Kinder Morgan (KMI) 10-K 2010 FY Annual report

Exhibit 99.4

CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

NGPL PIPECO LLC

And Subsidiaries

June 30, 2009 and 2008

June 2009 NGPL PipeCo LLC Financials

Report of Independent Auditors

To the Boards of Directors of NGPL PipeCo LLC and

Kinder Morgan, Inc.:

In our opinion, the accompanying consolidated and combined balance sheets and the related consolidated and combined statements of operations, of comprehensive income, of members' equity and of cashflows present fairly, in all material respects, the financial position of NGPL PipeCo LLC and its subsidiaries (the "Company") at June 30, 2009 and 2008, and the results of their operations and their cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.  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 of these statements 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 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.

As discussed in Note 2 to the consolidated and combined financial statements, the Company has entered into significant transactions with Kinder Morgan, Inc., a related party.

/s/ PricewaterhouseCoopers LLP

October 16, 2009

Houston, Texas

June 2009 NGPL PipeCo LLC Financials

CONSOLIDATED AND COMBINED STATEMENTS OF OPERATIONS

NGPL PipeCo LLC and Subsidiaries

	Year Ended June 30,
	2009			2008
	(In thousands)
Operating Revenues:
Transportation and Storage	$	1,020,659		$	987,727
Natural Gas Sales		301,188			198,823
Other		3,349			4,779
Total Operating Revenues		1,325,196			1,191,329
Operating Costs and Expenses:
Purchases and Other Costs of Sales		399,301			326,631
Operations and Maintenance		167,332			136,597
General and Administrative		45,163			46,540
Depreciation and Amortization		77,020			75,126
Taxes, Other Than Income Taxes		37,557			32,286
Other Expenses (Income)		(5,796	)		157
Total Operating Costs and Expenses		720,577			617,337
Operating Income		604,619			573,992
Other Income and (Expenses):
Interest Expense, Net		(212,807	)		(157,350	)
Interest Income		2,529			21,758
Equity in Earnings of Horizon		1,531			1,492
Minority Interests		314			1,125
Other, Net		6,868			(6,669	)
Total Other Income and (Expenses)		(201,565	)		(139,644	)
Income Before Income Taxes		403,054			434,348
Income Taxes		165,188			161,371
Net Income	$	237,866		$	272,977

The accompanying notes are an integral part of these consolidated and combined financial statements.

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June 2009 NGPL PipeCo LLC Financials

CONSOLIDATED AND COMBINED STATEMENTS OF COMPREHENSIVE INCOME

NGPL PipeCo LLC and Subsidiaries

	Year Ended June 30,
	2009			2008
	(In thousands)
Net Income	$	237,866		$	272,977
Other Comprehensive Income (Loss), Net of Tax:
Change in Fair Value of Derivatives Utilized for Hedging Purposes (Net of Tax Expense of $98,387 and Tax Benefit of $66,565)		151,916			(100,831	)
Reclassification of Change in Fair Value of Derivatives to Net Income (Net of Tax Benefits of
$26,145 and $283)		(37,648	)		(480	)
Total Other Comprehensive Income (Loss)		114,268			(101,311	)
Comprehensive Income	$	352,134		$	171,666

The accompanying notes are an integral part of these consolidated and combined financial statements.

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June 2009 NGPL PipeCo LLC Financials

CONSOLIDATED AND COMBINED BALANCE SHEETS

NGPL PipeCo LLC and Subsidiaries

	June 30, 2009			June 30, 2008
	(In thousands)
ASSETS:
Current Assets:
Cash and Cash Equivalents	$	236		$	17,601
Restricted Deposits		-			90,906
Accounts Receivable, Net		67,394			61,535
Gas in Underground Storage		105,947			170,296
Materials and Supplies		11,145			6,115
Gas Imbalances		23,097			25,841
Fair Value of Derivatives		45,323			18,032
Other		11,323			16,673
		264,465			406,999
Investments		13,058			13,827
Goodwill		5,014,465			5,014,136
Property, Plant and Equipment, Net:
Property, Plant and Equipment		1,835,145			1,762,421
Accumulated Depreciation and Amortization		(126,932	)		(66,070	)
		1,708,213			1,696,351
Deferred Charges and Other Assets		38,754			36,869
Total Assets	$	7,038,955		$	7,168,182
LIABILITIES AND MEMBERS’ EQUITY:
Current Liabilities:
Notes Payable	$	28,300		$	172,000
Accounts Payable		16,482			43,952
Accrued Interest		9,303			9,640
Accrued Income and Other Taxes		60,075			27,775
Gas Imbalances		19,949			17,656
Fair Value of Derivatives		8,330			118,411
Other		22,128			11,758
		164,567			401,192
Other Liabilities and Deferred Credits:
Deferred Income Taxes		291,377			201,289
Other		24,471			36,448
		315,848			237,737
Long-term Debt		3,000,000			3,000,000
Minority Interests in Equity of Subsidiaries		497			811
Commitments and Contingent Liabilities (Notes 4 and 9)
Members’ Equity:
Members’ Capital		3,530,721			3,615,388
Accumulated Other Comprehensive Income (Loss)		27,322			(86,946	)
Total Members’ Equity		3,558,043			3,528,442
Total Liabilities and Members’ Equity	$	7,038,955		$	7,168,182

The accompanying notes are an integral part of these consolidated and combined financial statements.

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June 2009 NGPL PipeCo LLC Financials

CONSOLIDATED AND COMBINED STATEMENTS OF MEMBERS’ EQUITY

NGPL PipeCo LLC and Subsidiaries

	Year Ended June 30,
	2009			2008
	(In thousands)
Members’ Capital:
Beginning Balance	$	3,615,388		$	6,410,214
Net Income		237,866			272,977
Distributions to Members (Note 2(L))		(322,533	)		(3,128,452	)
Non-cash Contribution (Note 2(L))		-			60,649
Ending Balance		3,530,721			3,615,388
Accumulated Other Comprehensive Income (Loss), Net of Tax:
Beginning Balance		(86,946	)		14,365
Change in Fair Value of Derivatives Utilized for Hedging Purposes		151,916			(100,831	)
Reclassification of Change in Fair Value
of Derivatives to Net Income		(37,648	)		(480	)
Ending Balance		27,322			(86,946	)
Total Members’ Equity	$	3,558,043		$	3,528,442

The accompanying notes are an integral part of these consolidated and combined financial statements.

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June 2009 NGPL PipeCo LLC Financials

CONSOLIDATED AND COMBINED STATEMENTS OF CASH FLOWS

NGPL PipeCo LLC and Subsidiaries

	Year Ended June 30,
	2009			2008
	(In thousands)
Increase (Decrease) in Cash and Cash Equivalents
Cash Flows From Operating Activities:
Net Income	$	237,866		$	272,977
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization		77,020			75,126
Deferred Income Taxes		28,323			5,789
Carrying Value Adjustments to Inventories (Note 2(E))		20,627			-
Interest Income from NGPL PipeCo Escrow		-			(10,196	)
Changes in Gas in Underground Storage		43,722			(39,846	)
Changes in Other Working Capital Items		49,357			(34,004	)
(Gains)/Losses From Sales of Assets		(5,796	)		157
Contribution to Voluntary Employee Benefit Association (Note 3)		(8,711	)		(7,259	)
Other, Net		1,231			(10,583	)
Net Cash Flows Provided by Operating Activities		443,639			252,161
Cash Flows From Investing Activities:
Capital Expenditures		(94,518	)		(198,096	)
Proceeds From Sales of Assets, Net		8,072			11,687
Investment In NGPL PipeCo Escrow		-			(3,096,263	)
Receipt From NGPL PipeCo Escrow		-			3,106,459
Investment in Restricted Deposits		90,906			(90,906	)
Return of Equity Investment in Horizon		769			1,508
Net Cash Flows Provided by (Used in) Investing Activities		5,229			(265,611	)
Cash Flows From Financing Activities:
Short-term Debt, Net		(143,700	)		172,000
Long-term Debt Issued		-			3,000,000
Debt Issuance Costs		-			(13,750	)
Distributions to Members (Note 2(L))		(322,533	)		(3,128,452	)
Net Cash Flows Provided by (Used in) Financing
Activities		(466,233	)		29,798
Net Increase (Decrease) in Cash and Cash Equivalents		(17,365	)		16,348
Cash and Cash Equivalents at Beginning of Period		17,601			1,253
Cash and Cash Equivalents at End of Period	$	236		$	17,601

The accompanying notes are an integral part of these consolidated and combined financial statements.

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June 2009 NGPL PipeCo LLC Financials

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

1.  Description of Business and Basis of Presentation

NGPL PipeCo LLC (“NGPL PipeCo”) engages in interstate natural gas transportation, compression and storage. NGPL PipeCo is 80% owned by Myria Acquisition LLC (formerly Myria Acquisition, Inc.), a wholly owned subsidiary of Myria Holdings Inc. and 20% owned by NGPL Holdco Inc., a wholly owned subsidiary of Kinder Morgan, Inc. (Kinder Morgan, Inc.’s name was changed to Knight Inc. on May 31, 2007, upon completion of the “Going Private” transaction [see Note 2(Q)] and was changed back to Kinder Morgan, Inc. in July 2009). Unless the context requires otherwise, references to “we,” “us,” “our,” or the “Company” are intended to mean NGPL PipeCo.

On February 15, 2008, Kinder Morgan, Inc. (“Kinder Morgan”) sold an 80% ownership interest in NGPL PipeCo to Myria Acquisition LLC (“Myria”) for approximately $2.9 billion in cash (the “Myria Transaction”). Kinder Morgan also received approximately $3.1 billion of cash previously held by us in escrow pending the closing of the Myria Transaction. Immediately prior to the closing of the Myria Transaction, the $3.1 billion held in escrow was paid to Kinder Morgan to retire a $2.85 billion intercompany note and $50.1 million of associated interest (see Note 7) and as a distribution. Pursuant to the purchase agreement, Myria acquired all 800 of our Class B shares and Kinder Morgan retained all 200 of our Class A shares. Kinder Morgan will continue to operate our assets pursuant to the 15-year Operatio ns and Reimbursement Agreement for Natural Gas Pipeline Company of America LLC dated as of February 15, 2008 (the “Operating Agreement”).

The principal wholly owned subsidiary of NGPL PipeCo is Natural Gas Pipeline Company of America LLC (“Natural”), which owns and operates a major interstate natural gas pipeline transmission and storage system, consisting primarily of two major interconnected transmission pipelines terminating in the Chicago, Illinois metropolitan area. Natural’s Amarillo Line originates in the West Texas and New Mexico producing areas and is comprised of approximately 4,400 miles of mainline and various small-diameter pipelines. The other major pipeline, the Gulf Coast Line, originates in the Gulf Coast areas of Texas and Louisiana and consists of approximately 4,100 miles of mainline and various small-diameter pipelines. These two main pipelines are connected at points in Texas and Oklahoma by Natural’s 800-mile Amarillo/Gu lf Coast pipeline. Natural also operates an approximate 3-mile natural gas pipeline in northern Illinois, which is owned by Kinder Morgan Illinois Pipeline LLC, our wholly owned subsidiary. Natural provides 360,000 Dth per day of capacity to Kinder Morgan Illinois Pipeline LLC under a long-term operating lease.

Natural owns investments in two joint ventures, Horizon Pipeline Company, L.L.C. (“Horizon”), which is 50% owned and accounted for under the equity method, reflecting our ability to exercise significant influence over its operating and financial policies (see Note 2(F)), and Canyon Creek Compression Company (“Canyon”), which is 70% owned and consolidated into these financial statements. We recently made a regulatory abandonment filing on Canyon (see Note 3).

Natural’s interstate natural gas pipeline and storage operations, as well as those of its joint venture investees, are subject to regulation by the Federal Energy Regulatory Commission (the “FERC”). The FERC regulates, among other things, rates and charges for transportation and storage of natural gas in interstate commerce, the construction and operation of interstate pipeline and storage facilities and the accounts and records of interstate pipelines.

Prior to February 15, 2008, these financial statements have been prepared from the historical accounting records of Kinder Morgan and are presented on a carve-out basis to include the historical operations applicable to MidCon Corp. and its subsidiaries and Kinder Morgan Illinois Pipeline LLC, which together are referred to as “NGPL PipeCo” in this report, and which were each directly wholly owned by Kinder Morgan. On February 15, 2008, NGPL PipeCo LLC merged with and into MidCon Corp. with MidCon Corp. continuing as the surviving legal entity, converted to a limited liability company and renamed NGPL PipeCo LLC. Within these financial statements, references to “Members” for periods prior to the February 15, 2008 merger of NGPL PipeCo LLC and MidCon Corp. refer to our then sole parent, Kinder Morgan.

Our Consolidated and Combined Financial Statements include the accounts of NGPL PipeCo LLC and our majority-owned subsidiaries. Investments in jointly owned operations in which we hold a 50% or less interest and have the ability to exercise significant influence over their operating and financial policies are accounted for under the equity method. All material intercompany transactions and balances have been eliminated. The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (“GAAP”) requires management to make estimates and assumptions. These estimates and assumptions affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities, and the reported amounts of revenues and expenses. Actual results could differ from these estimates. We evaluated subsequent events, which are events or transactions that occurred after June 30, 2009 but before our accompanying financial statements were issued, through October 16, 2009, the date we issued these Consolidated and Combined Financial Statements. As a result of the Myria Transaction, and in order to meet the reporting requirements of our members, on April 21, 2008, upon the vote of our Board of Directors, we changed our fiscal year to July 1 through June 30.

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June 2009 NGPL PipeCo LLC Financials

2.  Summary of Significant Accounting Policies

(A) Accounting for Regulatory Activities

Our regulated utility operations are accounted for in accordance with the provisions of SFAS No. 71, Accounting for the Effects of Certain Types of Regulation, which prescribes the circumstances in which the application of generally accepted accounting principles is affected by the economic effects of regulation. Regulatory assets and liabilities represent probable future revenues or expenses associated with certain charges and credits that will be recovered from or refunded to customers through the ratemaking process.

The following regulatory assets and liabilities are reflected in the accompanying Consolidated and Combined Balance Sheets in the captions “Deferred Charges and Other Assets” and “Other Liabilities and Deferred Credits: Other.”

	June 30, 2009		June 30, 2008
	(In thousands)
Regulatory Assets:
Employee Benefit Costs	$	1,216	$	1,396
Deferred Income Taxes		15,059		11,585
Rate Regulation and Application Costs		769		1,799
Total Regulatory Assets		17,044		14,780
Regulatory Liabilities:
Deferred Income Taxes		4,876		7,488
Total Regulatory Liabilities		4,876		7,488
Net Regulatory Assets	$	12,168	$	7,292

As of June 30, 2009 and 2008, $15.8 million and $13.4 million of our regulatory assets, respectively, and $4.9 million and $7.5 million of our regulatory liabilities, respectively, were being recovered from or refunded to customers through rates over periods ranging from 1 to 16 years. The regulatory asset of $1.2 million at June 30, 2009 related to employee benefit costs is not currently being recovered from customers through rates. We believe, however, that eventual recovery through future ratemaking procedures is probable.

(B) Revenue Recognition Policies

We recognize revenues as services are rendered or goods are delivered and, if applicable, title has passed.

We provide various types of natural gas transportation and storage services to our customers in which the natural gas remains the property of these customers at all times. In many cases (generally described as “firm service”), the customer pays a two-part rate that includes (i) a fixed fee reserving the right to transport or store natural gas in our facilities and (ii) a per-unit rate for volumes actually transported or injected into/withdrawn from storage. The fixed-fee component of the overall rate is recognized as revenue in the period the service is provided. The per-unit charge is recognized as revenue when the volumes are delivered to the customers’ agreed upon delivery point, or when the volumes are injected into/withdrawn from our storage facilities. In other cases (generally described as “interrupti ble service”), there is no fixed fee associated with the services because the customer accepts the possibility that service may be interrupted at our discretion in order to serve customers who have purchased firm service. In the case of interruptible service, revenue is recognized in the same manner utilized for the per-unit rate for volumes actually transported or injected into/withdrawn from storage under firm service agreements. In addition to our “firm” and “interruptible” services, we also provide a natural gas “park and loan” service to assist customers in managing short-term gas surpluses or deficits. Revenues are recognized based on the terms negotiated under these contracts.

(C) Restricted Deposits

“Restricted Deposits” consist principally of restricted funds on deposit with brokers in support of our risk management activities (see Note 8).

(D) Accounts Receivable

The caption “Accounts Receivable, Net” in the accompanying Consolidated and Combined Balance Sheets is presented net of allowances for doubtful accounts. Our policy for determining an appropriate allowance for doubtful accounts varies according to the type of service being provided and the customers being served. The allowance for doubtful accounts is

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June 2009 NGPL PipeCo LLC Financials

adjusted as necessary for changed circumstances and customer-specific information. When specific receivables are determined to be uncollectible, the reserve and receivable are relieved. Allowances for doubtful accounts were $0 and $11,000 at June 30, 2009 and 2008, respectively.

(E) Inventories

Our inventories consist of the following:

	June 30, 2009		June 30, 2008
	(In thousands)
Gas in Underground Storage (Current)	$	105,947	$	170,296
Materials and Supplies		11,145		6,115
	$	117,092	$	176,411

In accordance with our transportation tariffs, we collect natural gas in-kind from shippers on our systems. Certain of this gas is used by us as fuel in our operations. Fuel collected in excess of our operational needs typically is either sold by us or injected into storage for sale at a later date. Consequently, in the normal course of business, we both sell natural gas and maintain natural gas inventories. Our inventories are accounted for using the following methods, with the percent of the total value reported under each method shown in parentheses: last-in, first-out (90% and 97%) for gas in underground storage and average cost (10% and 3%) for materials and supplies at June 30, 2009 and 2008, respectively.

We enter into derivative contracts for the purpose of hedging exposures that accompany our operational gas sales and we utilize this risk management activity to formulate a gas sales plan. Natural gas placed in inventory is valued at our forecasted realizable value, net of hedge gains and losses, based on our operational gas sales plan. We evaluate our natural gas inventory on a quarterly basis and if the carrying value of our inventory is greater than the latest estimate of our net realizable value, we reduce the carrying value of the natural gas inventory to our estimated net realizable value. During the year ended June 30, 2009, we recorded $20.6 million of reductions in the carrying value of our natural gas storage inventories. Only the excess fuel gas that we take title to under our transportation tariffs is recorded in the ac companying Consolidated and Combined Balance Sheets. We receive fees from our storage service customers but do not reflect the value of their gas stored in our facilities in the accompanying Consolidated and Combined Balance Sheets.

(F) Investments

We have a 50% ownership in Horizon, which we account for using the equity method. The balance of our investment in Horizon was $13.1 million and $13.8 million at June 30, 2009 and 2008, respectively. Earnings from our equity investment in Horizon were $1.5 million for both years ended June 30, 2009 and 2008. We received distributions from Horizon of $2.3 million and $3.0 million during the years ended June 30, 2009 and 2008, respectively.

(G) Property, Plant and Equipment

We report property, plant and equipment at its acquisition cost. We expense costs for maintenance and repairs in the period incurred. When we sell or retire property, plant and equipment, we charge the original cost of property sold or retired to accumulated depreciation and amortization, net of salvage and cost of removal. Generally, we do not include retirement gain or loss in income except in cases of sales of operating systems or land. Gains and losses on minor system sales, excluding land, are recorded to the appropriate accumulated depreciation reserve. Gains and losses for operating systems sales and land sales are booked to income or expense accounts in accordance with regulatory accounting guidelines.

Depreciation on our long-lived assets is computed principally based on the straight-line method over their estimated useful lives. Generally, we apply composite depreciation rates to functional groups of property having similar economic characteristics. Depreciation rates range from 1.8% to 5.0%, excluding certain short-lived assets such as vehicles. Depreciation estimates are based on various factors, including age (in the case of acquired assets), manufacturing specifications, technological advances and historical data concerning useful lives of similar assets. Uncertainties that impact these estimates include changes in laws and regulations relating to restoration and abandonment requirements, economic conditions, and supply and demand in the area. When assets are put into service, we make estimates with respect to useful lives (and salvage values where appropriate) that we believe are reasonable. However, subsequent events could cause us to change our estimates, thus impacting the future calculation of depreciation and amortization expense. Historically, adjustments to useful lives have not had a material impact on our aggregate depreciation levels from year to year.

We maintain natural gas in underground storage as part of our inventory, which is recorded in the caption “Current Assets: Gas in Underground Storage” on the accompanying Consolidated and Combined Balance Sheets. This component of our

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June 2009 NGPL PipeCo LLC Financials

inventory represents the portion of gas stored in an underground storage facility generally known as “working gas,” and represents an estimate of the portion of gas in these facilities available for routine injection and withdrawal to meet current demand. In addition to this working gas, underground gas storage reservoirs contain injected gas, which is not routinely cycled but, instead, serves the function of maintaining the necessary pressure to allow efficient operation of the facility. This gas, generally known as “cushion gas,” is recorded in the caption “Property, Plant and Equipment” on the accompanying Consolidated and Combined Balance Sheets. Cushion gas is divided into the categories of “recoverable cushion gas” and “unrecoverable cushion gas,” based on an enginee ring analysis of whether the gas can be economically removed from the storage facility at any point during its life. The portion of cushion gas that is determined to be unrecoverable is considered to be a permanent part of the facility itself and is depreciated over the facility’s estimated useful life. The portion of cushion gas that is determined to be recoverable is also considered a component of the facility but is not depreciated because it is expected to ultimately be recovered and sold.

We review the carrying values of our long-lived assets whenever events or changes in circumstances indicate that such carrying values may not be recoverable. We would recognize an impairment loss when estimated future cash flows expected to result from our use of the asset and its eventual disposition are less than its carrying amount. We did not record any asset impairments during the years ended June 30, 2009 and 2008.

(H) Asset Retirement Obligations

We recognize a liability for the fair value of an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. A reconciliation of the changes in our accumulated asset retirement obligations, which are included in the caption “Other Liabilities and Deferred Credits: Other” on the accompanying Consolidated and Combined Balance Sheets, is as follows:

	Year Ended June 30,
	2009		2008
	(In thousands)
Balance at Beginning of Period	$	2,834	$	1,809
Liabilities Incurred		-		1,000
Liabilities Settled		-		-
Accretion Expense		85		25
Balance at End of Period	$	2,919	$	2,834

In general, our system is composed of underground piping, compressor stations and associated facilities, natural gas storage facilities and certain other facilities and equipment. Except as discussed following, we are not required to and have no plans to abandon any of these facilities, the majority of which have been providing utility service for many years, making it impossible to determine the timing of any potential retirement expenditures. Notwithstanding our current intentions, in general, if we were to cease utility operations in total or in any particular area, we would be permitted to abandon the underground piping in place, but we would have to remove our surface facilities from land belonging to our customers or others. We would generally have no obligations for removal or remediation with respect to equipment and facili ties, such as compressor stations, located on land we own.

In August 2007, BP notified Canyon of its decision to discontinue operations at the Whitney Plant, by October 1, 2007. As of September 4, 2007, BP has ceased operations at its Whitney Canyon Gas Plant, which is located near Evanston, Wyoming. The Whitney Plant is the exclusive source of gas compressed at Canyon’s facility. On June 30, 2008, Canyon filed an application with the FERC to abandon all of its facilities and services. On December 5, 2008, the FERC issued an order approving Canyon’s abandonment request subject to certain conditions.  The abandonment approval is for a three year time period subject to Canyon filing for Director of the Office of Energy Project approval prior to the disposition of any facilities so that the Director can perform an environmental review of the requested disposal. We do not believe that the abandonment of Canyon will have a material adverse impact on our business, cash flows, financial position or results of operations (see Note 3).

In addition, we have various condensate drip tanks located throughout the system, storage wells located within the storage fields, laterals no longer integral to the overall mainline transmission system, compressor stations which are no longer active, and other miscellaneous facilities, all of which have been officially abandoned. For these facilities, it is possible to reasonably estimate the timing of the payment of obligations associated with their retirement. The recognition of these obligations has resulted in a combined liability of approximately $2.9 million and $2.8 million at June 30, 2009 and 2008, respectively, which represents the present value of those future obligations for which we are able to make reasonable estimations of the current fair value due to, as discussed above, our ability to estimate the timing of the i ncurrence of the

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June 2009 NGPL PipeCo LLC Financials

expenditures. The remainder of our asset retirement obligations have not been recorded due to our inability, as discussed above, to reasonably estimate when they will be settled in cash.

(I) Gas Imbalances

Gas imbalances receivable and payable reflect gas volumes owed to us from interconnecting pipelines or by us to interconnecting pipelines and are valued at the lower of cost or market if they are receivables and at the higher of cost or market if they are payables. Gas imbalances represent the difference between customer nominated versus actual gas receipts from and gas deliveries to interconnecting pipelines under various operational balancing agreements. Gas imbalances are settled in cash (“cash outs”) or made up in-kind subject to the terms of the various agreements. We had net cash-outs on operational balancing agreements of $3.8 million and $5.7 million for the years ended June 30, 2009 and 2008, respectively.

(J) Interest Expense

“Interest Expense, Net” as presented in the accompanying Consolidated and Combined Statements of Operations principally consists of interest expense on (i) our $3.0 billion of outstanding long-term debt, (ii) our short-term revolving credit facility and (iii) our $2.85 billion note payable to Kinder Morgan (which was retired in February 2008, see note 7), net of amounts capitalized representing the debt component of the allowance for funds used during construction (“AFUDC — Interest”), as shown following.

	Year Ended June 30,
	2009			2008
	(In thousands)
Interest Expense	$	(213,041	)	$	(112,078	)
Interest Expense on Kinder Morgan Note		-			(50,143	)
AFUDC – Interest		234			4,871
Interest Expense, Net	$	(212,807	)	$	(157,350	)

(K) Cash Flow Information

We consider all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. “Other, Net,” presented as a component of “Net Cash Flows Provided by Operating Activities” in the accompanying Consolidated and Combined Statements of Cash Flows includes, among other things, non-cash charges and credits to income.

ADDITIONAL CASH FLOW INFORMATION

Changes in Other Working Capital Items

Increase (Decrease) in Cash and Cash Equivalents

	Year Ended June 30,
	2009			2008
	(In thousands)
Accounts Receivable	$	(11,402	)	$	3,366
Materials and Supplies Inventories		(5,030	)		(2,184	)
Other Current Assets		43,029			(52,830	)
Accounts Payable		(23,967	)		23,095
Other Current Liabilities		46,727			(5,451	)
	$	49,357		$	(34,004	)

On October 17, 2007, we made a $2.85 billion dividend to Kinder Morgan in the form of a promissory note. The promissory note was repaid in February 2008 (see Note 7).

We made cash payments for interest of approximately $211.5 million during the year ended June 30, 2009. We made cash payments for interest of approximately $151.9 million during the year ended June 30, 2008, including $50.1 million of interest on the note payable to Kinder Morgan.

Prior to the February 15, 2008 closing of the Myria Transaction, we were included in the consolidated income tax returns of Kinder Morgan, who made tax payments on our behalf. Subsequent to the closing of the Myria Transaction, we are included in the consolidated tax returns of Myria. During the year ended June 30, 2009, we made cash payments for income taxes of approximately $103.8 million. During the period February 15, 2008 to June 30, 2008, we made cash payments for income taxes of approximately $51.5 million.

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June 2009 NGPL PipeCo LLC Financials

Non-cash investing activities include decreases of $3.5 million and $2.2 million for the years ended June 30, 2009 and 2008, respectively, in the accrual for construction costs.

(L) Transactions with Related Parties

Prior to the February 15, 2008 closing of the Myria Transaction (see Note 1), Kinder Morgan charged us, at cost, for non-labor costs incurred on our behalf and for direct labor and related expenses for personnel who perform services for our benefit. Kinder Morgan also allocated to us certain corporate general and administrative expenses, such as expenses for executive compensation, accounting, human resources and information technology. The allocation method used to allocate such corporate costs was based on a weighted average of three factors: gross property, plant and equipment, direct payroll and operating income before corporate allocations. On February 15, 2008, Natural entered into the Operating Agreement (see Note 1) with Kinder Morgan. The Operating Agreement provides for Kinder Morgan to be reimbursed, at cost, for pre-app roved operations and maintenance costs, plus a fixed annual general and administration fee charge for services provided under the Operating Agreement. The annual fixed fee escalates at 3% each year until 2011 and is billed monthly. Fixed fee charges totaled $45.2 million and $16.7 million for the year ended June 30, 2009 and the period from February 15, 2008 to June 30, 2008, respectively.

In addition, in prior years, Kinder Morgan allocated to Natural a corporate charge related to interest expense based on the overall long-term debt position of Kinder Morgan (“Corporate Charges”). Effective January 1, 2008, Kinder Morgan no longer allocates this Corporate Charge to Natural.

On October 17, 2007, we declared a dividend in the amount of $2.85 billion to Kinder Morgan, our then sole shareholder. The dividend was paid on October 17, 2007, by issuing a $2.85 billion promissory note to Kinder Morgan. The note and accrued interest were paid in February 2008 upon the closing of the Myria Transaction. Interest on the note was based on the London Interbank Offered Rate plus 0.875%, payable in arrears at the end of each calendar quarter (see Note 7). Other distributions of approximately $211 million were made to Kinder Morgan during the year ended June 30, 2008, principally consisting of $206.3 million that had been held in escrow by us and was distributed to Kinder Morgan upon the closing of the Myria Transaction. In addition, on May 15, 2008, we made cash distributions to members totaling $67.6 million. The dis tributions were made on a pro rata basis of our ownership of 80% to Myria ($54.1 million) and 20% to Kinder Morgan ($13.5 million).

During the year ended June 30, 2009, we made cash distributions to members totaling $322.5 million. The distributions were made on a pro rata basis of our ownership of 80% to Myria ($258.0 million) and 20% to Kinder Morgan ($64.5 million).

The difference between the fair value of our assets and liabilities at the time of the Going Private transaction (see Note 2(Q)), was recorded as Goodwill. Upon recording the preliminary purchase price allocation at the time of the transaction, we recorded Goodwill of approximately $4.95 billion. Upon the finalization of the purchase price allocation in the quarter ended March 31, 2008, we recorded an additional $60.6 million of Goodwill, for a total of approximately $5.0 billion. The change in the purchase price allocation resulted in a non-cash contribution to Members’ Equity of $60.6 million, as reported in the accompanying Consolidated and Combined Statement of Members’ Equity for the year ended June 30, 2008.

From time to time in the ordinary course of business, we buy and sell pipeline services and related services from/to (i) Kinder Morgan Energy Partners, L.P. and its subsidiaries, affiliates of Kinder Morgan, and (ii) Horizon, our equity-method investee. Such transactions are conducted in accordance with all applicable laws and regulations and on an arm’s-length basis consistent with our policies governing such transactions.

Kinder Morgan’s policy is to combine payable and receivable balances that exist with affiliates at each month end and record them the following month as an interest-bearing advance to/from the affiliate. Therefore, the intercompany balances between Kinder Morgan and NGPL PipeCo prior to the February 15, 2008 Myria Transaction fluctuated through the normal course of business activity. There were no plans or intention to settle these intercompany balances and, thus, these balances represented an adjustment to Kinder Morgan’s equity investment in NGPL PipeCo. Therefore, in these Consolidated and Combined Financial Statements, related party balances with Kinder Morgan prior to the February 15, 2008, Myria Transaction have been reclassified as equity and no intercompany interest has been recorded except for interest on the $ 2.85 billion note payable to Kinder Morgan.

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June 2009 NGPL PipeCo LLC Financials

Totals of significant transactions with related parties are as follows:

	Year Ended June 30,
	2009		2008
	(In thousands)
Sales, Transportation and Storage of Natural Gas and Other Revenues	$	14,538	$	9,796
Purchases and Transportation of Natural Gas	$	4,289	$	1,044
Charges for General and Administrative Costs	$	45,163	$	46,540
Corporate Charges	$	-	$	11,616
Interest Charges	$	-	$	50,143

Totals of significant receivable (payable) balances with related parties are as follows:

	June 30, 2009			June 30, 2008
	(In thousands)
Accounts Receivable – Myria	$	830		$	782
Accounts Receivable – Other Affiliates	$	20		$	1
Accounts Payable – Kinder Morgan Energy Partners, L.P.	$	(975	)	$	(844	)
Accounts Payable – Kinder Morgan.	$	(683	)	$	(12,185	)
Accounts Payable – Other Affiliates	$	(2	)	$	-
Gas Imbalances – Receivables	$	10,162		$	10,283
Gas Imbalances – Payables	$	(11,543	)	$	(3,089	)

(M) Income Taxes

Income tax expense is recorded based on an estimate of the effective tax rate in effect or to be in effect during the relevant periods. Deferred income tax assets and liabilities are recognized for temporary differences between the basis of assets and liabilities for financial reporting and tax purposes. Changes in tax legislation are included in the relevant computations in the period in which such changes are effective. Deferred tax assets are reduced by a valuation allowance for the amount of any tax benefit we do not expect to be realized. Note 6 contains information about our income taxes, including the components of our income tax provision and the composition of our deferred income tax assets and liabilities.

(N) Accounting for Risk Management Activities

We enter into derivative contracts for the purpose of hedging exposures that accompany our normal business activities. We designate our derivative instruments as hedges of various exposures and test the effectiveness of changes in the value of these hedging instruments with the risk being hedged. Hedge ineffectiveness is recognized in income in the period in which it occurs. See Note 8 for a detailed discussion of our hedging activities.

(O) Accounting for Legal Costs

In general, we expense legal costs as incurred. When we identify significant specific litigation that is expected to continue for a significant period of time and require substantial expenditures, we identify a range of probable costs expected to be required to litigate the matter to a conclusion or reach an acceptable settlement. If no amount within this range is a better estimate than any other amount, we record a liability equal to the low end of the range. Any such liability recorded is revised as better information becomes available (see Note 4(B)).

(P) Environmental Costs

We expense or capitalize, as appropriate, environmental expenditures that relate to current operations. We expense amounts that relate to an existing condition caused by past operations that do not contribute to current or future revenue generation. We do not discount environmental liabilities to a net present value. We record environmental liabilities when environmental assessments and/or remedial efforts are probable and costs can be reasonably estimated. Generally, recording of these accruals coincides with the completion of a feasibility study or a commitment to a formal plan of action.

We utilize both internal staff and external experts to assist in identifying environmental issues and in estimating the costs and timing of remediation efforts. Often, as the remediation evaluation and effort progresses, additional information is obtained, requiring revisions to estimated costs. These revisions are reflected in income in the period in which they are reasonably determinable (see Note 4(A)).

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June 2009 NGPL PipeCo LLC Financials

(Q) Goodwill

On May 30, 2007, a group of investors, including CEO Richard D. Kinder and other members of Kinder Morgan, Inc. senior management, completed a “Going Private transaction” in which all of the outstanding shares of Kinder Morgan, Inc. were purchased for $107.50 per share and the company was renamed Knight Inc. The company name was changed back to Kinder Morgan, Inc. in July 2009. Prior to the Going Private transaction, there was no goodwill recorded on our Consolidated and Combined Balance Sheet. The Going Private transaction was accounted for as a purchase and, accordingly, the difference between the fair value of our assets and liabilities at the time of the Going Private transaction was recorded as Goodwill. Upon recording the preliminary purchase price allocation at the time of the transaction, we recorded Goodwill of approximately $4.95 billion. Upon the finalization of the purchase price allocation in the first quarter of 2008, we recorded an additional $60.6 million of Goodwill, for a total of approximately $5.0 billion. The change in the purchase price allocation resulted in a non-cash contribution to Members’ Equity of $60.6 million, as reported in the accompanying Consolidated and Combined Statement of Members’ Equity for the year ended June 30, 2008.

We evaluate goodwill for potential impairment on an annual basis or whenever events or changes in circumstances indicate that the carrying value may not be recoverable. We tested the goodwill associated with the Going Private transaction for impairment at May 31, 2009 and concluded that no impairment was required.

For investments we account for under the equity method of accounting, the excess cost over underlying fair value of net assets is referred to as equity method goodwill and is not subject to amortization but rather to impairment testing in accordance with the provisions of equity method accounting.

3.  Regulatory Matters

There are currently no proceedings challenging our rates. Regulators, as well as our shippers, do have rights, under circumstances prescribed by applicable regulations, to challenge rates that we charge. We can provide no assurance that we will not face challenges to the rates we charge in the future. Any successful challenge could have a material adverse impact on our future earnings and cash flows.

FERC Order No. 2004/717

On October 16, 2008, the FERC issued a Final Rule in Order No. 717 revising the FERC Standards of Conduct for natural gas and electric transmission providers by eliminating Order No. 2004’s concept of Energy Affiliates and corporate separation in favor of an employee functional approach as used in Order No. 497. A transmission provider is prohibited from disclosing to a marketing function employee non-public information about the transmission system or a transmission customer. The final rule also retains the long-standing no-conduit rule, which prohibits a transmission provider from disclosing non-public information to marketing function employees by using a third party conduit. Additionally, the final rule requires that a transmission provider provide annual training on the Standards of Conduct to all transmission function e mployees, marketing function employees, officers, directors, supervisory employees, and any other employees likely to become privy to transmission function information. This rule became effective on November 26, 2008.

Notice of Proposed Rule Making – Financial Reporting

On September 20, 2007, the FERC issued for public comment in Docket No. RM07-9 a proposed rule that would revise its financial forms to require that additional information be reported by natural gas companies. The proposed rule would require, among other things, that natural gas companies (i) submit additional revenue information, including revenue from shipper-supplied gas, (ii) identify the costs associated with affiliate transactions, and (iii) provide additional information on incremental facilities and on discounted and negotiated rates. The FERC proposed an effective date of January 1, 2008, which means that forms reflecting the new requirements for 2008 would be filed in early 2009. Comments on the proposed rule were filed by numerous parties on November 13, 2007.

On March 21, 2008, the FERC issued a Final Rule regarding changes to the Form 2, 2-A and 3Q. The revisions were designed to enhance the forms’ usefulness by updating them to reflect current market and cost information relevant to interstate pipelines and their customers. The rule is effective January 1, 2008 with the filing of the revised Form 3-Q beginning with the first quarter of 2009. The revised Form 2 and 2-A for calendar year 2008 material would be filed by April 18, 2009. On June 20, 2008, the FERC issued an Order Granting in Part and Denying in Part Rehearing and Granting Request for Clarification. No substantive changes were made to the March 21, 2008 Final Rule.

Notice of Inquiry – Fuel Retention Practices

On September 20, 2007, the FERC issued a Notice of Inquiry seeking comment on whether it should change its current policy and prescribe a uniform method for all interstate gas pipelines to use in recovering fuel gas and gas lost and unaccounted for. The Notice of Inquiry included numerous questions regarding fuel recovery issues and the effects of fixed

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June 2009 NGPL PipeCo LLC Financials

fuel percentages as compared with tracking provisions. Comments on the Notice of Inquiry were filed by numerous parties on November 30, 2007. On November 20, 2008 the FERC issued an order terminating the inquiry.

Notice of Proposed Rulemaking – Promotion of a More Efficient Capacity Release Market – Order 712

On November 15, 2007, the FERC issued a notice of proposed rulemaking in Docket No. RM 08-1-000 regarding proposed modifications to its Part 284 regulations concerning the release of firm capacity by shippers on interstate natural gas pipelines. The FERC proposes to remove, on a permanent basis, the rate ceiling on capacity release transactions of one year or less. Additionally, the FERC proposes to exempt capacity releases made as part of an asset management arrangement from the prohibition on tying and from the bidding requirements of Section 284.8. Initial comments were filed by numerous parties on January 25, 2008.

On June 19, 2008, the FERC issued a final rule in Order 712 regarding changes to the capacity release program. The FERC permitted market based pricing for short-term capacity releases of a year or less. Long-term capacity releases and a pipeline’s sale of its own capacity remain subject to a price cap. The ruling would facilitate asset management arrangements by relaxing the FERC’s prohibitions on tying and on its bidding requirements for certain capacity releases. The FERC further clarified that its prohibition on tying does not apply to conditions associated with gas inventory held in storage for releases for firm storage capacity. Finally, the FERC waived the prohibition on tying and bidding requirements for capacity releases made as part of state-approved retail open access programs. The final rule became effective on July 30, 2008.

On November 20, 2008, the FERC issued an order generally denying requests for rehearing and/or clarification that had been filed. The FERC reaffirmed its final rule, Order 712, and denied requests for rehearing stating the removal of the rate ceiling for short-term capacity release transactions is designed to extend to capacity release transactions the pricing flexibility already available to pipelines through negotiated rates without compromising the fundamental protection provided by the availability of recourse rate service.  Additionally the FERC clarified several areas of the rule as it relates to asset management arrangements.

Notice of Proposed Rulemaking – Natural Gas Price Transparency

On April 19, 2007, the FERC issued a notice of proposed rulemaking in Docket Nos. RM07-10-000 and AD06-11-000 regarding price transparency provisions of Section 23 of the Natural Gas Act and the Energy Policy Act. In the notice, the FERC proposed to revise its regulations to (i) require that intrastate pipelines post daily the capacities of, and volumes flowing through, their major receipt and delivery points and mainline segments in order to make available the information to track daily flows of natural gas throughout the United States; and (ii) require that buyers and sellers of more than a de minimis volume of natural gas report annual numbers and volumes of relevant transactions to the FERC in order to make possible an estimate of the size of the physical U.S. natural gas market, assess the importance of the use of index pricin g in that market, and determine the size of the fixed-price trading market that produces the information. The FERC believes these revisions to its regulations will facilitate price transparency in markets for the sale or transportation of physical natural gas in interstate commerce. Initial comments were filed on July 11, 2007 and reply comments were filed on August 23, 2007. In addition, the FERC conducted an informal workshop in this proceeding on July 24, 2007, to discuss implementation and other technical issues associated with the proposals set forth in the notice of proposed rulemaking.

Daily Reporting Requirement – Order No. 720

On December 21, 2007, the FERC issued a new notice of proposed rulemaking in Docket No. RM08-2-000 regarding the daily posting provisions that were contained in Docket Nos. RM07-10-000 and AD06-11-000. The new notice of proposed rulemaking proposes to exempt from the daily posting requirements those non-interstate pipelines that (i) flow less than ten million MMBtus of natural gas per year, (ii) fall entirely upstream of a processing plant and (iii) deliver more than ninety-five percent (95%) of the natural gas volumes they flow directly to end-users. However, the new notice of proposed rulemaking expands the proposal to require that both interstate and non-exempt non-interstate pipelines post daily the capacities of, volumes scheduled at, and actual volumes flowing through, their major receipt and delivery points and mainline segm ents. Initial comments were filed by numerous parties on March 13, 2008. A Technical Conference was held on April 3, 2008. Numerous reply comments were received on April 14, 2008.

On November 20, 2008, the FERC issued Order No. 720, which established new reporting requirements for interstate and major non-interstate pipelines. Major non-interstate pipelines are required to post design capacity, scheduled volumes and available capacity at each receipt or delivery point with a design capacity of 15,000 MMbtus of natural gas per day or greater when gas is scheduled at the point. The final rule became effective January 27, 2009 for interstate pipelines. On January 15, 2009, the FERC issued an order granting an extension of time for major non-interstate pipelines to comply with the requirements of Order No. 720 until 150 days following the issuance of an order addressing the pending requests for rehearing. On January 16, 2009, FERC granted rehearing of Order 720.  On July 16, 2009, the FERC issued a req uest for supplemental comments on revisions to the posting requirements.  Comments were due on August 31, 2009. We do not expect this Order to have a material impact on our Consolidated and Combined Financial Statements.

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June 2009 NGPL PipeCo LLC Financials

Annual Reporting Requirement – Order No. 704

On December 26, 2007, the FERC issued Order No. 704 in this docket implementing only the annual reporting provisions of the notice of proposed rulemaking with minimal changes to the original proposal. In Order No. 704, the FERC established reporting requirements on annual volumes of relevant transactions. The FERC issued Order No. 704-A on September 18, 2008. This order generally affirmed the rule, while clarifying what information certain natural gas market participants must report in Form 552. The revisions pertain to the reporting of transactions occurring in calendar year 2008. Order No. 704-A became effective October 27, 2008. On December 18, 2008, the FERC issued Order No. 704-B, denying rehearing and reconsideration of Order No. 704-A and granting a clarification regarding certain reportable volumes. On April 9, 2009, the FE RC granted an extension of time until July 1, 2009 for filing the initial Form 552. We filed our initial Form 552 on June 25, 2009.

Policy Statement - Equity Return Allowance

On April 17, 2008, the FERC adopted a new policy under Docket No. PL07-2-000 that allows master limited partnerships to be included in proxy groups for the purpose of determining rates of return for both interstate natural gas and oil pipelines. Additionally, the policy statement concluded that (i) there should be no cap on the level of distributions included in the FERC’s current discounted cash flow methodology, (ii) the Institutional Brokers Estimated System forecasts should remain the basis for the short-term growth forecast used in the discounted cash flow calculation, (iii) there should be an adjustment to the long-term growth rate used to calculate the equity cost of capital for a master limited partnership, specifically the long-term growth rate would be set at 50% of the gross domestic product, and (iv) there should be no modification to the current respective two-thirds and one-third weightings of the short-term and long-term growth factors. Additionally, the FERC decided not to explore other methods for determining a pipeline’s equity cost of capital at this time. The policy statement governs all future gas and oil rate proceedings involving the establishment of a return on equity, as well as those cases that are currently pending before either the FERC or an administrative law judge. On May 19, 2008, an application for rehearing was filed by The American Public Gas Association. On June 13, 2008, the FERC dismissed the request for rehearing.

Natural Gas Pipeline Expansion Filings

Natural Louisiana Line

On October 10, 2006, in FERC Docket No. CP07-3, Natural filed seeking approval to expand its Louisiana Line by 200,000 Dth/day. This $88 million project is supported by five-year agreements that fully subscribe the additional capacity. On July 2, 2007, the FERC issued an order authorizing construction and operation of the requested facilities. Natural accepted the order on July 6, 2007. This expansion was placed in service during the first quarter of 2008.

Herscher Galesville Storage Field

On December 7, 2007, Natural filed an application with the FERC seeking approval to expand its Herscher Galesville storage field in Kankakee County, Illinois to add 10 Bcf of incremental firm storage service for five expansion shippers. The project is fully supported by contracts ranging from 5 to 10 years. On August 11, 2008, the FERC issued an order authorizing the construction and operation of the requested facilities. Natural accepted the certificate on August 15, 2008. Service under the expansion commenced on March 1, 2009.

Canyon Filings

As part of its Docket No. RP02-356 rate case, Canyon implemented a cost of service tracker mechanism. This is a semi-annual cost of service tracker whereby rates charged customers will change each December 1 and June 1 and are adjusted for any over/under collections from Canyon’s estimate of cost and volumes for the prior six-month period versus the actual cost and volumes for that period as well as a projection of the cost and volumes for the ensuing six-month period. On April 30, 2008, Canyon filed its eleventh periodic tracker filing requesting a partial waiver of all applicable provisions included in Section 37 which proposed to maintain in effect its current Cost of Service and Deferred Account Rates, as opposed to filing revised rates. On May 28, 2008, the FERC approved Canyon’s request for a partial waiver of all applicable provisions included in Section 37 of the General Terms and Conditions of Canyon tariff so that Canyon can maintain in effect its existing Cost of Service and Deferred Account rates. Under the partial waiver, Canyon is not required to make semi-annual cost of service tracker filings.

On June 30, 2008, Canyon filed in Docket No. CP08-433-000 an application pursuant to section 7(b) of the Natural Gas Act , and Sections 157.7 and 157.18 of the FERC’s regulations for authorization to abandon: (i) its 22,000 horsepower compressor station and other appurtenant facilities located in Uinta County, Wyoming, (ii) its blanket gas in interstate commerce for interstate pipelines and others pursuant to Subpart G of Part 284 of the FERC’s regulations, (iii) its blanket certificate which authorized Canyon to engage in certain routine jurisdictional activities and for permission and approval to abandon certain services and facilities, as specified in Subpart F of Part 157 of the FERC’s regulations, and (iv) its 10-inch tap located in

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June 2009 NGPL PipeCo LLC Financials

Uinta County, Wyoming used to deliver gas to Kern River Gas Transmission Company. Canyon requested that it be granted a three year period in which to determine the ultimate disposition of its facilities, whether it is by sale or physical removal of all or a portion of the facilities. On December 5, 2008, the FERC issued an order approving Canyon’s abandonment request subject to certain conditions. The abandonment approval is for a three year time period subject to Canyon filing for Director of the Office of Energy Project approval prior to the disposition of any facilities so that the Director can perform an environmental review of the requested disposal. In addition, the FERC granted Canyon’s abandonment of its Part 284, Subpart G blanket certificate effective the date of the order.

VEBA Contributions

As part of Natural’s most recent rate case settlement, it is required to make annual contributions to one or more Voluntary Employee Benefit Associations (“VEBA”) for the purposes of providing postretirement benefits to employees. Natural complies with this requirement by making contributions to VEBA plans administered by Kinder Morgan.

4.  Environmental and Legal Matters

(A) Environmental Matters

We are subject to a variety of federal, state and local laws that regulate permitted activities relating to air and water quality, waste disposal, and other environmental matters.

Natural had established environmental reserves of approximately $3.3 million and $3.4 million as of June 30, 2009 and 2008, respectively to address remediation issues associated with four projects, which are recorded in the caption “Other Liabilities and Deferred Credits: Other” on the accompanying Consolidated and Combined Balance Sheets..

In August 2007, Natural and Kinder Morgan received an information request from the Illinois Attorney General’s Office regarding the presence of polychlorinated biphenyls (“PCBs”) in natural gas transmission lines. Thereafter, in October 2007, Natural received information requests regarding the presence of PCBs in its natural gas transmission lines in Missouri from Region 7 of the United States Environmental Protection Agency and the Missouri Attorney General’s Office. Natural responded to these requests. No proceeding or enforcement actions have been initiated.

After consideration of reserves established, we believe that costs for environmental remediation and ongoing compliance with these laws will not have a material adverse impact on our business, cash flows, financial position or results of operations. However, there can be no assurances that future events, such as changes in existing laws, the promulgation of new laws, or the development of new facts or conditions will not cause us to incur significant costs.

(B) Litigation Matters

United States of America, ex rel., Jack J. Grynberg v. K N Energy (Civil Action No. 97-D-1233, filed in the U.S. District Court, District of Colorado). This multi-district litigation proceeding involves four lawsuits filed in 1997 against numerous Kinder Morgan companies, including Natural. These suits were filed pursuant to the federal False Claims Act and allege underpayment of royalties due to mismeasurement of natural gas produced from federal and Indian lands. The complaints are part of a larger series of similar complaints filed by Mr. Grynberg against 77 natural gas pipelines (approximately 330 other defendants) in various courts throughout the country that were consolidated and transferred to the District of Wyoming.

In May 2005, a Special Master appointed in this litigation found that because there was a prior public disclosure of the allegations and that Grynberg was not an original source, the Court lacked subject matter jurisdiction. As a result, the Special Master recommended that the Court dismiss all the Kinder Morgan defendants, including Natural. In October 2006, the United States District Court for the District of Wyoming upheld the dismissal of each case against the Kinder Morgan defendants on jurisdictional grounds. Grynberg appealed this Order to the Tenth Circuit Court of Appeals. Briefing was completed and oral argument was held on September 25, 2008. A decision by the Tenth Circuit Court of Appeals affirming the dismissal of the Kinder Morgan defendants was issued on March 17, 2009. Grynberg’s petition for rehearing was de nied on May 4, 2009 and the Tenth Circuit issued its Mandate on May 18, 2009. Grynberg filed a Petition for Writ of Certiorari with the Supreme Court of the United States on August 3, 2009 and the defendants, including Natural, filed a Waiver of Brief in Opposition on August 28, 2009. The Supreme Court denied the Petition for Writ of Certiorari on October 5, 2009.

Prior to the dismissal order on jurisdictional grounds, the Kinder Morgan defendants filed Motions to Dismiss and for Sanctions alleging that Grynberg filed his Complaint without evidentiary support and for an improper purpose. On January 8, 2007, after the dismissal order, the Kinder Morgan defendants also filed a Motion for Attorney Fees under the False Claim Act. On April 24, 2007, the Court held a hearing on the Motions to Dismiss and for Sanctions and the Requests for Attorney Fees. A decision is still pending on the Motions to Dismiss and for Sanctions and the Requests for Attorney Fees.

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June 2009 NGPL PipeCo LLC Financials

On January 5, 2009, the trial of the lawsuit styled William R. Justiss II et al. v. Natural Gas Pipeline Company of America LLC and Kevin Brown was held in the 62nd Judicial District Court, Lamar County, Texas, in which the owners of seven neighboring properties near rural Howland, Texas sued for damages arising from the operation of a natural gas compressor station owned and operated by Natural. At the conclusion of the trial, the jury returned a verdict finding that the alleged nuisance in the form of noise and odor emitted from the station had existed since 1998 with respect to five of the seven properties in question and found that no nuisance existed for the remaining two properties.

On January 30, 2009, the trial court entered judgment in accordance with the verdict rendered. At the same time, the trial court ordered the parties to mediation within 30 days. Mediation was unsuccessful. The total principal amount of all compensatory damages found by the jury was $1.2 million. The court also awarded $0.7 million in prejudgment interest and court costs. The total judgment amount is $1.9 million. Natural filed motions for new trial and for judgment notwithstanding the verdict on February 27, 2009, based on factual and legal insufficiency of the evidence and on the applicable two-year statute of limitations. Such motions were denied by the trial court.

Natural appealed the final judgment and the appeal is now pending. In connection with the appeal, Defendant Natural Gas Pipeline Company of America, as principal, and Safeco Insurance Company of America, as surety, posted a surety bond obligating themselves, jointly and severally, to pay Plaintiffs the amount of $2.0 million, which includes the amount of the compensatory damages, costs, and one year of post judgment interest at the rate of 5% per annum.

Natural has asserted a claim for insurance coverage against Aegis Insurance Services, Inc. under an excess liability policy with underlying limits and/or self insured retention of $0.3 million. Aegis has purported to reserve its rights to deny coverage on multiple grounds.

In addition, we are a defendant in various lawsuits arising from the day-to-day operations of our business. Although no assurance can be given, we believe, based on our experience to date, that the ultimate resolution of such matters, including the matters discussed in this Note, will not have a material adverse impact on our business, cash flows, financial position or results of operations.

5.  Property, Plant and Equipment

Investments in property, plant and equipment, at cost, and accumulated depreciation and amortization are as follows:

	June 30, 2009			June 30, 2008
	(In thousands)
Natural Gas Transmission and Storage	$	1,680,829		$	1,588,057
General and Other		109,986			107,650
Construction Work in Process		44,330			66,714
Total Property, Plant and Equipment		1,835,145			1,762,421
Accumulated Depreciation and Amortization		(126,932	)		(66,070	)
Property, Plant and Equipment, Net	$	1,708,213		$	1,696,351

6.  Income Taxes

Components of the income tax provision for federal and state income taxes are as follows:

	Year Ended June 30,
	2009		2008
	(In thousands)
Current Tax Provision:
U.S.
Federal	$	113,521	$	134,184
State		23,344		21,398
		136,865		155,582
Deferred Tax (Benefit) Provision:
U.S.
Federal		18,060		10,723
State		10,263		(4,934	)
		28,323		5,789
Total Tax Provision	$	165,188	$	161,371

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June 2009 NGPL PipeCo LLC Financials

The difference between the statutory federal income tax rate and our effective income tax rate is summarized as follows:

	Year Ended June 30,
	2009		2008
Federal Income Tax Rate		35.0%		35.0%
Increase (Decrease) as a Result of:
State Income Tax, Net of Federal Benefit		4.4%		3.4%
State Tax Rate Change		1.1%		(1.4%	)
Other		0.5%		0.2%
Effective Tax Rate		41.0%		37.2%

Income taxes included in the financial statements were composed of the following:

	Year Ended June 30,
	2009		2008
	(In thousands)
Operations	$	165,188	$	161,371
Equity Items		72,242		(66,848	)
Total	$	237,430	$	94,523

Deferred tax assets and liabilities result from the following:

	June 30, 2009			June 30, 2008
	(In thousands)
Deferred Tax Assets:
Derivatives	$	-		$	53,156
Amortization of Regulatory Liabilities		1,941			2,854
Postretirement Benefits Accrual		3,859			3,780
Operating Reserve		-			411
Environmental Costs		1,284			1,305
Contributions In Aid of Construction		5,575			5,294
Bad Debt Reserve		937			1,036
Hedge Ineffectiveness		1,418	��		-
Other		10,457			678
Total Deferred Tax Assets		25,471			68,514
Deferred Tax Liabilities:
Property, Plant and Equipment		278,473			252,016
Amortization of Regulatory Assets		5,805			4,395
Partnership Income		9,487			8,436
Operations Reserve		1,740			-
Derivatives		17,975			-
Hedge Ineffectiveness		-			3,083
Other		3,891			1,180
Total Deferred Tax Liabilities		317,371			269,110
Net Deferred Tax Liabilities	$	291,900		$	200,596
Current Deferred Tax Asset	$	-		$	693
Current Deferred Tax Liability		523			-
Non-current Deferred Tax Liability		291,377			201,289
Net Deferred Tax Liabilities	$	291,900		$	200,596

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June 2009 NGPL PipeCo LLC Financials

FIN 48

In July 2006, the Financial Accounting Standards Board (“FASB”) issued Interpretation (“FIN”) No. 48, Accounting for Uncertainty in Income Taxes—an Interpretation of FASB Statement No. 109, which became effective January 1, 2007. FIN No. 48 addressed the determination of how tax benefits claimed or expected to be claimed on a tax return should be recorded in the financial statements. Under FIN 48, we must recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based not only on the technical merits of the tax position based on tax law, but also the past administrative practices and precedents of the taxing authority. The tax benef its recognized in the financial statements from such a position are measured based on the largest benefit that has a greater than 50% likelihood of being realized upon ultimate resolution.

A reconciliation of the changes in our gross unrecognized tax benefits is as follows:

	Year Ended June 30,
	2009			2008
	(In millions)
Balance at Beginning of Period	$	1.1		$	11.5
Current Year Tax Positions		10.4			0.5
Prior Year Tax Positions		(4.3	)		-
Settlements With Taxing Authorities		2.2			(10.9	)
Lapse in Statute of Limitations		(2.1	)		-
Balance at End of Period	$	7.3		$	1.1

Our continuing practice is to recognize interest and/or penalties related to income tax matters in income tax expense, and as of June 30, 2008, we had $0.1 million of accrued interest and no accrued penalties. As of June 30, 2009 (i) we had$0.5 million of net accrued interest income and no accrued penalties; (ii) we believe it is reasonably possible that our liability for unrecognized tax benefits will decrease by $6.3 million during the next twelve months, and (iii) we believe $0.9 million of the unrecognized tax benefits on our Consolidated and Combined Balance Sheet at June 30, 2009 would affect our effective tax rate in future periods in the event those unrecognized tax benefits were recognized. At the time of the Going Private transaction, an adjustment was made to goodwill for unrecognized tax benefits due to settlements with taxing authorities of the predecessor company for a total decrease of $10.9 million.

We are subject to taxation, and have tax years open to examination for the periods 2003 – 2008, in the United States and 1999 – 2009 in various states.

7.  Financing

On December 21, 2007, we issued $1.25 billion aggregate principal amount of 6.514% senior notes due December 15, 2012, $1.25 billion aggregate principal amount of 7.119% senior notes due December 15, 2017 and $0.5 billion aggregate principal amount of 7.768% senior notes due December 15, 2037. The notes were sold in a private placement to a syndicate of investment banks led by Lehman Brothers Inc., Banc of America Securities LLC and Deutsche Bank Securities Inc., and resold by the initial purchasers to qualified institutional buyers pursuant to Rule 144A under the Securities Act of 1933. The notes have not been registered under the Securities Act and may not be offered or sold in the United States absent registration or an applicable exemption from the registration requirements. The notes are the senior unsecured obligati ons of NGPL PipeCo and rank equally in right of payment with any of NGPL PipeCo’s future unsecured senior debt. The senior notes are redeemable in whole or in part, at our option at any time, at a price equal to 100% of the principal amount of the notes plus accrued interest to the redemption date plus a make-whole premium. The indenture for the senior notes includes covenants that, among other things, limit our ability and the ability of our subsidiaries to (i) create liens that secure debt, (ii) enter into sale-leaseback transactions, (iii) incur debt, subject to a leverage test, (iv) enter into business outside its present business and (v) merge or consolidate with, or sell, lease or transfer its assets substantially as an entirety to another entity. In addition, if we experience certain kinds of changes of control coupled with a ratings downgrade such that the notes cease to have an investment grade rating, it must give the holders of the notes the opportunity to sell their senior notes to us at 10 1% of their principal amount, plus accrued and unpaid interest. Our senior notes have a carrying value of $3.0 billion and a fair value of approximately $3.2 billion at June 30, 2009.

Maturities of long-term debt for the five years ended June 30, 2014 include the $1.25 billion of 6.514% senior notes, which mature on December 15, 2012.

On February 15, 2008, we entered into a five-year, $200 million credit facility with a syndicate of lenders and Bank of America, N.A., as Administrative Agent, Swing Line Lender and Letter of Credit Issuer. Borrowings under the credit facility

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can be used for general corporate purposes. The credit facility includes financial covenants and events of default that are common in such arrangements. Loans under the credit facility may be Base Rate Loans or Eurodollar Rate Loans. Interest rates on Base Rate Loans are based on an interest rate spread plus the higher of (1) the Federal Funds Rate plus one-half of one percent or (2) the publicly announced Bank of America “prime rate.” Interest rates on Eurodollar Rate Loans are based on an interest rate spread plus the British Bankers Association LIBOR Rate.

At June 30, 2009, there were $28.3 million of borrowings outstanding under this facility. After deducting outstanding letters of credit, the remaining borrowing capacity under this facility at June 30, 2009 was approximately $156.6 million. For the year ended June 30, 2009, average daily borrowings under this facility were approximately $28.9 million and the average interest rate on outstanding borrowings was 3.1%. At June 30, 2008, there were $172.0 million of borrowings outstanding under this facility. For the period February 15 through June 30, 2008, average daily borrowings under this facility were approximately $26.1 million and the average interest rate on outstanding borrowings was 3.5%. Due to the fact that borrowings under this facility are short-term in nature and that the interest rates applicable to borrowings under the facility float with current market rates, the carrying value of our borrowings under this facility approximate fair value.

On October 17, 2007, we declared a dividend in the amount of $2.85 billion to Kinder Morgan, our then sole shareholder. The dividend was paid on October 17, 2007, by issuing an interest bearing promissory note to Kinder Morgan in the principal amount of $2.85 billion. Interest on the note was based on the London Interbank Offered Rate plus 0.875%, payable in arrears at the end of each calendar quarter. The note and $50.1 million of accrued interest were paid in February 2008 upon the closing of the Myria Transaction (see Note 1).

8.  Risk Management

We enter into derivative contracts for the purpose of hedging exposures that accompany our normal business activities. We designate our derivative instruments as hedges of various exposures as discussed following, and test the effectiveness of changes in the value of these hedging instruments with the risk being hedged. Hedge ineffectiveness is recognized in income in the period in which it occurs.

Our normal business activities expose us to risks associated with changes in the market price of natural gas. Specifically, these risks are associated with (i) pre-existing or anticipated physical natural gas sales, (ii) natural gas purchases and (iii) natural gas system use and storage. Price changes in natural gas are often caused by shifts in the supply and demand for this commodity, as well as its locations. All of our derivative activities relating to the mitigation of these risks were designated and qualified as cash flow hedges for all periods presented. We recognized pre-tax gains of $2.3 million and pre-tax losses of $2.8 million in the years ended June 30, 2009 and 2008, respectively as a result of ineffectiveness of these hedges, which amounts are reported within the caption “Natural Gas Sales” in the accompa nying Consolidated and Combined Statement of Operations. There was no component of these derivatives instruments’ gain or loss excluded from the assessment of hedge effectiveness.

As hedged sales and purchases take place and we record them into earnings, we also reclassify the gains and losses included in accumulated other comprehensive income into earnings. During the year ended June 30, 2009, we reclassified approximately $37.6 million of accumulated other comprehensive income into earnings as a result of hedged forecasted transactions occurring during the period. During the year ended June 30, 2008, we reclassified $1.0 million of accumulated other comprehensive income into earnings as a result of hedged forecasted transactions occurring during the period and $0.5 million of other comprehensive loss into income due to hedges no longer being highly correlated with the hedged items. We expect to reclassify into earnings, during the next twelve months, substantially all of our $27.3 million balance of accumu lated other comprehensive income at June 30, 2009, representing unrecognized net gains on derivative activities.

We have counterparty credit risk as a result of our use of financial derivative contracts. Our counterparties consist primarily of financial institutions, major energy companies and local distribution companies. This concentration of counterparties may impact our overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions.

We maintain credit policies with regard to our counterparties that we believe minimize our overall credit risk. These policies include (i) an evaluation of potential counterparties’ financial condition (including credit ratings), (ii) collateral requirements under certain circumstances and (iii) the use of standardized agreements which allow for netting of positive and negative exposure associated with a single counterparty. Based on our policies, exposure, credit and other reserves, we do not anticipate a material adverse effect on our financial position, results of operations or cash flows as a result of counterparty performance.

Our over-the-counter swaps and options are entered into with counterparties outside central trading organizations such as a futures, options or stock exchange. These contracts are with a number of parties, all of which have investment grade credit ratings. While we enter into derivative transactions principally with investment grade counterparties and actively monitor

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their ratings, it is nevertheless possible that from time to time losses will result from counterparty credit risk in the future.

In addition, in conjunction with the purchase of exchange-traded derivative contracts or when the market value of our derivative contracts with specific counterparties exceeds established limits, we are required to provide collateral to our counterparties, which may include posting letters of credit or placing cash in margin accounts. At June 30, 2009 and 2008, we had one outstanding letter of credit totaling $15.0 million in support of our hedging of commodity price risks associated with the sale of natural gas. Additionally, we had no cash margin deposits and $90.9 million of cash margin deposits at June 30, 2009 and 2008, respectively, associated with our commodity contract positions and over-the-counter swap partners, and we reported these amounts in the caption “Restricted Deposits” on the accompanying Consolidated and Combined Balance Sheets.

SFAS No. 157

On September 15, 2006, the FASB issued SFAS No. 157, Fair Value Measurements, (“SFAS No. 157”). In general, fair value measurements and disclosures are made in accordance with the provisions of this Statement and, while not requiring material new fair value measurements, SFAS No. 157 established a single definition of fair value in generally accepted accounting principles and expanded disclosures about fair value measurements. The provisions of this Statement apply to other accounting pronouncements that require or permit fair value measurements; the FASB having previously concluded in those accounting pronouncements that fair value is the relevant measurement attribute. On February 12, 2008, the FASB issued FASB Staff Position (“FSP”) No. FAS 157-2, Effective Date of FASB Statement No. 157, (“FSP FAS 157-2”). FSP FAS 157-2 delayed the effective date of SFAS No. 157 for all nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually).

Accordingly, we have not applied the provisions of SFAS No. 157 to (i) nonfinancial assets and liabilities initially measured at fair value in business combinations; (ii) other nonfinancial assets measured at fair value in conjunction with impairment assessments; and (iii) asset retirement obligations initially measured at fair value, although the fair value measurements we have made in these circumstances are not necessarily different from those that would be made had the provisions of SFAS No. 157 been applied. We adopted the remainder of SFAS No. 157 effective July 1, 2008, and the adoption did not have a material impact on our balance sheet, statement of operations, or statement of cash flows since we already apply its basic concepts in measuring fair value.

On October 10, 2008, the FASB issued FSP No. FAS 157-3, Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active (“FSP FAS 157-3”). FSP FAS 157-3 provides clarification regarding the application of SFAS No. 157 in inactive markets. The provisions of FSP FAS 157-3 are effective immediately. This Staff Position did not have a material impact on our Consolidated and Combined Financial Statements.

The degree of judgment utilized in measuring the fair value of financial instruments generally correlates to the level of pricing observability. Pricing observability is affected by a number of factors, including the type of financial instrument, whether the financial instrument is new to the market and the characteristics specific to the transaction. Financial instruments with readily available active quoted prices or for which fair value can be measured from actively quoted prices generally will have a higher degree of pricing observability and a lesser degree of judgment utilized in measuring fair value. Conversely, financial instruments rarely traded or not quoted will generally have less (or no) pricing observability and a higher degree of judgment utilized in measuring fair value.

SFAS No. 157 established a hierarchical disclosure framework associated with the level of pricing observability utilized in measuring fair value. This framework defined three levels of inputs to the fair value measurement process, and requires that each fair value measurement be assigned to a level corresponding to the lowest level input that is significant to the fair value measurement in its entirety. The three broad levels of inputs defined by the SFAS No. 157 hierarchy are as follows:

● Level 1 Inputs - quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date;

● Level 2 Inputs - inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. If the asset or liability has a specified (contractual) term, a Level 2 input must be observable for substantially the full term of the asset or liability; and

● Level 3 Inputs - unobservable inputs for the asset or liability. These unobservable inputs reflect the entity’s own assumptions about the assumptions that market participants would use in pricing the asset or liability, and are developed based on the best information available in the circumstances (which might include the reporting entity’s own data).

Derivative contracts can be exchange-traded or over-the-counter (“OTC”). Exchange-traded derivative contracts typically fall within Level 1 of the fair value hierarchy if they are traded in an active market. We and our affiliated companies value exchange-traded derivative contracts using quoted market prices for identical securities.

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OTC derivatives are valued using models utilizing a variety of inputs including contractual terms; commodity, interest rate and foreign currency curves; and measures of volatility. The selection of a particular model and particular inputs to value an OTC derivative contract depends upon the contractual terms of the instrument as well as the availability of pricing information in the market. We and our affiliated companies use similar models to value similar instruments. For OTC derivative contracts that trade in liquid markets, such as generic forwards and swaps, model inputs can generally be verified and model selection does not involve significant management judgment. Such contracts are typically classified within Level 2 of the fair value hierarchy.

Certain OTC derivative contracts trade in less liquid markets with limited pricing information, and the determination of fair value for these derivative contracts is inherently more difficult. Such contracts are classified within Level 3 of the fair value hierarchy. The valuations of these less liquid OTC derivatives are typically impacted by Level 1 and/or Level 2 inputs that can be observed in the market, as well as unobservable Level 3 inputs. Use of a different valuation model or different valuation input values could produce a significantly different estimate of fair value. However, derivative contracts valued using inputs unobservable in active markets are generally not material to our financial statements.

When appropriate, valuations are adjusted for various factors including credit considerations. Such adjustments are generally based on available market evidence. In the absence of such evidence, management’s best estimate is used.

The following tables summarize the fair value measurements of our energy commodity derivative contracts based on the three levels established by SFAS No. 157:

	Asset Fair Value Measurements as of June 30, 2009 Using
	Total		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(In thousands)
Energy Commodity Derivative Contracts	$	46,178	$	18,742	$	26,877	$	559

	Liability Fair Value Measurements as of June 30, 2009 Using
	Total			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
	(In thousands)
Energy Commodity Derivative Contracts	$	(9,032	)	$	-	$	(1,351	)	$	(7,681	)

The table below provides a summary of changes in the fair value of our Level 3 energy commodity derivative contracts:

	Year Ended June 30, 2009
	(In thousands)
Net Asset (Liability)
Beginning Balance	$	15,774
Realized and Unrealized Net Gains		1,845
Settlements		(24,741	)
Balance as of June 30, 2009	$	(7,122	)
Change in Unrealized Net Gains Relating to
Contracts Still Held as of June 30, 2009	$	(6,286	)

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June 2009 NGPL PipeCo LLC Financials

9.  Commitments and Contingent Liabilities

(A) Leases

Expenses incurred under operating leases were $1.5 million and $3.1 million for the years ended June 30, 2009 and 2008, respectively. Future minimum commitments under major non-cancelable operating leases as of June 30, 2009 are as follows:

Fiscal Year	Operating Leases
	(In thousands)
2010	$	380
2011		392
2012		403
2013		416
2014		428
Thereafter		2,130
Total	$	4,149

(B) Capital Expenditures

Approximately $25.1 million had been committed for the purchase of property, plant and equipment at June 30, 2009.

10. Risks, Uncertainties and Concentration of Credit Risk

Our operations consist principally of natural gas transportation and storage services in interstate commerce. Our operations are principally regulated by the FERC (see Note 3). As such, our results of operations, cash flows and financial condition are subject to certain risks which include, among other things:

● a general economic downturn could adversely affect the demand for our products and services and our ability to secure investment capital necessary to maintain or expand our systems and operations;

● the current or future distressed financial condition of customers could have an adverse impact on our operations in the event these customers are unable to pay us for the products or services we provide;

● increased competition from existing or future natural gas transmission and storage operators could lead to lower levels of profits and adversely impact our ability to recontract for expiring transportation and storage capacity at favorable rates;

● the rates we charge shippers on our pipeline systems are subject to regulatory approval and oversight and could be negatively impacted by rate proceedings;

● environmental and other regulations could result in increased operating costs and capital costs; and

● our exposure to volatility in natural gas prices could adversely impact our earnings and cash flows.

With respect to our hedging activities (see Note 8), we enter into derivative contracts with a number of parties, all of which have investment grade credit ratings. While we enter into derivative transactions principally with investment grade counterparties and actively monitor their ratings, it is nevertheless possible that from time to time losses will result from counterparty credit risk in the future.

In addition, virtually all of our revenues are derived from companies in the domestic natural gas industry. This concentration could impact our overall exposure to credit risk since these customers may be impacted by similar economic or other conditions. To help mitigate our credit risk, we evaluate our customers’ financial condition and, where appropriate, require prepayment, collateral or financial guarantees and letters of credit. In support of credit extended to certain customers, we had received prepayments of $1.8 million and $2.4 million as of June 30, 2009 and 2008, respectively, included in the caption “Current Liabilities: Other” in the accompanying Consolidated and Combined Balance Sheet.

Natural had no customers that accounted for more than 10% of total revenues in calendar 2008.

Natural’s principal delivery market area encompasses the states of Illinois, Indiana and Iowa and secondary markets in portions of Wisconsin, Nebraska, Kansas, Missouri and Arkansas. Natural is the largest transporter of natural gas to the Chicago market. In calendar 2008, Natural delivered an average of 2.03 trillion Btus per day of natural gas to this market.  Natural’s storage capacity is largely located near its transportation delivery markets, effectively serving the same customer

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base. Natural has a number of individually significant customers, including local natural gas distribution companies in the greater Chicago area and major natural gas marketers and, during calendar 2008, approximately 50% of its operating revenues from tariff services were attributable to its nine largest customers.

11.  Recent Accounting Pronouncements

SFAS No. 157 and FASB Staff Position Nos. FAS 157-2 and FAS 157-3

For information on SFAS No. 157 and FASB Staff Position Nos. FAS 157-2 and FAS 157-3, see Note 7, Risk Management.

SFAS No. 159

On February 15, 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities. This Statement provides companies with an option to report selected financial assets and liabilities at fair value. The Statement’s objective is to reduce both complexity in accounting for financial instruments and the volatility in earnings caused by measuring related assets and liabilities differently. The Statement also establishes presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities.

SFAS No. 159 requires companies to provide additional information that will help investors and other users of financial statements to more easily understand the effect of the company’s choice to use fair value on its earnings. It also requires entities to display the fair value of those assets and liabilities for which the company has chosen to use fair value on the face of the balance sheet. The Statement does not eliminate disclosure requirements included in other accounting standards, including requirements for disclosures about fair value measurements included in SFAS No. 157, discussed in Note 7, and SFAS No. 107, Disclosures about Fair Value of Financial Instruments.

This Statement was adopted by us effective July 1, 2008, at which time no financial assets or liabilities not previously required to be recorded at fair value by other authoritative literature were designated to be recorded at fair value. As such, the adoption of this Statement did not have any impact on our Consolidated and Combined Financial Statements.

SFAS. No. 141 (R) and FASB Staff Position 141(R)-1

On December 4, 2007, the FASB issued SFAS No. 141 (revised 2007), Business Combinations. Although this statement amends and replaces SFAS No. 141, it retains the fundamental requirements in SFAS No. 141 that (i) the purchase method of accounting be used for all business combinations; and (ii) an acquirer be identified for each business combination. This Statement applies to all transactions or other events in which an entity (the acquirer) obtains control of one or more businesses (the acquiree), including combinations achieved without the transfer of consideration; however, this Statement does not apply to a combination between entities or businesses under common control.

Significant provisions of SFAS No. 141(R) concern principles and requirements for how an acquirer (i) recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree; (ii) recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase; and (iii) determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. This Statement applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008 (July 1, 2009 for us). Early adoption is not permitted. We do not anticipate that the adoption of th is Statement will have a material effect on our Consolidated and Combined Financial Statements.

On April 1, 2009, the FASB issued FSP No. FAS 141(R)-1, Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies. This FSPamends the provisions related to the initial recognition and measurement, subsequent measurement and disclosure of assets and liabilities arising from contingencies in a business combination under SFAS No. 141(R). This FSP carries forward the requirements in SFAS No. 141(R) for acquired contingencies, which would require that such contingencies be recognized at fair value on the acquisition date if fair value can be reasonably estimated during the allocation period. Otherwise, companies would typically account for the acquired contingencies in accordance with SFAS No. 5, Accounting for Contingencies. This FSP has the same effective date as SFAS No. 141(R), and we do not anticipate that its adoption will have a material effect on our Consolidated and Combined Financial Statements.

SFAS No. 160

On December 4, 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements – an amendment of ARB No. 51. This Statement changes the accounting and reporting for noncontrolling interests in consolidated

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financial statements. A noncontrolling interest, sometimes referred to as a minority interest, is the portion of equity in a subsidiary not attributable, directly or indirectly, to a parent.

Specifically, SFAS No. 160 establishes accounting and reporting standards that require (i) the ownership interests in subsidiaries held by parties other than the parent to be clearly identified, labeled, and presented in the consolidated balance sheet within equity, but separate from the parent’s equity; (ii) the equity amount of consolidated net income attributable to the parent and to the noncontrolling interest to be clearly identified and presented on the face of the consolidated income statement (consolidated net income and comprehensive income will be determined without deducting minority interest, however, earnings-per-share information will continue to be calculated on the basis of the net income attributable to the parent’s shareholders); and (iii) changes in a parent’s ownership interest while the parent retains its controlling financial interest in its subsidiary to be accounted for consistently and similarly—as equity transactions.

This Statement is effective for fiscal years, and interim periods within those fiscal years beginning on or after December 15, 2008 (July 1, 2009 for us). Early adoption is not permitted. SFAS No. 160 is to be applied prospectively as of the beginning of the fiscal year in which it is initially applied, except for its presentation and disclosure requirements, which are to be applied retrospectively for all periods presented. We do not anticipate that the adoption of this statement will have a material effect on our Consolidated and Combined Financial Statements.

SFAS No. 161

On March 19, 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities. This Statement amends SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities and is intended to help investors better understand how derivative instruments and hedging activities affect an entity’s financial position, financial performance and cash flows through enhanced disclosure requirements. The enhanced disclosures include, among other things, (i) a tabular summary of the fair value of derivative instruments and their gains and losses, (ii) disclosure of derivative features that are credit-risk–related to provide more information regarding an entity’s liquidity, and (iii) cross-referencing within footnotes to make it easier for financial statement users to locate important information about derivative instruments.

This Statement is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008 (July 1, 2009 for us). Early application is encouraged. We do not anticipate that the adoption of this statement will have a material effect on our Consolidated and Combined Financial Statements.

FSP No. FAS 142-3

On April 25, 2008, the FASB issued FSP No. FAS 142-3, Determination of the Useful Life of Intangible Assets. This FSPamends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS No. 142, Goodwill and Other Intangible Assets. This FSP is effective for financial statements issued for fiscal years beginning after December 15, 2008 (July 1, 2009 for us), and interim periods within those fiscal years. Early adoption is prohibited. We do not anticipate that the adoption of this FSP will have a material effect on our Consolidated and Combined Financial Statements.

EITF 08-6

On November 24, 2008, the FASB ratified the consensus reached by the Emerging Issues Task Force (“EITF”) on Issue No. 08-6, Equity Method Investment Accounting Considerations (“EITF 08-6”). EITF 08-6 clarifies certain accounting and impairment considerations involving equity method investments. This Issue is effective for fiscal years beginning on or after December 15, 2008 (July 1, 2009 for us), and interim periods within those fiscal years. The guidance in EITF 08-6 is to be applied prospectively for all financial statements presented. We do not anticipate that the adoption of EITF 08-6 will have a material effect on our Consolidated and Combined Financial Statements.

FSP No. FAS 157-4

FSP No. FAS 107-1 and APB 28-1

FSP No. FAS 115-2 and FAS 124-2

On April 9, 2009, the FASB issued three separate FSPs intended to provide additional application guidance and enhance disclosures regarding fair value measurements and impairments of securities. FSP No. FAS 157-4, Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly, provides guidelines for making fair value measurements more consistent with the principles presented in SFAS No. 157, Fair Value Measurements. This FSP provides additional guidance to highlight and expand on the factors that should be considered in estimating fair value when there has been a significant decrease in market activity for a financia l asset.

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FSP No. FAS 107-1 and APB 28-1, Interim Disclosures about Fair Value of Financial Instruments, enhances consistency in financial reporting by increasing the frequency of fair value disclosures from annual to quarterly, in order to provide financial statement users with more timely information about the effects of current market conditions on their financial instruments. This FSP requires us to disclose in our interim financial statements the fair value of all financial instruments within the scope of SFAS No. 107, Disclosures about Fair Value of Financial Instruments, as well as the method(s) and significant assumptions we use to estimate the fair value of those financial instruments.

FSP No. FAS 115-2 and FAS 124-2, Recognition and Presentation of Other-Than-Temporary Impairments, provides additional guidance designed to create greater clarity and consistency in accounting for and presenting impairment losses on securities. This FSP changes (i) the method for determining whether an other-than-temporary impairment exists for debt securities and (ii) the amount of an impairment charge to be recorded in earnings.

For us, each of these three FSPs became effective June 30, 2009; however, the adoption of these FSPs did not have a material impact on our Consolidated and Combined Financial Statements.

SFAS No. 165

On May 28, 2009, the FASB issued SFAS No. 165, Subsequent Events. This Statement establishes general standards of accounting for and disclosure of subsequent events—events or transactions that occur after the balance sheet date but before financial statements are issued or are available to be issued. It requires the disclosure of the date through which an entity has evaluated subsequent events and the basis for that date. This Statement was effective for interim and annual periods ending after June 15, 2009. For us, this Statement became effective June 30, 2009, and the adoption of this Statement did not have a material impact on our Consolidated and Combined Financial Statements. For more information on our disclosure of subsequent events, see Note 1.

SFAS Nos. 166 and 167

On June 12, 2009, the FASB published SFAS No. 166, Accounting for Transfers of Financial Assets—an amendment of FASB Statement No. 140 and SFAS No. 167, Amendments to FASB Interpretation No. 46(R). The Statements change the way entities account for securitizations and special-purpose entities. SFAS No. 166 is a revision of SFAS No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities, and will require more information about transfers of financial assets, including securitization transactions, and where companies have continuing exposure to the risks related to transferred financial assets. SFAS No. 167 is a revis ion to FASB Interpretation No. 46(R), Consolidation of Variable Interest Entities, and changes how a company determines when an entity that is insufficiently capitalized or is not controlled through voting (or similar rights) should be consolidated.

Both Statements Nos. 166 and 167 will be effective at the start of an entity’s first fiscal year beginning after November 15, 2009 (July 1, 2010 for us). We do not expect the adoption of these Statements to have a material impact on our Consolidated and Combined Financial Statements.

SFAS No. 168 and the Financial Accounting Standards Board’s Accounting Standards Codification

On June 3, 2009, the FASB voted to approve its Accounting Standards Codification as the single source of authoritative nongovernmental U.S. GAAP. The move was officially effected by the June 29, 2009 issuance of SFAS No. 168, The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principle—a replacement of SFAS No. 162. On the effective date of this Statement, the Codification will supersede all then-existing non-SEC accounting and reporting standards. All other nongrandfathered non-SEC accounting literature not included in the Codification will become nonauthoritative. In other words, the GAAP hierarchy will be modified to include only two levels of GAAP: authoritative and nonauthoritative.

While the Codification does not change U.S. GAAP, it introduces a new structure—reorganizing the thousands of pre-Codification U.S. GAAP pronouncements into approximately 90 accounting topics and displaying all topics consistently. Rules and interpretive releases of the SEC under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants, and the Codification includes relevant SEC guidance that follows the same topical structure in separate sections. All guidance contained in the Codification carries an equal level of authority.

The Codification will be effective for interim and annual periods ending after September 15, 2009. The adoption of the Accounting Standards Codification will affect the way we reference U.S. GAAP in our Consolidated and Combined Financial Statements and in our accounting policies; however, we do not expect the adoption to have any direct effect on our Consolidated and Combined Financial Statements.

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June 2009 NGPL PipeCo LLC Financials

Management’s Discussion and Analysis of Financial Condition and Results of Operations (Unaudited)

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June 2009 NGPL PipeCo LLC Financials

General

In this report, unless the context requires otherwise, references to “we,” “us,” “our,” or the “Company” are intended to mean NGPL PipeCo LLC (“NGPL PipeCo”) and its consolidated subsidiaries. The following discussion should be read in conjunction with the accompanying Consolidated and Combined Financial Statements and related Notes. NGPL PipeCo is 80% owned by Myria Acquisition LLC (formerly Myria Acquisition, Inc.), a wholly owned subsidiary of Myria Holdings Inc. and 20% owned by NGPL Holdco Inc., a wholly owned subsidiary of Kinder Morgan, Inc. (“Kinder Morgan”). Kinder Morgan, Inc.’s name was changed to Knight Inc. on May 31, 2007, upon completion of the “Going Private” transaction (see Note 2(Q) of the accompanying Notes to Consolidated and Combined Financial Statements) and was changed back to Kinder Morgan, Inc. in July 2009. Kinder Morgan operates our assets pursuant to the 15-year Operations and Reimbursement Agreement for Natural Gas Pipeline Company of America LLC dated as of February 15, 2008 (the “Operating Agreement”).

The principal wholly owned subsidiary of NGPL PipeCo is Natural Gas Pipeline Company of America LLC (“Natural”), which owns and operates a major interstate natural gas pipeline transmission and storage system, consisting primarily of two major interconnected transmission pipelines terminating in the Chicago, Illinois metropolitan area. Natural’s Amarillo Line originates in the West Texas and New Mexico producing areas and is comprised of approximately 4,400 miles of mainline and various small-diameter pipelines. The other major pipeline, the Gulf Coast Line, originates in the Gulf Coast areas of Texas and Louisiana and consists of approximately 4,100 miles of mainline and various small-diameter pipelines. These two main pipelines are connected at points in Texas and Oklahoma by Natural’s 800-mile Amarillo/Gu lf Coast pipeline. Natural also operates an approximate 3-mile natural gas pipeline in northern Illinois, which is owned by Kinder Morgan Illinois Pipeline LLC, our wholly owned subsidiary. Natural provides 360,000 Dth per day of capacity to Kinder Morgan Illinois Pipeline LLC under a long-term operating lease.

Natural owns investments in two joint ventures, Horizon Pipeline Company, L.L.C. (“Horizon”), which is 50% owned and accounted for under the equity method, and Canyon Creek Compression Company (“Canyon”), which is 70% owned and is consolidated into the accompanying Consolidated and Combined Financial Statements. We recently made a regulatory abandonment filing on Canyon (see Note 3 of the accompanying Notes to Consolidated and Combined Financial Statements for additional information).

Natural’s interstate natural gas pipeline and storage operations, as well as those of its joint venture investees, are subject to regulation by the Federal Energy Regulatory Commission (the “FERC”). The FERC regulates, among other things, rates and charges for transportation and storage of natural gas in interstate commerce, the construction and operation of interstate pipeline and storage facilities and the accounting and record keeping requirements of interstate pipelines.

Critical Accounting Policies and Estimates

Our discussion and analysis of financial condition and results of operations are based on our Consolidated and Combined Financial Statements, prepared in accordance with accounting principles generally accepted in the United States of America and contained within this report. Certain amounts included in or affecting our financial statements and related disclosure must be estimated, requiring us to make certain assumptions with respect to values or conditions, which cannot be known with certainty at the time the financial statements are prepared. The reported amounts of our assets and liabilities, revenues and expenses and associated disclosures with respect to contingent assets and obligations are necessarily affected by these estimates. We evaluate these estimates on an ongoing basis, utilizing historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from our estimates.

In preparing our financial statements and related disclosures, we must use estimates in determining the economic useful lives of our assets, the fair values and estimated future cash flows used to determine the recovery or possible impairment charges associated with long-lived assets, the effective income tax rate to apply to our pre-tax income, provisions for environmental reserves, provisions for uncollectible accounts receivable, and various other recorded or disclosed amounts. Certain of these accounting estimates are of more significance in our financial statement preparation process than others.

Intangible assets are those assets which provide future economic benefit but have no physical substance. We account for our intangible assets according to the provisions of SFAS No. 141, Business Combinations and SFAS No. 142, Goodwill and Other Intangible Assets. These accounting pronouncements introduced the concept of indefinite life intangible assets and provided that all identifiable intangible assets having indefinite useful economic lives, including goodwill, will not be subject to periodic amortization. Such assets are not to be amortized unless and until their lives are determined to be finite. Instead, the carrying amount of a recognized intangible asset with an indefinite useful life must be tested for impair ment annually or on an interim basis if events or circumstances indicate that the fair value of the asset has decreased below its carrying value. We use an annual impairment measurement date of May 31.

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June 2009 NGPL PipeCo LLC Financials

As a result of the Going Private transaction, as of June 30, 2009 and 2008, our goodwill was $5.014 billion (see Note 2(Q) of the accompanying Notes to Consolidated and Combined Financial Statements). We tested the goodwill associated with the Going Private transaction for impairment at May 31, 2009 and concluded that no impairment was required.

Due to the nature of the natural gas pipeline and storage business, we are required to make estimates for services rendered but for which actual metered volumes are not available at reporting dates. We believe that our estimates, which are revised to the  actual metered volumes in the next accounting month, provide acceptable approximations of the actual revenue earned during any period, especially given that the majority of our revenues in the pipeline business are derived from demand charges, which do not vary with the actual amount of gas transported.

With respect to our environmental exposure, we utilize both internal staff and external experts to assist us in identifying environmental issues and in estimating the costs and timing of remediation efforts. These estimates are affected by the choice of remediation methods as well as the expected timing and length of the effort. Often, as the remediation evaluation and effort progresses, additional information is obtained, requiring revisions to estimated costs. These revisions are reflected in our income in the period in which they are reasonably determinable.

We are subject to litigation as a result of our business operations and transactions. We utilize both internal and external counsel in evaluating our potential exposure to adverse outcomes from judgments or settlements. To the extent that actual outcomes differ from our estimates, or additional facts and circumstances cause us to revise our estimates, our earnings will be affected.

We record a valuation allowance to reduce our deferred tax assets to an amount that is more likely than not to be realized. While we have considered future taxable income and prudent and feasible tax planning strategies in determining the amount of our valuation allowance, any change in the amount that we expect to ultimately realize will be included in income in the period in which such a determination is reached. In addition, we do business in a number of states with differing laws concerning how income subject to each state’s tax structure is measured and at what effective rate such income is taxed. Therefore, we must make estimates of how our income before income taxes will be apportioned among the various states in order to arrive at an overall effective tax rate. Changes in our effective rate, including any effect on pr eviously recorded deferred taxes, are recorded in the period in which the need for such change is identified.

We enter into derivative contracts (natural gas futures, swaps and options) solely for the purpose of mitigating risks that accompany our normal business activities, principally the price of natural gas and associated transportation. We account for these derivative transactions as hedges in accordance with authoritative accounting guidelines, marking the derivatives to market at each reporting date, with the unrealized gains and losses recognized as part of comprehensive income. Any inefficiency in the performance of the hedge is recognized in income currently and, ultimately, the financial results of the hedge are recognized concurrently with the financial results of the underlying hedged item. All but an insignificant amount of our natural gas related derivatives are for terms of 18 months or less, allowing us to utilize widely a vailable, published forward pricing curves in determining all of our appropriate market values.

Results of Operations

	Year Ended June 30,
	2009			2008
	(In thousands)
Operating Revenues	$	1,325,196		$	1,191,329
Purchases and Other Costs of Sales		(399,301	)		(326,631	)
Other Operating Expenses, Excluding Depreciation		(244,256	)		(215,580	)
Operating Income Before Depreciation		681,639			649,118
Other Income and (Expenses), Excluding Interest Expense		11,242			17,706
Earnings Before Interest, Taxes, Depreciation and Amortization (EBITDA)		692,881			666,824
Depreciation Expense		(77,020	)		(75,126	)
Interest Expense, Net		(212,807	)		(157,350	)
Income Before Income Taxes		403,054			434,348
Income Taxes		(165,188	)		(161,371	)
Net Income	$	237,866		$	272,977

Operating revenues increased by $133.9 million (11%) from the year ended June 30, 2008 to the year ended June 30, 2009. Gross profit (operating revenues less purchases and other costs of sales) increased $61.2 million (7%) from the year ended June 30, 2008 to the year ended June 30, 2009. Results for fiscal 2009, relative to 2008, included an increase of $96.5 million in gross profit from transportation and storage services, principally resulting from successful re-contracting at higher rates

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June 2009 NGPL PipeCo LLC Financials

and increased contract volumes. This positive impact was partially offset by (i) an approximately $18.8 million increase in charges to reduce the carrying value of our current storage gas inventories to reflect the reduced market price of natural gas and (ii) a $16.1 million decrease in gross profits from operational gas sales due principally to the net effects of (1) lower sales volumes primarily driven by reduced cushion gas sales due to the completion of storage expansion projects, (2) increased operational sales volumes from fuel recoveries and (3) reduced natural gas prices. Natural’s operational natural gas sales are primarily made possible by its collection of fuel in-kind pursuant to its transportation tariffs and recovery of storage cushion gas volumes. Our future revenues from operational natural gas sales could be affected by, among other things, the market price of natural gas, the volume of fuel collected in-kind pursuant to our tariffs and our recovery and sales of storage cushion gas.

Other operating expenses, excluding depreciation, increased by $28.7 million (13%) from the year ended June 30, 2008 to the year ended June 30, 2009. Other operating expenses were negatively impacted in fiscal 2009, relative to 2008, principally by (i) a $9.1 million increase in electric compression costs, (ii) the fact that fiscal 2008 results included $6.1 million of emission credit sales, (iii) an additional $5.8 million in 2009 for expenses related to employee benefits, (iv) a $5.5 million increase in transmission mains damage prevention costs, (v) a $5.3 million increase in taxes other than income, principally property taxes, (vi) a $3.7 million increase in compressor station labor and expenses and (vii) $3.1 million in costs related to Hurricane Ike damage. These negative impacts in other operating expenses were partially off set by (i) a $5.8 million gain on the sale of land in fiscal 2009 and (ii) a $5.6 million decrease in costs from stress corrosion cracking rehabilitation projects and pipeline integrity management programs.

Other income and (expenses), excluding interest expense, decreased $6.5 million (37%) from the year ended June 30, 2008 to the year ended June 30, 2009. Other income and expenses were negatively impacted in fiscal 2009, relative to 2008, by a $19.2 million reduction in interest income, principally due to the closing of the Myria Transaction and the release of financing proceeds which generated the interest income from escrow (see Note 1 of the accompanying Notes to Consolidated and Combined Financial Statements). This negative impact was partially offset by an $11.6 million reduction in Corporate Charges from Kinder Morgan, which were terminated after calendar year 2008.

Interest expense, net increased by $55.5 million (35%) from the year ended June 30, 2008 to the year ended June 30, 2009. This increase resulted principally from (i) the net increase in our long-term debt from the issuance of $3.0 billion of senior notes and (ii) interest expense on our revolving credit facility (see Note 7 of the accompanying Notes to Consolidated and Combined Financial Statements).

Income tax expense increased by $3.8 million (2%) from the year ended June 30, 2008 to the year ended June 30, 2009. This increase resulted from the net effects of an increase in our effective tax rate from 37.1% to 41.0%, partially offset by a $31.3 million (7%) reduction in our pre-tax income. The increase in our effective tax rate was principally attributable to an increase in our state income tax rate due to increases in our apportionment factors in several states resulting from our no longer being included in the consolidated or combined state income tax returns of Kinder Morgan after February 14, 2008. See Note 6 of the accompanying Notes to Consolidated and Combined Financial Statements for additional information regarding income taxes.

Substantially all of Natural’s pipeline capacity is committed under firm transportation contracts ranging from one to six years. Under these contracts, over 90% of the revenues are derived from a demand charge and, therefore, are collected regardless of the volume of gas actually transported. The principal impact of the actual level of gas transported is on fuel recoveries, which are received in-kind as volumes move on the system. Approximately 42% of the total transportation volumes committed under Natural’s long-term firm transportation contracts in effect on June 30, 2009 had remaining terms of less than three years. Contracts representing approximately 12% of Natural’s total long-haul, contracted firm transport capacity as of June 30, 2009 are scheduled to expire during the following twelve months. Natural con tinues to pursue the renegotiation, extension and/or replacement of expiring contracts.

Our principal exposure to market variability is related to the variation in natural gas prices and basis differentials, which can affect our gross profit earned. “Basis differential” is a term that refers to the difference in natural gas prices between two locations or two points in time. These price differences can be affected by, among other things, natural gas supply and demand, available transportation capacity, storage inventories and deliverability, prices of alternative fuels and weather conditions. We have attempted to reduce our exposure to this form of market variability by pursuing long-term, fixed-rate type contract agreements to utilize the capacity on Natural’s system. In addition, we utilize a comprehensive risk management program to mitigate our exposure to changes in the market price of natural ga s and associated transportation.

Our interstate pipeline and storage systems are subject to rate regulation under the jurisdiction of the FERC. Currently, there are no material proceedings challenging the rates (which include reservation, commodity, surcharges, fuel and gas lost and unaccounted for) on any of our pipeline systems. Nonetheless, shippers on our pipelines do have rights, under certain circumstances prescribed by applicable regulations, to challenge the rates we charge. There can be no assurance that we will not face future challenges to the rates we receive for services on our pipeline systems, including our recovery of fuel in-kind

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from shippers, which could have material impacts on our business, financial condition and results of operations.

Liquidity and Capital Resources

Primary Cash Requirements

Our primary cash requirements, in addition to normal operating, general and administrative expenses, are for debt service,  capital expenditures to sustain our current pipeline and storage systems and for system expansions, cash payments to Myria for the purpose of making income tax payments and cash distributions to our members. Our capital expenditures, other than sustaining capital expenditures, and our cash distributions to our members are discretionary. Our capital expenditures for calendar 2009 are currently expected to be approximately $92.1 million, of which $27.7 had been expended as of June 30, 2009. We expect to fund these expenditures principally with existing cash and cash flows from operating activities. In addition to utilizing cash generated from operations, we could meet these cash requirements through bo rrowings under our credit facilities or by issuing additional long-term debt.

Invested Capital

The following table illustrates the sources of our invested capital.

	June 30,
	2009			2008
	(Dollars in thousands)
Long-term Debt	$	3,000,000	45.7%	$	3,000,000	45.9%
Minority Interests in Equity of Subsidiaries		497	0.0%		811	0.0%
Members’ Equity		3,558,043	54.3%		3,528,442	54.1%
Total Invested Capital	$	6,558,540	100.0%	$	6,529,253	100.0%

Short-term Liquidity

In addition to cash flows from operations, our principal source of short-term liquidity is our revolving credit facility. As of June 30, 2009, we had available a $200 million five-year credit facility dated February 15, 2008. We had $28.3 million and $172.0 million of borrowings outstanding under this facility at June 30, 2009 and 2008, respectively. After inclusion of applicable outstanding letters of credit that reduce our borrowing capacity under the credit facility, our remaining available borrowing capacity under the facility was $156.6 million and $12.9 million at June 30, 2009 and 2008, respectively.

Long-term Debt

On December 21, 2007, NGPL PipeCo LLC issued $1.25 billion aggregate principal amount of 6.514% senior notes due December 15, 2012, $1.25 billion aggregate principal amount of 7.119% senior notes due December 15, 2017 and $0.5 billion aggregate principal amount of 7.768% senior notes due December 15, 2037. The 2012, 2017 and 2037 senior notes are redeemable in whole or in part, at NGPL PipeCo LLC’s option at any time, at a price equal to 100% of the principal amount of the notes plus accrued interest to the redemption date plus a make-whole premium. The indenture for the senior notes includes covenants that, among other things, limit NGPL PipeCo’s ability and the ability of its subsidiaries to (i) create liens that secure debt, (ii) enter into sale-leaseback transactions, (iii) incur debt, subject to a leverage tes t, (iv) enter into business outside its present business and (v) merge or consolidate with, or sell, lease or transfer its assets substantially as an entirety to another entity. In addition, if NGPL PipeCo experiences certain kinds of changes of control coupled with a ratings downgrade such that the notes cease to have an investment grade rating, it must give the holders of the notes the opportunity to sell their senior notes to NGPL PipeCo at 101% of their principal amount, plus accrued and unpaid interest.

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Aggregate Contractual Obligations

			Amount of Commitment Expiration Per Period
	Total		Less than 1 year		2-3 years		4-5 years		After 5 years
	(In millions)
Contractual Obligations:
Long-term Debt:
Principal Payments	$	3,000.0	$	-	$	-	$	1,250.0	$	1,750.0
Interest Payments		2,148.3		209.3		418.5		296.4		1,224.1
Notes Payable		28.3		28.3		-		-		-
Operating Leases		4.1		0.4		0.8		0.8		2.1
Total Contractual Cash Obligations	$	5,180.7	$	238.0	$	419.3	$	1,547.2	$	2,976.2
Other Commercial Commitments:
Letters of Credit	$	15.1	$	15.1	$	-	$	-	$	-
Capital Expenditures	$	25.1	$	25.1	$	-	$	-	$	-

Cash Flows

The following discussion of cash flows should be read in conjunction with the accompanying Consolidated and Combined Statements of Cash Flows and related supplemental disclosures. All highly liquid investments purchased with an original maturity of three months or less are considered to be cash equivalents.

Net Cash Flows from Operating Activities

Net cash flows provided by operating activities increased from $252.2 million for the year ended June 30, 2008 to $443.6 million for the year ended June 30, 2009, an increase of $191.4 million (75.9%). Cash flows from operating activities were positively impacted in the year ended June 30, 2009, relative to the prior year by (i) a $15.3 million increase in net income, adjusted for certain non-cash items, (ii) an $83.6 million increase in cash flows attributable to changes in gas in underground storage, (iii) an $83.4 million increase in cash flows attributable to changes in other working capital items and (iv) a $10.6 million increase in cash flows attributable to changes in other long-term assets and liabilities. These positive impacts were partially offset by a $1.5 million increase in cash outflows for contributions to a volunta ry employee benefit association.

Net Cash Flows from Investing Activities

Net cash flows from investing activities increased from a use of cash of $265.6 million for the year ended June 30, 2008 to a source of cash of $5.2 million for the year ended June 30, 2009, an increase of $270.8 million. This increase in cash flows principally resulted from (i) a $103.6 million reduction in cash outflows for capital expenditures due, in part, to reduced expenditures for storage expansion projects and (ii) a $181.8 million increase in cash flows from restricted deposits  related to our hedging activities upon the return to us, in fiscal 2009, of cash posted as collateral in fiscal 2008. These positive impacts were partially offset by (i) a $10.2 million reduction in cash flows associated with interest earned on financing proceeds held in escrow pending the closing of the Myria transaction in February 2008 and (ii) a $3.6 million reduction in proceeds from sales of assets.

Net Cash Flows from Financing  Activities

Net cash flows from financing activities decreased from a source of cash of $29.8 million for the year ended June 30, 2008 to a use of cash of $466.2 million for the year ended June 30, 2009, a decrease of $496.0 million. This decrease in cash flows principally resulted from the offsetting effects of (i) $3.0 billion in long-term debt proceeds received in fiscal 2008, (ii) $2.85 billion paid in fiscal 2008 to retire a note payable to Kinder Morgan, (iii) a decrease of $315.7 million in net cash flows from short-term financing and (iv) an increase of $44.1 million in distributions to members.

Fair Value Measurement

SFAS No. 157, Fair Value Measurements establishes a hierarchal disclosure framework associated with the level of pricing observability utilized in measuring fair value. The hierarchy of valuation techniques is based upon whether the inputs to those valuation techniques reflect assumptions other market participants would use based upon market data obtained from independent sources (observable inputs) or reflect a company’s own assumptions of market participant valuation (unobservable inputs). This framework defines three levels of inputs to the fair value measurement process, and requires that each fair value measurement be assigned to a level corresponding to the lowest level input that is significant to the fair value measurement in its entirety. In accordance with SFA S No. 157, the lowest level of fair value hierarchy based on these two

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types of inputs is designated as Level 3 and is based on prices or valuations that require inputs that are both significant to the fair value measurement and unobservable.

As of June 30, 2009, the fair value of our derivative contracts classified as Level 3 under the established fair value hierarchy consisted principally of natural basis swaps and natural gas options. Basis swaps are used in connection with another derivative contract to reduce hedge ineffectiveness by reducing a basis difference between a hedged exposure and a derivative contract. Natural gas options are used to offset the exposure related to certain physical contracts.

The following table summarizes the total fair value asset and liability measurements of our Level 3 energy commodity derivative contracts in accordance with SFAS No. 157.

	Significant Unobservable Inputs (Level 3) At June 30, 2009
	Assets		Liabilities
	(In thousands)
Natural Gas Basis Swaps	$	559	$	7,681

There were no transfers into or out of Level 3 during the period.

The valuation techniques used for the above Level 3 input derivative contracts are as follows:

● Natural gas basis swaps—values obtained through a pricing service, derived by combining raw inputs from the New York Mercantile Exchange (referred to in this report as NYMEX) with proprietary quantitative models and processes. Although the prices are originating from a liquid market (NYMEX), we believe the incremental effort to further validate these prices would take undue effort and would not materially alter the assumptions. As a result, we have classified the valuation of these derivatives as Level 3.

For our energy commodity derivative contracts, the most observable inputs available are used to determine the fair value of each contract. In the absence of a quoted price for an identical contract in an active market, we use broker quotes for identical or similar contracts, or internally prepared valuation models as primary inputs to determine fair value. No adjustments were made to quotes or prices obtained from brokers and pricing services, and our valuation methods have not changed during the year ended June 30, 2009.

When appropriate, valuations are adjusted for various factors including credit considerations. Such adjustments are generally based on available market evidence, including but not limited to our credit default swap quotes as of June 30, 2009. Collateral agreements with our counterparties serve to reduce our credit exposure and are considered in the adjustment. We adjust the fair value measurements of our energy commodity derivative contracts for credit risk in accordance with SFAS No. 157, and as of June 30, 2009, our consolidated Accumulated Other Comprehensive Income (Loss) balance included a loss of $0.25 million related to discounting the value of our energy commodity derivative net assets for the effect of credit risk.

With the exception of the ineffective portion of our derivative contracts, our energy commodity derivative contracts are accounted for as cash flow hedges. In accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities and associated amendments (“SFAS No. 133”), gains and losses associated with cash flow hedges are reported in “Accumulated Other Comprehensive Income (Loss)” in the accompanying Consolidated and Combined Balance Sheets.

Litigation and Environmental

Refer to Notes 4(A) and 4(B) of the accompanying Notes to Consolidated and Combined Financial Statements for information on our pending environmental and litigation matters, respectively. We believe we have established adequate environmental and legal reserves such that the resolution of pending environmental matters and litigation will not have a material adverse impact on our business, cash flows, financial position or results of operations. However, changing circumstances could cause these matters to have a material adverse impact.

Regulation

The Pipeline Safety Improvement Act of 2002 was signed into law on December 17, 2002, providing guidelines in the areas of testing, education, training and communication. The Act requires pipeline companies to perform integrity tests on natural gas transmission pipelines that exist in high population density areas that are designated as High Consequence Areas. Pipeline companies are required to perform the integrity tests within ten years of the date of enactment and must perform subsequent integrity tests on a seven year cycle. At least 50% of the highest risk segments must be tested within five years of the enactment date. The risk ratings are based on numerous factors, including the population density in the geographic regions served by a particular pipeline, as well as the age and condition of the pipeline and its protective co ating. Testing

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consists of hydrostatic testing, internal electronic testing, or direct assessment of the piping. In addition to the pipeline integrity tests, pipeline companies must implement a qualification program to make certain that employees are properly trained. The United States Department of Transportation has approved our qualification program. We believe that we are in substantial compliance with this law’s requirements and have integrated appropriate aspects of this pipeline safety law into our Operator Qualification Program, which is already in place and functioning.

See Note 3 of the accompanying Notes to Consolidated and Combined Financial Statements for additional information regarding regulatory matters.

Information Regarding Forward-looking Statements

This report includes forward-looking statements. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. They use words such as “anticipate,” “believe,” “intend,” “plan,” “projection,” “forecast,” “strategy,” “position,” “continue,” “estimate,” “expect,” “may,” or the negative of those terms or other variations of them or comparable terminology. In particular, statements, express or implied, concerning future actions, conditions or events, future operating results or the ability to generate sales, income or cash flow or to pay dividends are forward-looking statements. Forward-looking statements are not guarantees of perf ormance. They involve risks, uncertainties and assumptions. Future actions, conditions or events and future results of operations may differ materially from those expressed in these forward-looking statements. Many of the factors that will determine these results are beyond our ability to control or predict. Specific factors that could cause actual results to differ from those in the forward-looking statements include:

price trends and overall demand for natural gas in the United States;

economic activity, weather, alternative energy sources, conservation and technological advances that may affect price trends and demand;

changes in our tariff rates, including our recovery of fuel in-kind from shippers on our pipeline systems;

our ability to expand our facilities;

changes in laws or regulations, third-party relations and approvals, decisions of courts, regulators and governmental bodies that may adversely affect our business or our ability to compete;

our indebtedness could make us vulnerable to general adverse economic and industry conditions, limit our ability to borrow additional funds and/or place us at competitive disadvantages compared to our competitors that have less debt or have other adverse consequences;

interruptions of electric power supply to our facilities due to natural disasters, power shortages, strikes, riots, terrorism, war or other causes;

our ability to obtain insurance coverage without a significant level of self-retention of risk;

acts of nature, sabotage, terrorism or other acts causing damage greater than our insurance coverage limits;

inflation;

interest rates; and

the timing and success of business development efforts.

You should not put undue reliance on any forward-looking statements. We disclaim any obligation to update the above list or to announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments.

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