Commodity Price Risk
We are exposed to the impact of market fluctuations in the prices of natural gas, propane, NGLs and condensate as a result of our gathering, processing, storage and sales activities. We employ established policies and procedures to manage our risks associated with these market fluctuations using various commodity derivatives, including forward contracts, swaps and futures. All derivative activity reflected in the combinedconsolidated financial statements for periods prior to December 7, 2005our predecessors was transacted directly by us or DCP Midstream, LLC, and DEFS prior to our initial public offering and was transferredand/or allocated to us, as more fully discussed in Note 1 of the notesNotes to our consolidated financial statements.Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data.” All derivative activity reflected in the consolidated financial statements, from December 7, 2005 and going forwardwhich is not related to our predecessors, has been and will be transacted by us.
For the year ending December 31, 2006,In 2007 we expect that a $1.00 per MMBtu change in price of natural gas, a $0.10 per gallon change in NGL prices and a $5.00 per barrel change in condensate prices would change our annual gross margin by approximately $0.2 million, $0.3$0.4 million and $0.3$0.1 million, respectively. These sensitivities include the effect of our executed hedging strategies executed in September 2005.strategies. Please read “— Quantitative and Qualitative Disclosures about Market Risk — Commodity Price Risk — Hedging Strategies” for more information about these hedging strategies. The magnitude of the impact on gross margin of changes in natural gas, NGL and condensate prices presented may not be representative of the magnitude of the impact on gross margin for different commodity prices or contract portfolios. Prices for these products can also affect our profitability indirectly by influencing the level of drilling activity and related opportunities for our services.
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Valuation — Valuation of a contract’s fair value is validated by an internal group independent of the trading areas of DEFS.group. While common industry practices are used to develop valuation techniques, changes in pricing methodologies or the underlying assumptions could result in significantly different fair values and income recognition. When available, quoted market prices or prices obtained through external sources are used to verifydetermine 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.
Values are adjusted to reflect the credit risk inherent in the transaction as well as the potential impact of liquidating open positions in an orderly manner over a reasonable time period under current conditions. Changes in market prices and management estimates directly affect the estimated fair value of these contracts. Accordingly, it is reasonably possible that such estimates may change in the near term.
Hedging Strategies — We closely monitor the risks associated with these commodity price changes on our future operations and, where appropriate, use various commodity instruments such as natural gas and crude oil contracts to mitigate the effect pricing fluctuations may have on the value of our assets and operations.
In September 2005, weWe executed a series of derivative financial instruments, which have been designated as cash flow hedgeshedges. These financial instruments are intended to hedge the risk of the price risk associated with our forecasted sales ofweakening natural gas, NGLsNGL and condensate.condensate prices. Because of the strong correlation between NGL prices and crude oil prices and the lack of liquidity in the NGL financial market, we have used crude oil swaps to hedge NGL price risk. As a result of these transactions, effective January 1, 2006 we have hedged approximately 80%a significant portion of our expected natural gas and NGL commodity price risk relating to our percentage of proceeds gathering and processing contractsthrough 2010 and condensate commodity price risk relating to condensate recovered from our gathering operations through 2010.
The natural gas and NGL price risk is associated with ourpercentage-of-proceeds arrangements. The condensate price risk is associated with our gathering operations where we recover and sell condensate.2011. The margins we earn from condensate sales are directly correlated with crude oil prices. We continually monitor our hedging program and expect to continue to adjust our hedge position as conditions warrant.
The derivative financial instruments we have entered into are typically referred to as “swap” contracts. These “swap”swap contracts entitle us to receive payment from the counterparty to the contract to the extent that the reference price is below the “swap price”swap price stated in the contract, and we are required to make payment to the counterparty to the extent that the reference price is higher than the “swap price”swap price stated in the contract. The swap contracts we have entered into to hedge our exposure to price risk associated with natural gas relate to the price of natural gas, settle on a monthly basis and provide that the reference price for each settlement period are the monthly index price for natural gas delivered into the Texas Gas Transmission pipeline in the North Louisiana area as published by an independent industry publication. The “swap price” for each of these natural gas hedge contracts is $9.20 per MMBtu, and the notional volume for each period covered, and time periods covered, by these contracts is set forth in the table below. The swap contracts we have entered
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into to hedge our exposure to price risk associated with NGLs and condensate relate to the price of crude oil, settle on a monthly basis and provide that the reference price for each settlement period are the average price for the month in which the Asian-pricing of NYMEX futures contracts for light, sweet crude delivered at Cushing, Oklahoma.oil. The weighted average “swap price” for these crude oil hedge contracts is $63.27 per barrel, and the notional volume for each period covered, and the time periods covered, by these contracts is set forth in the table below.
The counterparties to each of the swap contracts we have entered into are investment-grade rated financial institutions. Under these contracts, we may be required to provide collateral to the counterparties in the event that our potential payment exposure exceeds a predetermined “collateral threshold.” Based on the five-year forward price curve for NYMEX crude oil contracts, our exposure to a counterparty could exceed a predetermined collateral threshold if the forward curve price exceeds $83.50 per barrel of light, sweet crude oil and with the other counterparty if this forward curve price exceeds $96.31$104.52, $88.60 or $76.33 per barrel of light, sweet crude oil. As the swap contracts settle and the notional volume outstanding decreases, the forward curve price at which point collateral is required would be higher. Predetermined collateral thresholds for hedges guaranteed by DCP Midstream, LLC are generally dependent
65
on DEFS’DCP Midstream, LLC’s credit rating and would be reduced to $0 in the event DEFS’DCP Midstream, LLC’s credit rating were to fall below investment grade. DEFSDCP Midstream, LLC has provided guarantees to support thecertain natural gas, NGL and condensate hedging contracts.contracts through 2010.
The following table sets forth additional information about our natural gas and crude oil swaps:swaps used to hedge our natural gas and NGL price risk associated with ourpercentage-or-proceeds arrangements and our condensate price risk associated with our gathering operations:
| | | | | | | | |
Period | | Commodity | | Notional Volume | | Reference Price | | Swap Price |
|
January 2006 — December 2006 | | Natural Gas | | 4,200 MMBtu/d | | Texas Gas Transmission Price(1) | | $9.20/MMBtu |
January 2007 — December 2007 | | Natural Gas | | 4,100 MMBtu/d | | Texas Gas Transmission Price(1) | | $9.20/MMBtu |
January 2008 — December 2008 | | Natural Gas | | 4,000 MMBtu/d | | Texas Gas Transmission Price(1) | | $9.20/MMBtu |
January 2009 — December 2009 | | Natural Gas | | 4,000 MMBtu/d | | Texas Gas Transmission Price(1) | | $9.20/MMBtu |
January 2010 — December 2010 | | Natural Gas | | 3,900 MMBtu/d | | Texas Gas Transmission Price(1) | | $9.20/MMBtu |
January 2006 — December 2006 | | Crude Oil | | 670 Bbls/d | | NYMEX Index Price(2) | | $63.27/Bbl |
January 2007 — December 2007 | | Crude Oil | | 660 Bbls/d | | Asian-pricing of NYMEX Index Price(2)crude oil futures(2) | | $63.27/Bbl |
January 2008 — December 2008 | | Crude Oil | | 650 Bbls/d | | Asian-pricing of NYMEX Index Price(2)crude oil futures(2) | | $63.27/Bbl |
January 2009 — December 2009 | | Crude Oil | | 650 Bbls/d | | Asian-pricing of NYMEX Index Price(2)crude oil futures(2) | | $63.27/Bbl |
January 2010 — December 2010 | | Crude Oil | | 640 Bbls/d | | Asian-pricing of NYMEX Index Price(2)crude oil futures(2) | | $63.27/Bbl |
January 2011 — December 2011 | | Crude Oil | | 350 Bbls/d | | Asian-pricing of NYMEX crude oil futures(2) | | $68.50/Bbl |
| | |
(1) | | NYMEX index price for natural gas delivered into the Texas Gas Transmission pipeline in the North Louisiana area. |
|
(2) | | Monthly average of the daily close prices for the prompt month NYMEX index price for light, sweet crude oil delivered at Cushing, Oklahoma.futures contract (CL). |
At December 31, 2005,2006, the aggregate fair value of the crude oil and natural gas swaps described above was a $1.4$2.5 million gainnet loss and a $0.7$9.4 million loss,net gain, respectively.
In addition, on an infrequent basis, we may allow customers to manage their commodity price risk by offering physical deliveries of natural gas at a fixed price. When we enter into commercial arrangements with a fixed price, we also transact an offsetting financial hedge with another party.party and account for these as fair value hedges. At December 31, 2005,2006, there was onewere no open financial hedgehedges of this nature that had a fair value loss of $0.1 million.
To the extent that a hedge is effective, there is no impact to the consolidated statements of operations until delivery or settlement occurs. Several factors influence the effectiveness of a hedge contract, including the use of contracts with different commodities or unmatched terms. Hedge effectiveness is monitored regularly and measured quarterly.
The fair value of our qualifying hedge positions at a point in time is not necessarily indicative of the results realized when such contracts mature.nature.
For contracts that are designated and qualify as effective hedge positions of future cash flows, or fair values of assets, liabilities or firm commitments, to the extent that the hedge relationships are effective, their market value change impacts are not recognized in current earnings. The unrealized gains or losses on these contracts are deferred in AOCI for cash flow hedges or included in other current or noncurrentlong-term assets or liabilities on the consolidated balance sheets for fair value hedges of firm commitments. Amounts in AOCI are realized in earnings concurrently with the transaction being hedged. However, in instances where the hedging contract no longer qualifies for hedge accounting, amounts included in AOCI through the date of de-designation remain in AOCI until the underlying transaction actually occurs. The derivative contract (if continued as an open position) will be marked to market currently through earnings.
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The fair value of a derivative designated as a fair value hedge is recorded for balance sheet purposes as unrealized gains or unrealized losses on non-trading derivative and hedging instruments. We recognize the gain or loss on the derivative instrument, as well as the offsetting loss or gain on the hedged item in earnings in the current period. All derivatives designated and accounted for as fair value hedges are classified in the same category as the item being hedged in the results of operations.
The fair value of our qualifying interest rate and commodity hedge positions is expected to be realized in future periods, as detailed in the following table. The amount of cash ultimately realized for these contracts will differ from the amounts shown in the following table due to factors such as market volatility, counterparty default and other unforeseen events that could impact the amountand/or realization of these values.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Fair Value of Hedge Contracts as of December 31, 2005 | | | Fair Value of Hedge Contracts as of December 31, 2006 | |
| | | | | | | | Maturity in
| | | | | | | | | | | Maturity in
| | | |
| | Maturity in
| | Maturity in
| | Maturity in
| | 2009 and
| | Total Fair
| | | Maturity in
| | Maturity in
| | Maturity in
| | 2010 and
| | Total Fair
| |
Sources of Fair Value | | 2006 | | 2007 | | 2008 | | Thereafter | | Value | | | 2007 | | 2008 | | 2009 | | Thereafter | | Value | |
| | ($ in millions) | | | | | | | ($ in millions) | | | | | |
|
Prices supported by quoted market prices and other external sources | | $ | (1.8 | ) | | $ | (0.2 | ) | | $ | 0.1 | | | $ | — | | | $ | (1.9 | ) | | $ | 0.5 | | | $ | (1.0 | ) | | $ | (0.8 | ) | | $ | 0.1 | | | $ | (1.2 | ) |
Prices based on models or other valuation techniques | | | (0.5 | ) | | | (1.4 | ) | | | — | | | | 4.4 | | | | 2.5 | | | | 3.0 | | | | 1.7 | | | | 1.9 | | | | 1.9 | | | | 8.5 | |
| | | | | | | | | | | | | | | | | | | | | | |
Total | | $ | (2.3 | ) | | $ | (1.6 | ) | | $ | 0.1 | | | $ | 4.4 | | | $ | 0.6 | | | $ | 3.5 | | | $ | 0.7 | | | $ | 1.1 | | | $ | 2.0 | | | $ | 7.3 | |
| | | | | | | | | | | | | | | | | | | | | | |
The “prices supported by quoted market prices and other external sources” category includes our New York Mercantile Exchange swap positions ininterest rate swaps and our Asian-pricing NYMEX crude oil swaps, which have currently quoted monthly crude oil prices for the next 2936 months. In addition, this category includes our forward positions in natural gas basis swaps at points for whichover-the-counter, or OTC, broker quotes are available. On average, OTC quotes as of December 31, 2006, for natural gas swaps extend 10 monthsone month into the future. These positions are valued against internally developed forward market price curves that are validated and recalibrated against OTC broker quotes. This category also includes “strip” transactions whose prices are obtained from external sources and then modeled to daily or monthly prices as appropriate.
The “Prices“prices based on models and other valuation methods” category includes the value of transactions for which an internally developed price curve was constructed as a result of the long dated nature of the transaction or the illiquidity of the market point.
Normal Purchases and Normal Sales — If a contract qualifies and is designated as a normal purchase or normal sale, no recognition of the contract’s fair value in the consolidated financial statements is required until the associated delivery period occurs.impacts earnings. We have applied this accounting election for contracts involving the purchase or sale of physical natural gas, propane or NGLs in future periods.
Natural Gas Asset-Based MarketingActivities — Our operations of gathering, processing, and transporting natural gas, and the accompanying operations of transporting and marketing of NGLs create commodity price risk due to market fluctuations in commodity prices, primarily with respect to the prices of NGLs, natural gas and crude oil. To the extent possible, we match the pricing of our supply portfolio to our sales portfolio in order to lock in value and reduce our overall commodity price risk. We manage the commodity price risk of our natural gas activitiessupply portfolio and sales portfolio with both physical and financial transactions. ToWe occasionally will enter into financial derivatives to lock in price differentials across the extent possible, we match our natural gas supply portfolioPelico system to our sales portfolio. The majoritymaximize the value of thispipeline capacity. These financial activity is in the current or nearby month and isderivatives are accounted for usingmark-to-market accounting with changes in fair value recognized in current period earnings.
Our wholesale propane logistics business is generally designed to establish stable margins by entering into supply arrangements that specify prices based on established floating price indices and by entering into sales agreements that provide for floating prices that are tied to our variable supply costs plus a margin. Occasionally, we may enter into fixed price sales agreements in the event that a retail propane distributor desires to purchase propane from us on a fixed price basis. We manage this risk with both physical and financial transactions, sometimes using non-trading derivative instruments, which generally allow us to swap our fixed price risk to market index prices that are matched to our market index supply costs. In addition, we
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may on occasion use financial derivatives to manage the value of our propane inventories. These financial derivatives are accounted for usingmark-to-market accounting with changes in fair value recognized in current period earnings. We manage our asset-based activities in accordance with our Risk Management Policy which limits exposure to market risk and requires regular reporting to management of potential financial exposure. In addition, we may on occasion use financial derivatives to manage the value of our propane inventories.
Our profitability is affected by changes in prevailing natural gas, propane, NGL and condensate prices. Historically, changes in the prices of most NGL products and condensate have generally correlated with changes in the price of crude oil. Natural gas, propane, NGL and condensate prices are volatile and are impacted by changes in the supply and demand for natural gas, NGLs and condensatethese commodities, as well as market uncertainty. For a discussion of the volatility of natural gas and NGL prices, please read “Risk Factors — Risks Related to Our Business —Business.” The cash flowflows from our Natural Gas Services segment isand Wholesale Propane Logistics segments are affected by natural gas, NGL and condensate prices, and decreases in these prices could adversely affect our ability to make distributions to holders of our common units and subordinated units.” Additionally, since weather conditions may adversely affect the overall demand for propane, our wholesale propane business is vulnerable to, and could be adversely affected by, milder winters.
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| |
Item 8. | Financial Statements and Supplementary Data.Data |
INDEX TO FINANCIAL STATEMENTS
| | | | |
DCP MIDSTREAM PARTNERS, LP CONSOLIDATED FINANCIAL STATEMENTS: | | | | |
| | | 6983 | |
| | | 7084 | |
| | | 7185 | |
| | | 7286 | |
| | | 7387 | |
| | | 7488 | |
| | | 7589 | |
6882
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors of
DCP Midstream Partners GP, LLC:LLC
Denver, Colorado:
We have audited the accompanying consolidated balance sheets of DCP Midstream Partners, LP and subsidiaries (the “Company”) as of December 31, 20052006 and 2004,2005, and the related consolidated statements of operations, comprehensive income, changes in partners’ equity, and cash flows for each of the three years in the period ended December 31, 2005.2006. Our audits also included the financial statement schedule listed in Item 15. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements,statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the consolidated financial position of the CompanyDCP Midstream Partners, LP and subsidiaries at December 31, 2006 and 2005, and 2004 and the consolidated results of itstheir operations and itstheir cash flows for each of the three years in the period ended December 31, 2005,2006, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule when considered in relation towith the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
As discussed in Note 1 to the consolidated financial statements, on December 7, 2005, DCP Midstream Partners, LP was formed and began operating as a separate company. Through December 7, 2005 the accompanying consolidated financial statements have been prepared from the separate records maintained by DCP Midstream, LLC (formerly Duke Energy Field Services, LLCLLC) and may not necessarily be indicative of the conditions that would have existed or the results of operations if the Company had been operated as an unaffiliated entity. Portions of certain expenses represent allocations made from, and are applicable to, Duke Energy Field Services,DCP Midstream, LLC as a whole.
The consolidated financial statements give retroactive effect to the November 1, 2006 acquisition by DCP Midstream Partners, LP of the wholesale propane logistics business which, as a combination of entities under common control, has been accounted for similar to a pooling of interests as described in Note 1 to the consolidated financial statements. Also as described in Note 1 to the consolidated financial statements, through November 1, 2006, the portion of the accompanying consolidated financial statements attributable to the wholesale propane logistics business, have been prepared from the separate records maintained by DCP Midstream, LLC and may not necessarily be indicative of the conditions that would have existed or the results of operations if the wholesale propane logistics business had been operated as an unaffiliated entity. Portions of certain expenses represent allocations made from, and are applicable to DCP Midstream, LLC as a whole.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company’s internal control over financial reporting as of December 31, 2006, based on the criteria established inInternal Control — Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated March 14, 2007, expressed an unqualified opinion on management’s assessment of the effectiveness of the Company’s internal control over financial reporting and an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
/s/ Deloitte & Touche LLP
Denver, Colorado
March 1, 200614, 2007
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DCP MIDSTREAM PARTNERS, LP
| | | | | | | | | | | | | | | | |
| | December 31, | | | December 31, | |
| | 2005 | | 2004 | | | 2006 | | 2005 | |
| | ($ in millions) | | | ($ in millions) | |
|
ASSETS | ASSETS | ASSETS |
Current assets: | | | | | | | | | | | | | | | | |
Cash and cash equivalents | | $ | 42.2 | | | $ | — | | | $ | 46.2 | | | $ | 42.2 | |
Short-term investments | | | | 0.6 | | | | — | |
Accounts receivable: | | | | | | | | | | | | | | | | |
Trade, net of allowance for doubtful accounts of $0.1 million and $0.2 million, respectively | | | 24.4 | | | | 59.0 | | |
Trade, net of allowance for doubtful accounts of $0.3 million at both periods | | | | 43.4 | | | | 65.7 | |
Affiliates | | | 56.5 | | | | 1.9 | | | | 34.8 | | | | 56.5 | |
Imbalances | | | 1.1 | | | | 0.1 | | |
Inventories | | | 0.1 | | | | — | | | | 30.1 | | | | 41.7 | |
Unrealized gains on non-trading derivative and hedging transactions | | | 0.1 | | | | — | | |
Unrealized gains on non-trading derivative and hedging instruments | | | | 4.2 | | | | 0.2 | |
Other | | | 0.1 | | | | 0.1 | | | | 0.3 | | | | 0.1 | |
| | | | | | | | | | |
Total current assets | | | 124.5 | | | | 61.1 | | | | 159.6 | | | | 206.4 | |
| | | | | | |
Restricted investments | | | 100.4 | | | | — | | | | 102.0 | | | | 100.4 | |
Property, plant and equipment, net | | | 168.9 | | | | 172.0 | | | | 194.7 | | | | 178.7 | |
Intangible asset, net | | | 2.1 | | | | 2.2 | | |
Equity method investment | | | 5.3 | | | | 5.8 | | |
Unrealized gains on non-trading derivative and hedging transactions | | | 5.4 | | | | — | | |
Goodwill | | | | 29.3 | | | | 29.3 | |
Intangible assets, net | | | | 2.8 | | | | 3.2 | |
Equity method investments | | | | 5.9 | | | | 5.5 | |
Unrealized gains on non-trading derivative and hedging instruments | | | | 6.5 | | | | 5.4 | |
Other non-current assets | | | 0.7 | | | | — | | | | 0.8 | | | | 1.0 | |
| | | | | | | | | | |
Total assets | | $ | 407.3 | | | $ | 241.1 | | | $ | 501.6 | | | $ | 529.9 | |
| | | | | | | | | | |
| LIABILITIES AND PARTNERS’ EQUITY | LIABILITIES AND PARTNERS’ EQUITY | LIABILITIES AND PARTNERS’ EQUITY |
Current liabilities: | | | | | | | | | | | | | | | | |
Accounts payable: | | | | | | | | | | | | | | | | |
Trade | | $ | 42.5 | | | $ | 35.2 | | | $ | 66.9 | | | $ | 95.9 | |
Affiliates | | | 42.0 | | | | 3.2 | | | | 50.4 | | | | 42.4 | |
Imbalances | | | 2.5 | | | | 1.4 | | |
Unrealized losses on non-trading derivative and hedging transactions | | | 2.4 | | | | 0.1 | | |
Unrealized losses on non-trading derivative and hedging instruments | | | | 0.7 | | | | 2.7 | |
Accrued interest payable | | | 0.8 | | | | — | | | | 1.1 | | | | 0.8 | |
Other | | | 3.2 | | | | 2.7 | | | | 7.4 | | | | 4.5 | |
| | | | | | | | | | |
Total current liabilities | | | 93.4 | | | | 42.6 | | | | 126.5 | | | | 146.3 | |
| | | | | | |
Long-term debt | | | 210.1 | | | | — | | | | 268.0 | | | | 210.1 | |
Unrealized losses on non-trading derivative and hedging transactions | | | 2.5 | | | | — | | |
Unrealized losses on non-trading derivative and hedging instruments | | | | 2.7 | | | | 2.5 | |
Other long-term liabilities | | | 0.4 | | | | 0.1 | | | | 1.0 | | | | 0.5 | |
| | | | | | | | | | |
Total liabilities | | | 306.4 | | | | 42.7 | | | | 398.2 | | | | 359.4 | |
| | | | | | | | | | |
Commitments and contingent liabilities | | | | | | | | | | | | | | | | |
Partners’ equity: | | | | | | | | | | | | | | | | |
DCP Midstream Partners Predecessor equity | | | — | | | | 198.4 | | |
Common unitholders (10,357,143 units issued and outstanding at December 31, 2005) | | | 215.8 | | | | — | | |
Subordinated unitholders (7,142,857 convertible units issued and outstanding at December 31, 2005) | | | (109.7 | ) | | | — | | |
General partner interest (2% interest with 357,143 equivalent units outstanding at December 31, 2005) | | | (5.6 | ) | | | — | | |
Predecessor equity | | | | — | | | | 69.6 | |
Common unitholders (10,357,143 units issued and outstanding at December 31, 2006 and 2005) | | | | 223.4 | | | | 215.8 | |
Class C unitholders (200,312 units and 0 units issued and outstanding at December 31, 2006 and 2005) | | | | (20.7 | ) | | | — | |
Subordinated unitholders (7,142,857 convertible units issued and outstanding at December 31, 2006 and 2005) | | | | (101.6 | ) | | | (109.7 | ) |
General partner interest | | | | (5.0 | ) | | | (5.6 | ) |
Accumulated other comprehensive income | | | 0.4 | | | | — | | | | 7.3 | | | | 0.4 | |
| | | | | | | | | | |
Total partners’ equity | | | 100.9 | | | | 198.4 | | | | 103.4 | | | | 170.5 | |
| | | | | | | | | | |
Total liabilities and partners’ equity | | $ | 407.3 | | | $ | 241.1 | | | $ | 501.6 | | | $ | 529.9 | |
| | | | | | | | | | |
See accompanying notes to consolidated financial statements.
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DCP MIDSTREAM PARTNERS, LP
| | | | | | | | | | | | | |
| | Year Ended December 31, | | | | | | | | | | | | | |
| | 2005 | | 2004 | | 2003 | | | Year Ended December 31, | |
| | ($ in millions, except
| | | 2006 | | 2005 | | 2004 | |
| | per unit amounts) | | | ($ in millions, except per unit amounts) | |
|
Operating revenues: | | | | | | | | | | | | | | | | | | | | | | | | |
Sales of natural gas, NGLs and condensate | | $ | 647.8 | | | $ | 412.7 | | | $ | 319.3 | | |
Sales of natural gas, NGLs and condensate to affiliates | | | 114.5 | | | | 77.0 | | | | 134.7 | | |
Sales of natural gas, propane, NGLs and condensate | | | $ | 535.1 | | | $ | 1,004.6 | | | $ | 729.8 | |
Sales of natural gas, propane, NGLs and condensate to affiliates | | | | 232.8 | | | | 117.5 | | | | 85.6 | |
Transportation and processing services | | | 12.3 | | | | 9.5 | | | | 9.5 | | | | 15.0 | | | | 12.5 | | | | 9.5 | |
Transportation and processing services to affiliates | | | 10.6 | | | | 10.4 | | | | 9.1 | | | | 12.8 | | | | 10.6 | | | | 11.0 | |
(Losses) gains from non-trading derivative activity — affiliate | | | (0.7 | ) | | | (0.1 | ) | | | 2.5 | | |
Gains (losses) from non-trading derivative activity — affiliates | | | | 0.1 | | | | (0.9 | ) | | | (1.9 | ) |
| | | | | | | | | | | | | | |
Total operating revenues | | | 784.5 | | | | 509.5 | | | | 475.1 | | | | 795.8 | | | | 1,144.3 | | | | 834.0 | |
| | | | | | | | | | | | | | |
Operating costs and expenses: | | | | | | | | | | | | | | | | | | | | | | | | |
Purchases of natural gas and NGLs | | | 601.4 | | | | 404.1 | | | | 309.3 | | |
Purchases of natural gas and NGLs from affiliates | | | 107.9 | | | | 48.5 | | | | 121.3 | | |
Purchases of natural gas, propane and NGLs | | | | 581.2 | | | | 889.5 | | | | 644.2 | |
Purchases of natural gas, propane and NGLs from affiliates | | | | 119.2 | | | | 157.8 | | | | 116.4 | |
Operating and maintenance expense | | | 14.2 | | | | 13.6 | | | | 15.0 | | | | 23.7 | | | | 22.4 | | | | 19.8 | |
Depreciation and amortization expense | | | 11.7 | | | | 12.6 | | | | 12.8 | | | | 12.8 | | | | 12.7 | | | | 14.7 | |
General and administrative expense | | | 4.0 | | | | — | | | | — | | | | 12.9 | | | | 5.1 | | | | 0.9 | |
General and administrative expense — affiliates | | | 7.4 | | | | 6.5 | | | | 7.1 | | | | 8.1 | | | | 9.1 | | | | 7.8 | |
| | | | | | | | | | | | | | |
Total operating costs and expenses | | | 746.6 | | | | 485.3 | | | | 465.5 | | | | 757.9 | | | | 1,096.6 | | | | 803.8 | |
| | | | | | | | | | | | | | |
Operating income | | | 37.9 | | | | 24.2 | | | | 9.6 | | | | 37.9 | | | | 47.7 | | | | 30.2 | |
Interest income | | | 0.5 | | | | — | | | | — | | | | 6.3 | | | | 0.5 | | | | — | |
Interest expense | | | (0.8 | ) | | | — | | | | — | | | | (11.5 | ) | | | (0.8 | ) | | | — | |
Earnings from equity method investment | | | 0.4 | | | | 0.6 | | | | 0.4 | | |
Earnings from equity method investments | | | | 0.3 | | | | 0.4 | | | | 0.6 | |
Impairment of equity method investment | | | — | | | | (4.4 | ) | | | — | | | | — | | | | — | | | | (4.4 | ) |
| | | | | | | | |
Income before income taxes | | | | 33.0 | | | | 47.8 | | | | 26.4 | |
Income tax expense | | | | — | | | | 3.3 | | | | 2.5 | |
| | | | | | | | | | | | | | |
Net income | | $ | 38.0 | | | $ | 20.4 | | | $ | 10.0 | | | $ | 33.0 | | | $ | 44.5 | | | $ | 23.9 | |
Less: | | | | | | | | | | | | | | | | | | | | | | | | |
Net income attributable to DCP Midstream Partners Predecessor | | | (33.3 | ) | | | (20.4 | ) | | | (10.0 | ) | |
Net loss (income) attributable to predecessor operations | | | | 2.3 | | | | (39.8 | ) | | | (23.9 | ) |
General partner interest in net income | | | (0.1 | ) | | | — | | | | — | | | | (0.7 | ) | | | (0.1 | ) | | | — | |
| | | | | | | | | | | | | | |
Net income allocable to limited partners | | $ | 4.6 | | | $ | — | | | $ | — | | | $ | 34.6 | | | $ | 4.6 | | | $ | — | |
| | | | | | | | | | | | | | |
Net income per limited partners’ unit — basic and diluted | | $ | 0.20 | | | $ | — | | | $ | — | | |
Net income per limited partner unit — basic and diluted | | | $ | 1.90 | | | $ | 0.20 | | | $ | — | |
| | | | | | | | | | | | | | |
Weighted average limited partners’ units outstanding — basic and diluted | | | 17.5 | | | | — | | | | — | | |
Weighted-average limited partner units outstanding — basic and diluted | | | | 17.5 | | | | 17.5 | | | | — | |
See accompanying notes to consolidated financial statements.
7185
DCP MIDSTREAM PARTNERS, LP
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, | | | Year Ended December 31, | |
| | 2005 | | 2004 | | 2003 | | | 2006 | | 2005 | | 2004 | |
| | ($ in millions) | | | ($ in millions) | |
|
Net income | | $ | 38.0 | | | $ | 20.4 | | | $ | 10.0 | | | $ | 33.0 | | | $ | 44.5 | | | $ | 23.9 | |
| | | | | | | | |
Other comprehensive income: | | | | | | | | | | | | | | | | | | | | | | | | |
Reclassification of cash flow hedges into earnings | | | | (2.7 | ) | | | — | | | | — | |
Net unrealized gains on cash flow hedges | | | 0.4 | | | | — | | | | — | | | | 9.6 | | | | 0.4 | | | | — | |
| | | | | | | | | | | | | | |
Total other comprehensive income | | | 0.4 | | | | — | | | | — | | | | 6.9 | | | | 0.4 | | | | — | |
| | | | | | | | | | | | | | |
Total comprehensive income | | $ | 38.4 | | | $ | 20.4 | | | $ | 10.0 | | | $ | 39.9 | | | $ | 44.9 | | | $ | 23.9 | |
| | | | | | | | | | | | | | |
See accompanying notes to consolidated financial statements.
7286
DCP MIDSTREAM PARTNERS, LP
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | DCP
| | | | | | | | | | | | | | | | | | | | | | | Accumulated
| | | |
| | Midstream
| | | | | | | | Accumulated
| | | | | | | | | | | | | General
| | Other
| | Total
| |
| | Partners
| | | | | | General
| | Other
| | Total
| | | Predecessor
| | Common
| | Class C
| | Subordinated
| | Partner
| | Comprehensive
| | Partners’
| |
| | Predecessor
| | Common
| | Subordinated
| | Partner
| | Comprehensive
| | Partners’
| | | Equity | | Unitholders | | Unitholders | | Unitholders | | Interest | | Income | | Equity | |
| | Equity | | Unitholders | | Unitholders | | Interest | | Income | | Equity | | | | | | | | | ($ in millions) | | | | | | | |
| | ($ in millions) | |
| |
Balance, January 1, 2003 | | $ | 220.7 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 220.7 | | |
Balance, January 1, 2004 | | | $ | 257.6 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 257.6 | |
Net change in parent advances | | | (29.6 | ) | | | — | | | | — | | | | — | | | | — | | | | (29.6 | ) | | | (22.1 | ) | | | — | | | | — | | | | — | | | | — | | | | — | | | | (22.1 | ) |
Net income | | | 10.0 | | | | — | | | | — | | | | — | | | | — | | | | 10.0 | | |
| | | | | | | | | | | | | | |
Balance, December 31, 2003 | | | 201.1 | | | | — | | | | — | | | | — | | | | — | | | | 201.1 | | |
Net change in parent advances | | | (23.1 | ) | | | — | | | | — | | | | — | | | | — | | | | (23.1 | ) | |
Net income | | | 20.4 | | | | — | | | | — | | | | — | | | | — | | | | 20.4 | | |
Net income attributable to predecessor operations | | | | 23.9 | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 23.9 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Balance, December 31, 2004 | | | 198.4 | | | | — | | | | — | | | | — | | | | — | | | | 198.4 | | | | 259.4 | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 259.4 | |
Net change in parent advances | | | (123.6 | ) | | | — | | | | — | | | | — | | | | — | | | | (123.6 | ) | | | (121.5 | ) | | | — | | | | — | | | | — | | | | — | | | | — | | | | (121.5 | ) |
Other comprehensive income | | | | | | | — | | | | — | | | | — | | | | 0.4 | | | | 0.4 | | |
Net income through December 6, 2005 | | | 33.3 | | | | — | | | | — | | | | — | | | | — | | | | 33.3 | | |
Proceeds from initial public offering of 10,350,000 common units | | | | | | | 222.5 | | | | — | | | | — | | | | — | | | | 222.5 | | | | — | | | | 222.5 | | | | — | | | | — | | | | — | | | | — | | | | 222.5 | |
Underwriters’ discount and offering expenses | | | — | | | | (9.3 | ) | | | (6.4 | ) | | | (0.4 | ) | | | — | | | | (16.1 | ) | | | — | | | | (9.3 | ) | | | — | | | | (6.4 | ) | | | (0.4 | ) | | | — | | | | (16.1 | ) |
Distribution to Duke Energy Field Services | | | (218.7 | ) | | | — | | | | — | | | | — | | | | — | | | | (218.7 | ) | |
Allocation of DCP Midstream Partners Predecessor equity in exchange for 7,143 common units, 7,142,857 subordinated units and a 2% general partnership interest (represented by 357,143 equivalent units) | | | 110.6 | | | | (0.1 | ) | | | (105.2 | ) | | | (5.3 | ) | | | — | | | | — | | |
Distribution to unitholders | | | | (218.7 | ) | | | — | | | | — | | | | — | | | | — | | | | — | | | | (218.7 | ) |
Allocation of predecessor equity in exchange for 7,143 common units, 7,142,857 subordinated units and a 2% general partnership interest (represented by 357,143 equivalent units) | | | | 110.6 | | | | (0.1 | ) | | | — | | | | (105.2 | ) | | | (5.3 | ) | | | — | | | | — | |
Net income attributable to predecessor operations | | | | 39.8 | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 39.8 | |
Net income from December 7, 2005 through December 31, 2005 | | | — | | | | 2.7 | | | | 1.9 | | | | 0.1 | | | | — | | | | 4.7 | | | | — | | | | 2.7 | | | | — | | | | 1.9 | | | | 0.1 | | | | — | | | | 4.7 | |
Other comprehensive income | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 0.4 | | | | 0.4 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Balance, December 31, 2005 | | $ | — | | | $ | 215.8 | | | $ | (109.7 | ) | | $ | (5.6 | ) | | $ | 0.4 | | | $ | 100.9 | | | | 69.6 | | | | 215.8 | | | | — | | | | (109.7 | ) | | | (5.6 | ) | | | 0.4 | | | | 170.5 | |
Net change in parent advances | | | | (10.6 | ) | | | — | | | | — | | | | — | | | | — | | | | — | | | | (10.6 | ) |
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 loss attributable to predecessor operations | | | | (2.3 | ) | | | — | | | | — | | | | — | | | | — | | | | — | | | | (2.3 | ) |
Net income | | | | — | | | | 20.4 | | | | 0.1 | | | | 14.1 | | | | 0.7 | | | | — | | | | 35.3 | |
Other comprehensive income | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 6.9 | | | | 6.9 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Balance, December 31, 2006 | | | $ | — | | | $ | 223.4 | | | | (20.7 | ) | | $ | (101.6 | ) | | $ | (5.0 | ) | | $ | 7.3 | | | $ | 103.4 | |
| | | | | | | | | | | | | | | | |
See accompanying notes to consolidated financial statements.
7387
DCP MIDSTREAM PARTNERS, LP
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, | | | Year Ended December 31, | |
| | 2005 | | 2004 | | 2003 | | | 2006 | | 2005 | | 2004 | |
| | ($ in millions) | | | | | ($ in millions) | | | |
|
OPERATING ACTIVITIES: | | | | | | | | | | | | | | | | | | | | | | | | |
Net income | | $ | 38.0 | | | $ | 20.4 | | | $ | 10.0 | | | $ | 33.0 | | | $ | 44.5 | | | $ | 23.9 | |
Adjustments to reconcile net income to net cash provided by operating activities: | | | | | | | | | | | | | | | | | | | | | | | | |
Depreciation and amortization expense and impairment charge | | | 11.7 | | | | 17.0 | | | | 12.8 | | | | 12.8 | | | | 12.7 | | | | 19.1 | |
Undistributed earnings from equity method investments | | | | (0.3 | ) | | | (0.4 | ) | | | (0.6 | ) |
Deferred income tax benefit | | | | — | | | | (0.5 | ) | | | (0.1 | ) |
Other, net | | | (0.3 | ) | | | (0.6 | ) | | | 0.2 | | | | (2.4 | ) | | | 0.1 | | | | (0.2 | ) |
Change in operating assets and liabilities which provided (used) cash: | | | | | | | | | | | | | | | | | | | | | | | | |
Accounts receivable | | | (20.8 | ) | | | (15.7 | ) | | | (2.1 | ) | | | 43.1 | | | | (30.7 | ) | | | (19.0 | ) |
Net unrealized (gains) losses on non-trading derivative and hedging transactions | | | (0.3 | ) | | | 0.6 | | | | (0.5 | ) | |
Inventories | | | (0.1 | ) | | | — | | | | — | | | | 11.6 | | | | (21.0 | ) | | | 0.2 | |
Net unrealized (gains) losses on non-trading derivative and hedging instruments | | | | (0.1 | ) | | | 0.1 | | | | 0.3 | |
Accounts payable | | | 47.2 | | | | 3.8 | | | | 9.2 | | | | (31.5 | ) | | | 74.7 | | | | 0.8 | |
Accrued interest | | | 0.8 | | | | — | | | | — | | | | 0.3 | | | | 0.8 | | | | — | |
Income tax payable | | | | — | | | | (3.2 | ) | | | (0.1 | ) |
Other current assets and liabilities | | | (0.6 | ) | | | 0.1 | | | | 1.2 | | | | 2.0 | | | | (0.7 | ) | | | 0.4 | |
Other noncurrent assets and liabilities | | | (0.1 | ) | | | — | | | | — | | |
Other non-current assets and liabilities | | | | 0.4 | | | | (0.1 | ) | | | — | |
| | | | | | | | | | | | | | |
Net cash provided by operating activities | | | 75.5 | | | | 25.6 | | | | 30.8 | | | | 68.9 | | | | 76.3 | | | | 24.7 | |
| | | | | | | | | | | | | | |
INVESTING ACTIVITIES: | | | | | | | | | | | | | | | | | | | | | | | | |
Capital expenditures | | | (7.9 | ) | | | (3.1 | ) | | | (2.7 | ) | | | (27.2 | ) | | | (10.8 | ) | | | (3.3 | ) |
Acquisition of wholesale propane logistics business | | | | (56.7 | ) | | | — | | | | — | |
Proceeds from sales of assets | | | 1.2 | | | | 0.6 | | | | 1.5 | | | | 0.3 | | | | 1.2 | | | | 0.7 | |
Purchases ofavailable-for-sale securities | | | (731.0 | ) | | | — | | | | — | | | | (7,372.4 | ) | | | (731.0 | ) | | | — | |
Proceeds from sales ofavailable-for-sale securities | | | 630.8 | | | | — | | | | — | | | | 7,373.3 | | | | 630.8 | | | | — | |
Other investing activities | | | (0.1 | ) | | | — | | | | — | | | | — | | | | (0.1 | ) | | | — | |
| | | | | | | | | | | | | | |
Net cash used in investing activities | | | (107.0 | ) | | | (2.5 | ) | | | (1.2 | ) | | | (82.7 | ) | | | (109.9 | ) | | | (2.6 | ) |
| | | | | | | | | | | | | | |
FINANCING ACTIVITIES: | | | | | | | | | | | | | | | | | | | | | | | | |
Borrowings under debt facilities | | | | 78.0 | | | | 210.1 | | | | — | |
Repayments of debt | | | | (20.1 | ) | | | — | | | | — | |
Deferred financing costs | | | | (0.2 | ) | | | (0.5 | ) | | | — | |
Proceeds from issuance of common units, net of offering costs | | | 206.4 | | | | — | | | | — | | | | — | | | | 206.4 | | | | — | |
Borrowings under credit facility | | | 110.0 | | | | — | | | | — | | |
Borrowings under term loan facility | | | 100.1 | | | | — | | | | — | | |
Distributions to Duke Energy Field Services | | | (218.7 | ) | | | — | | | | — | | |
Net change in advances from Duke Energy Field Services | | | (123.6 | ) | | | (23.1 | ) | | | (29.6 | ) | |
Deferred financing costs | | | (0.5 | ) | | | — | | | | — | | |
Proceeds from issuance of equivalent units to general partner | | | | 0.1 | | | | — | | | | — | |
Excess purchase price over acquired assets | | | | (10.7 | ) | | | — | | | | — | |
Net change in advances from DCP Midstream, LLC | | | | (10.6 | ) | | | (121.5 | ) | | | (22.1 | ) |
Distributions to unitholders | | | | (22.1 | ) | | | (218.7 | ) | | | — | |
Contributions from unitholders | | | | 3.4 | | | | — | | | | — | |
| | | | | | | | | | | | | | |
Net cash provided by (used in) financing activities | | | 73.7 | | | | (23.1 | ) | | | (29.6 | ) | | | 17.8 | | | | 75.8 | | | | (22.1 | ) |
| | | | | | | | | | | | | | |
Net change in cash and cash equivalents | | | 42.2 | | | | — | | | | — | | | | 4.0 | | | | 42.2 | | | | — | |
Cash and cash equivalents, beginning of period | | | — | | | | — | | | | — | | | | 42.2 | | | | — | | | | — | |
| | | | | | | | | | | | | | |
Cash and cash equivalents, end of period | | $ | 42.2 | | | $ | — | | | $ | — | | | $ | 46.2 | | | $ | 42.2 | | | $ | — | |
| | | | | | | | | | | | | | |
Supplementary disclosure of cash flow information: | | | | | | | | | | | | | |
Cash paid for interest expense, net of capitalized interest | | | $ | 11.1 | | | $ | — | | | $ | — | |
Cash paid for income taxes | | | $ | — | | | $ | 2.6 | | | $ | 2.7 | |
See accompanying notes to consolidated financial statements.
7488
DCP MIDSTREAM PARTNERS, LP
Years Ended December 31, 2006, 2005 2004 and 20032004
| |
1. | Description of Business and Basis of Presentation |
DCP Midstream Partners, LP, (withwith its consolidated subsidiaries, the “Partnership”)or us, we or our, is engaged in the business of gathering, compressing, treating, processing, transporting and selling natural gas and the business of producing, transporting and selling propane and natural gas liquids, or NGLs.
The Partnership includes the results of operations, financial position, cash flows and changes in partners’ equity in itsOur partnership includes: our North Louisiana system assets, (“Minden”, “Ada”,or Minden, Ada, and “PELICO”), itsPelico; our Seabreeze NGL transportation pipeline (“Seabreeze”) and itspipeline; our 45% equity method investment in Black Lake Pipe Line Company, (“or Black Lake”)Lake, that were contributed to the Partnershipus on December 7, 2005 by DCP Midstream, LLC (formerly Duke Energy Field Services, LLC); our Wilbreeze NGL transportation pipeline which was completed in December 2006; and our wholesale propane logistics business that was acquired by us on November 1, 2006 from DCP Midstream, LLC. DCP Midstream, LLC (“DEFS” or the “Parent”). DEFS is owned 50% by DukeSpectra Energy Corporation (“Duke Energy”)Corp, or Spectra Energy, and 50% by ConocoPhillips. The consolidated financial statements includePrior to December 7, 2005, DCP Midstream Partners Predecessor (defined below) owned a 50% equity interest in Black Lake. DCP Midstream, LLC owns a 5% interest in Black Lake, in 2003, 2004 andeffective with the period beginning January 1, 2005 through December 6, 2005. Upon closingdate of the Partnership’sour initial public offering, on December 7, 2005, DEFS retained a 5%and an affiliate of BP PLC owns the remaining interest and is the operator of Black Lake. The Partnership owns a 45% equity interest in Black Lake.Spectra Energy is the natural gas business that was spun off from Duke Energy Corporation, or Duke Energy, effective January 2, 2007.
In November 2006, we acquired our wholesale propane logistics business from DCP Midstream, LLC for approximately $82.9 million, comprised of $77.3 million in cash ($9.9 million of which was paid in January 2007) and $5.6 million in limited partner units. Included in the acquisition was $10.5 million of costs incurred by DCP Midstream, LLC for the construction of a new propane pipeline terminal. In conjunction with the issuance of limited partner units, the general partner maintained its 2% ownership level, in exchange for $0.1 million. See Note 4 for additional information.
Net assets contributed by DCP Midstream, LLC represent a transfer of net assets between entities under common control. We recognize transfers of net assets between entities under common control at DCP Midstream, LLC’s basis in the net assets contributed. In addition, transfers of net assets between entities under common control are accounted for as if the transfer occurred at the beginning of the period, and prior years are retroactively adjusted to furnish comparative information similar to the pooling method. The Partnershipamount of the purchase price in excess of DCP Midstream, LLC’s basis in the net assets, if any, is recognized as a reduction to partners’ equity.
We closed itsour initial public offering of 10,350,000 common units at a price of $21.50 per unit on December 7, 2005. Proceeds from the initial public offering were $206.4 million, net of offering costs. In addition, concurrent with the initial public offering, DEFSDCP Midstream, LLC contributed to the Partnershipus the assets described above and retained (i)retained: (1) a 2% general partner interest in the Partnership; (ii)our partnership; (2) 7,142,857 subordinated units; and (iii)(3) 7,143 common units, representingunits. Following the equity transactions related to the acquisition of our wholesale propane logistics business noted above, DCP Midstream, LLC owns in aggregate an approximate 42%43% interest in the Partnership. The Partnership’s general partner is DCP Midstream GP, LP, a wholly-owned subsidiary of DEFS.our partnership. See Note 412 for information related to the distribution rights of the common, Class C and subordinated unitholders and the incentive distribution rights held by the general partner.
DEFSOur operations and activities are managed by our general partner, DCP Midstream GP, LP, which in turn is managed by its general partner, DCP Midstream GP, LLC, which we refer to as the General Partner, which is wholly-owned by DCP Midstream, LLC. DCP Midstream, LLC directs theour business operations of the Partnership through its ownership and control of the Partnership’s general partner. DEFSGeneral Partner. DCP Midstream, LLC and its affiliates’ employees provide administrative support to the Partnershipus and operate itsour assets.
The consolidated financial statements include theour accounts, of the Partnership, and prior to December 7, 2005 the assets, liabilities and operations contributed to us by DEFSDCP Midstream, LLC and its wholly-owned subsidiaries, (“which we refer to as DCP Midstream Partners Predecessor”)Predecessor, upon the closing of the Partnership’sour initial public offering, andoffering. In November 2006, we acquired our wholesale propane logistics business from DCP Midstream, LLC in a
89
DCP MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
transaction among entities under common control. Accordingly, our financial information includes the historical results of our wholesale propane logistics business for all periods presented.
The consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America.America, or GAAP. We refer to DCP Midstream Partners Predecessor, and the assets, liabilities and operations of our wholesale propane logistics business prior to our acquisition from DCP Midstream, LLC in November 2006, collectively as our “predecessors.” The consolidated financial statements of DCP Midstream Partners Predecessorour predecessors have been prepared from the separate records maintained by DEFSDCP Midstream, LLC and may not necessarily be indicative of the conditions that would have existed or the results of operations if DCP Midstream Partners Predecessorour predecessors had been operated as an unaffiliated entity. All significant intercompany balances and transactions have been eliminated. Transactions between the Partnershipus and other DEFSDCP Midstream, LLC operations have been identified in the consolidated financial statements as transactions between affiliates (see Note 7)5).
| |
2. | Summary of Significant Accounting Policies |
Use of Estimates — Conformity with accounting principles generally accepted in the United StatesGAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and notes. Although these estimates are based on management’s best available knowledge of current and expected future events, actual results could be differentdiffer from those estimates.
Reclassifications — Certain prior period amounts have been reclassified in the consolidated financial statements to conform to the current period presentation.
Cash and Cash Equivalents — The Partnership considersWe consider investments in highly liquid financial instruments purchased with an original stated maturity of 90 days or less to be cash equivalents.
Short-Term and Restricted Investments — Short-term investments consist of $0.6 million at December 31, 2006. We had no short-term investments at December 31, 2005. We invest available cash balances in various financial instruments, such as tax-exempt debt securities, that have stated maturities of 20 years or more. These instruments provide for a high degree of liquidity through features, which allow for the redemption of the investment at its face amount plus earned income. As we generally intend to sell these instruments within one year or less from the balance sheet date, and as they are available for use in current operations, they are classified as current assets, unless otherwise restricted.
Restricted investments consist of $102.0 million and $100.4 million in investments in commercial paper and various other high-grade debt securities.securities at December 31, 2006 and 2005, respectively. These investments are used as collateral to secure the term
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loan portion of theour credit facility and are to be used only for future capital expenditures. These
We have classified all short-term and restricted investments are classified asavailable-for-sale securities under Statement of Financial Accounting Standards, (“SFAS”)or SFAS, No. 115,Accounting for Certain Investments in Debt and Equity Securities, as management doeswe do not intend to hold them to maturity, nor are they bought or sold with the objective of generating profitsprofit on short-term differences in prices. These investments are recorded at fair value, with changes in fair market value recorded as unrealized holding gains orand losses in accumulated other comprehensive income, (“AOCI”). At December 31, 2005, no amounts related to these investmentsor AOCI. No gains or losses were deferred in AOCI. DueAOCI at December 31, 2006 or 2005. The cost, including accrued interest on investments, approximates fair value, due to the short-term, highly liquid nature of the securities held by the Partnershipus, and as interest rates are re-set on a daily, weekly or monthly basis,basis.
Gas and NGL Imbalance Accounting — Quantities of natural gas or NGLs over-delivered or under-delivered related to imbalance agreements with customers, producers or pipelines are recorded monthly as other receivables or other payables using current market prices or the weighted-average prices of natural gas
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or NGLs at the plant or system. These balances are settled with deliveries of natural gas or NGLs, or with cash.
Included in the consolidated balance sheets as accounts receivable — trade, were imbalances of $0.1 million and $1.1 million at December 31, 2006 and 2005, respectively. Included in the consolidated balance sheets as accounts payable — trade, were imbalances of $0.9 million and $2.5 million at December 31, 2006 and 2005, respectively.
Inventories — Inventories consist primarily of propane. Inventories are recorded at the lower of weighted-average cost or market value. Transportation costs are included in inventory on the consolidated balance sheets.
Property, Plant and Equipment — Property, plant and equipment are recorded at historical cost. Depreciation is computed using the straight-line method over the estimated useful lives of the assets (see Note 6). The costs of maintenance and repairs, which are not significant improvements, are expensed when incurred. Expenditures to extend the useful lives of the assets are capitalized.
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 increases due to the passage of time based on the time value of money until the obligation is settled. We recognize a liability of a conditional asset retirement obligation as soon as the fair value of the liability can be reasonably estimated. A conditional asset retirement obligation is defined as an unconditional legal obligation to perform an asset retirement activity in which the timingand/or method of settlement are conditional on a future event that may or may not be within the control of the entity.
Goodwill and Intangible Assets — Goodwill is the cost of an acquisition less the fair value of the net assets of the acquired business. The goodwill on the consolidated balance sheets was recognized by DCP Midstream, LLC when it acquired certain assets which are now included in the wholesale propane logistics business, and was allocated based on fair value to the wholesale propane logistics business in order to present historical information about the assets we acquired. 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. Impairment testing of goodwill consists of a two-step process. The first step involves comparing the fair value of the reporting unit, to which goodwill has been allocated, with its carrying amount. If the carrying amount of the reporting unit exceeds its fair value, the second step of the process involves comparing the fair value and carrying value of the goodwill of that reporting unit. If the carrying value of the goodwill of a reporting unit exceeds the fair value of that goodwill, an impairment loss is recognized in an amount equal to the excess.
Intangible assets consist primarily of commodity contracts. The commodity contracts are amortized on a straight-line basis over the period of expected future benefit, ranging from approximately five to 25 years (see Note 7).
Investment in and Impairment of Equity Method Investments — We account for investments in greater than 20% owned affiliates that are not variable interest entities and where we do not have the ability to exercise control, and investments in less than 20% owned affiliates where we have the ability to exercise significant influence, under the equity method.
We evaluate our equity method investments for impairment whenever events or changes in circumstances indicate that the carrying value of such investments may have experienced another-than-temporary 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. We assess the fair value of our equity method investments using commonly accepted techniques, and may use more than one
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method, including, accrued interestbut not limited to, recent third party comparable sales, internally developed discounted cash flow analysis and analysis from outside advisors. If the estimated fair value is less than the carrying value and we consider the decline in value to be other than temporary, the excess of the carrying value over the estimated fair value is recognized in the financial statements as an impairment.
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 investments, approximatesundiscounted cash flow projections. The carrying amount is not recoverable if it exceeds the undiscounted sum of cash flows expected to result from the use and eventual disposition of the asset. We consider various factors when determining if these assets should be evaluated for impairment, including but not limited to:
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| • | significant adverse change in legal factors or business climate; |
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| • | 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; |
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| • | an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of a long-lived asset; |
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| • | significant adverse changes in the extent or manner in which an asset is used, or in its physical condition; |
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| • | 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. |
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. During 2004,We assess the Partnership didfair value of long-lived assets using commonly accepted techniques, and may use more than one method, including, but not investlimited to, recent third party comparable sales, internally developed discounted cash flow analysis and analysis from outside advisors. Significant changes in these instruments.market conditions resulting from events such as the condition of an asset or a change in management’s intent to utilize the asset would generally require management to reassess the cash flows related to the long-lived assets.
Unamortized Debt Expense — Expenses incurred with the issuance of long-term debt are amortized over the terms of the debt using the effective interest method. These expenses are recorded on the consolidated balance sheet as other non-current assets.
Accounting for Risk Management and Hedging Activities and Financial Instruments — Each derivative not qualifying for the normal purchases and normal sales exception under SFAS No. 133, (“SFAS 133”),“Accounting for Derivative Instruments and Hedging Activities”Activities, as amended, or SFAS 133, is recorded on a gross basis in the consolidated balance sheets at its fair value as Unrealizedunrealized gains or Unrealizedunrealized losses on non-trading derivative and hedging transactions.instruments. Derivative assets and liabilities remain classified in the Partnership’sour consolidated balance sheets as unrealized gains or unrealized losses on non-trading derivative and hedging transactionsinstruments at fair value until the contractual settlement period occurs.impacts earnings.
All derivative activity reflected in the combined financial statements for periods prior to December 7, 2005 was transacted by the Partnership and DEFS and its subsidiaries prior to the initial public offering and was transferredand/or allocated to the Partnership. All derivative activity reflected in the consolidated financial statements from December 7, 2005for our predecessors was transacted by us or by DCP Midstream, LLC and going forwardits subsidiaries, and transferredand/or allocated to us. All derivative activity reflected in the consolidated financial statements, which is not related to our predecessors, has been and will be transacted by the Partnership. Management designatesus, although DCP Midstream, LLC personnel execute various transactions on our behalf (see Note 5). We designate each energy commodity derivative as either trading or non-trading. Certain non-trading derivatives are further designated as either a hedge of a forecasted transaction or future
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cash flow (cash flow hedge), a hedge of a recognized asset, liability or firm commitment (fair value hedge), or normal purchases or normal sales, while certain non-trading derivatives, which are related to asset-based activity,activities, are designated as non-trading derivative activity. For the periods presented, the Partnershipwe did not have any trading derivative activity, however, the Partnership didwe do have cash flow and fair value hedge activity, normal purchases and normal sales activity, and non-trading derivative activity included in thesethe consolidated financial statements. For each derivative, the accounting method and presentation of gains and losses or revenue and expense in the consolidated statements of operations are as follows:
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Classification of Contract | | Accounting Method | | Presentation of Gains & Losses or Revenue & Expense |
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Non-Trading Derivatives: | | | | |
Non-Trading Derivative Activity | | Mark-to-market(a)Mark-to-market method(a) | | Net basis in gains and losses(losses) from non-trading derivative activity |
Cash Flow Hedge | | Hedge method(b) | | Gross basis in the same statementconsolidated statements of operations category as the related hedged item |
Fair Value Hedge | | Hedge method(b) | | Gross basis in the same statementconsolidated statements of operations category as the related hedged item |
Normal Purchases or Normal Sales | | Accrual method(c) | | Gross basis upon settlement in the corresponding statementconsolidated statements of operations category based on purchase or sale |
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(a) | | Mark-to-market — An accounting method whereby the change in the fair value of the asset or liability is recognized in the resultsconsolidated statements of operations in gains and losses(losses) from non-trading derivative activity during the current period. |
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(b) | | Hedge method — An accounting method whereby the effective portion of the change in the fair value of the asset or liability is recorded in the consolidated balance sheets as a balance sheet adjustmentunrealized gains or unrealized losses on non-trading derivative and hedging instruments. For cash flow hedges, there is no recognition in the resultsconsolidated statements of operations for the effective portion until the service is provided or the associated delivery period occurs.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. |
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(c) | | Accrual method — An accounting method whereby there is no recognition in the resultsconsolidated 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 occurs.impacts earnings. |
Cash Flow and Fair Value Hedges — For derivatives designated as a cash flow hedge or a fair value hedge, management prepareswe maintain formal documentation of the hedge in accordance with SFAS 133. In addition, managementwe formally assesses,assess, both at the inception of the hedgehedging relationship and on an ongoing basis, whether the hedge contract is highly effective in offsetting changes in cash flows or fair values of hedged items. All components of each derivative gain or loss are included in the assessment of hedge effectiveness, unless otherwise noted.
The fair value of a derivative designated as a cash flow hedge is recorded forin the consolidated balance sheet purposessheets as unrealized gains or unrealized losses on non-trading derivative and hedging transactions.instruments. The effective portion of the change in fair value of a derivative designated as a cash flow hedge is recorded in partners’ equity as accumulated other comprehensive incomeAOCI, and the ineffective portion is recorded in the consolidated statements of operations. During the period in which the hedged transaction occurs,impacts earnings, amounts in AOCI associated with the hedged transaction are reclassified to the consolidated statements of operations in the same accounts as the item being hedged. Hedge accounting is discontinued prospectively when it is determined that the derivative no longer qualifies as an effective hedge, or when it is no longer probable that the hedged transaction will not occur. When hedge accounting is discontinued because the derivative no longer qualifies as an effective hedge, the
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derivative is subject to themark-to-market accounting method prospectively. The derivative continues to be carried on the consolidated balance sheets at its fair value; however, subsequent changes in its fair value are recognized in current period earnings. Gains and losses related to discontinued hedges that were previously accumulated in AOCI will remain in AOCI until the hedged transaction occurs,impacts earnings, unless it is no longer probable that the hedged transaction will not occur, in which case, the gains and losses that were previously deferred in AOCI will be immediately recognized in current period earnings.
The fair value of a derivative designated as a fair value hedge is recorded for balance sheet purposes as unrealized gains or unrealized losses on non-trading derivative and hedging transactions. The Partnership recognizesinstruments. We recognize the gain or loss on the derivative instrument, as well as the offsetting loss or gain on the hedged item in earnings in the current period. All derivatives designated and accounted for as fair value hedges are classified in the same category as the item being hedged in the results of operations.
Valuation — When available, quoted market prices or prices obtained through external sources are used to verifydetermine 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.
Values are adjusted to reflect the credit risk inherent in the transaction as well as the potential impact of liquidating open positions in an orderly manner over a reasonable time period under current conditions. Changes in market prices and management estimates directly affect the estimated fair value of these contracts. Accordingly, it is reasonably possible that such estimates may change in the near term.
Property, Plant and EquipmentRevenue Recognition — Property, plantWe generate the majority of our revenues from: (1) sales of natural gas, propane, NGLs and equipment are recorded at historical cost. Depreciation is computed usingcondensate; (2) natural gas gathering, processing and transportation, from which we generate revenue primarily through the straight-line method over the estimated useful livescompression, gathering, treating, processing and transportation of natural gas; (3) NGL transportation from which we generate revenues from transportation fees; as well as (4) trading and marketing of natural gas and NGLs.
We obtain access to commodities and provide our midstream services principally under contracts that contain a combination of one or more of the assets (see Note 8). The costs of maintenance and repairs, which are not significant improvements, are expensed when incurred. Expenditures to extend the useful lives of the assets are capitalized.
The Partnership has adopted SFAS No. 143 (“SFAS 143”),“Accounting for Asset Retirement Obligations,”and Financial Accounting Standards Board Interpretation No. 47 (“FIN 47”), “Accounting for Conditional Asset Retirement Obligations,”which address financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. The standard and interpretation apply to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, developmentand/or normal use of the asset. SFAS 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is
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incurred, if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset. This additional carrying amount is then depreciated over the life of the asset. The liability increases due to the passage of time based on the time value of money until the obligation is settled. FIN 47 requires the recognition of a liability of a conditional asset retirement obligation as soon as the fair value of the liability can be reasonably estimated. A conditional asset retirement obligation is defined as an unconditional legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity.
Impairment of Long-Lived Assets — Management periodically evaluates 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. The carrying amount is not recoverable if it exceeds the undiscounted sum of cash flows expected to result from the use and eventual disposition of the asset. Management considers various factors when determining if these assets should be evaluated for impairment, including but not limited to:following arrangements:
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| • | significant adverse changeFee-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. To the extent a sustained decline in legal factors orcommodity prices results in the business climate;a decline in volumes, however, our revenues from these arrangements would be reduced. |
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| • | a current-period operatingPercentage-of-proceeds arrangements — Underpercentage-of-proceeds arrangements, we generally purchase natural gas from producers at the wellhead, transport the wellhead natural gas through our gathering system, treat and process the natural gas, and then sell the resulting residue natural gas and NGLs at index prices based on 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 cash flow loss combined with a historyanagreed-upon percentage of operating or cash flow losses or a projection or forecast that demonstrates continuing losses associatedthe proceeds based on index related prices for the natural gas and the NGLs, regardless of the actual amount of the sales proceeds we receive. Under these types of arrangements, our revenues correlate directly with the useprice of a long-lived asset;natural gas and NGLs. |
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| • | an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction ofPropane 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 long-lived asset; |
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| • | significant adverse changes in the extent or manner in which an asset is used or in its physical condition; |
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| • | a significant 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. |
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. Management assesses 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, internally developed discounted cash flow analysis and analysis from outside advisors. Significant changes in market conditions resulting from events such as the condition of an asset or a change in management’s intent to utilize the asset would generally require management to reassess the cash flows related to the long-lived assets.
Intangible Asset — Intangible asset consists of a commodity contract. The commodity contract is amortized on a straight-line basis over the period of expected future benefit of approximately 25 years (see Note 9).
Equity Method Investment — The Partnership accounts for investments in 20% to 50% owned affiliates, and investments in less than 20% owned affiliates where the Partnership has the ability to exercise significant influence, under the equity method.
Impairment of Equity Method Investment — The Partnership evaluates its equity method investment for impairment when events or changes in circumstances indicate, in management’s judgment, that the carrying value of such investment may have experienced another-than-temporary decline in value. When evidence of loss in value has occurred, management compares the estimated fair value of the investment to the carrying value of the investment to determine whether an impairment has occurred. Management assesses the fair value of its equity method investment using commonly accepted techniques, and may use more than one method,
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| | 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. |
including, but not limited to, recent third party comparable
Our marketing of natural gas and NGLs consists of physical purchases and sales, internally developed discounted cash flow analysis and analysis from outside advisors. If the estimated fair value is less than the carrying value and management considers the declineas well as positions in value to be other than temporary, the excess of the carrying value over the estimated fair value is recognized in the financial statements as an impairment.derivative instruments.
Revenue Recognition — The Partnership’s primary types ofWe recognize revenues for sales and service activities reportedservices under the four revenue recognition criteria, as operating revenue include:follows:
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| • | salesPersuasive evidence of natural gas, NGLsan arrangement exists — Our customary practice is to enter into a written contract, executed by both us and condensate;the customer. |
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| • | natural gas gathering, processingDelivery — 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 transportation, from whichcustody is transferred to the Partnership generates revenues primarily through the compression, gathering, treating, processing and transportation of natural gas; andthird party purchaser. |
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| • | NGL transportation fromThe 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. |
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| • | Collectability is probable — Collectability is evaluated on acustomer-by-customer basis. New and existing customers are subject to a credit review process, which evaluates the Partnership generates revenues from transportation fees.customers’ financial position (for example, cash position and credit rating) and their ability to pay. If collectability is not considered probable at the outset of an arrangement in accordance with our credit review process, revenue is recognized when the fee is collected. |
Revenues associated with salesWe generally report revenues gross in the consolidated statements of natural gas, NGLs and condensate are recognized when title passesoperations, as we typically act as the principal in these transactions, take custody to the customer, which is whenproduct, and incur the riskrisks and rewards of ownership passes to the purchaserownership. Effective April 1, 2006, any new or amended contracts for certain sales and physical delivery occurs. Revenues associated with transportation and processing fees are recognized when the service is provided.
For gathering and processing services, the Partnership receives either fees or commodities from natural gas producers depending on the typepurchases of contract. Commodities received are in turn sold and recognized as revenue in accordanceinventory with the criteria outlined above. Under thepercentage-of-proceeds contract type, the Partnership is paid for its services by keeping a percentagesame counterparty, when entered into in contemplation of the NGLs produced and a percentage of the residue gas resulting from processing the natural gas. Under thepercentage-of-index contract type, the Partnership purchases wellhead natural gas and sells processed natural gas and NGLs to third parties.
The Partnership recognizesone another, are reported net as one transaction. We recognize revenues for non-trading derivative activity net in the consolidated statements of operations as gains (losses) gains from non-trading derivative activity, in accordance with EITF IssueNo. 02-03,“Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities.”activity. These activities includemark-to-market gains and losses on energy derivativetrading contracts and the financial or physical settlement of energy derivativetrading contracts.
The Partnership generally reports revenues gross in the consolidated statements of operations, in accordance with EITF IssueNo. 99-19,“Reporting Revenue Gross as a Principal versus Net as an Agent.”Except for fee-based agreements, the Partnership acts as the principal in these transactions, takes title to the product, and incurs the risks and rewards of ownership.
Significant Customer — The PartnershipWe had one customer, a third party, that accounted for 24%, 31%17% and 26%18% of total operating revenues for the years ended December 31, 2005 2004 and 2003,2004, respectively. Revenues from this customer are reported in the NGL Logistics Segment. The PartnershipThere were no customers that accounted for more than 10% of total operating revenues for the year ended December 31, 2006. We also had significant transactions with affiliates (see Note 7).
Unamortized Debt Expense5), and with suppliers of propane (see “Item 1. Business — Expenses incurred with the issuance of long-term debt are amortized over the terms of the debt using the effective interest method. These expenses are recorded on the consolidated balance sheet as other non-current assets.Wholesale Propane Logistics Segment.”)
Environmental Expenditures — Environmental expenditures are expensed or capitalized as appropriate, depending upon the future economic benefit. Expenditures that relate to an existing condition caused by past operations and that do not generate current or future revenue are expensed. Liabilities for these expenditures are recorded on an undiscounted basis when environmental assessmentsand/ororclean-ups clean-ups are probable and the costs can be reasonably estimated.
Gas Environmental liabilities as of December 31, 2006 and NGL Imbalance Accounting — Quantities of natural gas or NGLs over-delivered or under-delivered related to imbalance agreements with customers, producers or pipelines are recorded monthly2005, included in the consolidated balance sheets as
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other receivables or other payables using then current market prices or the weighted average prices of natural gas or NGLs at the plant or system. These balances are settled with deliveries of natural gas or NGLs or with cash.liabilities, were not significant.
Equity-Based Compensation — Under the Partnership’s Long TermDCP Midstream Partners, LP Long-Term Incentive Plan, or the LTIP, equity instruments may be granted to the Partnership’sour key employees. The Partnership accounts for equity-based compensation usingGeneral Partner adopted the intrinsic value recognition and measurement principles of Accounting Principles Board (“APB”) Opinion No. 25,“Accounting for Stock Issued to Employees,” and FASB Interpretation No. 44,“Accounting for Certain Transactions Involving Stock Compensation (an Interpretation of APB Opinion No. 25).” The Partnership had not granted any share-based instruments as of December 31, 2005.
DCP Midstream GP, LLC adopted a Long-Term Incentive Plan, or the Plan,LTIP for employees, consultants and directors of DCP Midstream GP, LLCthe General Partner and its affiliates who perform services for the Partnership.us. The PlanLTIP provides for the grant of restricted units, phantom units, unit options and substitute awards and, with respect to unit options and phantom units, the grant of distribution equivalent rights, or DERs. Subject to
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adjustment for certain events, an aggregate of 850,000 common units may be delivered pursuant to awards under the Plan. UnitsLTIP. Awards that are cancelled, forfeited or are withheld to satisfy DCP Midstream GP, LLC’sthe General Partner’s tax withholding obligations are available for delivery pursuant to other awards. The PlanLTIP is administered by the compensation committee of DCP Midstream GP, LLC’sthe General Partner’s board of directors. Awards were first granted under the LTIP during 2006.
Effective January 1, 2006, we adopted the provisions of SFAS No. 123 (Revised 2004),Share-Based Payment, or SFAS 123R, which establishes accounting for stock-based awards exchanged for employee and non-employee services. Accordingly, equity classified stock-based compensation cost is measured at grant date, based on the estimated fair value of the award, and is recognized as expense over the vesting period. Liability classified stock-based compensation cost is remeasured at each reporting date and is recognized over the requisite service period. Compensation expense for awards with graded vesting provisions is recognized on a straight-line basis over the requisite service period of each separately vesting portion of the award. Awards granted to non-employees are accounted for under the provisions of EITFNo. 96-18,Accounting for Equity Instruments That Are Issued to Other Than Employees for Acquiring, or in Conjunction with Selling, Goods or Services.
Income Taxes — We are structured as a master limited partnership which is a pass-through entity for federal income tax purposes. Our wholesale propane logistics business changed its tax structure, effective December 7, 2005, such that it became a pass-through entity. Prior to December 7, 2005, our wholesale propane logistics business was considered taxable for United States income tax purposes. Our wholesale propane logistics business followed the asset and liability method of accounting for income taxes, whereby deferred income taxes are recognized for the tax consequences of temporary differences between the financial statement carrying amounts and the tax basis of the assets and liabilities. Subsequent to December 7, 2005, our taxable income or loss, which may vary substantially from the net income or loss reported in the consolidated statements of operations, is includable in the federal returns of each partner.
Comprehensive Income — Comprehensive income consists of net income and other comprehensive income, which includes unrealized gains and losses on the effective portion of derivative instruments classified as cash flow hedges.
Net Income per Limited Partner Unit — Basic and diluted net income per limited partner unit is calculated by dividing limited partners’ interest in net income, less pro forma general partner incentive distributions under EITF IssueNo. 03-6,Participating Securities and the Two — Class Method Under FASB Statement No. 128, or EITF03-6, by the weighted averageweighted-average number of outstanding limited partner units during the period (see Note 5)16).
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3. | New Accounting Standards |
SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities — including an amendment of FAS 115, or SFAS 159 — In February 2007, the FASB issued SFAS 159, which allows entities to choose, at specified election dates, to measure eligible financial assets and liabilities at fair value that are not otherwise required to be measured at fair value. If a company elects the fair value option for an eligible item, changes in that item’s fair value in subsequent reporting periods must be recognized in current earnings. SFAS 159 also establishes presentation and disclosure requirements designed to draw comparison between entities that elect different measurement attributes for similar assets and liabilities. SFAS 159 is effective for us on January 1, 2008. We have not assessed the impact of SFAS 159 on our consolidated results of operations, cash flows or financial position.
SFAS No. 157, Fair Value Measurements, or SFAS 157 — In September 2006, the FASB issued SFAS 157, which provides guidance for using fair value to measure assets and liabilities. The standard also responds to investors’ requests for more information about: (1) the extent to which companies measure assets
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
and liabilities at fair value; (2) the information used to measure fair value; and (3) the effect that fair value measurements have on earnings. SFAS 157 will apply whenever another standard requires (or permits) assets or liabilities to be measured at fair value. SFAS 157 does not expand the use of fair value to any new circumstances. SFAS 157 is effective for us on January 1, 2008. We have not assessed the impact of SFAS 157 on our consolidated results of operations, cash flows or financial position.
SFAS No. 154, (“SFAS 154”), “AccountingAccounting Changes and Error Corrections.”Corrections, or SFAS 154 — In June 2005, the FASB issued SFAS 154, a replacement of APB Opinion No. 20, or APB 20,“Accounting Changes”Changes, and FASB StatementSFAS No. 3,“Reporting Accounting Changes in Interim Financial Statements”.Statements. Among other changes, SFAS 154 requires that a voluntary change in accounting principle be applied retrospectively with all prior period financial statements presented onunder the new accounting principle, unless it is impracticable to do so. SFAS 154 alsoalso: (1) provides that (1) a change in methoddepreciation or amortization of depreciating or amortizing a long-lived nonfinancial asset be accounted for as a change in estimate (prospectively) that was effected by a change in accounting principle,principle; and (2) carries forward without change the guidance within APB 20 for reporting the correction of errorsan error in previously issued financial statements should be termedand a restatement.change in accounting estimate. The new standard is effective for accounting changes and correction of errors made in fiscal years beginning after December 15, 2005. Early adoption of this standard is permitted for accounting changes and correction of errors made in fiscal years beginning after June 1, 2005. The impact of SFAS 154 will depend on the nature and extent of any changes in accounting principles after the effective date, but the Partnership doesJanuary 1, 2006, did not currently expect SFAS 154 to have a material impact on itsour consolidated results of operations, cash flows or financial position.
FIN No. 47 (“48, Accounting for Uncertainty in Income Taxes — An Interpretation of FASB Statement 109, or FIN 47”), “Accounting for Conditional Asset Retirement Obligations”.48 —In March 2005,July 2006, the FASB issued FIN 47,48, which clarifies the accounting for conditional asset retirement obligations as useduncertainty in SFASincome taxes recognized in financial statements in accordance with FASB Statement No. 143 (“SFAS 143”).109,“Accounting for Asset Retirement Obligations”.Income Taxes. A conditional asset retirement obligation is an unconditional legal obligation to perform an asset retirement activity in which the timingFIN 48 prescribes a recognition threshold and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. Therefore, an entity is required to recognize a liabilitymeasurement attribute for the fair valuefinancial statement recognition and measurement of a conditional asset retirement obligation under SFAS 143 if the fair value of the liability cantax position taken or expected to be reasonably estimated.taken in a tax return. FIN 47 permits, but does not require, restatement of48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim financial information.periods, disclosure and transition. The provisions of FIN 4748 are effective for reporting periods ending after December 15, 2005.us on January 1, 2007. The adoption of FIN 47 did48 is not expected to have a material impact on the Partnership’s consolidated results of operations, cash flows or financial position.
80
DCP MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
SFAS No. 153 (“SFAS 153”), “Exchanges of Nonmonetary Assets — an amendment of APB Opinion No. 29.” In December of 2004, the FASB issued SFAS 153, which amends APB Opinion No. 29 (“APB 29”) by eliminating the exception to the fair-value principle for exchanges of similar productive assets, which were accounted for under APB 29 based on the book value of the asset surrendered with no gain or loss recognition. SFAS 153 also eliminates APB 29’s concept of culmination of an earnings process. The amendment requires that an exchange of nonmonetary assets be accounted for at fair value if the exchange has commercial substance and fair value is determinable within reasonable limits. Commercial substance is assessed by comparing the entity’s expected cash flows immediately before and after the exchange. If the difference is significant, the transaction is considered to have commercial substance and should be recognized at fair value. SFAS 153 is effective for nonmonetary transactions occurring in fiscal periods beginning after June 15, 2005. The adoption of SFAS 153 did not have a material impact on the Partnership’sour consolidated results of operations, cash flows or financial position.
SFAS EITF IssueNo. 123 (Revised 2004) (“SFAS 123R”), “Share-Based Payment”.04-13, Accounting for Purchases and Sales of Inventory with the Same Counterparty, or EITF04-13 — In December of 2004,September 2005, the FASB issued SFAS 123R,ratified the EITF’s consensus on Issue04-13, which replaces SFAS 123requires an entity to treat sales and supersedespurchases of inventory between the entity and the same counterparty as one transaction for purposes of applying APB Opinion No. 25 (“29,Accounting for Nonmonetary Transactions, or APB 25”). SFAS 123R requires all share-based payments29, when such transactions are entered into in contemplation of each other. When such transactions are legally contingent on each other, they are considered to employees, including grantshave been entered into in contemplation of employee stock options, for public entities,each other. The EITF also agreed on other factors that should be considered in determining whether transactions have been entered into in contemplation of each other. EITF04-13 was applied to be recognized in the financial statements based on their fair values beginning with the first interim or annual periodnew arrangements that we entered into after June 15, 2005.March 31, 2006. The pro forma disclosures previously permitted under SFAS 123 no longer will be an alternative to financial statement recognition. The Partnership doesadoption of EITF04-13 did not currently expect SFAS 123R to have a material impact on itsour consolidated results of operations, cash flows or financial position.
Staff Accounting Bulletin No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements, or SAB 108 — In September 2006, the Securities and Exchange Commission, or SEC, issued SAB 108 to address diversity in practice in quantifying financial statement misstatements. SAB 108 requires entities to quantify misstatements based on their impact on each of their financial statements and related disclosures. SAB 108 is effective as of the end of our 2006 fiscal year, allowing a one-time transitional cumulative effect adjustment to retained earnings as of January 1, 2006 for errors that were not previously deemed material, but are material under the guidance in SAB 108. The adoption of SAB 108 did not have a material impact on our consolidated results of operations, cash flows or financial position.
| |
4. | Partnership Equity and DistributionsAcquisition |
General. The partnership agreement requires that, within 45 days after the endOn November 1, 2006, we acquired our wholesale propane logistics business, from DCP Midstream, LLC for aggregate consideration consisting of each quarter, the Partnership distribute allapproximately $82.9 million, which consisted of its available cash to unitholders of record on the applicable record date, as determined by the general partner.
Definition of Available Cash. Available cash and cash equivalents, for any quarter, consists of all cash on hand at the end of that quarter:
| | |
| • | less the amount of cash reserves established by the general partner to: |
| | |
| • | provide for the proper conduct of the Partnership’s business; |
|
| • | comply with applicable law, any of the Partnership’s debt instruments or other agreements; or |
|
| • | provide funds for distributions to the unitholders and to the general partner for any one or more of the next four quarters; |
| | |
| • | plus, if the general partner so determines, all or a portion of cash and cash equivalents on hand on the date of determination of available cash for the quarter. |
General Partner Interest and Incentive Distribution Rights. The general partner is entitled to 2% of all quarterly distributions that the Partnership makes prior to its liquidation. This general partner interest is represented by 357,143 general partner units. The general partner has the right, but not the obligation, to contribute a proportionate amount of capital to the Partnership to maintain its current general partner interest. The general partner’s initial 2% interest$77.3 million in these distributions will be reduced if the Partnership issues additional units in the future and the general partner does not contribute a proportionate amount of capital to the Partnership to maintain its 2% general partner interest.
The incentive distribution rights held by the general partner entitles it to receive an increasing share of available cash when pre-defined distribution targets are achieved. Please read theDistributions of Available Cash during the Subordination Period and Distributions of Available Cash after the Subordination Period
8197
DCP MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
sections below for more details aboutcash ($9.9 million of which was paid in January 2007), and the distribution targets and their impact onissuance of 200,312 Class C units valued at approximately $5.6 million. Included in the general partner’s incentive distribution rights.aggregate consideration was $10.5 million of costs associated with the construction of a new propane pipeline terminal.
Subordinated Units. AllThe transfer of assets between DCP Midstream, LLC and us represents a transfer of assets between entities under common control. Transfers of net assets or exchanges of shares between entities under common control are accounted for as if the transfer occurred at the beginning of the subordinated unitsperiod, and prior years are held by DEFS.retroactively adjusted to furnish comparative information similar to the pooling method. The partnership agreement provides that, during$26.3 million excess purchase price over the subordination period, the common units will have the right to receive distributions of available cash each quarter in an amount equal to $0.35 per common unit (the “Minimum Quarterly Distribution”), plus any arrearages in the paymenthistorical basis of the Minimum Quarterly Distributionnet acquired assets is recorded as a reduction to partners’ equity for financial accounting purposes.
The following table presents the impact on the common units from prior quarters, before any distributions of available cash may be made on the subordinated units. These units are deemed ”subordinated” because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distributions until the common units have received the Minimum Quarterly Distribution plus any arrearages from prior quarters. Furthermore, no arrearages will be paid on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that during the subordination period there will be available cash to be distributed on the common units. The subordination period will end, and the subordinated units will convert to common units, on a one for one basis, when certain distribution requirements, as defined in the partnership agreement, have been met. The earliest dateour condensed consolidated financial position at which the subordination period may end is December 31, 2008 and 50%2005, adjusted for the acquisition of the subordinated units may convert to common units as early as December 31, 2007. The rights of the subordinated unitholders, other than the distribution rights described above, are substantially the same as the rights of the common unitholders.our wholesale propane logistics business from DCP Midstream, LLC ($ in millions):
| | | | | | | | | | | | |
| | | | | Wholesale
| | | Combined
| |
| | DCP
| | | Propane
| | | DCP
| |
| | Midstream
| | | Logistics
| | | Midstream
| |
| | Partners, LP | | | Business | | | Partners, LP | |
|
ASSETS |
Current assets: | | | | | | | | | | | | |
Cash and cash equivalents | | $ | 42.2 | | | $ | — | | | $ | 42.2 | |
Accounts receivable | | | 82.0 | | | | 40.2 | | | | 122.2 | |
Inventories | | | 0.1 | | | | 41.6 | | | | 41.7 | |
Other | | | 0.2 | | | | 0.1 | | | | 0.3 | |
| | | | | | | | | | | | |
Total current assets | | | 124.5 | | | | 81.9 | | | | 206.4 | |
Restricted investments | | | 100.4 | | | | — | | | | 100.4 | |
Property, plant and equipment, net | | | 168.9 | | | | 9.8 | | | | 178.7 | |
Goodwill and intangible assets, net | | | 2.1 | | | | 30.4 | | | | 32.5 | |
Other non-current assets | | | 11.4 | | | | 0.5 | | | | 11.9 | |
| | | | | | | | | | | | |
Total assets | | $ | 407.3 | | | $ | 122.6 | | | $ | 529.9 | |
| | | | | | | | | | | | |
|
LIABILITIES AND PARTNERS’ EQUITY |
Accounts payable and other current liabilities | | $ | 93.4 | | | $ | 52.9 | | | $ | 146.3 | |
Long-term debt | | | 210.1 | | | | — | | | | 210.1 | |
Other long-term liabilities | | | 2.9 | | | | 0.1 | | | | 3.0 | |
| | | | | | | | | | | | |
Total liabilities | | | 306.4 | | | | 53.0 | | | | 359.4 | |
| | | | | | | | | | | | |
Commitments and contingent liabilities | | | | | | | | | | | | |
Partners’ equity: | | | | | | | | | | | | |
Net equity | | | 100.5 | | | | 69.6 | | | | 170.1 | |
Accumulated other comprehensive income | | | 0.4 | | | | — | | | | 0.4 | |
| | | | | | | | | | | | |
Total partners’ equity | | | 100.9 | | | | 69.6 | | | | 170.5 | |
| | | | | | | | | | | | |
Total liabilities and partners’ equity | | $ | 407.3 | | | $ | 122.6 | | | $ | 529.9 | |
| | | | | | | | | | | | |
Distributions of Available Cash during the Subordination Period. The partnership agreement requires that the Partnership makes distributions of available cash for any quarter during the subordination period in the following manner:
| | |
| • | first, 98% to the common unitholders, pro rata, and 2% to the general partner, until the Partnership distributes for each outstanding common unit an amount equal to the Minimum Quarterly Distribution for that quarter; |
|
| • | second, 98% to the common unitholders, pro rata, and 2% to the general partner, until the Partnership distributes 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, 98% to the subordinated unitholders, pro rata, and 2% to the general partner, until the Partnership distributes for each subordinated unit an amount equal to the Minimum Quarterly Distribution for that quarter; and |
|
| • | fourth, 98% to all unitholders, pro rata, and 2% to the general partner, until each unitholder receives a total of $0.4025 per unit for that quarter; |
|
| • | fifth, 85% to all unitholders, pro rata, and 15% to the general partner, until each unitholder receives a total of $0.4375 per unit for that quarter; |
|
| • | sixth, 75% to all unitholders, pro rata, and 25% to the general partner, until each unitholder receives a total of $0.525 per unit for that quarter; and |
|
| • | thereafter, 50% to all unitholders, pro rata, and 50% to the general partner. |
Distributions of Available Cash after the Subordination Period. The partnership agreement requires that the Partnership makes distributions of available cash from operating surplus for any quarter after the subordination period in the following manner:
| | |
| • | first, 98% to all unitholders, pro rata, and 2% to the general partner, until each unitholder receives a total of $0.4025 per unit for that quarter; |
8298
DCP MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| | |
| • | second, 85% to all unitholders, pro rata, and 15% toThe following tables present the general partner, until each unitholder receives a total of $0.4375 per unit for that quarter; |
|
| • | third, 75% to all unitholders, pro rata, and 25% to the general partner, until each unitholder receives a total of $0.525 per unit for that quarter; and |
|
| • | thereafter, 50% to all unitholders, pro rata, and 50% to the general partner. |
On January 25, 2006, the Partnership announced the declaration of a cash distribution of $0.095 per unit, payable on February 13, 2006 to unitholders of record on February 3, 2006. That distribution represents the pro rata portion of the Partnership’s Minimum Quarterly Distribution of $0.35 per unit for the period December 7, 2005, the closing of the Partnership’s initial public offering, through December 31, 2005.
| |
5. | Net Income per Limited Partner Unit |
The Partnership’s net income is allocated to the general partner and the limited partners, including the holders of the subordinated units, in accordance with their respective ownership percentages, after giving effect to incentive distributions paid to the general partner.
EITF IssueNo. 03-6, (“EITF 03-6”)“Participating Securities and the Two — Class Method Under FASB Statement No. 128,”addresses the computation of earnings per share by entities that have issued securities other than common stock that contractually entitle the holder to participate in dividends and earnings of the entity when, and if, it declares dividends on its common stock.
EITF 03-6 requires that securities that meet the definition of a participating security be considered for inclusion in the computation of basic earnings per unit using the two-class method. Under the two-class method, earnings per unit is calculated as if all of the earnings for the period were distributed under the terms of the partnership agreement, regardless of whether the general partner has discretion over the amount of distributions to be made in any particular period, whether those earnings would actually be distributed during a particular period from an economic or practical perspective, or whether the general partner has other legal or contractual limitations on its ability to pay distributions that would prevent it from distributing all of the earnings for a particular period.
EITF 03-6 does not impact the Partnership’s overall net income or other financial results; however, in periods in which aggregate net income exceeds the Partnership’s aggregate distributions for such period, it will have the impact of reducing net income per limited partner unit. This result occurs as a larger portion of the Partnership’s aggregate earnings, as if distributed, is allocated to the incentive distribution rights of the general partner, even though the Partnership makes distributions on the basis of available cash and not earnings. In periods in which the Partnership’s aggregate net income does not exceed its aggregate distributions for such period,EITF 03-6 does not have any impact on the Partnership’s calculationcondensed consolidated statements of earnings per limited partner unit.operations, adjusted for the acquisition of our wholesale propane logistics business from DCP Midstream, LLC, for the periods presented ($ in millions):
| | | | | | | | | | | | |
| | Year Ended December 31, 2005 | |
| | DCP
| | | Wholesale
| | | Combined
| |
| | Midstream
| | | Propane
| | | DCP
| |
| | Partners, LP and
| | | Logistics
| | | Midstream
| |
| | Predecessor | | | Business | | | Partners, LP | |
|
Operating revenues: | | | | | | | | | | | | |
Sales of natural gas, propane, NGLs and condensate | | $ | 762.3 | | | $ | 359.8 | | | $ | 1,122.1 | |
Transportation and other | | | 22.2 | | | | — | | | | 22.2 | |
| | | | | | | | | | | | |
Total operating revenues | | | 784.5 | | | | 359.8 | | | | 1,144.3 | |
| | | | | | | | | | | | |
Operating costs and expenses: | | | | | | | | | | | | |
Purchases of natural gas, propane and NGLs | | | 709.3 | | | | 338.0 | | | | 1,047.3 | |
Operating and maintenance expense | | | 14.2 | | | | 8.2 | | | | 22.4 | |
Depreciation and amortization expense | | | 11.7 | | | | 1.0 | | | | 12.7 | |
General and administrative expense | | | 11.4 | | | | 2.8 | | | | 14.2 | |
| | | | | | | | | | | | |
Total operating costs and expenses | | | 746.6 | | | | 350.0 | | | | 1,096.6 | |
| | | | | | | | | | | | |
Operating income | | | 37.9 | | | | 9.8 | | | | 47.7 | |
Interest expense, net | | | (0.3 | ) | | | — | | | | (0.3 | ) |
Earnings from equity method investments | | | 0.4 | | | | — | | | | 0.4 | |
Income tax expense | | | — | | | | (3.3 | ) | | | (3.3 | ) |
| | | | | | | | | | | | |
Net income | | $ | 38.0 | | | $ | 6.5 | | | $ | 44.5 | |
| | | | | | | | | | | | |
Basic and diluted net income per limited partner unit is calculated by dividing limited partners’ interest in net income, less pro forma general partner incentive distributions underEITF 03-6, by the weighted average number of outstanding limited partner units during the period.
| | | | | | | | | | | | |
| | Year Ended December 31, 2004 | |
| | DCP
| | | Wholesale
| | | Combined
| |
| | Midstream
| | | Propane
| | | DCP
| |
| | Partners
| | | Logistics
| | | Midstream
| |
| | Predecessor | | | Business | | | Partners, LP | |
|
Operating revenues: | | | | | | | | | | | | |
Sales of natural gas, propane, NGLs and condensate | | $ | 489.7 | | | $ | 325.7 | | | $ | 815.4 | |
Transportation and other | | | 19.8 | | | | (1.2 | ) | | | 18.6 | |
| | | | | | | | | | | | |
Total operating revenues | | | 509.5 | | | | 324.5 | | | | 834.0 | |
| | | | | | | | | | | | |
Operating costs and expenses: | | | | | | | | | | | | |
Purchases of natural gas, propane and NGLs | | | 452.6 | | | | 308.0 | | | | 760.6 | |
Operating and maintenance expense | | | 13.6 | | | | 6.2 | | | | 19.8 | |
Depreciation and amortization expense | | | 12.6 | | | | 2.1 | | | | 14.7 | |
General and administrative expense | | | 6.5 | | | | 2.2 | | | | 8.7 | |
| | | | | | | | | | | | |
Total operating costs and expenses | | | 485.3 | | | | 318.5 | | | | 803.8 | |
| | | | | | | | | | | | |
Operating income | | | 24.2 | | | | 6.0 | | | | 30.2 | |
Earnings from equity method investments | | | 0.6 | | | | — | | | | 0.6 | |
Impairment of equity method investment | | | (4.4 | ) | | | — | | | | (4.4 | ) |
Income tax expense | | | — | | | | (2.5 | ) | | | (2.5 | ) |
| | | | | | | | | | | | |
Net income | | $ | 20.4 | | | $ | 3.5 | | | $ | 23.9 | |
| | | | | | | | | | | | |
8399
DCP MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The following table illustrates the Partnership’s calculation of net income per limited partner unit for the year ended December 31, 2005:
| | | | |
Net income | | $ | 38.0 | |
Less: | | | | |
Net income applicable to the period through December 6, 2005 | | | (33.3 | ) |
| | | | |
Net income applicable to the period December 7, 2005 through December 31, 2005 | | | 4.7 | |
Less: General partner interest in net income | | | (0.1 | ) |
| | | | |
Limited partners’ interest in net income (see Note 4) | | | 4.6 | |
Additional earnings allocation to general partner | | | (1.1 | ) |
| | | | |
Net income available to limited partners underEITF 03-6 | | $ | 3.5 | |
| | | | |
Net income per limited partner unit — basic and diluted | | $ | 0.20 | |
| | | | |
| |
6. | Impairment of Equity Method Investment |
In the third quarter of 2004, the Partnership recognized another-than-temporary impairment of its investment in Black Lake totaling $4.4 million as impairment of equity method investment, included in the consolidated statements of operations. This investment was written down to fair value which was determined based on management’s best estimates of discounted future cash flow models. The charge associated with this impairment is recorded in the NGL Logistics segment.
| |
7.5. | Agreements and Transactions with Affiliates |
DEFSDCP Midstream, LLC
Omnibus Agreement
The employees supporting the Partnership’s operations are employees of DEFS. The Partnership is required to reimburse DEFS for salaries of operating personnel and employee benefits as well as capital expenditures, maintenance and repair costs and taxes. DEFS also providesDCP Midstream, LLC provided centralized corporate functions on behalf of the Partnership,our predecessor operations, including legal, accounting, cash management, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, taxes and engineering. DEFS records the accrued liabilities and prepaid expenses for most general and administrative expenses in its financial statements, including liabilities related to payroll, short and long-term incentive plans, employee retirement and medical plans, paid time off, audit, tax, insurance and other service fees. The Partnership’spredecessor’s share of those costs has beenwas allocated based on the Partnership’spredecessor’s proportionate net investment (consisting of property, plant and equipment, net, equity method investment, and intangible assets, net) as compared to DEFS’DCP Midstream, LLC’s net investment. In management’s estimation, the allocation methodologies used arewere reasonable and resultresulted in an allocation to the Partnershippredecessors of itstheir respective costs of doing business, which were borne by DEFS.DCP Midstream, LLC.
Upon the closing of the initial public offering, the PartnershipOmnibus Agreement
We have entered into an omnibus agreement, or the Omnibus Agreement, with DEFS, its general partnerDCP Midstream, LLC. Under the Omnibus Agreement, as amended, we are required to reimburse DCP Midstream, LLC for salaries of operating personnel and othersemployee benefits as well as capital expenditures, maintenance and repair costs, taxes and other direct costs incurred by DCP Midstream, LLC on our behalf. We also pay DCP Midstream, LLC an annual fee of $4.8 million related to the DCP Midstream Predecessor business contributed to us upon our initial public offering. The annual fee is for centralized corporate functions performed by DCP Midstream, LLC on our behalf, including legal, accounting, cash management, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, taxes and engineering. In the second quarter of 2006, we amended the Omnibus Agreement. The amendment clarifies that the annual fee of $4.8 million under the agreement is fixed at such amount, subject to annual increases in the Consumer Price Index, and increases in connection with the expansion of our operations through the acquisition or construction of new assets or businesses. The Omnibus Agreement was further amended in November 2006, in conjunction with the acquisition of our wholesale propane logistics business from DCP Midstream, LLC. Under this amendment, we pay DCP Midstream, LLC an additional annual fee of $2.0 million related to our wholesale propane logistics business, subject to the same conditions noted above. This additional $2.0 million fee was prorated in 2006 from the date of our wholesale propane logistics business acquisition.
The Omnibus Agreement addresses the following matters:
| | |
| • | the Partnership’sour obligation to reimburse DEFSDCP Midstream, LLC for the payment of operating expenses, including salary and benefits of operating personnel, it incurs on the Partnership’sour behalf in connection with the Partnership’sour business and operations; |
|
| • | the Partnership’sour obligation to reimburse DEFSDCP Midstream, LLC for providing the Partnershipus with general and administrative services with respect to itsour business and operations, which is capped at a maximum of $4.8$6.8 million, subject to an increase for 2007 and 2008 based on increases in the Consumer Price Index |
84
DCP MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| | |
| | and subject to further increases in connection with expansions of the Partnership’sour operations through the acquisition or construction of new assets or businesses with the concurrence of the Partnership’sour special committee; |
| | |
| • | the Partnership’sour obligation to reimburse DEFSDCP Midstream, LLC for insurance coverage expenses it incurs with respect to the Partnership’sour business and operations and with respect to director and officer liability coverage; |
|
| • | DEFS’DCP Midstream, LLC’s obligation to indemnify the Partnershipus for certain liabilities and the Partnership’sour obligation to indemnify DEFSDCP Midstream, LLC for certain liabilities; |
|
| • | DEFS’DCP Midstream, LLC’s obligation to continue to maintain its credit support, including without limitation guarantees and letters of credit, for the Partnership’sour obligations related to derivative financial instruments, such as commodity price hedging contracts, to the extent that such credit support arrangements arewere in |
100
DCP MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| | |
| | effect as of the closing of theour initial public offering until the earlier to occur of the fifth anniversary of the closing of theour initial public offering or such time as the Partnership obtainswe obtain an investment grade credit rating from either Moody’s Investor Services, Inc. or Standard & Poor’s Ratings Group with respect to any of itsour unsecured indebtedness; and |
| | |
| • | DEFS’DCP Midstream, LLC’s obligation to continue to maintain its credit support, including without limitation guarantees and letters of credit, for the Partnership’sour obligations related to commercial contracts with respect to its business or operations that arewere in effect at the closing of theour initial public offering until the expiration of such contracts. |
Any or all of the provisions of the Omnibus Agreement, other than the indemnification provisions, will be terminable by DEFSDCP Midstream, LLC at its option if the general partner is removed without cause and units held by the general partner and its affiliates are not voted in favor of that removal. The Omnibus Agreement will also terminate in the event of a change of control of the Partnership,us, the general partner (DCP Midstream GP, LP) or the general partner’s general partner.General Partner (DCP Midstream GP, LLC).
Reimbursement of Operating and General and Administrative Expense
Under the Omnibus Agreement the Partnership reimburses DEFS for the payment of certain operating expenses and for the provision of various general and administrative services for the Partnership’s benefit with respect to the assets contributed to it at the closing of the initial public offering. The Omnibus Agreement provides that the Partnership will reimburse DEFS for its allocable portion of the premiums on insurance policies covering its assets.
Pursuant to these arrangements, DEFS performs centralized corporate functions for the Partnership, such as legal, accounting, treasury, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, taxes and engineering. The Partnership will reimburse DEFS for the direct expenses to provide these services as well as other direct expenses it incurs on the Partnership’s behalf, such as salaries of operational personnel performing services for the Partnership’s benefit and the cost of their employee benefits, including 401(k), pension and health insurance benefits.
Competition
None of DEFSDCP Midstream, LLC, nor any of its affiliates, including DukeSpectra Energy and ConocoPhillips, is restricted, under either the partnership agreement or the Omnibus Agreement, from competing with the Partnership. DEFSus. DCP Midstream, LLC and any of its affiliates, including DukeSpectra Energy and ConocoPhillips, may acquire, construct or dispose of additional midstream energy or other assets in the future without any obligation to offer the Partnershipus the opportunity to purchase or construct those assets.
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DCP MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Indemnification
Under the Omnibus Agreement, DEFSDCP Midstream, LLC will indemnify the Partnershipus for three years after the closing of theour initial public offering against certain potential environmental claims, losses and expenses associated with the operation of the assets and occurring before the closing date of theour initial public offering. DEFS’DCP Midstream, LLC’s maximum liability for this indemnification obligation does not exceed $15 million and DEFSDCP Midstream, LLC does not have any obligation under this indemnification until the Partnership’sour aggregate losses exceed $250,000. DEFSDCP Midstream, LLC has no indemnification obligations with respect to environmental claims made as a result of additions to or modifications of environmental laws promulgated after the closing date of theour initial public offering. The Partnership hasWe have agreed to indemnify DEFSDCP Midstream, LLC against environmental liabilities related to the Partnership’sour assets to the extent DEFSDCP Midstream, LLC is not required to indemnify the Partnership.us.
Additionally, DEFSDCP Midstream, LLC will indemnify the Partnershipus for losses attributable to title defects, retained assets and liabilities (including preclosing litigation relating to contributed assets) and income taxes attributable to pre-closing operations. The PartnershipWe will indemnify DEFSDCP Midstream, LLC for all losses attributable to the postclosing operations of the assets contributed to the Partnership,us, to the extent not subject to DEFS’DCP Midstream, LLC’s indemnification obligations. In addition, DEFSDCP Midstream, LLC has agreed to indemnify the Partnershipus for up to $5.3 million of itsour pro rata share of any capital contributions required to be made by the Partnershipus to Black Lake associated with any repairs to the Black Lake pipeline that are determined to be necessary as a result of the currently ongoing pipeline integrity testing occurring from 2005 through 2007. DEFSDCP Midstream, LLC has also agreed to indemnify the Partnershipus for up to $4.0 million of the costs associated with any repairs to the Seabreeze pipeline that are determined to be necessary as a result of the scheduled pipeline integrity testing occurringthat occurred in 2006. Pipeline integrity testing and repairs are our responsibility and are recognized as operating and maintenance expense. Any reimbursements of these expenses from DCP Midstream, LLC will be recognized by us as a capital contribution. Reimbursements related to the Seabreeze pipeline integrity repairs in 2006 and 2007.were not significant.
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DCP MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Other Agreements and Transactions with DEFSDCP Midstream, LLC
Prior to theour initial public offering on December 7, 2005, the Partnershipwe participated in DEFS’DCP Midstream, LLC’s cash management program. As a result, the Partnershipwe had no cash balances on theour consolidated balance sheets and all cash management activity was performed by DEFSDCP Midstream, LLC on our behalf, of the Partnership, including collection of receivables, payment of payables, and the settlement of sales and purchases transactions between the Partnershipus and DEFS,DCP Midstream, LLC, which were recorded as parent advances and included in accounts receivable — affiliates or accounts payable — affiliates. Subsequent to the initial public offering, the Partnership maintainswe maintain separate cash accounts, which are managed by DEFS.DCP Midstream, LLC.
The Partnership hasDCP Midstream, LLC owns certain assets and is party to certain contractual relationships around our Pelico system that are periodically used for the benefit of Pelico. DCP Midstream, LLC is able to source natural gas upstream of Pelico and deliver it to the inlet of the Pelico system, and is able to take natural gas from the outlet of the Pelico system and market it downstream of Pelico. Because of DCP Midstream, LLC’s ability to move natural gas around Pelico, there are certain contractual relationships around Pelico that define how natural gas is bought and sold between us and DCP Midstream, LLC.
Effective December 2005, we entered into a contractual arrangement with a subsidiary of DEFSDCP Midstream, LLC that provides that DEFSDCP Midstream, LLC will purchase natural gas and transport it to the PELICOPelico system, where the Partnershipwe will buy the gas from DEFSDCP Midstream, LLC at its weighted averageweighted-average cost delivered to the Pelico system, plus a contractually agreed toagreed-to marketing fee.fee and other related adjustments. In addition, for a significant portion of the gas that the Partnership sellswe sell out of its PELICOour Pelico system, the Partnership has entered into a contractual arrangement with a subsidiary of DEFS that provides that DEFSDCP Midstream, LLC will purchase that natural gas from the Partnershipus and transport it to a sales point at a price equal to its net weighted averageweighted-average sales price, less a contractually agreedagreed-to marketing fee and other related adjustments. We generally report revenues and purchases associated with these activities gross in the consolidated statements of operations as sales of natural gas, propane, NGLs and condensate to marketing fee. These agreements have a two year term beginning in December 2005.affiliates and purchases of natural gas, propane and NGLs from affiliates.
The above agreement was amended and restated effective February 2006 in response to DCP Midstream, LLC securing additional access to natural gas for our Pelico system. The revised agreement is described below:
| | |
| • | DCP Midstream, LLC will supply Pelico’s system requirements that exceed its on-system supply. Accordingly, DCP Midstream, LLC purchases natural gas and 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 anindex-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 and processing services to affiliates. |
Effective December 2005, we entered into a contractual arrangement with a subsidiary of DCP Midstream, LLC that provides that for certain industrial end-user customers of the PELICOPelico system from time to time the Partnershipwe may sell
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DCP MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
aggregated natural gas to a subsidiary of DEFSDCP Midstream, LLC, which in turn would resell natural gas to these customers. The sales price to the subsidiary of DEFSDCP Midstream, LLC is equal to that subsidiary of DEFS’DCP Midstream, LLC’s net weighted averageweighted-average sales price delivered from the Pelico system less a contractually agreedagreed-to marketing fee, which is recorded in the consolidated statements of operations as sales of natural gas, propane, NGLs and condensate to marketing fee.affiliates.
Effective December 1, 2005, the Partnershipwe entered into a contractual arrangement with a subsidiary of DEFSDCP Midstream, LLC that provides that DEFSDCP Midstream, LLC will purchase the NGLs that were historically purchased by the Seabreeze pipeline, and DEFSDCP Midstream, LLC will pay the Partnershipus to transport the NGLs pursuant to a fee-based rate that will be applied to the volumes transported. The Partnership hasWe have entered into this fee-based contractual arrangement with the objective of generating approximately the same operating income per barrel transported that it
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DCP MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
we realized when it waswe were the purchaser and seller of NGLs. The Partnership doesWe do not take titlecustody to the products transported on the NGL pipeline; rather, the shipper retains titlecustody and the associated commodity price risk. DEFSDCP Midstream, LLC is the sole shipper on the Seabreeze pipeline under a17-year transportation agreement expiring in 2022. The Seabreeze pipeline collects only fee-basedWe generally report revenues associated with these activities in the consolidated statements of operations as transportation revenue under this agreement.and processing services to affiliates.
In December 2006, we completed construction of our Wilbreeze pipeline, which connects a DCP Midstream, LLC gas processing plant to our Seabreeze pipeline. The Partnership sellsproject is supported by a10-year NGL product dedication agreement with DCP Midstream, LLC.
We sell NGLs and condensate from itsour Minden and Ada processing plants, and the PELICOcondensate from our Pelico system to a subsidiary of DEFSDCP Midstream, LLC equal to that subsidiary of DEFS’DCP Midstream, LLC’s net weighted averageweighted-average sales price.price adjusted for transportation and other charges from the tailgate of the respective asset, which is recorded in the consolidated statements of operations as sales of natural gas, propane, NGLs and condensate to affiliates. We also sell propane to a subsidiary of DCP Midstream, LLC.
Management anticipatesWe anticipate continuing to purchase these commodities from and sell these commodities to DEFSDCP Midstream, LLC in the ordinary course of business. DEFS
In the second quarter of 2006, we entered into a letter agreement with DCP Midstream, LLC whereby DCP Midstream, LLC will make capital contributions to us as reimbursement for capital projects, which were forecasted to be completed prior to our initial public offering, but were not completed by that date. Pursuant to the letter agreement, DCP Midstream, LLC made capital contributions to us of $3.4 million during 2006, to reimburse us for the capital costs we incurred, primarily for growth capital projects. At December 31, 2006, all of these projects were completed.
We had an operating lease with an affiliate during the years ended December 31, 2005 and 2004. Operating lease expense related to this lease was $0.7 million and $2.8 million for the years ended December 31, 2005 and 2004, respectively.
DCP Midstream, LLC was a significant customer during the years ended December 31, 2006, 2005 2004 and 2003.2004.
Duke Energy and Spectra Energy
The Partnership chargesPrior to December 31, 2006, we charged transportation fees, sells asold portion of itsour residue gas to, and purchasespurchased raw natural gas from, Duke Energy and its affiliates. Management anticipatesWe anticipate continuing to purchase and sell these commodities to DukeSpectra Energy and its affiliates in the ordinary course of business. Duke Energy was a significant customer during the year ended December 31, 2003.
ConocoPhillips
The Partnership charges transportation fees and sellsWe have multiple agreements whereby we provide a portionvariety of its residue gas and NGLsservices to and purchases raw natural gas from ConocoPhillips and its affiliates. The Partnership has aagreements include fee-based contractual relationship with ConocoPhillips pursuant to which ConocoPhillips has dedicated all of its naturalandpercentage-of-proceeds gathering and processing
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DCP MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
arrangements, gas production within an area of mutual interest to the assets in the Partnership’s Natural Gas Services segment. Management anticipatespurchase and gas sales agreements. We anticipate continuing to purchase from and sell these commodities to ConocoPhillips and its affiliates in the ordinary course of business. In addition, the Partnershipwe may be reimbursed by ConocoPhillips for certain capital projects where the work is performed by the Partnership. The Partnershipus. We received $3.9 million, $0.2 million $0.3 million and $0.5$0.3 million of capital reimbursements during the years ended December 31, 2006, 2005 2004 and 2003,2004, respectively.
The following table summarizes the transactions with DEFS,DCP Midstream, LLC, Duke Energy and ConocoPhillips as described above ($ in millions):
| | | | | | | | | | | | |
| | For the Years Ended
| |
| | December 31, | |
| | 2005 | | | 2004 | | | 2003 | |
|
Duke Energy Field Services: | | | | | | | | | | | | |
Sales of natural gas, NGLs and condensate | | $ | 105.8 | | | $ | 63.0 | | | $ | 50.0 | |
Transportation and processing services | | $ | 0.3 | | | $ | — | | | $ | — | |
Purchases of natural gas and NGLs | | $ | 86.1 | | | $ | 26.7 | | | $ | 87.8 | |
(Losses) gains from non-trading derivative activity | | $ | (0.7 | ) | | $ | (0.1 | ) | | $ | 2.5 | |
General and administrative expense | | $ | 7.4 | | | $ | 6.5 | | | $ | 7.1 | |
Duke Energy: | | | | | | | | | | | | |
Sales of natural gas, NGLs and condensate | | $ | 1.4 | | | $ | 10.3 | | | $ | 81.1 | |
Transportation and processing services | | $ | 0.3 | | | $ | 0.5 | | | $ | 0.7 | |
Purchases of natural gas and NGLs | | $ | 3.1 | | | $ | 3.4 | | | $ | 1.6 | |
ConocoPhillips: | | | | | | | | | | | | |
Sales of natural gas, NGLs and condensate | | $ | 7.3 | | | $ | 3.7 | | | $ | 3.6 | |
Transportation and processing services | | $ | 10.0 | | | $ | 9.9 | | | $ | 8.4 | |
Purchases of natural gas and NGLs | | $ | 18.7 | | | $ | 18.4 | | | $ | 31.9 | |
| | | | | | | | | | | | |
| | Year Ended December 31, | |
| | 2006 | | | 2005 | | | 2004 | |
|
DCP Midstream, LLC: | | | | | | | | | | | | |
Sales of natural gas, propane, NGLs and condensate | | $ | 231.7 | | | $ | 108.8 | | | $ | 71.6 | |
Transportation and processing services | | $ | 4.8 | | | $ | 0.3 | | | $ | 0.6 | |
Purchases of natural gas, propane and NGLs | | $ | 102.9 | | | $ | 134.4 | | | $ | 94.4 | |
Gains (losses) from non-trading derivative activity | | $ | 0.1 | | | $ | (0.9 | ) | | $ | (1.9 | ) |
General and administrative expense | | $ | 8.1 | | | $ | 9.1 | | | $ | 7.8 | |
Duke Energy: | | | | | | | | | | | | |
Sales of natural gas, propane, NGLs and condensate | | $ | — | | | $ | 1.4 | | | $ | 10.3 | |
Transportation and processing services | | $ | — | | | $ | 0.3 | | | $ | 0.5 | |
Purchases of natural gas, propane and NGLs | | $ | 3.4 | | | $ | 4.7 | | | $ | 3.4 | |
ConocoPhillips: | | | | | | | | | | | | |
Sales of natural gas, propane, NGLs and condensate | | $ | 1.1 | | | $ | 7.3 | | | $ | 3.7 | |
Transportation and processing services | | $ | 8.0 | | | $ | 10.0 | | | $ | 9.9 | |
Purchases of natural gas, propane and NGLs | | $ | 12.9 | | | $ | 18.7 | | | $ | 18.6 | |
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DCP MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The PartnershipWe had accounts receivable and accounts payable with affiliates as follows ($ in millions):
| | | | | | | | | | | | | | | | |
| | December 31, | | | December 31, | |
| | 2005 | | 2004 | | | 2006 | | 2005 | |
|
Duke Energy Field Services: | | | | | | | | | |
DCP Midstream, LLC: | | | | | | | | | |
Accounts receivable | | $ | 53.5 | | | $ | 0.7 | | | $ | 30.0 | | | $ | 53.5 | |
Accounts payable | | $ | 15.9 | | | $ | — | | | $ | 46.6 | | | $ | 15.9 | |
Duke Energy: | | | | | | | | | | | | | | | | |
Accounts receivable | | $ | 0.4 | | | $ | — | | | $ | 0.2 | | | $ | 0.4 | |
Accounts payable | | $ | 23.6 | | | $ | — | | | $ | 1.8 | | | $ | 24.0 | |
ConocoPhillips: | | | | | | | | | | | | | | | | |
Accounts receivable | | $ | 2.6 | | | $ | 1.2 | | | $ | 4.6 | | | $ | 2.6 | |
Accounts payable | | $ | 2.5 | | | $ | 3.2 | | | $ | 2.0 | | | $ | 2.5 | |
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DCP MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
the associated delivery period impacts earnings. We have applied this accounting election for contracts involving the purchase or sale of physical natural gas, propane or NGLs in future periods.
Commodity Non-Trading Derivative Activity — TheOur operations of gathering, processing, and transporting natural gas, and the accompanying operations of transporting and marketing of energy related products and services exposes the PartnershipNGLs create commodity price risk due to the fluctuations in the market values of exchanged instruments. The Partnership’s marketing program is designed to realize margins related to fluctuations in commodity prices, and differences inprimarily with respect to the prices of NGLs, natural gas prices at various receipt and delivery pointscrude oil. To the extent possible, we match the pricing of our supply portfolio to our sales portfolio in order to lock in value and reduce our overall commodity price risk. We manage the commodity price risk of our supply portfolio and sales portfolio with both physical and financial transactions. We occasionally will enter into financial derivatives to lock in price differentials across the Pelico system to maximize the value of pipeline capacity. These financial derivatives are accounted for the Partnership’s Natural Gasusingmark-to-market accounting with changes in fair value recognized in current period earnings.
91
Our wholesale propane logistics business is generally designed to establish stable margins by entering into supply arrangements that specify prices based on established floating price indices and by entering into sales agreements that provide for floating prices that are tied to our variable supply costs plus a margin. Occasionally, we may enter into fixed price sales agreements in the event that a retail propane distributor desires to purchase propane from us on a fixed price basis. We manage this risk with both physical and financial transactions, sometimes using non-trading derivative instruments, which generally allow us to swap our fixed price risk to market index prices that are matched to our market index supply costs. In addition, we may on occasion use financial derivatives to manage the value of our propane inventories. These financial derivatives are accounted for usingDCP MIDSTREAM PARTNERS, LP
mark-to-market accounting with changes in fair value recognized in current period earnings. We manage our asset-based activities in accordance with our Risk Management Policy which limits exposure to market risk and requires regular reporting to management of potential financial exposure. In addition, we may on occasion use financial derivatives to manage the value of our propane inventories.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTSInterest Rate Cash Flow Hedge — (Continued)
Services segment. DEFS manages the Partnership’s marketing portfolios with strict policies which limit exposure to market risk.
Credit Facility with Financial Institutions — On December 7, 2005, the PartnershipDuring 2006, we entered into a5-yearinterest rate swap agreements to hedge the variable interest rate on $125.0 million of the indebtedness outstanding under our revolving credit agreement (the “Credit Agreement”), providing a $250 million revolving and a $100.1 million term loan facility. The Credit Agreement maturesinterest rate swap agreements have been designated as cash flow hedges, and effectiveness is determined by matching the principal balance and terms with that of the specified obligation. The effective portions of changes in fair value are recognized in AOCI in the consolidated balance sheets. For the year ended December 31, 2006, gains of $0.1 million were reclassified into earnings as a result of settlements. As of December 31, 2006, gains of $0.4 million were deferred in AOCI related to these swaps. As of December 31, 2006, $0.4 million of these deferred net gains on derivative instruments in AOCI are expected to be reclassified into earnings during the next 12 months as the hedged transactions impact earnings however, due to the volatility of the interest rate markets, the corresponding value in AOCI is subject to change prior to its reclassification into earnings. Ineffective portions of changes in fair value are recognized in earnings. The agreements reprice prospectively approximately every 90 days, and expire on December 7, 2010. The Credit Agreement prohibitsUnder the Partnership from making distributionsterms of available cash to unitholders if any default or event of default (as defined in the Credit Agreement) exists. The Credit Agreement requires the Partnership to maintain at all times (commencing with the quarter ending March 31, 2006) a leverage ratio (the ratio of its consolidated indebtedness to its consolidated EBITDA, in each case as is defined by the credit agreement) of less than or equal to 4.75 to 1.0 (and on a temporary basis for not more than three consecutive quarters following the acquisition of assets in the midstream energy business of not more than 5.25 to 1.0); and maintain at the end of each fiscal quarter an interest coverage ratio (defined to be the ratio of adjusted EBITDA, as defined by the Credit Agreement to be earnings before interest, taxes and depreciation and amortization and other non-cash adjustments, for the four most recent quarters to interest expense for the same period) of greater than or equal to 3.0 to 1.0. The term loan bears interest at a rate equal to either LIBOR plus 0.15%, the Federal Funds rate plus 0.5%, or the Wachovia Bank prime rate. The revolving credit facility bears interest at a rate equal to LIBOR plus an applicable margin, which ranges from 0.27% to 1.025% based on leverage leveland/or debt rating, or at the Wachovia Bank prime rate plus an applicable percentage based on leverage leveland/or debt rating. At December 31, 2005, there was $110.0 million outstanding on the revolving credit facility and $100.1 million outstanding on the term loan facility, which is fully collateralized by high-grade securities. As of December 31, 2005, $0.8 million was recorded as accrued interest. No interest was paid during 2005. There were no letters of credit outstanding as of December 31, 2005. In December 2005, the Partnership incurred $0.7 million of debt issuance costs associated with the Credit Agreement. These expenses are deferred as other non-current assets in the accompanying consolidated balance sheet and will be amortized over the term of the Credit Agreement.
Long-term debt at December 31, 2005 and 2004 was as follows ($ in millions):
| | | | | | | | | | | | | | | | |
| | Principal Amount | | | | | | Interest
| |
| | 2005 | | | 2004 | | | Due Date | | | Rate | |
|
Revolving credit facility | | $ | 110.0 | | | $ | — | | | | December 7, 2010 | | | | Varies | |
Term loan facility | | | 100.1 | | | | — | | | | December 7, 2010 | | | | Varies | |
| | | | | | | | | | | | | | | | |
Long-term debt | | $ | 210.1 | | | $ | — | | | | | | | | | |
| | | | | | | | | | | | | | | | |
Future maturities of long-term debt in the year indicated are as follows at December 31, 2005:
| | | | |
| | Debt Maturities | |
| | ($ in millions) | |
|
2006 | | $ | — | |
2007 | | | — | |
2008 | | | — | |
2009 | | | — | |
2010 | | | 210.1 | |
Thereafter | | | — | |
| | | | |
Total long-term debt | | $ | 210.1 | |
| | | | |
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DCP MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| |
13. | Estimated Fair Value of Financial Instruments |
The Partnership has determined the following fair value amounts using available market information and appropriate valuation methodologies. However, considerable judgment is required in interpreting market data to develop the estimates of fair value. Accordingly, the estimates presented herein are not necessarily indicative of the amounts that the Partnership could realize in a current market exchange. The use of different market assumptionsand/or estimation methods may have a material effect on the estimated fair value amounts.
| | | | | | | | | | | | | | | | |
| | December 31, 2005 | | | December 31, 2004 | |
| | Carrying
| | | Estimated Fair
| | | Carrying
| | | Estimated Fair
| |
| | Amount | | | Value | | | Amount | | | Value | |
| | ($ in millions) | |
|
Restricted investments | | $ | 100.4 | | | $ | 100.4 | | | $ | — | | | $ | — | |
Accounts receivable | | $ | 82.0 | | | $ | 82.0 | | | $ | 61.0 | | | $ | 61.0 | |
Accounts payable | | $ | 87.0 | | | $ | 87.0 | | | $ | 39.8 | | | $ | 39.8 | |
Unrealized gains (losses) onmark-to-market and hedging transactions | | $ | 0.6 | | | $ | 0.6 | | | $ | (0.1 | ) | | $ | (0.1 | ) |
Long-term debt | | $ | 210.1 | | | $ | 210.1 | | | $ | — | | | $ | — | |
The fair value of restricted investments, accounts receivable and accounts payable are not materially different from their carrying amounts because of the short term nature of these instruments or the stated rates approximating market rates.
The fair value of the non-trading derivative and hedging transactions is recorded on the consolidated balance sheets. The fair value is determined by multiplying the difference between the quoted termination prices for commodity contract prices by the quantities under contract.
The carrying value of long-term debt approximated fair value as the interest rate is variableswap agreements, we pay fixed rates ranging from 4.68% to 5.08%, and is reflectivereceive interest payments based on the three-month LIBOR. The differences to be paid or received under the interest rate swap agreements are recognized as an adjustment to interest expense. The agreements are with major financial institutions, which are expected to fully perform under the terms of current market conditions.the agreements.
| |
14. | Equity-Based Compensation |
On November 28, 2005, the board of directors of our General Partner adopted the LTIP for employees, consultants and directors of our General Partner and its affiliates who perform services for us, effective as of December 7, 2005. Under the LTIP, equity-based instruments may be granted to our key employees. The LTIP provides for the grant of limited partner units, or LPUs, phantom units, unit options and substitute awards, and, with respect to unit options and phantom units, the grant of DERs. Subject to adjustment for certain events, an aggregate of 850,000 LPUs may be delivered pursuant to awards under the LTIP. Awards that are
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DCP MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
canceled, forfeited or are withheld to satisfy the General Partner’s tax withholding obligations are available for delivery pursuant to other awards. The LTIP is administered by the compensation committee of the General Partner’s board of directors. We first granted awards under the LTIP during 2006.
Performance Units — During the year ended December 31, 2006, we awarded 40,560 phantom LPUs pursuant to the LTIP, or Performance Units, to certain employees. Performance Units generally vest in their entirety at the end of a three year performance period. The number of Performance Units which will ultimately vest range from 0% to 150% of the outstanding Performance Units, depending on the achievement of specified performance targets over a three year period ending on December 31, 2008. The final performance payout is determined by the compensation committee of the board of directors of our General Partner. Each Performance Unit includes a DER, which will be paid in cash at the end of the performance period. We recorded approximately $0.2 million of compensation expense related to the Performance Units during the year ended December 31, 2006. There was no compensation expense related to Performance Units prior to January 1, 2006. At December 31, 2006, there was approximately $0.6 million of unrecognized compensation expense related to the Performance Units that is expected to be recognized over a weighted-average period of 2.0 years. The following table presents information related to the Performance Units:
| | | | | | | | | | | | |
| | | | | Grant Date
| | | Measurement Date
| |
| | | | | Weighted-Average
| | | Weighted-Average
| |
| | Units(a) | | | Price per Unit | | | Price per Unit | |
|
Outstanding at December 31, 2005 | | | — | | | $ | — | | | | | |
Granted | | | 40,560 | | | $ | 26.96 | | | | | |
Forfeited | | | (17,470 | ) | | $ | 26.96 | | | | | |
| | | | | | | | | | | | |
Outstanding at December 31, 2006 | | | 23,090 | | | $ | 26.96 | | | $ | 34.55 | |
| | | | | | | | | | | | |
Expected to vest | | | 23,090 | | | $ | 26.96 | | | $ | 34.55 | |
The estimate of Performance Units that are expected to vest is based on highly subjective assumptions that could potentially change over time, including the expected forfeiture rate and achievement of performance targets. Therefore the amount of unrecognized compensation expense noted above does not necessarily represent the value that will ultimately be realized in our consolidated statements of operations.
IPO Phantom Units — In conjunction with our initial public offering, in January 2006 our General Partner’s board of directors awarded phantom LPUs, or IPO Phantom Units, to key employees, and to directors who are not officers or employees of affiliates of our General Partner. Of these IPO Phantom Units, 16,700 units will vest upon the three year anniversary of the grant date, and 8,000 units vest ratably over three years. Each IPO Phantom Unit includes a DER, which is paid quarterly in arrears. We recorded approximately $0.4 million of compensation expense related to the IPO Phantom Units during the year ended December 31, 2006. There was no compensation expense related to IPO Phantom Units prior to January 1, 2006. At December 31, 2006, there was approximately $0.5 million of unrecognized compensation expense related to the IPO Phantom Units that is expected to be recognized over a weighted-average period of 1.7 years. The following table presents information related to the IPO Phantom Units:
| | | | | | | | | | | | |
| | | | | Grant Date
| | | Measurement Date
| |
| | | | | Weighted-Average
| | | Weighted-Average
| |
| | Units(a) | | | Price per Unit | | | Price per Unit | |
|
Outstanding at December 31, 2005 | | | — | | | $ | — | | | | | |
Granted | | | 35,900 | | | $ | 24.05 | | | | | |
Forfeited | | | (11,200 | ) | | $ | 24.05 | | | | | |
| | | | | | | | | | | | |
Outstanding at December 31, 2006 | | | 24,700 | | | $ | 24.05 | | | $ | 34.55 | |
| | | | | | | | | | | | |
Expected to vest | | | 24,700 | | | $ | 24.05 | | | $ | 34.55 | |
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DCP MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The estimate of IPO Phantom Units that are expected to vest is based on highly subjective assumptions that could potentially change over time, including the expected forfeiture rate. Therefore the amount of unrecognized compensation expense noted above does not necessarily represent the value that will ultimately be realized in our consolidated statements of operations.
We intend to settle the awards issued under the LTIP in cash upon vesting. Compensation expense is recognized ratably over each vesting period, and will be remeasured quarterly for all awards outstanding until the units are vested. The fair value of all awards is determined based on the closing price of our common units at each measurement date. During the year ended December 31, 2006, no awards were vested or settled.
We are structured as a master limited partnership, which is a pass-through entity for U.S. income tax purposes. The income tax expense reflected on our consolidated statements of operations is applicable to our wholesale propane logistics business. On December 7, 2005, our wholesale propane logistics business changed its tax structure, which resulted in its activities changing from taxable to non-taxable for United States income tax purposes.
Income tax expense consisted of the following for the years ended December 31, 2005 and 2004 ($ in millions):
| | | | | | | | |
| | Year Ended December 31, | |
| | 2005 | | | 2004 | |
|
Current: | | | | | | | | |
Federal | | $ | 3.0 | | | $ | 2.0 | |
State | | | 0.8 | | | | 0.6 | |
Deferred: | | | | | | | | |
Federal | | | (0.4 | ) | | | (0.1 | ) |
State | | | (0.1 | ) | | | — | |
| | | | | | | | |
Total income tax expense | | $ | 3.3 | | | $ | 2.5 | |
| | | | | | | | |
A reconciliation of the actual income tax expense and the amount computed by applying the federal statutory rate of 35% to the income before income taxes is as follows ($ in millions):
| | | | | | | | |
| | Year Ended December 31, | |
| | 2005 | | | 2004 | |
|
Federal income tax at statutory rate | | $ | 3.4 | | | $ | 2.1 | |
State income taxes, net of federal benefit | | | 0.6 | | | | 0.5 | |
Change in tax structure | | | (0.5 | ) | | | — | |
Depreciation and amortization | | | — | | | | 0.4 | |
Net trading margins | | | — | | | | (0.4 | ) |
Other | | | (0.2 | ) | | | (0.1 | ) |
| | | | | | | | |
Total income tax expense | | $ | 3.3 | | | $ | 2.5 | |
| | | | | | | | |
The change in tax structure resulted in the reversal of the net deferred tax liabilities in the year ended December 31, 2005. Accordingly, we had no deferred tax balances as of December 31, 2006 or 2005, and no income tax expense for the year ended December 31, 2006.
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DCP MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
In May 2006, the State of Texas enacted a new margin-based franchise tax into law that replaces the existing franchise tax. This new tax is commonly referred to as the Texas margin tax. Corporations, limited partnerships, limited liability companies, limited liability partnerships and joint ventures are examples of the types of entities that are subject to the new tax. The tax is considered an income tax for purposes of adjustments to the deferred tax liability. The tax is determined by applying a tax rate to a base that considers both revenues and expenses. The Texas margin tax becomes effective for franchise tax reports due on or after January 1, 2008. The tax, which is assessed at 1% of taxable margin apportioned to Texas, will be based on the margin earned during the prior calendar year.
The Texas margin tax is considered an income tax for purposes of calculating the deferred tax liability. GAAP requires that deferred taxes be adjusted upon enactment of new tax law, which occurred in 2006. The deferred tax liabilities associated with the Texas margin tax were insignificant.
| |
16. | Net Income per Limited Partner Unit |
Our net income is allocated to the general partner and the limited partners, including the holders of the subordinated units, in accordance with their respective ownership percentages, after giving effect to incentive distributions paid to the general partner.
EITF03-6 addresses the computation of earnings per share by entities that have issued securities other than common stock that contractually entitle the holder to participate in dividends and earnings of the entity when, and if, it declares dividends on its common stock.
EITF03-6 requires that securities that meet the definition of a participating security be considered for inclusion in the computation of basic earnings per unit using the two-class method. Under the two-class method, earnings per unit is calculated as if all of the earnings for the period were distributed under the terms of the partnership agreement, regardless of whether the general partner has discretion over the amount of distributions to be made in any particular period, whether those earnings would actually be distributed during a particular period from an economic or practical perspective, or whether the general partner has other legal or contractual limitations on its ability to pay distributions that would prevent it from distributing all of the earnings for a particular period.
EITF03-6 does not impact our overall net income or other financial results; however, in periods in which aggregate net income exceeds the First Target Distribution Level, it will have the impact of reducing net income per limited partner unit. This result occurs as a larger portion of our aggregate earnings, as if distributed, is allocated to the incentive distribution rights of the general partner, even though we make distributions on the basis of Available Cash and not earnings. In periods in which our aggregate net income does not exceed the First Target Distribution Level, EITF03-6 does not have any impact on our calculation of earnings per limited partner unit. During the year ended December 31, 2006, our aggregate net income per limited partner unit exceeded the Second Target Distribution level, and as a result we allocated $1.3 million in additional earnings to the general partner.
Basic and diluted net income per limited partner unit is calculated by dividing limited partners’ interest in net income, less pro forma general partner incentive distributions under EITF03-6, by the weighted-average number of outstanding limited partner units during the period.
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DCP MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The following table illustrates our calculation of net income per limited partner unit ($ in millions):
| | | | | | | | |
| | Year Ended December 31, | |
| | 2006 | | | 2005 | |
|
Net income | | $ | 33.0 | | | $ | 44.5 | |
Less: | | | | | | | | |
Net loss (income) attributable to predecessor operations | | | 2.3 | | | | (39.8 | ) |
| | | | | | | | |
Net income attributable to the partnership | | | 35.3 | | | | 4.7 | |
Less: General partner interest in net income | | | (0.7 | ) | | | (0.1 | ) |
| | | | | | | | |
Limited partners’ interest in net income (see Note 12) | | | 34.6 | | | | 4.6 | |
Less: Additional earnings allocation to general partner | | | (1.3 | ) | | | (1.1 | ) |
| | | | | | | | |
Net income available to limited partners under EITF03-6 | | $ | 33.3 | | | $ | 3.5 | |
| | | | | | | | |
Net income per limited partner unit — basic and diluted | | $ | 1.90 | | | $ | 0.20 | |
| | | | | | | | |
| |
17. | Commitments and Contingent Liabilities |
Litigation — The Partnership isWe are not a party to any significant legal proceedings but isare a party to various administrative and regulatory proceedings that have arisen in the ordinary course of the Partnership’sour business. Management currently believes that the ultimate resolution of the foregoing matters, taken as a whole, and after consideration of amounts accrued, insurance coverage or other indemnification arrangements, will not have a material adverse effect upon the Partnership’s futureour consolidated results of operations, financial position, operations andor cash flows.
In June 2006, a DCP Midstream, LLC customer whose plant is served by our Seabreeze pipeline notified DCP Midstream, LLC that off specification NGLs had been received into their facility. Our Seabreeze pipeline transports NGLs owned by DCP Midstream, LLC that are delivered to the customer under the terms of a transportation agreement. The customer sent a letter to DCP Midstream, LLC claiming that the off specification NGLs delivered to their facility caused damage to their plant facility. On December 29, 2006 we entered into a settlement agreement with the customer to settle all our issues regarding this matter, and our portion of the settlement was $0.3 million.
In December 2006, El Paso E&P Company, L.P., or El Paso, filed a lawsuit against one of our subsidiaries, DCP Assets Holding, LP and an affiliate of our General Partner, DCP Midstream GP, LP, in District Court, Harris County, Texas. The litigation stems from an ongoing commercial dispute involving our Minden processing plant that dates back to August 2000, which is prior to our acquisition of this asset from DCP Midstream, LLC. El Paso claims damages, including interest, in the amount of $5.7 million in the litigation, the bulk of which stems from audit claims under our commercial contract for historical periods prior to our ownership of this asset. We will only be responsible for potential payments, if any, for claims that involve periods of time after the date we acquired this asset from DCP Midstream, LLC in December 2005. It is not possible to predict whether we will incur any liability or to estimate the damages, if any, we might incur in connection with this matter. Management does not believe the ultimate resolution of this issue will have a material adverse effect on our consolidated results of operations, financial position or cash flows.
Insurance — DEFS carriesIn 2005, DCP Midstream, LLC carried insurance coverage, which includes theincluded our assets and operations, with an affiliate of the Partnership,Duke Energy. Beginning in 2006, DCP Midstream, LLC elected to carry our property and excess liability insurance coverage with an affiliate of Duke Energy that management believes is consistent with companies engaged in similar commercial operations with similar type properties. DEFS’and an affiliate of ConocoPhillips. DCP Midstream, LLC provides our remaining insurance coverage includeswith a third party insurer. DCP Midstream, LLC’s insurance coverage includes: (1) commercial general public liability insurance for liabilities arising to third parties for bodily injury and property damage resulting from operations; (2) workers’
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DCP MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
compensation liability coverage to required statutory limits; (3) automobile liability insurance for all owned, non-owned and hired vehicles covering liabilities to third parties for bodily injury and property damage; (4) excess liability insurance above the established primary limits for commercial general liability and automobile liability insurance; (5) property insurance covering the replacement value of all real and personal property damage, including damages arising from boiler and machinery breakdowns, windstorms, earthquake, flood damage and business interruption/extra expense; and (5)(6) directors and officers insurance covering the performance of the Partnership’s directors’our directors and officers’ duties as they relateofficers for acts related to the Partnership.our activities. All coverages are subject to certain limits and deductibles, the terms and conditions of which are common for companies with similar types of operations. DEFS’ also maintains excessEffective August 2006, we contracted with a third party insurer for our property and primary liability insurance coverage above the established primary limits for commercial general liability and automobile liability insurance. Limits, terms, conditions and deductibles are comparable to those carried by other energy companies of similar size. The cost of general insurance
93
DCP MIDSTREAM PARTNERS, LP
coverage.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
coverages continued to fluctuate over the past year reflecting the changing conditions of the insurance markets.
A portion of the insurance costs described above are allocated by DEFS to the Partnership through the allocation methodology described in Note 7.
Environmental — The operation of pipelines, plants and other facilities for gathering, transporting, processing, treating, or storing natural gas, NGLs and other products is subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of these facilities, the Partnershipwe must comply with United States laws and regulations at the federal, state and local levels that relate to air and water quality, hazardous and solid waste management and disposal, and other environmental matters. The cost of planning, designing, constructing and operating pipelines, plants, and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures, including citizen suits, which can include the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of injunctions or restrictions on operation. Management believes that, based on currently known information, compliance with these laws and regulations will not have a material adverse effect on the Partnership’sour consolidated results of operations, financial position or cash flows.
Indemnification — DEFS will indemnify the PartnershipDCP Midstream, LLC has indemnified us for three years after the closing of the Partnership’sour initial public offering against certain potential environmental claims, losses and expenses associated with the operation of the assets and occurring before the closing date of the Partnership’sour initial public offering, on December 7, 2005. DEFS’DCP Midstream, LLC’s maximum liability for this indemnification obligation does not exceedis $15.0 million and DEFSDCP Midstream, LLC does not have any obligation under this indemnification until the Partnership’sour aggregate losses exceed $250,000. DEFSDCP Midstream, LLC has no indemnification obligations with respect to environmental claims made as a result of additions to or modifications of environmental laws promulgated after the closing date of the Partnership’sour initial public offering. The Partnership hasWe have agreed to indemnify DEFSDCP Midstream, LLC against environmental liabilities related to the Partnership’sour assets to the extent DEFSDCP Midstream, LLC is not required to indemnify the Partnership.us.
Additionally, DCP Midstream, LLC will indemnify us for three years after the closing for losses attributable to title defects, certain retained assets and liabilities (including preclosing legal actions relating to contributed assets) and income taxes attributable to pre-closing operations. We will indemnify DCP Midstream, LLC for all losses attributable to the postclosing operations of the assets contributed to us, to the extent not subject to DCP Midstream, LLC’s indemnification obligations. In addition, DCP Midstream, LLC has agreed to indemnify us for up to $5.3 million of our pro rata share of any capital contributions required to be made by us to Black Lake associated with any repairs to the Black Lake pipeline that are determined to be necessary as a result of the ongoing pipeline integrity testing occurring from 2005 through 2007. DCP Midstream, LLC has also agreed to indemnify us for up to $4.0 million of the costs associated with any repairs to the Seabreeze pipeline that are determined to be necessary as a result of pipeline integrity testing that occurred in 2006. Pipeline integrity testing and repairs are our responsibility and are recognized as operating and maintenance expense. Any reimbursements of these expenses from DCP Midstream, LLC will be recognized by us as a capital contribution. Reimbursements related to the Seabreeze pipeline integrity repairs in 2006 were not significant.
Other Commitments and Contingencies — The Partnership utilizesWe utilize assets under operating leases in several areas of operation. Consolidated rental expense, including leases with no continuing commitment, amounted to $1.3
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DCP MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
$11.2 million, $1.4$10.3 million, and $1.0$1.5 million for the years ended December 31, 2006, 2005 and 2004, and 2003, respectively. AtRental expense for leases with escalation clauses is recognized on a straight line basis over the initial lease term.
Minimum rental payments under our various operating leases in the year indicated are as follows at December 31, 2005, minimum rental payments totaling $0.1 million under the Partnership’s operating leases are scheduled to occur2006 ($ in 2006.millions):
| | | | |
2007 | | $ | 9.7 | |
2008 | | | 7.8 | |
2009 | | | 5.8 | |
2010 | | | 5.1 | |
2011 | | | 4.3 | |
Thereafter | | | 10.4 | |
| | | | |
Total minimum rental payments | | $ | 43.1 | |
| | | | |
The Partnership’sOur operations are located in the United States and are organized into twothree reporting segments: (1) Natural Gas Services; (2) Wholesale Propane Logistics; and (2)(3) NGL Logistics.
Natural Gas Services — The Natural Gas Services segment consists of the North Louisiana system assets, an integrated gas gathering, compression, treating, processing, and transportation system located in northern Louisiana and southern Arkansas that includes the Minden and Ada natural gas processing plants and gathering systems and the PELICOPelico intrastate natural gas gathering and transportation pipeline.
Wholesale Propane Logistics — The Wholesale Propane Logistics segment consists of six owned propane rail terminals located in the Midwest and northeastern United States, one leased propane marine terminal located in Providence, Rhode Island, one propane terminal pipeline under construction in Midland, Pennsylvania and access to several open access pipeline terminals.
NGL Logistics — The NGL Logistics segment consists of the Seabreeze and Wilbreeze NGL transportation pipelinepipelines, which are located along the Gulf Coast area of southeastern Texas, and ana non-operated equity interest in the Black Lake FERC-regulated interstate NGL pipeline located in northern Louisiana and southeastern Texas, and regulated by the Federal Energy Regulatory Commission, or FERC. Our equity interest consists of 45% from December 7, 2005 through December 31, 2006, and 50% in 2003, 2004 and the period from January 1, 2005 through December 6, 2005 and of 45% from December 7, 2005 through December 31, 2005, in line with the closing of the Partnership’s initial public offering on December 7, 2005, whereby DEFS retained2005. DCP Midstream, LLC owns a 5% interest ofin Black Lake, effective with the date of our initial public offering, and an affiliate of BP PLC owns the remaining interest and is the operator of Black Lake.
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DCP MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
These segments are monitored separately by management for performance against itsour internal forecast and are consistent with internal financial reporting. These segments have been identified based on the differing products and services, regulatory environment and the expertise required for these operations. Gross margin is a performance measure utilized by management to monitor the business of each segment. The accounting policies for the segments are the same as those described in Note 2.
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DCP MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The following tables set forth the Partnership’sour segment information.
Year ended December 31, 2006 ($ in millions):
| | | | | | | | | | | | | | | | | | | | |
| | | | | Wholesale
| | | | | | | | | | |
| | Natural Gas
| | | Propane
| | | NGL
| | | | | | | |
| | Services | | | Logistics | | | Logistics | | | Other(c) | | | Total | |
|
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 | | | — | | | | — | | | | — | | | | (12.9 | ) | | | (12.9 | ) |
General and administrative expense — affiliate | | | — | | | | — | | | | — | | | | (8.1 | ) | | | (8.1 | ) |
Earnings from equity method investments | | | — | | | | — | | | | 0.3 | | | | — | | | | 0.3 | |
Interest income | | | — | | | | — | | | | — | | | | 6.3 | | | | 6.3 | |
Interest expense | | | — | | | | — | | | | — | | | | (11.5 | ) | | | (11.5 | ) |
| | | | | | | | | | | | | | | | | | | | |
Net income (loss) | | $ | 50.7 | | | $ | 6.6 | | | $ | 1.9 | | | $ | (26.2 | ) | | $ | 33.0 | |
| | | | | | | | | | | | | | | | | | | | |
Capital expenditures | | $ | 6.5 | | | $ | 9.4 | | | $ | 11.3 | | | $ | — | | | $ | 27.2 | |
| | | | | | | | | | | | | | | | | | | | |
Year ended December 31, 2005 ($ in millions):
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | Wholesale
| | | | | | | |
| | Natural Gas
| | NGL
| | | | | | | Natural Gas
| | Propane
| | NGL
| | | | | |
| | Services | | Logistics | | Other(b) | | Total | | | Services | | Logistics | | Logistics | | Other(c) | | Total | |
|
Total operating revenues | | $ | 592.8 | | | $ | 191.7 | | | $ | — | | | $ | 784.5 | | | $ | 592.8 | | | $ | 359.8 | | | $ | 191.7 | | | $ | — | | | $ | 1,144.3 | |
| | | | | | | | | | | | |
Gross margin(a) | | $ | 71.4 | | | $ | 3.8 | | | $ | — | | | $ | 75.2 | | | $ | 71.4 | | | $ | 21.8 | | | $ | 3.8 | | | $ | — | | | $ | 97.0 | |
Operating and maintenance expense | | | (14.0 | ) | | | (0.2 | ) | | | — | | | | (14.2 | ) | | | (14.0 | ) | | | (8.2 | ) | | | (0.2 | ) | | | — | | | | (22.4 | ) |
Depreciation and amortization expense | | | (10.8 | ) | | | (0.9 | ) | | | — | | | | (11.7 | ) | | | (10.8 | ) | | | (1.0 | ) | | | (0.9 | ) | | | — | | | | (12.7 | ) |
General and administrative expense | | | — | | | | — | | | | (4.0 | ) | | | (4.0 | ) | | | — | | | | — | | | | — | | | | (5.1 | ) | | | (5.1 | ) |
General and administrative expense — affiliate | | | — | | | | — | | | | (7.4 | ) | | | (7.4 | ) | | | — | | | | — | | | | — | | | | (9.1 | ) | | | (9.1 | ) |
Earnings from equity method investment | | | — | | | | 0.4 | | | | — | | | | 0.4 | | |
Earnings from equity method investments | | | | — | | | | — | | | | 0.4 | | | | — | | | | 0.4 | |
Interest income | | | — | | | | — | | | | 0.5 | | | | 0.5 | | | | — | | | | — | | | | — | | | | 0.5 | | | | 0.5 | |
Interest expense | | | — | | | | — | | | | (0.8 | ) | | | (0.8 | ) | | | — | | | | — | | | | — | | | | (0.8 | ) | | | (0.8 | ) |
Income tax expense(b) | | | | — | | | | — | | | | — | | | | (3.3 | ) | | | (3.3 | ) |
| | | | | | | | | | | | | | | | | | | | |
Net income (loss) | | $ | 46.6 | | | $ | 3.1 | | | $ | (11.7 | ) | | $ | 38.0 | | | $ | 46.6 | | | $ | 12.6 | | | $ | 3.1 | | | $ | (17.8 | ) | | $ | 44.5 | |
| | | | | | | | | | | | | | | | | | | | |
Capital expenditures | | $ | 7.9 | | | $ | — | | | $ | — | | | $ | 7.9 | | | $ | 7.9 | | | $ | 2.9 | | | $ | — | | | $ | — | | | $ | 10.8 | |
| | | | | | | | | | | | | | | | | | | | |
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DCP MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Year ended December 31, 2004 ($ in millions):
| | | | | | | | | | | | | | | | |
| | Natural Gas
| | | NGL
| | | | | | | |
| | Services | | | Logistics | | | Other(b) | | | Total | |
|
Total operating revenues | | $ | 353.3 | | | $ | 156.2 | | | $ | — | | | $ | 509.5 | |
Gross margin(a) | | $ | 53.6 | | | $ | 3.3 | | | $ | — | | | $ | 56.9 | |
Operating and maintenance expense | | | (13.4 | ) | | | (0.2 | ) | | | — | | | | (13.6 | ) |
Depreciation and amortization expense | | | (11.7 | ) | | | (0.9 | ) | | | — | | | | (12.6 | ) |
General and administrative expense — affiliate | | | — | | | | — | | | | (6.5 | ) | | | (6.5 | ) |
Earnings from equity method investment | | | — | | | | 0.6 | | | | — | | | | 0.6 | |
Impairment of equity method investment | | | — | | | | (4.4 | ) | | | — | | | | (4.4 | ) |
| | | | | | | | | | | | | | | | |
Net income (loss) | | $ | 28.5 | | | $ | (1.6 | ) | | $ | (6.5 | ) | | $ | 20.4 | |
| | | | | | | | | | | | | | | | |
Capital expenditures | | $ | 2.8 | | | $ | 0.3 | | | $ | — | | | $ | 3.1 | |
| | | | | | | | | | | | | | | | |
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DCP MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Year ended December 31, 2003 ($ in millions):
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | Wholesale
| | | | | | | |
| | Natural Gas
| | NGL
| | | | | | | Natural Gas
| | Propane
| | NGL
| | | | | |
| | Services | | Logistics | | Other(b) | | Total | | | Services | | Logistics | | Logistics | | Other(c) | | Total | |
|
Total operating revenues | | $ | 343.7 | | | $ | 131.4 | | | $ | — | | | $ | 475.1 | | | $ | 353.3 | | | $ | 324.5 | | | $ | 156.2 | | | $ | — | | | $ | 834.0 | |
| | | | | | | | | | | | |
Gross margin(a) | | $ | 42.2 | | | $ | 2.3 | | | $ | — | | | $ | 44.5 | | | $ | 53.6 | | | $ | 16.5 | | | $ | 3.3 | | | $ | — | | | $ | 73.4 | |
Operating and maintenance expense | | | (14.7 | ) | | | (0.3 | ) | | | — | | | | (15.0 | ) | | | (13.4 | ) | | | (6.2 | ) | | | (0.2 | ) | | | — | | | | (19.8 | ) |
Depreciation and amortization expense | | | (11.9 | ) | | | (0.9 | ) | | | — | | | | (12.8 | ) | | | (11.7 | ) | | | (2.1 | ) | | | (0.9 | ) | | | — | | | | (14.7 | ) |
General and administrative expense | | | | — | | | | — | | | | — | | | | (0.9 | ) | | | (0.9 | ) |
General and administrative expense — affiliate | | | — | | | | — | | | | (7.1 | ) | | | (7.1 | ) | | | — | | | | — | | | | — | | | | (7.8 | ) | | | (7.8 | ) |
Earnings from equity method investment | | | — | | | | 0.4 | | | | — | | | | 0.4 | | |
Earnings from equity method investments | | | | — | | | | — | | | | 0.6 | | | | — | | | | 0.6 | |
Impairment of equity method investment | | | | — | | | | — | | | | (4.4 | ) | | | — | | | | (4.4 | ) |
Income tax expense(b) | | | | — | | | | — | | | | — | | | | (2.5 | ) | | | (2.5 | ) |
| | | | | | | | | | | | | | | | | | | | |
Net income (loss) | | $ | 15.6 | | | $ | 1.5 | | | $ | (7.1 | ) | | $ | 10.0 | | | $ | 28.5 | | | $ | 8.2 | | | $ | (1.6 | ) | | $ | (11.2 | ) | | $ | 23.9 | |
| | | | | | | | | | | | | | | | | | | | |
Capital expenditures | | $ | 2.4 | | | $ | 0.3 | | | $ | — | | | $ | 2.7 | | | $ | 2.8 | | | $ | 0.2 | | | $ | 0.3 | | | $ | — | | | $ | 3.3 | |
| | | | | | | | | | | | | | | | | | | | |
The following table sets forth the Partnership’sour total assets segment information ($ in millions):
| | | | | | | | | | | | | | | | |
| | December 31, | | | December 31, | |
| | 2005 | | 2004 | | | 2006 | | 2005 | |
|
Segment long-term assets: | | | | | | | | | |
Segment non-current assets: | | | | | | | | | |
Natural Gas Services | | $ | 152.8 | | | $ | 154.9 | | | $ | 147.4 | | | $ | 152.8 | |
Wholesale Propane Logistics | | | | 50.2 | | | | 40.4 | |
NGL Logistics | | | 23.5 | | | | 25.1 | | | | 35.1 | | | | 23.5 | |
Other(c) | | | 106.5 | | | | — | | |
Other(d) | | | | 109.3 | | | | 106.8 | |
| | | | | | | | | | |
Total long-term assets | | | 282.8 | | | | 180.0 | | |
Total non-current assets | | | | 342.0 | | | | 323.5 | |
Current assets | | | 124.5 | | | | 61.1 | | | | 159.6 | | | | 206.4 | |
| | | | | | | | | | |
Total assets | | $ | 407.3 | | | $ | 241.1 | | | $ | 501.6 | | | $ | 529.9 | |
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(a) | | Gross margin consists of total operating revenues less purchases of natural gas, propane and NGLs. Gross margin is viewed as a non-Generally Accepted Accounting Principles (“GAAP”)non-GAAP measure under the rules of the Securities and Exchange Commission (“SEC”),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 the Partnership’sour operating performance, Grossgross margin should not be considered an alternative to, or more meaningful than, net income or cash flow as determined in accordance with GAAP. The Partnership’s GrossOur 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. |
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(b) | | Other consists of general and administrative expense.Income tax expense relates to our wholesale propane logistics business, which changed its tax status in December 2005. |
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(c) | | Other long-termconsists of general and administrative expense, interest income, interest expense and income tax expense. |
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(d) | | Other non-current assets not allocable to segments consist of restricted investments, of $100.4 million, $5.4 million unrealized gaingains on non-trading derivative and hedging transactionsinstruments, and deferred offering costs of $0.7 million.other non-current assets. |
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DCP MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
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16.19. | Quarterly Financial Data (Unaudited) |
The Partnership’sIn November 2006, we acquired our wholesale propane logistics business from DCP Midstream, LLC in a transaction among entities under common control. Accordingly, the results of operations by quarter have been retroactively adjusted for to include the results of our wholesale propane logistics business for all periods presented.
Our consolidated results of operations by quarter for the years ended December 31, 20052006 and 20042005 were as follows ($ in millions, except per unit amounts):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
2005 | | First | | Second | | Third | | Fourth | | Total | | |
2006 | | | First | | Second | | Third | | Fourth | | Total | |
|
Total operating revenues | | $ | 127.4 | | | $ | 150.4 | | | $ | 233.1 | | | $ | 273.6 | | | $ | 784.5 | | | $ | 265.4 | | | $ | 160.1 | | | $ | 162.8 | | | $ | 207.5 | | | $ | 795.8 | |
Operating income | | $ | 6.9 | | | $ | 7.7 | | | $ | 3.4 | | | $ | 19.9 | | | $ | 37.9 | | | $ | 9.1 | | | $ | 9.3 | | | $ | 7.3 | | | $ | 12.2 | | | $ | 37.9 | |
Net income | | $ | 7.1 | | | $ | 7.8 | | | $ | 3.5 | | | $ | 19.6 | | | $ | 38.0 | | | $ | 8.0 | | | $ | 8.3 | | | $ | 6.1 | | | $ | 10.6 | | | $ | 33.0 | |
Limited partners’ interest in net income(a) | | | $ | 5.3 | | | $ | 8.6 | | | $ | 9.5 | | | $ | 11.1 | | | $ | 34.6 | |
Basic net income per limited partner unit(a) | | $ | — | | | $ | — | | | $ | — | | | $ | 0.20 | | | $ | 0.20 | | | $ | 0.30 | | | $ | 0.47 | | | $ | 0.51 | | | $ | 0.55 | | | $ | 1.90 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
2004 | | First | | Second | | Third(b) | | Fourth | | Total | | |
2005 | | | First | | Second | | Third | | Fourth | | Total | |
|
Total operating revenues | | $ | 116.3 | | | $ | 126.2 | | | $ | 126.8 | | | $ | 140.2 | | | $ | 509.5 | | | $ | 264.4 | | | $ | 202.5 | | | $ | 285.0 | | | $ | 392.4 | | | $ | 1,144.3 | |
Operating income | | $ | 6.9 | | | $ | 4.8 | | | $ | 6.2 | | | $ | 6.3 | | | $ | 24.2 | | | $ | 15.1 | | | $ | 7.2 | | | $ | 2.7 | | | $ | 22.7 | | | $ | 47.7 | |
Net income | | $ | 7.0 | | | $ | 5.0 | | | $ | 1.9 | | | $ | 6.5 | | | $ | 20.4 | | | $ | 11.9 | | | $ | 7.4 | | | $ | 6.0 | | | $ | 19.2 | | | $ | 44.5 | |
Basic net income per limited partner unit | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | |
Limited partners’ interest in net income(b) | | | $ | — | | | $ | — | | | $ | — | | | $ | 4.6 | | | $ | 4.6 | |
Basic net income per limited partner unit(b) | | | $ | — | | | $ | — | | | $ | — | | | $ | 0.20 | | | $ | 0.20 | |
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(a) | | Total limited partners’ interest in net income and basic net income per limited partner unit excludes the results from our wholesale propane logistics business for the period January 1, 2006 through October 31, 2006. See Note 16. |
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(b) | | Total limited partners’ interest in net income and basic income per limited partner unit is calculated using net income of $3.5 million earned by the Partnershipus from December 7, 2005 through December 31, 2005.2005, excluding the results from our wholesale propane logistics business. See Note 5. |
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(b) | | A $4.4 million impairment of equity method investment was recorded in the third quarter of 2004.16. |
Our consolidated results of operations by quarter, excluding our wholesale propane logistics business, for the years ended December 31, 2006 and 2005 were as follows ($ in millions, except per unit amounts):
| | | | | | | | | | | | | | | | | | | | |
2006 | | First | | | Second | | | Third | | | Fourth | | | Total | |
|
Total operating revenues | | $ | 120.0 | | | $ | 95.0 | | | $ | 102.0 | | | $ | — | | | $ | — | |
Operating income | | $ | 6.5 | | | $ | 9.8 | | | $ | 10.9 | | | $ | — | | | $ | — | |
Net income | | $ | 5.4 | | | $ | 8.8 | | | $ | 9.7 | | | $ | — | | | $ | — | |
Limited partners’ interest in net income | | $ | 5.3 | | | $ | 8.6 | | | $ | 9.5 | | | $ | — | | | $ | — | |
Basic net income per limited partner unit | | $ | 0.30 | | | $ | 0.47 | | | $ | 0.51 | | | $ | — | | | $ | — | |
| | | | | | | | | | | | | | | | | | | | |
2005 | | First | | | Second | | | Third | | | Fourth | | | Total | |
|
Total operating revenues | | $ | 127.4 | | | $ | 150.4 | | | $ | 233.1 | | | $ | 273.6 | | | $ | 784.5 | |
Operating income | | $ | 6.9 | | | $ | 7.7 | | | $ | 3.4 | | | $ | 19.9 | | | $ | 37.9 | |
Net income | | $ | 7.1 | | | $ | 7.8 | | | $ | 3.5 | | | $ | 19.6 | | | $ | 38.0 | |
Limited partners’ interest in net income | | $ | — | | | $ | — | | | $ | — | | | $ | 4.6 | | | $ | 4.6 | |
Basic net income per limited partner unit | | $ | — | | | $ | — | | | $ | — | | | $ | 0.20 | | | $ | 0.20 | |
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DCP MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Our combined results of operations by quarter for our wholesale propane logistics business for the years ended December 31, 2006 and 2005 were as follows ($ in millions):
| | | | | | | | | | | | | | | | | | | | |
2006 | | First | | | Second | | | Third | | | Fourth | | | Total | |
|
Total operating revenues | | $ | 145.4 | | | $ | 65.1 | | | $ | 60.8 | | | $ | — | | | $ | — | |
Operating income | | $ | 2.6 | | | $ | (0.5 | ) | | $ | (3.6 | ) | | $ | — | | | $ | — | |
Net income (loss) | | $ | 2.6 | | | $ | (0.5 | ) | | $ | (3.6 | ) | | $ | — | | | $ | — | |
Limited partners’ interest in net income | | | N/A | | | | N/A | | | | N/A | | | | N/A | | | | N/A | |
Basic net income per limited partner unit | | | N/A | | | | N/A | | | | N/A | | | | N/A | | | | N/A | |
| | | | | | | | | | | | | | | | | | | | |
2005 | | First | | | Second | | | Third | | | Fourth | | | Total | |
|
Total operating revenues | | $ | 137.0 | | | $ | 52.1 | | | $ | 51.9 | | | $ | 118.8 | | | $ | 359.8 | |
Operating income | | $ | 8.2 | | | $ | (0.5 | ) | | $ | (0.7 | ) | | $ | 2.8 | | | $ | 9.8 | |
Net income (loss) | | $ | 4.8 | | | $ | (0.4 | ) | | $ | 2.5 | | | $ | (0.4 | ) | | $ | 6.5 | |
Limited partners’ interest in net income | | | N/A | | | | N/A | | | | N/A | | | | N/A | | | | N/A | |
Basic net income per limited partner unit | | | N/A | | | | N/A | | | | N/A | | | | N/A | | | | N/A | |
In March 2007, we entered into a definitive agreement to acquire certain gathering and compression assets located in southern Oklahoma from Anadarko Petroleum Corporation for approximately $180.3 million, subject to customary closing conditions and certain regulatory approvals. We paid an earnest deposit of $9.0 million when we entered into this agreement. If Anadarko Petroleum Corporation terminates because we materially breach our representations, warranties or covenants under this agreement, they may retain this earnest deposit as liquidated damages. This deposit will be applied against the purchase price at closing of this transaction, which is expected in the second quarter of 2007. The remaining purchase price is expected to be funded by the issuance of partnership units and by proceeds from our credit facility.
On January 25, 2006,24, 2007, the board of directors of DCP Midstream Partners’ general partnerour General Partner declared a prorated quarterly distribution of $0.095$0.43 per unit, payable on February 13, 200614, 2007, to unitholders of record on February 3, 2006, for the period from the close of the initial public offering of December 7, 2005 through December 31, 2005.
In February 2006, the Partnership announced plans to construct a new37-mile NGL pipeline to connect a DEFS gas processing plant to the Seabreeze pipeline for a cost of approximately $12 million. The project is estimated to be completed during the fourth quarter of 2006 and is supported by a10-year NGL product dedication by DEFS. Volumes from DEFS are estimated to be approximately 5.3 MBbls/d.2007.
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Item 9. | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.Disclosure |
There were no changes in or disagreements with accountants on accounting and financial disclosures during the year ended December 31, 2005.2006.
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Item 9a. | Controls and Procedures.Procedures |
We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports that we file or submit to the Securities and Exchange Commission under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified by the Commission’s rules and forms, and that information is accumulated and communicated to the management of our general partner, including our general partner’s principal executive and principal financial officers (whom we refer to as the Certifying Officers), as appropriate to allow timely decisions regarding required disclosure. The management of our general partner evaluated, with the participation of the Certifying Officers, the effectiveness of our disclosure controls and procedures as of December 31, 2005,2006, pursuant toRule 13a-15(b) under the Exchange Act. Based upon that evaluation, the Certifying Officers concluded that, as of December 31, 2005,2006, our disclosure controls and procedures were effective. There were no significant changes in internal control over financial reporting (as defined inRule 13a-15(f) under the Exchange Act) that occurred during the fourth quarter of 20052006 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Management’s Annual Report On Internal Control Over Financial Reporting
Our general partner is responsible for establishing and maintaining an adequate system of internal control over financial reporting, as such term is defined in Exchange ActRules 13a-15(f) and15d-15(f). Our internal control system was designed to provide reasonable assurance to our management and board of directors of our general partner regarding the preparation and fair presentation of published financial statements.
All internal control systems, no matter how well designed, have inherent limitations. Therefore, internal control over financial reporting may not prevent or detect misstatements. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with policies and procedures may deteriorate.
Our management, including our Chief Executive Officer and Chief Financial Officer, has conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2006 based on the framework in “Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.” Based on that evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2006.
Our assessment of the effectiveness of our internal control over financial reporting as of December 31, 2006 has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report which immediately follows.
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March 14, 2007
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors of
DCP Midstream Partners GP, LLC
Denver, Colorado:
We have audited management’s assessment, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting, that DCP Midstream Partners, LP and subsidiaries (the “Company”) maintained effective internal control over financial reporting as of December 31, 2006, based on criteria established inInternal Control — Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, management’s assessment that the Company maintained effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on the criteria established inInternal Control — Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on the criteria established inInternal Control — Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission.
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We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedule as of and for the year ended December 31, 2006, of the Company, and our report dated March 14, 2007, expressed an unqualified opinion on those financial statements and financial statement schedule and included an explanatory paragraph relating to the basis of presentation of the consolidated financial statements of DCP Midstream Partners, LP (formerly Duke Energy Field Services, LLC) to retroactively reflect the company’s acquisition of the wholesale propane logistics business and the preparation of the portion of the DCP Midstream Partners, LP financial statements attributable to the wholesale propane logistics business from the separate records maintained by DCP Midstream, LLC (formerly Duke Energy Field Services, LLC).
/s/ Deloitte & Touche LLP
Denver, Colorado
March 14, 2007
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Item 9b. | Other Information.Information |
No information was required to be disclosed in a report onForm 8-K, but not so reported, for the quarter ended December 31, 2005.2006.
Part III
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Item 10. | Directors, and Executive Officers of our General Partner.and Corporate Governance |
Management of DCP Midstream Partners, LP
We do not have directors or officers, which is commonly the case with publicly traded partnerships. Our operations and activities are managed by our general partner, DCP Midstream GP, LP, which in turn is managed by its general partner, DCP Midstream GP, LLC, which we refer to as our General Partner. Our General Partner is wholly-owned by DEFS.DCP Midstream, LLC. The officers and directors of our General Partner are responsible for managing us. All of the directors of our General Partner are elected annually by DEFSDCP Midstream, LLC and all of the officers of our General Partner serve at the discretion of the directors. Unitholders are not entitled to participate, directly or indirectly, in our management or operations.
Board of Directors and Officers
The board of directors of our General Partner that oversees our operations currently has teneight members, fivethree of whom are independent as defined under the independence standards established by the New York Stock Exchange. The New York Stock Exchange does not require a listed limited partnership like us to have a majority of independent directors on its general partner’s board of directors or to establish a compensation committee or a nominating committee. However, the board of directors of our General Partner has established an audit committee consisting of three independent members of the board, a compensation committee and a special committee to address conflict situations.
Our General Partner’s board of directors annually reviews the independence of directors and affirmatively makes a determination that each director expected to be independent has no material relationship with our General Partner, either directly or indirectly as a partner, unitholder or officer of an organization that has a relationship with our General Partner.
The Named Executiveexecutive officers of our General Partner manage theday-to-day affairs of our business and devote all of their time to our business and affairs. We also utilize a significant number of employees of DEFSDCP Midstream, LLC to operate our business and provide us with general and administrative services.
Meeting Attendance and Preparation
Members of our board of directors attended at least 75% of regular board meetings and meetings of the committees on which they serve, either in person or telephonically. In addition, directors are expected to be prepared for each meeting of the board by reviewing materials distributed in advance.
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Directors and Executive Officers
The following table shows information regarding the current directors and the Named Executive Officersexecutive officers of DCP Midstream GP, LLC. Directors are elected for one-year terms.
| | | | | | |
Name | | Age | | Position with DCP Midstream GP, LLC |
|
Jim W. Mogg | | | 5758 | | | Chairman of the Board |
Michael J. BradleyMark A. Borer | | | 5152 | | | President, Chief Executive Officer and Director |
Thomas E. Long | | | 4950 | | | Vice President and Chief Financial Officer |
Michael S. Richards | | | 4647 | | | Vice President, General Counsel and Secretary |
Greg K. Smith | | | 3940 | | | Vice President, Business Development |
William H. Easter III | | | 5657 | | | Director |
Paul F. Ferguson, Jr. | | | 5657 | | | Director |
John E. Lowe | | | 47 | | | Director |
Milton Carroll | | | 5548 | | | Director |
Derrill Cody | | | 6768 | | | Director |
Frank A. McPherson | | | 7273 | | | Director |
Thomas C. Morris | | | 65 | | | Director |
Michael J. Panatier | | | 5766 | | | Director |
Our directors hold office for one year or until the earlier of their death, resignation, removal or disqualification or until their successors have been elected and qualified. Officers serve at the discretion of the board of directors. There are no family relationships among any of our directors or executive officers.
Jim W. Moggwas elected Chairman of the Board of DCP Midstream GP, LLC in August 2005. Mr. Mogg isretired from his position as Group Vice President, and Chief Development Officer and advisor to the Chairman of Duke Energy.Energy in September 2006. Mr. Mogg assumed his currentformer position with Duke Energy in January 2004. He previously served as President and Chief Executive Officer of DEFSDCP Midstream, LLC from December 1994 and Chairman, President and Chief Executive Officer of DEFSDCP Midstream, LLC from 1999 through December 2003. In these capacities, Mr. Mogg was significantly involved in the development and growth of DEFS. From October 1997 until March 2005,DCP Midstream, LLC. Mr. Mogg also served as a directorwill be retiring from the board of directors of the general partnerGeneral Partner in the second quarter of TEPPCO Partners, L.P.2007, at which time Mr. Mogg was appointed ChairmanFred J. Fowler will assume the responsibilities of the compensation committee of the general partner of TEPPCO Partners, L.P. in April 2000 and Chairman of the Board in May 2002.chairman.
Michael J. BradleyMark A. Borerwas elected President and Chief Executive Officer, and director of DCP Midstream GP, LLC in August 2005 and director in November 2005.2006. Mr. Bradley has beenBorer was previously Group Vice President, GatheringMarketing and ProcessingCorporate Development of DEFSDCP Midstream, LLC since July 2004. From April 2002 until July 2004, Mr. Bradley wasHe previously served as Executive Vice President Gatheringof Marketing and ProcessingCorporate Development of DEFS. From 1999 until AprilDCP Midstream, LLC from May 2002 through July 2004. Mr. Bradley was Senior Vice President, Northern Division of DEFS. Mr. Bradley joined DEFS in 1994 andBorer served as Senior Vice President. In these capacities,President, Southern Division of DCP Midstream, LLC from April 1999 through May 2002. Prior to that time, Mr. BradleyBorer was significantly involved in the development and growthVice President of DEFS. From February 2003 until March 2005, Mr. Bradley also served as a director of the general partner of TEPPCO Partners, L.P.Natural Gas Marketing for Union Pacific Fuels, Inc.
Thomas E. Longwas elected Vice President and Chief Financial Officer of DCP Midstream GP, LLC in September 2005. Mr. Long has beenwas previously Vice President of National Methanol Company, Duke Energy’s international chemical joint venture, since December 2004. From April 2002 until December 2004, Mr. Long served as Vice President and Treasurer of DEFS.DCP Midstream, LLC. From April 1, 2000 until April 2002, Mr. Long served as Vice President, Investor Relations of DEFS.DCP Midstream, LLC. Mr. Long joined Duke Energy in 1979 and served in a variety of positions in accounting, finance, tax, investor relations and business development. Mr. Long is a Certified Public Accountant licensed in the state of Texas.
Michael S. Richardswas elected Vice President, General Counsel and Secretary of DCP Midstream GP, LLC in September 2005. Mr. Richards was previously Assistant General Counsel and Assistant Secretary of DEFSDCP Midstream, LLC since February 2000. He was previously Assistant General Counsel and Assistant Secretary at KN Energy, Inc. from December 1997 until he joined DEFS.DCP Midstream, LLC. Prior to that, he was Senior Counsel and Risk
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Manager at Total Petroleum (North America) Ltd. from 1994 through 1997. Mr. Richards was previously in private practice where he focused on securities and corporate finance.
Greg K. Smithwas elected Vice President, Business Development of DCP Midstream GP, LLC in September 2005. Mr. Smith was previously Vice President, Corporate Development of DEFS DCP Midstream, LLC
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since June 2002. From July 1996 until June 2002, Mr. Smith held several positions at DEFS,DCP Midstream, LLC, including Commercial Director and Senior Attorney. Mr. Smith was previously an attorney with El Paso Natural Gas from 1992 until July 1996.
William H. Easter IIIwas elected as a director of DCP Midstream GP, LLC in November 2005. Mr. Easter is Chairman of the Board, President and Chief Executive Officer of DEFS.DCP Midstream, LLC. Prior to joining DEFSDCP Midstream, LLC in January 2004, Mr. Easter served as Vice President of State Government Affairs for ConocoPhillips from 2002 through 2003. From 1998 to 2002, Mr. Easter served as General Manager of the Gulf Coast business unit for Conoco Inc. and from 1992 to 1998 he served as Managing Director and Chief Executive Officer of Conoco Jet Nordic in Stockholm, Sweden. From March 2004 until March 2005, Mr. Easter served as a director of the general partner of TEPPCO Partners, L.P.
Paul F. Ferguson, Jr. was elected as a director of DCP Midstream GP, LLC in November 2005. Mr. Ferguson was a director of the general partner of TEPPCO Partners, L.P. from October 2004 until his resignation in 2005. Mr. Ferguson was a member of the Compensation, Audit and special committees of the general partner of TEPPCO Partners, L.P. He was elected Chairman of the audit committee in October 2004. He served as Senior Vice President and Treasurer of Duke Energy from June 1997 to June 1998, when he retired. Mr. Ferguson served as Senior Vice President and Chief Financial Officer of PanEnergy Corp. from September 1995 to June 1997. He held various other financial positions with PanEnergy Corp. from 1989 to 1995 and served as Treasurer of Texas Eastern Corporation from 1988 to 1989.
John E. Lowewas elected as a director of DCP Midstream GP, LLC in November 2005. Mr. Lowe is Executive Vice President, Planning, Strategy and Corporate AffairsCommercial of ConocoPhillips. He has responsibility for planningthe supply and strategic transactions, emerging businesses, government affairs and communications.trading operations. Mr. Lowe previously served as Executive Vice President, Planning, Strategy and Corporate Affairs from 2002 until April 2006. He was named to this position after serving as Senior Vice President, Corporate Strategy and Development and was responsible for the forward strategy, development opportunities and public relations functions of Phillips Petroleum Company. He was named to this position in 2001 after serving as Senior Vice President of Planning and Strategic transactions in 2000 and Vice President of Planning and Strategic Transactions in 1999. Lowe currently serves on the board of directors for Chevron Phillips Chemical Company, DEFS,DCP Midstream, LLC, the Houston Museum of Natural Science and the National Association of Manufacturers. He is a certified public accountant.
Milton Carrollwas elected as a director of DCP Midstream GP, LLC in December 2005. Mr. Carroll is chairman of CenterPoint Energy, Inc., a Houston-based gas and electric utility where he has served as a director since 1992. Mr. Carroll is founder and chairman of Instrument Products, Inc., an oil-tool manufacturing company in Houston, Texas. He also serves as chairman of Healthcare Service Corporation and a director of Eagle Global Logistics, Inc. At various times from 1985 to 2005, he served on the boards of PanEnergy Corp., the Federal Reserve Bank of Houston and Dallas, Devon Energy Corporation, the general partner of TEPPCO Partners, L.P., and as chairman of both the Houston Endowment Foundation and the Texas Southern University Board of Regents. He is also a former Port Commissioner of the Port of Houston Authority.
Derrill Codywas elected as a director of DCP Midstream GP, LLC in December 2005. Mr. Cody is presently of counsel to the law firm of Tomlinson & O’Connell in Oklahoma City, Oklahoma since December 1, 2005. Prior to that he was of counsel to the law firm of McKinney & Stringer, P.C., in Oklahoma City from 1990. Mr. Cody served as executive vice president of Texas Eastern Corporation and chairman and chief executive officer of Texas Eastern Gas Pipeline Company in Houston, Texas. Prior to joining Texas Eastern in 1986, Mr. Cody held executive roles with both Kerr McGee Corporation and Texas Gas Resources Corporation prior to its merger with CSX Corporation. Mr. Cody currently serves on the board of CenterPoint Energy, Inc. and the board of regents of Seminole State College. He also previously served on the boards of the general partner of TEPPCO Partners, L.P.; Plains Petroleum Company from 1990 until its merger with Barrett Resources Corporation in 1995; and Barrett Resources Corporation from 1995 to 2001.
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Frank A. McPhersonwas elected as a director of DCP Midstream GP, LLC in December 2005. Mr. McPherson retired as chairman and chief executive officer from Kerr McGee Corporation in 1997 after a40-year career with the company. Mr. McPherson was chairman and chief executive officer of Kerr McGee from 1983 to 1997. Prior to that he served in various capacities in management of Kerr McGee. Mr. McPherson joined Kerr McGee in 1957. Mr. McPherson serves on the boards of Integris Health, Tri Continental Corporation, Seligman Group of Mutual Funds, and several non-profit organizations in Oklahoma. He previously served on the boards of ConocoPhillips, Kimberly Clark Corporation, MAPCO Inc., Bank of Oklahoma, the Federal Reserve Bank of Kansas City, the Oklahoma State University Foundation Board of Trustees and the American Petroleum Institute.
Thomas C. Morriswas elected as a director of DCP Midstream GP, LLC in December 2005. Mr. Morris is currently retired, having served 34 years with Phillips Petroleum Company. Mr. Morris served in various capacities with Phillips, including vice president and treasurer and subsequently senior vice president and chief financial officer from 1994 until his retirement in 2001. Mr. Morris served as vice chairman of the board of OK Mozart, is a former member of the executive board of the American Petroleum Institute finance committee and a former member of the Business Development Council of Texas A&M University.
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Michael J. Panatierwas elected as a director of DCP Midstream GP, LLC in December 2005. Mr. Panatier served as a director of DEFS from March 2000 until his resignation in August 2002 and was vice chairman of the board of DEFS through 2001. Mr. Panatier held several executive roles at Phillips Petroleum Company and its subsidiaries, including executive vice president of refining, marketing and transportation through 2002, senior vice president of gas processing and marketing from 1998 until 2000, and president and chief executive officer of GPM Gas Corporation from 1994 until 2000.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Securities Exchange Act of 1934 requires DCP Midstream GP, LLC’s directors and executive officers, and persons who own more than 10% of any class of our equity securities to file with the SEC and the New York Stock Exchange initial reports of ownership and reports of changes in ownership of our common units and our other equity securities. Specific due dates for those reports have been established, and we are required to report herein any failure to file reports by those due dates. Directors, executive officers and greater than 10% unitholders are also required by SEC regulations to furnish us with copies of all Section 16(a) reports they file.
To our knowledge, based solely on a review of the copies of reports furnished to us and written representations that no other reports were required during the fiscal year ended December 31, 2005,2006, all Section 16(a) filing requirements applicable to such reporting persons were complied with except that Mr. Bradley filed a late Form 4 reporting the disposition of 19 common units to our employees, officersand/or board members for the issuance of commemorative common unit certificates associated with our initial public offering and each of Messrs. Mogg, Long, Richards, Smith, Easter, Ferguson, and Lowe filed a late Form 4 and each of Messrs. Carroll, Cody, McPherson, Morris and Panatier filed an amended Form 3, all reporting the acquisition of one commemorative common unit issued as part of our initial public offering. In addition Messrs. Bradley, Long, Richards, Smith, Ferguson, Carroll, Cody, McPherson, Morris and Panatier filed a late Form 4 reporting the acquisition of phantom units in January 2006 under our Long-Term Incentive Plan.with.
Audit Committee
The board of directors of DCP Midstream GP, LLCour General Partner has a standing audit committee. The audit committee is composed of three nonmanagement directors, Paul F. Ferguson, Jr. (chairman), Frank A. McPherson and Thomas C. Morris, each of whom is able to understand fundamental financial statements and at least one of whom has past experience in accounting or related financial management experience. The board has determined that each member of the audit committee is independent under Section 303A.02 of the New York Stock Exchange listing standards and Section 10A(m)(3) of the Securities Exchange Act of 1934, as amended. In making the independence determination, the board considered the requirements of the New York Stock Exchange and our Code of Business Ethics. Among other factors, the board considered current or previous employment with the Partnership, its
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us, our auditors or their affiliates by the director or his immediate family members, ownership of our voting securities, and other material relationships with the Partnership.us. The audit committee has adopted a charter, which has been ratified and approved by the board of directors.
With respect to material relationships, the following relationships are not considered to be material for purposes of assessing independence: service as an officer, director, employee or trustee of, or greater than five percent beneficial ownership in (a) a supplier to the partnership if the annual sales to the partnership are less than one percent of the sales of the supplier; (b) a lender to the partnership if the total amount of the partnership’s indebtedness is less than one percent of the total consolidated assets of the lender; or (c) a charitable organization if the total amount of the partnership’s annual charitable contributions to the organization are less than three percent of that organization’s annual charitable receipts.
Mr. Ferguson has been designated by the board as the audit committee’s financial expert meeting the requirements promulgated by the SEC and set forth in Item 401(h) ofRegulation S-K of the Securities Exchange Act of 1934 based upon his education and employment experience as more fully detailed in Mr. Ferguson’s biography set forth above.
Special Committee
The board of directors of our General Partner has a standing special committee, which is comprised of fourthree nonmanagement directors, Frank A. McPherson Milton Carroll,(chairman), Paul F. Ferguson, Jr. and Thomas C. Morris. The special committee will review specific matters that the board believes may involve conflicts of interest. The special committee will determine if the resolution of the conflict of interest is fair and reasonable to us. The special committee may also occasionally meet in an executive session without management participation. The members of the special committee may not be officers or employees of our General Partner or directors, officers or employees of its affiliates. Each of the members of the special committee meet the independence and experience standards established by the New York Stock Exchange and the Securities Exchange Act of 1934, as amended. Any matters approved by the special committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners, and not a breach by our General Partner of any duties it may owe us or our unitholders.
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Compensation Committee
The board of directors of our General Partner has a standing compensation committee, which is composed of sixfour directors, Jim W. Mogg Milton Carroll,(chairman), Derrill Cody, William H. Easter, III and Frank McPherson and Michael Panatier.A. McPherson. The compensation committee oversees compensation decisions for the officers of our general partner and administers the long-term incentive plan, selecting individuals to be granted equity-based awards from among those eligible to participate. The compensation committee has adopted a charter, which has been ratified and approved by the board of directors.
Corporate Governance Guidelines and Code of Business Ethics
Our board of directors has adopted Corporate Governance Guidelines that outline the important policies and practices regarding our governance.
We have adopted a Code of Business Ethics applicable to the persons serving as our directors, officers (including without limitation, the chief executive officer, chief financial officer and principal accounting officer) and employees, which includes the prompt disclosure to the SEC of a current report onForm 8-K of any waiver of the code for executive officers or directors approved by the board of directors. A copy
Copies of our Corporate Governance Guidelines, our Code of Business Ethics, isour Audit Committee Charter and our Compensation Committee Charter are available on our website atwww.dcppartners.com. Copies of these items are also available free of charge in print to any unitholder who sends a request to the office of the Secretary of DCP Midstream Partners, LP at 370 17th17th Street, Suite 2775, Denver, Colorado 80202. The Code of Business Ethics is also posted on our website atwww.dcppartners.com.80202,(303) 633-2921.
Communications by Unitholders
Unitholders may communicate with any and all members of our board, including our nonmanagement directors, by transmitting correspondence by mail or facsimile addressed to one or more directors by name or to the chairman of the board or any committee of the board at the following address and fax number; Name of the Director(s),c/o Secretary, DCP Midstream Partners, LP, 370 17th17th Street, Suite 2775, Denver, Colorado 80202.
New York Stock Exchange, or NYSE, Annual Certification
On January 25, 2007, Mark A. Borer, our Chief Executive Officer, certified to the NYSE, as required by NYSE rules, that as of January 25, 2007, he was not aware of any violation by us of the NYSE’s Corporate Governance Listing Standards.
Report of the Audit Committee
The audit committee oversees our financial reporting process on behalf of the board of directors. Management has the primary responsibility for the financial statements and the reporting process including the systems of internal controls. The audit committee operates under a written charter approved by the board of directors. The charter, among other things, provides that the audit committee has authority to appoint, retain and oversee the independent auditor. In this context, the audit committee:
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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; |
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| • | 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; |
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| • | 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; |
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| • | 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; |
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| • | discussed with Deloitte & Touche, LLP the matters required to be discussed by statement on auditing standards No. 61 (communications with audit committees); |
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| • | 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; |
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| • | 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, 2006, for filing with the Securities and Exchange Commission; and |
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| • | approved the selection and appointment of Deloitte & Touche, LLP to serve as our independent auditors. |
This report has been furnished by the members of the audit committee of the board of directors:
Audit Committee
Paul F. Ferguson, Jr. (Chairman)
Frank A. McPherson
Thomas C. Morris
March 14, 2007
The report of the audit committee in this report shall not be deemed incorporated by reference into any other filing by DCP Midstream Partners, LP under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, except to the extent that we specifically incorporate this information by reference, and shall not otherwise be deemed filed under such acts.
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Item 11. | Executive Compensation.Compensation |
Compensation Discussion and Analysis
General
As a publicly traded limited partnership, we do not have directors, officers or employees. Instead, our operations are managed by our general partner, DCP Midstream GP, LP, which in turn is managed by its general partner, DCP Midstream GP, LLC, which we refer to as our General Partner. Our General Partner is a wholly-owned subsidiary of DCP Midstream, LLC.
Our General Partner currently has four executive officers and five additional employees who are solely dedicated to our operations and management. The General Partner has not entered into employment agreements with any of our executive officers. The compensation committee of our General Partner’s board of directors establishes the compensation program for these employees.
Compensation Committee
The compensation committee is comprised of directors of our General Partner and currently has four members. The compensation committee’s responsibilities include, among other duties, the following:
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| • | annually review and approve Partnership goals and objectives relevant to compensation of the Chief Executive Officer, or the CEO, and other executive officers; |
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| • | annually evaluate the CEO’s performance in light of the Partnership goals and objectives, and approve the CEO’s compensation levels based on this evaluation; |
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| • | 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; |
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| • | periodically evaluate incentive compensation and equity-related plans and consider amendments if appropriate; |
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| • | periodically evaluate the compensation of the directors; |
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| • | retain and terminate any compensation consultant to be used to assist in the evaluation of director, CEO or executive officer compensation; and |
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| • | perform other duties as deemed appropriate by the General Partner’s board of directors. |
Compensation Philosophy
Our compensation program is structured to provide the following benefits:
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| • | 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 and in similar lines of business; |
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| • | Motivate executive officers and key employees to achieve strong financial and operational performance; |
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| • | Emphasize performance-based compensation, balancing short-term and long-term results; |
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| • | Reward individual performance; and |
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| • | Encourage a long-term commitment to the Partnership by requiring target levels of unit ownership. |
Methodology
The compensation committee reviews data from market surveys provided by independent consultants to assess the competitive position with respect to base salary, annual short-term incentives and long-term incentive compensation. With respect to executive officer compensation, the compensation committee also
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considers individual performance, levels of responsibility, skills and experience. In 2006 we engaged the services of Apogee, a compensation consultant, to conduct a study to assist us in establishing overall compensation packages for our executives. The study was based on compensation as reported in the annual reports onForm 10-K for a group of peer companies with a similar tax status, and the 2005 Towers Perrin General Industry Executive Compensation Database, or the Towers Perrin Database. The study was comprised of the following companies: Boardwalk Pipeline Partners, LP, Copano Energy, L.L.C., Crosstex Energy, L.P., Enbridge Energy Partners, LP, Genesis Energy, LP, Magellan Midstream Partners, L.P., MarkWest Energy Partners, LP, ONEOK Partners, L.P., Plains All American Pipeline, L.P., Sunoco Logistics Partners L.P. and Valero L.P. Studies such as this generally include only the most highly compensated officers of the company, which correlates to our executive officers. The results of this study, as well as other factors such as our targeted performance objectives, served as a benchmark for establishing our total direct compensation packages. In order to assess the competitiveness of the total direct compensation packages for our executive officers we used the median amount for peer positions from the Apogee study and the data point that represents the 50th percentile of the market in the Towers Perrin Database.
Components of Compensation
The total annual direct compensation program for executives of the General Partner consists of three components: (1) base salary; (2) an annual short-term cash incentive, or STI, which is based on a percentage of annual base salary; and (3) the present value of an equity-based grant under our long-term incentive plan, or LTIP. Under our compensation structure, the allocation between base salary, STI and LTIP varies depending upon job title and responsibility levels. In 2006 this allocation for our executive officers was as follows:
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| | | | | Targeted
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| | Base Salary | | | STI Level | | | LTIP Level | |
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CEO | | | 33 | % | | | 20 | % | | | 47 | % |
CFO | | | 44 | % | | | 20 | % | | | 36 | % |
Vice Presidents | | | 44 | % | | | 20 | % | | | 36 | % |
In allocating compensation among these components, we believe the compensation of our executive officers should be more heavily weighted toward performance-based compensation since these individuals have a greater opportunity to influence the Partnership’s performance. In making this allocation, we have relied in part on the Apogee study of the companies named above. Each component of compensation is further described below.
Base Salary — Base salaries for executives are determined based upon job responsibilities, level of experience, individual performance, and comparisons to the salaries of executives in similar positions obtained from the Apogee study. The goal of the base salary component is to compensate executives at a level that approximates the median salaries of individuals in comparable positions at comparably sized companies in our industry.
The base salaries for executives are generally reevaluated annually as part of our performance review process, or when there is a change in the level of job responsibility. The base salaries paid to our executive officers in fiscal year 2006 are set forth in the “Summary Compensation” table below.
Annual Short-Term Cash Incentive, or STI — Under the STI, annual cash incentives are provided to executives to promote the achievement of performance objectives of the Partnership. Target incentive opportunities for executives under the STI are established as a percentage of base salary. Incentive amounts are intended to provide total cash compensation at the market median for executive officers in comparable positions and markets when target performance is achieved, below the market median when minimum performance is achieved and above the market median when maximum performance is achieved. The Apogee study was used to determine the competitiveness of the incentive opportunity for comparable positions. STI payments are generally paid in cash in March of each year for the prior fiscal year’s performance.
In 2006, the STI objectives were initially designed and proposed by the executive officers and presented to the Chairman of the General Partner’s board of directors. These objectives were then considered and
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approved by the compensation committee. In 2006, the STI objectives approved by the compensation committee were divided as follows: (1) a financial objective accounted for 50% of the STI; (2) company objectives accounted for 25% of the STI; and (3) personal objectives accounted for 25% of the STI. The target incentive opportunities for 2006 as a percentage of base salary for the CEO, the CFO, and the Vice Presidents were 60%, 45% and 45%, respectively. All STI objectives are subject to change each year.
The 2006 stated financial objective under the STI was based on the achievement of certain levels of distributable cash flow relative to the forecast in the Partnership’s initial public offering. As a publicly traded limited partnership, our performance is generally judged on our ability to pay cash distributions to our unitholders. We use distributable cash flow as the financial objective because we believe it is a useful measure of our ability to make such cash distributions. Accordingly, we believe that establishing a financial objective based on distributable cash flow appropriately encourages and rewards decision-making designed to increase our ability to pay cash distributions. For fiscal year 2006, the payout on the financial objective ranged from 50% if the minimum level of performance was achieved, 100% if the target level of performance was achieved and 200% if the maximum level of performance was achieved. When the performance level falls between these percentages, payout will be determined by straight-line interpolation. For fiscal year 2006, the maximum level of performance, or 200% payout, was achieved on this financial objective.
The 2006 stated company objectives under the STI were based on: (1) achievement of certain levels of per unit distribution growth, excluding distribution growth resulting from the contribution of assets from DCP Midstream, LLC; and (2) establishing and maintaining strong internal controls and accounting accuracy while meeting the performance requirements of the Sarbanes-Oxley Act of 2002. The payout on these company objectives ranged from 50% if the minimum level of performance was achieved, 100% if the target level of performance was achieved and 200% if the maximum level of performance was achieved. When the performance level falls between these percentages, payout will be determined by straight-line interpolation. For fiscal year 2006, the 130% payout level of performance, which was between target and maximum level of performance, was achieved for the per unit distribution growth objective and the 200% payout level of performance, which was the maximum level of performance, was achieved for the internal controls and accounting accuracy objective.
The 2006 stated personal objectives under the STI were based on a number of individual performance objectives for each employee, which included items such as total unitholder return relative to the peer group, establishment of strong corporate governances and execution of growth strategies for earnings and targeted EBITDA additions. The personal objectives were approved by the compensation committee for the CEO, and by the CEO for the other executive officers. The payout on the individual personal objectives ranged from 0% if the minimum level of performance was not achieved, 75% if the minimum level of performance was achieved, 100% if the target level of performance was achieved and 125% if the maximum level of performance was achieved. When the performance level falls between these percentages, payout will be determined by straight-line interpolation. For fiscal year 2006, the aggregate level of performance achieved by the executive officers on their personal objectives ranged from 70% payout to 113% payout.
Long-Term Incentive Plan, or LTIP — The long-term incentive compensation program has the objective of providing a focus on long-term value creation and enhancing executive retention. Under our 2006 LTIP program, we make cash payments to each executive officer if certain compound annual growth rates in our distributable cash flow are achieved within a three year period, and such executive officer remains employed with us during this period. We believe this program promotes retention of our executive officers, and focuses our executive officers on the goal of long-term value creation through the long-term growth in our distributable cash flow.
For 2006, the compensation committee awarded our executive officers phantom limited partnership units, or phantom LPUs, which vest in their entirety at the end of a three-year measurement period, or the Performance Period, to the extent the performance measure is achieved during the Performance Period. The initial awards were granted at the first board of directors’ meeting following the end of the first quarter of 2006. The number of awards granted to our executive officers is set forth in the “Grants of Plan Based Awards” table below. Award recipients also received the right to receive distribution equivalent rights, or
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DERs, on the number of units earned during the Performance Period. Our practice is to determine the dollar amount of long-term incentive compensation that we want to provide, and to then grant a number of phantom LPUs that have a fair market value equal to that amount on the date of grant, which is based on the closing price of our common units on the New York Stock Exchange on the date of grant. Target long-term incentive opportunities for executives under the plan are established as a percentage of base salary, using the Apogee study data for individuals in comparable positions. The target 2006 long-term incentive opportunities, expressed as a percentage of base salary, for the CEO, the CFO and the Vice Presidents were 140%, 80% and 80%, respectively.
Both the phantom LPUs and the DERs will be paid in cash upon vesting. The amount paid on the phantom LPUs will be based on the product of the number of LPUs earned times the fair market value of our common units on the payment date, which is determined to be the closing sales price of our common units on the vesting date, or, if there is no trading in the common units on such date, on the next preceding date on which there is trading. The amount paid on the DERs will equal the quarterly distributions actually paid during the Performance Period on the number of LPUs earned.
For the phantom LPUs granted in 2006, the performance measure is compound annual growth rate, or CAGR, on distributable cash flow over the Performance Period. This performance measure was initially designed and proposed by the executive officers and presented to the chairman of the General Partner’s board of directors. These objectives were then considered and approved by the compensation committee. For the Performance Period, CAGR on distributable cash flow will be measured from a baseline measurement of $1.62 of distributable cash flow per unit, based on $28.3 million of distributable cash flow and 17.5 million units outstanding. If the minimum performance target of 10% CAGR on distributable cash flow is not attained during the Performance Period, none of the phantom LPUs will vest. If the CAGR on distributable cash flow is 10%, 50% of the phantom LPUs will vest. If the CAGR on distributable cash flow is 15%, 100% of the phantom LPUs will vest. If the CAGR on distributable cash flow is 25% or greater, 150% of the phantom LPUs will vest. When the CAGR falls between the 50%, 100% and 150% levels, vesting will be determined by straight-line interpolation. The compensation committee may, in its sole discretion, increase or decrease the percentage of units vesting by up to 25 percentage points to reflect its evaluation of key performance issues that may not be captured by the performance measure.
In the event that any person other than DCP Midstream, LLCand/or an affiliate thereof becomes the beneficial owner of more than 50% of the combined voting power of the General Partner’s equity interests prior to the completion of the Performance Period, the phantom LPUs and related DERs will vest pro rata based on the number of days that have lapsed in the Performance Period through the date of the change of control, and the remainder of the LPUs and DERs that do not vest will be forfeited. The vested phantom LPUs and related DERs will be paid in cash. In the event an award recipient’s employment is terminated for reasons of death, disability, early or normal retirement, or if the recipient is terminated by the General Partner for reasons other than cause, the recipient (or his estate) will be entitled to a pro rata amount of the award based upon the percentage of the Performance Period the recipient was employed and our performance. Termination of employment for any other reason will result in the forfeiture of any unvested units.
Other Compensation — In addition, our executives are eligible to participate in other compensation programs, which include but are not limited to:
IPO Phantom Units — In conjunction with our initial public offering, in January 2006 our General Partner’s board of directors granted phantom LPUs to key employees, including the executive officers, which vest in their entirety three years following the grant date. Upon vesting, the phantom LPUs will be paid in common units or, at the discretion of the compensation committee, cash based on the fair market value of our common units on the payment date. There is no performance condition associated with these phantom LPUs. Award recipients also receive DERs based on the number of common units awarded, which are paid in cash on a quarterly basis from the date of the initial grant. These phantom LPUs were granted to reward those key employees and executive officers that made significant contributions to our successful initial public offering. The amounts of awards granted to our executive officers are set forth in the “Grants of Plan Based Awards” table below.
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In the event that any person other than DCP Midstream, LLCand/or an affiliate thereof becomes the beneficial owner of more than 50% of the combined voting power of the General Partner’s equity interests prior to the completion of the vesting period, all the phantom LPUs will become fully vested upon such change of control, and will be paid in common units of the Partnership, or in the compensation committee’s sole discretion, cash. If cash is paid, the amount will be determined based upon the closing price of the Partnership’s common units on the New York Stock Exchange upon such change of control. In the event an award recipient’s employment is terminated for reasons of death, disability, early or normal retirement, or if the recipient is terminated by the General Partner for reasons other than cause, the phantom LPUs will immediately vest and the recipient (or his estate) will be entitled to the full amount of the award. Termination of employment for any other reason will result in the forfeiture of any unvested units.
Company Retirement Contributions — Employees may elect to participate in the DCP Midstream, LLC 401(k) and Retirement Plan. Under the plan, employees may elect to defer up to 75% of their eligible compensation, or up to the limits specified by the Internal Revenue Service. The Partnership matches the first 6% of eligible compensation contributed by the employee to the plan. In addition, the Partnership makes retirement contributions equal to 4% of the eligible compensation of qualifying participants to the plan, up to the limits specified by the Internal Revenue Service. Effective January 1, 2007, the Partnership will make retirement contributions ranging from 4% to 7% of eligible compensation of all employees, based on years of service.
Miscellaneous Compensation — Our executive officers are eligible to participate in a nonqualified deferred compensation program. Executive officers are allowed to defer up to 75% of their base salary, and up to 100% of their STI, LTIP or other compensation. Executive officers elect either to receive amounts contributed during specific plan years as a lump sum at a specific date, subject to Internal Revenue Service rules, or in a lump sum or annual annuity (over three to 20 years) at termination.
Executive officers and other eligible employees may participate in a noncontributory, defined benefit retirement plan. Benefits earned under this plan are attributable to compensation in excess of the annual compensation limits under section 401(k) of the Internal Revenue Code. Under this plan, the Partnership makes a contribution of up to 10% of eligible compensation, as defined by this plan, to the nonqualified deferred compensation program.
In addition, we provide our employees, including the executive officers, with a variety of health and welfare benefit programs. The health and welfare programs are intended to protect employees against catastrophic loss and promote well being. These programs include medical, wellness, pharmacy, dental, vision, life insurance premiums, and accidental death and disability. In addition, we pay certain perquisites to our executives, which include items such as financial planning, club dues and an allowance towards annual medical expenses. Finally, we provide all our employees with a monthly parking pass or a pass to be used on available public transportation systems.
Other
Unit Ownership Guidelines — To underscore the importance of linking executive and unitholder interests, the board of directors of our General Partner has adopted unit ownership guidelines for executive officers and key employees who are eligible to receive long-term incentive awards. To that extent, the board has established target equity ownership obligations for the various levels of executives, which have a five-year build term. Ownership is reported annually to the compensation committee. As of December 31, 2006, the unit ownership guidelines for the executive officers were as follows:
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CEO | | | 28,000 | |
CFO | | | 10,000 | |
Vice Presidents | | | 10,000 | |
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Report of the Compensation Committee
We have reviewed and discussed with management the “Compensation Discussion and Analysis” sections above. Based on this review and discussion, we recommended to the board of directors of the General Partner that the “Compensation Discussion and Analysis” referred to above be included in this annual report onForm 10-K for the year ended December 31, 2006.
Compensation Committee
Jim W. Mogg (Chairman)
Derrill Cody
William H. Easter III
Frank A. McPherson
Executive Compensation
The aggregatefollowing table discloses the compensation of the General Partner’s principal executive officers, principal financial officer and named executive officers, or collectively, the “executive officers”, for the year ended December 31, 2006:
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| | Summary Compensation | | | | |
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| | | | | | | | | | | Non-Equity
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| | | | | | | | LPU
| | | Incentive Plan
| | | Compensation
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Name and Principal Position | | Year | | | Salary | | | Awards(c) | | | Compensation | | | Earnings(d) | | | Compensation(e) | | | Total | |
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Michael J. Bradley(a) | | | 2006 | | | $ | 291,497 | | | $ | — | (f) | | $ | — | (f) | | $ | 4,427 | | | $ | 68,410 | | | $ | 364,334 | |
Former President and | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Chief Executive Officer | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Mark A. Borer(b) | | | 2006 | | | $ | 47,215 | | | $ | — | | | $ | 46,655 | | | $ | 45 | | | $ | 2,052 | | | $ | 95,967 | |
President and Chief | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Executive Officer | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Thomas E. Long | | | 2006 | | | $ | 180,000 | | | $ | 92,191 | | | $ | 133,650 | | | $ | — | | | $ | 33,182 | | | $ | 439,023 | |
Vice President and Chief Financial Officer | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Michael S. Richards | | | 2006 | | | $ | 165,000 | | | $ | 88,390 | | | $ | 122,048 | | | $ | — | | | $ | 32,717 | | | $ | 408,155 | |
Vice President, General | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Counsel and Secretary | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Greg K. Smith | | | 2006 | | | $ | 170,000 | | | $ | 89,600 | | | $ | 121,444 | | | $ | 480 | | | $ | 36,044 | | | $ | 417,568 | |
Vice President, Business | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Development | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
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(a) | | Mr. Bradley’s employment with the General Partner terminated effective October 31, 2006. |
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(b) | | Mr. Borer’s employment with the General Partner commenced effective November 10, 2006. |
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(c) | | The amounts in this column reflect the dollar amount recognized for financial statement reporting purposes for the year ended December 31, 2006, in accordance with the provisions of Statement of Financial Standards No. 123,Share-Based Payment, as revised, or SFAS 123R, and include amounts from awards granted in January 2006 related to our initial public offering, and awards granted in conjunction with our LTIP during 2006. See Note 14 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data.” |
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(d) | | Amounts in this column are also included in the “Nonqualified Deferred Compensation” table below. |
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(e) | | 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. |
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(f) | | Forfeited effective with the resignation from the General Partner. |
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Michael J. Bradley, Former President and CEO
Prior to his resignation, Mr. Bradley was receiving an annual base salary of $336,500, of which he deferred $23,320 of the amounts earned in 2006. Mr. Bradley forfeited all of his phantom LPU awards, which were valued at $177,874 for financial statement reporting purposes for the year ended December 31, 2006, in accordance with the provisions of SFAS 123R, effective with his resignation from the General Partner on October 31, 2006. Additionally, Mr. Bradley forfeited the unvested DERs related to the phantom LPUs granted pursuant to the 2006 LTIP, which were valued at $12,753, in accordance with the provisions of SFAS 123R. Under the STI, Mr. Bradley was eligible to earn a targeted level of 60% of his annual base salary, which he also forfeited effective with his resignation from the General Partner.
“All Other Compensation” includes the following:
| | |
| • | Company retirement contributions of $22,000; |
|
| • | Nonqualified deferred compensation program contributions of $31,648; |
|
| • | DERs of $5,940; |
|
| • | Life insurance premiums of $1,057 paid by the Partnership on behalf of Mr. Bradley; and |
|
| • | Payout of vacation accrued as of October 31, 2006, of $7,765. |
Mark A. Borer, President and CEO
The annual base salary for 2006 for Mr. Borer was $341,000, of which he deferred $8,944 of the amount of $47,215 earned for his service with the Partnership in 2006. Under the 2006 STI, Mr. Borer’s target opportunity was 60% of his annual base salary, with the possibility of earning from 0% to 109% of his annual base salary, depending on the level of performance in each of the STI objectives, which was pro rated based upon his service period for 2006. While an employee at DCP Midstream, LLC, he received various equity grants and other compensation which are not reflected as part of the compensation attributable to his service with the Partnership.
“All Other Compensation” includes the following:
| | |
| • | Nonqualified deferred compensation program contributions of $1,945; and |
|
| • | Life insurance premiums of $107 paid by the Partnership on behalf of Mr. Borer. |
Thomas E. Long, Vice President and CFO
The annual base salary for Mr. Long was $180,000 of which none was deferred in 2006. The LPU awards are comprised of IPO Phantom Units and phantom LPUs pursuant to the Named Executive OfficersLTIP. Under the 2006 STI, Mr. Long’s target opportunity was 45% of his annual base salary, with the possibility of earning from 0% to 82% of his annual base salary, depending on the level of performance in each of the STI objectives.
“All Other Compensation” includes the following:
| | |
| • | Company retirement contributions of $21,553; |
|
| • | DERs of $10,981; and |
|
| • | Life insurance premiums of $648 paid by the Partnership on behalf of Mr. Long. |
Michael S. Richards, Vice President, General Counsel and Secretary
The annual base salary for services renderedMr. Richards was $165,000 of which none was deferred in 2006. The LPU awards are comprised of IPO Phantom Units and phantom LPUs pursuant to usthe LTIP. Under the 2006 STI, Mr. Richards’ target opportunity was 45% of his annual base salary, with the possibility of earning from 0% to 82% of his annual base salary, depending on the level of performance in each of the STI objectives.
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“All Other Compensation” includes the following:
| | |
| • | Company retirement contributions of $20,891; |
|
| • | DERs of $10,482; |
|
| • | Life insurance premiums of $594 paid by the Partnership on behalf of Mr. Richards; and |
|
| • | A deminimus bonus of $750. |
Greg K. Smith, Vice President, Business Development
The annual base salary for Mr. Smith was $170,000 of which he deferred $6,800 of the amounts earned in 2006. The LPU awards are comprised of IPO Phantom Units and phantom LPUs pursuant to the LTIP. Under the 2006 STI, Mr. Smith’s target opportunity was 45% of his annual base salary, with the possibility of earning from 0% to 82% of his annual base salary, depending on the level of performance in each of the STI objectives.
“All Other Compensation” includes the following:
| | |
| • | Company retirement contributions of $21,928; |
|
| • | Nonqualified deferred compensation program contributions of $2,864; |
|
| • | DERs of $10,640; and |
|
| • | Life insurance premiums of $612 paid by the Partnership on behalf of Mr. Smith. |
Grants of Plan-Based Awards
Following are the grants of plan-based awards for the period from December 7, 2005, the dateGeneral Partner’s executive officers as of our initial public offering, through December 31, 2005 was approximately $55,000.2006:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Estimated Future Payouts under
| | | | | | | |
| | | | Non-Equity Incentive Plan
| | | Estimated Future Payouts under
| | | | |
| | | | Awards(a) | | | Equity Incentive Plan Awards | | | | |
| | | | | | | | | | | | | | | | | | | | | | Grant Date
| |
| | | | | | | | | | | | | | | | | | | | | | Fair Value
| |
| | | | | | | | | | | | | | | | | | | | | | of LPU
| |
| | | | Minimum
| | | Target
| | | Maximum
| | | Minimum
| | | Target
| | | Maximum
| | | Awards
| |
Name | | Grant Date | | ($) | | | ($) | | | ($) | | | (#) | | | (#) | | | (#) | | | ($) | |
|
Mark A. Borer(c) | | NA | | $ | 15,935 | | | $ | 28,329 | | | $ | 51,346 | | | | — | | | | — | | | | — | | | $ | — | |
Thomas E. Long | | NA | | $ | 45,563 | | | $ | 81,000 | | | $ | 146,813 | | | | — | | | | — | | | | — | | | | — | |
| | 1/3/2006 | | | — | | | | — | | | | — | | | | 4,000 | | | | 4,000 | | | | 4,000 | | | $ | 96,200 | |
| | 5/5/2006(b) | | | — | | | | — | | | | — | | | | 2,670 | | | | 5,340 | | | | 8,010 | | | $ | 143,966 | |
Michael S. Richards | | NA | | $ | 41,766 | | | $ | 74,250 | | | $ | 134,578 | | | | — | | | | — | | | | — | | | | — | |
| | 1/3/2006 | | | — | | | | — | | | | — | | | | 4,000 | | | | 4,000 | | | | 4,000 | | | $ | 96,200 | |
| | 5/5/2006(b) | | | — | | | | — | | | | — | | | | 2,450 | | | | 4,900 | | | | 7,350 | | | $ | 132,104 | |
Greg K. Smith | | NA | | $ | 43,031 | | | $ | 76,500 | | | $ | 138,656 | | | | — | | | | — | | | | — | | | | — | |
| | 1/3/2006 | | | — | | | | — | | | | — | | | | 4,000 | | | | 4,000 | | | | 4,000 | | | $ | 96,200 | |
| | 5/5/2006(b) | | | — | | | | — | | | | — | | | | 2,520 | | | | 5,040 | | | | 7,560 | | | $ | 135,878 | |
Our
| | |
(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 on the line with the grant date of5/5/2006 represent units awarded under the 2006 LTIP. If minimum levels of performance are not met, then the payout may be zero. |
|
(c) | | Prorated based on period of service for 2006. |
The IPO Phantom Units were awarded on January 3, 2006, and will vest in their entirety on January 3, 2009. The phantom LPUs pursuant to the 2006 LTIP were awarded on May 5, 2006, and will vest in their
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entirety on December 31, 2008, if the specified performance conditions are satisfied. Mr. Bradley forfeited all of his IPO Phantom Unit awards and the phantom LPU awards pursuant to the 2006 LTIP upon his resignation from the General Partner on October 31, 2006.
Outstanding Equity Awards at Fiscal Year-End
Following are the outstanding equity awards for the General Partner’s executive officers as of December 31, 2006:
| | | | | | | | | | | | | | | | |
| | Outstanding LPU Awards | |
| | | | | | | | Equity Incentive
| | | Equity Incentive
| |
| | | | | | | | Plan Awards:
| | | Plan Awards:
| |
| | | | | Market Value of
| | | Unearned Units
| | | Market Value of
| |
| | Units That Have
| | | Units That Have Not
| | | That Have Not
| | | Unearned Units That
| |
Name | | Not Vested(a) | | | Vested(b) | | | Vested(c) | | | Have Not Vested(b) | |
|
Thomas E. Long | | | 4,000 | | | $ | 138,200 | | | | 5,340 | | | $ | 184,497 | |
Michael S. Richards | | | 4,000 | | | $ | 138,200 | | | | 4,900 | | | $ | 169,295 | |
Greg K. Smith | | | 4,000 | | | $ | 138,200 | | | | 5,040 | | | $ | 174,132 | |
| | |
(a) | | IPO Phantom Units awarded1/3/2006; units vest in their entirety on1/3/2009. For additional information, see “Compensation Discussion and Analysis — Other Compensation — IPO Phantom Units.” |
|
(b) | | Value calculated based on the closing price of a common LPU at December 29, 2006. |
|
(c) | | Phantom LPUs pursuant to the 2006 LTIP awarded5/5/2006; units vest in their entirety over a range of 0% to 150% on12/31/2008 if the specified performance conditions are satisfied; valuation of unvested units is based on assumed performance at “target” performance levels. |
Options Exercises and DCP Midstream GP, LLCStock Vested
There were formed in August 2005. Accordingly, DCP Midstream GP, LLC has not accrued any obligations with respect to management incentive or retirement benefitsno options exercised and no limited partnership units that vested during the year ended December 31, 2006.
Nonqualified Deferred Compensation
Following is the nonqualified deferred compensation for its directors andthe General Partner’s executive officers for the 2004year ended December 31, 2006:
| | | | | | | | | | | | | | | | | | | | |
| | Executive
| | | Registrant
| | | Aggregate
| | | | | | Aggregate
| |
| | Contributions
| | | Contributions
| | | Earnings in
| | | Aggregate
| | | Balance at
| |
| | in Last Fiscal
| | | in Last Fiscal
| | | Last Fiscal
| | | Withdrawals/
| | | December 31,
| |
Name | | Year(a)(b) | | | Year(b) | | | Year(c) | | | Distributions(d) | | | 2006(d) | |
|
Michael J. Bradley | | $ | 23,320 | | | $ | — | | | $ | 33,480 | | | $ | 318,831 | | | $ | 84,243 | |
Mark A. Borer | | $ | 8,944 | | | $ | — | | | $ | 24,651 | | | $ | — | | | $ | 480,389 | |
Greg K. Smith | | $ | 6,800 | | | $ | — | | | $ | 885 | | | $ | — | | | $ | 20,582 | |
| | |
(a) | | These amounts were included in the gross salary reported in the “Salary” column of the “Summary Compensation” table. |
|
(b) | | We have not included “Executive Contributions” or “Registrant Contributions” attributable to the executive officers’ prior service with our parent company, DCP Midstream, LLC (their former employer). |
|
(c) | | Amounts attributable to 2006 contributions are included in the “Summary Compensation” table as “Change in Nonqualified Deferred Compensation Earnings.” The remaining amounts are earnings on contributions attributable to the executive officers’ prior service with our parent company, DCP Midstream, LLC (their former employer). |
|
(d) | | Includes amounts attributable to the executive officers’ service with the Partnership, as well as their prior service with our parent company, DCP Midstream, LLC (their former employer). |
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Executive officers are allowed to defer up to 75% of their base salary, and up to 100% of their STI, LTIP or 2005 fiscal years. Our General Partner currently has nine employees includingother compensation. Executive officers elect either to receive amounts contributed during specific plan years as a lump sum at a specific date, subject to Internal Revenue Service rules, or in a lump sum or annual annuity (over three to 20 years) at termination.
Potential Payments Upon Termination or Change in Control
As noted above, the Chief Executive Officer, the Chief Financial Officer, the general counsel, a senior business development executive and support staff. The officers and employees of our General Partner may participate in employee benefit plans and arrangements sponsored by DEFS. Our General Partner has not entered into any employment agreements with any of itsour executive officers. The boardThere are no formal severance plans in place for any employees in the event of directors granted awardstermination of employment, or a change in control of the Partnership. When an employee terminates employment with the Partnership, they are entitled to our key employees and our outside directors pursuant toa cash payment for the Long-Term Incentive Plan in January 2006.amount of unused vacation hours at the date of their termination.
Compensation of Directors
General — On February 8, 2006, the board of directors of ourthe General Partner approved a compensation package for directors who are not officers or employees of affiliates of the General Partner, (“or Non-Employee Directors”).Directors. Members of the board who are also officers or employees of affiliates of ourthe General Partner do not receive additional compensation for serving on the board. The board approved the payment to each Non-Employee Director of an annual compensation package containing the following: (i)(1) a $35,000 retainer; (ii)(2) a board meeting fee of $1,000 for each board meeting attended; (iii)(3) a telephonic board meeting fee of $500 for each telephonic meeting attended; (iv)(4) an initial grant of 2,000 phantom units,LPUs, under the Partnership’s Long-Term Incentive Plan,LTIP, that represent an approximate equivalent value of common units representing limited partnership interestsLPUs in the Partnership; and (v)(5) following the first year, an annual grant of 1,000 common LPUs. The directors also receive DERs, based on the number of units awarded, which are paid in cash on a quarterly basis. The phantom units, under the Partnership’s Long-Term Incentive Plan, that represent an approximate equivalent value of common units representing limited partnership interests in the Partnership. The grant of phantom unitsLPUs will vest ratably over three years. In addition,The phantom LPUs will be paid in cash upon vesting, based on fair market value on the Chairpayment date, which is determined to be the closing sales price of a common unit of the audit committee ofPartnership on the board will receive an annual retainer of $20,000 andvesting date, or, if there is no trading in the members ofunits on such date, on the audit committee will receive $1,500 for each audit committee meeting attended. The Chair of the special committee of the Board will likewise receive an annual retainer of $20,000 and the members of the special committee will receive $1,000 for each special committee meeting attended. Finally, the members of the compensation committee will receive $1,000 for each compensation committee meeting attended. Suchnext preceding date on which there was trading.
Our directors will also be reimbursed forout-of-pocket expenses in connection with attending meetings of the board of directors and committees. Each director will be fully indemnified by us for his actions associated with being a director to the fullest extent permitted under Delaware law.
Long-Term Incentive PlanCommittees — The chairman of the audit committee of the board will receive an annual retainer of $20,000 and the members of the audit committee will receive $1,500 for each audit committee meeting attended. The chairman of the special committee of the board will likewise receive an annual retainer of $20,000 and the members of the special committee will receive $1,000 for each special committee meeting attended. Finally, the members of the compensation committee will receive $1,000 for each compensation committee meeting attended.
A complete description of our long-term incentive planFollowing is incorporated herein by reference to Note 2the compensation of the accompanying Notes to Consolidated Financial Statements included in Item 8 of thisForm 10-K.General Partner’s Non-Employee Directors for the year ended December 31, 2006:
| | | | | | | | | | | | | | | | |
| | Fees Earned
| | | | | | | | | | |
| | or Paid in
| | | LPU
| | | All Other
| | | | |
Name | | Cash | | | Awards(d) | | | Compensation(e) | | | Total | |
|
Jim W. Mogg(a) | | $ | 40,000 | | | $ | — | | | $ | 1,275 | | | $ | 41,275 | |
Paul F. Ferguson, Jr. | | $ | 85,500 | | | $ | 42,237 | | | $ | 8,022 | | | $ | 135,759 | |
Frank A. McPherson | | $ | 87,000 | | | $ | 42,237 | | | $ | 4,966 | | | $ | 134,203 | |
Thomas C. Morris | | $ | 65,500 | | | $ | 42,237 | | | $ | 6,896 | | | $ | 114,633 | |
Milton Carroll(b) | | $ | 52,000 | | | $ | — | | | $ | 3,659 | | | $ | 55,659 | |
Derrill Cody | | $ | 45,500 | | | $ | 42,237 | | | $ | 3,577 | | | $ | 91,314 | |
Michael J. Panatier(c) | | $ | 41,500 | | | $ | — | | | $ | 2,460 | | | $ | 43,960 | |
| | |
(a) | | Chairman of the board of directors of the General Partner; compensation prorated from September 1, 2006. |
103142
| | |
(b) | | Mr. Carroll resigned from the board of directors of the General Partner effective December 20, 2006. |
|
(c) | | Mr. Panatier resigned from the board of directors of the General Partner effective November 27, 2006. |
|
(d) | | The amounts in this column reflect the dollar amount recognized for financial statement reporting purposes for the year ended December 31, 2006, in accordance with the provisions of SFAS 123R, and include amounts from awards granted in conjunction with our LTIP during 2006. See Note 14 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data.” |
|
(e) | | Includes DERs, and reimbursement forout-of-pocket expenses in connection with attending meetings. |
On November 29, 2006, the board of directors of the General Partner approved a compensation package for Jim W. Mogg, the chairman of the board of directors. Mr. Mogg, who retired from Duke Energy Corporation in September 2006, will receive an annual retainer of $120,000, which was prorated for 2006 and will continue for 2007. Mr. Mogg is not eligible for additional compensation for attending board meetings or committee meetings that our other Non-Employee Directors are eligible to receive. Mr. Mogg is also the compensation committee chair. He received no additional compensation for serving in that capacity during 2006. Mr. Mogg will be retiring from the board of directors of the General Partner in the second quarter of 2007, at which time Mr. Fred J. Fowler will assume the responsibilities of the chairman.
Mr. Ferguson is the audit committee chair and a member of the special committee.
Mr. McPherson is the special committee chair, and a member of the audit committee and the compensation committee.
Mr. Morris is a member of the audit committee and the special committee.
Mr. Carroll was a member of the compensation committee and the special committee. The value of Mr. Carroll’s phantom LPU awards, calculated in accordance with the provisions of SFAS 123R, was $41,321 as of the date of his resignation.
Mr. Cody is a member of the compensation committee.
Mr. Panatier was a member of the compensation committee. The value of Mr. Panatier’s phantom LPU awards, calculated in accordance with the provisions of SFAS 123R, was $40,330 as of the date of his resignation.
The total grant date fair value of phantom LPU awards for the Non-Employee Directors was $288,600, of which $96,200 was forfeited by Messrs. Carroll and Panatier upon their respective resignations from the board of directors. At December 31, 2006, Messrs. Cody, Ferguson, McPherson and Morris each had 2,000 phantom LPUs outstanding, related to awards granted in 2006.
| |
Item 12. | Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters.Matters |
The following table sets forth the beneficial ownership of our units and the related transactions held by:
| | |
| • | each person who beneficially owns 5% or more of our outstanding units as of February 17, 2006;March 12, 2007; |
|
| • | all of the directors of DCP Midstream GP, LLC; |
|
| • | each Named Executive Officer of DCP Midstream GP, LLC; and |
|
| • | all directors and Named Executive Officers of DCP Midstream GP, LLC as a group. |
| | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | Percentage of
| |
| | | | | | | | | | | Percentage of
| | | Total Common and
| |
| | Common
| | | Percentage of
| | | Subordinated
| | | Subordinated
| | | Subordinated
| |
| | Units
| | | Common Units
| | | Units
| | | Units
| | | Units
| |
| | Beneficially
| | | Beneficially
| | | Beneficially
| | | Beneficially
| | | Beneficially
| |
Name of Beneficial Owner(1) | | Owned | | | Owned | | | Owned | | | Owned | | | Owned | |
|
Duke Energy Field Services, LLC(2) | | | 7,143 | | | | * | | | | 7,142,857 | | | | 100 | % | | | 40.0 | % |
DCP LP Holdings, LP(3) | | | 7,143 | | | | * | | | | 7,142,857 | | | | 100 | % | | | 40.0 | % |
Williams, Jones & Associates, Inc.(4) | | | 911,500 | | | | 8.8 | % | | | — | | | | — | | | | 8.8 | % |
Jim W. Mogg | | | 13,001 | | | | * | | | | — | | | | — | | | | * | |
Michael J. Bradley | | | 15,081 | | | | * | | | | — | | | | — | | | | * | |
Thomas E. Long | | | 22,501 | | | | * | | | | — | | | | — | | | | * | |
Michael S. Richards | | | 1,501 | | | | * | | | | — | | | | — | | | | * | |
Greg K. Smith | | | 5,001 | | | | * | | | | — | | | | — | | | | * | |
William H. Easter III | | | 3,501 | | | | * | | | | — | | | | — | | | | * | |
Paul F. Ferguson, Jr. | | | 1,001 | | | | * | | | | — | | | | — | | | | * | |
John E. Lowe | | | 10,001 | | | | * | | | | — | | | | — | | | | * | |
Milton Carroll | | | 3,001 | | | | * | | | | — | | | | — | | | | * | |
Derrill Cody | | | 15,001 | | | | * | | | | — | | | | — | | | | * | |
Frank A. McPherson | | | 5,001 | | | | * | | | | — | | | | — | | | | * | |
Thomas C. Morris | | | 5,001 | | | | * | | | | — | | | | — | | | | * | |
Michael J. Panatier | | | 5,001 | | | | * | | | | — | | | | — | | | | * | |
All directors and executive officers as a group (13 persons) | | | 104,593 | | | | * | | | | — | | | | — | | | | * | |
Percentage of total common, Class C and subordinated units beneficially owned is based on 17,700,312 units outstanding.
143
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | Percentage of
| | | | |
| | | | | | | | | | | | | | | | | | | | Total Common,
| | | | |
| | | | | Percentage of
| | | | | | Percentage of
| | | | | | Percentage of
| | | Class C and
| | | | |
| | Common
| | | Common
| | | Class C
| | | Class C
| | | Subordinated
| | | Subordinated
| | | Subordinated
| | | | |
| | Units
| | | Units
| | | Units
| | | Units
| | | Units
| | | Units
| | | Units
| | | | |
| | Beneficially
| | | Beneficially
| | | Beneficially
| | | Beneficially
| | | Beneficially
| | | Beneficially
| | | Beneficially
| | | | |
Name of Beneficial Owner(a) | | Owned | | | Owned | | | Owned | | | Owned | | | Owned | | | Owned | | | Owned | | | | |
|
DCP Midstream, LLC(b)(1) | | | 7,143 | | | | | * | | | 200,312 | | | | 100 | % | | | 7,142,857 | | | | 100 | % | | | 41.5 | % | | | | |
DCP LP Holdings, LP(c)(1) | | | 7,143 | | | | | * | | | 200,312 | | | | 100 | % | | | 7,142,857 | | | | 100 | % | | | 41.5 | % | | | | |
Fiduciary Asset Management, L.L.C.(d) | | | 971,640 | | | | 9.4 | % | | | — | | | | — | | | | — | | | | — | | | | 5.5 | % | | | | |
Williams, Jones & Associates, LLC(e) | | | 968,174 | | | | 9.4 | % | | | — | | | | — | | | | — | | | | — | | | | 5.5 | % | | | | |
Jim W. Mogg | | | 13,001 | | | | | * | | | — | | | | — | | | | — | | | | — | | | | * | | | | | |
Mark A. Borer | | | 32,001 | | | | | * | | | — | | | | — | | | | — | | | | — | | | | * | | | | | |
Thomas E. Long | | | 22,501 | | | | | * | | | — | | | | — | | | | — | | | | — | | | | * | | | | | |
Michael S. Richards | | | 1,501 | | | | | * | | | — | | | | — | | | | — | | | | — | | | | * | | | | | |
Greg K. Smith | | | 5,001 | | | | | * | | | — | | | | — | | | | — | | | | — | | | | * | | | | | |
William H. Easter III | | | 3,501 | | | | | * | | | — | | | | — | | | | — | | | | — | | | | * | | | | | |
Paul F. Ferguson, Jr. | | | 1,001 | | | | | * | | | — | | | | — | | | | — | | | | — | | | | * | | | | | |
John E. Lowe | | | 10,001 | | | | | * | | | — | | | | — | | | | — | | | | — | | | | * | | | | | |
Derrill Cody | | | 15,001 | | | | | * | | | — | | | | — | | | | — | | | | — | | | | * | | | | | |
Frank A. McPherson | | | 5,001 | | | | | * | | | — | | | | — | | | | — | | | | — | | | | * | | | | | |
Thomas C. Morris | | | 5,001 | | | | | * | | | — | | | | — | | | | — | | | | — | | | | * | | | | | |
All directors and executive officers as a group (11 persons) | | | 113,511 | | | | | * | | | — | | | | — | | | | — | | | | — | | | | * | | | | | |
| | |
* | | Less than 1%. |
|
(1)(a) | | Unless otherwise indicated, the address for all beneficial owners in this table is 370 17th Street, Suite 2775, Denver, Colorado 80202. |
|
(2)(b) | | Duke Energy Field ServicesDCP 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. Duke Energy Field ServicesDCP Midstream, LLC disclaims beneficial ownership of all of the units owned by DCP LP Holdings, LP. The address of Duke Energy Field ServicesDCP Midstream, LLC is 370 17th Street, Suite 2500, Denver, Colorado 80202. |
|
(3)(c) | | The address of DCP LP Holdings, LP is 370 17th Street, Suite 2500, Denver, Colorado 80202. |
|
(4)(d) | | As set forth in a Schedule 13G filed on January 18, 2006.10, 2007. The address of Fiduciary Asset Management, L.L.C. is 8112 Maryland Avenue, Suite 400, St. Louis, MO 63105. Fiduciary Asset Management, L.L.C. acts as an investmentsub-advisor to certain closed-end investment companies, as well as to private individuals, some of whom may be deemed to be beneficial owners. |
|
(e) | | As set forth in a Schedule 13G filed on February 14, 2007. The address of Williams, Jones & Associates, Inc.LLC is 717 Fifth Avenue, New York, New York 10022. |
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Equity Compensation Plan Information
The following table summarizes information about our equity compensation plan as of December 31, 2005.2006.
| | | | | | | | | | | | |
| | Number of
| | | Weighted-
| | | Number of Securities
| |
| | Securities to be
| | | Average
| | | Remaining Available for
| |
| | Issued upon
| | | Exercise Price
| | | Future Issuance underUnder
| |
| | Exercise of
| | | of Outstanding
| | | Equity Compensation
| |
| | Outstanding
| | | Options,
| | | Plans (Excluding
| |
| | Options, Warrants
| | | Warrants and
| | | Securities Reflected in
| |
| | and Rights(1)
| | | Rights
| | | Column(a))
| |
| | (a) | | | (b) | | | (c) | |
|
Equity compensation plans approved by unitholders | | | — | | | $ | — | | | | — | |
Equity compensation plans not approved by unitholders | | | — | | | | — | | | | —802,210 | |
| | | | | | | | | | | | |
Total | | | — | | | $ | — | | | | —802,210 | |
| | | | | | | | | | | | |
| | |
(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“Executive Compensation — Long-Term Incentive Plan.Components of Compensation.” |
| |
Item 13. | Certain Relationships and Related Transactions.Transactions, and Director Independence |
Distributions and Payments to our General Partner and its Affiliates
The following table summarizes the distributions and payments to be made by us to our General Partner and its affiliates in connection with our formation, ongoing operation, and liquidation. These distributions and payments are determined by and among affiliated entities and, consequently, are not the result of arm’s-length negations.
| | |
Formation Stage:
| | |
The consideration received by our General Partner and its affiliates for the contribution of the assets and liabilities | | • 7,143 common units;
• 7,142,857 subordinated units;
• 2% general partner interest in DCP Midstream GP, LP;
• The incentive distribution rights; and
• $8.6 million cash payment from the proceeds of the offering and borrowings under our new credit facility, in part to reimburse them for certain capital expenditures.
|
105
| | |
Operational Stage:
| | | |
Distributions of available cashAvailable Cash to our General Partner and its affiliates | | | We will generally make cash distributions 98% to the unitholders and 2% to our General Partner. 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 50% of the distributions above the highest target level.
For the period from December 7, 2005, the date of our initial public offering, through December 31, 2005, we made a prorated distribution of $0.095 per unit to our unitholders, including DEFS and its affiliates. Assuming we have sufficient available cash to pay the full minimum quarterly distribution on all of our outstanding units for four quarters, our general partner and its affiliates would receive an annual distribution of approximately $0.5 million on the 2% general partner interest and approximately $10.0 million on their common units and subordinated units.
|
Payments to our General Partner and its affiliates | | | We reimburse DEFSDCP Midstream, LLC and its affiliates up to $4.8$6.8 million per year, adjusted annually commencing in 2007, 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.
|
| | | |
145
Omnibus Agreement
The employees supporting our operations are employees of DEFS.DCP Midstream, LLC. We are required to reimburse DEFSDCP Midstream, LLC for salaries of operating personnel and employee benefits as well as capital expenditures, maintenance and repair costs, taxes and taxes. DEFSother direct costs incurred by DCP Midstream, LLC on our behalf. DCP Midstream, LLC also provides centralized corporate functions on our behalf, including legal, accounting, cash management, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, taxes and engineering. DEFS recordsOur Omnibus Agreement, as amended, clarifies that the accrued liabilitiesannual fee of $6.8 million under the agreement is fixed at such amount, subject to annual increases in the Consumer Price Index, and prepaid expenses for most general and administrative expensesincreases in its financial statements, including liabilities related to payroll, short and long-term incentive plans, employee retirement and medical plans, paid time off, audit, tax, insurance and other service fees. Our share of those costs has been allocated based on our proportionate net investment (consisting of property, plant and equipment, net, equity method investment, and intangible assets, net) compared to DEFS’ net investment. In management’s estimation,connection with the allocation methodologies used are reasonable and result in an allocation to usexpansion of our costsoperations through the acquisition or construction of doing business borne by DEFS.new assets or businesses.
Upon the closing of our initial public offering, we entered into anOur Omnibus Agreement with DEFS,DCP Midstream, LLC, our General Partner and others that addresses the following matters:
| | |
| • | our obligation to reimburse DEFSDCP Midstream, LLC for the payment of operating expenses, including salary and benefits of operating personnel, it incurs on our behalf in connection with our business and operations; |
106
KNOW ALL PERSONS BY THESE PRESENTS that each person whose signature appears below constitutes and appoints Michael J. Bradleyeach of Mark A. Borer and Thomas E. Long as his true and lawfulattorney-in-fact and agent, with full power of substitution and resubstitution, for him or in his name, place, and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments) to this annual report, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto saidattorney-in-fact and agent full power and authority to do and perform each and every act and thing requisite and necessary to be done in connection therewith, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that saidattorney-in-fact and agent or their or his substitute or substitutes, may lawfully do or cause to be done by virtue hereof.
Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.