Exhibit 99.1

THE SOUTHEAST TEXAS MIDSTREAM BUSINESS

COMBINED FINANCIAL STATEMENTS

AS OF DECEMBER 31, 2010 AND 2009

AND THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008

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				Deloitte & Touche LLP
				Suite 3600
				555 Seventeenth Street
				Denver, CO 80202-3942
				USA
				Tel: +1 303 292 5400
				Fax: +1 303 312 4000
				www.deloitte.com

INDEPENDENT AUDITORS’ REPORT

To the Board of Directors and Members of

DCP Midstream, LLC

Denver, CO

We have audited the accompanying combined balance sheets of the Southeast Texas Midstream Business (the “Business”), which consists of assets which are under common ownership and common management, as of December 31, 2010 and 2009, and the related combined statements of operations, comprehensive income, changes in net parent equity, and cash flows for each of the three years in the period ended December 31, 2010. These combined financial statements are the responsibility of the Business’ management. Our responsibility is to express an opinion on these combined financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes 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 Business’ 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, 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 combined financial statements present fairly, in all material respects, the combined financial position of the Business at December 31, 2010 and 2009, and the combined results of its operations and its combined cash flows for each of the three years in the period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America.

The accompanying combined financial statements 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 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.

/s/ Deloitte & Touche LLP

June 17, 2011

Member of            

Deloitte Touche Tohmatsu

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THE SOUTHEAST TEXAS MIDSTREAM BUSINESS

COMBINED BALANCE SHEETS

 

		December 31, 2010				December 31, 2009
		(Millions)
ASSETS
Current assets:
Accounts receivable:
Trade		$	51.1			$	37.3
Affiliates			45.2				1.5
Inventories			9.5				19.5
Unrealized gains on derivative instruments			12.6				35.4
Total current assets			118.4				93.7
Property, plant and equipment, net			281.5				225.2
Goodwill, net			11.9				—
Intangibles, net			33.7				—
Unrealized gains on derivative instruments			0.5				4.7
Other long-term assets			0.6				0.5
Total assets		$	446.6			$	324.1
LIABILITIES AND NET PARENT EQUITY
Current liabilities:
Accounts payable:
Trade		$	74.3			$	66.7
Unrealized losses on derivative instruments			13.6				31.9
Capital spending accrual			9.5				0.3
Other			6.7				4.0
Total current liabilities			104.1				102.9
Unrealized losses on derivative instruments			0.2				4.5
Other long-term liabilities			4.5				4.4
Total liabilities			108.8				111.8
Commitments and contingent liabilities
Equity:
Parent equity			340.5				215.0
Accumulated other comprehensive loss			(2.7	)			(2.7	)
Total net parent equity			337.8				212.3
Total liabilities and net parent equity		$	446.6			$	324.1

See accompanying notes to combined financial statements.

 

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THE SOUTHEAST TEXAS MIDSTREAM BUSINESS

COMBINED STATEMENTS OF OPERATIONS

 

		Year Ended December 31,
		2010				2009				2008
		(Millions)
Operating revenues:
Sales of natural gas, NGLs and condensate		$	416.8			$	274.4			$	707.9
Sales of natural gas, NGLs and condensate to affiliates			395.7				241.9				410.5
Transportation, processing and other			13.2				9.7				10.8
Transportation, processing and other to affiliates			1.8				—				—
Gains from commodity derivative activity, net			12.5				8.9				12.8
(Losses) gains from commodity derivative activity, net — affiliates			(1.1	)			0.6				0.1
Total operating revenues			838.9				535.5				1,142.1
Operating costs and expenses:
Purchases of natural gas and NGLs			749.7				471.5				1,049.2
Purchases of natural gas and NGLs from affiliates			0.8				0.6				16.2
Operating and maintenance expense			18.5				14.5				17.6
Depreciation and amortization expense			14.4				12.0				11.8
General and administrative expense — affiliates			12.1				10.8				10.6
Other income			(1.0	)			—				—
Loss on sale of assets			—				0.5				1.8
Total operating costs and expenses			794.5				509.9				1,107.2
Operating income			44.4				25.6				34.9
Income tax expense			(1.2	)			(0.4	)			(0.7	)
Net income		$	43.2			$	25.2			$	34.2

See accompanying notes to combined financial statements.

 

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THE SOUTHEAST TEXAS MIDSTREAM BUSINESS

COMBINED STATEMENTS OF COMPREHENSIVE INCOME

 

		Year Ended December 31,
		2010				2009				2008
		(Millions)
Net income		$	43.2			$	25.2			$	34.2
Other comprehensive loss:
Net unrealized losses on cash flow hedges			—				(2.0	)			(0.7	)
Total other comprehensive loss			—				(2.0	)			(0.7	)
Total comprehensive income		$	43.2			$	23.2			$	33.5

See accompanying notes to combined financial statements.

 

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THE SOUTHEAST TEXAS MIDSTREAM BUSINESS

COMBINED STATEMENTS OF CASH FLOWS

 

		Year Ended December 31,
		2010				2009				2008
		(Millions)
OPERATING ACTIVITIES:
Net income		$	43.2			$	25.2			$	34.2
Adjustments to reconcile net income to net cash provided by operating activities:
Loss on sale of assets			—				0.5				1.8
Depreciation and amortization expense			14.4				12.0				11.8
Other, net			(0.9	)			0.1				(0.1	)
Change in operating assets and liabilities, which (used) provided cash:
Accounts receivable			(54.0	)			2.1				23.5
Inventories			10.0				(13.8	)			32.8
Net unrealized losses (gains) on derivative instruments			4.4				—				(1.4	)
Accounts payable			4.2				19.8				(45.8	)
Other current assets and liabilities			0.4				(0.7	)			0.9
Other long-term assets and liabilities			(0.1	)			(0.4	)			(0.2	)
Net cash provided by operating activities			21.6				44.8				57.5
INVESTING ACTIVITIES:
Capital expenditures			(25.2	)			(17.4	)			(14.1	)
Purchase of Ceritas			(78.8	)			—				—
Proceeds from sale of assets			0.1				1.1				5.7
Net cash used in investing activities			(103.9	)			(16.3	)			(8.4	)
FINANCING ACTIVITIES:
Net change in parent advances			82.3				(28.5	)			(49.1	)
Net cash provided by (used in) financing activities			82.3				(28.5	)			(49.1	)
Net change in cash and cash equivalents			—				—				—
Cash and cash equivalents, beginning of period			—				—				—
Cash and cash equivalents, end of period		$	—			$	—			$	—

See accompanying notes to combined financial statements.

 

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THE SOUTHEAST TEXAS MIDSTREAM BUSINESS

COMBINED STATEMENTS OF CHANGES IN NET PARENT EQUITY

 

		Parent Equity				Accumulated Other Comprehensive Loss				Net Parent Equity
		(Millions)
Balance, January 1, 2008		$	233.2			$	—			$	233.2
Net change in parent advances			(49.1	)			—				(49.1	)
Comprehensive income (loss):
Net income			34.2				—				34.2
Net unrealized losses on cash flow hedges			—				(0.7	)			(0.7	)
Total comprehensive income (loss)			34.2				(0.7	)			33.5
Balance, December 31, 2008			218.3				(0.7	)			217.6
Net change in parent advances			(28.5	)			—				(28.5	)
Comprehensive income (loss):
Net income			25.2				—				25.2
Net unrealized losses on cash flow hedges			—				(2.0	)			(2.0	)
Total comprehensive income (loss)			25.2				(2.0	)			23.2
Balance, December 31, 2009			215.0				(2.7	)			212.3
Net change in parent advances			82.3				—				82.3
Comprehensive income:
Net income			43.2				—				43.2
Total comprehensive income			43.2				—				43.2
Balance, December 31, 2010		$	340.5			$	(2.7	)		$	337.8

See accompanying notes to combined financial statements.

 

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THE SOUTHEAST TEXAS MIDSTREAM BUSINESS

NOTES TO COMBINED FINANCIAL STATEMENTS

1. Description of Business and Basis of Presentation

The Southeast Texas Midstream Business, or the Business, we, our, or us, is engaged in the business of gathering, transporting, treating, compressing and processing natural gas and natural gas liquids, or NGL’s. The operations, located in Southeast, Texas, include 3 natural gas processing facilities with a total capacity of approximately 350 million cubic feet per day. The facilities are connected to our Liberty 36-mile gathering system and to our CIPCO system, which includes in excess of 600 miles of gathering and transmission lines, as well as our 3 salt dome natural gas storage caverns at Spindletop with a total working gas capacity of 9 billion cubic feet.

These combined financial statements and related notes present the financial position, results of operations, cash flows, and changes in net parent equity of the Business held by DCP Midstream, LLC and its subsidiaries, or Midstream. Midstream is owned 50% by Spectra Energy Corp, or Spectra Energy, and 50% by ConocoPhillips. As of June 17, 2011, Midstream owned an approximately 27% interest, including a 1% general partner interest, in DCP Midstream Partners, LP, or Partners. The Business was contributed to DCP Southeast Texas Holdings GP, and on January 1, 2011, Partners acquired from Midstream a 33.33% interest in DCP Southeast Texas Holdings, GP, or the transaction. As part of the closing of the transaction, the assets, liabilities and operations of the Business, with the exception of any financial derivative instruments and certain working capital and other liabilities now reside in DCP Southeast Texas Holdings, GP. Subsequent to the transaction, Midstream still directs our business operations. The Business does not currently and is not expected to have any employees. Midstream and its affiliates’ employees are responsible for conducting our business and operating our assets.

The combined financial statements include the accounts of the Business and have been prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP. The combined financial statements of the Business have been prepared from the separate records maintained by Midstream and may not necessarily be indicative of the conditions that would have existed, or the results of operations, if the Business had been operated as an unaffiliated entity. Because a direct ownership relationship did not exist among all the various assets comprising the Business, Midstream’s net investment in the Business is shown as net parent equity, in lieu of owner’s equity, in the combined financial statements. All intercompany balances and transactions have been eliminated. Transactions between us and other Midstream operations have been identified in the combined financial statements as transactions between affiliates. In the opinion of management, all adjustments have been reflected that are necessary for a fair presentation of the combined financial statements.

2. Summary of Significant Accounting Policies

Use of Estimates — Conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the combined financial statements and notes. Although these estimates are based on management’s best available knowledge of current and expected future events, actual results could differ from those estimates.

Inventories — Inventories consist primarily of natural gas held in storage for transportation and sales commitments. Inventories are recorded at the lower of weighted-average cost or market value. Transportation costs are included in inventory.

Property, Plant and Equipment — Property, plant and equipment are recorded at historical cost. The cost of maintenance and repairs, which are not significant improvements, are expensed when incurred. Depreciation is computed using the straight-line method over the estimated useful lives of the assets.

Asset Retirement Obligations — Our asset retirement obligations relate primarily to the retirement of various gathering pipelines and processing facilities, obligations related to right-of-way easement agreements and contractual leases for land use. We adjust our asset retirement obligation for any liabilities incurred or settled during the period, accretion expense and any revisions made to the estimated cash flows.

Asset retirement obligations associated with tangible long-lived assets are recorded at fair value in the period in which they are incurred, if a reasonable estimate of fair value can be made, and added to the carrying amount of the associated asset. This additional carrying amount is then depreciated over the life of the asset. The liability is determined using a risk free interest rate, and increases due to the passage of time based on the time value of money until the obligation is settled.

Goodwill and Intangible Assets — Goodwill is the cost of an acquisition less the fair value of the net assets of the acquired business. We perform an annual impairment test of goodwill in the third quarter, and update the test during interim periods when we believe events or changes in circumstances indicate that we may not be able to recover the carrying value of a reporting unit.

 

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THE SOUTHEAST TEXAS MIDSTREAM BUSINESS

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

 

Impairment testing 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, the excess of the carrying value over the fair value is recognized as an impairment loss. We use a discounted cash flow analysis supported by market valuation principles to perform the assessment. Key assumptions in the analysis include the use of an appropriate discount rate and estimated future cash flows. In estimating cash flows, we incorporate current market information, as well as historical and other factors, into our forecasted commodity prices. If actual results are not consistent with our assumptions and estimates, or our assumptions and estimates change due to new information, we may be exposed to goodwill impairment charges, which would be recognized in the period in which the carrying value exceeds fair value.

Intangible assets consist primarily of customer contracts. These intangible assets will be amortized on a straight-line basis over the term of the contract or anticipated relationship, of approximately 15 years. Intangible assets are removed from the gross carrying amount and the total of accumulated amortization in the period in which they become fully amortized.

Long-Lived Assets — We evaluate whether the carrying value of long-lived assets has been impaired when circumstances indicate the carrying value of those assets may not be recoverable. This evaluation is based on undiscounted cash flow projections. The carrying amount is not recoverable if it exceeds the sum of the undiscounted 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:

 

•

significant adverse change in legal factors or business climate;

 

•

a current-period operating or cash flow loss combined with a history of operating or cash flow losses, or a projection or forecast that demonstrates continuing losses associated with the use of a long-lived asset;

 

•

an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of a long-lived asset;

 

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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

 

•

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. We assess the fair value of long-lived assets using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales and discounted cash flow models. 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.

 

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THE SOUTHEAST TEXAS MIDSTREAM BUSINESS

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

 

Accounting for Risk Management and Derivative Activities and Financial Instruments — 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 cash flow (cash flow hedge) or normal purchases or normal sales. The remaining non-trading derivatives, which are related to assets-based activities for which the normal purchases or normal sale exception are not elected, are recorded at fair value in the combined balance sheets as unrealized gains or unrealized losses in derivative instruments, with changes in the fair value recognized in the combined statements of operations. For each derivative, the accounting method and presentation of gains and losses or revenue and expense in the combined statements of operations are as follows:

 

Classification of Contract		Accounting Method		Presentation of Gains & Losses or Revenue & Expense
Non-Trading Derivative Activity		Mark-to-market     method (a)		Net basis in gains and losses from commodity derivative activity
Cash Flow Hedge		Hedge method (b)		Gross basis in the same combined statements of operations category as the related hedged item

 

(a)	Mark-to-market — An accounting method whereby the change in the fair value of the asset or liability is recognized in the combined statements of operations in gains and losses from commodity derivative activity during the current period.

(b)

Hedge method — An accounting method whereby the change in the fair value of the asset or liability is recorded in the combined balance sheets as unrealized gains or unrealized losses on derivative instruments. For cash flow hedges, there is no recognition in the combined statements of operations for the effective portion until the service is provided or the associated delivery period impacts earnings.

Cash Flow Hedges — For derivatives designated as a cash flow hedge, we maintain formal documentation of the hedge. In addition, we formally assess both at the inception of the hedging relationship and on an ongoing basis, whether the hedge contract is highly effective in offsetting changes in cash flows 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 in the combined balance sheets as unrealized gains or unrealized losses on derivative instruments. The effective portion of the change in fair value of a derivative designated as a cash flow hedge is recorded in net parents’ equity as Accumulated Other Comprehensive Income, or AOCI, and the ineffective portion is recorded in the combined statements of operations. During the period in which the hedged transaction impacts earnings, amounts in AOCI associated with the hedged transaction are reclassified to the combined 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 probable that the hedged transaction will not occur. When hedge accounting is discontinued because the derivative no longer qualifies as an effective hedge, the derivative is subject to the mark-to-market accounting method prospectively. The derivative continues to be carried on the combined 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 impacts earnings, unless it is 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.

Valuation — When available, quoted market prices or prices obtained through external sources are used to determine a contract’s fair value. For contracts with a delivery location or duration for which quoted market prices are not available, fair value is determined based on internally developed pricing models developed primarily from historical relationships with quoted market prices and the expected relationship with quoted market prices.

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

Revenue Recognition — We generate the majority of our revenues from natural gas gathering, and NGL processing, compressing and transporting, as well as trading and marketing of natural gas. We realize revenues either by selling the residue natural gas and NGLs, or by receiving fees from the producers.

We obtain access to commodities and provide our midstream services principally under contracts that contain a combination of one or more of the following arrangements:

 

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Fee-based arrangements — Under fee-based arrangements, we receive a fee or fees for one or more of the following services: gathering, compressing, treating, processing, storing 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 fees we would otherwise charge for transportation of natural gas from the wellhead location to the

 

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THE SOUTHEAST TEXAS MIDSTREAM BUSINESS

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

 

delivery point. The revenues we earn are directly related to the volume of natural gas or NGLs that flows through our systems and are not directly dependent on commodity prices. However, to the extent a sustained decline in commodity prices results in a decline in volumes, our revenues from these arrangements would be reduced.

 

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Percent-of-proceeds/liquids arrangements — Under percent-of-proceeds arrangements, we generally purchase natural gas from producers at the wellhead, or other receipt points, gather the wellhead natural gas through our gathering system, treat and process the natural gas, and then sell the resulting residue natural gas, NGLs and condensate based on index prices from published index market prices. We remit to the producers either an agreed-upon percentage of the actual proceeds that we receive from our sales of the residue natural gas, NGLs and condensate, or an agreed-upon percentage of the proceeds based on index related prices for the natural gas, NGLs and condensate, regardless of the actual amount of the sales proceeds we receive. We keep the difference between the proceeds received and the amount remitted back to the producer. Under percent-of-liquids arrangements, we do not keep any amounts related to residue natural gas proceeds and only keep amounts related to the difference between the proceeds received and the amount remitted back to the producer related to NGLs and condensate. Certain of these arrangements may also result in our returning all or a portion of the producer’s share of residue natural gas and/or the NGLs to the producer, in lieu of returning sales proceeds. Additionally, these arrangements may include fee-based components. Our revenues under percent-of-proceeds arrangements relate directly with the price of natural gas, NGLs and condensate. Our revenues under percent-of-liquids arrangements relate directly with the price of NGLs and condensate.

Our trading and marketing of natural gas consists of physical purchases and sales, as well as derivative instruments.

We recognize revenues for sales and services under the four revenue recognition criteria, as follows:

 

•

Persuasive evidence of an arrangement exists — Our customary practice is to enter into a written contract.

 

•

Delivery — Delivery is deemed to have occurred at the time custody is transferred, or in the case of fee-based arrangements, when the services are rendered. To the extent we retain product as inventory, delivery occurs when the inventory is subsequently sold and custody is transferred to the third party purchaser.

 

•

The fee is fixed or determinable — We negotiate the fee for our services at the outset of our fee-based arrangements. In these arrangements, the fees are nonrefundable. For other arrangements, the amount of revenue, based on contractual terms, is determinable when the sale of the applicable product has been completed upon delivery and transfer of custody.

 

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Collectability is reasonably assured — Collectability is evaluated on a customer-by-customer basis. New and existing customers are subject to a credit review process, which evaluates the customers’ financial position (for example, credit metrics, liquidity and credit rating) and their ability to pay. If collectability is not considered reasonably assured at the outset of an arrangement in accordance with our credit review process, revenue is not recognized until the cash is collected.

We generally report revenues gross in the combined statements of operations, as we typically act as the principal in these transactions, take custody of the product, and incur the risks and rewards of ownership. New or amended contracts for certain sales and purchases of inventory with the same counterparty, when entered into in contemplation of one another, are reported net as one transaction. We recognize revenues for non-trading commodity derivative activity net in the combined statements of operations as gains and losses from commodity derivative activity. These activities include mark-to-market gains and losses on energy trading contracts and the settlement of financial or physical energy trading contracts.

Quantities of natural gas or NGLs over-delivered or under-delivered related to imbalance agreements with customers, producers or pipelines are recorded monthly as accounts receivable or accounts payable using 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. Included in the combined balance sheets as accounts receivable—trade and accounts receivable—affiliates as of December 31, 2010 and December 31, 2009, were imbalances of $0.2 million and $0.1 million, respectively. Included in the combined balance sheets as accounts payable—trade as of December 31, 2010 and December 31, 2009, were imbalances of $0.2 million and $0.2 million, respectively.

 

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THE SOUTHEAST TEXAS MIDSTREAM BUSINESS

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

 

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 assessments and/or clean-ups are probable and the costs can be reasonably estimated.

Allowance for Doubtful Accounts — Management estimates the amount of required allowances for the potential non-collectability of accounts receivable generally based upon the number of days past due, past collection experience and consideration of other relevant factors. However, past experience may not be indicative of future collections and therefore additional charges could be incurred in the future to reflect differences between estimated and actual collections.

Income Taxes — We are treated as a pass-through entity for federal income tax purposes, as such we do not directly pay federal income taxes. We are subject to the Texas margin tax, which is treated as an income tax. We follow the asset and liability method of accounting for income taxes. Under this method, 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. The Business is a member of a group. We have calculated current and deferred income taxes as if we were a separate tax payer.

3. Recent Accounting Pronouncements

Financial Accounting Standards Board, or FASB, Accounting Standards Update, or ASU, 2010-29 “Business Combinations (Topic 805): Disclosure of Supplementary Pro Forma Information for Business Combinations,” or ASU 2010-29 — In December 2010, the FASB issued ASU 2010-29 which amended Accounting Standards Codification, or ASC, Topic 805 “Business Combinations” to specify that if a public entity presents comparative financial statements, the entity should disclose revenue and earnings of the combined entity as though the business combination that occurred during the year had occurred as of the beginning of the comparable prior annual reporting period only. The ASU also expands the supplemental pro forma disclosures under Topic 805 to include a description of the nature and the amount of material, nonrecurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenue and earnings. ASU 2010-29 is effective for business combinations for which the acquisition date is on or after January 1, 2011 and we will disclose information in accordance with the ASU within all financial statements issued after the effective date.

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

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

ASU 2009-13 “Revenue Recognition (Topic 605) Multiple-Deliverable Revenue Arrangements,” or ASU 2009-13 — In October 2009, the FASB issued ASU 2009-13 which amended ASC Topic 605 “Revenue Recognition.” The ASU addresses the accounting for multiple-deliverable arrangements, to enable vendors to account for products or services separately rather than as a combined unit. ASU 2009-13 became effective for us on January 1, 2011 and there was no impact on our combined results of operations, cash flows and financial position as a result of adoption.

 

10

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THE SOUTHEAST TEXAS MIDSTREAM BUSINESS

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

 

4. Acquisitions

On June 29, 2010, we acquired the Raywood processing plant and Liberty gathering system, which are located in Liberty County, Texas, from Ceritas Holdings, LP, or Ceritas, for $78.8 million, subject to customary purchase price adjustments. We initially recorded a liability in other current liabilities of $3.1 million, which represented the fair value of the contingent consideration associated with anticipated recoveries of certain currently non-producing wells for a period of approximately one year. We reassessed the fair value of the contingent consideration and adjusted the fair value of the liability to $2.1 million. Accordingly, we recognized a gain of $1.0 million for the year ended December 31, 2010, within other operating income in the combined results of operations. This liability was settled subsequent to December 31, 2010 for an amount approximating our December 31, 2010 accrued balance to Ceritas. As of December 31, 2010, this liability is recorded in other current liabilities within the combined balance sheet. The acquired system will connect with our existing southeast Texas assets.

The purchase price allocation is as follows:

 

		(Millions)
Aggregate consideration		$	78.8
Property, plant and equipment		$	34.6
Intangible assets			34.9
Goodwill			11.9
Other current assets			3.5
Other current liabilities			(3.0	)
Contingent consideration			(3.1	)
Total preliminary purchase price allocation		$	78.8

Combined Financial Information

The following table presents unaudited pro forma information for the combined statements of operations for the years ended December 31, 2010 and 2009, as if the acquisition of the Raywood processing plant and Liberty gathering system had occurred at the beginning of each period presented. For the twelve months ended December 31, 2010, revenues of $32.5 million and net income of $2.1 million associated with the acquired assets, from the date of acquisition through December 31, 2010 have been included in the combined statements of operations.

 

		Year Ended December 31, 2010												Year Ended December 31, 2009
		The South East Texas Midstream Business				Acquisition of the Raywood Processing Plant and  the Liberty Gathering System				The South East Texas Midstream Business Pro Forma				The South East Texas Midstream Business				Acquisition of the Raywood Processing Plant and  the Liberty Gathering System				The South East Texas Midstream Business Pro Forma
		(Millions)
Total operating revenues		$	838.9			$	22.6			$	861.5			$	535.5			$	40.5			$	576.0
Net income		$	43.2			$	2.0			$	45.2			$	25.2			$	2.9			$	28.1

5. Agreements and Transactions with Affiliates

DCP Midstream, LLC

The employees supporting our operations are employees of Midstream. Costs incurred by Midstream on our behalf for salaries and benefits of operating personnel, as well as capital expenditures, maintenance and repair costs, and taxes have been directly allocated to us. Midstream also provides centralized corporate functions on our behalf, including legal, accounting, cash

 

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management, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, taxes and engineering. Midstream records the accrued liabilities and prepaid expenses for 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. Our share of those costs has been allocated based on Midstream’s proportionate investment (consisting of property, plant and equipment, intangibles, and investments in unconsolidated affiliates) compared to our investment. In management’s estimation, the allocation methodologies used are reasonable and result in an allocation to us of our costs of doing business borne by Midstream.

Midstream has issued parental guarantees in favor of certain counterparties. A portion of these parental guarantees relate to assets included in these combined financial statements.

We participate in Midstream’s cash management program. As a result, prior to December 31, 2010, we had no cash balances on the combined balance sheets and all of our cash management activity was performed by Midstream on our behalf, including collection of receivables, payment of payables, and the settlement of sales and purchases transactions with Midstream, which were recorded as parent advances and are included in net parent equity on the accompanying combined balance sheets.

We currently, and anticipate to continue to, purchase and sell to Midstream in the ordinary course of business. Midstream was a significant customer during the years ended December 31, 2010, 2009 and 2008.

ConocoPhillips

We currently, and anticipate to continue to, sell to ConocoPhillips in the ordinary course of business. ConocoPhillips was a significant customer during the years ended December 31, 2010, 2009 and 2008.

 

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Summary of Transactions with Affiliates

The following table summarizes our transactions with related parties and affiliates:

 

		Year Ended December 31,
		2010				2009				2008
		(Millions)
DCP Midstream, LLC:
Sales of natural gas, NGLs and condensate		$	358.4			$	216.5			$	313.6
Purchases of natural gas and NGLs		$	0.8			$	0.4			$	9.7
Losses from commodity derivative activity, net		$	(0.7	)		$	(0.1	)		$	(0.2	)
General and administrative expense		$	12.1			$	10.8			$	10.6
ConocoPhillips:
Sales of natural gas, NGLs and condensate		$	37.3			$	25.1			$	96.9
Transportation, processing and other		$	1.8			$	—			$	—
Purchases of natural gas and NGLs		$	—			$	0.1			$	5.8
(Losses) gains on derivative activity, net		$	(0.4	)		$	0.7			$	0.3
Spectra Energy:
Sales of natural gas, NGLs and condensate		$	—			$	0.3			$	—
Purchases of natural gas and NGLs		$	—			$	0.1			$	0.4
Operating and maintenance expense (a)		$	(0.3	)		$	0.2			$	—
Other:
Purchases of natural gas and NGLs		$	—			$	—			$	0.3
Operating and maintenance expense (b)		$	—			$	(0.2	)		$	—

 

(a)	Relates to insurance reimbursements received for hurricane Rita.

(b)	Balance for the year ended December 31, 2009 includes hurricane insurance recovery receivables, which were treated as a reduction to operating expense in the accompanying combined statements of operations.

We had balances with affiliates as follows:

 

		December 31, 2010				December 31, 2009
		(Millions)
DCP Midstream, LLC:
Accounts Receivable		$	38.6			$	—
ConocoPhillips:
Accounts receivable		$	6.3			$	1.5
Unrealized gains on derivative instruments — current		$	0.1			$	0.4
Unrealized gains on derivative instruments — long-term		$	(0.3	)		$	—
Spectra Energy:
Accounts receivable		$	0.3			$	—

 

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6. Property, Plant and Equipment

Property, plant and equipment by classification is as follows:

 

		Depreciable Life				December 31, 2010				December 31, 2009
						(Millions)
Gathering and transmission systems			15 — 30 Years			$	175.8			$	162.8
Processing and storage facilities			0 — 50 Years				221.4				168.6
Other			3 — 30 Years				2.3				2.8
Construction work in progress							24.2				20.0
Property, plant and equipment							423.7				354.2
Accumulated depreciation							(142.2	)			(129.0	)
Property, plant and equipment, net						$	281.5			$	225.2

The above amounts include accrued capital expenditures of $9.5 million and $0.3 million for the years ended December 31, 2010 and 2009, respectively. There was no interest capitalized on construction projects for the years ended December 31, 2010, 2009 and 2008.

Depreciation expense was $13.2 million, $12.0 million and $11.8 million for the years ended December 31, 2010, 2009 and 2008, respectively.

Asset Retirement Obligations — Asset retirement obligations, included in other long-term liabilities in the combined balance sheets, are $0.9 million at December 31, 2010 and $0.8 million at December 31, 2009. Accretion expense for the years ended December 31, 2010 and 2009 was $0.1 million for both periods. During the year ended December 31, 2008, we purchased a parcel of land which was previously leased. This transaction resulted in relieving the associated ARO and recognizing a $0.1 million benefit to accretion expense.

We identified various assets as having an indeterminate life, for which there is no requirement to establish a fair value for future retirement obligations associated with such assets. These assets include certain pipelines, gathering systems and processing facilities. A liability for these asset retirement obligations will be recorded only if and when a future retirement obligation with a determinable life is identified. These assets have an indeterminate life because they are owned and will operate for an indeterminate future period when properly maintained. Additionally, if the portion of an owned plant containing asbestos were to be modified or dismantled, we would be legally required to remove the asbestos. We currently have no plans to take actions that would require the removal of the asbestos in these assets. Accordingly, the fair value of the asset retirement obligation related to this asbestos cannot be estimated and no obligation has been recorded.

7. Goodwill and Intangible Assets

At December 31, 2010, we had goodwill of $11.9 million as a result of the amount that we recognized in connection with our acquisition of the Raywood processing plant and Liberty gathering system from Ceritas on June 29, 2010.

 

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Intangible assets consist primarily of customer contracts, and are as a result of our acquisition of the Raywood processing plant and Liberty gathering system from Ceritas on June 29, 2010. The gross carrying amount and accumulated amortization of these intangible assets are included in the accompanying consolidated balance sheets as intangible assets, net, and are as follows:

 

		December 31, 2010
		(Millions)
Gross carrying amount		$	34.9
Amortization charge			(1.2	)
Intangible assets, net		$	33.7

Estimated amortization for these intangibles is as follows as of December 31, 2010:

Estimated Amortization

(Millions)

 

2011		$	2.3
2012			2.3
2013			2.3
2014			2.3
2015			2.3
Thereafter			22.2
Total		$	33.7

As of December 31, 2010, the remaining amortization period was 14.5 years.

8. Fair Value Measurement

Determination of Fair Value

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

 

•

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

 

•

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

 

•

Liquidity valuation adjustments are necessary when we are not able to observe a recent market price for financial instruments that trade in less active markets for the fair value to reflect the cost of exiting the position. Exchange traded contracts are valued at market value without making any additional valuation adjustments and, therefore, no liquidity

 

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reserve is applied. For contracts other than exchange traded instruments, we mark our positions to the midpoint of the bid/ask spread, and record a liquidity reserve based upon our total net position. We believe that such practice results in the most reliable fair value measurement as viewed by a market participant.

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

The methods described above may produce a fair value calculation that may not be indicative of net realizable value or reflective of future fair values. While we believe that our valuation methods are appropriate and consistent with other market participants, we recognize that the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different estimate of fair value at the reporting date. We review our fair value policies on a regular basis taking into consideration changes in the marketplace and, if necessary, will adjust our policies accordingly. See Note 9 Risk Management and Hedging Activities.

Valuation Hierarchy

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

 

•

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

 

•

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

 

•

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

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

Commodity Derivative Assets and Liabilities

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

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

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

 

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Nonfinancial Assets and Liabilities

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

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

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

 

		December 31, 2010																December 31, 2009
		Level 1				Level 2				Level 3				Total Carrying Value				Level 1				Level 2				Level 3				Total Carrying Value
		(Millions)
Current assets:
Commodity derivatives (a)		$	—			$	12.6			$	—			$	12.6			$	—			$	34.6			$	0.8			$	35.4
Long-term assets:
Commodity derivatives (b)		$	—			$	0.5			$	—			$	0.5			$	—			$	4.2			$	0.5			$	4.7
Current liabilities :
Commodity derivatives (c)		$	—			$	(13.6	)		$	—			$	(13.6	)		$	—			$	(31.1	)		$	(0.8	)		$	(31.9	)
Acquisition related contingent consideration (d)		$	—			$	—			$	(2.1	)		$	(2.1	)		$	—			$	—			$	—			$	—
Long-term liabilities (e):
Commodity derivatives		$	—			$	(0.2	)		$	—			$	(0.2	)		$	—			$	(4.2	)		$	(0.3	)		$	(4.5	)

 

(a)	Included in current unrealized gains on derivative instruments in our combined balance sheets.

(b)	Included in long-term unrealized gains on derivative instruments in our combined balance sheets.

(c)	Included in current unrealized losses on derivative instruments in our combined balance sheets.

(d)	Included in other current liabilities in our combined balance sheets.

(e)	Included in long-term unrealized losses on derivative instruments in our combined balance sheets.

Changes in Level 3 Fair Value Measurements

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

 

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

 

		Commodity Derivative Instruments
		Current Assets				Long-Term Assets				Current Liabilities				Long-Term Liabilities
		(Millions)
Year ended December 31, 2010:
Beginning balance		$	0.8			$	0.5			$	(0.8	)		$	(0.3	)
Net realized and unrealized gains (losses) included in earnings			0.1				(0.5	)			—				0.3
Transfers into Level 3 (a)			—				—				—				—
Transfers out of Level 3 (a)			(0.5	)			—				0.3				—
Purchases, issuances and settlements, net			(0.4	)			—				0.5				—
Ending balance		$	—			$	—			$	—			$	—
Net unrealized gains (losses) still held included in earnings (b)		$	—			$	—			$	—			$	—
Year ended December 31, 2009:
Beginning balance		$	0.2			$	—			$	—			$	—
Net realized and unrealized gains included in earnings			1.0				0.5				(0.8	)			(0.3	)
Net transfers in (out) of Level 3 (c)			—				—				—				—
Purchases, issuances and settlements, net			(0.4	)			—				—				—
Ending balance		$	0.8			$	0.5			$	(0.8	)		$	(0.3	)
Net unrealized gains (losses) still held included in earnings (b)		$	0.9			$	0.5			$	(0.8	)		$	(0.3	)

 

(a)	Amounts transferred in and amounts transferred out are reflected at fair value as of the end of the period.

(b)	Represents the amount of total gains or losses for the period, included in gains or losses from commodity derivative activity, net, attributable to change in unrealized gains or losses relating to assets and liabilities classified as Level 3 that are still held as of December 31, 2010 and 2009.

(c)	Amounts transferred in are reflected at the fair value as of the beginning of the period and amounts transferred out are reflected at the fair value at the end of the period.

During 2010, we recognized the fair value of our contingent consideration, which is classified as Level 3, in relation to our acquisition of the Raywood processing plant and Liberty gathering system, of approximately $3.1 million, which we recorded to other current liabilities in our combined balance sheets. During the year ended December 31, 2010, we reassessed the fair value of the contingent consideration and adjusted the fair value of the liability to $2.1 million. Accordingly we recognized $1.0 million in other income in our combined statements of operations during the year ended December 31, 2010.

 

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During the year ended December 31, 2010, we had the following transfers into and out of Levels 1, 2 and 3. To qualify as a transfer, the asset or liability must have existed in the previous reporting period and moved into a different level during the current period.

 

		Year Ended December 31, 2010
		Transfers from Level 1  to Level 2				Transfers from Level 2  to Level 1				Transfers from Level 2  to Level 3				Transfers from Level 3  to Level 2 (a)
		(Millions)
Current assets		$	—			$	—			$	—			$	0.5
Current liabilities		$	—			$	—			$	—			$	(0.3	)

 

(a)	Financial instruments have moved into a lower level due to the passage of time. The inputs now include quoted prices for similar assets and liabilities in active markets and inputs that are observable for the asset or liability, either directly or indirectly.

Estimated Fair Value of Financial Instruments

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

The fair value of accounts receivable and accounts payable are not materially different from their carrying amounts because of the short-term nature of these instruments. Unrealized gains and unrealized losses on derivative instruments are carried at fair value.

9. Risk Management and Hedging Activities

Our day to day operations expose us to a variety of risks including but not limited to changes in the prices of commodities that we buy or sell and the creditworthiness of each of our counterparties. We manage certain of these exposures with both physical and financial transactions. All of our derivative activities are conducted under the governance of Midstream’s internal Risk Management Committees that establish policies, limiting exposure to market risk and requiring daily reporting to management of potential financial exposure. These policies include statistical risk tolerance limits using historical price movements to calculate daily value at risk. The following briefly describes each of the risks that we manage.

Commodity Price Risk

Our natural gas asset based trading and marketing activities engage in the business of trading energy related products and services, including managing purchase and sales portfolios, storage contracts and facilities, and transportation commitments for products. These energy trading operations are exposed to market variables and commodity price risk with respect to these products and services, and we may enter into physical contracts and financial instruments with the objective of realizing a positive margin from the purchase and sale of commodity-based instruments. We manage commodity price risk related to owned natural gas storage and pipeline assets by engaging in natural gas asset based trading and marketing. The commercial activities related to our natural gas asset based trading and marketing primarily consist of time spreads and basis spreads.

We may execute a time spread transaction when the difference between the current price of natural gas (cash or futures) and the futures market price for natural gas exceeds our cost of storing physical gas in our owned and/or leased storage facilities. The time spread transaction allows us to lock in a margin when this market condition exists. A time spread transaction is executed by establishing a long gas position at one point in time and establishing a corresponding short gas position at a different point in time. We typically use swaps to execute these transactions, which are not designated as hedging instruments and are recorded at fair value with changes in fair value recorded in the current period combined statement of operations. While gas held in our storage location is recorded at the lower of average cost or market, the derivative instruments that are used to manage our storage facility are recorded at fair value and any changes in fair value are currently recorded in our combined statements of operations. Even though we may have economically hedged our exposure and locked in a future margin the use of lower-of-cost-or-market accounting for our physical inventory and the use of mark-to-market accounting for our derivative instruments may subject our earnings to market volatility.

 

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We may execute basis spread transactions when the market price differential between locations on a pipeline asset exceeds our cost of transporting physical gas through our owned and/or leased pipeline asset. When this market condition exists, we may execute derivative instruments around this differential at the market price. This basis spread transaction allows us to lock in a margin on our physical purchases and sales of gas. We typically use swaps to execute these transactions, which are not designated as hedging instruments and are recorded at fair value with changes in fair value recorded in the current period combined statements of operations. As discussed above, the accounting for physical gas purchases and sales and the accounting for the derivative instruments used to manage such purchases and sales differ, and may subject our earnings to market volatility, even though the transaction represents an economic hedge in which we have locked in a future margin.

Additionally, in order for our storage facility to remain operational, we maintain a minimum level of base gas in our storage cavern, which is capitalized on our combined balance sheets as a component of property, plant and equipment, net. In the fourth quarter of 2008 we commenced a capacity expansion project for one of our storage caverns, which required us to sell all of the base gas within the cavern. During 2009, the expansion project was completed and base gas was repurchased to restore our storage cavern to operation. To mitigate the risk associated with the forecasted re-purchase of base gas, we executed a series of derivative financial instruments, which were designated as cash flow hedges. The cash paid upon settlement of these hedges economically offsets the cash paid to purchase the base gas. A deferred loss of $2.7 million was recognized and will remain in AOCI until such time that our cavern is emptied and the base gas is sold.

Contingent Credit Features

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

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

 

•

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

 

•

Additionally, in some cases, our ISDA contracts contain cross-default provisions that could constitute a credit-risk related contingent feature. These provisions apply if we default in making timely payments under those agreements and the amount of the default is above certain predefined thresholds, which are significantly high. As of December 31, 2010, we are not a party to any agreements that would be subject to these provisions.

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

Depending upon the movement of commodity prices, each of our individual contracts with counterparties to our commodity derivative instruments are in either a net asset or net liability position. As of December 31, 2010, we had $1.0 million of individual commodity derivative contracts that contain credit-risk related contingent features that were in a net liability position, and have not posted any cash collateral relative to such positions. If a credit-risk related event were to occur and we were required to net settle our position with an individual counterparty, our ISDA contracts permit us to net all outstanding contracts with that counterparty, whether in a net asset or net liability position, as well as any cash collateral already posted. As of December 31, 2010, if a credit-risk related event were to occur we may be required to post additional collateral. Additionally, although our commodity derivative contracts that contain credit-risk related contingent features were in a net liability position as of December 31, 2010, if a credit-risk related event were to occur, the net liability position would be partially offset by contracts in a net asset position reducing our net liability to $0.9 million.

 

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THE SOUTHEAST TEXAS MIDSTREAM BUSINESS

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

 

Summarized Derivative Information

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

 

		December 31, 2010				December 31, 2009
		(Millions)
Commodity cash flow hedges:
Net deferred losses in AOCI		$	(2.7	)		$	(2.7	)
Total AOCI		$	(2.7	)		$	(2.7	)

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

 

		December 31,										December 31,
Balance Sheet Line Item		2010				2009				Balance Sheet Line Item		2010				2009
		(Millions)										(Millions)
Derivative Assets Designated as Hedging Instruments:										Derivative Liabilities Designated as Hedging Instruments:
Commodity derivatives:										Commodity derivatives:
Unrealized gains on derivative instruments – current		$	—			$	0.6			Unrealized losses on derivative instruments – current		$	—			$	(3.1	)
Unrealized gains on derivative instruments – long-term			—				—			Unrealized losses on derivative instruments – long-term			—				—
		$	—			$	0.6					$	—			$	(3.1	)
Derivative Assets Not Designated as Hedging Instruments:										Derivative Liabilities Not Designated as Hedging Instruments:
Commodity derivatives:										Commodity derivatives:
Unrealized gains on derivative instruments – current		$	12.6			$	34.8			Unrealized losses on derivative instruments – current		$	(13.6	)		$	(28.8	)
Unrealized gains on derivative instruments – long-term			0.5				4.7			Unrealized losses on derivative instruments – long-term			(0.2	)			(4.5	)
		$	13.1			$	39.5					$	(13.8	)		$	(33.3	)

 

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THE SOUTHEAST TEXAS MIDSTREAM BUSINESS

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

 

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

 

		Loss Recognized in AOCI on Derivatives — Effective  Portion								Gain (Loss) Recognized in Income on Derivatives — Ineffective  Portion and Amount Excluded From Effectiveness Testing								Deferred Losses in AOCI Expected to be Reclassified  into Earnings Over the 12 Months
		Year Ended December 31,
		2010				2009				2010				2009
		(Millions)								(Millions)								(Millions)
Commodity derivatives		$	—			$	(2.0	)		$	—			$	—	(a)		$	—

 

(a)	For the years ended December 31, 2010 and 2009, no derivative gains or losses were reclassified from AOCI to current period earnings as a result of the discontinuance of cash flow hedges related to certain forecasted transactions that are not probable of occurring.

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

 

Commodity Derivatives: Statements of Operations Line Item		Year Ended December 31,
		2010				2009				2008
		(Millions)
Third party:
Realized		$	18.8			$	9.5			$	11.8
Unrealized			(6.3	)			(0.6	)			1.0
Gains from commodity derivative activity, net		$	12.5			$	8.9			$	12.8
Affiliates:
Realized		$	(0.5	)		$	0.2			$	(0.3	)
Unrealized			(0.6	)			0.4				0.4
(Losses) gains from commodity derivative activity, net — affiliates		$	(1.1	)		$	0.6			$	0.1

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

 

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THE SOUTHEAST TEXAS MIDSTREAM BUSINESS

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

 

The following tables represent, by commodity type, our net long or short positions that are expected to partially or entirely settle in each respective year. To the extent that we have long dated derivative positions that span multiple calendar years, the contract will appear in more than one line item in the table below. Additionally, relative to the hedging of certain of our storage and/or transportation assets, we may execute basis transactions for natural gas, which may result in a net long/ short position of zero. This table also presents our net long or short natural gas basis swap positions separately from our net long or short natural gas positions.

 

		December 31, 2010
		Natural Gas				Natural Gas Basis Swaps
Year of Expiration		Net Long (Short) Position (MMBtu)				Net Long (Short) Position (MMBtu)
2011			(7,272,500	)			6,025,000
2012			—				8,220,000

 

		December 31, 2009
		Natural Gas				Natural Gas Basis Swaps
Year of Expiration		Net Long (Short) Position (MMBtu)				Net Long (Short) Position (MMBtu)
2010			(16,552,500	)			(8,670,000	)
2011			(3,650,000	)			1,460,000

10. Income Taxes

The State of Texas imposes a margin tax that is assessed at 1% of taxable margin apportioned to Texas. Accordingly, we have recorded current tax expense for the Texas margin tax beginning in 2007.

Income tax expense consists of the following:

 

		Year Ended December 31,
		2010				2009				2008
		(Millions)
Current:
State		$	(0.7	)		$	(0.5	)		$	(0.6	)
Deferred:
State			(0.5	)			0.1				(0.1	)
Total income tax expense		$	(1.2	)		$	(0.4	)		$	(0.7	)

We had net long-term deferred tax liabilities of $2.5 million, $2.0 million, and $2.1 million as of December 31, 2010, 2009 and 2008, respectively. The net long-term deferred tax liabilities are included in other long-term liabilities on the combined balance sheets and are primarily associated with depreciation and amortization related to property.

Our effective tax rate differs from statutory rates primarily due to us being treated as a pass-through entity for federal income tax purposes, while being treated as a taxable entity in Texas.

 

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THE SOUTHEAST TEXAS MIDSTREAM BUSINESS

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

 

11. Commitments and Contingent Liabilities

Litigation — We are not party to any significant legal proceedings, but are a party to various administrative and regulatory proceedings and commercial disputes that have arisen in the ordinary course of our business. Management currently believes that the ultimate resolution of 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 on our combined results of operations, financial position, or cash flows.

General Insurance — Midstream’s insurance coverage is carried with an affiliate of ConocoPhillips, an affiliate of Spectra Energy and third-party insurers. Midstream’s insurance coverage includes: (1) general liability insurance covering third-party exposures; (2) statutory workers’ compensation insurance; (3) automobile liability insurance for all owned, non-owned and hired vehicles; (4) excess liability insurance above the established primary limits for general liability and automobile liability insurance; (5) property insurance, which covers the replacement value of real and personal property and includes business interruption/extra expense; and (6) directors and officers insurance covering Midstream’s directors and officers for acts related to Midstream’s business activities. All coverage is subject to certain limits and deductibles, the terms and conditions of which are common for companies with similar types of operations.

A portion of the insurance costs described above are allocated by Midstream to us through the allocation methodology described in Note 5.

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, we 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 storage, management, transportation and disposal, and other environmental matters including recently adopted EPA regulations related to reporting of greenhouse gas emissions which became effective in January 2010. 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, the issuance of injunctions or restrictions on operations. Management believes that, based on currently known information, compliance with these laws and regulations will not have a material adverse effect on our combined results of operations, financial position or cash flows.

As of December 31, 2010 and December 31, 2009, we had no environmental liabilities in our combined balance sheets.

12. Supplemental Cash Flow Information

 

		Year Ended December 31,
		2010				2009				2008
		(Millions)
Cash paid for income taxes, net of income tax refunds		$	0.4			$	0.7			$	0.7
Non-cash investing and financing activities:
Other non-cash additions of property, plant and equipment		$	10.1			$	0.3			$	2.8
Acquisition related contingent consideration		$	2.1			$	—			$	—

 

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THE SOUTHEAST TEXAS MIDSTREAM BUSINESS

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

 

13. Subsequent Events

We have evaluated subsequent events occurring through June 17, 2011.

As of December 31, 2010 the fair value of the contingent consideration accrued on our balance sheet was $2.1 million. This liability was retained by DCP Midstream upon the formation of the joint venture on January 1, 2011. On March 4, 2011, DCP Midstream paid an amount approximating our December 31, 2010 accrued balance to Ceritas to settle the contingent consideration.

 

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