligation with effective fixed rates ranging from 2.94% to 2.99%, for a net effective rate of 2.84% on the $300.0 million of outstanding debt under our revolving credit facility as of September 30, 2012. $450.0 million of debt was swapped to a fixed-rate obligation with effective fixed-rates ranging from 2.94% to 5.19%, for a net effective rate of 4.86% on the $497.0 million of outstanding debt under our revolving credit facility as of December 31, 2011.

Credit Agreement

We have a $1.0 billion revolving credit facility that matures November 10, 2016, or the Credit Agreement.

At September 30, 2012 and December 31, 2011, we had $1.0 million of letters of credit issued and outstanding under the Credit Agreement. As of September 30, 2012, the unused capacity under the revolving credit facility was $699.0 million, of which approximately $685.3 million was available for general working capital purposes.

Our borrowing capacity is limited at September 30, 2012 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 November 10, 2016 maturity date.

Under the Credit Agreement, indebtedness under the revolving credit facility bears interest at either: (1) LIBOR, plus an applicable margin of 1.25% based on our current credit rating; or (2) (a) the base rate which shall be the higher of Wells Fargo Bank N.A.’s prime rate, the Federal Funds rate plus 0.50% or the LIBOR Market Index rate plus 1%, plus (b) an applicable margin of 0.25% based on our current credit rating. The revolving credit facility incurs an annual facility fee of 0.25% based on our current credit rating. This fee is paid on drawn and undrawn portions of the revolving credit facility.

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 following the consummation of qualifying acquisitions, not more than 5.5 to 1.0, on a temporary basis for three consecutive quarters, including the quarter in which such acquisition is consummated.

 

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Debt Securities

On March 13, 2012, we issued $350.0 million of 4.95% 10-year Senior Notes due April 1, 2022. We received proceeds of $345.8 million, net of underwriters’ fees, related expenses and unamortized discounts of $4.2 million, which we used to fund the cash portion of the acquisition of the remaining 66.67% interest in Southeast Texas and to repay funds borrowed under our Term Loan and Credit Facility. Interest on the notes will be paid semi-annually on April 1 and October 1 of each year, commencing October 1, 2012. The notes will mature on April 1, 2022, unless redeemed prior to maturity. The underwriters’ fees and related expenses are deferred in other long-term assets in our condensed consolidated balance sheets and will be amortized over the term of the notes.

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

Term Loan Agreements

On July 2, 2012, we entered into a 2-year Term Loan Agreement and borrowed $140.0 million (the “$140 million Term Loan”) to fund the cash portion of the acquisition of the Mont Belvieu fractionators. The $140 million Term Loan will mature on July 2, 2014. Effective November 1, 2012, the proceeds of any subsequent indebtedness issued with a maturity date after July 2, 2014 must first be used to prepay the $140 million Term Loan. Indebtedness under the $140 million Term Loan bears interest at either: (1) LIBOR, plus an applicable margin of 1.375% based on our current credit rating; or (2) (a) the higher of SunTrust Bank’s prime rate, the Federal Funds rate plus 0.50% or the LIBOR Market Index rate plus 1%, plus (b) an applicable margin of 0.25% based on our current credit rating. The $140 million Term Loan 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 $140 million Term Loan Agreement) consistent with our Credit Agreement. On January 2, 2013 and July 2, 2013, one-time payments of 0.125% and 0.20%, respectively, on the outstanding principal amount of the $140 million Term Loan are required.

On January 3, 2012, we entered into a 2-year Term Loan Agreement and borrowed $135.0 million which was used to fund the cash portion of the acquisition of the remaining 49.9% interest in East Texas. In March 2012, we repaid the term loan with proceeds from our 4.95% 10-year Senior Notes.

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

 

     Debt
Maturities
 
     (Millions)  

2012

   $ —     

2013

     —     

2014

     140.0   

2015

     250.0   

Thereafter

     650.0   
  

 

 

 
     1,040.0   

Unamortized discount

     (1.7
  

 

 

 

Total

   $ 1,038.3   
  

 

 

 

 

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11. Risk Management and Hedging Activities

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

Commodity Price Risk

Cash Flow Protection Activities — We are exposed to the impact of market fluctuations in the prices of natural gas, NGLs and condensate as a result of our gathering, processing, sales and storage activities. For gathering, processing and storage services, we may receive cash or commodities as payment for these services, depending on the contract type. We enter into derivative financial instruments to mitigate a portion of the risk of weakening natural gas, NGL and condensate prices associated with our gathering, processing and sales activities, thereby stabilizing our cash flows. We have mitigated a portion of our expected commodity price risk associated with our gathering, processing and sales activities through 2016 with commodity derivative instruments. Our commodity derivative instruments used for our hedging program are a combination of direct NGL product, crude oil, and natural gas hedges. Due to the limited liquidity and tenor of the NGL derivative market, we have used crude oil swaps and costless collars to mitigate a portion of our commodity price exposure to NGLs. Historically, prices of NGLs have generally been related to crude oil prices, however there are periods of time when NGL pricing may be at a greater discount to crude oil, resulting in additional exposure to NGL commodity prices. During 2012, the relationship of NGLs to crude oil has been lower than historical relationships, however a significant amount of our NGL hedges in 2012 and 2013 are direct product hedges. When our crude oil swaps become short-term in nature, we have periodically converted certain crude oil derivatives to NGL derivatives by entering into offsetting crude oil swaps while adding NGL swaps. Our crude oil and NGL transactions are primarily accomplished through the use of forward contracts that effectively exchange our floating price risk for a fixed price. We also utilize crude oil costless collars that minimize our floating price risk by establishing a fixed price floor and a fixed price ceiling. However, the type of instrument that we use to mitigate a portion of our risk may vary depending upon our risk management objective. These transactions are not designated as hedging instruments for accounting purposes and the change in fair value is reflected within our consolidated statements of operations as a gain or a loss on commodity derivative activity.

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, including fixed price sales. While the majority of our sales and purchases in this segment are index-based, occasionally, we may enter into fixed price sales agreements in the event that a 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 use financial derivatives to manage the value of our propane inventories. These transactions are not designated as hedging instruments for accounting purposes and any change in fair value is reflected in the current period within our condensed consolidated statements of operations as a gain or loss on commodity derivative activity.

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

Natural Gas Storage and Pipeline Asset Based Commodity Derivative Program — Our natural gas storage and pipeline assets are exposed to certain risks including changes in commodity prices. We manage commodity price risk related to our natural gas storage and pipeline assets through our commodity derivative program. The commercial activities related to our natural gas storage and pipeline assets primarily consist of the purchase and sale of gas and associated time spreads and basis spreads.

 

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A time spread transaction is executed by establishing a long gas position at one point in time and establishing an equal short gas position at a different point in time. Time spread transactions allow us to lock in a margin supported by the injection, withdrawal, and storage capacity of our natural gas storage assets. We may execute basis spread transactions to mitigate the risk of sale and purchase price differentials across our system. A basis spread transaction allows us to lock in a margin on our physical purchases and sales of gas, including injections and withdrawals from storage. We typically use swaps to execute these transactions, which are not designated as hedging instruments and are recorded at fair value with changes in fair value recorded in the current period condensed consolidated statements of operations. While gas held in our storage locations is recorded at the lower of average cost or market, the derivative instruments that are used to manage our storage facilities are recorded at fair value and any changes in fair value are currently recorded in our condensed consolidated statements of operations. Even though we may have economically hedged our exposure and locked in a future margin, the use of lower-of-cost-or-market accounting for our physical inventory and the use of mark-to-market accounting for our derivative instruments may subject our earnings to market volatility.

Commodity Cash Flow Hedges — On March 30, 2012, we acquired the remaining 66.67% interest in Southeast Texas, and commodity derivative instruments related to the Southeast Texas storage business.

During 2011, Southeast Texas commenced an expansion project to build an additional storage cavern. Upon completion of the expansion project, Southeast Texas will be required to purchase a significant amount of base gas to bring the storage cavern to operation. To mitigate risk associated with the forecasted purchase of natural gas in June, July and August 2013, Southeast Texas executed a series of derivative financial instruments, which have been designated as cash flow hedges. These cash flow hedges were in a loss position of $2.8 million as of September 30, 2012 and will fluctuate in value through the term of construction. Any effective changes in fair value of these derivative instruments will be deferred in AOCI until the underlying purchase of inventory occurs. While the cash paid or received upon settlement of these hedges will economically offset the cash required to purchase the base gas, following completion of the additional storage cavern, any deferred gain or loss at the time of the purchase will remain in AOCI until the cavern is emptied and the base gas is sold.

In order for storage facilities to remain operational, a minimum level of base gas must be maintained in each storage cavern, which is capitalized on our condensed consolidated balance sheets as a component of property, plant and equipment, net. To mitigate the risk associated with the forecasted re-purchase of base gas, in 2008 we executed a series of derivative financial instruments, which were designated as cash flow hedges. The cash paid upon settlement of these hedges economically offsets the cash paid to purchase the base gas. As a result, a deferred loss of $2.7 million was recognized and will remain in AOCI until such time that our cavern is emptied and the base gas is sold.

Interest Rate Risk

We mitigate a portion of our interest rate risk with interest rate swaps that reduce our exposure to market rate fluctuations by converting variable interest rates on our existing debt to fixed interest rates. The interest rate swap agreements convert the interest rate associated with the indebtedness outstanding under our revolving credit facility to a fixed-rate obligation, thereby reducing the exposure to market rate fluctuations.

At December 31, 2011, we had interest rate swap agreements totaling $450.0 million, of which we had designated $425.0 million as cash flow hedges and accounted for the remaining $25.0 million under the mark-to-market method of accounting. In March 2012, we paid down a portion of the revolving credit facility and, as a result, we discontinued cash flow hedge accounting on $225.0 million of our interest rate swap agreements. $300.0 million of swap agreements settled in Q2 2012.

At September 30, 2012, we had interest rate swap agreements extending through June 2014 totaling $150.0 million, which are designated as cash flow hedges. Based on our current operations we believe our interest rate swap agreements mitigate our interest rate risk associated with our variable-rate debt.

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

Effectiveness of our interest rate swap agreements designated as cash flow hedges 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 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.

At September 30, 2012, $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 2.94% to 2.99%, and receive interest payments based on the one-month LIBOR.

On March 8, 2012, we settled $195.0 million of our forward-starting interest rate swap agreements for $6.6 million. The remaining net deferred losses of $4.8 million in AOCI will be amortized into interest expense associated with our long-term debt offering through 2022.

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 we or DCP Midstream, LLC were to be downgraded below investment grade by at least one of the major credit rating agencies, certain of our ISDA counterparties 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, 2012, we are not a party to any agreements that would be subject to these provisions other than our credit agreement.

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

Depending upon the movement of commodity prices 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, 2012, we had $27.4 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, 2012, if a credit-risk related event were to occur we may be required to post additional collateral. Although our commodity derivative contracts that contain credit-risk related contingent features were in a net liability position as of September 30, 2012, 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 $24.2 million.

 

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(Unaudited)

 

As of September 30, 2012, we had $150.0 million of individual interest rate swap instruments that were in a net liability position of $7.0 million and were 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 have the right to request that we net settle the instrument in the form of cash.

Unconsolidated Affiliates

Discovery Producer Services LLC, one of our unconsolidated affiliates, entered into agreements with a pipe vendor denominated in a foreign currency in connection with the expansion of the natural gas gathering pipeline system in the deepwater Gulf of Mexico, the Keathley Canyon Connector. Discovery entered into certain foreign currency derivative contracts to mitigate a portion of the foreign currency exchange risks which were designated as cash flow hedges. As these hedges are owned by Discovery, an unconsolidated affiliate, we include the impact to AOCI on our consolidated balance sheet.

Collateral

DCP Midstream, LLC had issued and outstanding parental guarantees totaling $25.0 million in favor of certain counterparties to our commodity derivative instruments. These parental guarantees reduce the amount of cash we may be required to post as collateral. As of September 30, 2012, 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,
2012
    December 31,
2011
 
     (Millions)  

Commodity cash flow hedges:

    

Net deferred losses in AOCI

   $ (5.4   $ (1.8

Interest rate cash flow hedges:

    

Net deferred losses in AOCI

     (10.1     (19.4
  

 

 

   

 

 

 

Total AOCI

   $ (15.5   $ (21.2
  

 

 

   

 

 

 

 

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The fair value of our derivative instruments that are designated as hedging instruments and 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,
2012
    December 31,
2011
     Balance Sheet Line Item   September 30,
2012
    December 31,
2011
 
    (Millions)          (Millions)  

Derivative Assets Designated as Hedging Instruments:

  

   Derivative Liabilities Designated as Hedging Instruments:   

Commodity derivatives:

       Commodity derivatives:    

Unrealized gains on derivative instruments — current

  $ —        $ —        

Unrealized losses on derivative instruments — current

  $ (2.8   $ —     

Unrealized gains on derivative instruments — long-term

    —          —        

Unrealized losses on derivative instruments — long-term

    —          (2.6
 

 

 

   

 

 

      

 

 

   

 

 

 
  $ —        $ —           $ (2.8   $ (2.6
 

 

 

   

 

 

      

 

 

   

 

 

 

Interest rate derivatives:

       Interest rate derivatives:    

Unrealized gains on derivative instruments — current

  $ —        $ —        

Unrealized losses on derivative instruments — current

  $ (4.1   $ (15.7

Unrealized gains on derivative instruments — long-term

    —          —        

Unrealized losses on derivative instruments — long-term

    (2.9     (5.0
 

 

 

   

 

 

      

 

 

   

 

 

 
  $ —        $ —           $ (7.0   $ (20.7
 

 

 

   

 

 

      

 

 

   

 

 

 

Derivative Assets Not Designated as Hedging Instruments:

  

   Derivative Liabilities Not Designated as Hedging Instruments:   

Commodity derivatives:

       Commodity derivatives:    

Unrealized gains on derivative instruments — current

  $ 47.3      $ 41.2      

Unrealized losses on derivative instruments — current

  $ (36.5   $ (43.8

Unrealized gains on derivative instruments — long-term

    37.2        6.4      

Unrealized losses on derivative instruments — long-term

    (10.7     (25.2
 

 

 

   

 

 

      

 

 

   

 

 

 
  $ 84.5      $ 47.6         $ (47.2   $ (69.0
 

 

 

   

 

 

      

 

 

   

 

 

 

Interest rate derivatives:

       Interest rate derivatives:    

Unrealized gains on derivative instruments — current

  $ —        $ —        

Unrealized losses on derivative instruments — current

  $ —        $ (0.4

Unrealized gains on derivative instruments — long-term

    —          —        

Unrealized losses on derivative instruments — long-term

    —          —     
 

 

 

   

 

 

      

 

 

   

 

 

 
  $ —