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(Mark One) | ||
þ | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |
For the fiscal year ended: December 31, 2008 | ||
or | ||
o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |
For the transition period from to |
Delaware (State or other jurisdiction of incorporation or organization) | 03-0567133 (I.R.S. Employer Identification No.) | |
370 17th Street, Suite 2775 Denver, Colorado (Address of principal executive offices) | 80202 (Zip Code) |
Title of Each Class: | Name of Each Exchange on Which Registered: | |
Common Units Representing Limited Partner Interests | New York Stock Exchange |
Large accelerated filer o | Accelerated filer þ | Non-accelerated filer o | Smaller reporting company o |
FORM 10-K FOR THE YEAR ENDED DECEMBER 31, 2008
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Bbl | barrel | |
Bbls/d | barrels per day | |
BBtu/d | one billion Btus per day | |
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 | |
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 | |
MMscf | one million standard cubic feet | |
NGLs | natural gas liquids | |
Tcf | one trillion cubic feet | |
Throughput | the volume of product transported or passing through a pipeline or other facility |
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• | the extent of changes in commodity prices, our ability to effectively limit a portion of the adverse impact of potential changes in prices through derivative financial instruments, and the potential impact of price on natural gas drilling, demand for our services, and the volume of NGLs and condensate extracted; | |
• | general economic, market and business conditions; | |
• | the level and success of natural gas drilling around our assets, and our ability to connect supplies to our gathering and processing systems in light of competition; | |
• | our ability to grow through acquisitions, contributions from affiliates, or organic growth projects, and the successful integration and future performance of such assets; | |
• | our ability to access the debt and equity markets, which will depend on general market conditions, interest rates and our ability to effectively limit a portion of the adverse effects of potential changes in interest rates by entering into derivative financial instruments, and the credit ratings for our debt obligations; | |
• | our ability to purchase propane from our principal suppliers for our wholesale propane logistics business; | |
• | our ability to construct facilities in a timely fashion, which is partially dependent on obtaining required building, environmental and other permits issued by federal, state and municipal governments, or agencies thereof, the availability of specialized contractors and laborers, and the price of and demand for supplies; | |
• | the creditworthiness of counterparties to our transactions; | |
• | weather and other natural phenomena, including their potential impact on demand for the commodities we sell and our third-party-owned infrastructure; | |
• | changes in laws and regulations, particularly with regard to taxes, safety and protection of the environment or the increased regulation of our industry; | |
• | industry changes, including the impact of consolidations, increased delivery of liquefied natural gas to the United States, alternative energy sources, technological advances and changes in competition; and | |
• | the amount of collateral we may be required to post from time to time in our transactions. |
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Item 1. | Business |
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• | Our Northern Louisiana system, which is an integrated pipeline system located in northern Louisiana and southern Arkansas that gathers, compresses, treats, processes, transports and sells natural gas, and that transports and sells NGLs and condensate. This system consists of the following: |
• | the Minden processing plant and gathering system, which includes a115 MMcf/d cryogenic natural gas processing plant supplied by approximately 725 miles of natural gas gathering pipelines, connected to approximately 460 receipt points, with throughput and processing capacity of approximately115 MMcf/d; | |
• | the Ada processing plant and gathering system, which includes a45 MMcf/d refrigeration natural gas processing plant supplied by approximately 130 miles of natural gas gathering pipelines, connected to approximately 210 receipt points, with throughput capacity of approximately80 MMcf/d; and |
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• | the Pelico Pipeline, LLC system, or Pelico system, an approximately600-mile intrastate natural gas gathering and transportation pipeline with throughput capacity of approximately250 MMcf/d and connections to the Minden and Ada processing plants and approximately 450 other receipt points. The Pelico system delivers natural gas to multiple interstate and intrastate pipelines, as well as directly to industrial and utility end-use markets. |
• | Our Southern Oklahoma, or Lindsay, gathering system, which was acquired in May 2007, consists of approximately 225 miles of pipeline, with throughput capacity of approximately35 MMcf/d. | |
• | Our equity interests that were acquired in July 2007 from DCP Midstream, LLC, consist of the following: |
• | our 40% interest in Discovery Producer Services LLC, or Discovery, which operates a600 MMcf/d cryogenic natural gas processing plant, a natural gas liquids fractionator plant, an approximately280-mile natural gas pipeline with approximate throughput capacity of600 MMcf/d that transports gas from the Gulf of Mexico to its processing plant, and several onshore laterals expanding its presence in the Gulf; and | |
• | our 25% interest in DCP East Texas Holdings, LLC, or East Texas, which operates a780 MMcf/d natural gas processing complex, a natural gas liquids fractionator and an approximately900-mile gathering system with approximate throughput capacity of780 MMcf/d, as well as third party gathering systems, and delivers residue gas to interstate and intrastate pipelines. |
• | Our Colorado and Wyoming gathering, processing and compression assets were acquired in August 2007 from DCP Midstream, LLC, and consist of the following: |
• | our 70% operating interest in the approximately30-mile Collbran Valley Gas Gathering system, or Collbran system, has assets in the Piceance Basin that gather and process natural gas from over 20,000 dedicated acres in western Colorado, and a processing facility with a capacity of120 MMcf/d; and | |
• | The Powder River Basin assets, which include the approximately 1,320-mile Douglas gas gathering system, or Douglas system, with throughput capacity of approximately60 MMcf/d and covers more than 4,000 square miles in northeastern Wyoming, and Millis terminal, and associated NGL pipelines in southwestern Wyoming. |
• | Our Michigan gathering and treating assets were acquired in October 2008 from Michigan Pipeline & Processing, LLC, or MPP. These assets consist of five natural gas treating plants and an approximately155-mile gas gathering pipeline system with throughput capacity of330 MMcf/d; an approximately55-mile residue gas pipeline; a 75% interest in Jackson Pipeline Company, a partnership owning an approximately25-mile residue pipeline, or Jackson Pipeline; and a 44% interest in the Litchfield pipeline, a30-mile pipeline whereby we lease our undivided interest to ANR Pipeline Company through the use of a direct financing lease expiring in 2031. |
• | six owned rail terminals located in the Midwest and northeastern United States, one of which was idled in 2007 to consolidate our operations, with aggregate storage capacity of 25 MBbls; | |
• | one leased marine terminal located in Providence, Rhode Island, with storage capacity of 410 MBbls; | |
• | one pipeline terminal located in Midland, Pennsylvania with storage capacity of 56 MBbls; and | |
• | access to several open access pipeline terminals. |
• | our Seabreeze pipeline, an approximately68-mile intrastate NGL pipeline located in Texas with throughput capacity of 33 MBbls/d; |
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• | our Wilbreeze pipeline, the construction of which was completed in December 2006, an approximately39-mile intrastate NGL pipeline located in Texas, which connects a DCP Midstream, LLC gas processing plant to the Seabreeze pipeline, with throughput capacity of 11 MBbls/d; and | |
• | our 45% interest in the Black Lake Pipe Line Company, or Black Lake, the owner of an approximately317-mile interstate NGL pipeline in Louisiana and Texas with throughput capacity of 40 MBbls/d. |
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Approximate | ||||||||||||||||||||||||||||
Gas Gathering | Approximate | 2008 Operating Data | ||||||||||||||||||||||||||
and | Partnership | Plants | Fractionator | Net Plant | Natural Gas | NGL | ||||||||||||||||||||||
Transmission | Operated | Operated | Operated by | Capacity | Throughput | Production | ||||||||||||||||||||||
System | System (Miles) | Plants | by Others | Others | (MMcf/d) | (MMcf/d)(a) | (Bbls/d)(a) | |||||||||||||||||||||
Minden | 725 | 1 | — | — | 115 | 83 | 4,619 | |||||||||||||||||||||
Ada | 130 | 1 | — | — | 45 | 62 | 165 | |||||||||||||||||||||
Pelico | 600 | — | — | — | — | 171 | — | |||||||||||||||||||||
Southern Oklahoma (Lindsay) | 225 | — | — | — | — | 18 | 2,203 | |||||||||||||||||||||
Collbran | 30 | 1 | — | — | 120 | 90 | 486 | |||||||||||||||||||||
Douglas | 1,320 | — | — | — | — | 16 | 1,025 | |||||||||||||||||||||
Michigan | 265 | — | — | — | — | 75 | — | |||||||||||||||||||||
Discovery | 280 | — | 1 | 1 | 240 | (b) | 170 | (b) | 4,703 | (b) | ||||||||||||||||||
East Texas | 900 | — | 1 | 1 | 195 | (b) | 153 | (b) | 7,458 | (b) | ||||||||||||||||||
Total | 4,475 | 3 | 2 | 2 | 715 | 838 | 20,659 | |||||||||||||||||||||
(a) | Represents total volumes for 2008 divided by 366 days. | |
(b) | For Discovery and East Texas, includes our 40% and 25% proportionate share, respectively, of the approximate net plant capacity, natural gas throughput and NGL production. |
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• | certification and construction of new facilities; | |
• | extension or abandonment of services and facilities; | |
• | maintenance of accounts and records; | |
• | acquisition and disposition of facilities; | |
• | initiation and discontinuation of services; | |
• | terms and conditions of services and service contracts with customers; | |
• | depreciation and amortization policies; | |
• | conduct and relationship with certain affiliates; and | |
• | various other matters. |
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• | requiring the acquisition of permits to conduct regulated activities; | |
• | restricting the way we can handle or dispose of our wastes; | |
• | limiting or prohibiting construction activities in sensitive areas such as wetlands, coastal regions or areas inhabited by endangered species; | |
• | requiring remedial action to mitigate pollution conditions caused by our operations or attributable to former operations; and | |
• | enjoining the operations of facilities deemed in non-compliance with permits issued pursuant to such environmental laws and regulations. |
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Item 1A. | Risk Factors |
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• | the fees we charge and the margins we realize for our services; | |
• | the prices of, level of production of, and demand for, natural gas, propane, condensate and NGLs; | |
• | the success of our commodity derivative and interest rate hedging programs in mitigating fluctuations in commodity prices and interest rates; | |
• | the volume of natural gas we gather, treat, compress, process, transport and sell, the volume of propane and NGLs we transport and sell, and the volumes of propane we store; | |
• | the relationship between natural gas, NGL and crude oil prices; | |
• | the level of competition from other energy companies; | |
• | the impact of weather conditions on the demand for natural gas and propane; | |
• | the level of our operating and maintenance and general and administrative costs; and | |
• | prevailing economic conditions. |
• | the level of capital expenditures we make; | |
• | the cost and form of payment for acquisitions; | |
• | our debt service requirements and other liabilities; | |
• | fluctuations in our working capital needs; | |
• | our ability to borrow funds and access capital markets at reasonable rates; | |
• | restrictions contained in our debt agreements; | |
• | the amount of cash distributions we receive from our equity interests; and | |
• | the amount of cash reserves established by our general partner. |
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• | We have limited ability to influence decisions with respect to the operations of these entities and their subsidiaries, including decisions with respect to incurrence of expenses and distributions to us; | |
• | These entities may establish reserves for working capital, capital projects, environmental matters and legal proceedings which would otherwise reduce cash available for distribution to us; | |
• | These entities may incur additional indebtedness, and principal and interest made on such indebtedness may reduce cash otherwise available for distribution to us; and | |
• | These entities may require us to make additional capital contributions to fund working capital and capital expenditures, our funding of which could reduce the amount of cash otherwise available for distribution. |
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• | the impact of weather, including abnormally mild winter or summer weather that cause lower energy usage for heating or cooling purposes, respectively, or extreme weather that may disrupt our operations or related downstream operations; | |
• | the level of domestic and offshore production; | |
• | a general downturn in economic conditions, including demand for NGLs; | |
• | the availability of imported natural gas, NGLs and crude oil and the demand in the U.S. and globally for these commodities; | |
• | actions taken by foreign oil and gas producing nations; | |
• | the availability of local, intrastate and interstate transportation systems; | |
• | the availability and marketing of competitive fuels; | |
• | the extent of governmental regulation and taxation. |
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• | identify businesses engaged in managing, operating or owning pipelines, processing and storage assets or other midstream assets for acquisitions, joint ventures and construction projects; | |
• | consummate accretive acquisitions or joint ventures and complete construction projects; | |
• | appropriately identify liabilities associated with acquired businesses or assets; | |
• | integrate acquired or constructed businesses or assets successfully with our existing operations and into our operating and financial systems and controls; | |
• | hire, train and retain qualified personnel to manage and operate our growing business; and | |
• | obtain required financing for our existing and new operations. |
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• | perform ongoing assessments of pipeline integrity; | |
• | identify and characterize applicable threats to pipeline segments that could impact a high consequence area; | |
• | improve data collection, integration and analysis; | |
• | repair and remediate the pipeline as necessary; and | |
• | implement preventive and mitigating actions. |
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• | mistaken assumptions about volumes, future contract terms with customers, revenues and costs, including synergies; | |
• | an inability to successfully integrate the businesses we acquire; | |
• | the assumption of unknown liabilities; |
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• | limitations on rights to indemnity from the seller; | |
• | mistaken assumptions about the overall costs of equity or debt; | |
• | the diversion of management’s and employees’ attention from other business concerns; | |
• | change in competitive landscape; | |
• | unforeseen difficulties operating in new product areas or new geographic areas; and | |
• | customer or key employee losses at the acquired businesses. |
• | damage to pipelines, plants and terminals, related equipment and surrounding properties caused by hurricanes, tornadoes, floods, fires and other natural disasters and acts of terrorism; | |
• | inadvertent damage from construction, farm and utility equipment; | |
• | leaks of natural gas, propane, NGLs and other hydrocarbons or losses of natural gas, propane or NGLs as a result of the malfunction of equipment or facilities; | |
• | contaminants in the pipeline system; | |
• | fires and explosions; and | |
• | other hazards that could also result in personal injury and loss of life, pollution and suspension of operations. |
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• | our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms; | |
• | an increased amount of cash flow will be required to make interest payments on our debt; | |
• | our debt level will make us more vulnerable to competitive pressures or a downturn in our business or the economy generally; and | |
• | our debt level may limit our flexibility in responding to changing business and economic conditions. |
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• | neither our partnership agreement nor any other agreement requires DCP Midstream, LLC to pursue a business strategy that favors us. DCP Midstream, LLC’s directors and officers have a fiduciary duty to |
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make these decisions in the best interests of the owners of DCP Midstream, LLC, which may be contrary to our interests; |
• | our general partner is allowed to take into account the interests of parties other than us, such as DCP Midstream, LLC and its affiliates, in resolving conflicts of interest; | |
• | DCP Midstream, LLC and its affiliates, including Spectra Energy and ConocoPhillips, are not limited in their ability to compete with us. Please read “DCP Midstream, LLC and its affiliates are not limited in their ability to compete with us” below; | |
• | once certain requirements are met, our general partner may make a determination to receive a quantity of our Class B units in exchange for resetting the target distribution levels related to its incentive distribution rights without the approval of the special committee of our general partner or our unitholders; | |
• | some officers of DCP Midstream, LLC who provide services to us also will devote significant time to the business of DCP Midstream, LLC, and will be compensated by DCP Midstream, LLC for the services rendered to it; | |
• | our general partner has limited its liability and reduced its fiduciary duties, and has also restricted the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty; | |
• | our general partner determines the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership securities and reserves, each of which can affect the amount of cash that is distributed to unitholders; | |
• | our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders; | |
• | our general partner determines which costs incurred by it and its affiliates are reimbursable by us; | |
• | our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf; | |
• | our general partner intends to limit its liability regarding our contractual and other obligations and, in some circumstances, is entitled to be indemnified by us; | |
• | our general partner may exercise its limited right to call and purchase common units if it and its affiliates own more than 80% of the common units; | |
• | our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates; and | |
• | our general partner decides whether to retain separate counsel, accountants or others to perform services for us. |
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• | the exercise of its right to reset the target distribution levels of its incentive distribution rights at higher levels and receive, in connection with this reset, a number of Class B units that are convertible at any time following the first anniversary of the issuance of these Class B units into common units; | |
• | its limited call right; | |
• | its voting rights with respect to the units it owns; | |
• | its registration rights; and | |
• | its determination whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement. |
• | provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith, meaning it believed the decision was in the best interests of our partnership; |
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• | generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the special committee of the board of directors of our general partner and not involving a vote of unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or must be “fair and reasonable” to us, as determined by our general partner in good faith and that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us; and provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the general partner or those other persons acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal. |
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• | your proportionate ownership interest in us will decrease; | |
• | the amount of cash available for distribution on each unit may decrease; | |
• | the ratio of taxable income to distributions may increase; | |
• | the relative voting strength of each previously outstanding unit may be diminished; and | |
• | the market price of the common units may decline. |
• | a court or government agency determined that we were conducting business in a state but had not complied with that particular state’s partnership statute; or |
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• | the right of holders of limited partner interests to act with other unitholders to remove or replace the general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business. |
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Item 1B. | Unresolved Staff Comments |
Item 2. | Properties |
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Item 3. | Legal Proceedings |
Item 4. | Submission of Matters to a Vote of Unitholders |
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Item 5. | Market for Registrant’s Common Equity, and Related Unitholder Matters and Issuer Purchases of Units |
Distribution Per | Distribution Per | |||||||||||||||
Common | Subordinated | |||||||||||||||
Quarter Ended | High | Low | Unit | Unit | ||||||||||||
December 31, 2008 | $ | 16.94 | $ | 5.75 | $ | 0.600 | $ | 0.600 | ||||||||
September 30, 2008 | $ | 30.21 | $ | 16.92 | $ | 0.600 | $ | 0.600 | ||||||||
June 30, 2008 | $ | 31.51 | $ | 28.98 | $ | 0.600 | $ | 0.600 | ||||||||
March 31, 2008 | $ | 43.51 | $ | 27.37 | $ | 0.590 | $ | 0.590 | ||||||||
December 31, 2007 | $ | 45.95 | $ | 37.68 | $ | 0.570 | $ | 0.570 | ||||||||
September 30, 2007 | $ | 50.50 | $ | 41.75 | $ | 0.550 | $ | 0.550 | ||||||||
June 30, 2007 | $ | 47.00 | $ | 38.15 | $ | 0.530 | $ | 0.530 | ||||||||
March 31, 2007 | $ | 40.06 | $ | 33.99 | $ | 0.465 | $ | 0.465 |
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• | less the amount of cash reserves established by our general partner to: |
• | provide for the proper conduct of our business; | |
• | comply with applicable law, any of our debt instruments or other agreements; or | |
• | provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters; |
• | plus, if our general partner so determines, all or a portion of cash and cash equivalents on hand on the date of determination of Available Cash for the quarter. |
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Item 6. | Selected Financial Data |
Year Ended December 31, | ||||||||||||||||||||
2008(a) | 2007(a) | 2006 | 2005 | 2004 | ||||||||||||||||
(Millions, except per unit data) | ||||||||||||||||||||
Statements of Operations Data: | ||||||||||||||||||||
Total operating revenues(b) | $ | 1,285.8 | $ | 873.3 | $ | 795.8 | $ | 1,144.3 | $ | 834.0 | ||||||||||
Operating costs and expenses: | ||||||||||||||||||||
Purchases of natural gas, propane and NGLs | 1,061.2 | 826.7 | 700.4 | 1,047.3 | 760.6 | |||||||||||||||
Operating and maintenance expense | 43.0 | 32.1 | 23.7 | 22.4 | 19.8 | |||||||||||||||
Depreciation and amortization expense | 36.5 | 24.4 | 12.8 | 12.7 | 14.7 | |||||||||||||||
General and administrative expense | 24.0 | 24.1 | 21.0 | 14.2 | 8.7 | |||||||||||||||
Other | (1.5 | ) | — | — | — | — | ||||||||||||||
Total operating costs and expenses | 1,163.2 | 907.3 | 757.9 | 1,096.6 | 803.8 | |||||||||||||||
Operating income (loss) | 122.6 | (34.0 | ) | 37.9 | 47.7 | 30.2 | ||||||||||||||
Interest income | 5.6 | 5.3 | 6.3 | 0.5 | — | |||||||||||||||
Interest expense | (32.8 | ) | (25.8 | ) | (11.5 | ) | (0.8 | ) | — | |||||||||||
Earnings from equity method investments(c) | 34.3 | 39.3 | 29.2 | 25.7 | 17.6 | |||||||||||||||
Impairment of equity method investment(d) | — | — | — | — | (4.4 | ) | ||||||||||||||
Non-controlling interest in income | (3.9 | ) | (0.5 | ) | — | — | — | |||||||||||||
Income tax expense(e) | (0.1 | ) | (0.1 | ) | — | (3.3 | ) | (2.5 | ) | |||||||||||
Net income (loss) | $ | 125.7 | $ | (15.8 | ) | $ | 61.9 | $ | 69.8 | $ | 40.9 | |||||||||
Less: | ||||||||||||||||||||
Net income attributable to predecessor operations(f) | — | (3.6 | ) | (26.6 | ) | (65.1 | ) | (40.9 | ) | |||||||||||
General partner interest in net income | (11.9 | ) | (2.2 | ) | (0.7 | ) | (0.1 | ) | — | |||||||||||
Net income (loss) allocable to limited partners | $ | 113.8 | $ | (21.6 | ) | $ | 34.6 | $ | 4.6 | $ | — | |||||||||
Net income (loss) per limited partner unit-basic and diluted | $ | 3.25 | $ | (1.05 | ) | $ | 1.90 | $ | 0.20 | $ | — | |||||||||
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Year Ended December 31, | ||||||||||||||||||||
2008(a) | 2007(a) | 2006 | 2005 | 2004 | ||||||||||||||||
(Millions, except per unit data) | ||||||||||||||||||||
Balance Sheet Data (at period end): | ||||||||||||||||||||
Property, plant and equipment, net | $ | 629.3 | $ | 500.7 | $ | 194.7 | $ | 178.7 | $ | 179.3 | ||||||||||
Total assets | $ | 1,180.0 | $ | 1,120.7 | $ | 665.9 | $ | 680.1 | $ | 472.5 | ||||||||||
Accounts payable | $ | 78.4 | $ | 165.8 | $ | 117.3 | $ | 138.3 | $ | 63.5 | ||||||||||
Long-term debt | $ | 656.5 | $ | 630.0 | $ | 268.0 | $ | 210.1 | $ | — | ||||||||||
Partners’ equity | $ | 329.1 | $ | 168.4 | $ | 267.7 | $ | 320.7 | $ | 400.5 | ||||||||||
Other Information: | ||||||||||||||||||||
Cash distributions declared per unit | $ | 2.390 | $ | 2.115 | $ | 1.565 | $ | 0.095 | N/A | |||||||||||
Cash distributions paid per unit | $ | 2.360 | $ | 1.975 | $ | 1.230 | N/A | N/A |
(a) | Includes the effect of the acquisition of the Southern Oklahoma system in May 2007, certain subsidiaries of Momentum Energy Group, Inc. in August 2007 and Michigan Pipeline & Processing, LLC in October 2008. | |
(b) | Includes the effect of the acquisition of the Swap entered into by DCP Midstream, LLC in March 2007. The Swap was for a total of approximately 1.9 million barrels at $66.72 per barrel. | |
(c) | Includes the effect of the acquisition of a 25% limited liability company interest in East Texas and a 40% limited liability company interest in Discovery for all periods presented, as well our proportionate share of the earnings of Black Lake, East Texas and Discovery. Earnings for Discovery and Black Lake include the amortization of the net difference between the carrying amount of the investments and the underlying equity of the investments. | |
(d) | In 2004, we recorded our proportionate share of an impairment charge on Black Lake totaling $4.4 million. | |
(e) | Income tax expense for 2004 through 2005 is applicable to the results of operations of our wholesale propane logistics business. We incurred no income tax expense in 2006, due to the change in tax status of our wholesale propane logistics business in December 2005. Income tax expense in 2008 and 2007 represents a margin-based franchise tax in Texas, or the Texas margin tax and a Michigan business tax. See Note 15 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data.” | |
(f) | Includes the net income attributable to DCP Midstream Partners Predecessor through December 7, 2005, the net income (loss) attributable to our wholesale propane logistics business prior to the date of our acquisition from DCP Midstream, LLC in November 2006, and the net income attributable to the acquisition of a 25% limited liability company interest in East Texas, a 40% limited liability company interest in Discovery, and the Swap prior to the date of our acquisition from DCP Midstream, LLC in July 2007. |
Item 7. | Management’s Discussion and Analysis of Financial Condition and Results of Operations |
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• | our Natural Gas Services segment, which consists of (1) our Northern Louisiana natural gas gathering, processing and transportation system; (2) our Southern Oklahoma system acquired in May 2007; (3) our limited liability company interest in East Texas, our limited liability company interest in Discovery, and the Swap, acquired in July 2007 from DCP Midstream, LLC; (4) our Colorado and Wyoming systems, acquired in August 2007 from DCP Midstream, LLC, which were acquired by DCP Midstream, LLC from Momentum Energy Group, Inc., or MEG, in August 2007 (referred to as the MEG acquisition); and (5) our Michigan systems, acquired in October 2008 from Michigan Pipeline & Processing, LLC (referred to as the MPP acquisition); | |
• | our Wholesale Propane Logistics segment, which consists of six owned rail terminals, one of which was idled in 2007 to consolidate our operations, one leased marine terminal, one pipeline terminal which became operational in May 2007, and access to several open access pipeline terminals; and | |
• | our NGL Logistics segment, which consists of our Seabreeze and Wilbreeze NGL transportation pipelines, and a non-operated equity interest in the Black Lake interstate NGL pipeline. |
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• | Fee-based arrangements —Under fee-based arrangements, we receive a fee or fees for one or more of the following services: gathering, compressing, treating, processing or transporting natural gas; and transporting NGLs. Our fee-based arrangements include natural gas purchase arrangements pursuant to which we purchase natural gas at the wellhead or other receipt points, at an index related price at the delivery point less a specified amount, generally the same as the transportation fees we would otherwise charge for transportation of natural gas from the wellhead location to the delivery point. The revenues we earn are directly related to the volume of natural gas or NGLs that flows through our systems and are not directly dependent on commodity prices. However, to the extent a sustained decline in commodity prices results in a decline in volumes, our revenues from these arrangements would be reduced. | |
• | Percent-of-proceeds— Under percent-of-proceeds arrangements, we generally purchase natural gas from producers at the wellhead, or other receipt points, gather the wellhead natural gas through our gathering system, treat and process the natural gas, and then sell the resulting residue natural gas and |
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NGLs based on index prices from published index market prices. We remit to the producers either anagreed-upon percentage of the actual proceeds that we receive from our sales of the residue natural gas and NGLs, or anagreed-upon percentage of the proceeds based on index related prices for the natural gas and the NGLs, regardless of the actual amount of the sales proceeds we receive. Certain of these arrangements may also result in our returning all or a portion of the residue natural gasand/or the NGLs to the producer, in lieu of returning sales proceeds. Our revenues under percent-of-proceeds arrangements correlate directly with the price of natural gasand/or NGLs. |
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Year Ended December 31, | ||||||||||||
Reconciliation of Non-GAAP Measures | 2008 | 2007 | 2006 | |||||||||
(Millions) | ||||||||||||
Reconciliation of net income (loss) to gross margin: | ||||||||||||
Net income (loss) | $ | 125.7 | $ | (15.8 | ) | $ | 61.9 | |||||
Interest expense | 32.8 | 25.8 | 11.5 | |||||||||
Income tax expense | 0.1 | 0.1 | — | |||||||||
Operating and maintenance expense | 43.0 | 32.1 | 23.7 | |||||||||
Depreciation and amortization expense | 36.5 | 24.4 | 12.8 | |||||||||
General and administrative expense | 24.0 | 24.1 | 21.0 | |||||||||
Other | (1.5 | ) | — | — | ||||||||
Non-controlling interest in income | 3.9 | 0.5 | — | |||||||||
Interest income | (5.6 | ) | (5.3 | ) | (6.3 | ) | ||||||
Earnings from equity method investments | (34.3 | ) | (39.3 | ) | (29.2 | ) | ||||||
Gross margin | $ | 224.6 | $ | 46.6 | $ | 95.4 | ||||||
Reconciliation of segment net income to segment gross margin: | ||||||||||||
Natural Gas Services segment: | ||||||||||||
Segment net income | $ | 170.2 | $ | 11.6 | $ | 79.6 | ||||||
Depreciation and amortization expense | 33.8 | 21.9 | 11.1 | |||||||||
Operating and maintenance expense | 32.1 | 20.9 | 13.5 | |||||||||
Non-controlling interest in income | 3.9 | 0.5 | — | |||||||||
Earnings from equity method investments | (33.5 | ) | (38.7 | ) | (28.9 | ) | ||||||
Segment gross margin | $ | 206.5 | $ | 16.2 | $ | 75.3 | ||||||
Non-cash commodity derivative mark-to-market(a) | $ | 99.2 | $ | (78.3 | ) | $ | 0.1 | |||||
Wholesale Propane Logistics segment: | ||||||||||||
Segment net income | $ | 1.3 | $ | 14.0 | $ | 6.6 | ||||||
Depreciation and amortization expense | 1.3 | 1.1 | 0.8 | |||||||||
Operating and maintenance expense | 9.9 | 10.4 | 8.6 | |||||||||
Other | (1.5 | ) | — | — | ||||||||
Segment gross margin | $ | 11.0 | $ | 25.5 | $ | 16.0 | ||||||
Non-cash commodity derivative mark-to-market(a) | $ | 2.4 | $ | (2.8 | ) | $ | — | |||||
NGL Logistics segment: | ||||||||||||
Segment net income | $ | 5.5 | $ | 3.3 | $ | 1.9 | ||||||
Depreciation and amortization expense | 1.4 | 1.4 | 0.9 | |||||||||
Operating and maintenance expense | 1.0 | 0.8 | 1.6 | |||||||||
Earnings from equity method investments | (0.8 | ) | (0.6 | ) | (0.3 | ) | ||||||
Segment gross margin | $ | 7.1 | $ | 4.9 | $ | 4.1 | ||||||
(a) | Non-cash commodity derivative mark-to-market is included in segment gross margin, along with cash settlements for our derivative contracts. |
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Year Ended December 31, | ||||||||||||
2008 | 2007 | 2006 | ||||||||||
Affiliate: | ||||||||||||
Omnibus Agreement: | ||||||||||||
Annual fee | $ | 5.1 | $ | 5.0 | $ | 4.8 | ||||||
Wholesale propane logistics business | 2.0 | 2.0 | 0.3 | |||||||||
Southern Oklahoma | 0.2 | 0.1 | — | |||||||||
Discovery | 0.2 | 0.1 | — | |||||||||
Additional services | 0.6 | 0.2 | — | |||||||||
Momentum Energy Group, Inc. | 1.6 | 0.5 | — | |||||||||
Michigan Pipeline & Processing, LLC | 0.1 | — | — | |||||||||
Total Omnibus Agreement | 9.8 | 7.9 | 5.1 | |||||||||
Other — DCP Midstream, LLC | 1.8 | 2.1 | 3.0 | |||||||||
Total affiliate | 11.6 | 10.0 | 8.1 | |||||||||
Other | 12.4 | 14.1 | 12.9 | |||||||||
Total | $ | 24.0 | $ | 24.1 | $ | 21.0 | ||||||
Terms | Effective Date | Fee | ||||
(Millions) | ||||||
Annual fee | 2006 | $ | 5.1 | |||
Wholesale propane logistics business | November 2006 | 2.0 | ||||
Southern Oklahoma | May 2007 | 0.2 | ||||
Discovery | July 2007 | 0.2 | ||||
Additional services | August 2007 | 0.6 | ||||
Momentum Energy Group, Inc. | August 2007 | 1.6 | ||||
Michigan Pipeline & Processing, LLC | October 2008 | 0.4 | ||||
Total | $ | 10.1 | ||||
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• | DCP Midstream, LLC’s obligation to indemnify us for certain liabilities and our obligation to indemnify DCP Midstream, LLC for certain liabilities; | |
• | DCP Midstream, LLC’s obligation to continue to maintain its credit support for certain obligations related to derivative financial instruments, such as commodity derivative instruments, to the extent that such credit support arrangements were in effect as of December 7, 2005 until the earlier of December 7, 2010 or when we obtain certain credit ratings from either Moody’s Investor Services, Inc. or Standard & Poor’s Ratings Group with respect to any of our unsecured indebtedness; and | |
• | DCP Midstream, LLC’s obligation to continue to maintain its credit support for our obligations related to commercial contracts with respect to its business or operations that were in effect at December 7, 2005 until the expiration of such contracts. |
• | the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness, make cash distributions to our unitholders and general partner, and finance maintenance capital expenditures; | |
• | financial performance of our assets without regard to financing methods, capital structure or historical cost basis; | |
• | our operating performance and return on capital as compared to those of other companies in the midstream energy industry, without regard to financing methods or capital structure; and | |
• | viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities. |
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Year Ended December 31, | ||||||||||||
Reconciliation of Non-GAAP Measures | 2008 | 2007 | 2006 | |||||||||
(Millions) | ||||||||||||
Reconciliation of net income (loss) to EBITDA: | ||||||||||||
Net income (loss) | $ | 125.7 | $ | (15.8 | ) | $ | 61.9 | |||||
Interest income | (5.6 | ) | (5.3 | ) | (6.3 | ) | ||||||
Interest expense | 32.8 | 25.8 | 11.5 | |||||||||
Income tax expense | 0.1 | 0.1 | — | |||||||||
Depreciation and amortization expense | 36.5 | 24.4 | 12.8 | |||||||||
EBITDA | $ | 189.5 | $ | 29.2 | $ | 79.9 | ||||||
Reconciliation of net cash provided by operating activities to EBITDA: | ||||||||||||
Net cash provided by operating activities | $ | 101.5 | $ | 65.4 | $ | 94.8 | ||||||
Interest income | (5.6 | ) | (5.3 | ) | (6.3 | ) | ||||||
Interest expense | 32.8 | 25.8 | 11.5 | |||||||||
Earnings from equity method investments, net of distributions | (25.6 | ) | 0.4 | 3.3 | ||||||||
Income tax expense | 0.1 | 0.1 | — | |||||||||
Net changes in operating assets and liabilities | 89.8 | (56.9 | ) | (25.8 | ) | |||||||
Other, net | (3.5 | ) | (0.3 | ) | 2.4 | |||||||
EBITDA | $ | 189.5 | $ | 29.2 | $ | 79.9 | ||||||
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Effect if Actual Results Differ from | ||||
Description | Judgments and Uncertainties | Assumptions | ||
Inventories | ||||
Inventories, which consist primarily of propane, are recorded at the lower of weighted-average cost or market value. | Judgment is required in determining the market value of inventory, as the geographic location impacts market prices, and quoted market prices may not be available for the particular location of our inventory. | If the market value of our inventory is lower than the cost, we may be exposed to losses that could be material. If propane prices were to decrease by 10% below our December 31, 2008 weighted-average cost, our net income would be affected by approximately $2.1 million. | ||
Goodwill | ||||
Goodwill is the cost of an acquisition less the fair value of the net assets of the acquired business. We evaluate goodwill for impairment annually in the third quarter, and whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying amount. | We determine fair value using widely accepted valuation techniques, namely discounted cash flow and market multiple analyses. These techniques are also used when allocating the purchase price to acquired assets and liabilities. These types of analyses require us to make assumptions and estimates regarding industry and economic factors and the profitability of future business strategies. It is our policy to conduct impairment testing based on our current business strategy in light of present industry and economic conditions, as well as future expectations. | We completed our impairment testing of goodwill using the methodology described herein, and determined there was no impairment. We have not recorded goodwill impairment during the year ended December 31, 2008. The carrying value of goodwill as of December 31, 2008 was $88.8 million. | ||
Impairment of Long-Lived Assets | ||||
We periodically evaluate whether the carrying value of long-lived assets has been impaired when circumstances indicate the carrying value of those assets may not be recoverable. This evaluation is based on undiscounted cash flow projections expected to be realized over the remaining useful life of the primary asset. The carrying amount is not recoverable if it exceeds the sum of undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the carrying value is not recoverable, the impairment loss is measured as the excess of the asset’s carrying value over its fair value. | Our impairment analyses may require management to apply judgment in estimating future cash flows as well as asset fair values, including forecasting useful lives of the assets, assessing the probability of different outcomes, and selecting the discount rate that reflects the risk inherent in future cash flows. We assess the fair value of long-lived assets using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales and discounted cash flow models. These techniques are also used when allocating the purchase price to acquired assets and liabilities. | Using the impairment review methodology described herein, we have not recorded impairment charges during the year ended December 31, 2008. 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 an impairment charge. The carrying value of our long-lived assets as of December 31, 2008 was $677.0 million. |
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Effect if Actual Results Differ from | ||||
Description | Judgments and Uncertainties | Assumptions | ||
Impairment of Equity Method Investments | ||||
We evaluate our equity method investments for impairment whenever events or changes in circumstances indicate, in management’s judgment, that the carrying value of such investment may have experienced a decline in value. When evidence of loss in value has occurred, we compare the estimated fair value of the investment to the carrying value of the investment to determine whether an impairment has occurred. | Our impairment loss calculations require management to apply judgment in estimating future cash flows and asset fair values, including forecasting useful lives of the assets, assessing the probability of differing estimated outcomes, and selecting the discount rate that reflects the risk inherent in future cash flows. We assess the fair value of our equity method investments using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales and discounted cash flow models. | Using the impairment review methodology described herein, we have not recorded impairment charges during the year ended December 31, 2008. If the estimated fair value of our equity method investments is less than the carrying value, we would recognize an impairment loss for the excess of the carrying value over the estimated fair value. The carrying value of our equity method investments as of December 31, 2008 was $175.4 million. | ||
Accounting for Risk Management Activities and Financial Instruments | ||||
Each derivative not qualifying for the normal purchases and normal sales exception is recorded on a gross basis in the consolidated balance sheets at its fair value as unrealized gains or unrealized losses on derivative instruments. Derivative assets and liabilities remain classified in our consolidated balance sheets as unrealized gains or unrealized losses on derivative instruments at fair value until the contractual settlement period impacts earnings. 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. | 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 correlations with quoted market prices. | If our estimates of fair value are inaccurate, we may be exposed to losses or gains that could be material. A 10% difference in our estimated fair value of derivatives at December 31, 2008 would have affected net income by approximately $2.0 million for the year ended December 31, 2008. | ||
Accounting for Equity-Based Compensation | ||||
Our long-term incentive plan permits for the grant of restricted units, phantom units, unit options and substitute awards. Equity-based compensation expense is recognized over the vesting period or service period of the related awards. We estimate the fair value of each award, and the number of awards that will ultimately vest, at the end of each period. | Estimating the fair value of each award, the number of awards that will ultimately vest, and the forfeiture rate requires management to apply judgment to estimate the tenure of our employees and the achievement of certain performance targets over the performance period. | If actual results are not consistent with our assumptions and judgments or our assumptions and estimates change due to new information, we may experience material changes in compensation expense. |
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Effect if Actual Results Differ from | ||||
Description | Judgments and Uncertainties | Assumptions | ||
Accounting for Asset Retirement Obligations | ||||
Asset retirement obligations associated with tangible long-lived assets are recorded at fair value in the period in which they are incurred, if a reasonable estimate of fair value can be made, and added to the carrying amount of the associated asset. This additional carrying amount is then depreciated over the life of the asset. The liability is determined using a credit adjusted risk free interest rate, and increases due to the passage of time based on the time value of money until the obligation is settled. | Estimating the fair value of asset retirement obligations requires management to apply judgment to evaluate the necessary retirement activities, estimate the costs to perform those activities, including the timing and duration of potential future retirement activities, and estimate the risk free interest rate. When making these assumptions, we consider a number of factors, including historical retirement costs, the location and complexity of the asset and general economic conditions. | If actual results are not consistent with our assumptions and judgments or our assumptions and estimates change due to new information, we may experience material changes in our asset retirement obligations. Establishing an asset retirement obligation has no initial impact on net income. A 10% change in depreciation and accretion expense associated with our asset retirement obligations during the year ended December 31, 2008, would not have had a significant effect on net income. |
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Variance | Variance | |||||||||||||||||||||||||||
2008 vs. 2007 | 2007 vs. 2006 | |||||||||||||||||||||||||||
Year Ended December 31, | Increase | Increase | ||||||||||||||||||||||||||
2008(a) | 2007(a) | 2006 | (Decrease) | Percent | (Decrease) | Percent | ||||||||||||||||||||||
(Millions, except as indicated) | ||||||||||||||||||||||||||||
Operating revenues: | ||||||||||||||||||||||||||||
Natural Gas Services(b) | $ | 791.5 | $ | 404.1 | $ | 415.3 | $ | 387.4 | 96 | % | $ | (11.2 | ) | (3 | )% | |||||||||||||
Wholesale Propane Logistics | 483.0 | 459.6 | 375.2 | 23.4 | 5 | % | 84.4 | 23 | % | |||||||||||||||||||
NGL Logistics | 11.3 | 9.6 | 5.3 | 1.7 | 18 | % | 4.3 | 81 | % | |||||||||||||||||||
Total operating revenues | 1,285.8 | 873.3 | 795.8 | 412.5 | 47 | % | 77.5 | 10 | % | |||||||||||||||||||
Gross margin(c): | ||||||||||||||||||||||||||||
Natural Gas Services | 206.5 | 16.2 | 75.3 | 190.3 | 1,175 | % | (59.1 | ) | (78 | )% | ||||||||||||||||||
Wholesale Propane Logistics | 11.0 | 25.5 | 16.0 | (14.5 | ) | (57 | )% | 9.5 | 59 | % | ||||||||||||||||||
NGL Logistics | 7.1 | 4.9 | 4.1 | 2.2 | 45 | % | 0.8 | 20 | % | |||||||||||||||||||
Total gross margin | 224.6 | 46.6 | 95.4 | 178.0 | 382 | % | (48.8 | ) | (51 | )% | ||||||||||||||||||
Operating and maintenance expense | (43.0 | ) | (32.1 | ) | (23.7 | ) | 10.9 | 34 | % | 8.4 | 35 | % | ||||||||||||||||
General and administrative expense | (24.0 | ) | (24.1 | ) | (21.0 | ) | (0.1 | ) | — | % | 3.1 | 15 | % | |||||||||||||||
Other | 1.5 | — | — | 1.5 | * | — | — | % | ||||||||||||||||||||
Earnings from equity method investments(d) | 34.3 | 39.3 | 29.2 | (5.0 | ) | (13 | )% | 10.1 | 35 | % | ||||||||||||||||||
Non-controlling interest in income | (3.9 | ) | (0.5 | ) | — | 3.4 | 680 | % | 0.5 | 100 | ||||||||||||||||||
EBITDA(e) | 189.5 | 29.2 | 79.9 | 160.3 | 549 | % | (50.7 | ) | (64 | )% | ||||||||||||||||||
Depreciation and amortization expense | (36.5 | ) | (24.4 | ) | (12.8 | ) | 12.1 | 50 | % | 11.6 | 91 | % | ||||||||||||||||
Interest income | 5.6 | 5.3 | 6.3 | 0.3 | 6 | % | (1.0 | ) | 16 | % | ||||||||||||||||||
Interest expense | (32.8 | ) | (25.8 | ) | (11.5 | ) | 7.0 | 27 | % | 14.3 | * | |||||||||||||||||
Income tax expense | (0.1 | ) | (0.1 | ) | — | — | — | % | 0.1 | 100 | % | |||||||||||||||||
Net income (loss) | $ | 125.7 | $ | (15.8 | ) | $ | 61.9 | $ | 141.5 | * | $ | (77.7 | ) | * | ||||||||||||||
Operating data: | ||||||||||||||||||||||||||||
Natural gas throughput(MMcf/d)(d) | 838 | 756 | 666 | 82 | 11 | % | 90 | 14 | % | |||||||||||||||||||
NGL gross production (Bbls/d)(d) | 20,659 | 22,122 | 19,485 | (1,463 | ) | (7 | )% | 2,637 | 14 | % | ||||||||||||||||||
Propane sales volume (Bbls/d) | 21,053 | 22,798 | 21,259 | (1,745 | ) | (8 | )% | 1,539 | 7 | % | ||||||||||||||||||
NGL pipelines throughput (Bbls/d)(d) | 31,407 | 28,961 | 25,040 | 2,446 | 8 | % | 3,921 | 16 | % |
* | Percentage change is not meaningful. | |
(a) | Includes the results from the Michigan Pipeline & Processing, LLC, or MPP, Momentum Energy Group, Inc, or MEG, and Southern Oklahoma acquisitions, from their respective acquisition dates of October 2008, August 2007 and May 2007. | |
(b) | Includes the effect of the acquisition of the Swap entered into by DCP Midstream, LLC in March 2007. The Swap was for a total of approximately 1.9 million barrels at $66.72 per barrel. |
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(c) | Gross margin consists of total operating revenues, including commodity derivative activity, less purchases of natural gas, propane and NGLs, and segment gross margin for each segment consists of total operating revenues for that segment, less commodity purchases for that segment. Please read “How We Evaluate Our Operations” above. | |
(d) | Includes our proportionate share of the throughput volumes and earnings of Black Lake, East Texas and Discovery for all periods presented. Earnings for Discovery and Black Lake include the amortization of the net difference between the carrying amount of the investments and the underlying equity of the investments. | |
(e) | EBITDA consists of net income or loss less interest income plus interest expense, income tax expense, and depreciation and amortization expense. Please read “How We Evaluate Our Operations” above. |
• | $213.7 million increase primarily attributable to increased commodity prices as well as higher natural gas, NGL and condensate sales volumes, primarily as a result of the MEG, MPP and Southern Oklahoma acquisitions, partially offset by decreased volumes due to the impact of hurricanes, for our Natural Gas Services segment; | |
• | $156.8 million increase related to commodity derivative activity, resulting from the following: |
• | we had a gain of $72.3 million in 2008 and a loss of $87.6 million in 2007, resulting in an increase of $159.9 million, which is included in gains (losses) from commodity derivative activity. This increase includes an increase in unrealized gains of $184.1 million due to forward prices of commodities generally being lower at the end of the year 2008 compared to 2007. Offsetting this increase in gain was an increase in realized cash settlement losses of $24.2 million due to average prices of commodities generally being higher for the year ended December 31, 2008 compared to 2007; and | |
• | we had a $3.1 million increase in unrealized loss, which is included in sales of natural gas, NGLs and condensate; |
• | $22.1 million increase in transportation processing and other revenue, primarily attributable to the MEG and MPP acquisitions in our Natural Gas Services segment; | |
• | $19.0 million increase attributable to higher propane prices offset by decreased propane sales volumes as a result of lower demand for our Wholesale Propane Logistics segment; and | |
• | $0.9 million increase due to increased throughput volumes, transportation, processing and other revenue, and increases related to settlement of pipeline imbalances in our NGL logistics segment. |
• | $190.3 million increase for our Natural Gas Services segment primarily due to increases related to commodity derivative activity, an increase in natural gas, NGL and condensate production, mainly as a result of the MEG, MPP and Southern Oklahoma acquisitions, partially offset by decreased volumes due to the impact of hurricanes; and | |
• | $2.2 million increase for our NGL Logistics segment primarily attributable to increases related to settlement of pipeline imbalances and increased throughput volumes; partially offset by | |
• | $14.5 million decrease for our Wholesale Propane Logistics segment as a result of increased non-cash lower of cost or market inventory adjustments due to a decline in propane prices in the second half of 2008. We estimate that approximately half of the 2008 write downs were recovered through the sale of inventory in 2008. We also had lower per unit margins and propane sales volumes, partially offset by commodity derivative activity. |
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• | $88.1 million increase attributable to higher propane prices and higher sales volumes for our Wholesale Propane Logistics segment; | |
• | $66.2 million increase primarily attributable to an increase in natural gas, NGL and condensate sales volumes, including increases as a result of the MEG and Southern Oklahoma acquisitions, and increases in NGL and condensate prices, partially offset by a decrease in natural gas sales volumes, primarily as a result of an amendment to a contract with an affiliate in 2006, which resulted in a prospective change in the reporting of certain Pelico revenues from a gross presentation to a net presentation for our Natural Gas Services segment; | |
• | $7.3 million increase in transportation processing and other revenue primarily attributable to an increase in throughput volumes in our Natural Gas Services segment; and | |
• | $3.4 million increase due to changes in product mix and increased volumes for our NGL Logistics segment; offset by | |
• | $87.5 million decrease related to commodity derivative activity, an increase of $0.2 million which is included in sales of natural gas, NGLs and condensate, and a decrease of $87.7 million which is included in losses from derivative activity. |
• | $59.1 million decrease for our Natural Gas Services segment primarily due to decreases related to commodity derivative activity, and a decrease in marketing margins from the decline in the differences of natural gas prices at various receipt and delivery points across our Pelico system, offset by an increase in NGL and condensate production, mainly as a result of the MEG and Southern Oklahoma acquisitions, an increase in natural gas throughput volumes and higher contractual fees charged to customers; offset by |
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• | $9.5 million increase for our Wholesale Propane Logistics segment due to higher per unit margins as a result of changes in contract mix and the ability to capture lower priced supply sources, decreased non-cash lower of cost or market inventory adjustments recognized in 2007, and higher sales volumes primarily due to the completion of the Midland terminal, which became operational in May 2007, partially offset by a decrease related to commodity derivative activity; and | |
• | $0.8 million increase for our NGL Logistics segment primarily attributable to changes in product mix and increased volumes, as well as increased transportation processing and other revenue. |
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Variance | Variance | |||||||||||||||||||||||||||
2008 vs. 2007 | 2007 vs. 2006 | |||||||||||||||||||||||||||
Year Ended December 31, | Increase | Increase | ||||||||||||||||||||||||||
2008(a) | 2007(a) | 2006 | (Decrease) | Percent | (Decrease) | Percent | ||||||||||||||||||||||
(Millions, except operating data) | ||||||||||||||||||||||||||||
Operating revenues: | ||||||||||||||||||||||||||||
Sales of natural gas, NGLs and condensate | $ | 668.8 | $ | 458.2 | $ | 391.8 | $ | 210.6 | 46 | % | $ | 66.4 | 17 | % | ||||||||||||||
Transportation, processing and other | 50.2 | 29.4 | 23.5 | 20.8 | 71 | % | 5.9 | 25 | % | |||||||||||||||||||
Gains (losses) from commodity derivative activity(b) | 72.5 | (83.5 | ) | — | 156.0 | * | (83.5 | ) | * | |||||||||||||||||||
Total operating revenues | 791.5 | 404.1 | 415.3 | 387.4 | 96 | % | (11.2 | ) | (3 | )% | ||||||||||||||||||
Purchases of natural gas and NGLs | 585.0 | 387.9 | 340.0 | 197.1 | 51 | % | 47.9 | 14 | % | |||||||||||||||||||
Segment gross margin(c) | 206.5 | 16.2 | 75.3 | 190.3 | 1,175 | % | (59.1 | ) | (79 | )% | ||||||||||||||||||
Operating and maintenance expense | (32.1 | ) | (20.9 | ) | (13.5 | ) | 11.2 | 54 | % | 7.4 | 55 | % | ||||||||||||||||
Depreciation and amortization expense | (33.8 | ) | (21.9 | ) | (11.1 | ) | 11.9 | 54 | % | 10.8 | 97 | % | ||||||||||||||||
Earnings from equity method investments(d) | 33.5 | 38.7 | 28.9 | (5.2 | ) | (13 | )% | 9.8 | 34 | % | ||||||||||||||||||
Non-controlling interest in income | (3.9 | ) | (0.5 | ) | — | 3.4 | 680 | % | 0.5 | 100 | % | |||||||||||||||||
Segment net income | $ | 170.2 | $ | 11.6 | $ | 79.6 | $ | 158.6 | 1,367 | % | $ | (68.0 | ) | (85 | )% | |||||||||||||
Operating data: | ||||||||||||||||||||||||||||
Natural gas throughput(MMcf/d)(d) | 838 | 756 | 666 | 82 | 11 | % | 90 | 14 | % | |||||||||||||||||||
NGL gross production (Bbls/d) | 20,659 | 22,122 | 19,485 | (1,463 | ) | (7 | )% | 2,637 | 14 | % |
* | Percentage change is not meaningful. | |
(a) | Includes the results from the MEG, MPP and Southern Oklahoma acquisitions, from their respective acquisition dates of October 2008, August 2007 and May 2007. | |
(b) | Includes the effect of the acquisition of the Swap entered into by DCP Midstream, LLC in March 2007. The Swap was for a total of approximately 1.9 million barrels through 2012, at $66.72 per barrel. | |
(c) | Segment gross margin consists of total operating revenues, including commodity derivative activity, less purchases of natural gas and NGLs. Please read “How We Evaluate Our Operations” above. | |
(d) | Includes our proportionate share of the throughput volumes and earnings of East Texas and Discovery for all periods presented. Earnings for Discovery include the amortization of the net difference between the carrying amount of the investments and the underlying equity of the investments. |
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• | $152.9 million increase related to commodity derivative activity, resulting from the following: |
• | we had a gain of $72.5 million in 2008 and a loss of $83.5 million in 2007, resulting in an increase of $156.0 million, which is included gains (losses) from commodity derivative activity. This increase includes an increase in unrealized gains of $178.8 million due to forward prices of commodities generally being lower at the end of the year 2008 compared to 2007. Offsetting this increase in gain was an increase in realized cash settlement losses of $22.8 million due to average prices of commodities generally being higher for the year ended December 31, 2008 compared to 2007; and | |
• | we had a $3.1 million increase in unrealized loss, which is included in sales of natural gas, NGLs and condensate; |
• | $150.3 million increase attributable to increased commodity prices; | |
• | $63.4 million increase attributable to higher natural gas, NGL and condensate sales volumes, primarily as a result of the MEG, MPP and Southern Oklahoma acquisitions, partially offset by decreased volumes due to the impact of hurricanes; and | |
• | $20.8 million increase in transportation, processing and other revenue as a result of the MEG and MPP acquisitions. |
• | $152.9 million increase related to commodity derivative activity, as discussed in the Operating Revenues section above; | |
• | $24.1 million increase primarily attributable to an increase in natural gas, NGL and condensate production as a result of the MEG, MPP and Southern Oklahoma acquisitions, partially offset by decreased volumes due to the impact of hurricanes; | |
• | $9.0 million increase primarily attributable to changes in contract mix; and | |
• | $4.3 million increase due to higher commodity prices. |
• | Decreased equity earnings from Discovery were the result of a decrease in Discovery’s net income of $13.7 million due primarily to $32.5 million resulting from hurricanes Ike and Gustav, partially offset by $10.4 million higher product margins, $4.6 million lower depreciation and accretion expense and a 2008 reserve reversal of $3.5 million related to a recently approved Federal Energy Regulatory Commission rate case settlement. |
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• | Increased equity earnings from East Texas were the result of an increase in East Texas’s net income of $6.0 million due primarily to a $14.9 million increase as a result of higher commodity prices, a $9.0 million increase due to increased fee-based revenue, and decreased general and administrative expenses of $2.9 million, partially offset by a $12.9 million decrease due to decreased NGL production, partially due to the effects of hurricanes and other severe weather and an increase in operating and maintenance expenses of $7.3 million. |
• | $83.3 million decrease related to commodity derivative activity, an increase of $0.2 million which is included in sales of natural gas, NGLs and condensate, and a decrease of $83.5 million which is included in losses from derivative activity; offset by | |
• | $49.0 million increase attributable to an increase in natural gas, NGL and condensate sales volumes, primarily as a result of the MEG and Southern Oklahoma acquisitions, partially offset by a decrease in natural gas sales volumes, primarily as a result of an amendment to a contract with an affiliate in 2006, which resulted in a prospective change in the reporting of certain Pelico revenues from a gross presentation to a net presentation; | |
• | $17.2 million increase attributable to increased NGL and condensate prices; and | |
• | $5.9 million increase in transportation, processing and other services revenue primarily attributable to an increase in natural gas throughput. |
• | $83.3 million decrease related to commodity derivative activity; | |
• | $2.5 million decrease attributable primarily to a decrease in marketing margins from the decline in the differences in natural gas prices at various receipt and delivery points across our Pelico system, which were atypically high in 2006; partially offset by | |
• | $25.2 million increase primarily attributable to an increase in NGL and condensate production, partially as a result of the MEG and Southern Oklahoma acquisitions, and an increase in natural gas throughput volumes; | |
• | $1.0 million increase primarily attributable to higher contractual fees charged to customers; and | |
• | $0.5 million increase primarily attributable to favorable frac spreads. |
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• | Increased equity earnings from Discovery were the result of an increase in Discovery’s net income of $18.0 million, or 60%, due primarily to $39.0 million higher gross processing margins resulting from higher NGL sales volumes and NGL prices, partially offset by $9.9 million lower fee-based transportation, gathering, processing and fractionation revenues, $5.9 million higher operating and maintenance expense and $2.2 million higher other expenses. In addition, exceptionally strong commodity margins compelled Discovery’s customers to process their natural gas rather than by-pass, which led to higher product sales revenues on Discovery’s percent-of-proceeds and keep-whole processing contracts. | |
• | Increased equity earnings from East Texas were the result of an increase in East Texas’s net income of $10.7 million, or 22%, due primarily to a $28.5 million increase as a result of higher commodity prices and a $1.1 million decrease in income tax expense due to recording a deferred tax liability of $1.8 million in 2006 related to the Texas margin tax; partially offset by an $11.6 million decrease due to a decline in natural gas volumes, a $3.0 million decrease due to decreased fee-based revenue, and an increase in operating and maintenance expenses of $2.8 million, primarily due to increased contract services, materials and supplies, and labor an benefits, increased depreciation expense of $1.2 million due to the addition of a new pipeline, and increased general and administrative expenses of $0.6 million, primarily due to higher allocated costs from DCP Midstream, LLC. |
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Variance | Variance | |||||||||||||||||||||||||||
2008 vs. 2007 | 2007 vs. 2006 | |||||||||||||||||||||||||||
Year Ended December 31, | Increase | Increase | ||||||||||||||||||||||||||
2008 | 2007 | 2006 | (Decrease) | Percent | (Decrease) | Percent | ||||||||||||||||||||||
(Millions, except operating data) | ||||||||||||||||||||||||||||
Operating revenues: | ||||||||||||||||||||||||||||
Sales of propane | $ | 482.1 | $ | 463.1 | $ | 375.0 | $ | 19.0 | 4 | % | $ | 88.1 | 24 | % | ||||||||||||||
Transportation, processing and other | 1.1 | 0.6 | 0.1 | 0.5 | 83 | % | 0.5 | * | ||||||||||||||||||||
(Losses) gains from commodity derivative activity | (0.2 | ) | (4.1 | ) | 0.1 | (3.9 | ) | (95 | )% | (4.2 | ) | * | ||||||||||||||||
Total operating revenues | 483.0 | 459.6 | 375.2 | 23.4 | 5 | % | 84.4 | 23 | % | |||||||||||||||||||
Purchases of propane | 472.0 | 434.1 | 359.2 | 37.9 | 9 | % | 74.9 | 21 | % | |||||||||||||||||||
Segment gross margin(a) | 11.0 | 25.5 | 16.0 | (14.5 | ) | (57 | )% | 9.5 | 59 | % | ||||||||||||||||||
Operating and maintenance expense | (9.9 | ) | (10.4 | ) | (8.6 | ) | (0.5 | ) | (5 | )% | 1.8 | 21 | % | |||||||||||||||
Depreciation and amortization expense | (1.3 | ) | (1.1 | ) | (0.8 | ) | 0.2 | 18 | % | 0.3 | 38 | % | ||||||||||||||||
Other | 1.5 | — | — | 1.5 | * | — | — | % | ||||||||||||||||||||
Segment net income | $ | 1.3 | $ | 14.0 | $ | 6.6 | $ | (12.7 | ) | (91 | )% | $ | 7.4 | * | ||||||||||||||
Operating Data: | ||||||||||||||||||||||||||||
Propane sales volume (Bbls/d) | 21,053 | 22,798 | 21,259 | (1,745 | ) | (8 | )% | 1,539 | 7 | % |
* | Percentage change is not meaningful. | |
(a) | Segment gross margin consists of total operating revenues, including commodity derivative activity, less purchases of propane. Please read “How We Evaluate Our Operations” above. |
• | $54.1 million increase attributable to higher propane prices; | |
• | $3.9 million increase related to commodity derivative activity, which represents increased unrealized gains of $5.3 million, partially offset by increased realized cash settlement losses of $1.4 million; and | |
• | $0.5 million increase attributable to other fee revenue; partially offset by | |
• | $35.1 million decrease attributable to decreased propane sales volumes as a result of lower demand. |
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• | $60.8 million increase attributable to higher propane prices; | |
• | $27.3 million increase attributable to higher propane sales volumes as a result of colder weather in the northeastern United States and the completion of the Midland terminal, which became operational in May 2007; and | |
• | $0.5 million increase in transportation, processing and other services; offset by | |
• | $4.2 million decrease related to commodity derivative activity. |
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Variance | Variance | |||||||||||||||||||||||||||
2008 vs. 2007 | 2007 vs. 2006 | |||||||||||||||||||||||||||
Year Ended December 31, | Increase | Increase | ||||||||||||||||||||||||||
2008 | 2007 | 2006 | (Decrease) | Percent | (Decrease) | Percent | ||||||||||||||||||||||
(Millions, except operating data) | ||||||||||||||||||||||||||||
Operating revenues: | ||||||||||||||||||||||||||||
Sales of NGLs | $ | 5.4 | $ | 4.5 | $ | 1.1 | $ | 0.9 | 20 | % | $ | 3.4 | * | |||||||||||||||
Transportation, processing and other | 5.9 | 5.1 | 4.2 | 0.8 | 16 | % | 0.9 | 21 | % | |||||||||||||||||||
Total operating revenues | 11.3 | 9.6 | 5.3 | 1.7 | 18 | % | 4.3 | 81 | % | |||||||||||||||||||
Purchases of NGLs | 4.2 | 4.7 | 1.2 | (0.5 | ) | (11 | )% | 3.5 | * | |||||||||||||||||||
Segment gross margin(a) | 7.1 | 4.9 | 4.1 | 2.2 | 45 | % | 0.8 | 20 | % | |||||||||||||||||||
Operating and maintenance expense | (1.0 | ) | (0.8 | ) | (1.6 | ) | 0.2 | 25 | % | (0.8 | ) | (50 | )% | |||||||||||||||
Depreciation and amortization expense | (1.4 | ) | (1.4 | ) | (0.9 | ) | — | — | % | 0.5 | 56 | % | ||||||||||||||||
Earnings from equity method investment(b) | 0.8 | 0.6 | 0.3 | 0.2 | 33 | % | 0.3 | 100 | % | |||||||||||||||||||
Segment net income | $ | 5.5 | $ | 3.3 | $ | 1.9 | $ | 2.2 | 67 | % | $ | 1.4 | 74 | % | ||||||||||||||
Operating data: | ||||||||||||||||||||||||||||
NGL pipelines throughput (Bbls/d)(b) | 31,407 | 28,961 | 25,040 | 2,446 | 8 | % | 3,921 | 16 | % |
* | Percentage change is not meaningful. | |
(a) | Segment gross margin consists of total operating revenues less purchases of natural gas and NGLs. Please read “How We Evaluate Our Operations” above. | |
(b) | Includes our proportionate share of the throughput volumes and earnings of Black Lake for all periods presented. Earnings for Black Lake include the amortization of the net difference between the carrying amount of the investment and the underlying equity of the investment. |
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• | cash generated from operations; | |
• | cash distributions from our equity method investments; | |
• | borrowings under our revolving credit facility; | |
• | cash realized from the liquidation of securities that are pledged under our term loan facility; | |
• | issuance of additional partnership units; | |
• | debt offerings; | |
• | guarantees issued by DCP Midstream, LLC, which reduce the amount of collateral we may be required to post with certain counterparties to our commodity derivative instruments; and | |
• | letters of credit. |
• | capital expenditures; | |
• | contributions to our equity method investments to finance our share of their capital expenditures; | |
• | business and asset acquisitions; | |
• | collateral with counterparties to our swap contracts to secure potential exposure under these contracts, which may, at times, be significant depending on commodity price movements, and which is required to the extent we exceed certain guarantees issued by DCP Midstream, LLC and letters of credit we have posted; and | |
• | quarterly distributions to our unitholders. |
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Year Ended December 31, | ||||||||||||
2008 | 2007 | 2006 | ||||||||||
(Millions) | ||||||||||||
Net cash provided by operating activities | $ | 101.5 | $ | 65.4 | $ | 94.8 | ||||||
Net cash used in investing activities | $ | (166.9 | ) | $ | (521.7 | ) | $ | (93.8 | ) | |||
Net cash provided by financing activities | $ | 88.9 | $ | 434.6 | $ | 3.0 |
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• | $320.4 million borrowings for cash collateral postings with our commodity derivative contracts and for general working capital purposes. $293.9 million of these borrowings were repaid as of December 31, 2008; | |
• | $150.0 million borrowing on our term loan facility, the proceeds of which were used to reduce borrowings on our revolving credit facility; and | |
• | $190.0 million borrowing from our revolving credit facility, $146.4 million of which was used for the Michigan acquisition and the remainder was used for other capital expenditures. |
• | $11.0 million under our revolving credit facility to fund the purchase of the Laser assets from Midstream; | |
• | $89.0 million under our revolving credit facility to partially fund the Southern Oklahoma acquisition; | |
• | $88.0 million under a bridge loan to partially fund the Southern Oklahoma acquisition, which was extinguished with borrowings under our revolving credit facility; | |
• | $246.0 million from our revolving credit facility to finance the acquisition of our interests in East Texas and Discovery; | |
• | $100.0 million from our term loan facility and $35.0 million from our revolving credit facility to finance the MEG acquisition and for general corporate purposes; and | |
• | $10.0 million from our revolving credit facility for general corporate purposes, which was subsequently repaid. |
• | maintenance capital expenditures, which are cash expenditures where we add on to or improve capital assets owned or acquire or construct new capital assets if such expenditures are made to maintain, including over the long term, our operating capacity or revenues; and | |
• | expansion capital expenditures, which are cash expenditures for acquisitions or capital improvements (where we add on to or improve the capital assets owned, or acquire or construct new gathering lines, treating facilities, processing plants, fractionation facilities, pipelines, terminals, docks, truck racks, |
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tankage and other storage, distribution or transportation facilities and related or similar midstream assets) in each case if such addition, improvement, acquisition or construction is made to increase our operating capacity or revenues. |
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Payments Due by Period | ||||||||||||||||||||
2014 and | ||||||||||||||||||||
Total | 2009 | 2010-2011 | 2012-2013 | Thereafter | ||||||||||||||||
(Millions) | ||||||||||||||||||||
Long-term debt(a) | $ | 733.4 | $ | 26.6 | $ | 42.4 | $ | 664.4 | $ | — | ||||||||||
Operating lease obligations | 44.7 | 12.4 | 16.9 | 12.8 | 2.6 | |||||||||||||||
Purchase obligations(b) | 632.8 | 140.8 | 201.9 | 188.2 | 101.9 | |||||||||||||||
Other long-term liabilities(c) | 8.5 | — | 0.4 | 0.1 | 8.0 | |||||||||||||||
Total | $ | 1,419.4 | $ | 179.8 | $ | 261.6 | $ | 865.5 | $ | 112.5 | ||||||||||
(a) | Includes interest payments on long-term debt that has been hedged, because the interest rate is determinable. Interest payments on long-term debt, which has not been hedged, are not included as they are based on floating interest rates and we cannot determine with accuracy the periodic repayment dates or the amounts of the interest payments. | |
(b) | Purchase obligations include $3.3 million of purchase orders for capital expenditures and $629.5 million of various non-cancelable commitments to purchase physical quantities of commodities in future periods. For contracts where the price paid is based on an index, the amount is based on the forward market prices at December 31, 2008. Purchase obligations exclude accounts payable, accrued interest payable and other current liabilities recognized in the consolidated balance sheets. Purchase obligations also exclude current and long-term unrealized losses on derivative instruments included in the consolidated balance sheet, which represent the current fair value of various derivative contracts and do not represent future cash purchase obligations. These contracts may be settled financially at the difference between the future market price and the contractual price and may result in cash payments or cash receipts in the future, but generally do not require delivery of physical quantities of the underlying commodity. In addition, many of our gas purchase contracts include short and long term commitments to purchase produced gas at market prices. These contracts, which have no minimum quantities, are excluded from the table. | |
(c) | Other long-term liabilities include $7.9 million of asset retirement obligations and $0.6 million of environmental reserves, recognized on the consolidated balance sheet. |
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• | defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date; | |
• | establishes a framework for measuring fair value; | |
• | establishes a three-level hierarchy for fair value measurements based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date; | |
• | nullifies the guidance in Emerging Issues Task Force, or EITF,02-3,Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Involved in Energy Trading and Risk Management Activities, which required the deferral of profit at inception of a transaction involving a derivative financial instrument in the absence of observable data supporting the valuation technique; and | |
• | significantly expands the disclosure requirements around instruments measured at fair value. |
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Item 7A. | Quantitative and Qualitative Disclosures about Market Risk |
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Swap | ||||||||
Period | Commodity | Notional Volume | Reference Price | Price Range | ||||
January 2009 — December 2009 | Natural Gas | 2,000 MMBtu/d | Texas Gas Transmission Price(a) | $9.20/MMBtu | ||||
January 2010 — December 2010 | Natural Gas | 1,900 MMBtu/d | Texas Gas Transmission Price(a) | $9.20/MMBtu | ||||
January 2009 — December 2013 | Natural Gas | 1,500 MMBtu/d | NYMEX Final Settlement Price(b) | $8.22/MMBtu | ||||
January 2009 — December 2013 | Natural Gas Basis | 1,500 MMBtu/d | IFERC Monthly Index Price for | NYMEX less | ||||
Panhandle Eastern Pipe Line(c) | $0.68/MMBtu | |||||||
January 2009 — December 2009 | Crude Oil | 2,450 Bbls/d | Asian-pricing of NYMEX crude oil futures(d) | $63.05 - $86.95/Bbl | ||||
January 2010 — December 2010 | Crude Oil | 2,415 Bbls/d | Asian-pricing of NYMEX crude oil futures(d) | $63.05 - $87.25/Bbl | ||||
January 2011 — December 2011 | Crude Oil | 2,350 Bbls/d | Asian-pricing of NYMEX crude oil futures(d) | $66.72 - $87.25/Bbl | ||||
January 2012 — December 2012 | Crude Oil | 2,325 Bbls/d | Asian-pricing of NYMEX crude oil futures(d) | $66.72 - $90.00/Bbl | ||||
January 2013 — December 2013 | Crude Oil | 1,250 Bbls/d | Asian-pricing of NYMEX crude oil futures(d) | $67.60 - $71.20/Bbl | ||||
March 2009 — December 2010(f) | Natural Gas | 1,634 MMBtu/d | IFERC Monthly Index Price for Colorado Interstate Gas Pipeline(e) | $3.94/MMBtu | ||||
April 2010 — December 2011(f) | Crude Oil | 250 Bbls/d | Asian-pricing of NYMBEX crude oil futures(d) | $56.75 - $59.30/Bbl |
(a) | The Inside FERC index price for natural gas delivered into the Texas Gas Transmission pipeline in the North Louisiana area. | |
(b) | NYMEX final settlement price for natural gas futures contracts (NG). | |
(c) | The Inside FERC monthly published index price for Panhandle Eastern Pipe Line (Texas, Oklahoma — mainline) less the NYMEX final settlement price for natural gas futures contracts. | |
(d) | Monthly average of the daily close prices for the prompt month NYMEX light, sweet crude oil futures contract (CL). | |
(e) | The Inside FERC index price for natural gas delivered into the Colorado Interstate Gas (CIG) pipeline. | |
(f) | These trades were entered into subsequent to December 31, 2008. |
Estimated | ||||||||||||
Decrease in | ||||||||||||
Annual Net | ||||||||||||
Per Unit Decrease | Unit of Measurement | Income | ||||||||||
(Millions) | ||||||||||||
Natural gas prices | $ | 1.00 | MMBtu | $ | 0.3 | |||||||
Crude oil prices(a) | $ | 5.00 | Barrel | $ | 1.7 | |||||||
NGL to crude oil price relationship(b) | 5 percentage point change | Barrel | $ | 4.6 |
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(a) | Assuming 60% NGL to crude oil price relationship. | |
(b) | Assuming 60% NGL to crude oil price relationship and $60.00/Bbl crude oil price. Generally, this sensitivity changes by $1.5 million for each $20.00/Bbl change in the price of crude oil. As crude oil prices increase from $60.00/Bbl, we become slightly more sensitive to the change in the relationship of NGL prices to crude oil prices. As crude oil prices decrease from $60.00/Bbl, we become less sensitive to the change in the relationship of NGL prices to crude oil prices. |
Estimated | ||||||||||||
Mark-to-Market | ||||||||||||
Impact | ||||||||||||
(Decrease in | ||||||||||||
Per Unit Increase | Unit of Measurement | Net Income) | ||||||||||
(Millions) | ||||||||||||
Natural gas prices | $ | 1.00 | MMBtu | $ | 4.9 | |||||||
Crude oil prices | $ | 5.00 | Barrel | $ | 18.8 |
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Fair Value of Contracts as of December 31, 2008 | ||||||||||||||||||||
Maturity in | ||||||||||||||||||||
Maturity in | Maturity in | Maturity in | 2014 and | |||||||||||||||||
Sources of Fair Value | Total | 2009 | 2010-2011 | 2012-2013 | Thereafter | |||||||||||||||
(Millions) | ||||||||||||||||||||
Prices supported by quoted market prices and other external sources | $ | (21.7 | ) | $ | (2.6 | ) | $ | (15.1 | ) | $ | (4.0 | ) | $ | — | ||||||
Prices based on models or other valuation techniques | 2.0 | 0.3 | 1.7 | — | — | |||||||||||||||
Total | $ | (19.7 | ) | $ | (2.3 | ) | $ | (13.4 | ) | $ | (4.0 | ) | $ | — | ||||||
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Item 8. | Financial Statements and Supplementary Data |
DCP MIDSTREAM PARTNERS, LP CONSOLIDATED FINANCIAL STATEMENTS: | ||||
101 | ||||
102 | ||||
103 | ||||
104 | ||||
105 | ||||
106 | ||||
107 |
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DCP Midstream Partners GP, LLC
Denver, Colorado:
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December 31, | ||||||||
2008 | 2007 | |||||||
(Millions) | ||||||||
ASSETS | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 48.0 | $ | 24.5 | ||||
Short-term investments | — | 1.3 | ||||||
Accounts receivable: | ||||||||
Trade, net of allowance for doubtful accounts of $0.6 million and $1.2 million, respectively | 43.6 | 81.7 | ||||||
Affiliates | 36.8 | 52.1 | ||||||
Inventories | 20.9 | 37.3 | ||||||
Unrealized gains on derivative instruments | 15.4 | 3.1 | ||||||
Other | 0.5 | 18.5 | ||||||
Total current assets | 165.2 | 218.5 | ||||||
Restricted investments | 60.2 | 100.5 | ||||||
Property, plant and equipment, net | 629.3 | 500.7 | ||||||
Goodwill | 88.8 | 80.2 | ||||||
Intangible assets, net | 47.7 | 29.7 | ||||||
Equity method investments | 175.4 | 187.2 | ||||||
Unrealized gains on derivative instruments | 8.6 | 2.7 | ||||||
Other long-term assets | 4.8 | 1.2 | ||||||
Total assets | $ | 1,180.0 | $ | 1,120.7 | ||||
LIABILITIES AND PARTNERS’ EQUITY | ||||||||
Current liabilities: | ||||||||
Accounts payable: | ||||||||
Trade | $ | 44.8 | $ | 110.2 | ||||
Affiliates | 33.6 | 55.6 | ||||||
Unrealized losses on derivative instruments | 17.7 | 30.9 | ||||||
Accrued interest payable | 1.3 | 1.6 | ||||||
Other | 27.4 | 21.3 | ||||||
Total current liabilities | 124.8 | 219.6 | ||||||
Long-term debt | 656.5 | 630.0 | ||||||
Unrealized losses on derivative instruments | 26.0 | 70.0 | ||||||
Other long-term liabilities | 8.9 | 5.8 | ||||||
Total liabilities | 816.2 | 925.4 | ||||||
Non-controlling interests | 34.7 | 26.9 | ||||||
Commitments and contingent liabilities | ||||||||
Partners’ equity: | ||||||||
Common unitholders (24,661,754 and 16,840,326 units issued and outstanding, respectively) | 429.0 | 308.8 | ||||||
Subordinated unitholders (3,571,429 and 7,142,857 convertible units issued and outstanding, respectively) | (54.6 | ) | (120.1 | ) | ||||
General partner interest | (4.8 | ) | (5.4 | ) | ||||
Accumulated other comprehensive loss | (40.5 | ) | (14.9 | ) | ||||
Total partners’ equity | 329.1 | 168.4 | ||||||
Total liabilities and partners’ equity | $ | 1,180.0 | $ | 1,120.7 | ||||
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Year Ended December 31, | ||||||||||||
2008 | 2007 | 2006 | ||||||||||
(Millions, except per unit amounts) | ||||||||||||
Operating revenues: | ||||||||||||
Sales of natural gas, propane, NGLs and condensate | $ | 678.5 | $ | 628.1 | $ | 535.1 | ||||||
Sales of natural gas, propane, NGLs and condensate to affiliates | 477.8 | 297.7 | 232.8 | |||||||||
Transportation, processing and other | 31.2 | 18.5 | 15.0 | |||||||||
Transportation, processing and other to affiliates | 26.0 | 16.6 | 12.8 | |||||||||
Gains (losses) from commodity derivative activity, net | 75.4 | (83.1 | ) | — | ||||||||
(Losses) gains from commodity derivative activity, net — affiliates | (3.1 | ) | (4.5 | ) | 0.1 | |||||||
Total operating revenues | 1,285.8 | 873.3 | 795.8 | |||||||||
Operating costs and expenses: | ||||||||||||
Purchases of natural gas, propane and NGLs | 798.3 | 647.4 | 581.2 | |||||||||
Purchases of natural gas, propane and NGLs from affiliates | 262.9 | 179.3 | 119.2 | |||||||||
Operating and maintenance expense | 43.0 | 32.1 | 23.7 | |||||||||
Depreciation and amortization expense | 36.5 | 24.4 | 12.8 | |||||||||
General and administrative expense | 12.4 | 14.1 | 12.9 | |||||||||
General and administrative expense — affiliates | 11.6 | 10.0 | 8.1 | |||||||||
Other | (1.5 | ) | — | — | ||||||||
Total operating costs and expenses | 1,163.2 | 907.3 | 757.9 | |||||||||
Operating income (loss) | 122.6 | (34.0 | ) | 37.9 | ||||||||
Interest income | 5.6 | 5.3 | 6.3 | |||||||||
Interest expense | (32.8 | ) | (25.8 | ) | (11.5 | ) | ||||||
Earnings from equity method investments | 34.3 | 39.3 | 29.2 | |||||||||
Non-controlling interest in income | (3.9 | ) | (0.5 | ) | — | |||||||
Income (loss) before income taxes | 125.8 | (15.7 | ) | 61.9 | ||||||||
Income tax expense | (0.1 | ) | (0.1 | ) | — | |||||||
Net income (loss) | $ | 125.7 | $ | (15.8 | ) | $ | 61.9 | |||||
Less: | ||||||||||||
Net income attributable to predecessor operations | — | (3.6 | ) | (26.6 | ) | |||||||
General partner interest in net income | (11.9 | ) | (2.2 | ) | (0.7 | ) | ||||||
Net income (loss) allocable to limited partners | $ | 113.8 | $ | (21.6 | ) | $ | 34.6 | |||||
Net income (loss) per limited partner unit — basic and diluted | $ | 3.25 | $ | (1.05 | ) | $ | 1.90 | |||||
Weighted-average limited partner units outstanding — basic and diluted | 27.4 | 20.5 | 17.5 |
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Year Ended December 31, | ||||||||||||
2008 | 2007 | 2006 | ||||||||||
(Millions) | ||||||||||||
Net income (loss) | $ | 125.7 | $ | (15.8 | ) | $ | 61.9 | |||||
Other comprehensive income (loss): | ||||||||||||
Reclassification of cash flow hedges into earnings | 7.5 | (3.1 | ) | (2.7 | ) | |||||||
Net unrealized (losses) gains on cash flow hedges | (33.1 | ) | (19.1 | ) | 9.6 | |||||||
Total other comprehensive (loss) income | (25.6 | ) | (22.2 | ) | 6.9 | |||||||
Total comprehensive income (loss) | $ | 100.1 | $ | (38.0 | ) | $ | 68.8 | |||||
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Accumulated | ||||||||||||||||||||||||||||
General | Other | Total | ||||||||||||||||||||||||||
Predecessor | Common | Class C | Subordinated | Partner | Comprehensive | Partners’ | ||||||||||||||||||||||
Equity | Unitholders | Unitholders | Unitholders | Interest | Income (Loss) | Equity | ||||||||||||||||||||||
(Millions) | ||||||||||||||||||||||||||||
Balance, January 1, 2006 | $ | 219.8 | $ | 215.8 | $ | — | $ | (109.7 | ) | $ | (5.6 | ) | $ | 0.4 | $ | 320.7 | ||||||||||||
Net change in parent advances | (25.4 | ) | — | — | — | — | — | (25.4 | ) | |||||||||||||||||||
Acquisition of wholesale propane logistics business | (56.7 | ) | — | — | — | — | — | (56.7 | ) | |||||||||||||||||||
Excess purchase price over acquired assets | — | — | (26.3 | ) | — | — | — | (26.3 | ) | |||||||||||||||||||
Issuance of 200,312 Class C units | — | — | 5.6 | — | — | — | 5.6 | |||||||||||||||||||||
Proceeds from general partner interest (represented by 4,088 equivalent units) | — | — | — | — | 0.1 | — | 0.1 | |||||||||||||||||||||
Contributions by unitholders | — | — | — | 2.8 | 0.2 | — | 3.0 | |||||||||||||||||||||
Distributions to unitholders | — | (12.8 | ) | (0.1 | ) | (8.8 | ) | (0.4 | ) | — | (22.1 | ) | ||||||||||||||||
Net income attributable to predecessor operations | 26.6 | — | — | — | — | — | 26.6 | |||||||||||||||||||||
Net income | — | 20.4 | 0.1 | 14.1 | 0.7 | — | 35.3 | |||||||||||||||||||||
Other comprehensive income | — | — | — | — | — | 6.9 | 6.9 | |||||||||||||||||||||
Balance, December 31, 2006 | 164.3 | 223.4 | (20.7 | ) | (101.6 | ) | (5.0 | ) | 7.3 | 267.7 | ||||||||||||||||||
Net change in parent advances | (14.6 | ) | — | — | — | — | — | (14.6 | ) | |||||||||||||||||||
Acquisition of East Texas, Discovery and the Swap | (153.3 | ) | 27.0 | — | — | 0.6 | — | (125.7 | ) | |||||||||||||||||||
Excess purchase price over acquired assets | — | (118.0 | ) | — | — | — | — | (118.0 | ) | |||||||||||||||||||
Acquisition of Momentum Energy Group, Inc. | — | 12.0 | — | — | — | — | 12.0 | |||||||||||||||||||||
Purchase of units | — | (0.3 | ) | — | — | — | — | (0.3 | ) | |||||||||||||||||||
Issuance of units | — | 0.3 | — | — | — | — | 0.3 | |||||||||||||||||||||
Issuance of 5,386,732 common units | — | 228.5 | — | — | — | — | 228.5 | |||||||||||||||||||||
Conversion of Class C units to common units | — | (20.7 | ) | 20.7 | — | — | — | — | ||||||||||||||||||||
Contributions by unitholders | — | 0.2 | — | 0.6 | — | — | 0.8 | |||||||||||||||||||||
Distributions to unitholders | — | (27.0 | ) | (0.2 | ) | (14.1 | ) | (3.2 | ) | — | (44.5 | ) | ||||||||||||||||
Equity-based compensation | — | 0.2 | — | — | — | — | 0.2 | |||||||||||||||||||||
Net income attributable to predecessor operations | 3.6 | — | — | — | — | — | 3.6 | |||||||||||||||||||||
Net income (loss) | — | (16.8 | ) | 0.2 | (5.0 | ) | 2.2 | — | (19.4 | ) | ||||||||||||||||||
Other comprehensive loss | — | — | — | — | — | (22.2 | ) | (22.2 | ) | |||||||||||||||||||
Balance, December 31, 2007 | — | 308.8 | — | (120.1 | ) | (5.4 | ) | (14.9 | ) | 168.4 | ||||||||||||||||||
Issuance of 4,250,000 common units | — | 132.1 | — | — | — | — | 132.1 | |||||||||||||||||||||
Conversion of subordinated units to common units | (66.4 | ) | — | 66.4 | — | — | — | |||||||||||||||||||||
Contributions by unitholders | — | 4.0 | — | — | — | — | 4.0 | |||||||||||||||||||||
Distributions to unitholders and general partner | — | (53.9 | ) | — | (10.5 | ) | (11.3 | ) | — | (75.7 | ) | |||||||||||||||||
Equity-based compensation | — | 0.2 | — | — | — | — | 0.2 | |||||||||||||||||||||
Net income | — | 104.2 | — | 9.6 | 11.9 | — | 125.7 | |||||||||||||||||||||
Other comprehensive loss | — | — | — | — | — | (25.6 | ) | (25.6 | ) | |||||||||||||||||||
Balance, December 31, 2008 | $ | — | $ | 429.0 | $ | — | $ | (54.6 | ) | $ | (4.8 | ) | $ | (40.5 | ) | $ | 329.1 | |||||||||||
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Year Ended December 31, | ||||||||||||
2008 | 2007 | 2006 | ||||||||||
(Millions) | ||||||||||||
OPERATING ACTIVITIES: | ||||||||||||
Net income (loss) | $ | 125.7 | $ | (15.8 | ) | $ | 61.9 | |||||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||||||||||||
Depreciation and amortization expense | 36.5 | 24.4 | 12.8 | |||||||||
Earnings from equity method investments, net of distributions | 25.6 | (0.4 | ) | (3.3 | ) | |||||||
Non-controlling interest in income | 3.9 | 0.5 | — | |||||||||
Other, net | (0.4 | ) | (0.2 | ) | (2.4 | ) | ||||||
Change in operating assets and liabilities which provided (used) cash, net of effects of acquisitions: | ||||||||||||
Accounts receivable | 55.4 | (42.2 | ) | 43.1 | ||||||||
Inventories | 16.4 | (7.2 | ) | 11.6 | ||||||||
Net unrealized (gains) losses on derivative instruments | (101.0 | ) | 81.1 | (0.1 | ) | |||||||
Accounts payable | (79.7 | ) | 38.9 | (31.5 | ) | |||||||
Accrued interest | (0.3 | ) | 0.5 | 0.3 | ||||||||
Other current assets and liabilities | 19.8 | (16.4 | ) | 2.0 | ||||||||
Other long-term assets and liabilities | (0.4 | ) | 2.2 | 0.4 | ||||||||
Net cash provided by operating activities | 101.5 | 65.4 | 94.8 | |||||||||
INVESTING ACTIVITIES: | ||||||||||||
Capital expenditures | (41.0 | ) | (21.3 | ) | (27.2 | ) | ||||||
Acquisition of Michigan Pipeline & Processing, LLC, net of cash acquired | (146.4 | ) | — | — | ||||||||
Acquisition of subsidiaries of Momentum Energy Group, Inc., net of cash acquired | (10.9 | ) | (142.0 | ) | — | |||||||
Acquisition of assets | — | (191.3 | ) | — | ||||||||
Acquisition of equity method investments | — | (153.3 | ) | — | ||||||||
Investments in equity method investments | (13.8 | ) | (16.3 | ) | (11.1 | ) | ||||||
Payment of earnest deposit | — | (9.0 | ) | — | ||||||||
Refund of earnest deposit | — | 9.0 | — | |||||||||
Acquisition of wholesale propane logistics business | — | — | (56.7 | ) | ||||||||
Proceeds from sales of assets | 2.9 | 0.1 | 0.3 | |||||||||
Purchases of available-for-sale securities | (608.2 | ) | (6,921.6 | ) | (7,372.4 | ) | ||||||
Proceeds from sales of available-for-sale securities | 650.5 | 6,924.0 | 7,373.3 | |||||||||
Net cash used in investing activities | (166.9 | ) | (521.7 | ) | (93.8 | ) | ||||||
FINANCING ACTIVITIES: | ||||||||||||
Proceeds from debt | 660.4 | 579.0 | 78.0 | |||||||||
Payments of debt | (633.9 | ) | (217.0 | ) | (20.1 | ) | ||||||
Payment of deferred financing costs | — | (0.6 | ) | (0.2 | ) | |||||||
Purchase of units | — | (0.3 | ) | — | ||||||||
Proceeds from issuance of common units, net of offering costs | 132.1 | 228.5 | — | |||||||||
Proceeds from issuance of equivalent units to general partner | — | — | 0.1 | |||||||||
Excess purchase price over acquired assets | — | (100.3 | ) | (10.7 | ) | |||||||
Net change in advances from DCP Midstream, LLC | — | (14.6 | ) | (25.4 | ) | |||||||
Distributions to unitholders and general partner | (76.2 | ) | (44.0 | ) | (22.1 | ) | ||||||
Distributions to non-controlling interests | (3.3 | ) | — | — | ||||||||
Contributions from non-controlling interests | 5.7 | 3.4 | — | |||||||||
Contributions from DCP Midstream, LLC | 4.1 | 0.5 | 3.4 | |||||||||
Net cash provided by financing activities | 88.9 | 434.6 | 3.0 | |||||||||
Net change in cash and cash equivalents | 23.5 | (21.7 | ) | 4.0 | ||||||||
Cash and cash equivalents, beginning of period | 24.5 | 46.2 | 42.2 | |||||||||
Cash and cash equivalents, end of period | $ | 48.0 | $ | 24.5 | $ | 46.2 | ||||||
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1. | Description of Business and Basis of Presentation |
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2. | Summary of Significant Accounting Policies |
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• | significant adverse change in legal factors or business climate; | |
• | a current-period operating or cash flow loss combined with a history of operating or cash flow losses, or a projection or forecast that demonstrates continuing losses associated with the use of a long-lived asset; | |
• | an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of a long-lived asset; | |
• | significant adverse changes in the extent or manner in which an asset is used, or in its physical condition; | |
• | a significant adverse change in the market value of an asset; or | |
• | a current expectation that, more likely than not, an asset will be sold or otherwise disposed of before the end of its estimated useful life. |
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Classification of Contract | Accounting Method | Presentation of Gains & Losses or Revenue & Expense | ||
Non-Trading Derivative Activity | Mark-to-market method(b) | Net basis in gains and losses from derivative activity | ||
Cash Flow Hedge(a) | Hedge method(c) | Gross basis in the same consolidated statements of operations category as the related hedged item | ||
Fair Value Hedge(a) | Hedge method(c) | Gross basis in the same consolidated statements of operations category as the related hedged item | ||
Normal Purchases or Normal Sales | Accrual method(d) | Gross basis upon settlement in the corresponding consolidated statements of operations category based on purchase or sale |
(a) | Effective July 1, 2007, all commodity cash flow hedges are classified as non-trading derivative activity. Our interest rate swaps continue to be accounted for as cash flow hedges. As of December 31, 2007 we no longer use fair value hedges. | |
(b) | Mark-to-market — An accounting method whereby the change in the fair value of the asset or liability is recognized in the consolidated statements of operations in gains and losses from derivative activity during the current period. | |
(c) | Hedge method — An accounting method whereby the change in the fair value of the asset or liability is recorded in the consolidated balance sheets as unrealized gains or unrealized losses on derivative instruments. For cash flow hedges, there is no recognition in the consolidated statements of operations for the |
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effective portion until the service is provided or the associated delivery period impacts earnings. For fair value hedges, the change in the fair value of the asset or liability, as well as the offsetting changes in value of the hedged item, are recognized in the consolidated statements of operations in the same category as the related hedged item. | ||
(d) | Accrual method — An accounting method whereby there is no recognition in the consolidated balance sheets or consolidated statements of operations for changes in fair value of a contract until the service is provided or the associated delivery period impacts earnings. |
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• | Fee-based arrangements —Under fee-based arrangements, we receive a fee or fees for one or more of the following services: gathering, compressing, treating, processing or transporting natural gas; and transporting NGLs. Our fee-based arrangements include natural gas purchase arrangements pursuant to which we purchase natural gas at the wellhead or other receipt points, at an index related price at the delivery point less a specified amount, generally the same as the transportation fees we would otherwise charge for transportation of natural gas from the wellhead location to the delivery point. The revenues we earn are directly related to the volume of natural gas or NGLs that flows through our systems and are not directly dependent on commodity prices. However, to the extent a sustained decline in commodity prices results in a decline in volumes, our revenues from these arrangements would be reduced. | |
• | Percent-of-proceeds arrangements— Under percent-of-proceeds arrangements, we generally purchase natural gas from producers at the wellhead, or other receipt points, gather the wellhead natural gas through our gathering system, treat and process the natural gas, and then sell the resulting residue natural gas and NGLs based on index prices from published index market prices. We remit to the producers either anagreed-upon percentage of the actual proceeds that we receive from our sales of the residue natural gas and NGLs, or anagreed-upon percentage of the proceeds based on index related prices for the natural gas and the NGLs, regardless of the actual amount of the sales proceeds we receive. Certain of these arrangements may also result in our returning all or a portion of the residue natural gasand/or the NGLs to the producer, in lieu of returning sales proceeds. Our revenues under percent-of-proceeds arrangements correlate directly with the price of natural gasand/or NGLs. | |
• | Propane sales arrangements— Under propane sales arrangements, we generally purchase propane from natural gas processing plants and fractionation facilities, and crude oil refineries. We sell propane on a wholesale basis to retail propane distributors, who in turn resell to their retail customers. Our sales of propane are not contingent upon the resale of propane by propane distributors to their retail customers. |
• | Persuasive evidence of an arrangement exists— Our customary practice is to enter into a written contract, executed by both us and the customer. | |
• | Delivery— Delivery is deemed to have occurred at the time custody is transferred, or in the case of fee-based arrangements, when the services are rendered. To the extent we retain product as inventory, delivery occurs when the inventory is subsequently sold and custody is transferred to the third party purchaser. | |
• | The fee is fixed or determinable— We negotiate the fee for our services at the outset of our fee-based arrangements. In these arrangements, the fees are nonrefundable. For other arrangements, the amount of revenue, based on contractual terms, is determinable when the sale of the applicable product has been completed upon delivery and transfer of custody. | |
• | Collectibility is probable— Collectibility is evaluated on acustomer-by-customer basis. New and existing customers are subject to a credit review process, which evaluates the customers’ financial position (for example, credit metrics, liquidity and credit rating) and their ability to pay. If collectibility is not considered probable at the outset of an arrangement in accordance with our credit review process, revenue is not recognized until the cash is collected. |
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3. | Recent Accounting Pronouncements |
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• | defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date; | |
• | establishes a framework for measuring fair value; | |
• | establishes a three-level hierarchy for fair value measurements based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date; | |
• | nullifies the guidance in Emerging Issues Task Force, or EITF,02-3,Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Involved in Energy Trading and Risk Management Activities, which required the deferral of profit at inception of a transaction involving a derivative financial instrument in the absence of observable data supporting the valuation technique; and | |
• | significantly expands the disclosure requirements around instruments measured at fair value. |
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4. | Acquisitions |
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(Millions) | ||||
Cash | $ | 1.7 | ||
Accounts receivable | 2.1 | |||
Other assets | 0.1 | |||
Other long term assets | 3.8 | |||
Property, plant and equipment | 116.1 | |||
Goodwill | 6.7 | |||
Intangible assets | 20.0 | |||
Other liabilities | (0.5 | ) | ||
Non-controlling interest in joint venture | (1.6 | ) | ||
Total purchase price allocation | $ | 148.4 | ||
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(Millions) | ||||
Cash consideration | $ | 153.8 | ||
Payable to DCP Midstream, LLC | 10.9 | |||
Common limited partner units | 12.0 | |||
Aggregate consideration | $ | 176.7 | ||
The purchase price allocation is as follows: | ||||
Cash | $ | 11.8 | ||
Accounts receivable | 14.1 | |||
Other assets | 1.5 | |||
Property, plant and equipment | 127.8 | |||
Goodwill | 52.8 | |||
Intangible assets | 15.5 | |||
Accounts payable | (11.1 | ) | ||
Other liabilities | (12.9 | ) | ||
Non-controlling interest in joint venture | (22.8 | ) | ||
Total purchase price allocation | $ | 176.7 | ||
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2008 | 2007 | |||||||||||||||||||||||
DCP | DCP | |||||||||||||||||||||||
DCP | Midstream | DCP | Midstream | |||||||||||||||||||||
Midstream | Acquisition | Partners, LP | Midstream | Acquisition | Partners, LP | |||||||||||||||||||
Partners, LP | of MPP | Pro Forma | Partners, LP | of MPP | Pro Forma | |||||||||||||||||||
(Millions, except per unit amounts) | ||||||||||||||||||||||||
Total operating revenues | $ | 1,285.8 | $ | 14.8 | $ | 1,300.6 | $ | 873.3 | $ | 20.9 | $ | 894.2 | ||||||||||||
Net income (loss) | $ | 125.7 | $ | 2.2 | $ | 127.9 | $ | (15.8 | ) | $ | 1.2 | $ | (14.6 | ) | ||||||||||
Less: | ||||||||||||||||||||||||
Net income attributable to predecessor operations | — | — | — | (3.6 | ) | — | (3.6 | ) | ||||||||||||||||
General partner interest in net income | (11.9 | ) | — | (11.9 | ) | (2.2 | ) | (0.1 | ) | (2.3 | ) | |||||||||||||
Net income (loss) allocable to limited partners | $ | 113.8 | $ | 2.2 | $ | 116.0 | $ | (21.6 | ) | $ | 1.1 | $ | (20.5 | ) | ||||||||||
Net income (loss) per limited partner unit — basic and diluted | $ | 3.25 | $ | 0.04 | $ | 3.29 | $ | (1.05 | ) | $ | 0.05 | $ | (1.00 | ) |
5. | Agreements and Transactions with Affiliates |
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• | DCP Midstream, LLC’s obligation to indemnify us for certain liabilities and our obligation to indemnify DCP Midstream, LLC for certain liabilities; | |
• | DCP Midstream, LLC’s obligation to continue to maintain its credit support, including without limitation guarantees and letters of credit, for our obligations related to derivative financial instruments, such as commodity price hedging contracts, to the extent that such credit support arrangements were in effect as of the closing of our initial public offering in December 2005, until the earlier to occur of the fifth anniversary of the closing of our initial public offering or such time as we obtain an investment grade credit rating from either Moody’s Investor Services, Inc. or Standard & Poor’s Ratings Group with respect to any of our unsecured indebtedness; and | |
• | DCP Midstream, LLC’s obligation to continue to maintain its credit support, including without limitation guarantees and letters of credit, for our obligations related to commercial contracts with respect to its business or operations that were in effect at the closing of our initial public offering until the expiration of such contracts. |
Year Ended December 31, | ||||||||||||||
Terms | Effective Date | 2008 | 2007 | 2006 | ||||||||||
(Millions) | ||||||||||||||
Annual fee | 2006 | $ | 5.1 | $ | 5.0 | $ | 4.8 | |||||||
Wholesale propane logistics business | November 2006 | 2.0 | 2.0 | 0.3 | ||||||||||
Southern Oklahoma | May 2007 | 0.2 | 0.1 | — | ||||||||||
Discovery | July 2007 | 0.2 | 0.1 | — | ||||||||||
Additional services | August 2007 | 0.6 | 0.2 | — | ||||||||||
Momentum Energy Group, Inc. | August 2007 | 1.6 | 0.5 | — | ||||||||||
Michigan Pipeline & Processing, LLC | October 2008 | 0.1 | — | — | ||||||||||
Total Omnibus Agreement | 9.8 | 7.9 | 5.1 | |||||||||||
Other fees | 1.8 | 2.1 | 3.0 | |||||||||||
Total | $ | 11.6 | $ | 10.0 | $ | 8.1 | ||||||||
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• | DCP Midstream, LLC will supply Pelico’s system requirements that exceed its on-system supply. Accordingly, DCP Midstream, LLC purchases natural gas and transports it to our Pelico system, where we buy the gas from DCP Midstream, LLC at the actual acquisition cost plus transportation service charges incurred. We generally report purchases associated with these activities gross in the consolidated statements of operations as purchases of natural gas, propane and NGLs from affiliates. | |
• | If our Pelico system has volumes in excess of the on-system demand, DCP Midstream, LLC will purchase the excess natural gas from us and transport it to sales points at an index-based price, less a contractually agreed-to marketing fee. We generally report revenues associated with these activities gross in the consolidated statements of operations as sales of natural gas, propane and NGLs to affiliates. | |
• | In addition, DCP Midstream, LLC may purchase other excess natural gas volumes at certain Pelico outlets for a price that equals the original Pelico purchase price from DCP Midstream, LLC, plus a portion of the index differential between upstream sources to certain downstream indices with a maximum differential and a minimum differential, plus a fixed fuel charge and other related adjustments. We generally report revenues and purchases associated with these activities net in the consolidated statements of operations as transportation, processing and other services to affiliates. |
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Year Ended December 31, | ||||||||||||
2008 | 2007 | 2006 | ||||||||||
(Millions) | ||||||||||||
DCP Midstream, LLC: | ||||||||||||
Sales of natural gas, propane, NGLs and condensate | $ | 475.7 | $ | 290.0 | $ | 231.7 | ||||||
Transportation, processing and other | $ | 15.4 | $ | 6.0 | $ | 4.8 | ||||||
Purchases of natural gas, propane and NGLs | $ | 175.3 | $ | 150.1 | $ | 102.9 | ||||||
(Losses) gains from derivative activity, net | $ | (3.1 | ) | $ | (4.5 | ) | $ | 0.1 | ||||
Operating and maintenance expense | $ | — | $ | 0.4 | $ | 0.2 | ||||||
General and administrative expense | $ | 11.6 | $ | 10.0 | $ | 8.1 | ||||||
Interest expense | $ | 0.4 | $ | — | $ | — | ||||||
Spectra Energy: | ||||||||||||
Sales of natural gas, propane, NGLs and condensate | $ | 0.3 | $ | 1.1 | $ | — | ||||||
Transportation, processing and other | $ | 0.2 | $ | — | $ | — | ||||||
Purchases of natural gas, propane and NGLs | $ | 51.0 | $ | — | $ | — | ||||||
Duke Energy: | ||||||||||||
Purchases of natural gas, propane and NGLs | $ | — | $ | — | $ | 3.4 | ||||||
ConocoPhillips: | ||||||||||||
Sales of natural gas, propane, NGLs and condensate | $ | 1.8 | $ | 6.6 | $ | 1.1 | ||||||
Transportation, processing and other | $ | 10.4 | $ | 10.6 | $ | 8.0 | ||||||
Purchases of natural gas, propane and NGLs | $ | 36.6 | $ | 29.2 | $ | 12.9 |
December 31, | ||||||||
2008 | 2007 | |||||||
(Millions) | ||||||||
DCP Midstream, LLC: | ||||||||
Accounts receivable | $ | 30.3 | $ | 47.3 | ||||
Accounts payable | $ | 27.9 | $ | 53.3 | ||||
Spectra Energy: | ||||||||
Accounts receivable | $ | 4.0 | $ | 1.5 | ||||
Accounts payable | $ | 5.3 | $ | — | ||||
ConocoPhillips: | ||||||||
Accounts receivable | $ | 2.5 | $ | 3.3 | ||||
Accounts payable | $ | 0.4 | $ | 2.3 |
December 31, | ||||||||
2008 | 2007 | |||||||
(Millions) | ||||||||
DCP Midstream, LLC: | ||||||||
Unrealized losses — current | $ | (1.2 | ) | $ | (2.7 | ) |
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6. | Property, Plant and Equipment |
Depreciable | December 31, | |||||||||||
Life | 2008 | 2007 | ||||||||||
(Millions) | ||||||||||||
Gathering systems | 15 — 30 Years | $ | 405.0 | $ | 371.3 | |||||||
Processing plants | 25 — 30 Years | 163.4 | 91.4 | |||||||||
Terminals | 25 — 30 Years | 28.5 | 24.2 | |||||||||
Transportation | 25 — 30 Years | 174.0 | 141.0 | |||||||||
General plant | 3 — 5 Years | 6.0 | 4.0 | |||||||||
Construction work in progress | 43.5 | 25.5 | ||||||||||
Property, plant and equipment | 820.4 | 657.4 | ||||||||||
Accumulated depreciation | (191.1 | ) | (156.7 | ) | ||||||||
Property, plant and equipment, net | $ | 629.3 | $ | 500.7 | ||||||||
Rental Payments | ||||
(Millions) | ||||
2009 | $ | 3.0 | ||
2010 | 2.9 | |||
2011 | 2.9 | |||
2012 | 2.8 | |||
2013 | 2.3 | |||
Thereafter | 20.7 | |||
Total | $ | 34.6 | ||
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7. | Goodwill and Intangible Assets |
December 31, | ||||||||
2008 | 2007 | |||||||
(Millions) | ||||||||
Beginning of period | $ | 80.2 | $ | 29.3 | ||||
Acquisitions | 8.6 | 50.9 | ||||||
End of period | $ | 88.8 | $ | 80.2 | ||||
December 31, | ||||||||
2008 | 2007 | |||||||
(Millions) | ||||||||
Gross carrying amount | $ | 52.5 | $ | 32.4 | ||||
Accumulated amortization | (4.8 | ) | (2.7 | ) | ||||
Intangible assets, net | $ | 47.7 | $ | 29.7 | ||||
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Estimated Future | ||||
Amortization | ||||
(Millions) | ||||
2009 | $ | 2.6 | ||
2010 | 2.6 | |||
2011 | 2.3 | |||
2012 | 2.3 | |||
2013 | 2.3 | |||
Thereafter | 35.6 | |||
Total | $ | 47.7 | ||
8. | Equity Method Investments |
Percentage of | ||||||||||||
Ownership as of | Carrying Value as of | |||||||||||
December 31, | December 31, | |||||||||||
2008 and 2007 | 2008 | 2007 | ||||||||||
(Millions) | ||||||||||||
Discovery Producer Services LLC | 40 | % | $ | 105.0 | $ | 117.9 | ||||||
DCP East Texas Holdings, LLC | 25 | % | 63.9 | 62.9 | ||||||||
Black Lake Pipe Line Company | 45 | % | 6.3 | 6.2 | ||||||||
Other | 50 | % | 0.2 | 0.2 | ||||||||
Total equity method investments | $ | 175.4 | $ | 187.2 | ||||||||
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Year Ended December 31, | ||||||||||||
2008 | 2007 | 2006 | ||||||||||
(Millions) | ||||||||||||
Discovery Producer Services LLC | $ | 17.4 | $ | 24.1 | $ | 16.9 | ||||||
DCP East Texas Holdings, LLC | 16.1 | 14.6 | 12.0 | |||||||||
Black Lake Pipe Line Company and other | 0.8 | 0.6 | 0.3 | |||||||||
Total earnings from equity method investments | $ | 34.3 | $ | 39.3 | $ | 29.2 | ||||||
Distributions from equity method investments | $ | 59.9 | $ | 38.9 | $ | 25.9 | ||||||
Earnings from equity method investments, net of distributions | $ | (25.6 | ) | $ | 0.4 | $ | 3.3 | |||||
Year Ended December 31, | ||||||||||||
2008 | 2007 | 2006 | ||||||||||
(Millions) | ||||||||||||
Statements of operations: | ||||||||||||
Operating revenue | $ | 792.7 | $ | 739.6 | $ | 686.9 | ||||||
Operating expenses | $ | (696.9 | ) | $ | 634.6 | $ | 612.2 | |||||
Net income | $ | 99.8 | $ | 106.8 | $ | 77.4 |
December 31, | ||||||||
2008 | 2007 | |||||||
(Millions) | ||||||||
Balance sheet: | ||||||||
Current assets | $ | 104.3 | $ | 168.8 | ||||
Long-term assets | 646.3 | 630.3 | ||||||
Current liabilities | (84.4 | ) | (100.9 | ) | ||||
Long-term liabilities | (22.4 | ) | (14.9 | ) | ||||
Net assets | $ | 643.8 | $ | 683.3 | ||||
9. | Fair Value Measurement |
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• | Counterparty credit valuation adjustments are necessary when the market price of an instrument is not indicative of the fair value as a result of the credit quality of the counterparty. Generally, market quotes assume that all counterparties have near zero, or low, default rates and have equal credit quality. Therefore, an adjustment may be necessary to reflect the credit quality of a specific counterparty to determine the fair value of the instrument. We record counterparty credit valuation adjustments on all derivatives that are in a net asset position as of the measurement date in accordance with our established counterparty credit policy, which takes into account any collateral margin that a counterparty may have posted with us. | |
• | Entity valuation adjustments are necessary to reflect the effect of our own credit quality on the fair value of our net liability position with each counterparty. This adjustment takes into account any credit enhancements, such as collateral margin we may have posted with a counterparty, as well as any letters of credit that we have provided. The methodology to determine this adjustment is consistent with how we evaluate counterparty credit risk, taking into account our own credit rating, current credit spreads, as well as any change in such spreads since the last measurement date. | |
• | Liquidity valuation adjustments are necessary when we are not able to observe a recent market price for financial instruments that trade in less active markets for the fair value to reflect the cost of exiting the position. Exchange traded contracts are valued at market value without making any additional valuation adjustments and, therefore, no liquidity reserve is applied. For contracts other than exchange traded instruments, we mark our positions to the midpoint of the bid/ask spread, and record a liquidity reserve based upon our total net position. We believe that such practice results in the most reliable fair value measurement as viewed by a market participant. |
• | Level 1 — inputs are unadjusted quoted prices foridenticalassets or liabilities in active markets. |
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• | Level 2 — inputs include quoted prices forsimilarassets 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. |
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Internal Models | Internal Models | |||||||||||||||
Quoted Market | with Significant | with Significant | ||||||||||||||
Prices in | Observable | Unobservable | ||||||||||||||
Active Markets | Market Inputs | Market Inputs | Total Carrying | |||||||||||||
(Level 1) | (Level 2) | (Level 3) | Value | |||||||||||||
(Millions) | ||||||||||||||||
Current assets: | ||||||||||||||||
Commodity derivative instruments(a) | $ | — | $ | 15.1 | $ | 0.3 | $ | 15.4 | ||||||||
Long-term assets: | ||||||||||||||||
Restricted investments | $ | — | $ | 60.2 | $ | — | $ | 60.2 | ||||||||
Commodity derivative instruments(b) | $ | — | $ | 6.9 | $ | 1.7 | $ | 8.6 | ||||||||
Interest rate instruments(b) | $ | — | $ | — | $ | — | $ | — | ||||||||
Current liabilities(c): | ||||||||||||||||
Commodity derivative instruments | $ | — | $ | (1.2 | ) | $ | — | $ | (1.2 | ) | ||||||
Interest rate instruments | $ | — | $ | (16.5 | ) | $ | — | $ | (16.5 | ) | ||||||
Long-term liabilities(d): | ||||||||||||||||
Commodity derivative instruments | $ | — | $ | (3.2 | ) | $ | — | $ | (3.2 | ) | ||||||
Interest rate instruments | $ | — | $ | (22.8 | ) | $ | — | $ | (22.8 | ) |
(a) | Included in current unrealized gains on derivative instruments in our consolidated balance sheets. | |
(b) | Included in long-term unrealized gains on derivative instruments in our consolidated balance sheets. | |
(c) | Included in current unrealized losses on derivative instruments in our consolidated balance sheets. | |
(d) | Included in long-term unrealized losses on derivative instruments in our consolidated balance sheets. |
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Net Realized | ||||||||||||||||||||||||
and Unrealized | Net Unrealized | |||||||||||||||||||||||
Balance at | Gains Included | Transfers In/ | Purchases, | Balance at | Gains (Losses) | |||||||||||||||||||
December 31, | in (Losses) | Out of | Issuances and | December 31, | Still Held Included | |||||||||||||||||||
2007 | Earnings | Level 3(a) | Settlements, Net | 2008 | in Earnings(b) | |||||||||||||||||||
(Millions) | ||||||||||||||||||||||||
Commodity derivative instruments: | ||||||||||||||||||||||||
Current assets | $ | 0.2 | $ | 0.8 | $ | — | $ | (0.7 | ) | $ | 0.3 | $ | 0.3 | |||||||||||
Long-term assets | $ | 1.5 | $ | 1.0 | $ | (0.8 | ) | $ | — | $ | 1.7 | $ | 1.0 | |||||||||||
Current liabilities | $ | (1.6 | ) | $ | (0.2 | ) | $ | — | $ | 1.8 | $ | — | $ | — | ||||||||||
Long-term liabilities | $ | (0.2 | ) | $ | 0.2 | $ | — | $ | — | $ | — | $ | 0.2 |
(a) | Amounts transferred in are reflected at fair value as of the end of the period and amounts transferred out are reflected at fair value at the beginning of the period. | |
(b) | Represents the amount of total gains or losses for the period, included in gains or losses from commodity derivative activity, net, attributable to change in unrealized gains (losses) relating to assets and liabilities classified as Level 3 that are still held at December 31, 2008. |
10. | Estimated Fair Value of Financial Instruments |
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11. | Debt |
Principal Amount | ||||||||
2008 | 2007 | |||||||
(Millions) | ||||||||
Revolving credit facility, weighed-average interest rate of 2.08% and 5.47%, respectively, due June 21, 2012(a) | $ | 596.5 | $ | 530.0 | ||||
Term loan facility, interest rate 1.54% and 5.05%, respectively, due June 21, 2012(b) | 60.0 | 100.0 | ||||||
Total long-term debt | $ | 656.5 | $ | 630.0 | ||||
(a) | $575.0 million of debt has been swapped to a fixed rate obligation with effective fixed rates ranging from 2.26% to 5.19%, for a net effective rate of 4.48% on the $596.5 million of outstanding debt under our revolving credit facility as of December 31, 2008. | |
(b) | The term loan facility is fully secured by restricted investments. |
• | a $764.6 million revolving credit facility; and | |
• | a $60.0 million term loan facility. |
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12. | Partnership Equity and Distributions |
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• | less the amount of cash reserves established by the general partner to: |
• | provide for the proper conduct of our business; | |
• | comply with applicable law, any of our debt instruments or other agreements; or | |
• | provide funds for distributions to the unitholders and to our general partner for any one or more of the next four quarters; |
• | plus, if our general partner so determines, all or a portion of cash and cash equivalents on hand on the date of determination of Available Cash for the quarter. |
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• | first,to the common unitholders and the general partner, in accordance with their pro rata interest, until we distribute for each outstanding common unit an amount equal to the Minimum Quarterly Distribution for that quarter; | |
• | second,to the common unitholders and the general partner, in accordance with their pro rata interest, until we distribute for each outstanding common unit an amount equal to any arrearages in payment of the Minimum Quarterly Distribution on the common units for any prior quarters during the subordination period; | |
• | third,to the subordinated unitholders and the general partner, in accordance with their pro rata interest, until we distribute for each subordinated unit an amount equal to the Minimum Quarterly Distribution for that quarter; | |
• | fourth,to all unitholders and the general partner, in accordance with their pro rata interest, until each unitholder receives a total of $0.4025 per unit for that quarter (the First Target Distribution); | |
• | fifth,13% to the general partner, plus the general partner’s pro rata interest, and the remainder to all unitholders pro rata until each unitholder receives a total of $0.4375 per unit for that quarter (the Second Target Distribution); | |
• | sixth,23% to the general partner, plus the general partner’s pro rata interest, and the remainder to all unitholders pro rata until each unitholder receives a total of $0.525 per unit for that quarter (the Third Target Distribution); and | |
• | thereafter,48% to the general partner, plus the general partner’s pro rata interest, and the remainder to all unitholders (the Fourth Target Distribution). |
• | first,to all unitholders and the general partner, in accordance with their pro rata interest, until each unitholder receives a total of $0.4025 per unit for that quarter; | |
• | second,13% to the general partner, plus the general partner’s pro rata interest, and the remainder to all unitholders pro rata until each unitholder receives a total of $0.4375 per unit for that quarter; | |
• | third,23% to the general partner, plus the general partner’s pro rata interest, and the remainder to all unitholders pro rata until each unitholder receives a total of $0.525 per unit for that quarter; and | |
• | thereafter,48% to the general partner, plus the general partner’s pro rata interest, and the remainder to all unitholders. |
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Per Unit | Total Cash | |||||||
Payment Date | Distribution | Distribution | ||||||
(Millions) | ||||||||
November 14, 2008 | $ | 0.600 | $ | 20.1 | ||||
August 14, 2008 | 0.600 | 20.1 | ||||||
May 15, 2008 | 0.590 | 19.6 | ||||||
February 14, 2008 | 0.570 | 15.7 | ||||||
November 14, 2007 | 0.550 | 14.7 | ||||||
August 14, 2007 | 0.530 | 12.4 | ||||||
May 15, 2007 | 0.465 | 8.6 | ||||||
February 14, 2007 | 0.430 | 7.8 | ||||||
November 14, 2006 | 0.405 | 7.4 | ||||||
August 14, 2006 | 0.380 | 6.7 | ||||||
May 15, 2006 | 0.350 | 6.3 | ||||||
February 13, 2006(a) | 0.095 | 1.7 |
(a) | Represents the pro rata portion of our Minimum Quarterly distribution of $0.35 per unit for the period December 7, 2005, the closing of our initial public offering, through December 31, 2005. |
13. | Risk Management Activities, Credit Risk and Financial Instruments |
Year Ended December 31, | ||||||||||||
2008 | 2007 | 2006 | ||||||||||
(Millions) | ||||||||||||
Commodity cash flow hedges: | ||||||||||||
Losses due to ineffectiveness | $ | — | $ | — | $ | (0.3 | ) | |||||
(Losses) gains reclassified into earnings | $ | (0.8 | ) | $ | 2.4 | $ | 2.6 | |||||
Commodity derivative activity: | ||||||||||||
Unrealized gains (losses) from derivative activity | $ | 102.4 | $ | (81.7 | ) | $ | 0.3 | |||||
Realized losses from derivative activity | $ | (30.1 | ) | $ | (5.9 | ) | $ | (0.2 | ) | |||
Interest rate cash flow hedges: | ||||||||||||
(Losses) gains reclassified into earnings | $ | (6.7 | ) | $ | 0.7 | $ | 0.1 |
December 31, | ||||||||
2008 | 2007 | |||||||
(Millions) | ||||||||
Commodity cash flow hedges: | ||||||||
Net deferred losses in AOCI | $ | (1.8 | ) | $ | (2.6 | ) | ||
Interest rate cash flow hedges: | ||||||||
Net deferred losses in AOCI | $ | (38.7 | ) | $ | (12.3 | ) |
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14. | Equity-Based Compensation |
Year Ended December 31, | ||||||||||||
2008 | 2007 | 2006 | ||||||||||
(Millions) | ||||||||||||
Performance Units | $ | (0.7 | ) | $ | 1.1 | $ | 0.2 | |||||
Phantom Units | (0.4 | ) | 0.6 | 0.4 | ||||||||
Restricted Phantom Units | 0.1 | — | — | |||||||||
Total compensation (credit) cost | $ | (1.0 | ) | $ | 1.7 | $ | 0.6 | |||||
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Grant Date | ||||||||||||
Weighted- | Measurement | |||||||||||
Average Price | Date Price | |||||||||||
Units | per Unit | per Unit | ||||||||||
Outstanding at January 1, 2006 | — | $ | — | |||||||||
Granted | 40,560 | $ | 26.96 | |||||||||
Forfeited | (17,470 | ) | $ | 26.96 | ||||||||
Outstanding at December 31, 2006 | 23,090 | $ | 26.96 | |||||||||
Granted | 29,610 | $ | 37.29 | |||||||||
Forfeited | (5,740 | ) | $ | 31.39 | ||||||||
Outstanding at December 31, 2007 | 46,960 | $ | 32.93 | |||||||||
Granted | 17,085 | $ | 33.85 | |||||||||
Forfeited | (12,025 | ) | $ | 32.42 | ||||||||
Outstanding at December 31, 2008 | 52,020 | $ | 33.35 | $ | 9.40 | |||||||
Expected to vest(a) | 45,350 | $ | 31.70 | $ | 9.40 |
(a) | Based on our December 31, 2008 estimated achievement of specified performance targets, the performance target for units granted in 2008 is 100%, for units granted in 2007 is 102%, and for units granted in 2006 is 140.4%. The estimated forfeiture rate for units granted in 2008 and 2007 is 50%, and for units granted in 2006 is 0%. |
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Grant Date | ||||||||||||
Weighted- | Measurement | |||||||||||
Average Price | Date Price | |||||||||||
Units | per Unit | per Unit | ||||||||||
Outstanding at January 1, 2006 | — | $ | — | |||||||||
Granted | 35,900 | $ | 24.05 | |||||||||
Forfeited | (11,200 | ) | $ | 24.05 | ||||||||
Outstanding at December 31, 2006 | 24,700 | $ | 24.05 | |||||||||
Granted | 4,500 | $ | 42.90 | |||||||||
Forfeited | (2,333 | ) | $ | 24.05 | ||||||||
Vested | (6,668 | ) | $ | 35.23 | ||||||||
Outstanding at December 31, 2007 | 20,199 | $ | 24.56 | |||||||||
Granted | 4,000 | $ | 35.88 | |||||||||
Forfeited | (4,000 | ) | $ | 24.05 | ||||||||
Vested | (6,501 | ) | $ | 32.91 | ||||||||
Outstanding at December 31, 2008 | 13,698 | $ | 24.05 | $ | 9.40 | |||||||
Expected to vest | 13,698 | $ | 24.05 | $ | 9.40 |
Grant Date | ||||||||||||
Weighted- | Measurement | |||||||||||
Average Price | Date Price | |||||||||||
Units | per Unit | per Unit | ||||||||||
Outstanding at January 1, 2008 | — | $ | — | $ | — | |||||||
Granted | 17,085 | $ | 33.85 | |||||||||
Forfeited | (2,395 | ) | $ | 35.88 | ||||||||
Vested | — | $ | — | |||||||||
Outstanding at December 31, 2008 | 14,690 | $ | 33.52 | $ | 9.40 | |||||||
Expected to vest | 8,544 | $ | 33.85 | $ | 9.40 |
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15. | Income Taxes |
16. | Net Income or Loss per Limited Partner Unit |
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Year Ended December 31, | ||||||||||||
2008 | 2007 | 2006 | ||||||||||
(Millions) | ||||||||||||
Net income (loss) | $ | 125.7 | $ | (15.8 | ) | $ | 61.9 | |||||
Less: | ||||||||||||
Net income attributable to predecessor operations | — | (3.6 | ) | (26.6 | ) | |||||||
Net income (loss) attributable to the partnership | 125.7 | (19.4 | ) | 35.3 | ||||||||
Less: General partner interest in net income | (11.9 | ) | (2.2 | ) | (0.7 | ) | ||||||
Limited partners’ interest in net income or net loss | 113.8 | (21.6 | ) | 34.6 | ||||||||
Less: Additional earnings allocation to general partner | (24.8 | ) | — | (1.3 | ) | |||||||
Net income (loss) available to limited partners | $ | 89.0 | $ | (21.6 | ) | $ | 33.3 | |||||
Net income (loss) per LPU — basic and diluted | $ | 3.25 | $ | (1.05 | ) | $ | 1.90 | |||||
17. | Commitments and Contingent Liabilities |
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(Millions) | ||||
2009 | $ | 12.4 | ||
2010 | 9.0 | |||
2011 | 7.9 | |||
2012 | 7.0 | |||
2013 | 5.8 | |||
Thereafter | 2.6 | |||
Total minimum rental payments | $ | 44.7 | ||
18. | Business Segments |
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Wholesale | ||||||||||||||||||||
Natural Gas | Propane | NGL | ||||||||||||||||||
Services | Logistics | Logistics | Other(c) | Total | ||||||||||||||||
(Millions) | ||||||||||||||||||||
Total operating revenue | $ | 791.5 | $ | 483.0 | $ | 11.3 | $ | — | $ | 1,285.8 | ||||||||||
Gross margin(a) | $ | 206.5 | $ | 11.0 | $ | 7.1 | $ | — | $ | 224.6 | ||||||||||
Operating and maintenance expense | (32.1 | ) | (9.9 | ) | (1.0 | ) | — | (43.0 | ) | |||||||||||
Depreciation and amortization expense | (33.8 | ) | (1.3 | ) | (1.4 | ) | — | (36.5 | ) | |||||||||||
General and administrative expense | — | — | — | (24.0 | ) | (24.0 | ) | |||||||||||||
Other | — | 1.5 | — | — | 1.5 | |||||||||||||||
Earnings from equity method investments | 33.5 | — | 0.8 | — | 34.3 | |||||||||||||||
Interest income | — | — | — | 5.6 | 5.6 | |||||||||||||||
Interest expense | — | — | — | (32.8 | ) | (32.8 | ) | |||||||||||||
Income tax expense(b) | — | — | — | (0.1 | ) | (0.1 | ) | |||||||||||||
Non-controlling interest in income | (3.9 | ) | — | — | — | (3.9 | ) | |||||||||||||
Net income (loss) | $ | 170.2 | $ | 1.3 | $ | 5.5 | $ | (51.3 | ) | $ | 125.7 | |||||||||
Non-cash derivative mark-to-market(d) | $ | 99.2 | $ | 2.4 | $ | — | $ | (0.6 | ) | $ | 101.0 | |||||||||
Capital expenditures | $ | 36.6 | $ | 3.3 | $ | 0.4 | $ | 0.7 | $ | 41.0 | ||||||||||
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Wholesale | ||||||||||||||||||||
Natural Gas | Propane | NGL | ||||||||||||||||||
Services | Logistics | Logistics | Other(c) | Total | ||||||||||||||||
(Millions) | ||||||||||||||||||||
Total operating revenue | $ | 404.1 | $ | 459.6 | $ | 9.6 | $ | — | $ | 873.3 | ||||||||||
Gross margin(a) | $ | 16.2 | $ | 25.5 | $ | 4.9 | $ | — | $ | 46.6 | ||||||||||
Operating and maintenance expense | (20.9 | ) | (10.4 | ) | (0.8 | ) | — | (32.1 | ) | |||||||||||
Depreciation and amortization expense | (21.9 | ) | (1.1 | ) | (1.4 | ) | — | (24.4 | ) | |||||||||||
General and administrative expense | — | — | — | (24.1 | ) | (24.1 | ) | |||||||||||||
Earnings from equity method investments | 38.7 | — | 0.6 | — | 39.3 | |||||||||||||||
Interest income | — | — | — | 5.3 | 5.3 | |||||||||||||||
Interest expense | — | — | — | (25.8 | ) | (25.8 | ) | |||||||||||||
Income tax expense(b) | — | — | — | (0.1 | ) | (0.1 | ) | |||||||||||||
Non-controlling interest in income | (0.5 | ) | — | — | — | (0.5 | ) | |||||||||||||
Net income (loss) | $ | 11.6 | $ | 14.0 | $ | 3.3 | $ | (44.7 | ) | $ | (15.8 | ) | ||||||||
Non-cash derivative mark-to-market(d) | $ | (78.3 | ) | $ | (2.8 | ) | $ | — | $ | — | $ | (81.1 | ) | |||||||
Capital expenditures | $ | 16.2 | $ | 3.9 | $ | 1.2 | $ | — | $ | 21.3 | ||||||||||
Wholesale | ||||||||||||||||||||
Natural Gas | Propane | NGL | ||||||||||||||||||
Services | Logistics | Logistics | Other(c) | Total | ||||||||||||||||
(Millions) | ||||||||||||||||||||
Total operating revenue | $ | 415.3 | $ | 375.2 | $ | 5.3 | $ | — | $ | 795.8 | ||||||||||
Gross margin(a) | $ | 75.3 | $ | 16.0 | $ | 4.1 | $ | — | $ | 95.4 | ||||||||||
Operating and maintenance expense | (13.5 | ) | (8.6 | ) | (1.6 | ) | — | (23.7 | ) | |||||||||||
Depreciation and amortization expense | (11.1 | ) | (0.8 | ) | (0.9 | ) | — | (12.8 | ) | |||||||||||
General and administrative expense | — | — | — | (21.0 | ) | (21.0 | ) | |||||||||||||
Earnings from equity method investments | 28.9 | — | 0.3 | — | 29.2 | |||||||||||||||
Interest income | — | — | — | 6.3 | 6.3 | |||||||||||||||
Interest expense | — | — | — | (11.5 | ) | (11.5 | ) | |||||||||||||
Net income (loss) | $ | 79.6 | $ | 6.6 | $ | 1.9 | $ | (26.2 | ) | $ | 61.9 | |||||||||
Non-cash derivative mark-to-market(d) | $ | 0.1 | $ | — | $ | — | $ | — | $ | 0.1 | ||||||||||
Capital expenditures | $ | 6.5 | $ | 9.4 | $ | 11.3 | $ | — | $ | 27.2 | ||||||||||
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December 31, | ||||||||
2008 | 2007 | |||||||
(Millions) | ||||||||
Segment long-term assets: | ||||||||
Natural Gas Services(e) | $ | 856.4 | $ | 710.7 | ||||
Wholesale Propane Logistics | 54.3 | 52.6 | ||||||
NGL Logistics | 33.8 | 34.8 | ||||||
Other(f) | 70.3 | 104.1 | ||||||
Total long-term assets | 1,014.8 | 902.2 | ||||||
Current assets | 165.2 | 218.5 | ||||||
Total assets | $ | 1,180.0 | $ | 1,120.7 | ||||
(a) | Gross margin consists of total operating revenues, including commodity derivative activity, less purchases of natural gas, propane and NGLs. Gross margin is viewed as a non-GAAP measure under the rules of the SEC, but is included as a supplemental disclosure because it is a primary performance measure used by management as it represents the results of product sales versus product purchases. As an indicator of our operating performance, gross margin should not be considered an alternative to, or more meaningful than, net income or cash flow as determined in accordance with GAAP. Our gross margin may not be comparable to a similarly titled measure of another company because other entities may not calculate gross margin in the same manner. | |
(b) | Income tax expense in 2008 and 2007 relates primarily to the Texas margin tax. | |
(c) | Other consists of general and administrative expense, interest income, interest expense and income tax expense. | |
(d) | Non-cash derivative mark-to-market is included in segment gross margin, along with cash settlements for our derivative contracts. | |
(e) | Long-term assets for our Natural Gas Services segment increased in 2008 as a result of our acquisition of MPP in October 2008, and in 2007 as a result of our Southern Oklahoma acquisition in May 2007, and our acquisition of certain MEG subsidiaries in August 2007. Long-term assets for our Natural Gas Services segment include the effects of our 25% equity interest in East Texas, our 40% equity interest in Discovery and the Swap acquired in July 2007, for all periods presented. | |
(f) | Other long-term assets not allocable to segments consist of restricted investments, unrealized gains on derivative instruments, corporate leasehold improvements and other long-term assets. |
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19. | Supplemental Cash Flow Information |
Year Ended December 31, | ||||||||||||
2008 | 2007 | 2006 | ||||||||||
(Millions) | ||||||||||||
Cash paid for interest: | ||||||||||||
Cash paid for interest, net of amounts capitalized | $ | 26.3 | $ | 26.5 | $ | 11.1 | ||||||
Non-cash investing and financing activities: | ||||||||||||
Non-cash additions of property, plant and equipment | $ | 1.5 | $ | 5.9 | $ | 1.4 | ||||||
Accounts payable related to acquisitions | $ | — | $ | 9.0 | $ | 9.9 | ||||||
Accrued distributions to DCP Midstream, LLC related to reimbursements | $ | — | $ | 0.5 | $ | — | ||||||
Accrued contributions from DCP Midstream, LLC related to reimbursements | $ | — | $ | 0.3 | $ | — | ||||||
Accrued equity-based compensation | $ | 0.2 | $ | 0.2 | $ | — |
20. | Quarterly Financial Data (Unaudited) |
Year Ended | ||||||||||||||||||||
December 31, | ||||||||||||||||||||
2008 | First | Second | Third | Fourth | 2008 | |||||||||||||||
Total operating revenues | $ | 337.7 | $ | 145.9 | $ | 426.8 | $ | 375.4 | $ | 1,285.8 | ||||||||||
Operating (loss) income | $ | (16.6 | ) | $ | (165.7 | ) | $ | 152.4 | $ | 152.5 | $ | 122.6 | ||||||||
Net (loss) income | $ | (6.5 | ) | $ | (159.3 | ) | $ | 152.7 | $ | 138.8 | $ | 125.7 | ||||||||
Limited partners’ interest in net (loss) income | $ | (8.2 | ) | $ | (159.8 | ) | $ | 147.8 | $ | 134.0 | $ | 113.8 | ||||||||
Basic net (loss) income per limited partner unit | $ | (0.33 | ) | $ | (5.66 | ) | $ | 2.97 | $ | 2.72 | $ | 3.25 |
Year Ended | ||||||||||||||||||||
December 31, | ||||||||||||||||||||
2007 | First | Second | Third | Fourth | 2007 | |||||||||||||||
Total operating revenues | $ | 237.2 | $ | 181.1 | $ | 188.6 | $ | 266.4 | $ | 873.3 | ||||||||||
Operating income (loss) | $ | 11.5 | $ | (1.8 | ) | $ | 3.9 | $ | (47.6 | ) | $ | (34.0 | ) | |||||||
Net income (loss) | $ | 15.8 | $ | 0.8 | $ | 7.5 | $ | (39.9 | ) | $ | (15.8 | ) | ||||||||
Limited partners’ interest in net income (loss)(a) | $ | 12.2 | $ | 0.2 | $ | 6.6 | $ | (40.6 | ) | $ | (21.6 | ) | ||||||||
Basic net income (loss) per limited partner unit(a) | $ | 0.58 | $ | 0.01 | $ | 0.29 | $ | (1.69 | ) | $ | (1.05 | ) |
Year Ended | ||||||||||||||||||||
December 31, | ||||||||||||||||||||
2006 | First | Second | Third | Fourth | 2006 | |||||||||||||||
Total operating revenues | $ | 265.4 | $ | 160.1 | $ | 162.8 | $ | 207.5 | $ | 795.8 | ||||||||||
Operating income | $ | 9.1 | $ | 9.3 | $ | 7.3 | $ | 12.2 | $ | 37.9 | ||||||||||
Net income | $ | 16.3 | $ | 15.7 | $ | 14.3 | $ | 15.6 | $ | 61.9 | ||||||||||
Limited partners’ interest in net income(a)(b) | $ | 5.3 | $ | 8.6 | $ | 9.5 | $ | 11.1 | $ | 34.6 | ||||||||||
Basic net income per limited partner unit(a)(b) | $ | 0.30 | $ | 0.47 | $ | 0.51 | $ | 0.55 | $ | 1.90 |
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(a) | Total limited partners’ interest in net income and basic income per limited partner unit excludes the results from our interest in East Texas, Discovery and the Swap for the period January 1, 2006 through June 30, 2007. | |
(b) | Total limited partners’ interest in net income and basic income per limited partner unit excludes the results from our wholesale propane logistics business for the period January 1, 2006 through October 31, 2006. |
21. | Subsequent Events |
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Item 9. | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure |
Item 9A. | Controls and Procedures |
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Item 10. | Directors, Executive Officers and Corporate Governance |
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Name | Age | Position with DCP Midstream GP, LLC | ||||
Thomas C. O’Connor | 53 | Chairman of the Board and Director | ||||
Mark A. Borer | 54 | President, Chief Executive Officer and Director | ||||
Angela A. Minas | 44 | Vice President and Chief Financial Officer | ||||
Michael S. Richards | 49 | Vice President, General Counsel and Secretary | ||||
Don Baldridge | 39 | Vice President, Business Development | ||||
Paul F. Ferguson, Jr. | 59 | Director | ||||
Gregory J. Goff | 52 | Director | ||||
Alan N. Harris | 55 | Director | ||||
John E. Lowe | 50 | Director | ||||
Frank A. McPherson | 75 | Director | ||||
Thomas C. Morris | 68 | Director | ||||
Stephen R. Springer | 62 | Director |
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• | reviewed and discussed the audited financial statements in this annual report onForm 10-K with management, including a discussion of the quality, not just the acceptability, of the accounting principles, the reasonableness of significant judgments and the clarity of disclosures in the financial statements; | |
• | reviewed with Deloitte & Touche, LLP, our independent auditors, who are responsible for expressing an opinion on the conformity of those audited financial statements with generally accepted accounting principles, their judgments as to the quality and acceptability of our accounting principles and such other matters as are required to be discussed with the audit committee under generally accepted auditing standards; | |
• | received the written disclosures and the letter required by standard No. 1 of the independence standards board (independence discussions with audit committees) provided to the audit committee by Deloitte & Touche, LLP; | |
• | discussed with Deloitte & Touche, LLP its independence from management and us and considered the compatibility of the provision of nonaudit service by the independent auditors with the auditors’ independence; | |
• | discussed with Deloitte & Touche, LLP the matters required to be discussed by statement on auditing standards No. 61 (communications with audit committees); | |
• | discussed with our internal auditors and Deloitte & Touche, LLP the overall scope and plans for their respective audits. The audit committee meets with the internal auditors and Deloitte & Touche, LLP, with and without management present, to discuss the results of their examinations, their evaluations of our internal controls and the overall quality of our financial reporting; | |
• | based on the foregoing reviews and discussions, recommended to the board of directors that the audited financial statements be included in the annual report onForm 10-K for the year ended December 31, 2008, for filing with the Securities and Exchange Commission; and | |
• | approved the selection and appointment of Deloitte & Touche, LLP to serve as our independent auditors. |
Frank A. McPherson
Thomas C. Morris
Stephen R. Springer
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Item 11. | Executive Compensation |
• | annually review and approve Partnership goals and objectives relevant to compensation of the CEO and other executive officers; | |
• | annually evaluate the CEO’s performance in light of the Partnership goals and objectives, and approve the compensation levels for the CEO and other executive officers; | |
• | periodically evaluate the terms and administration of the Partnership’s short-term and long-term incentive plans to assure that they are structured and administered in a manner consistent with the Partnership’s goals and objectives; | |
• | periodically evaluate incentive compensation and equity-related plans and consider amendments if appropriate; | |
• | retain and terminate any compensation consultant to be used to assist in the evaluation of director, CEO or executive officer compensation; and | |
• | perform other duties as deemed appropriate by the General Partner’s board of directors. |
• | Attract, retain and reward talented executive officers and key management employees by providing total compensation competitive with that of other executive officers and key management employees employed by publicly traded limited partnerships of similar size or in similar lines of business; | |
• | Motivate executive officers and key management employees to achieve strong financial and operational performance; | |
• | Emphasize performance-based compensation, balancing short-term and long-term results; | |
• | Reward individual performance; and | |
• | Encourage a long-term commitment to the Partnership by requiring target levels of unit ownership. |
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Targeted | Targeted | |||||||||||
Base Salary | STI Level | LTIP Level | ||||||||||
CEO | 34 | % | 21 | % | 45 | % | ||||||
Chief Financial Officer, or CFO | 44 | % | 20 | % | 36 | % | ||||||
Vice Presidents | 44 | % | 20 | % | 36 | % |
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1) | The achievement of our budget for operating cash flow from our 2008 budgeted asset base, excluding the impact from non-cash mark to market adjustments to derivative instruments and any one-time transaction costs. We define operating cash flow as our distributable cash flow plus maintenance capital and interest expense. As a publicly traded limited partnership, our performance is generally judged on our ability to pay cash distributions to our unitholders. Distributable cash flow has three primary components: maintenance capital, interest expense and operating cash flow. We use operating cash flow as the financial objective because we believe it is the most controllable component of distributable cash flow and permits management to focus on the long term sustainability and development of our assets. For this company objective, the target level of performance is operating cash flow of $118.0 million, the maximum level of performance is operating cash flow of $135.0 million and the minimum level of performance operating cash flow of $110.0 million. The weighting of this objective relative to the other stated company objectives was 35%. | |
2) | Deliver on board approved 2008 growth capital including acquisitions, organic growth projects and the dropdown of assets from our sponsors. We believe that our performance is also judged by our growth, which can translate into distribution growth. For this company objective, the target level of performance is $400.0 million of approved growth capital in 2008, the maximum level of performance is $900.0 million of approved growth capital in 2008 and the minimum level of performance is $250.0 million of approved growth capital in 2008. The weighting of this objective relative to the other stated company objectives was 25%. | |
3) | Establishing and maintaining strong internal controls and accounting accuracy while meeting the performance requirements of the Sarbanes-Oxley Act of 2002. For this company objective, the minimum level of performance will be based on having no material weaknesses identified by management or the external auditor. A subjective determination will be made by the Audit Committee to assess performance between the minimum and maximum level of performance taking into consideration the number of significant deficiencies identified. The weighting of this objective relative to the other stated company objectives was 7%. | |
4) | A safety objective based on recordable incident rate, or RIR, of both our assets and the assets of DCP Midstream, LLC, the owner of our general partner and the operator or our assets. If a fatality occurs of our employee or that of our contractor on our premises, a 5% safety penalty will be assessed against the entire STI payout. For this company objective, the target level of performance is an RIR of 0.75, the maximum level of performance is an RIR of 0.40 and the minimum level of performance is an RIR of 0.95. The weighting of this objective relative to the other stated company objectives was 5%. | |
5) | An environmental objective of non-routine air emissions, natural gas vented or flared, of both our assets and the assets of DCP Midstream, LLC. For this company objective, the target level of |
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performance is 1,000 million standard cubic feet, or MMscf, the maximum level of performance is 790 MMscf and the minimum level of performance is 1,200 MMscf. The weighting of this objective relative to the other stated company objectives was 3%. |
Level of | ||
STI Objective | Performance Achieved | |
1) Operating cash flow | Between Minimum and Target | |
2) Growth capital | Between Minimum and Target | |
3) Internal controls | Target | |
4) Safety | Between Minimum and Target | |
5) Environmental | Below Minimum — No Payout |
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Number of | ||||
Units | ||||
CEO | 28,000 | |||
CFO | 10,000 | |||
Vice Presidents | 10,000 |
Change in | ||||||||||||||||||||||||||||
Nonqualified | ||||||||||||||||||||||||||||
Non-Equity | Deferred | |||||||||||||||||||||||||||
Incentive Plan | Compensation | All Other | ||||||||||||||||||||||||||
Name and Principal Position | Year | Salary | LTIP Awards(e) | Compensation | Earnings(f) | Compensation(g) | Total | |||||||||||||||||||||
Mark A. Borer(a) | 2008 | $ | 358,538 | $ | (34,138 | ) | $ | 80,671 | $ | 56,236 | $ | 126,851 | $ | 588,158 | ||||||||||||||
President and Chief | 2007 | $ | 341,000 | $ | 151,763 | $ | 331,043 | $ | 36,518 | $ | 80,908 | $ | 941,232 | |||||||||||||||
Executive Officer | 2006 | $ | 47,215 | $ | — | $ | 46,655 | $ | 45 | $ | 2,052 | $ | 95,967 | |||||||||||||||
Angela A. Minas(b) | 2008 | $ | 61,923 | $ | 3,541 | $ | 18,252 | $ | — | $ | 49,199 | $ | 132,915 | |||||||||||||||
Vice President and Chief Financial Officer | ||||||||||||||||||||||||||||
Thomas E. Long(c) | 2008 | $ | 76,168 | $ | (396,593 | ) | $ | — | $ | (61,564 | ) | $ | 31,955 | $ | (350,034 | ) | ||||||||||||
Vice President and | 2007 | $ | 199,212 | $ | 304,402 | $ | 145,605 | $ | 1,584 | $ | 54,268 | $ | 705,071 | |||||||||||||||
Chief Financial Officer | 2006 | $ | 180,000 | $ | 92,191 | $ | 133,650 | $ | — | $ | 33,182 | $ | 439,023 | |||||||||||||||
Michael S. Richards | 2008 | $ | 181,748 | $ | (232,166 | ) | $ | 52,343 | $ | (6,765 | ) | $ | 65,136 | $ | 60,296 | |||||||||||||
Vice President, General | 2007 | $ | 172,615 | $ | 282,729 | $ | 125,903 | $ | 48 | $ | 46,431 | $ | 627,726 | |||||||||||||||
Counsel and Secretary | 2006 | $ | 165,000 | $ | 88,390 | $ | 122,048 | $ | — | $ | 32,717 | $ | 408,155 | |||||||||||||||
Greg K. Smith(d) | 2008 | $ | 190,970 | $ | (236,289 | ) | $ | 32,226 | $ | (4,248 | ) | $ | 69,620 | $ | 52,279 | |||||||||||||
Vice President, Business | 2007 | $ | 179,644 | $ | 289,184 | $ | 131,080 | $ | 866 | $ | 51,185 | $ | 651,959 | |||||||||||||||
Development | 2006 | $ | 170,000 | $ | 89,600 | $ | 121,444 | $ | 480 | $ | 36,044 | $ | 417,568 |
(a) | Mr. Borer’s employment with the General Partner commenced effective November 10, 2006. |
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(b) | Ms. Minas’ employment with the General Partner commenced effective September 8, 2008. | |
(c) | Mr. Long’s employment with the General Partner terminated effective April 30, 2008. | |
(d) | Mr. Smith’s employment with the General Partner terminated effective January 5, 2009, and he commenced employment with DCP Midstream, LLC. Mr. Smith has been replaced by Don Baldridge, formerly employed by DCP Midstream, LLC. | |
(e) | The amounts in this column reflect the dollar amount recognized for financial statement reporting purposes in accordance with the provisions of Statement of Financial Accounting Standard No. 123(R), Share-Based Payment, or SFAS 123R, which incorporates re-measurement of awards for changes in the underlying assumptions used in prior periods, such as the unit price at the measurement date and the performance measure percentage. These amounts reflect our accounting expense and may not necessarily correspond to the actual value that will be realized by the named executives. The amounts exclude the impact of an estimated forfeiture rate under SFAS 123R, but do include the impact of forfeited awards if any of the named executives fail to perform the requisite service. Accordingly, the amounts may be negative due to these factors. This column reflects awards granted in January 2006 related to our initial public offering, and awards granted in conjunction with our LTIP. See Note 14 of the Notes to Consolidated Financial Statements in Item 8, “Financial Statements and Supplementary Data.” | |
(f) | Amounts in this column are also included in the “Nonqualified Deferred Compensation” table below. | |
(g) | Includes DERs, company retirement and nonqualified deferred compensation program contributions by the Partnership, the value of life insurance premiums paid by the Partnership on behalf of an executive and other deminimus compensation. |
2008 | 2007 | 2006 | ||||||||||
Company retirement contributions to defined contribution plans | $ | 29,900 | $ | 29,950 | $ | — | ||||||
Nonqualified deferred compensation program contributions | $ | 50,160 | $ | 32,063 | $ | 1,945 | ||||||
DERs | $ | 44,947 | $ | 18,370 | $ | — | ||||||
Life insurance premiums(a) | $ | 1,844 | $ | 1,225 | $ | 107 |
(a) | Paid by the Partnership on behalf of Mr. Borer. |
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2008 | ||||
Relocation expenses | $ | 41,901 | ||
Company retirement contributions to defined contribution plans | $ | 5,131 | ||
DERs | $ | 2,034 | ||
Life insurance premiums(a) | $ | 133 |
(a) | Paid by the Partnership on behalf of Ms. Minas. |
2008 | 2007 | 2006 | ||||||||||
Company retirement contributions to defined contribution plans | $ | 11,795 | $ | 28,476 | $ | 21,553 | ||||||
Nonqualified deferred compensation program contributions | $ | 14,796 | $ | — | $ | — | ||||||
DERs | $ | 5,324 | $ | 25,075 | $ | 10,981 | ||||||
Life insurance premiums(a) | $ | 40 | $ | 717 | $ | 648 |
(a) | Paid by the Partnership on behalf of Mr. Long. |
2008 | 2007 | 2006 | ||||||||||
Company retirement contributions to defined contribution plans | $ | 23,000 | $ | 22,500 | $ | 20,891 | ||||||
Nonqualified deferred compensation program contributions | $ | 6,550 | $ | — | $ | — | ||||||
DERs | $ | 35,020 | $ | 23,309 | $ | 10,482 | ||||||
Life insurance premiums(a) | $ | 566 | $ | 622 | $ | 594 | ||||||
Deminimus bonus | $ | — | $ | — | $ | 750 |
(a) | Paid by the Partnership on behalf of Mr. Richards. |
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2008 | 2007 | 2006 | ||||||||||
Company retirement contributions to defined contribution plans | $ | 23,926 | $ | 23,855 | $ | 21,928 | ||||||
Nonqualified deferred compensation program contributions | $ | 9,265 | $ | 2,864 | $ | 2,864 | ||||||
DERs | $ | 36,030 | $ | 23,818 | $ | 10,640 | ||||||
Life insurance premiums(a) | $ | 399 | $ | 648 | $ | 612 |
(a) | Paid by the Partnership on behalf of Mr. Smith. |
Grant Date | ||||||||||||||||||||||||||||||
Fair Value | ||||||||||||||||||||||||||||||
Estimated Future Payouts under Non-Equity Incentive Plan Awards (a) | Estimated Future Payouts under Equity Incentive Plan Awards | of LTIP | ||||||||||||||||||||||||||||
Minimum | Target | Maximum | Minimum | Target | Maximum | Awards | ||||||||||||||||||||||||
Name | Grant Date | ($) | ($) | ($) | (#) | (#) | (#) | ($) | ||||||||||||||||||||||
Mark A. Borer | NA | $ | 109,500 | $ | 219,000 | $ | 438,000 | — | — | — | $ | — | ||||||||||||||||||
PPUs | 2/25/2008(b) | $ | — | $ | — | $ | — | 3,305 | 6,610 | 9,915 | $ | 237,167 | ||||||||||||||||||
RPUs | 2/25/2008(c) | $ | — | $ | — | $ | — | 6,610 | 6,610 | 6,610 | $ | 237,167 | ||||||||||||||||||
Angela A. Minas | NA | $ | 51,750 | $ | 103,500 | $ | 207,000 | — | — | — | $ | — | ||||||||||||||||||
PPUs | 2/25/2008(b) | $ | — | $ | — | $ | — | 848 | 1,695 | 2,543 | $ | 28,273 | ||||||||||||||||||
RPUs | 2/25/2008(c) | $ | — | $ | — | $ | — | 1,695 | 1,695 | 1,695 | $ | 28,273 | ||||||||||||||||||
Michael S. Richards | NA | $ | 41,625 | $ | 83,250 | $ | 166,500 | — | — | — | $ | — | ||||||||||||||||||
PPUs | 2/25/2008(b) | $ | — | $ | — | $ | — | 1,030 | 2,060 | 3,090 | $ | 73,913 | ||||||||||||||||||
RPUs | 2/25/2008(c) | $ | — | $ | — | $ | — | 2,060 | 2,060 | 2,060 | $ | 73,913 | ||||||||||||||||||
Greg K. Smith | NA | $ | 43,875 | $ | 87,750 | $ | 175,500 | — | — | — | $ | — | ||||||||||||||||||
PPUs | 2/25/2008(b) | $ | — | $ | — | $ | — | 1,088 | 2,175 | 3,263 | $ | 78,039 | ||||||||||||||||||
RPUs | 2/25/2008(c) | $ | — | $ | — | $ | — | 2,175 | 2,175 | 2,175 | $ | 78,039 |
(a) | Amounts shown represent amounts under the STI. If minimum levels of performance are not met, then the payout for one or more of the components of the STI may be zero. | |
(b) | The number of units shown represents units awarded under the LTIP. If minimum levels of performance are not met, then the payout may be zero. | |
(c) | The number of units shown represents units awarded under the LTIP and these units vest at the end of the Vesting Period provided the individual is still employed by the Partnership. |
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Outstanding LTIP Awards | ||||||||||||||||
Equity Incentive | ||||||||||||||||
Equity Incentive | Plan Awards: | |||||||||||||||
Plan Awards: | Market Value of | |||||||||||||||
Market Value of | Unearned Units | Unearned Units | ||||||||||||||
Units That Have | Units That Have Not | That Have Not | That Have Not | |||||||||||||
Name | Not Vested(a) | Vested(b) | Vested(c) | Vested(b) | ||||||||||||
Mark A. Borer | — | $ | — | 25,110 | $ | 238,269 | ||||||||||
Angela A. Minas | — | $ | — | 3,390 | $ | 31,866 | ||||||||||
Michael S. Richards | 4,000 | $ | 37,600 | 12,730 | $ | 138,968 | ||||||||||
Greg K. Smith | 4,000 | $ | 37,600 | 13,250 | $ | 144,416 |
(a) | Phantom IPO Units awarded 1/3/2006; units vest in their entirety on 1/3/2009. For additional information, see “Compensation Discussion and Analysis — Other Compensation — Phantom IPO Units.” | |
(b) | Value calculated based on the closing price of our common units at December 31, 2008. | |
(c) | PPUs and RPUs awarded 5/5/2006, 2/26/2007 and 2/25/2008; units vest in their entirety over a range of 0% to 150% on 12/31/2008, 12/31/2009 and 12/31/2010, respectively, if the specified performance conditions are satisfied, except that the RPUs vest in their entirety on 12/31/2010; to determine the market value, the calculation of the number of units that are expected to vest for units granted in 2008 is based on assumed performance at 100%, for units granted in 2007 is based on assumed performance at 102%, and for units granted in 2006 is based on actual performance at 140.4%. |
Executive | Registrant | Aggregate Earnings | Aggregate | |||||||||||||||||
Contributions in | Contributions in | (Losses) in | Aggregate | Balance at | ||||||||||||||||
Last Fiscal | Last Fiscal | Last Fiscal | Withdrawals/ | December 31, | ||||||||||||||||
Name | Year(a) | Year(b) | Year(c) | Distributions | 2008 | |||||||||||||||
Mark A. Borer | $ | 125,488 | $ | 50,160 | $ | 56,236 | $ | — | $ | 901,245 | ||||||||||
Thomas E. Long | $ | 131,070 | $ | 14,796 | $ | (61,564 | ) | $ | (27,339 | ) | $ | 148,337 | ||||||||
Angela A. Minas | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||
Michael S. Richards | $ | 15,397 | $ | 6,550 | $ | (6,765 | ) | $ | — | $ | 18,708 | |||||||||
Greg K. Smith | $ | 7,638 | $ | 9,265 | $ | (4,248 | ) | $ | — | $ | 44,305 |
(a) | These amounts were included in the gross salary reported in the “Salary” column of the “Summary Compensation” table. | |
(b) | These amounts are included in the “Summary Compensation” table within “All Other Compensation.” | |
(c) | These amounts are included in the “Summary Compensation” table as “Change in Nonqualified Deferred Compensation Earnings.” |
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LTIP | ||||||||||||||||
Name | Fees Earned | Awards(a) | DERs | Total | ||||||||||||
Paul F. Ferguson, Jr. | $ | 90,000 | $ | 5,479 | $ | 2,762 | $ | 98,241 | ||||||||
Frank A. McPherson | $ | 72,500 | $ | 5,479 | $ | 2,762 | $ | 80,741 | ||||||||
Thomas C. Morris | $ | 69,000 | $ | 5,479 | $ | 2,762 | $ | 77,241 | ||||||||
Stephen R. Springer | $ | 89,500 | $ | 24,774 | $ | 1,475 | $ | 115,749 |
(a) | The amounts in this column reflect the dollar amount recognized for financial statement reporting purposes, in accordance with the provisions of SFAS 123R, and include amounts from awards granted in conjunction with our LTIP. See Note 14 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data.” |
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Item 12. | Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters |
• | each person who beneficially owns 5% or more of our outstanding units as of February 23, 2009; | |
• | all of the directors of DCP Midstream GP, LLC; | |
• | each Named Executive Officer of DCP Midstream GP, LLC; and | |
• | all directors and executive officers of DCP Midstream GP, LLC as a group. |
Percentage of | ||||||||
Common | Common | |||||||
Units | Units | |||||||
Beneficially | Beneficially | |||||||
Name of Beneficial Owner(a) | Owned | Owned | ||||||
DCP LP Holdings, LP(b)(1) | 8,246,451 | 29.2 | % | |||||
Kayne Anderson Capital Advisors, L.P.(c) | 1,778,335 | 6.3 | % | |||||
Barclays PLC(d) | 1,666,334 | 5.9 | % | |||||
Mark A. Borer | 38,001 | * | ||||||
Angela A. Minas | 15,000 | * | ||||||
Michael S. Richards | 12,101 | * | ||||||
Don Baldridge | 6,101 | * | ||||||
Alan N. Harris | 9,842 | * | ||||||
Paul F. Ferguson, Jr. | 6,334 | * | ||||||
John E. Lowe | 40,001 | * | ||||||
Frank A. McPherson | 15,666 | * | ||||||
Thomas C. Morris | 20,667 | * | ||||||
Thomas C. O’Connor | 8,000 | * | ||||||
Stephen R. Springer | 1,500 | * | ||||||
All directors and executive officers as a group (11 persons) | 173,213 | * |
* | Less than 1%. | |
(a) | Unless otherwise indicated, the address for all beneficial owners in this table is 370 17th Street, Suite 2775, Denver, Colorado 80202. | |
(b) | DCP Midstream, LLC is the ultimate parent company of DCP LP Holdings, LP and may, therefore, be deemed to beneficially own the units held by DCP LP Holdings, LP. DCP Midstream, LLC disclaims beneficial ownership of all of the units owned by DCP LP Holdings, LP. The address of DCP LP Holdings, LP and DCP Midstream, LLC is 370 17th Street, Suite 2500, Denver, Colorado 80202. | |
(c) | As set forth in a Schedule 13G filed on February 17, 2009. The address of Kayne Anderson Capital Advisors, L.P. is 1800 Avenue of the Stars, Second Floor, Los Angeles, CA 90067. | |
(d) | As set forth in a Schedule 13G filed on September 22, 2008. The address of Barclays PLC is 1 Churchill Place, London, E14 5HP, England. |
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Number of | Number of Securities | |||||||||||
Securities to be | Remaining Available for | |||||||||||
Issued upon | Weighted-Average | Future Issuance Under | ||||||||||
Exercise of | Exercise Price of | Equity Compensation | ||||||||||
Outstanding | Outstanding | Plans (Excluding | ||||||||||
Options, Warrants | Options, Warrants | Securities Reflected in | ||||||||||
and rights (1) | and Rights | Column (a)) | ||||||||||
(a) | (b) | (c) | ||||||||||
Equity compensation plans approved by unitholders | — | $ | — | — | ||||||||
Equity compensation plans not approved by unitholders | — | — | 769,592 | |||||||||
Total | — | $ | — | 769,592 | ||||||||
(1) | The long-term incentive plan currently permits the grant of awards covering an aggregate of 850,000 units. For more information on our long-term incentive plan, which did not require approval by our limited partners, refer to Item 11. “Executive Compensation — Components of Compensation.” |
Item 13. | Certain Relationships and Related Transactions, and Director Independence |
Operational Stage: | |||
Distributions of Available Cash to our General Partner and its affiliates | We will generally make cash distributions to the unitholders and to our General Partner, in accordance with their pro rata interest. In addition, if distributions exceed the minimum quarterly distribution and other higher target levels, our General Partner will be entitled to increasing percentages of the distributions, up to 48% of the distributions above the highest target level. Currently, our distribution to our general partner related to its incentive distribution rights is at the highest level. | ||
Payments to our General Partner and its affiliates | We reimburse DCP Midstream, LLC and its affiliates $10.1 million per year, adjusted annually by changes in the Consumer Price Index, for the provision of various general and administrative services for our benefit. For further information regarding the reimbursement, please see the “Omnibus Agreement” section below. | ||
Withdrawal or removal of our General Partner | If our General Partner withdraws or is removed, its general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests. | ||
Liquidation Stage: | |||
Liquidation | Upon our liquidation, the partners, including our General Partner, will be entitled to receive liquidating distributions according to their respective capital account balances. | ||
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Terms | Effective Date | Fee | ||||
(Millions) | ||||||
Annual fee | 2006 | $ | 5.1 | |||
Wholesale propane logistics business | November 2006 | 2.0 | ||||
Southern Oklahoma | May 2007 | 0.2 | ||||
Discovery | July 2007 | 0.2 | ||||
Additional services | August 2007 | 0.6 | ||||
Momentum Energy Group, Inc. | August 2007 | 1.6 | ||||
Michigan Pipeline & Processing, LLC | October 2008 | 0.4 | ||||
Total | $ | 10.1 | ||||
• | DCP Midstream, LLC’s obligation to indemnify us for certain liabilities and our obligation to indemnify DCP Midstream, LLC for certain liabilities; | |
• | DCP Midstream, LLC’s obligation to continue to maintain its credit support, including without limitation guarantees and letters of credit, for our obligations related to derivative financial instruments, such as commodity price derivative contracts, to the extent that such credit support arrangements were in effect as of December 7, 2005 until the earlier of December 7, 2010 or when we obtain an investment grade credit rating from either Moody’s Investor Services, Inc. or Standard & Poor’s Ratings Group with respect to any of our unsecured indebtedness; and | |
• | DCP Midstream, LLC’s obligation to continue to maintain its credit support, including without limitation guarantees and letters of credit, for our obligations related to commercial contracts with respect to its business or operations that were in effect at the closing of our initial public offering until the expiration of such contracts. |
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• | approved by the conflicts committee; | |
• | approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates; | |
• | on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or | |
• | fair and reasonable to us, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us. |
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Item 14. | Principal Accounting Fees and Services |
Year Ended December 31, | ||||||||
Type of Fees | 2008 | 2007 | ||||||
(Millions) | ||||||||
Audit Fees(a) | $ | 1.6 | $ | 1.9 | ||||
(a) | Audit Fees are fees billed by Deloitte for professional services for the audit of our consolidated financial statements included in our annual report onForm 10-K and review of financial statements included in our quarterly reports onForm 10-Q, services that are normally provided by Deloitte in connection with statutory and regulatory filings or engagements or any other service performed by Deloitte to comply with generally accepted auditing standards and include comfort and consent letters in connection with Securities and Exchange Commission filings and financing transactions. |
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Item 15. | Exhibits and Financial Statement Schedules |
(a) | Schedule II — Consolidated Valuation and Qualifying Accounts and Reserves |
(b) | Consolidated Financial Statements of Discovery Producer Services LLC and Financial Statements of DCP East Texas Holdings, LLC |
(c) | Exhibits |
(a) | Financial Statement Schedules |
Charged to | Credit to | |||||||||||||||||||||||
Balance at | Consolidated | Charged to | Consolidated | Balance at | ||||||||||||||||||||
Beginning of | Statements of | Other | Deductions/ | Statements of | End of | |||||||||||||||||||
Period | Operations | Accounts(a) | Other | Operations | Period | |||||||||||||||||||
(Millions) | ||||||||||||||||||||||||
December 31, 2008 | ||||||||||||||||||||||||
Allowance for doubtful accounts | $ | 1.2 | $ | (0.5 | ) | $ | — | $ | (0.1 | ) | $ | — | $ | 0.6 | ||||||||||
Environmental | 1.7 | 0.5 | — | (0.3 | ) | — | 1.9 | |||||||||||||||||
Other(b) | — | 2.6 | — | — | — | 2.6 | ||||||||||||||||||
$ | 2.9 | $ | 2.6 | $ | — | $ | (0.4 | ) | $ | — | $ | 5.1 | ||||||||||||
December 31, 2007 | ||||||||||||||||||||||||
Allowance for doubtful accounts | $ | 0.3 | $ | 0.8 | $ | 0.2 | $ | (0.1 | ) | $ | — | $ | 1.2 | |||||||||||
Environmental | 0.1 | 0.1 | 1.6 | (0.1 | ) | — | 1.7 | |||||||||||||||||
Other(b) | 0.3 | — | — | (0.3 | ) | — | — | |||||||||||||||||
$ | 0.7 | $ | 0.9 | $ | 1.8 | $ | (0.5 | ) | $ | — | $ | 2.9 | ||||||||||||
December 31, 2006 | ||||||||||||||||||||||||
Allowance for doubtful accounts | $ | 0.3 | $ | 0.3 | $ | — | $ | (0.3 | ) | $ | — | $ | 0.3 | |||||||||||
Environmental | 0.1 | — | — | — | — | 0.1 | ||||||||||||||||||
Other(b) | — | 0.3 | — | — | — | 0.3 | ||||||||||||||||||
$ | 0.4 | $ | 0.6 | $ | — | $ | (0.3 | ) | $ | — | $ | 0.7 | ||||||||||||
(a) | Related to acquisition of certain subsidiaries of Momentum Energy Group, Inc. | |
(b) | Principally consists of other contingency liabilities, which are included in other current liabilities. |
(b) | Financial Statements |
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Discovery Producer Services LLC
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December 31, | ||||||||
2008 | 2007 | |||||||
(In thousands) | ||||||||
ASSETS | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 42,052 | $ | 38,509 | ||||
Trade accounts receivable: | ||||||||
Affiliate | 202 | 22,467 | ||||||
Other | 1,899 | 5,847 | ||||||
Insurance receivable | 3,373 | 5,692 | ||||||
Inventory | 519 | 483 | ||||||
Other current assets | 2,933 | 5,037 | ||||||
Total current assets | 50,978 | 78,035 | ||||||
Restricted cash | 3,470 | 6,222 | ||||||
Property, plant, and equipment, net | 370,482 | 368,228 | ||||||
Total assets | $ | 424,930 | $ | 452,485 | ||||
LIABILITIES AND MEMBERS’ CAPITAL | ||||||||
Current liabilities: | ||||||||
Accounts payable: | ||||||||
Affiliate | $ | 3,125 | $ | 8,106 | ||||
Other | 34,779 | 17,617 | ||||||
Accrued liabilities | 5,714 | 6,439 | ||||||
Other current liabilities | 1,616 | 1,658 | ||||||
Total current liabilities | 45,234 | 33,820 | ||||||
Noncurrent accrued liabilities | 19,771 | 12,216 | ||||||
Members’ capital | 359,925 | 406,449 | ||||||
Total liabilities and members’ capital | $ | 424,930 | $ | 452,485 | ||||
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Years Ended December 31, | ||||||||||||
2008 | 2007 | 2006 | ||||||||||
(In thousands) | ||||||||||||
Revenues: | ||||||||||||
Product sales: | ||||||||||||
Affiliate | $ | 207,706 | $ | 216,889 | $ | 148,385 | ||||||
Third-party | 1,324 | 5,251 | — | |||||||||
Gas and condensate transportation services: | ||||||||||||
Affiliate | 782 | 979 | 3,835 | |||||||||
Third-party | 13,308 | 15,553 | 14,668 | |||||||||
Gathering and processing services: | ||||||||||||
Affiliate | 1,506 | 3,092 | 8,605 | |||||||||
Third-party | 12,709 | 17,767 | 19,473 | |||||||||
Other revenues | 3,913 | 1,141 | 2,347 | |||||||||
Total revenues | 241,248 | 260,672 | 197,313 | |||||||||
Costs and expenses: | ||||||||||||
Product cost and shrink replacement: | ||||||||||||
Affiliate | 83,576 | 93,722 | 66,890 | |||||||||
Third-party | 63,422 | 61,982 | 52,662 | |||||||||
Operating and maintenance expenses: | ||||||||||||
Affiliate | 8,836 | 5,579 | 5,276 | |||||||||
Third-party | 27,834 | 23,409 | 17,773 | |||||||||
Depreciation and accretion | 21,324 | 25,952 | 25,562 | |||||||||
Taxes other than income | 1,439 | 1,330 | 1,114 | |||||||||
General and administrative expenses — affiliate | 4,500 | 2,280 | 2,150 | |||||||||
Other (income) expense, net | (3,511 | ) | 534 | 283 | ||||||||
Total costs and expenses | 207,420 | 214,788 | 171,710 | |||||||||
Operating income | 33,828 | 45,884 | 25,603 | |||||||||
Interest income | (650 | ) | (1,799 | ) | (2,404 | ) | ||||||
Foreign exchange (gain) loss | 78 | (388 | ) | (2,076 | ) | |||||||
Net income | $ | 34,400 | $ | 48,071 | $ | 30,083 | ||||||
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Williams | ||||||||||||||||||||
Williams | Partners | DCP Assets | ||||||||||||||||||
Energy, | Operating | Holding, | ||||||||||||||||||
L.L.C. | LLC | LP | Total | |||||||||||||||||
Balance, December 31, 2005 | $ | 87,806 | $ | 170,532 | $ | 155,298 | $ | 413,636 | ||||||||||||
Contributions | 800 | 1,600 | 11,109 | 13,509 | ||||||||||||||||
Distributions | (10,798 | ) | (16,400 | ) | (16,400 | ) | (43,598 | ) | ||||||||||||
Net income | 6,017 | 12,033 | 12,033 | 30,083 | ||||||||||||||||
Balance at December 31, 2006 | 83,825 | 167,765 | 162,040 | 413,630 | ||||||||||||||||
Contributions | — | — | 3,920 | 3,920 | ||||||||||||||||
Distributions | (7,233 | ) | (28,270 | ) | (23,669 | ) | (59,172 | ) | ||||||||||||
Net income | 2,602 | 26,241 | 19,228 | 48,071 | ||||||||||||||||
Sale of Williams Energy, L.L.C.’s 20% interest to Williams Partners Operating LLC | (79,194 | ) | 79,194 | — | — | |||||||||||||||
Balance at December 31, 2007 | — | 244,930 | 161,519 | 406,449 | ||||||||||||||||
Contributions | — | 5,700 | 7,376 | 13,076 | ||||||||||||||||
Distributions | — | (56,400 | ) | (37,600 | ) | (94,000 | ) | |||||||||||||
Net income | — | 20,641 | 13,759 | 34,400 | ||||||||||||||||
Balance at December 31, 2008 | $ | — | $ | 214,871 | $ | 145,054 | $ | 359,925 | ||||||||||||
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Years Ended December 31, | ||||||||||||
2008 | 2007 | 2006 | ||||||||||
(In thousands) | ||||||||||||
OPERATING ACTIVITIES: | ||||||||||||
Net income | $ | 34,400 | $ | 48,071 | $ | 30,083 | ||||||
Adjustments to reconcile to cash provided by operations: | ||||||||||||
Depreciation and accretion | 21,324 | 25,952 | 25,562 | |||||||||
Net loss on disposal of equipment | 175 | 603 | — | |||||||||
Cash provided (used) by changes in assets and liabilities: | ||||||||||||
Trade accounts receivable | 26,213 | (9,389 | ) | 26,599 | ||||||||
Insurance receivable | 2,319 | 6,931 | (12,147 | ) | ||||||||
Inventory | (36 | ) | 93 | 348 | ||||||||
Other current assets | 2,104 | (802 | ) | (1,911 | ) | |||||||
Accounts payable | 5,932 | (7,540 | ) | (6,062 | ) | |||||||
Accrued liabilities | (725 | ) | 1,320 | (1,086 | ) | |||||||
Other current liabilities | (52 | ) | (3,147 | ) | 2,070 | |||||||
Net cash provided by operating activities | 91,654 | 62,092 | 63,456 | |||||||||
INVESTING ACTIVITIES: | ||||||||||||
Decrease in restricted cash | 2,752 | 22,551 | 15,786 | |||||||||
Property, plant, and equipment: | ||||||||||||
Capital expenditures | (16,188 | ) | (31,739 | ) | (33,516 | ) | ||||||
Proceeds from sale of property, plant and equipment | — | 649 | — | |||||||||
Change in accounts payable — capital expenditures | 6,249 | 2,625 | 568 | |||||||||
Net cash used by investing activities | (7,187 | ) | (5,914 | ) | (17,162 | ) | ||||||
FINANCING ACTIVITIES: | ||||||||||||
Distributions to members | (94,000 | ) | (59,172 | ) | (43,598 | ) | ||||||
Capital contributions | 13,076 | 3,920 | 13,509 | |||||||||
Net cash used by financing activities | (80,924 | ) | (55,252 | ) | (30,089 | ) | ||||||
Increase in cash and cash equivalents | 3,543 | 926 | 16,205 | |||||||||
Cash and cash equivalents at beginning of period | 38,509 | 37,583 | 21,378 | |||||||||
Cash and cash equivalents at end of period | $ | 42,052 | $ | 38,509 | $ | 37,583 | ||||||
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Note 1. | Organization and Description of Business |
Note 2. | Summary of Significant Accounting Policies |
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Note 3. | Related Party Transactions |
• | sales to Williams of NGLs to which we take title and excess gas at current market prices for the products and | |
• | processing and sales of natural gas liquids and transportation of gas and condensate for DCP’s affiliates, Texas Eastern Corporation and ConocoPhillips Company. |
Years Ended December 31, | ||||||||||||
2008 | 2007 | 2006 | ||||||||||
(In thousands) | ||||||||||||
Williams | $ | 207,782 | $ | 217,012 | $ | 148,543 | ||||||
Texas Eastern Corporation | 1,953 | 3,912 | 12,282 | |||||||||
ConocoPhillips | 259 | 36 | — | |||||||||
Total | $ | 209,994 | $ | 220,960 | $ | 160,825 | ||||||
• | direct payroll and employee benefit costs incurred on our behalf by Williams, and | |
• | rental expense under a10-year leasing agreement for pipeline capacity through 2015 from Texas Eastern Transmission, LP (an affiliate of DCP) |
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Years Ended December 31, | ||||||||||||
2008 | 2007 | 2006 | ||||||||||
(In thousands) | ||||||||||||
Capitalized labor | $ | 317 | $ | 222 | $ | 373 | ||||||
Capitalized project fee | 375 | 651 | 538 | |||||||||
$ | 692 | $ | 873 | $ | 911 | |||||||
Note 4. | Property, Plant, and Equipment |
Estimated | ||||||||||||
Years Ended December 31, | Depreciable | |||||||||||
2008 | 2007 | Lives | ||||||||||
(In thousands) | ||||||||||||
Property, plant, and equipment: | ||||||||||||
Construction work in progress | $ | 76,302 | $ | 66,550 | ||||||||
Buildings | 5,054 | 4,950 | 25 — 35 years | |||||||||
Land and land rights | 5,575 | 2,491 | 0 — 35 years | |||||||||
Transportation lines | 305,172 | 311,368 | 25 — 35 years | |||||||||
Plant and other equipment | 216,189 | 200,722 | 25 — 35 years | |||||||||
Total property, plant, and equipment | 608,292 | 586,081 | ||||||||||
Less accumulated depreciation | 237,810 | 217,853 | ||||||||||
Net property, plant, and equipment | $ | 370,482 | $ | 368,228 | ||||||||
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Years Ended December 31, | ||||||||
2008 | 2007 | |||||||
(In thousands) | ||||||||
Balance at January 1 | $ | 12,118 | $ | 3,728 | ||||
Accretion expense | 1,082 | 422 | ||||||
Estimate revisions | 3,327 | 7,554 | ||||||
Liabilities incurred | 3,157 | 414 | ||||||
Balance at December 31 | $ | 19,684 | $ | 12,118 | ||||
Note 5. | Leasing Activities |
(In thousands) | ||||
2009 | $ | 1,241 | ||
2010 | 1,241 | |||
2011 | 1,241 | |||
2012 | 1,241 | |||
2013 | 1,241 | |||
Thereafter | 2,105 | |||
$ | 8,310 | |||
Note 6. | Financial Instruments and Concentrations of Credit Risk |
2008 | 2007 | |||||||||||||||
Carrying | Fair | Carrying | Fair | |||||||||||||
Amount | Value | Amount | Value | |||||||||||||
(In thousands) | ||||||||||||||||
Cash and cash equivalents | $ | 42,052 | $ | 42,052 | $ | 38,509 | $ | 38,509 | ||||||||
Restricted cash | 3,470 | 3,470 | 6,222 | 6,222 |
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![](https://capedge.com/proxy/10-K/0000950134-09-004580/d66661d6666103.gif)
Deloitte & Touche LLP Suite 3600 555 Seventeenth Street Denver, CO80202-3942 USA | ||
Tel: +1 303 292 5400 Fax: +1 303 312 4000 www.deloitte.com |
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December 31, | ||||||||
2008 | 2007 | |||||||
ASSETS | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 13.9 | $ | 4.8 | ||||
Accounts receivable: | ||||||||
Trade, net of allowance for doubtful accounts of $0.4 million and $0.5 million, respectively | 14.1 | 16.0 | ||||||
Affiliates | 20.7 | 64.5 | ||||||
Other | 1.1 | 0.8 | ||||||
Other | 0.4 | 0.4 | ||||||
Total current assets | 50.2 | 86.5 | ||||||
Property, plant and equipment, net | 253.4 | 236.5 | ||||||
Total assets | $ | 303.6 | $ | 323.0 | ||||
LIABILITIES AND PARTNERS’ EQUITY | ||||||||
Current liabilities: | ||||||||
Accounts payable: | ||||||||
Trade | $ | 25.8 | $ | 53.6 | ||||
Affiliates | 2.4 | 1.5 | ||||||
Other | 0.9 | 2.9 | ||||||
Operating accrual | 1.8 | 1.3 | ||||||
Capital spending accrual | 5.1 | 2.7 | ||||||
Other | 2.4 | 3.7 | ||||||
Total current liabilities | 38.4 | 65.7 | ||||||
Deferred income taxes | 1.7 | 1.7 | ||||||
Other long-term liabilities | 0.6 | 0.5 | ||||||
Total liabilities | 40.7 | 67.9 | ||||||
Commitments and contingent liabilities | ||||||||
Partners’ equity | 262.9 | 255.1 | ||||||
Total liabilities and partners’ equity | $ | 303.6 | $ | 323.0 | ||||
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Years Ended December 31, | ||||||||||||
2008 | 2007 | 2006 | ||||||||||
Operating revenues: | ||||||||||||
Sales of natural gas, NGLs and condensate | $ | 202.8 | $ | 179.8 | $ | 177.7 | ||||||
Sales of natural gas, NGLs and condensate to affiliates | 313.7 | 270.9 | 286.6 | |||||||||
Transportation and processing services | 28.7 | 22.2 | 21.9 | |||||||||
Transportation and processing services to affiliates | 0.2 | 0.1 | 0.3 | |||||||||
Losses from non-trading derivative activity — affiliates | (0.6 | ) | (0.1 | ) | (1.1 | ) | ||||||
Total operating revenues | 544.8 | 472.9 | 485.4 | |||||||||
Operating costs and expenses: | ||||||||||||
Purchases of natural gas and NGLs | 419.7 | 357.8 | 376.0 | |||||||||
Purchases of natural gas and NGLs from affiliates | 0.1 | 1.1 | 9.3 | |||||||||
Operating and maintenance expense | 34.5 | 27.2 | 24.4 | |||||||||
Depreciation expense | 16.7 | 15.8 | 14.6 | |||||||||
General and administrative expense | 0.7 | 1.8 | 0.2 | |||||||||
General and administrative expense — affiliate | 8.5 | 10.3 | 11.3 | |||||||||
Total operating costs and expenses | 480.2 | 414.0 | 435.8 | |||||||||
Operating income | 64.6 | 58.9 | 49.6 | |||||||||
Interest income | 0.4 | 0.3 | — | |||||||||
Income before income taxes | 65.0 | 59.2 | 49.6 | |||||||||
Income tax expense | 0.5 | 0.7 | 1.8 | |||||||||
Net income | $ | 64.5 | $ | 58.5 | $ | 47.8 | ||||||
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Balance, January 1, 2006 | $ | 194.0 | ||
Net change in parent advances | (38.1 | ) | ||
Net income | 47.8 | |||
Balance, December 31, 2006 | 203.7 | |||
Net change in parent advances | (17.1 | ) | ||
Contributions | 54.5 | |||
Distributions | (44.5 | ) | ||
Net income | 58.5 | |||
Balance, December 31, 2007 | 255.1 | |||
Contributions | 29.5 | |||
Distributions | (86.2 | ) | ||
Net income | 64.5 | |||
Balance, December 31, 2008 | $ | 262.9 | ||
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Year Ended December 31, | ||||||||||||
2008 | 2007 | 2006 | ||||||||||
CASH FLOWS FROM OPERATING ACTIVITIES: | ||||||||||||
Net income | $ | 64.5 | $ | 58.5 | $ | 47.8 | ||||||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||||||
Depreciation expense | 16.7 | 15.8 | 14.6 | |||||||||
Deferred income taxes | (0.1 | ) | (0.1 | ) | 1.8 | |||||||
Other, net | (0.1 | ) | (0.1 | ) | 0.1 | |||||||
Change in operating assets and liabilities which provided (used) cash: | ||||||||||||
Accounts receivable | 45.9 | (50.6 | ) | 0.3 | ||||||||
Accounts payable | (28.7 | ) | 10.2 | (12.6 | ) | |||||||
Other current assets and liabilities | (0.8 | ) | 2.9 | (1.0 | ) | |||||||
Other non-current assets and liabilities | — | — | (0.2 | ) | ||||||||
Net cash provided by operating activities | 97.4 | 36.6 | 50.8 | |||||||||
CASH FLOWS FROM INVESTING ACTIVITIES: | ||||||||||||
Capital expenditures | (31.6 | ) | (24.5 | ) | (12.8 | ) | ||||||
Proceeds from sales of assets | — | — | 0.1 | |||||||||
Net cash used in investing activities | (31.6 | ) | (24.5 | ) | (12.7 | ) | ||||||
CASH FLOWS FROM FINANCING ACTIVITIES: | ||||||||||||
Net change in parent advances | — | (17.1 | ) | (38.1 | ) | |||||||
Distributions | (86.2 | ) | (44.5 | ) | — | |||||||
Contributions | 29.5 | 54.3 | — | |||||||||
Net cash used in financing activities | (56.7 | ) | (7.3 | ) | (38.1 | ) | ||||||
Net change in cash and cash equivalents | 9.1 | 4.8 | — | |||||||||
Cash and cash equivalents, beginning of period | 4.8 | — | — | |||||||||
Cash and cash equivalents, end of period | $ | 13.9 | $ | 4.8 | $ | — | ||||||
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1. | Description of Business and Basis of Presentation |
2. | Summary of Significant Accounting Policies |
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• | significant adverse change in legal factors or business climate; | |
• | a current-period operating or cash flow loss combined with a history of operating or cash flow losses, or a projection or forecast that demonstrates continuing losses associated with the use of a long-lived asset; | |
• | an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of a long-lived asset; | |
• | significant adverse changes in the extent or manner in which an asset is used, or in its physical condition; | |
• | a significant adverse change in the market value of an asset; or |
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• | a current expectation that, more likely than not, an asset will be sold or otherwise disposed of before the end of its estimated useful life. |
• | Fee-based arrangements —Under fee-based arrangements, we receive a fee or fees for one or more of the following services: gathering, compressing, treating, processing, or transporting of natural gas. Our fee-based arrangements include natural gas purchase arrangements pursuant to which we purchase natural gas at the wellhead, or other receipt points, at an index related price at the delivery point less a specified amount, generally the same as the fees we would otherwise charge for gathering of natural gas from the wellhead location to the delivery point. The revenue we earn is directly related to the volume of natural gas that flows through our systems and is not directly dependent on commodity prices. To the extent a sustained decline in commodity prices results in a decline in volumes, however, our revenues from these arrangements would be reduced. | |
• | Percent-of-proceeds arrangements —Underpercent-of-proceeds arrangements, we generally purchase natural gas from producers at the wellhead, or other receipt points, gather the wellhead natural gas through our gathering system, treat and process the natural gas, and then sell the resulting residue natural gas and NGLs based on index prices from published index market prices. We remit to the producers either anagreed-upon percentage of the actual proceeds that we receive from our sales of the residue natural gas and NGLs, or anagreed-upon percentage of the proceeds based on index related prices for the natural gas and the NGLs, regardless of the actual amount of the sales proceeds we receive. Certain of these arrangements may also result in our returning all or a portion of the residue natural gasand/or the NGLs to the producer, in lieu of returning sales proceeds. Our revenues underpercent-of-proceeds arrangements correlate directly with the price of natural gasand/or NGLs. | |
• | Keep-whole arrangements — Under the terms of a keep-whole processing contract, we gather raw natural gas from the producer for processing, sell the NGLs and return to the producer residue natural gas with a British thermal unit, or Btu, content equivalent to the Btu content of the natural gas gathered. This arrangement keeps the producer whole to the thermal value of the natural gas received. Under these types of contracts, we are exposed to the “frac spread.” The frac spread is the difference between the value of the NGLs extracted from processing and the value of the Btu equivalent of the residue natural gas. We benefit in periods when NGL prices are higher relative to natural gas prices. |
• | Persuasive evidence of an arrangement exists —Our customary practice is to enter into a written contract, executed by both us and the customer. | |
• | Delivery —Delivery is deemed to have occurred at the time custody is transferred, or in the case of fee-based arrangements, when the services are rendered. To the extent we retain product as inventory, |
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delivery occurs when the inventory is subsequently sold and custody is transferred to the third party purchaser. |
• | The fee is fixed or determinable — We negotiate the fee for our services at the outset of our fee-based arrangements. In these arrangements, the fees are nonrefundable. For other arrangements, the amount of revenue, based on contractual terms, is determinable when the sale of the applicable product has been completed upon delivery and transfer of custody. | |
• | Collectibility is probable —Collectibility is evaluated on acustomer-by-customer basis. New and existing customers are subject to a credit review process, which evaluates the customers’ financial position (for example, credit metrics, liquidity and credit rating) and their ability to pay. If collectibility is not considered probable at the outset of an arrangement in accordance with our credit review process, revenue is recognized until the cash is collected. |
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3. | Recent Accounting Pronouncements |
• | defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date; | |
• | establishes a framework for measuring fair value; | |
• | establishes a three-level hierarchy for fair value measurements based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date; |
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• | nullifies the guidance in Emerging Issues Task Force, or EITF,02-3,Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Involved in Energy Trading and Risk Management Activities, which required the deferral of profit at inception of a transaction involving a derivative financial instrument in the absence of observable data supporting the valuation technique; and | |
• | significantly expands the disclosure requirements around instruments measured at fair value. |
4. | Agreements and Transactions with Affiliates |
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Year Ended December 31, | ||||||||||||
2008 | 2007 | 2006 | ||||||||||
(Millions) | ||||||||||||
DCP Midstream, LLC: | ||||||||||||
Sales of natural gas, NGLs and condensate | $ | 284.4 | $ | 263.2 | $ | 276.3 | ||||||
Losses from non-trading derivative activity | $ | 0.6 | $ | 0.1 | $ | 1.1 | ||||||
General and administrative expense | $ | 8.5 | $ | 10.3 | $ | 11.3 | ||||||
Duke Energy Corporation: | ||||||||||||
Sales of natural gas, NGLs and condensate | $ | — | $ | — | $ | 6.6 | ||||||
Purchases of natural gas and NGLs | $ | — | $ | — | $ | 0.1 | ||||||
ConocoPhillips: | ||||||||||||
Sales of natural gas, NGLs and condensate | $ | 29.3 | $ | 7.7 | $ | 3.7 | ||||||
Transportation and processing services | $ | 0.2 | $ | 0.1 | $ | 0.3 | ||||||
Purchases of natural gas and NGLs | $ | 0.1 | $ | 1.1 | $ | 9.2 |
December 31, | ||||||||
2008 | 2007 | |||||||
(Millions) | ||||||||
DCP Midstream LLC: | ||||||||
Accounts receivable | $ | 20.6 | $ | 64.5 | ||||
Accounts payable | $ | 2.4 | $ | 1.5 | ||||
ConocoPhillips: | ||||||||
Accounts receivable | $ | 0.1 | $ | — |
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5. | Property, Plant and Equipment |
Depreciable | December 31, | |||||||||||
Life | 2008 | 2007 | ||||||||||
(Millions) | ||||||||||||
Gathering systems | 15 – 30 Years | $ | 92.8 | $ | 78.9 | |||||||
Processing plants | 25 – 30 Years | 219.8 | 218.5 | |||||||||
Transportation | 25 – 30 Years | 42.6 | 40.0 | |||||||||
Underground storage | 20 – 50 Years | 0.1 | — | |||||||||
General plant | 3 – 5 Years | 7.9 | 7.8 | |||||||||
Construction work in progress | 30.3 | 14.7 | ||||||||||
393.5 | 359.9 | |||||||||||
Accumulated depreciation | (140.1 | ) | (123.4 | ) | ||||||||
Property, plant and equipment, net | $ | 253.4 | $ | 236.5 | ||||||||
6. | Risk Management and Derivative Activities, Credit Risk and Financial Instruments |
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7. | Asset Retirement Obligations |
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8. | Income Taxes |
9. | Commitments and Contingent Liabilities |
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10. | Supplemental Cash Flow Information |
Year Ended December 31, | ||||||||||||
2008 | 2007 | 2006 | ||||||||||
(Millions) | ||||||||||||
Non-cash investing and financing activities: | ||||||||||||
Non-cash additions of property, plant and equipment | $ | 2.0 | $ | 0.9 | $ | 3.1 | ||||||
Accrued contributions related to reimbursements | $ | — | $ | 0.2 | $ | — |
11. | Subsequent Events |
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Charged to | ||||||||||||||||
Balance at | Consolidated | Balance at | ||||||||||||||
Beginning of | Statements of | Deductions/ | End of | |||||||||||||
Period | Operations | Other | Period | |||||||||||||
(Millions) | ||||||||||||||||
December 31, 2008 | ||||||||||||||||
Allowance for doubtful accounts | $ | 0.5 | $ | (0.1 | ) | $ | — | $ | 0.4 | |||||||
December 31, 2007 | ||||||||||||||||
Allowance for doubtful accounts | $ | 0.2 | $ | 0.3 | $ | — | $ | 0.5 | ||||||||
Environmental | 0.3 | — | (0.3 | ) | — | |||||||||||
$ | 0.5 | $ | 0.3 | $ | (0.3 | ) | $ | 0.5 | ||||||||
December 31, 2006 | ||||||||||||||||
Allowance for doubtful accounts | $ | 0.1 | $ | 0.1 | $ | — | $ | 0.2 | ||||||||
Environmental | 0.4 | — | (0.1 | ) | 0.3 | |||||||||||
$ | 0.5 | $ | 0.1 | $ | (0.1 | ) | $ | 0.5 | ||||||||
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(c) | Exhibits |
Exhibit | ||||
Number | Description | |||
3 | .1 | Amendment No. 1 to Amended and Restated Limited Liability Company Agreement of DCP Midstream GP, LLC dated as of January 20, 2009 and Amended and Restated Limited Liability Company Agreement of DCP Midstream GP, LLC dated December 7, 2005. | ||
10 | .1* | Purchase and Sale Agreement, dated March 7, 2007, between Anadarko Gathering Company, Anadarko Energy Services Company and DCP Midstream Partners, LP (attached as Exhibit 99.1 to DCP Midstream Partners, LP’s current report onForm 8-K (FileNo. 001-32678) filed with the SEC on May 14, 2007). | ||
10 | .2* | Bridge Credit Agreement, dated May 9, 2007 among DCP Midstream Operating, LP, DCP Midstream Partners, LP and Wachovia Bank, National Association (attached as Exhibit 99.2 to DCP Midstream Partners, LP’s current report onForm 8-K (FileNo. 001-32678) filed with the SEC on May 14, 2007). | ||
10 | .3* | Third Amendment to Omnibus Agreement, dated May 9, 2007, among DCP Midstream, LLC, DCP Midstream Partners, LP, DCP Midstream GP, LP, DCP Midstream GP, LLC, and DCP Midstream Operating, LP (attached as Exhibit 99.3 to DCP Midstream Partners LP’s current report onForm 8-K (FileNo. 001-32678) filed with the SEC on May 14, 2007). | ||
10 | .4* | First Amendment to Credit Agreement, dated May 9, 2007, among DCP Midstream Operating, LP, DCP Midstream Partners, LP and Wachovia Bank, National Association (attached as Exhibit 99.4 to DCP Midstream Partners LP’s current report onForm 8-K (FileNo. 001-32678) filed with the SEC on May 14, 2007). | ||
10 | .5* | Contribution and Sale Agreement, dated May 21, 2007, between Gas Supply Resources Holdings, Inc., DCP Midstream, LLC and DCP Midstream Partners, LP (attached as Exhibit 10.1 to DCP Midstream Partners LP’s current report onForm 8-K (FileNo. 001-32678) filed with the SEC on May 25, 2007). | ||
10 | .6* | Common Unit Purchase Agreement, dated May 21, 2007, by and among DCP Midstream Partners, LP and the Purchasers listed therein (attached as Exhibit 10.1 to DCP Midstream Partners LP’s current report onForm 8-K (FileNo. 001-32678) filed with the SEC on May 25, 2007). | ||
10 | .7* | Contribution Agreement, dated May 23, 2007, among DCP LP Holdings, LP, DCP Midstream, LLC, DCP Midstream GP, LP and DCP Midstream Partners, LP (attached as Exhibit 10.1 to DCP Midstream Partners LP’s current report onForm 8-K (FileNo. 001-32678) filed with the SEC on May 25, 2007). | ||
10 | .8* | Common Unit Purchase Agreement, dated June 19, 2007, by and among DCP Midstream Partners, LP and the Purchasers listed therein (attached as Exhibit 10.1 to DCP Midstream Partners LP’s current report onForm 8-K (FileNo. 001-32678) filed with the SEC on June 25, 2007). | ||
10 | .9* | Registration Rights Agreement, dated June 22, 2007, by and among DCP Midstream Partners, LP and the Purchasers listed therein (attached as Exhibit 10.2 to DCP Midstream Partners LP’s current report onForm 8-K (FileNo. 001-32678) filed with the SEC on June 25, 2007). | ||
10 | .10* | Amended and Restated Credit Agreement, dated June 21, 2007, among DCP Midstream Operating, LP, DCP Midstream Partners, LP and Wachovia Bank, National Association as Administrative Agent (attached as Exhibit 10.1 to DCP Midstream Partners LP’s current report onForm 8-K (FileNo. 001-32678) filed with the SEC on June 27, 2007). | ||
10 | .11* | Fourth Amendment to Omnibus Agreement, dated July 1, 2007, by and among DCP Midstream, LLC, DCP Midstream GP, LLC, DCP Midstream GP, LP, DCP Midstream Partners, LP, and DCP Midstream Operating, LP (attached as Exhibit 10.2 to DCP Midstream Partners LP’s current report onForm 8-K (FileNo. 001-32678) filed with the SEC on July 2, 2007). | ||
10 | .12* | Amended and Restated Limited Liability Company Agreement of DCP East Texas Holdings, LLC, dated July 1, 2007, between DCP Midstream, LLC and DCP Assets Holding, LP (attached as Exhibit 10.3 to DCP Midstream Partners LP’s current report onForm 8-K (FileNo. 001-32678) filed with the SEC on July 2, 2007). | ||
10 | .13* | Fifth Amendment to Omnibus Agreement dated August 7, 2007, among DCP Midstream, LLC, DCP Midstream Partners, LP, DCP Midstream GP, LP, DCP Midstream GP, LLC, and DCP Midstream Operating, LP (attached as Exhibit 10.1 to DCP Midstream Partners, LPForm 10-Q (FileNo. 001-32678) filed with the Securities and Exchange Commission on August 9, 2007). |
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Exhibit | ||||
Number | Description | |||
10 | .14* | Sixth Amendment to Omnibus Agreement, dated August 29, 2007, among DCP Midstream, LLC, DCP Midstream Partners, LP, DCP Midstream GP, LP, DCP Midstream GP, LLC, and DCP Midstream Operating, LP (attached as Exhibit 10.1 to DCP Midstream Partners LP’s current report onForm 8-K (FileNo. 001-32678) filed with the SEC on September 5, 2007). | ||
10 | .15* | Registration Rights Agreement, dated August 29, 2007, by and among DCP Midstream Partners, LP and the Purchasers listed therein (attached as Exhibit 10.2 to DCP Midstream Partners LP’s current report onForm 8-K (FileNo. 001-32678) filed with the SEC on September 5, 2007). | ||
10 | .16 | Contribution Agreement dated February 24, 2009, among DCP Midstream Partners, LP, DCP LP Holdings, LLC, DCP Midstream GP, LP and DCP Midstream, LLC. | ||
12 | .1 | Ratio of Earnings to Fixed Charges. | ||
21 | .1 | List of Subsidiaries of DCP Midstream Partners, LP. | ||
23 | .1 | Consent of Deloitte & Touche LLP on Consolidated Financial Statements and Financial Statement Schedule of DCP Midstream Partners, LP and the effectiveness of DCP Midstream Partners, LP’s internal control over financial reporting. | ||
23 | .2 | Consent of Ernst & Young LLP on Consolidated Financial Statements of Discovery Producer Services LLC. | ||
23 | .3 | Consent of Deloitte & Touche LLP on Consolidated Financial Statements of DCP East Texas Holdings, LLC. | ||
23 | .4 | Consent of Deloitte & Touche LLP on Consolidated Balance Sheet of DCP Midstream GP, LP. | ||
23 | .5 | Consent of Deloitte & Touche LLP on Consolidated Balance Sheet of DCP Midstream, LLC. | ||
31 | .1 | Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | ||
31 | .2 | Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | ||
32 | .1 | Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | ||
32 | .2 | Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | ||
99 | .1 | Consolidated Balance Sheet of DCP Midstream GP, LP as of December 31, 2008. | ||
99 | .2 | Consolidated Balance Sheet of DCP Midstream, LLC as of December 31, 2008. |
* | Each such exhibit has heretofore been filed with the SEC as part of the filing indicated and is incorporated herein by reference. |
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By: | /s/ DCP Midstream GP, LP |
By: | /s/ DCP Midstream GP, LLC |
By: | /s/ Mark A. Borer |
Title: | President and Chief Executive Officer |
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Signature | Title | Date | ||||
/s/ Mark A. Borer Mark A. Borer | President, Chief Executive Officer and Director (Principal Executive Officer) | March 5, 2009 | ||||
/s/ Angela A. Minas Angela A. Minas | Vice President and Chief Financial Officer (Principal Financial Officer) | March 5, 2009 | ||||
/s/ Scott R. Delmoro Scott R. Delmoro | Chief Accounting Officer (Principal Accounting Officer) | March 5, 2009 | ||||
/s/ Thomas C. O’Connor Thomas C. O’Connor | Chairman of the Board and Director | March 5, 2009 | ||||
/s/ Paul F. Ferguson, Jr. Paul F. Ferguson, Jr. | Director | March 5, 2009 | ||||
/s/ Gregory J. Goff Gregory J. Goff | Director | March 5, 2009 | ||||
/s/ Alan N. Harris Alan N. Harris | Director | March 5, 2009 | ||||
/s/ John E. Lowe John E. Lowe | Director | March 5, 2009 | ||||
/s/ Frank A. McPherson Frank A. McPherson | Director | March 5, 2009 | ||||
/s/ Thomas C. Morris Thomas C. Morris | Director | March 5, 2009 | ||||
/s/ Stephen R. Springer Stephen R. Springer | Director | March 5, 2009 |
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Exhibit | ||||
Number | Description | |||
3 | .1 | Amendment No. 1 to Amended and Restated Limited Liability Company Agreement of DCP Midstream GP, LLC dated as of January 20, 2009 and Amended and Restated Limited Liability Company Agreement of DCP Midstream GP, LLC dated December 7, 2005. | ||
10 | .1* | Purchase and Sale Agreement, dated March 7, 2007, between Anadarko Gathering Company, Anadarko Energy Services Company and DCP Midstream Partners, LP (attached as Exhibit 99.1 to DCP Midstream Partners, LP’s current report onForm 8-K (FileNo. 001-32678) filed with the SEC on May 14, 2007). | ||
10 | .2* | Bridge Credit Agreement, dated May 9, 2007 among DCP Midstream Operating, LP, DCP Midstream Partners, LP and Wachovia Bank, National Association (attached as Exhibit 99.2 to DCP Midstream Partners, LP’s current report onForm 8-K (FileNo. 001-32678) filed with the SEC on May 14, 2007). | ||
10 | .3* | Contribution and Sale Agreement, dated May 9, 2007, among DCP Midstream, LLC, DCP Midstream Partners, LP, DCP Midstream GP, LP, DCP Midstream GP, LLC, and DCP Midstream Operating, LP (attached as Exhibit 99.3 to DCP Midstream Partners LP’s current report onForm 8-K (FileNo. 001-32678) filed with the SEC on May 14, 2007). | ||
10 | .4* | First Amendment to Credit Agreement, dated May 9, 2007, among DCP Midstream Operating, LP, DCP Midstream Partners, LP and Wachovia Bank, National Association (attached as Exhibit 99.4 to DCP Midstream Partners LP’s current report onForm 8-K (FileNo. 001-32678) filed with the SEC on May 14, 2007). | ||
10 | .5* | Contribution Agreement, dated May 21, 2007, among DCP LP Holdings, LP, DCP Midstream, LLC and DCP Midstream Partners, LP (attached as Exhibit 10.1 to DCP Midstream Partners LP’s current report onForm 8-K (FileNo. 001-32678) filed with the SEC on May 25, 2007). | ||
10 | .6* | Common Unit Purchase Agreement, dated May 21, 2007, by and among DCP Midstream Partners, LP and the Purchasers listed therein (attached as Exhibit 10.1 to DCP Midstream Partners LP’s current report onForm 8-K (FileNo. 001-32678) filed with the SEC on May 25, 2007). | ||
10 | .7* | Contribution Agreement, dated May 23, 2007, among DCP Midstream Partners, LP (attached as Exhibit 10.1 to DCP Midstream Partners LP’s current report onForm 8-K (FileNo. 001-32678) filed with the SEC on May 25, 2007). | ||
10 | .8* | Common Unit Purchase Agreement, dated June 19, 2007, among DCP Midstream Partners, LP and the Purchasers listed therein (attached as Exhibit 10.1 to DCP Midstream Partners LP’s current report onForm 8-K (FileNo. 001-32678) filed with the SEC on June 25, 2007). | ||
10 | .9* | Registration Rights Agreement, dated June 22, 2007, by and among DCP Midstream Partners, LP and the Purchasers listed therein (attached as Exhibit 10.2 to DCP Midstream Partners LP’s current report onForm 8-K (FileNo. 001-32678) filed with the SEC on June 25, 2007). | ||
10 | .10* | Amended and Restated Credit Agreement, dated July 1, 2007, among DCP Midstream, LLC and Wachovia Bank, National Association as Administrative Agent (attached as Exhibit 10.1 to DCP Midstream Partners LP’s current report onForm 8-K (FileNo. 001-32678) filed with the SEC on June 27, 2007). | ||
10 | .11* | Fourth Amendment to Omnibus Agreement, dated July 1, 2007, by and among DCP Midstream, LLC, DCP Midstream GP, LLC, DCP Midstream GP, LP, DCP Midstream Partners, LP, and DCP Midstream Operating, LP (attached as Exhibit 10.2 to DCP Midstream Partners LP’s current report onForm 8-K (FileNo. 001-32678) filed with the SEC on July 2, 2007). | ||
10 | .12* | Amended and Restated Limited Liability Company Agreement of DCP East Texas Holdings, LLC, dated July 1, 2007, between DCP Midstream, LLC and DCP Assets Holding, LP (attached as Exhibit 10.3 to DCP Midstream Partners LP’s current report onForm 8-K (FileNo. 001-32678) filed with the SEC on July 2, 2007). | ||
10 | .13* | Fifth Amendment to Omnibus Agreement dated August 7, 2007, among DCP Midstream, LLC, DCP Midstream Partners, LP, DCP Midstream GP, LP, DCP Midstream GP, LLC, and DCP Midstream Operating, LP (attached as Exhibit 10.1 to DCP Midstream Partners, LPForm 10-Q (FileNo. 001-32678) filed with the Securities and Exchange Commission on August 9, 2007). |
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Exhibit | ||||
Number | Description | |||
10 | .14* | Sixth Amendment to Omnibus Agreement, dated August 29, 2007, among DCP Midstream, LLC, DCP Midstream Partners, LP, DCP Midstream GP, LP, DCP Midstream GP, LLC, and DCP Midstream Operating, LP (attached as Exhibit 10.1 to DCP Midstream Partners LP’s current report onForm 8-K (FileNo. 001-32678) filed with the SEC on September 5, 2007). | ||
10 | .15* | Registration Rights Agreement, dated August 29, 2007, by and among DCP Midstream Partners, LP and the Purchasers listed therein (attached as Exhibit 10.2 to DCP Midstream Partners LP’s current report onForm 8-K (FileNo. 001-32678) filed with the SEC on September 5, 2007). | ||
10 | .16 | Contribution Agreement dated February 24, 2009, among DCP Midstream Partners, LP, DCP LP Holdings, LLC, DCP Midstream GP, LP and DCP Midstream, LLC. | ||
12 | .1 | Ratio of Earnings to Fixed Charges. | ||
21 | .1 | List of Subsidiaries of DCP Midstream Partners, LP. | ||
23 | .1 | Consent of Deloitte & Touche LLP on Consolidated Financial Statements and Financial Statement Schedule of DCP Midstream Partners, LP and the effectiveness of DCP Midstream Partners, LP’s internal control over financial reporting. | ||
23 | .2 | Consent of Ernst & Young LLP on Consolidated Financial Statements of Discovery Producer Services LLC. | ||
23 | .3 | Consent of Deloitte & Touche LLP on Consolidated Financial Statements of DCP East Texas Holdings, LLC. | ||
23 | .4 | Consent of Deloitte & Touche LLP on Consolidated Balance Sheet of DCP Midstream GP, LP. | ||
23 | .5 | Consent of Deloitte & Touche LLP on Consolidated Balance Sheet of DCP Midstream, LLC. | ||
31 | .1 | Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | ||
31 | .2 | Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | ||
32 | .1 | Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | ||
32 | .2 | Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | ||
99 | .1 | Consolidated Balance Sheet of DCP Midstream GP, LP as of December 31, 2008. | ||
99 | .2 | Consolidated Balance Sheet of DCP Midstream, LLC as of December 31, 2008. |
* | Each such exhibit has heretofore been filed with the SEC as part of the filing indicated and is incorporated herein by reference. |
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