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

Exhibit 99.3

CONSOLIDATED FINANCIAL STATEMENTS

NGPL PIPECO LLC

And Subsidiaries

June 30, 2010 and 2009

Report of Independent Auditors

To the Boards of Directors of NGPL PipeCo LLC:

In our opinion, the accompanying consolidated balance sheetsand the related consolidated statements of operations, of comprehensive income, of members' equity and of cash flows present fairly, in all material respects, the financial position of  NGPL PipeCo LLC and its subsidiaries (the "Company")at June 30, 2010 and 2009, and the results of their operations and their cash flows for the years then endedin 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 opini on 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.

/s/ PricewaterhouseCoopers LLP

September 28, 2010

Houston, Texas

June 2010 NGPL PipeCo LLC Financials

CONSOLIDATED STATEMENTS OF OPERATIONS

NGPL PipeCo LLC and Subsidiaries

	Year Ended June 30,
	2010			2009
	(In thousands)
Operating Revenues:
Transportation and Storage	$	852,463		$	1,020,659
Natural Gas Sales		189,450			301,188
Other		4,214			3,377
Total Operating Revenues		1,046,127			1,325,224
Operating Costs and Expenses:
Purchases and Other Costs of Sales		207,743			399,301
Operations and Maintenance		143,080			166,861
General and Administrative		46,519			45,163
Depreciation and Amortization		78,399			76,472
Taxes, Other Than Income Taxes		34,808			37,550
Goodwill Impairment (Note 2)		815,909			-
Other Expenses (Income)		21			(5,796	)
Total Operating Costs and Expenses		1,326,479			719,551
Operating Income (Loss)		(280,352	)		605,673
Other Income and (Expenses):
Interest Expense, Net		(212,020	)		(212,807	)
Interest Income		1,493			2,521
Equity in Earnings of Horizon		1,461			1,531
Other, Net		4,158			6,868
Total Other Income and (Expenses)		(204,908	)		(201,887	)
Income (Loss) Before Income Taxes		(485,260	)		403,786
Income Taxes		136,221			165,410
Income (Loss) From Continuing Operations		(621,481	)		238,376
Income (Loss) From Discontinued Operations		679			(824	)
Net Income (Loss)		(620,802	)		237,552
Net Loss Attributable to Noncontrolling Interests		(420	)		(314	)
Net Income (Loss) Attributable to NGPL PipeCo LLC	$	(620,382	)	$	237,866

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

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June 2010 NGPL PipeCo LLC Financials

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

NGPL PipeCo LLC and Subsidiaries

	Year Ended June 30,
	2010			2009
	(In thousands)
Net Income (Loss)	$	(620,802	)	$	237,552
Other Comprehensive Income (Loss), Net of Tax:
Change in Fair Value of Derivatives Utilized for Hedging Purposes (Net of Tax Expense of $18,732 and $98,387)		25,090			151,916
Reclassification of Change in Fair Value of Derivatives to Net Income (Net of Tax Benefit of $29,393 and $26,145)		(41,952	)		(37,648	)
Total Other Comprehensive Income (Loss)		(16,862	)		114,268
Comprehensive Income (Loss)		(637,664	)		351,820
Comprehensive Loss Attributable to Noncontrolling Interests		(420	)		(314	)
Comprehensive Income (Loss) Attributable to NGPL PipeCo LLC	$	(637,244	)	$	352,134

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

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June 2010 NGPL PipeCo LLC Financials

CONSOLIDATED BALANCE SHEETS

NGPL PipeCo LLC and Subsidiaries

	June 30, 2010			June 30, 2009
	(In thousands)
ASSETS:
Current Assets:
Cash and Cash Equivalents	$	259		$	236
Restricted Deposits		1,714			-
Accounts Receivable		62,203			67,394
Gas in Underground Storage		116,688			105,947
Materials and Supplies		31,776			11,145
Gas Imbalances		11,279			23,097
Fair Value of Derivatives		24,993			45,323
Prepaid Income Taxes		11,096			-
Other		12,148			11,323
		272,156			264,465
Investments		12,993			13,058
Goodwill (Note 2)		4,198,556			5,014,465
Property, Plant and Equipment, Net:
Property, Plant and Equipment		1,866,088			1,835,145
Accumulated Depreciation and Amortization		(174,872	)		(126,932	)
		1,691,216			1,708,213
Deferred Charges and Other Assets		36,105			38,754
Total Assets	$	6,211,026		$	7,038,955
LIABILITIES AND EQUITY:
Current Liabilities:
Notes Payable	$	24,300		$	28,300
Accounts Payable		17,051			16,482
Accrued Interest		9,372			9,303
Accrued Income and Other Taxes		31,183			60,075
Gas Imbalances		14,646			19,949
Fair Value of Derivatives		6,430			8,330
Other		11,815			22,128
		114,797			164,567
Other Liabilities and Deferred Credits:
Deferred Income Taxes		374,270			291,377
Other		20,651			24,471
		394,921			315,848
Long-term Debt		3,000,000			3,000,000
Commitments and Contingent Liabilities (Notes 5 and 11)
Equity:
NGPL PipeCo LLC Members’ Equity:
Members’ Capital		2,690,848			3,530,721
Accumulated Other Comprehensive Income		10,460			27,322
Total NGPL PipeCo LLC Members’ Equity		2,701,308			3,558,043
Noncontrolling Interests		-			497
Total Equity		2,701,308			3,558,540
Total Liabilities and Equity	$	6,211,026		$	7,038,955

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

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June 2010 NGPL PipeCo LLC Financials

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

NGPL PipeCo LLC and Subsidiaries

	Year Ended June 30,
	2010			2009
	(In thousands)
NGPL PipeCo LLC Members’ Equity:
Members’ Capital:
Beginning Balance	$	3,530,721		$	3,615,388
Net Income (Loss) Attributable to NGPL PipeCo LLC		(620,382	)		237,866
Distributions to Members		(219,491	)		(322,533	)
Ending Balance		2,690,848			3,530,721
Accumulated Other Comprehensive Income (Loss), Net of Tax:
Beginning Balance		27,322			(86,946	)
Change in Fair Value of Derivatives Utilized for Hedging Purposes		25,090			151,916
Reclassification of Change in Fair Value of Derivatives to Net Income		(41,952	)		(37,648	)
Ending Balance		10,460			27,322
Total NGPL PipeCo LLC Members’ Equity		2,701,308			3,558,043
Noncontrolling Interests:
Beginning Balance		497			811
Net Loss Attributable to Noncontrolling Interests		(420	)		(314	)
Distributions		(77	)		-
Ending Balance		-			497
Total Equity	$	2,701,308		$	3,558,540

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

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June 2010 NGPL PipeCo LLC Financials

CONSOLIDATED STATEMENTS OF CASH FLOWS

NGPL PipeCo LLC and Subsidiaries

	Year Ended June 30,
	2010			2009
	(In thousands)
Increase (Decrease) in Cash and Cash Equivalents
Cash Flows From Operating Activities:
Net Income (Loss)	$	(620,802	)	$	237,552
Adjustments to Reconcile Net Income (Loss) to Net Cash Flows Provided by Operating Activities:
Goodwill Impairment (Note 2)		815,909			-
Depreciation and Amortization		76,993			77,020
Deferred Income Taxes		90,931			28,323
Carrying Value Adjustments to Inventories (Note 3(E))		6,831			20,627
Gains From Sales of Assets		(9,188	)		(5,796	)
Changes in Components of Working Capital:
Gas in Underground Storage		(17,572	)		43,722
Accounts Receivable		7,805			(11,402	)
Materials and Supplies Inventories		(63	)		(5,030	)
Other Current Assets		(4,184	)		43,029
Accounts Payable		805			(23,967	)
Other Current Liabilities		(44,819	)		46,727
Other, Net		(6,051	)		(7,166	)
Net Cash Flows Provided by Operating Activities		296,595			443,639
Cash Flows From Investing Activities:
Capital Expenditures		(76,782	)		(94,518	)
Proceeds From Sales of Assets, Net of Disposal Costs		5,427			8,072
Return of Equity Investment in Horizon		65			769
(Investments In) Proceeds From Restricted Deposits		(1,714	)		90,906
Net Cash Flows Provided by (Used in) Investing Activities		(73,004	)		5,229
Cash Flows From Financing Activities:
Short-term Debt, Net		(4,000	)		(143,700	)
Distributions to Noncontrolling Interests		(77	)		-
Distributions to Members		(219,491	)		(322,533	)
Net Cash Flows Used in Financing Activities		(223,568	)		(466,233	)
Net Increase (Decrease) in Cash and Cash Equivalents		23			(17,365	)
Cash and Cash Equivalents at Beginning of Period		236			17,601
Cash and Cash Equivalents at End of Period	$	259		$	236

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

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June 2010 NGPL PipeCo LLC Financials

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.  Description of Business and Basis of Presentation

NGPL PipeCo LLC (“NGPL PipeCo”) engages in interstate natural gas transportation and storage. NGPL PipeCo is 80% owned by Myria Acquisition LLC (“Myria”), 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”). 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 sold an 80% ownership interest in NGPL PipeCo to Myria. 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 continues to operate 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 (“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 a 50% investment in Horizon Pipeline Company, L.L.C. (“Horizon”), which is accounted for under the equity method, reflecting our ability to exercise significant influence over its operating and financial policies. In December 2009, we sold Canyon Creek Compression Company for approximately $255,000.

Natural’s interstate natural gas pipeline and storage operations, as well as those of its joint venture investee, 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. On November 19, 2009, the FERC issued an order instituting an investigation of Natural’s rates pursuant to Section 5 of the Natural Gas Act. On June 11, 2010, Natural filed an Offer of Settlement (the "Settlement"), which was approved without modification by the FERC on July 29, 2010. The Settlement resolved all issues in the proceeding. The Settlement provide s that Natural will reduce its fuel and gas lost and unaccounted for fuel retention factors (“Fuel Retention Factors”) as of July 1, 2010. The Settlement further provides a timeline for additional prospective Fuel Retention Factor reductions and prospective reductions in the maximum recourse reservation rates that it bills firm transportation and storage shippers. See Notes 2 and 4 for additional information.

On June 3, 2009, the Financial Accounting Standards Board (“FASB”) voted to approve its Accounting Standards Codification (“ASC”) as the single source of authoritative nongovernmental generally accepted accounting principles in the United States of America (“U.S. GAAP”). The move was officially effected by the June 29, 2009 issuance of Statement of Financial Accounting Standards (“SFAS”) No. 168, The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles. On the effective date of this Statement, the ASC superseded all then-existing non-SEC accounting and reporting standards. All other nongrandfathered, non-SEC accounting litera ture not included in the ASC became nonauthoritative. In other words, the U.S. GAAP hierarchy has been modified to include only two levels of GAAP: authoritative and nonauthoritative. While the ASC does not change U.S. GAAP, it introduces a new structure—reorganizing the thousands of pre-ASC U.S. GAAP pronouncements into approximately 90 accounting topics and displaying all topics consistently. All guidance contained in the ASC carries an equal level of authority. The ASC became effective for interim and annual periods ending after September 15, 2009. The adoption of the ASC affects the way we reference U.S. GAAP in our consolidated financial statements and in our accounting policies; however, the adoption did not have any direct effect on our consolidated financial statements.

Effective July 1, 2009, we adopted accounting standard changes applicable to ASC Topic 810, Consolidation, which require us to present our noncontrolling interests (previously referred to as minority interests) that have the characteristics of permanent equity (related to Canyon Creek Compression Company, our consolidated subsidiary prior to its sale in December 2009) as a separate component of equity rather than as a “mezzanine” item between liabilities and equity on our Consolidated Balance Sheets. Additionally, we are also required to present our noncontrolling interests as a separate caption in our Consolidated Statements of Operations. Our financial statements for all periods presented have been adjusted to retrospectively apply these changes to the presentat ion and disclosures related to noncontrolling interests. These accounting standard changes also require that all transactions with noncontrolling interest holders after adoption, including the issuance

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June 2010 NGPL PipeCo LLC Financials

and repurchase of noncontrolling interests, be accounted for as equity transactions unless a change in control of the subsidiary occurs.

These consolidated 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 U.S. 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. Subsequent events have been evaluated through September 28 , 2010, the date these financial statements were available to be issued. Certain prior year amounts have been reclassified to conform to the current year presentation.

2.  Goodwill Impairment

On November 19, 2009, Natural was notified by the FERC of a proceeding against it pursuant to Section 5 of the Natural Gas Act. The proceeding instituted an investigation into the justness and reasonableness of Natural’s transportation and storage rates as well as its Fuel Retention Factors. On June 11, 2010, Natural filed an Offer of Settlement, which was approved without modification by the FERC on July 29, 2010. The Settlement resolved all issues in the proceeding. The Settlement provides shippers on Natural’s system with reductions in Fuel Retention Factors effective July 1, 2010, reductions in maximum recourse reservation rates effective November 1, 2010, and future additional reductions to both Fuel Retention Factors and maximum recourse reservation rates during the term of the Settlement. In particular, the Settl ement provides that for the period July 1, 2010 through June 30, 2011, the Fuel Retention Factors will be the Fuel Retention Factors that were in effect April 1, 2010, reduced by thirty percent. The Settlement also provides that effective July 1, 2011, the Fuel Retention Factors will be the Fuel Retention Factors that were in effect April 1, 2010, reduced by forty-five percent. In regard to maximum recourse rates, the Settlement provides that from November 1, 2010 through March 31, 2011, the maximum recourse reservation rates for all firm transportation rate schedules will be the rates that were in effect April 1, 2010, reduced by three percent. For the period April 1, 2011 through June 30, 2011, the maximum recourse reservation rates for all firm transportation rate schedules will be the rates that were in effect April 1, 2010, reduced by five percent. Effective July 1, 2011, the Settlement provides that the maximum recourse reservation rates for all firm transportation rate schedules will be the rates that were in effect April 1, 2010, reduced by eight percent. For firm storage services, the maximum reservation rates will be reduced by three percent, effective November 1, 2010.

The Offer of Settlement caused Natural to evaluate for impairment the carrying value of its goodwill. An assessment was performed to determine whether the carrying value of Natural exceeded its fair value and the amount, if any, of goodwill impairment to record. The assessment utilized a weighted income approach and market approach to estimate the fair value of Natural. The income approach is a valuation technique that provides an estimation of the value of an asset or business based on the benefit stream that an asset or business can be expected to generate over its remaining useful life and is typically applied using a discounted cash flow (“DCF”) analysis. The DCF analysis involves discounting the asset’s or business’s projected future cash flows at an appropriately derived rate, which considers the time value of money, inflation, and the risk inherent in ownership of the asset or business being valued. The market approach is a valuation technique that provides an estimation of the value an asset or business using one or more methods that compare the subject asset or business to similar assets or businesses that have been historically transacted in a marketplace.Step one of the assessment indicated that the carrying value of Natural was greater than its fair value. Step two of the assessment resulted in a goodwill impairment charge of $815.9 million, recorded in the caption “Goodwill Impairment” on the accompanying Consolidated Statements of Operations. Goodwill was also tested for impairment as of our regular annual impairment testing date of May 31, 2010 and no additional impairment was indicated. In prior years, we utilized the income approach to estimate the fair value of Natural when assessing our goodwill for potential impairment . The assessments performed during the current year utilized a weighted income approach and market approach to estimate the fair value of Natural.

The following table summarizes the change in our Goodwill balance:

	Historical Goodwill		Accumulated Impairment Losses			Total
	(in thousands)
Historical Goodwill	$	5,014,465	$	-		$	5,014,465
Accumulated Impairment Losses		-		-			-
Balance at June 30, 2009		5,014,465		-			5,014,465
Impairment Charges		-		(815,909	)		(815,909	)
Balance at June 30, 2010	$	5,014,465	$	(815,909	)	$	4,198,556

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June 2010 NGPL PipeCo LLC Financials

3.  Summary of Significant Accounting Policies

(A) Accounting for Regulatory Activities

Our regulated utility operations are accounted for in accordance with the provisions of ASC Topic 980, Regulated Operations, 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 Balance Sheets in the captions “Deferred Charges and Other Assets” and “Other Liabilities and Deferred Credits: Other.”

	June 30, 2010		June 30, 2009
	(In thousands)
Regulatory Assets:
Employee Benefit Costs	$	927	$	1,216
Deferred Income Taxes		15,015		15,059
Rate Regulation and Application Costs		3,812		769
Total Regulatory Assets		19,754		17,044
Regulatory Liabilities:
Deferred Income Taxes		2,506		4,876
Total Regulatory Liabilities		2,506		4,876
Net Regulatory Assets	$	17,248	$	12,168

As of June 30, 2010 and 2009, $18.8 million and $15.8 million of our regulatory assets, respectively, and $2.5 million and $4.9 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 $0.9 million at June 30, 2010 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.

In addition, we record an allowance for funds used during construction (“AFUDC”), which is recorded as part of property, plant and equipment. During each of the years ended June 30, 2010 and 2009, we recorded $1.3 million of AFUDC, including both debt and equity components of AFUDC.

(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.

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June 2010 NGPL PipeCo LLC Financials

(C) Restricted Deposits

“Restricted Deposits” consist principally of restricted funds on deposit with brokers in support of our risk management activities (see Note 9).

(D) Accounts Receivable

The caption “Accounts Receivable, Net” in the accompanying Consolidated 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 adjusted as necessary for changed circumstances and customer-specific information. When specific receivables are determined to be uncollectible, the reserve and receivable are relieved. We had no allowances for doubtful accounts at June 30, 2010 and 2009.

(E) Inventories

Our inventories consist of the following:

	June 30, 2010		June 30, 2009
	(In thousands)
Gas in Underground Storage	$	116,688	$	105,947
Materials and Supplies		31,776		11,145
	$	148,464	$	117,092

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 (79% and 90%) for gas in underground storage and average cost (21% and 10%) for materials and supplies at June 30, 2010 and 2009, respectively. The excess of current cost over the reported last-in, first-out value of gas in underground storage was $0.5 million and $0.7 million at June 30, 2010 and 2009, 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 (the “net realizable value”), 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. We recorded $6.8 million and $20.6 million of reductions in the carrying value of our natural gas storage inventories during the twelve months ended June 30, 2010 and 2009, respectively. Only the fue l gas that we take title to under our transportation tariffs is recorded in the accompanying Consolidated 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 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 $13.0 million and $13.1 million at June 30, 2010 and 2009, respectively. Earnings from our equity investment in Horizon were $1.5 million for both years ended June 30, 2010 and 2009. We received distributions from Horizon of $1.5 million and $2.3 million during the years ended June 30, 2010 and 2009, 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.

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June 2010 NGPL PipeCo LLC Financials

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 Balance Sheets. This component of our 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, Pla nt and Equipment” on the accompanying Consolidated Balance Sheets. Cushion gas is divided into the categories of “recoverable cushion gas” and “unrecoverable cushion gas,” based on an engineering 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 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 impairments to property, plant and equipment during the years ended June 30, 2010 and 2009.

(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 Balance Sheets, is as follows:

	Year Ended June 30,
	2010			2009
	(In thousands)
Balance at Beginning of Period	$	2,919		$	2,834
Liabilities Incurred		-			-
Liabilities Settled		(1,000	)		-
Accretion Expense		39			85
Balance at End of Period	$	1,958		$	2,919

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 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 $2.0 million and $2.9 million at June 30, 2010 and 2009, 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 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.

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June 2010 NGPL PipeCo LLC Financials

(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 $4.0 million and $3.8 million for the years ended June 30, 2010 and 2009, respectively.

(J) Interest Expense

“Interest Expense, Net” as presented in the accompanying Consolidated Statements of Operations principally consists of interest expense on (i) our $3.0 billion of outstanding long-term debt and (ii) our short-term revolving credit facility, 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,
	2010			2009
	(In thousands)
Interest Expense	$	(212,451	)	$	(213,041	)
AFUDC – Interest		431			234
Interest Expense, Net	$	(212,020	)	$	(212,807	)

(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 Statements of Cash Flows includes, among other things, non-cash charges and credits to income.

During the years ended June 30, 2010 and 2009, we made cash payments for interest of approximately $210.6 million and $211.5 million, respectively.

During the years ended June 30, 2010 and 2009, we made cash payments for income taxes of approximately $83.0 million and $103.8 million, respectively.

(L) Transactions with Related Parties

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-approved 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 $46.5 million and $45.2 million for the years ended June 30, 2010 and 2009, respectively.

During the years ended June 30, 2010 and 2009, we made cash distributions to members totaling $219.5 million and $322.5 million, respectively. The distributions were made on a pro rata basis of our ownership of 80% to Myria ($175.6 million and $258.0 million) and 20% to Kinder Morgan ($43.9 million and $64.5 million).

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.

Totals of significant transactions with related parties are as follows:

	Year Ended June 30,
	2010		2009
	(In thousands)
Sales, Transportation and Storage of Natural Gas and Other Revenues	$	10,363	$	14,538
Purchases and Transportation of Natural Gas	$	961	$	4,289
Charges for General and Administrative Costs	$	46,519	$	45,163

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June 2010 NGPL PipeCo LLC Financials

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

	June 30, 2010			June 30, 2009
	(In thousands)
Accounts Receivable – Myria	$	716		$	830
Accounts Receivable – Other Affiliates	$	56		$	20
Accounts Payable – Kinder Morgan Energy Partners, L.P.	$	(1,250	)	$	(975	)
Accounts Payable – Kinder Morgan.	$	(1,298	)	$	(683	)
Accounts Payable – Other Affiliates	$	(55	)	$	(2	)
Gas Imbalances Receivable – Kinder Morgan Energy Partners, L.P.	$	1,261		$	3,716
Gas Imbalances Receivable – Midcontinent Express Pipeline LLC	$	5,287		$	-
Gas Imbalances Receivable – Rockies Express Pipeline LLC	$	-		$	6,446
Gas Imbalances Payable – Kinder Morgan Energy Partners, L.P.	$	(717	)	$	(8,460	)
Gas Imbalances Payable – Rockies Express Pipeline LLC.	$	(2,039	)	$	-
Gas Imbalances Payable – Midcontinent Express Pipeline LLC.	$	-		$	(2,785	)
Gas Imbalances Payable – Horizon Pipeline Company, L.L.C.	$	(294	)	$	(298	)

(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 7 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) 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 9 for a detailed discussion of our hedging activities.

(O) 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 5(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 5(A)).

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June 2010 NGPL PipeCo LLC Financials

(Q) Goodwill

On May 30, 2007, a group of investors, including Kinder Morgan CEO Richard D. Kinder and other members of Kinder Morgan senior management, completed a “Going Private transaction” in which all of the outstanding shares of Kinder Morgan were purchased for $107.50 per share. Prior to the Going Private transaction, there was no goodwill recorded on our Consolidated 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, approximately $5.0 billion, was recorded as Goodwill.

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. The events associated with the Section 5 rate proceeding caused us to record an $815.9 million impairment of our goodwill (see Notes 2 and 4).

4.  Regulatory Matters

Section 5 Rate Proceeding

On November 19, 2009, Natural was notified by the FERC of a proceeding against it pursuant to Section 5 of the Natural Gas Act. The proceeding instituted an investigation into the justness and reasonableness of Natural’s transportation and storage rates as well as its Fuel Retention Factors. On June 11, 2010 Natural filed an Offer of Settlement, which was approved without modification by the FERC on July 29, 2010. The Settlement resolved all issues in the proceeding. The Settlement provides shippers on Natural’s system with reductions in Fuel Retention Factors effective July 1, 2010, reductions in maximum recourse reservation rates effective November 1, 2010, and future additional reductions to both Fuel Retention Factors and maximum recourse reservation rates during the term of the Settlement. In particular, the Settle ment provides that for the period July 1, 2010 through June 30, 2011, the Fuel Retention Factors will be the Fuel Retention Factors that were in effect April 1, 2010, reduced by thirty percent. The Settlement also provides that effective July 1, 2011, the Fuel Retention Factors will be the Fuel Retention Factors that were in effect April 1, 2010, reduced by forty-five percent. In regard to maximum recourse rates, the Settlement provides that from November 1, 2010 through March 31, 2011, the maximum recourse reservation rates for all firm transportation rate schedules will be the rates that were in effect April 1, 2010, reduced by three percent. For the period April 1, 2011 through June 30, 2011, the maximum recourse reservation rates for all firm transportation rate schedules will be the rates that were in effect April 1, 2010, reduced by five percent. Effective July 1, 2011, the Settlement provides that the maximum recourse reservation rates for all firm transportation rate schedules will be the rates that were in effect April 1, 2010, reduced by eight percent. For firm storage service, the maximum reservation rates will be reduced by three percent, effective November 1, 2010. See Note 2 for additional information.

FERC Order No. 2004/717

On October 15, 2009, the FERC issued Order No. 717-A, an order on rehearing and clarification regarding FERC’s Affiliate Rule - Standards of Conduct. The FERC clarified a lengthy list of issues relating to: the applicability, the definition of transmission function and transmission function employees, the definition of marketing function and marketing function employees, the definition of transmission function information, independent functioning, transparency, training, and North American Energy Standards Board business practice standards. The FERC generally reaffirmed its determinations in Order No. 717, but granted rehearing on and clarified certain provisions. Order No. 717-A aims to make the Standards of Conduct clearer and to refocus the rules on the areas where there is the greatest potential for abuse. Order No. 717-A addresses requests for rehearing and clarification of the following issues: (i) applicability of the Standards of Conduct to transmission owners with no marketing affiliate transactions, (ii) whether the Independent Functioning Rule applies to balancing authority employees, (iii) which activities of transmission function employees or marketing function employees are subject to the Independent Functioning Rule, (iv) whether local distribution companies making off-system sales on nonaffiliated pipelines are subject to the Standards of Conduct, (v) whether the Standards of Conduct apply to a pipeline’s sale of its own production, (vi) applicability of the Standards of Conduct to asset management agreements, (vii) whether incidental purchases to remain in balance or sales of unneeded gas supply subject the company to the Standards of Conduct, (viii) applicability of the No Conduit Rule to certain situations and (ix) applicability of the Transparency Rule to certain situations. The rehearing and clarificat ion granted are not anticipated to have a material impact on the operation of Natural’s interstate pipeline.

Notice of Proposed Rulemaking – Natural Gas Price Transparency

On November 20, 2008, the FERC issued Order No. 720, establishing new reporting requirements for interstate and major non-interstate natural gas pipelines. Interstate pipelines are required to post no-notice activity at each receipt and delivery point three days after the day of gas flow. Major non-interstate pipelines are required to post daily the design capacity, scheduled volumes and available capacity at each receipt or delivery point with a design capacity of 15,000 MMBtus of

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June 2010 NGPL PipeCo LLC Financials

natural gas per day or greater. 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 until 150 days following the issuance of an order addressing the pending requests for rehearing. On January 16, 2009, the FERC granted rehearing of Order No. 720. On July 16, 2009, the FERC issued a request for supplemental comments on revisions to the posting requirements. On January 21, 2010, the FERC issued an Order on Rehearing and Clarification that affirmed its order issued in Order No. 720. Natural does not expect this Order to have a material impact on its financial statements.

Order on Flow-Through of Discounted or Negotiated Usage and Fuel Charges

On October 15, 2009, the FERC issued this Order to address the issue of whether asset manager replacement shippers are entitled to the same discounts as their releasing shippers under the Commission’s capacity release program as revised by Order No. 712. The FERC decided not to establish a blanket requirement that pipelines must always provide the same discounted or negotiated usage or fuel charges to an asset manager replacement shipper that it has provided to the primary firm shipper. Instead, the FERC determined that pipelines should apply the Commission’s existing selective discounting policy on a case-by-case basis in deciding whether to grant a discounted or negotiated usage or fuel charge to an asset manager replacement shipper, subject to a general requirement of no undue discrimination.

5.  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 $3.1 million and $3.3 million as of June 30, 2010 and 2009, 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 Balance Sheets..

On January 8, 2010, we received a Clean Air Act Section 114 information request from the United States Environmental Protection Agency (“EPA”), Region 5. This information request requires that we provide the EPA with air permit and various other information related to our natural gas pipeline compressor station operations in Illinois. We have responded to this information request and we believe our natural gas compressor station operations are in substantial compliance with applicable air quality laws and regulations.

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 the EPA, Region 7 and the Missouri Attorney General’s Office. Natural responded to these requests. No proceeding or enforcement actions have been initiated. However, in April 2010, the EPA issued an Advanced Notice of Proposed Rulemaking (“ANPRM”) proposing major changes in the way in which PCBs are regulated for all industries, including natural gas pipelines. There can be no assurance that Natural will not incur additional costs for P CB compliance in the future.

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

In a lawsuit styled William Roy Price, II vs. Kinder Morgan, Inc., in the District Court of Titus County, Texas, a group of nine homeowners filed suit, alleging that Natural’s No. 803 natural gas compressor station constitutes a private nuisance. They complain that the construction of the plant brought excessive travel, construction, people, noise and waste to the area. They further allege that after the plant became operational, the operations caused excess noise, heat, pollution (emissions) and vibrations. The alleged damages are loss of enjoyment of their property, personal discomfort, diminishment of the value of their respective properties, and mental anguish. In their depositions, each of the plaintiffs claimed that the value of their property is zero because of t he nuisance. The cumulative value of the properties is over $1 million. On March 8, 2010, Natural successfully settled the last of the nine claims for various amounts totaling approximately $253,000.

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

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June 2010 NGPL PipeCo LLC Financials

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. 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 appealed the trial court’s judgment. 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.

On April 30, 2010, the Court of Appeals for the Sixth Appellate District of Texas at Texarkana issued a memorandum opinion that affirmed the trial court’s judgment. On August 12, 2010, we filed a petition to the Texas Supreme Court seeking further appellate review. We have 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 denied coverage, but has agreed to postpone any arbitration over coverage until we exhaust appellate review.

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.

6.  Property, Plant and Equipment

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

	June 30, 2010			June 30, 2009
	(In thousands)
Natural Gas Transmission and Storage	$	1,746,586		$	1,680,829
General and Other		101,096			109,986
Construction Work in Process		18,406			44,330
Total Property, Plant and Equipment		1,866,088			1,835,145
Accumulated Depreciation and Amortization		(174,872	)		(126,932	)
Property, Plant and Equipment, Net	$	1,691,216		$	1,708,213

7.  Income Taxes

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

	Year Ended June 30,
	2010		2009
	(In thousands)
Current Tax Expense:
U.S.
Federal	$	34,748	$	114,310
State		10,476		23,356
		45,224		137,666
Deferred Tax Expense:
U.S.
Federal		82,426		21,114
State		8,571		6,630
		90,997		27,744
Total Tax Expense	$	136,221	$	165,410

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June 2010 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,
	2010		2009
Federal Income Tax Rate		35.0 %		35.0%
Increase (Decrease) as a Result of:
Goodwill Impairment		(58.8)%		-
State Income Tax, Net of Federal Benefit		(3.3)%		4.4%
State Tax Rate Change		-		1.1%
Other		(1.0)%		0.5%
Effective Tax Rate		(28.1)%		41.0%

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

	Year Ended June 30,
	2010			2009
	(In thousands)
Continuing Operations	$	136,221		$	165,410
Discontinued Operations		677			(222	)
Equity Items		(10,661	)		72,242
Total	$	126,237		$	237,430

Deferred tax assets and liabilities result from the following:

	June 30, 2010		June 30, 2009
	(In thousands)
Deferred Tax Assets:
Amortization of Regulatory Liabilities	$	971	$	1,941
Postretirement Benefits Accrual		6,748		3,859
Environmental Costs		1,203		1,284
Contributions In Aid of Construction		8,613		5,575
Bad Debt Reserve		710		937
Hedge Ineffectiveness		-		1,418
Operations Reserve		1,501		-
Other		8,696		10,457
Total Deferred Tax Assets		28,442		25,471
Deferred Tax Liabilities:
Property, Plant and Equipment		368,153		278,473
Amortization of Regulatory Assets		5,815		5,805
Partnership Income		8,549		9,487
Operations Reserve		-		1,740
Hedge Ineffectiveness		2,980		-
Derivatives		7,315		17,975
Other		7,370		3,891
Total Deferred Tax Liabilities		400,182		317,371
Net Deferred Tax Liabilities	$	371,740	$	291,900
Current Deferred Tax Asset	$	2,530	$	-
Current Deferred Tax Liability		-		523
Non-current Deferred Tax Liability		374,270		291,377
Net Deferred Tax Liabilities	$	371,740	$	291,900

Unrecognized Tax Benefits

ASC Topic 740, Income Taxes, addresses the determination of how tax benefits claimed or expected to be claimed on a tax return should be recorded in the financial statements. Under ASC 740-10, 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 benefits recognized in the financial statements from such a position

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June 2010 NGPL PipeCo LLC Financials

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,
	2010			2009
	(In millions)
Balance at Beginning of Period	$	7.3		$	1.1
Current Year Tax Positions		-			10.4
Prior Year Tax Positions		(3.0	)		(4.3	)
Settlements With Taxing Authorities		2.8			2.2
Lapse in Statute of Limitations		(0.1	)		(2.1	)
Balance at End of Period	$	7.0		$	7.3

Our continuing practice is to recognize interest and/or penalties related to income tax matters in income tax expense, and as of June 30, 2009, we had $0.5 million of accrued interest and no accrued penalties. As of June 30, 2010 (i) we had$0.7 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 $4.4 million during the next twelve months, and (iii) we believe $2.5 million of the unrecognized tax benefits on our Consolidated Balance Sheet at June 30, 2010 would affect our effective tax rate in future periods in the event those unrecognized tax benefits were recognized.

We are subject to taxation, and have tax years open to examination for the periods 2006 – 2009 in the United States and 2003 – 2009 in various states.

8.  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 our present business and (v) merge or consolidate with, or sell, lease or transfer our 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, we 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 had a carrying value of $3.0 billion at June 30, 2010 and 2009 and a fair value of approximately $2.9 billion and $3.2 billion at June 30, 2010 and 2009, respectively.

Maturities of long-term debt for the five years ended June 30, 2015 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 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.

There were $24.3 million and $28.3 million of borrowings outstanding under this facility at June 30, 2010 and 2009, respectively. After deducting outstanding letters of credit, the remaining borrowing capacity under this facility was approximately $170.6 million and $156.6 million at June 30, 2010 and 2009, respectively. Average daily borrowings under this facility were $8.6 million and $28.9 million for the years ended June 30, 2010 and 2009, respectively. The weighted average interest rate on outstanding borrowings was 3.2% and 3.1% for the years ended June 30, 2010 and 2009, respectively. 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 appro ximate fair value.

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June 2010 NGPL PipeCo LLC Financials

9.  Risk Management

Effective July 1, 2009, we adopted accounting standard changes applicable to ASC Topic 815, Derivatives and Hedging, that required additional disclosures regarding derivative activities. 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.

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. There was no component of our derivative instruments’ gain or loss excluded from the assessment of hedge effectiveness.

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 originally designated and qualified as cash flow hedges for all periods presented. However, as a result of the settlement of our Section 5 rate proceeding (see Note 4), certain of our derivative instruments no longer qualify for hedge accounting treatment because the forecasted hedged transactions are no longer probable of occurring. Since these derivatives no longer qualify for hedge accounting treatment, all realized and unrealized gains and losses on these derivatives are recognized in the Statement of Operations for the current period. We recorded a pre-tax gain of $5.2 million ($3.1 million after tax) in June 2010 as a result of the discontinuance of hedge accounting treatment for these derivatives. The proceeds or payments resulting from the settlement of cash flow hedges are reflected in the operating activities section of our Consolidated Statements of Cash Flows as net income and changes in components of working capital.

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 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. We had one outstanding letter of credit for $5.0 million and one outstanding letter of credit for $15.0 million at June 30, 2010 and 2009, respectively, in support of our hedging of commodity price risks associated with the sale of natural gas. Additionally, as of June 30, 2010, we had cash margin deposits associated with our energy commodity contract positions and over-the-counter swap partners totaling $1.7 million, reported in the caption “Restricted Deposits” on our accompanying Consol idated Balance Sheet. As of June 30, 2009, counterparties associated with our energy commodity contract positions and over-the-counter swap agreements had margin deposits with us totaling $15.8 million, reported within the caption “Current Liabilities: Other” on our accompanying Consolidated Balance Sheet. As of June 30, 2010, our maximum potential exposure to credit losses on derivative contracts was $24.1 million.

We expect to reclassify into earnings, during the next twelve months, all of our $10.5 million accumulated other comprehensive income balance at June 30, 2010,representing unrecognized net gains on derivative activities. As of June 30, 2010, the maximum length of time over which we have hedged our exposure to commodity price risk is through November 2010.

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June 2010 NGPL PipeCo LLC Financials

As of June 30, 2010, we had entered into the following outstanding commodity forward contracts to hedge our forecasted energy commodity sales:

	Notional quantity
Derivatives designated as hedging contracts
Natural gas(a)	23.1 billion cubic feet
Derivatives not designated as hedging contracts
Natural gas(a)	6.1 billion cubic feet
(a)  Notional quantities are shown net.

Fair Value of Derivative Contracts

The fair values of our current asset and current liability derivative contracts are reported in the captions “Current Assets: Fair Value of Derivatives” and “Current Liabilities: Fair Value of Derivatives,” respectively, on the accompanying Consolidated Balance Sheets. The fair values of our non-current asset and non-current liability derivative contracts are reported in the captions “Deferred Charges and Other Assets” and “Deferred Credits: Other,” respectively, on the accompanying Consolidated Balance Sheets. The following table summarizes the fair values of our derivative contracts included on the accompanying Consolidated Balance Sheets as of June 30, 2010 and 2009 (in thousands):

	Asset derivatives						Liability derivatives
	June 30, 2010			June 30, 2009			June 30, 2010			June 30, 2009
	Balance sheet Location	Fair value		Balance sheet Location	Fair value		Balance sheet Location	Fair value		Balance sheet location	Fair value
Derivatives designated as hedging contracts
Energy commodity derivative contracts	Current	$	19,474	Current	$	45,323	Current	$	(6,121)	Current	$	(8,330)
	Non-current		-	Non-current		855	Non-current		-	Non-current		(702)
Total			19,474			46,178			(6,121)			(9,032)
Derivatives not designated as hedging contracts
Energy commodity derivative contracts	Current		5,519	Current		-	Current		(309)	Current		-
Total derivatives		$	24,993		$	46,178		$	(6,430)		$	(9,032)

Effect of Derivative Contracts on the Statement of Operations

The following tables summarize the pre-tax impact of our derivative contracts on the accompanying Consolidated Statements of Operations (in thousands):

Derivatives in cash flow hedging relationships	Amount of gain/(loss) recognized in OCI on derivative (effective portion)				Location of gain/(loss) reclassified from Accumulated OCI into income (effective portion)	Amount of gain/(loss) reclassified from Accumulated OCI into income (effective portion)				Location of gain/(loss) recognized in income on derivative (ineffective portion )	Amount of gain/(loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)
	Year Ended June 30,					Year Ended June 30,					Year Ended June 30,
	2010		2009			2010		2009			2010		2009
Energy commodity derivative contracts	$	43,822	$	250,303	Operating Revenues: Natural Gas Sales	$	66,135	$	63,793	Operating Revenues: Natural Gas Sales	$	-	$	2,285

Derivatives not designated as hedging contracts	Location of gain/(loss) recognized in income on derivative	Amount of gain/(loss) recognized in income on derivative
		Year Ended June 30,
		2010		2009
Energy commodity derivative contracts	Operating Revenues: Natural Gas Sales	$	5,210	$	-

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June 2010 NGPL PipeCo LLC Financials

10.  Fair Value Measurements

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.

Accounting principles generally accepted in the United States include a hierarchical disclosure framework associated with the level of pricing observability utilized in measuring fair value. 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. The three broad levels of inputs defined by the disclosure framework 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.

OTC derivatives are valued using models utilizing a variety of inputs including contractual terms and commodity and interest rate curves. 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.

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June 2010 NGPL PipeCo LLC Financials

The following two tables summarize the fair value measurements of our derivative contracts , based on the three levels established by the ASC and does not include cash margin deposits, which are reported as “Restricted Deposits” in the accompanying Consolidated Balance Sheets (in thousands):

	Asset fair value measurements using
	Total		Quoted prices in active markets for identical assets (Level 1)		Significant other observable inputs (Level 2)		Significant unobservable inputs (Level 3)
As of June 30, 2010
Energy commodity derivative contracts	$	24,993	$	-	$	24,106	$	887
As of June 30, 2009
Energy commodity derivative contracts	$	46,178	$	18,742	$	26,877	$	559

	Liability fair value measurements using
	Total			Quoted prices in active markets for identical liabilities (Level 1)		Significant other observable inputs (Level 2)			Significant unobservable inputs (Level 3)
As of June 30, 2010
Energy commodity derivative contracts(c)	$	(6,430	)	$	-	$	(3,593	)	$	(2,837	)
As of June 30, 2009
Energy commodity derivative contracts(d)	$	(9,032	)	$	-	$	(1,351	)	$	(7,681	)

The following table provides a summary of changes in the fair value of our Level 3 derivative contracts (in thousands):

Energy Commodity Derivative Contracts – Level 3
	Year Ended June 30,
		2010			2009
Net Asset (Liability)
Beginning Balance	$	(7,122	)	$	15,774
Realized and Unrealized Net Gains (Losses)		(13,870	)		1,845
Settlements		19,042			(24,741	)
Transfers In (Out) of Level 3		-			-
Ending Balance	$	(1,950	)	$	(7,122	)
Change in Unrealized Net Gains (Losses) Relating
to Contracts Still Held at End of Period	$	(1,702	)	$	(6,286	)

Assets Measured at Fair Value on a Non-Recurring Basis

In accordance with the provisions of ASC Topic 350, Intangibles—Goodwill and Other, a goodwill impairment charge of $815.9 million was recorded to write down the carrying value of our goodwill from $5.0 billion to its implied fair value of $4.2 billion. The charge was included in the statement of operations for the year ended June 30, 2010. See Note 2 for additional information.

The Offer of Settlement caused Natural to evaluate for impairment the carrying value of its goodwill. The following table summarizes the fair value measurement of goodwill, which was initially measured at fair value and has been re-measured at fair value on a non-recurring basis based on the three levels established by the ASC (in thousands):

	Asset fair value measurements using
	Total			Quoted prices in active markets for identical assets (Level 1)			Significant other observable inputs (Level 2)			Significant unobservable inputs (Level 3)
Goodwill		$	4,198,556		$	-		$	-		$	4,198,556

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June 2010 NGPL PipeCo LLC Financials

11.  Commitments and Contingent Liabilities

(A) Leases

Expenses incurred under operating leases were $1.8 million and $1.5 million for the years ended June 30, 2010 and 2009, respectively. Future minimum commitments under major non-cancelable operating leases as of June 30, 2010 are as follows:

Fiscal Year	Operating Leases
	(In thousands)
2011	$	392
2012		403
2013		416
2014		428
2015		441
Thereafter		1,689
Total	$	3,769

(B) Capital Expenditures

Approximately $21.6 million had been committed for the purchase of property, plant and equipment at June 30, 2010.

12. Major Customers and Concentration of Credit Risk

Natural had no customers that accounted for more than 10% of total revenues for the year ended June 30, 2010.

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. Natural delivers an average of 2.0 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 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 approximately 57% of its operating revenues from tariff services are attributable to its ten largest customers. Natural mitigates credit risk by requiring collateral or financial g uarantees and letters of credit from customers with specific credit concerns. In support of credit extended to certain customers, Natural had received prepayments of $3.0 million and $1.8 million at June 30, 2010 and 2009, respectively, included in the caption “Current Liabilities: Other” in the accompanying Consolidated Balance Sheets.

13.  Recent Accounting Pronouncements

In January 2010, the FASB issued ASU No. 2010-06, Improving Disclosures about Fair Value Measurements. This ASU requires both the gross presentation of activity within the Level 3 fair value measurement roll forward and the details of transfers in and out of Level 1 and 2 fair value measurements. It also clarifies certain disclosure requirements on the level of disaggregation of fair value measurements and disclosures on inputs and valuation techniques. For us, this ASU is effective for interim and annual reporting periods beginning on or after January 1, 2010 (except for the Level 3 roll forward information, which is effective for us July 1, 2011); however, because this ASU pertains to disclosure requirements only, the adoption of this ASU did not have a material impact on o ur consolidated financial statements.

On February 24, 2010, the FASB issued ASU No. 2010-09, Subsequent Events (Topic 855): Amendments to Certain Recognition and Disclosure Requirements. This ASU modifies the disclosure requirements related to subsequent events such that an entity that is an SEC filer is no longer required to disclose the date through which subsequent events have been evaluated. An entity that is either an SEC filer or a conduit bond obligor for conduit debt securities that are traded in a public market is required to evaluate subsequent events through the date that the financial statements are issued. An entity that meets neither of the above criteria must evaluate subsequent events through the date the financial statements are available to be issued or until the date the financial statements ar e issued and must disclose the date through which subsequent events have been evaluated. This ASU was effective immediately upon issuance and its adoption did not have a material impact on our consolidated financial statements.

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June 2010 NGPL PipeCo LLC Financials

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

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June 2010 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 Financial Statements and related Notes. NGPL PipeCo is 80% owned by Myria Acquisition LLC (“Myria”), 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 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 a 50% investment in Horizon Pipeline Company, L.L.C. (“Horizon”), which is accounted for under the equity method, reflecting our ability to exercise significant influence over its operating and financial policies. In December 2009, we sold Canyon Creek Compression Company for approximately $255,000.

Natural’s interstate natural gas pipeline and storage operations, as well as those of its joint venture investee, 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. On November 19, 2009, the FERC issued an order instituting an investigation of Natural’s rates pursuant to Section 5 of the Natural Gas Act. On June 11, 2010, Natural filed an Offer of Settlement (the "Settlement"), which was approved without modification by the FERC on July 29, 2010. The Settlement resolved all issues in the proceeding. The Settlement provide s that Natural will reduce its fuel and gas lost and unaccounted for fuel retention factors (“Fuel Retention Factors”) as of July 1, 2010. The Settlement further provides a timeline for additional prospective Fuel Retention Factor reductions and prospective reductions in the maximum recourse reservation rates that it bills firm transportation and storage shippers. Notes 2 and 4 of the accompanying Notes to Consolidated Financial Statements and the Critical Accounting Policies and Estimates discussion below contain additional information on this subject.

Critical Accounting Policies and Estimates

Our discussion and analysis of financial condition and results of operations are based on our Consolidated 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 disclosures must be estimated, requiring us to make certain assumptions with respect to values or conditions that 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 a nd 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 Accounting Standards Codification (“ASC”) Topic 350, Intangibles – Goodwill and Other. This ASC Topic provides accounting guidance regarding the concept of indefinite life intangible assets and provides 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 impairment annually or on an interim ba sis 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 2010 NGPL PipeCo LLC Financials

The Offer of Settlement caused Natural to evaluate for impairment the carrying value of its goodwill. An assessment was performed to determine whether the carrying value of Natural exceeded its fair value and the amount, if any, of goodwill impairment to record. The assessment utilized a weighted income approach and market approach to estimate the fair value of Natural. The income approach is a valuation technique that provides an estimation of the value of an asset or business based on the benefit stream that an asset or business can be expected to generate over its remaining useful life and is typically applied using a discounted cash flow (“DCF”) analysis. The DCF analysis involves discounting the asset’s or business’s projected future cash flows at an appropriately derived rate, which considers the time value of money, inflation, and the risk inherent in ownership of the asset or business being valued. The market approach is a valuation technique that provides an estimation of the value an asset or business using one or more methods that compare the subject asset or business to similar assets or businesses that have been historically transacted in a marketplace.Step one of the assessment indicated that the carrying value of Natural was greater than its fair value. Step two of the assessment resulted in a goodwill impairment charge of $815.9 million, recorded in the caption “Goodwill Impairment” on the accompanying Consolidated Statements of Operations. Goodwill was also tested for impairment as of our regular annual impairment testing date of May 31, 2010 and no additional impairment was indicated. In prior years, we utilized the income approach to estimate the fair value of Natural when assessing our goodwill for potential impairment . The assessments performed during the current year utilized a weighted income approach and market approach to estimate the fair value of Natural.

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. All of our derivative activities relating to the mitigation of these risks were originally designated and qualified as cash flow hedges for all periods presented. However, as a result of the Settlement, certain of our derivative instruments no longer qualify for hedge accounting treatment because the forecasted hedged transactions are no longer expected to occur. Since these derivatives no longer qualify for hedge accounting treatment, all realized and unrealized gains and losses on these derivatives are recognized in the Statement of Operations for the current period. We recorded a pre-tax gain of $5.2 million ($3.1 million after tax) in June 2010 as a result of the discontinuance of hedge treatment for these derivatives.

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June 2010 NGPL PipeCo LLC Financials

Results of Operations

	Year Ended June 30,
	2010			2009
	(In thousands)
Operating Revenues	$	1,046,127		$	1,325,224
Purchases and Other Costs of Sales		(207,743	)		(399,301	)
Gross Profit		838,384			925,923
Other Operating Expenses, Excluding Depreciation,
Amortization and Goodwill Impairment		(224,428	)		(243,778	)
Operating Income Before Depreciation, Amortization     and Goodwill Impairment		613,956			682,145
Other Income and (Expenses), Excluding Interest Expense		7,112			10,920
Earnings Before Interest, Taxes, Depreciation,     Amortization and Goodwill Impairment		621,068			693,065
Goodwill Impairment		(815,909	)		-
Depreciation and Amortization Expense		(78,399	)		(76,472	)
Interest Expense, Net		(212,020	)		(212,807	)
Income (Loss) Before Income Taxes		(485,260	)		403,786
Income Taxes		136,221			165,410
Income (Loss) From Continuing Operations		(621,481	)		238,376
Income (Loss) From Discontinued Operations		679			(824	)
Net Income (Loss)		(620,802	)		237,552
Net Loss Attributable to Noncontrolling Interests		(420	)		(314	)
Net Income (Loss) Attributable to NGPL PipeCo LLC	$	(620,382	)	$	237,866

The largest discrete item affecting our 2010 operating results was an $815.9 million goodwill impairment charge. This charge resulted from a rate proceeding initiated by the FERC on November 19, 2009, which was concluded on July 29, 2010. This rate proceeding and the resulting goodwill impairment charge are discussed in more detail under the “General” and “Critical Accounting Policies and Estimates” subheadings above.

Gross profit (operating revenues less purchases and other costs of sales) decreased $87.5 million (9%) from the year ended June 30, 2009 to the year ended June 30, 2010. Gross profit for fiscal 2010 was negatively impacted, relative to 2009, by (i) a decrease of $44.3 million in gross profit from transportation and storage services due principally to reduced revenues from reservation charges and line pack services, (ii) a decrease of $56.4 million in gross profit from operational gas sales due to lower sales volumes from fuel recoveries and reduced natural gas prices, (iii) a $5.1 million decrease in gross profit due to expenses for storage services from other pipelines and (iv) a $1.2 million net reduction in other miscellaneous items affecting gross profit. These negative impacts were partially offset by (i) a $14.3 million reduc tion in charges to reduce the carrying value of our current storage gas inventories to reflect the reduced market price of natural gas and (ii) $5.2 million of gross profit in 2010 from the discontinuance of certain hedges resulting from the fact that the forecasted hedged transactions are no longer probable of occurring. Natural’s operational natural gas sales are primarily made possible by (i) its collection of fuel in-kind pursuant to its transportation tariffs and (ii) recovery of storage cushion gas volumes due to storage system expansion projects. Storage expansion projects often include the addition of compression facilities to storage reservoirs. This additional compression decreases the amount of cushion gas required to maintain the necessary pressure to allow efficient operation of the facility. Therefore, expansion projects can result in cushion gas being available for recovery and sale. See Note 3(G) of the accompanying Consolidated Financial Statements for additional information regarding storage cushion gas. Our future revenues from operational natural gas sales will be reduced as a result of the Settlement, as discussed in Critical Accounting Policies and Estimates above, and could also be affected by, among other things, the market price of natural gas and our future recoveries and sales of storage cushion gas.

Other operating expenses, excluding depreciation, amortization and goodwill impairment charges decreased by $19.4 million (8%) from the year ended June 30, 2009 to the year ended June 30, 2010. Other operating expenses were positively impacted in fiscal 2010, relative to 2009, principally by (i) a $14.1 million reduction in electric compression costs, (ii) $3.8 million of Hurricane Ike insurance proceeds received in 2010, (iii) a $2.9 million decrease in expenses for stress corrosion cracking rehabilitation projects and pipeline integrity management programs, (iv) a $2.7 million reduction in taxes other than income taxes (principally property taxes) and (v) a $3.1 million net decrease in other operating expenses. These positive impacts were partially offset by (i) the fact that 2009 results included $5.8 million of gains from sales of land and (ii) a $1.4 million increase in general and administrative expenses due to the 3% annual increase in the fixed fee component of the Operating Agreement (see Note 3(L) of the accompanying Consolidated Financial Statements).

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June 2010 NGPL PipeCo LLC Financials

Other Income and (Expenses), Excluding Interest Expense was negatively impacted in 2010, relative to 2009, by (i) a $1.1 million reduction in interest income, (ii) a $0.1 million reduction in earnings from our investment in Horizon Pipeline and (iii) a $2.7 million net reduction in income from other miscellaneous items.

Interest expense, net was nearly unchanged period to period, due to the fixed interest rates of our long-term debt.

Income tax expense decreased by $29.2 million (18%) from the year ended June 30, 2009 to the year ended June 30, 2010 due principally to the reduction in our pre-tax income before the goodwill impairment charge, which had no impact on our income tax expense.

Substantially all of Natural’s pipeline capacity is committed under firm transportation contracts ranging from one to seven 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 72% of the total transportation volumes committed under Natural’s long-term firm transportation contracts in effect on June 30, 2010 had remaining terms of less than three years. Contracts representing approximately 10.4% of Natural’s total long-haul, contracted firm transport capacity as of June 30, 2010 are scheduled to expire during the following twelve months. Natural continues 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. Shippers on our pipelines do have rights, under certain circumstances prescribed by applicable regulations, to challenge the rates we charge (which includes reservation, commodity, surcharges, fuel and gas lost and unaccounted for). According to the terms of the Settlement of our Section 5 proceeding, parties to the Settlement, in general, will not be able to challenge our rates prior to April 2016. 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 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 2010 are currently expected to be approximately $74.8 million, of which $18.6 had been expended as of June 30, 2010. 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 borrowings un der our credit facilities or by issuing additional long-term debt.

Invested Capital

The following table illustrates the sources of our invested capital.

	June 30,
	2010			2009
	(Dollars in thousands)
Long-term Debt	$	3,000,000	52.6%	$	3,000,000	45.7%
NGPL PipeCo LL C Members’ Equity		2,701,308	47.4%		3,558,043	54.3%
Noncontrolling Interests		-	-		497	-
Total Invested Capital	$	5,701,308	100.0%	$	6,558,540	100.0%

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June 2010 NGPL PipeCo LLC Financials

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, 2010, we had available a $200 million five-year credit facility dated February 15, 2008. We had $24.3 million and $28.3 million of borrowings outstanding under this facility at June 30, 2010 and 2009, 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 $170.6 million and $156.6 million at June 30, 2010 and 2009, respectively.

Long-term Debt

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 2012, 2017 and 2037 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 our present busine ss and (v) merge or consolidate with, or sell, lease or transfer our 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, we must give the holders of the notes the opportunity to sell their senior notes to us at 101% of their principal amount, plus accrued and unpaid interest.

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		1,939.1		209.3		377.8		255.7		1,096.3
Notes Payable		24.3		24.3		-		-		-
Operating Leases		3.8		0.4		0.8		0.9		1.7
Total Contractual Cash Obligations	$	4,967.2	$	234.0	$	1,628.6	$	256.6	$	2,848.0
Other Commercial Commitments:
Letters of Credit	$	5.2	$	5.2	$	-	$	-	$	-
Capital Expenditures	$	21.6	$	21.6	$	-	$	-	$	-

Cash Flows

The following discussion of cash flows should be read in conjunction with the accompanying Consolidated 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 decreased from $443.6 million for the year ended June 30, 2009 to $296.6 million for the year ended June 30, 2010, a decrease of $147.0 million (33.1%). The decrease in cash flows from operating activities in 2010, relative to 2009, principally resulted from (i) an $89.8 million decrease in net cash flows attributable to changes in other working capital items and (ii) a $61.3 million decrease in net cash flows attributable to changes in gas in underground storage due to (1) a $47.1 million decrease attributable to changes in natural gas volumes stored and (2) a $14.3 million decrease attributable to changes in natural gas prices. The change attributable to natural gas volumes resulted from a decrease in volumes held in storage during the year ended June 30, 2009, followed by an increa se in volumes held in storage during the year ended June 30, 2010. The change attributable to natural gas prices was principally due to the decrease of natural gas prices during the year ended June 30, 2009.

Net Cash Flows from Investing Activities

Net cash flows from investing activities decreased from a source of cash of $5.2 million for the year ended June 30, 2009 to a use of cash of $73.0 million for the year ended June 30, 2010, a decrease of $78.2 million. This decrease in net cash flows

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June 2010 NGPL PipeCo LLC Financials

from investing activities in 2010, relative to 2009, principally resulted from (i) a $92.6 million decrease in net cash flows attributable to restricted deposits associated with our hedging activities and (ii) a $17.7 million decrease in cash outflows for capital expenditures.

Net Cash Flows from Financing  Activities

Net cash flows used in financing activities decreased from $466.2 million for the year ended June 30, 2009 to $223.6 million for the year ended June 30, 2010, a decrease of $242.6 million. The decrease in net cash flows used in financing activities in 2010, relative to 2009, resulted principally from (i) a $139.7 million decrease in net cash flows used for short-term borrowings and (ii) a $103.0 million decrease in distributions to members.

Litigation and Environmental

Refer to Notes 5(A) and 5(B) of the accompanying Notes to Consolidated 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 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 4 of the accompanying Notes to Consolidated 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 service our debt or pay distributions are forward-looking statements. Forward-looking statements ar e not guarantees of performance. 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

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June 2010 NGPL PipeCo LLC Financials

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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