exv99w3

Exhibit 99.3

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Management Committee of

Discovery Producer Services LLC

We have audited the accompanying consolidated balance sheets of Discovery Producer Services LLC as of December 31, 2006 and 2005, and the related consolidated statements of income, members’ capital, and cash flows for each of the three years in the period ended December 31, 2006. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements 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. We were not engaged to perform an audit of the Company’s 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, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Discovery Producer Services LLC at December 31, 2006 and 2005, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2006, in conformity with U.S. generally accepted accounting principles.

/s/ Ernst & Young LLP

Tulsa, Oklahoma

March 5, 2007

DISCOVERY PRODUCER SERVICES LLC

CONSOLIDATED BALANCE SHEETS


	December 31,				September 30,
	2005		2006		2007
	(In thousands)
					(Unaudited)

ASSETS
Current assets:
Cash and cash equivalents	$	21,378	$	37,583	$	28,444
Accounts receivable:
Affiliate		31,448		11,986		14,975
Other		13,975		6,838		7,013
Insurance receivable		476		12,623		6,036
Inventory		924		576		479
Other current assets		2,324		4,235		4,101

Total current assets		70,525		73,841		61,048
Restricted cash		44,559		28,773		6,117
Property, plant and equipment, net		344,743		355,304		378,552

Total assets	$	459,827	$	457,918	$	445,717


LIABILITIES AND MEMBERS’ CAPITAL
Current liabilities:
Accounts payable:
Affiliate	$	12,970	$	7,017	$	10,931
Other		23,160		23,618		11,709
Accrued liabilities		6,205		5,119		5,173
Other current liabilities		2,735		4,805		5,353

Total current liabilities		45,070		40,559		33,166
Noncurrent accrued liabilities		1,121		3,728		13,993
Commitments and contingent liabilities (Note 7)
Members’ capital		413,636		413,631		398,558

Total liabilities and members’ capital	$	459,827	$	457,918	$	445,717

See accompanying notes to consolidated financial statements.

DISCOVERY PRODUCER SERVICES LLC

CONSOLIDATED STATEMENTS OF INCOME


	Year Ended December 31,									Nine Months Ended September 30,
	2004			2005			2006			2006			2007
	(In thousands)
										(Unaudited)

Revenues:
Product sales:
Affiliate	$	57,838		$	70,848		$	148,385		$	102,395		$	141,667
Third-party		1,611			4,271			—			—			5,251
Gas and condensate transportation services:
Affiliate		3,966			2,104			3,835			3,703			803
Third-party		12,052			13,302			14,668			11,004			11,354
Gathering and processing services:
Affiliate		6,962			3,912			8,605			7,894			2,527
Third-party		14,168			25,806			19,473			15,387			13,737
Other revenues		3,279			2,502			2,347			2,071			756

Total revenues		99,876			122,745			197,313			142,454			176,095

Costs and expenses:
Product cost and shrink replacement:
Affiliate		423			19,103			66,890			49,593			66,442
Third-party		44,932			45,364			52,662			34,716			41,503
Operating and maintenance expenses:
Affiliate		3,098			3,739			5,276			3,198			4,001
Third-party		14,756			6,426			17,773			10,721			17,264
Depreciation and accretion		22,795			24,794			25,562			19,133			19,234
General and administrative expenses — affiliate		1,424			2,053			2,150			1,606			1,702
Taxes other than income		1,382			1,151			1,114			800			997
Other — net		(54	)		(33	)		283			292			(12	)
Loss on the sale of property, plant and equipment		—			—			—			—			603

Total costs and expenses		88,756			102,597			171,710			120,059			151,734

Operating income		11,120			20,148			25,603			22,395			24,361
Interest income		(550	)		(1,685	)		(2,404	)		(1,835	)		(1,472	)
Foreign exchange loss (gain)		—			1,005			(2,076	)		(1,228	)		(346	)

Income before cumulative effect of change in accounting principle		11,670			20,828			30,083			25,458			26,179
Cumulative effect of change in accounting principle		—			(176	)		—			—			—

Net income	$	11,670		$	20,652		$	30,083		$	25,458		$	26,179

See accompanying notes to consolidated financial statements.

DISCOVERY PRODUCER SERVICES LLC

CONSOLIDATED STATEMENT OF MEMBERS’ CAPITAL


				Williams						Eni
	Williams			Partners			DCP			BB
	Energy,			Operating			Midstream,			Pipeline,
	L.L.C.			LLC			LLC			LLC			Total
	(In thousands)

Balance, December 31, 2003	$	189,987		$	—		$	126,650		$	63,338		$	379,975
Net income — 2004		5,835			—			3,890			1,945			11,670

Balance, December 31, 2004		195,822			—			130,540			65,283			391,645
Contributions		16,269			24,400			7,634			—			48,303
Distributions		(30,030	)		(1,280	)		(15,654	)		—			(46,964	)
Net income — 2005		8,063			4,651			6,909			1,029			20,652
Sale of Eni’s 16.67% interest to Williams Energy, L.L.C.		66,312			—			—			(66,312	)		—
Sale of Williams Energy, L.L.C.’s 40% interest to Williams Partners Operating LLC		(142,761	)		142,761			—			—			—
Sale of Williams Energy, L.L.C.’s 6.67% interest to DCP Midstream, LLC		(25,869	)		—			25,869			—			—

Balance, December 31, 2005		87,806			170,532			155,298			—			413,636
Contributions		800			1,600			11,109			—			13,509
Distributions		(10,797	)		(16,400	)		(16,400	)		—			(43,597	)
Net income		6,017			12,033			12,033			—			30,083

Balance, December 31, 2006		83,826			167,765			162,040			—			413,631
Contributions (unaudited)		—			—			3,920						3,920
Distributions (unaudited)		(7,235	)		(19,868	)		(18,069	)		—			(45,172	)
Sale of Williams Energy, L.L.C.’s 20% interest to Williams Partners Operating LLC. (unaudited)		(79,194	)		79,194			—			—			—
Net income — nine months ended September 30, 2007 (unaudited)		2,603			13,105			10,471			—			26,179

Balance, September 30, 2007 (unaudited)	$	—		$	240,196		$	158,362		$	—		$	398,558

See accompanying notes to consolidated financial statements.

DISCOVERY PRODUCER SERVICES LLC

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Year Ended December 31,									Nine Months Ended September 30,
	2004			2005			2006			2006			2007
	(In thousands)
										(Unaudited)

OPERATING ACTIVITIES:
Income before cumulative effect of change in accounting principle	$	11,670		$	20,652		$	30,083		$	25,458		$	26,179
Cumulative effect of change in accounting principle		—			176			—			—			—
Adjustments to reconcile to cash provided by operations:
Depreciation and accretion		22,795			24,794			25,562			19,133			19,234
Loss on the sale of property, plant and equipment		—			—			—			—			603
Cash provided (used) by changes in asset and liabilities:
Trade accounts receivable		( 1,658	)		(35,263	)		26,599			25,534			(3,164	)
Insurance receivable					(476	)		(12,147	)		(6,478	)		6,587
Inventory		(240	)		(84	)		348			(30	)		97
Other current assets		(1	)		(1,012	)		(1,911	)		(2,431	)		134
Accounts payable		1,256			29,355			(6,063	)		(19,872	)		(10,715	)
Other current liabilities		(668	)		664			2,070			(1,181	)		548
Accrued liabilities		2,469			(7,992	)		(1,086	)		(1,199	)		54

Net cash provided by operating activities		35,623			30,814			63,455			38,934			39,557

INVESTING ACTIVITIES:
Property, plant and equipment:
Capital expenditures		(46,701	)		(12,906	)		(33,516	)		(23,549	)		(33,469	)
Proceeds from sale of property, plant and equipment		—			—			—			—			649
Change in accounts payable — capital expenditures		7,586			(8,532	)		568			285			2,720
(Increase) decrease in restricted cash		—			(44,559	)		15,786			13,778			22,656

Net cash used by investing activities		(39,115	)		(65,997	)		(17,162	)		(9,486	)		(7,444	)

FINANCING ACTIVITIES:
Distributions to members		—			(46,964	)		(43,597	)		(32,598	)		(45,172	)
Capital contributions		—			48,303			13,509			8,989			3,920

Net cash provided (used) by financing activities		—			1,339			(30,088	)		(23,609	)		(41,252	)

Increase (decrease) in cash and cash equivalents		(3,492	)		(33,844	)		16,205			5,839			(9,139	)
Cash and cash equivalents at beginning of period		58,714			55,222			21,378			21,378			37,583

Cash and cash equivalents at end of period	$	55,222		$	21,378		$	37,583		$	27,217		$	28,444

See accompanying notes to consolidated financial statements.

DISCOVERY PRODUCER SERVICES LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Information as of September 30, 2007 and for the nine months ended
September 30, 2007 and 2006 is unaudited)


Note 1.	Organization and Description of Business

Our company consists of Discovery Producer Services LLC, or DPS, a Delaware limited liability company formed on June 24, 1996, and its wholly owned subsidiary, Discovery Gas Transmission LLC, or DGT, a Delaware limited liability company formed on June 24, 1996. DPS was formed for the purpose of constructing and operating a 600 million cubic feet per day, or MMcf/d, cryogenic natural gas processing plant near Larose, Louisiana and a 32,000 barrel per day, or bpd, natural gas liquids fractionator plant near Paradis, Louisiana. DGT was formed for the purpose of constructing and operating a natural gas pipeline from offshore deep water in the Gulf of Mexico to DPS’s gas processing plant in Larose, Louisiana. The pipeline has a design capacity of 600 MMcf/d and consists of approximately 173 miles of pipe. DPS has since connected several laterals to the DGT pipeline to expand its presence in the Gulf. Herein, DPS and DGT are collectively referred to in the first person as “we,” “us” or “our” and sometimes as “the Company”.

Until April 14, 2005, we were owned 50% by Williams Energy, L.L.C. (a wholly owned subsidiary of The Williams Companies, Inc.), 33.33% by DCP Midstream, LLC, or DCP Midstream, formerly Duke Energy Field Services, LLC, and 16.67% by Eni BB Pipeline, LLC, or Eni, Williams Energy, L.L.C. is our operator. Herein, The Williams Companies, Inc. and its subsidiaries are collectively referred to as “Williams.”

On April 14, 2005, Williams acquired the 16.67% ownership interest in us, which was previously held by Eni. As a result, we became 66.67% owned by Williams and 33.33% owned by DCP Midstream.

On August 22, 2005, we distributed cash of $44.0 million to the members based on 66.67% ownership by Williams and 33.33% ownership by DCP Midstream.

On August 23, 2005, Williams Partners Operating LLC (a wholly owned subsidiary of Williams Partners L.P., or WPZ), acquired a 40% interest in us, which was previously held by Williams. As a result, we became 40% owned by WPZ, 26.67% owned by Williams and 33.33% owned by DCP Midstream. In connection with this acquisition, Williams, DCP Midstream and WPZ amended our limited liability company agreement including provisions for (1) quarterly distributions of available cash, as defined in the amended agreement and (2) pursuit of capital projects for the benefit of one or more of our members when there is not unanimous consent.

On December 22, 2005, DCP Midstream acquired a 6.67% interest in us, which was previously held by Williams. As a result, we became 40% owned by WPZ, 20% owned by Williams and 40% owned by DCP Midstream.

On June 28, 2007, WPZ acquired an additional 20% interest in us from Williams. As a result, we became 60% owned by WPZ and 40% owned by DCP Midstream.


Note 2.	Summary of Significant Accounting Policies

Basis of Presentation. The consolidated financial statements have been prepared based upon accounting principles generally accepted in the United States and include the accounts of DPS and its wholly owned subsidiary, DGT. Intercompany accounts and transactions have been eliminated. The accompanying unaudited interim consolidated financial statements include all normal recurring adjustments that, in the opinion of management, are necessary to present fairly our financial position at September 30, 2007, and the results of operations and cash flows for the nine months ended September 30, 2006 and 2007.

Reclassifications. Certain prior years amounts have been reclassified to conform with the current year presentation. Certain revenues, expenses, and liabilities for the year ended December 31, 2006 have been reclassified as affiliate transactions due to the affiliate relationship with DCP Midstream. Capitalized labor and projects fees for 2006 were also reclassified.

DISCOVERY PRODUCER SERVICES LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Information as of September 30, 2007 and for the nine months ended
September 30, 2007 and 2006 is unaudited)

Use of Estimates. The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates.

Estimates and assumptions used in the calculation of asset retirement obligations are, in the opinion of management, significant to the underlying amounts included in the consolidated financial statements. It is reasonably possible that future events or information could change those estimates.

Cash and Cash Equivalents. Cash and cash equivalents include demand and time deposits, certificates of deposit and other marketable securities with maturities of three months or less when acquired.

Trade Accounts Receivable. Trade accounts receivable are carried on a gross basis, with no discounting, less an allowance for doubtful accounts. No allowance for doubtful accounts is recognized at the time the revenue that generates the accounts receivable is recognized. We estimate the allowance for doubtful accounts based on existing economic conditions, the financial condition of the customers, and the amount and age of past due accounts. Receivables are considered past due if full payment is not received by the contractual due date. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been exhausted. There was no allowance for doubtful accounts at December 31, 2006 and 2005.

Insurance Receivable. Expenditures incurred for the repair of the pipeline and onshore facilities damaged by Hurricane Katrina in 2005, which are probable of recovery when incurred, are recorded as insurance receivable. Expenditures up to the insurance deductible and amounts subsequently determined not to be recoverable are expensed.

Gas Imbalances. In the course of providing transportation services to customers, DGT may receive different quantities of gas from shippers than the quantities delivered on behalf of those shippers. This results in gas transportation imbalance receivables and payables which are recovered or repaid in cash, based on market-based prices, or through the receipt or delivery of gas in the future. Imbalance receivables and payables are included in Other current assets and Other current liabilities in the Consolidated Balance Sheets. Settlement of imbalances requires agreement between the pipelines and shippers as to allocations of volumes to specific transportation contracts and the timing of delivery of gas based on operational conditions. In accordance with its tariff, DGT is required to account for this imbalance (cash-out) liability/receivable and refund or invoice the excess or deficiency when the cumulative amount exceeds $400,000. To the extent that this difference, at any year end, is less than $400,000, such amount would carry forward and be included in the cumulative computation of the difference evaluated at the following year end.

Inventory. Inventory includes fractionated products at our Paradis facility and is carried at the lower of cost or market.

Restricted Cash. Restricted cash within non-current assets relates to escrow funds contributed by our members for the construction of the Tahiti pipeline lateral expansion. The restricted cash is classified as non-current because the funds will be used to construct a long-term asset. The restricted cash is primarily invested in short-term money market accounts with financial institutions.

Property, Plant, and Equipment. Property, plant, and equipment are carried at cost. We base the carrying value of these assets on estimates, assumptions and judgments relative to capitalized costs, useful lives and salvage values. The natural gas and natural gas liquids maintained in the pipeline facilities necessary for their operation (line fill) are included in property, plant, and equipment.

Depreciation of DPS’s facilities and equipment is computed primarily using the straight-line method with 25-year lives. Depreciation of DGT’s facilities and equipment is computed using the straight-line method with 15-year lives.

We record an asset and a liability equal to the present value of each expected future asset retirement obligation, or ARO. The ARO asset is depreciated in a manner consistent with the depreciation of the underlying physical asset. We measure changes in the liability due to passage of time by applying an interest method of allocation. This amount is recognized as an increase in the carrying amount of the liability and as a corresponding accretion expense included in operating income.

Revenue Recognition. Revenue for sales of products are recognized in the period of delivery and revenues from the gathering, transportation and processing of gas are recognized in the period the service is provided based on contractual terms and the related natural gas and liquid volumes. DGT is subject to Federal Energy Regulatory Commission, or FERC, regulations, and accordingly, certain revenues collected may be subject to possible refunds upon final orders in pending cases. DGT records rate refund liabilities considering regulatory proceedings by DGT and other third parties, advice of counsel, and estimated total exposure as discounted and risk weighted, as well as collection and other risks. There were no rate refund liabilities accrued at December 31, 2006 or 2005.

Impairment of Long-Lived Assets. We evaluate long-lived assets for impairment on an individual asset or asset group basis when events or changes in circumstances indicate that, in our management’s judgment, the carrying value of such assets may not be recoverable. When such a determination has been made, we compare our management’s estimate of undiscounted future cash flows attributable to the assets to the carrying value of the assets to determine whether the carrying value is recoverable. If the carrying value is not recoverable, we determine the amount of the impairment recognized in the financial statements by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value.

Accounting for Repair and Maintenance Costs. We expense the cost of maintenance and repairs as incurred. Expenditures that enhance the functionality or extend the useful lives of the assets are capitalized and depreciated over the remaining useful life of the asset.

Income Taxes. For federal tax purposes, we have elected to be treated as a partnership with each member being separately taxed on its ratable share of our taxable income. This election, to be treated as a pass-through entity, also applies to our wholly owned subsidiary, DGT. Therefore, no income taxes or deferred income taxes are reflected in the consolidated financial statements.

Foreign Currency Transactions. Transactions denominated in currencies other than the functional currency are recorded based on exchange rates at the time such transactions arise. Subsequent changes in exchange rates result in transaction gains or losses which are reflected in the Consolidated Statements of Income.

Recent Accounting Standards. In January 2006, Williams adopted Statement of Financial Accounting Standard, or SFAS, No. 123, “Share-Based Payment.” Accordingly payroll costs directly charged to us by Williams and general and administrative costs allocated to us by Williams include such compensation costs beginning January 1, 2006. The cost is charged to us through specific allocations of certain employees if they directly support our operations. Our adoption of this Statement did not have a material impact on our Consolidated Financial Statements.

In January 2006, we adopted SFAS No. 151, “Inventory Costs, an Amendment of ARB No. 43, Chapter 4.” The Statement amends Accounting Research Bulletin, or ARB, No. 43, Chapter 4, “Inventory

Pricing,” to clarify that abnormal amounts of certain costs should be recognized as current period charges and that the allocation of overhead costs should be based on the normal capacity of the production facility. Our adoption of this Statement did not have a material impact on our Consolidated Financial Statements.

In January 2006, we adopted SFAS No. 153, “Exchanges of Nonmonetary Assets, an amendment of APB Opinion No. 29.” The Statement amends APB Opinion No. 29, “Accounting for Nonmonetary Transactions.” The guidance in APB Opinion No. 29 is based on the principle that exchanges of nonmonetary assets should be measured based on the fair value of the assets exchanged but includes certain exceptions to that principle. SFAS No. 153 amends APB Opinion No. 29 to eliminate the exception for nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. A nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. The impact of this Statement on our Financial Statements was not material.

In September 2006, the Financial Accounting Standards Board, or FASB, issued SFAS No. 157, “Fair Value Measurements.” This Statement establishes a framework for fair value measurements in the financial statements by providing a single definition of fair value, provides guidance on the methods used to estimate fair value and increases disclosures about estimates of fair value. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007 and is generally applied prospectively. We will assess the impact of this Statement on our Consolidated Financial Statements.

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities — Including an Amendment of FASB Statement No. 115”. SFAS No. 159 establishes a fair value option permitting entities to elect the option to measure eligible financial instruments and certain other items at fair value on specified election dates. Unrealized gains and losses on items for which the fair value option has been elected will be reported in earnings. The fair value option may be applied on an instrument-by-instrument basis, with a few exceptions, is irrevocable and is applied only to entire instruments and not to portions of instruments. SFAS No. 159 is effective as of the beginning of the first fiscal year beginning after November 15, 2007 and should not be applied retrospectively to fiscal years beginning prior to the effective date, except as permitted for early adoption. We will not adopt SFAS No. 159 prior to January 1, 2008. On the adoption date, an entity may elect the fair value option for eligible items existing at that date and the adjustment for the initial remeasurement of those items to fair value should be reported as a cumulative effect adjustment to the opening balance of retained earnings. We continue to assess whether to apply the provisions of SFAS No. 159 to eligible financial instruments in place on the adoption date and the related impact on our Consolidated Financial Statements.


Note 3.	Related Party Transactions

We have no employees. Pipeline and plant operations are performed under operation and maintenance agreements with Williams. Under these agreements, we reimburse Williams for direct payroll and employee benefit costs incurred on our behalf. Most costs for materials, services and other charges are third-party charges and are invoiced directly to us. Additionally, we purchase a portion of the natural gas from Williams to meet our fuel and shrink requirements at our processing plant. These purchases are made at market rates at the time of purchase. These costs are included in Operating and maintenance expenses — affiliate and Product costs and shrink replacement — affiliate on the Consolidated Statements of Income. Also included in our Operating and maintenance expenses — affiliate is rental expense resulting from a 10 year leasing agreement for pipeline capacity from Texas Eastern Transmission, LP (DCP Midstream’s affiliate), as part of our Market Expansion project which began in June 2005.

We pay Williams a monthly operation and management fee to cover the cost of accounting services, computer systems and management services provided to us. This fee is presented as General and administrative expenses — affiliate on the Consolidated Statements of Income.

We also pay Williams a project management fee to cover the cost of managing capital projects. This fee is determined on a project by project basis and is capitalized as part of the construction costs. A summary of the payroll costs and project fees charged to us by Williams and capitalized are as follows:


	For the Nine Months Ended September 30,				Years Ended December 31,
	2007		2006		2006		2005		2004
					(In thousands)

Capitalized labor	$	186	$	270	$	373	$	115	$	288
Capitalized project fee		697		389		538		351		854

	$	883	$	659	$	911	$	466	$	1,142

We have various business transactions with our members and other subsidiaries and affiliates of our members. We sell the NGLs to which we take title and excess gas to Williams. Revenues associated with these activities are reflected as Product sales — affiliate on the Consolidated Statements of Income. These transactions are conducted at current market prices for the products. In 2006, we had transactions with DCP Midstream’s affiliate, Texas Eastern Corporation. During 2005, we had transactions with DCP Midstream’s affiliates, Texas Eastern Corporation and ConocoPhillips Company. These transactions primarily included processing and sales of natural gas liquids and transportation of gas and condensate. We have business transactions with Eni that primarily include processing and transportation of gas and condensate. The following table summarizes these related-party revenues during 2006, 2005 and 2004.


	Years Ended December 31,
	2006		2005		2004
	(In thousands)

Williams	$	148,543	$	70,848	$	57,838
Texas Eastern Corporation		12,282		2,663		—
Eni*		—		2,830		10,928
ConocoPhillips		—		523		—

Total	$	160,825	$	76,864	$	68,766


*		Through April 14, 2005


Note 4.	Property, Plant, and Equipment

Property, plant, and equipment consisted of the following at December 31, 2006 and 2005:


	Years Ended December 31,
	2006		2005
	(In thousands)

Property, plant, and equipment:
Construction work in progress	$	37,259	$	5,444
Buildings		4,434		4,406
Land and land rights		2,491		1,530
Transportation lines		303,283		302,252
Plant and other equipment		200,990		198,837

Total property, plant, and equipment		548,457		512,469
Less accumulated depreciation		193,153		167,726

Net property, plant, and equipment	$	355,304	$	344,743

Commitments for construction and acquisition of property, plant, and equipment for the Tahiti pipeline lateral expansion are approximately $33.3 million at December 31, 2006.

Effective December 31, 2005, we adopted Financial Accounting Standards Board Interpretation, or FIN, No. 47, “Accounting for Conditional Asset Retirement Obligations.” This Interpretation clarifies that an entity is required to recognize a liability for the fair value of a conditional ARO when incurred if the liability’s fair value can be reasonably estimated. The Interpretation clarifies when an entity would have sufficient information to reasonably estimate the fair value of an ARO. As required by the new standard, we reassessed the estimated remaining life of all our assets with a conditional ARO. We recorded additional liabilities totaling $327,000 equal to the present value of expected future asset retirement obligations at December 31, 2005. The liabilities are slightly offset by a $151,000 increase in property, plant, and equipment, net of accumulated depreciation, recorded as if the provisions of the Interpretation had been in effect at the date the obligation was incurred. The net $176,000 reduction to earnings is reflected as a cumulative effect of a change in accounting principle for the year ended 2005. If the Interpretation had been in effect at the beginning of 2004, the impact to our income from continuing operations and net income would have been immaterial.

Our obligations relate primarily to our offshore platform and pipelines and our onshore processing and fractionation facilities. At the end of the useful life of each respective asset, we are legally or contractually obligated to dismantle the offshore platform, properly abandon the offshore pipelines, remove the onshore facilities and related surface equipment and restore the surface of the property.

A rollforward of our asset retirement obligation for 2006 and 2005 is presented below.


	Years Ended December 31,
	2006		2005
	(In thousands)

Balance at January 1	$	1,121	$	702
Accretion expense		135		92
Estimate revisions		2,472		—
FIN No. 47 revisions		—		327

Balance at December 31	$	3,728	$	1,121

During the third quarter of 2007, we began our annual update of assumptions used in the calculation of our asset retirement obligations. As expected, changes to these assumptions significantly increased the recorded asset retirement obligation by an additional $10.3 million, primarily due to an increase in our cost estimates following recent retirements which indicated that actual retirement costs exceeded our previous estimates.


Note 5.	Leasing Activities

We lease the land on which the Paradis fractionator plant and the Larose processing plant are located. The initial terms of the leases are 20 years with renewal options for an additional 30 years. We entered into a ten-year leasing agreement for pipeline capacity from Texas Eastern Transmission, LP, as part of our Market Expansion project which began in June 2005. The lease includes renewal options and options to increase capacity which would also increase rentals. The future minimum annual rentals under these non-cancelable leases as of December 31, 2006 are payable as follows:


	(In thousands)

2007	$	854
2008		858
2009		858
2010		858
2011		858
Thereafter		3,252

	$	7,538

Total rent expense for 2006, 2005 and 2004, including a cancelable platform space lease and month-to-month leases, was $1,383,261, $1,059,909 and $866,000, respectively.


Note 6.	Financial Instruments and Concentrations of Credit Risk

Financial Instruments Fair Value

We used the following methods and assumptions to estimate the fair value of financial instruments:

Cash and cash equivalents. The carrying amounts reported in the consolidated balance sheets approximate fair value due to the short-term maturity of these instruments.

Restricted cash. The carrying amounts reported in the consolidated balance sheets approximate fair value as these instruments have interest rates approximating market.


	2006				2005
	Carrying		Fair		Carrying		Fair
	Amount		Value		Amount		Value
	(In thousands)

Cash and cash equivalents	$	37,583	$	37,583	$	21,378	$	21,378
Restricted cash		28,773		28,773		44,559		44,559

Concentrations of Credit Risk

Our cash equivalents and restricted cash consist of high-quality securities placed with various major financial institutions with credit ratings at or above AA by Standard & Poor’s or Aa by Moody’s Investor’s Service.

At December 31, 2006 and 2005, substantially all of our customer accounts receivable result from gas transmission services for and natural gas liquids sales to our two largest customers. This concentration of customers may impact our overall credit risk either positively or negatively, in that these entities may be similarly affected by industry-wide changes in economic or other conditions. As a general policy, collateral is not required for receivables, but customers’ financial condition and credit worthiness are evaluated regularly. Our credit policy and the relatively short duration of receivables mitigate the risk of uncollected receivables. We did not incur any credit losses on receivables during 2006 and 2005.

Major Customers. Williams and Eni accounted for approximately $57.8 million (58%) and $10.9 million (11%), respectively, of our total revenues in 2004, and $70.8 million (58%) and $8.5 million (7%), respectively, of our total revenues in 2005. Williams and Texas Eastern Corporation accounted for approximately $149.0 million (75%) and $12.2 million (6%), respectively, of our total revenues in 2006.


Note 7.	Rate and Regulatory Matters and Contingent Liabilities

Rate and Regulatory Matters. Annually, DGT files a request with the FERC for a lost-and-unaccounted-for gas percentage to be allocated to shippers for the upcoming fiscal year beginning July 1. On June 1, 2006, DGT filed to maintain a lost-and-unaccounted-for percentage of zero percent for the period July 1, 2006 to June 30, 2007 and to retain the 2005 net system gains of $1.2 million that are unrelated to the lost-and-unaccounted-for gas over recovered from its shippers. By Order dated June 29, 2006 the filing was approved. On May 31, 2007, DGT filed to maintain a lost-and-unaccounted-for percentage of zero percent for the period July 1, 2007 to June 30, 2008 and to retain the 2006 net system gains of $1.8 million that are unrelated to the lost-and-unaccounted-for gas over recovered from its shippers. By Order dated June 28, 2007 the filing was approved. The approval was subject to a 30 day protest period, which passed without protest. As of September 30, 2007 (unaudited), December 31, 2006 and 2005, DGT has deferred amounts of $4.4 million, $4.6 million and $6.0 million, respectively, included in current accrued liabilities in the accompanying Consolidated Balance Sheets representing amounts collected from customers pursuant to prior years’ lost and unaccounted for gas percentage and unrecognized net system gains.

On November 25, 2003, the FERC issued Order No. 2004 promulgating new standards of conduct applicable to natural gas pipelines. On August 10, 2004, the FERC granted DGT a partial exemption allowing the continuation of DGT’s current ownership structure and management subject to compliance with many of the other standards of conduct. On November 17, 2006, the United States Court of Appeals for the District of Columbia Circuit vacated and remanded Order No. 2004 as applied to interstate natural gas pipelines and their affiliates. On January 9, 2007, the FERC issued an interim rule. The Interim Rule re-promulgates, on an interim basis, the standards of conduct that were not challenged before the Court. The Interim Rule applies to the relationship between interstate natural gas pipelines and their marketing and brokering affiliates, but not necessarily to their other affiliates, such as gatherers, processors or exploration and production companies. On

March 21, 2007 the FERC issued an Order on Clarification and Rehearing of the Interim Rule. The FERC clarified that the interim standards of conduct only apply to natural gas transmission providers that are affiliated with a marketing or brokering entity that conducts transportation transactions on such natural gas transmission provider’s pipeline. Currently DGT’s marketing or brokering affiliates do not conduct transmission transactions on DGT. On January 18, 2007, the FERC issued a Notice of Proposed Rulemaking to propose permanent regulations regarding the standards of conduct. Comments were due April 4, 2007. The FERC may enact a final rule at any time. At this stage, it cannot be determined how a final rule may or may not affect us (or DGT).

On July 20, 2006, DGT and DPS filed applications for Certificates of Public Convenience and Necessity for DPS to provide to DGT the use of capacity on a DPS gathering line which would be subject to a Limited Jurisdiction Certificate. The capacity would be provided to DGT under a capacity lease and would allow DGT to effectuate transportation of gas received from Texas Eastern Transmission, LP for delivery to DPS’ Larose processing plant. DPS’ request for a Limited Jurisdiction Certificate would permit DGT’s use of DPS’ non-jurisdictional gathering line for DGT’s jurisdictional transportation without having DPS’ gathering and processing facilities and operations becoming subject to the full panoply of the Natural Gas Act. On November 26, 2006, the Commission issued an order granting the requested Certificates. The order was limited to interruptible service. On December 14, 2006, DGT and DPS filed a request for an amendment to the Certificates to permit DGT to offer firm service on the leased capacity. The Commission approved the request by order issued on March 23, 2007.

Pogo Producing Company. On January 16, 2006, DPS and DGT received notice of a claim by Pogo Producing Company, or Pogo, relating to the results of a Pogo audit performed first in April 2004 and then continued through August 2005. Pogo claimed that DPS and DGT overcharged Pogo and its working interest owners approximately $600,000 relating to condensate transportation and handling during 2000 — 2005. The underlying agreements limit audit claims to a two-year period from the date of the audit. DPS and DGT disputed the validity of the claim. On November 2, 2007, the claim was settled for $300,000.

Environmental Matters. We are subject to extensive federal, state, and local environmental laws and regulations which affect our operations related to the construction and operation of our facilities. Appropriate governmental authorities may enforce these laws and regulations with a variety of civil and criminal enforcement measures, including monetary penalties, assessment and remediation requirements and injunctions as to future compliance. We have not been notified and are not currently aware of any noncompliance under the various environmental laws and regulations.

Other. We are party to various other claims, legal actions and complaints arising in the ordinary course of business. Litigation, arbitration and environmental matters are subject to inherent uncertainties. Were an unfavorable ruling to occur, there exists the possibility of a material adverse impact on the results of operations in the period in which the ruling occurs. Management, including internal counsel, 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 our future financial position.


Note 8.	Subsequent Events (unaudited)

On October 30, 2007, we made quarterly cash distributions totaling $14.0 million to our members.