Kinder Morgan, Inc. 2005 3rd Qtr. Form 10-Q

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

The number of shares outstanding of the registrant’s common stock, $5 par value, as of October 28, 2005 was 122,064,950 shares.

	Three Months Ended September 30,				Nine Months Ended September 30,
	2005		2004		2005		2004
	(In thousands except per share amounts)
Operating Revenues:
Natural Gas Transportation and Storage	$ 175,725		$ 171,468		$ 571,563		$ 542,207
Natural Gas Sales	87,275		51,834		278,034		231,877
Other	30,106		26,340		73,083		65,011
Total Operating Revenues	293,106		249,642		922,680		839,095

Operating Costs and Expenses:
Gas Purchases and Other Costs of Sales	113,007		55,821		325,176		241,502
Operations and Maintenance	45,110		42,650		130,971		116,778
General and Administrative	16,942		18,334		52,181		60,501
Depreciation and Amortization	30,312		29,949		89,883		89,137
Taxes, Other Than Income Taxes	8,378		6,953		25,492		23,785
Total Operating Costs and Expenses	213,749		153,707		623,703		531,703

Operating Income	79,357		95,935		298,977		307,392

Other Income and (Expenses):
Equity in Earnings of Kinder Morgan Energy Partners	169,192		143,979		480,399		405,548
Equity in Earnings of Other Equity Investments	3,639		2,965		10,259		8,467
Interest Expense	(39,742	)	(33,990	)	(114,070	)	(98,785	)
Interest Expense – Deferrable Interest Debentures	(5,478	)	(5,478	)	(16,434	)	(16,434	)
Minority Interests	(23,694	)	(21,114	)	(55,022	)	(45,511	)
Other, Net	467		1,756		29,770		3,277
Total Other Income and (Expenses)	104,384		88,118		334,902		256,562

Income from Continuing Operations Before
Income Taxes	183,741		184,053		633,879		563,954
Income Taxes	74,577		72,123		258,051		220,592
Income from Continuing Operations	109,164		111,930		375,828		343,362
Loss on Disposal of Discontinued Operations, Net of Tax	-		-		(1,389	)	-

Net Income	$ 109,164		$ 111,930		$ 374,439		$ 343,362

Basic Earnings (Loss) Per Common Share:
Income from Continuing Operations	$ 0.89		$ 0.91		$ 3.06		$ 2.77
Loss on Disposal of Discontinued Operations	-		-		(0.01	)	-
Total Basic Earnings Per Common Share	$ 0.89		$ 0.91		$ 3.05		$ 2.77

Number of Shares Used in Computing Basic
Earnings Per Common Share (Thousands)	122,494		123,673		122,568		123,756

Diluted Earnings (Loss) Per Common Share:
Income from Continuing Operations	$ 0.88		$ 0.90		$ 3.04		$ 2.75
Loss on Disposal of Discontinued Operations	-		-		(0.01	)	-
Total Diluted Earnings Per Common Share	$ 0.88		$ 0.90		$ 3.03		$ 2.75

Number of Shares Used in Computing Diluted
Earnings Per Common Share (Thousands)	123,684		124,683		123,754		124,852

Dividends Per Common Share	$ 0.7500		$ 0.5625		$ 2.1500		$ 1.6875

We are an energy transportation, storage and related services provider and have operations in the Rocky Mountain and mid-continent regions of the United States, with principal operations in Arkansas, Colorado, Illinois, Iowa, Kansas, Louisiana, Missouri, Nebraska, New Mexico, Oklahoma, Texas and Wyoming. Our business activities include: (i) transporting, storing and selling natural gas, (ii) providing retail natural gas distribution services and (iii) operating and, in previous periods, developing and constructing electric generation facilities. We have both regulated and nonregulated operations. In addition, we own the general partner interest, as well as significant limited partner interests, in Kinder Morgan Energy Partners, L.P., a publicly traded pipeline master limited partnership, referred to in these Notes as “Kinder Morgan Energy Partners,” and receive a substantial portion of our earnings from returns on these investments. Our common stock is traded on the New York Stock Exchange under the symbol “KMI.”

We have prepared the accompanying unaudited interim consolidated financial statements under the rules and regulations of the Securities and Exchange Commission. Under such rules and regulations, we have condensed or omitted certain information and notes normally included in financial statements prepared in conformity with accounting principles generally accepted in the United States of America. We believe, however, that our disclosures are adequate to make the information presented not misleading. The consolidated financial statements reflect all adjustments, which are solely normal and recurring adjustments that are, in the opinion of management, necessary for a fair presentation of our financial results for the interim periods presented. You should read these interim consolidated financial statements in conjunction with our consolidated financial statements and related notes included in our Annual Report on Form 10-K for the year ended December 31, 2004 (“2004 Form 10-K”). Unless the context requires otherwise, references to “we,” “us,” “our,” or the “Company” are intended to mean Kinder Morgan, Inc. and its consolidated subsidiaries.

For a complete discussion of our significant accounting policies, see Note 1 of Notes to Consolidated Financial Statements included in our 2004 Form 10-K.

Statement of Financial Accounting Standards (“SFAS”) No. 123, Accounting for Stock-Based Compensation, encourages, but does not require, entities to adopt the fair value method of accounting for stock-based compensation plans. As allowed under SFAS No. 123, we continue to apply Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees. Accordingly, compensation expense would not be recognized for stock options unless the options were granted at an exercise price lower than the market price on the grant date, which we have not done. Had compensation cost for these plans been determined consistent with SFAS No. 123, net income and diluted earnings per share would have been reduced to the pro forma amounts shown in the table below. Because the SFAS No. 123 method of accounting has not been applied to options granted prior to January 1, 1995, among other factors, the resulting pro forma compensation cost may not be representative of that to be expected in future years. Additionally, the pro forma amounts include approximately $218,000 and $726,000 for the three months and nine months ended September 30, 2004, respectively, related to the 15 percent purchase discount offered under the employee stock purchase plan. Effective January 1, 2005, the purchase discount offered under the employee stock purchase plan was reduced to 5 percent. Amounts related to the 5 percent discount are not included in the pro forma amounts for the three months and nine months ended September 30, 2005 because the employee stock purchase plan is no longer considered a compensatory plan under SFAS No. 123.

The Financial Accounting Standards Board (“FASB”) recently issued SFAS No. 123R (revised 2004), Share-Based Payment, which will change our accounting for stock options and similar awards, see Note 18.

On August 1, 2005, we and Terasen Inc. (TSX:TER) announced a definitive agreement whereby we will acquire all of the outstanding shares of Terasen Inc., a provider of energy and utility services based in Vancouver, British Columbia, Canada. The total purchase price, including the debt held within the Terasen companies, is expected to be approximately US$5.6 billion. Under the terms of the transaction, Terasen shareholders will be able to elect to receive, for each Terasen share held, either (i) C$35.75 in cash, (ii) 0.3331 shares of our common stock, or (iii) C$23.25 in cash plus 0.1165 shares of our common stock. All elections will be subject to proration in the event total cash elections exceed approximately 65 percent of the total consideration to be paid or total stock elections exceed approximately 35 percent. The transaction was unanimously approved by each company’s board of directors and by a special committee of independent Terasen directors created by the Terasen board to oversee the process. On October 18, 2005, the transaction was approved by a vote of Terasen shareholders. The transaction is also subject to regulatory approvals and other conditions, and is expected to close by year-end 2005.

Terasen owns two core businesses: (i) a natural gas distribution business serving approximately 875,000 customers in British Columbia and (ii) a refined products and crude oil transportation pipeline business with three pipelines, (a) Trans Mountain Pipeline, extending from Edmonton to Vancouver and Washington State, (b) Corridor Pipeline, extending from the Athabasca oilsands to Edmonton and (c) a one-third interest in the Express and Platte pipeline systems extending from Alberta to the U.S. Rocky Mountain and Midwest regions. In addition, Terasen owns a water and utility services business that operates 90 water and wastewater systems in over 50 communities throughout British Columbia, Alberta and Alaska.

Basic earnings per common share is computed based on the weighted-average number of common

shares outstanding during each period. In recent periods, we have repurchased a significant number of our outstanding shares, see Note 12. Diluted earnings per common share is computed based on the weighted-average number of common shares outstanding during each period, increased by the assumed exercise or conversion of securities convertible into common stock, for which the effect of conversion or exercise using the treasury stock method would be dilutive. Stock options are currently the only such securities outstanding.

No options were excluded from the diluted earnings per share calculation for the three months and the nine months ended September 30, 2005. Weighted-average stock options outstanding totaling 0.3 million and 0.2 million for the three months and the nine months ended September 30, 2004, respectively, were excluded from the diluted earnings per common share calculation because the effect of including them would have been antidilutive.

The effective tax rate (calculated by dividing the amount in the caption “Income Taxes” by the amount in the caption “Income from Continuing Operations Before Income Taxes” as shown in the accompanying interim Consolidated Statements of Operations) was 40.6% and 40.7% for the three and nine months ended September 30, 2005, respectively. These effective tax rates reflect, among other factors, the impact of (i) the tax effects of gains from our first and second quarter 2005 sales of Kinder Morgan Management shares that we owned (see Note 8) and (ii) the minority interest associated with Kinder Morgan Management. We made no sales of Kinder Morgan Management shares in the three months ended September 30, 2005. We recorded pre-tax gains from sales of Kinder Morgan Management shares of $26.5 million in the nine months ended September 30, 2005. In conjunction with these gains, we increased our total income tax provision by $15.5 million in the nine months ended September 30, 2005. We have not recorded deferred taxes with respect to our investment in Kinder Morgan Management due to our ability and intent to recover our investment in a tax-free manner. The effective tax rate was 39.2% and 39.1% for the three and nine months ended September 30, 2004, respectively, reflecting the impact of the minority interest associated with Kinder Morgan Management, among other factors.

At September 30, 2005, we had a capital loss carryforward of approximately $83.0 million. No valuation allowance has been recorded with respect to this deferred tax asset. This capital loss carryforward was affected by a subsequent event – see the discussion regarding the sale of Kinder Morgan Management shares that we owned in Note 19.

We consider all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.

Changes in Working Capital Items:
(Net of Effects of Acquisitions and Sales)
Increase (Decrease) in Cash and Cash Equivalents

Distributions received by our Kinder Morgan Management subsidiary from its investment in i-units of Kinder Morgan Energy Partners are in the form of additional i-units, while distributions made by Kinder Morgan Management to its shareholders are in the form of additional Kinder Morgan Management shares, see Note 7. “Other, Net” as presented in the accompanying interim Consolidated Statements of Cash Flows includes other non-cash increases and decreases to earnings, including amortization of deferred revenue, amortization of debt discount and expense and amortization of interest rate swap gains and losses previously recorded upon termination of the swaps.

The Accumulated Other Comprehensive Loss balance of $176.3 million at September 30, 2005 consisted of (i) $130.9 million representing our pro rata share of the accumulated other comprehensive loss of Kinder Morgan Energy Partners and (ii) $45.4 million representing unrecognized net losses on hedging activities.

Kinder Morgan Management, LLC, referred to in this report as Kinder Morgan Management, is a publicly traded Delaware limited liability company that was formed on February 14, 2001. Kinder Morgan G.P., Inc., our indirect wholly owned subsidiary, owns all of Kinder Morgan Management’s voting shares. Kinder Morgan Management’s shares (other than the voting shares we hold) are traded on the New York Stock Exchange under the ticker symbol “KMR”. Kinder Morgan Management, pursuant to a delegation of control agreement, has been delegated, to the fullest extent permitted under Delaware law, all of Kinder Morgan G.P., Inc.’s power and authority to manage and control the business and affairs of Kinder Morgan Energy Partners, L.P., subject to Kinder Morgan G.P., Inc.’s right to approve certain transactions.

On August 12, 2005, Kinder Morgan Management made a distribution of 0.016210 of its shares per outstanding share (909,009 total shares) to shareholders of record as of July 29, 2005, based on the $0.78 per common unit distribution declared by Kinder Morgan Energy Partners. On November 14, 2005, Kinder Morgan Management will make a distribution of 0.016360 of its shares per outstanding share (932,292 total shares) to shareholders of record as of October 31, 2005, based on the $0.79 per common unit distribution declared by Kinder Morgan Energy Partners. These distributions are paid in the form of additional shares or fractions thereof calculated by dividing the Kinder Morgan Energy Partners’ cash distribution per common unit by the average market price of a Kinder Morgan Management listed share determined for a ten-trading day period ending on the trading day immediately prior to the ex-dividend date for the shares.

In August and September 2005, Kinder Morgan Energy Partners issued 5.75 million common units in a public offering at a price of $51.25 per common unit, receiving total net proceeds (after underwriting discount) of $283.6 million. We did not acquire any of these common units. In August 2005, Kinder Morgan Energy Partners issued 64,412 common units as partial consideration for the acquisition of General Stevedores, L.P. These issuances, collectively, reduced our percentage ownership of Kinder Morgan Energy Partners (at the time of the transactions) from approximately 17.3% to approximately 16.9% and had the associated effects of increasing our (i) investment in the net assets of Kinder Morgan Energy Partners by $30.1 million, (ii) associated accumulated deferred income taxes by $3.2 million and (iii) paid-in capital by $5.7 million and, in addition, reduced our equity method goodwill in Kinder Morgan Energy Partners by $21.2 million. In addition, in August 2005, in order to maintain our 1% general partner interest in Kinder Morgan Energy Partners’ operating partnerships, we made a contribution of approximately $2.6 million.

On June 1, 2005, we sold 1,717,033 Kinder Morgan Management shares that we owned for approximately $75.0 million. We recognized a pre-tax gain of $22.0 million associated with this sale.

In April 2005, Kinder Morgan Energy Partners issued 957,656 common units as partial consideration for the acquisition of seven bulk terminal operations. This transaction reduced our percentage ownership of Kinder Morgan Energy Partners (at the time of the transaction) from approximately 18.13% to approximately 18.06% and had the associated effects of increasing our (i) investment in the net assets of

Kinder Morgan Energy Partners by $5.1 million, (ii) associated accumulated deferred income taxes by $0.5 million and (iii) paid-in capital by $0.9 million and, in addition, reduced our equity method goodwill in Kinder Morgan Energy Partners by $3.6 million. In addition, in April 2005, in order to maintain our 1% general partner interest in Kinder Morgan Energy Partners’ operating partnerships, we made a contribution of approximately $0.6 million.

On January 31, 2005, we sold 413,516 Kinder Morgan Management shares that we owned for approximately $17.5 million. We recognized a pre-tax gain of $4.5 million associated with this sale.

In July 2004, we sold our remaining surplus LM 6000 gas-fired turbine for consideration of $8.3 million (net of marketing fees), which consideration consisted of $2.0 million in cash, a note receivable of $6.5 million and a payable for marketing fees of $0.2 million.

In April 2004, we sold two LM6000 gas-fired turbines for $16.5 million (net of marketing fees), which consideration consisted of $2.4 million in cash, a note receivable of $14.5 million and a note payable for marketing fees of $0.4 million. During September 2004, the remaining balance of this receivable was collected. In June 2004, we sold two LM6000 turbines and two boilers to Kinder Morgan Production Company, L.P., a subsidiary of Kinder Morgan Energy Partners, for their estimated fair market value of $21.1 million, which we received in cash. This equipment was a portion of the equipment that became surplus as a result of our decision to exit the power development business.

On March 25, 2004, Kinder Morgan Management closed the issuance and sale of 360,664 listed shares in a limited registered offering. None of the shares from the offering were purchased by us. Kinder Morgan Management used the net proceeds of approximately $14.9 million from the offering to buy 360,664 additional i-units from Kinder Morgan Energy Partners. This issuance of i-units reduced our percentage ownership of Kinder Morgan Energy Partners (at the time of the transaction) from approximately 18.54% to approximately 18.51% and had the associated effects of increasing our investment in the net assets of Kinder Morgan Energy Partners by $1.2 million and reducing our (i) equity method goodwill in Kinder Morgan Energy Partners by $1.5 million, (ii) paid-in capital by $0.2 million and (iii) associated accumulated deferred income taxes by $0.1 million. In addition, in order to maintain our 1% general partner interest in Kinder Morgan Energy Partners’ operating partnerships, we made a contribution of approximately $0.2 million.

In February 2004, Kinder Morgan Energy Partners issued 5.3 million common units in a public offering at a price of $46.80 per common unit, receiving total net proceeds (after underwriting discount) of $237.8 million. We did not acquire any of these common units. This transaction reduced our percentage ownership of Kinder Morgan Energy Partners (at the time of the transaction) from approximately 19.0% to approximately 18.5% and had the associated effects of increasing our (i) investment in the net assets of Kinder Morgan Energy Partners by $23.2 million, (ii) associated accumulated deferred income taxes by $0.1 million and (iii) paid-in capital by $0.2 million and, in addition, reduced our equity method goodwill in Kinder Morgan Energy Partners by $23.1 million. In addition, in February 2004, in order to maintain our 1% general partner interest in Kinder Morgan Energy Partners’ operating partnerships, we made a contribution of approximately $2.4 million.

Following is summarized income statement information for Kinder Morgan Energy Partners, a publicly traded master limited partnership in which we own the general partner interest and significant limited partner interests in the form of Kinder Morgan Energy Partners common units, i-units and Class B limited partner units. This investment, which is accounted for under the equity method of accounting, is described in more detail in our 2004 Form 10-K. Additional information about Kinder Morgan Energy

Partners’ results of operations and financial position are contained in its Quarterly Report on Form 10-Q for the quarter ended September 30, 2005 and in its Annual Report on Form 10-K for the year ended December 31, 2004.

During 1999, we adopted and implemented a plan to discontinue a number of lines of business. During 2000, we essentially completed the disposition of these discontinued operations. For the three months ended September 30, 2005, no incremental losses were recorded. For the nine months ended September 30, 2005, incremental losses of approximately $1.4 million (net of tax benefits of $0.8 million) were recorded to increase previously recorded liabilities to reflect updated estimates. The cash flows attributable to discontinued operations included in the accompanying interim Consolidated Statements of Cash Flows under the caption “Net Cash Flows Used in Discontinued Operations” result from cash activity attributable to retained liabilities associated with these discontinued operations. Note 7 of Notes to Consolidated Financial Statements included in our 2004 Form 10-K contains additional information on these matters.

At September 30, 2005, we had available an $800 million five-year senior unsecured revolving credit facility dated August 5, 2005. This credit facility replaced an $800 million five-year senior unsecured revolving credit agreement dated August 18, 2004, effectively extending the maturity of our credit facility by one year, and includes covenants and requires payment of facility fees that are similar in nature to the covenants and facility fees required by the revolving bank facility it replaced, which are discussed in our 2004 Form 10-K. In this credit facility, the definition of consolidated net worth, which is a component of total capitalization, was revised to exclude other comprehensive income/loss, and the definition of consolidated indebtedness was revised to exclude the debt of Kinder Morgan Energy Partners that is guaranteed by us. This facility was amended subsequent to the date of these financial statements – see Note 19. This credit facility can be used for general corporate purposes, including serving as support for our commercial paper program. Under this bank facility, we are required to pay a facility fee based on the total commitment, whether used or unused, at a rate that varies based on our senior debt rating. We had no borrowings under our bank facility at September 30, 2005.

The commercial paper we issue, which is supported by the credit facility described above, is comprised of unsecured short-term notes with maturities not to exceed 270 days from the date of issue. Commercial paper outstanding at September 30, 2005 was $269.3 million. We had no commercial paper outstanding at December 31, 2004. Our weighted-average interest rate on short-term borrowings outstanding at September 30, 2005 was 3.93 percent. Average short-term borrowings outstanding during the third quarter of 2005 were $202.4 million and the weighted-average interest rate was 3.60 percent. Average short-term borrowings outstanding during the first nine months of 2005 were $198.3 million and the weighted-average interest rate was 3.20 percent.

Our current maturities of long-term debt of $5 million at September 30, 2005 represented $5 million of current maturities of our 6.50% Series Debentures due September 1, 2013 (which are payable September 1, 2006).

On March 1, 2005, our $500 million of 6.65% Senior Notes matured, and we paid the holders of the notes, utilizing a combination of cash on hand and borrowings under our commercial paper program.

On March 15, 2005, we issued $250 million of our 5.15% Senior Notes due March 1, 2015. The proceeds of $248.5 million, net of underwriting discounts and commissions, were used to repay short-term commercial paper debt that was incurred to pay our 6.65% Senior Notes that matured on March 1, 2005.

On August 12, 2005, we paid a cash dividend on our common stock of $0.75 per share to shareholders of record as of July 29, 2005. On October 19, 2005, our Board of Directors approved a cash dividend of $0.75 per common share payable on November 14, 2005 to shareholders of record as of October 31, 2005.

On August 14, 2001, we announced a program to repurchase $300 million of our outstanding common stock, which program was increased to $400 million, $450 million, $500 million, $550 million, $750 million and $800 million in February 2002, July 2002, November 2003, April 2004, November 2004 and April 2005, respectively. As of September 30, 2005, we had repurchased a total of approximately $754.3 million (13,248,600 shares) of our outstanding common stock under the program, of which $9.4 million (101,600 shares) and $193.1 million (2,519,900 shares) were repurchased in the three months and nine months ended September 30, 2005, respectively. We repurchased $15.8 million (264,900 shares) and $55.1 million (931,100 shares) of our common stock in the three months and nine months ended September 30, 2004, respectively.

In accordance with the manner in which we manage our businesses, including the allocation of capital and evaluation of business segment performance, we report our operations in the following segments: (1) Natural Gas Pipeline Company of America and certain affiliates, referred to as Natural Gas Pipeline Company of America or NGPL, a major interstate natural gas pipeline and storage system; (2) prior to its contribution to Kinder Morgan Energy Partners as discussed following, TransColorado Gas Transmission Company, referred to as TransColorado, an interstate natural gas pipeline located in western Colorado and northwest New Mexico; (3) Kinder Morgan Retail, the regulated sale and transportation of natural gas to residential, commercial and industrial customers (including a small distribution system in Hermosillo, Mexico) and the sale of natural gas to certain utility customers under the Choice Gas Program and (4) Power, the operation and, in previous periods, development and construction of natural gas-fired electric generation facilities. Our investment in TransColorado Gas Transmission Company was contributed to Kinder Morgan Energy Partners effective November 1, 2004.

The accounting policies we apply in the generation of business segment information are generally the same as those applied to our consolidated operations and described in Note 1 of Notes to Consolidated Financial Statements included in our 2004 Form 10-K, except that (i) certain items below the “Operating Income” line (such as interest expense) are either not allocated to business segments or are not considered by management in its evaluation of business segment performance and (ii) equity in earnings of equity method investees, other than Kinder Morgan Energy Partners, are included in segment earnings. These equity method earnings are included in “Other Income and (Expenses)” in the

accompanying interim Consolidated Statements of Operations. In addition, (i) certain items included in operating income (such as general and administrative expenses) are not considered by management in its evaluation of business segment performance and (ii) gains and losses from incidental sales of assets are included in segment earnings. With adjustment for these items, we currently evaluate business segment performance primarily based on operating income in relation to the level of capital employed. We account for intersegment sales at market prices, while we account for asset transfers at either market value or, in some instances, book value.

Represents revenues from KM Insurance Ltd., our wholly owned subsidiary that was formed during the second quarter of 2005 for the purpose of providing insurance services to Kinder Morgan Energy Partners and us. KM Insurance Ltd. was formed as a Class 2 Bermuda insurance company, the sole business of which is to issue policies for Kinder Morgan Energy Partners and us to secure the deductible portion of our workers’ compensation, automobile liability and general liability policies placed in the commercial insurance market.

Includes market value of derivative instruments (including interest rate swaps), income tax receivables and miscellaneous corporate assets (such as information technology and telecommunications equipment) not allocated to individual segments.

All but an insignificant amount of our assets and operations are located in the continental United States of America.

Our normal business activities expose us to risks associated with changes in the market price of natural gas and associated transportation. We engage in derivative transactions for the purpose of mitigating these risks, which transactions are accounted for in accordance with SFAS No. 133, Accounting for

Derivative Instruments and Hedging Activities and associated amendments. The accompanying interim Consolidated Balance Sheet as of September 30, 2005, includes, exclusive of amounts related to interest rate swaps as discussed below, balances of approximately $188.5 million, $2.2 million, $173.8 million and $1.9 million in the captions “Current Assets: Other,” “Deferred Charges and Other Assets,” “Current Liabilities: Other,” and “Other Liabilities and Deferred Credits: Other” respectively, related to these derivative financial instruments. During the three and nine month periods ended September 30, 2005 and 2004, our derivative activities relating to the mitigation of these risks were designated and qualified as cash flow hedges. We recognized a pre-tax loss of approximately $24.6 million and $78,000 in the three months ended September 30, 2005, and 2004, respectively, and a pre-tax loss of approximately $26.4 million and $0.8 million in the nine month periods ended September 30, 2005 and 2004, respectively, as a result of ineffectiveness of these hedges, which amounts are reported within the captions “Natural Gas Sales” and “Gas Purchases and Other Costs of Sales” in the accompanying interim Consolidated Statements of Operations. There was no component of these derivative instruments’ gain or loss excluded from the assessment of hedge effectiveness. As the hedged sales and purchases take place and we record them into earnings, we also reclassify the gains and losses included in accumulated other comprehensive income into earnings. We expect to reclassify into earnings, during the next twelve months, substantially all of our accumulated other comprehensive loss balance related to these derivatives of $45.4 million at September 30, 2005, representing unrecognized net losses on derivative activities. During the three and nine month periods ended September 30, 2005 and 2004, we reclassified no gains or losses into earnings as a result of the discontinuance of cash flow hedges due to a determination that the forecasted transactions would no longer occur by the end of the originally specified time period. In conjunction with these activities, we are required to place funds in margin accounts (included with “Restricted Deposits” in the accompanying interim Consolidated Balance Sheets) when the market value of these derivatives with specific counterparties exceeds established limits, or in conjunction with the purchase of exchange-traded derivatives.

We have outstanding fixed-to-floating interest rate swap agreements with a notional principal amount of $1.25 billion at September 30, 2005. These agreements effectively convert the interest expense associated with our 7.25% Debentures due in 2028 and $750 million of our 6.50% Senior Notes due in 2012 from fixed rates to floating rates based on the three-month London Interbank Offered Rate (“LIBOR”) plus a credit spread. These swaps have been designated as fair value hedges, and we have accounted for them utilizing the “shortcut” method prescribed for qualifying fair value hedges under SFAS No. 133. Accordingly, the carrying value of the swap is adjusted to its fair value as of the end of each reporting period, and an offsetting entry is made to adjust the carrying value of the debt securities whose fair value is being hedged. The fair value of the swaps of $65.7 million at September 30, 2005 reflects $68.1 million included in the caption “Deferred Charges and Other Assets” and $2.4 million included in the caption “Other Liabilities and Deferred Credits: Other” in the accompanying interim Consolidated Balance Sheet. We record interest expense equal to the floating rate payments, which is accrued monthly and paid semi-annually.

On March 10, 2005, we terminated $250 million of our interest rate swap agreements associated with our 6.50% Senior Notes due 2012 and paid $3.5 million in cash. We are amortizing this amount to interest expense over the period the 6.50% Senior Notes are outstanding. The unamortized balance of $3.3 million at September 30, 2005 is included in the caption “Value of Interest Rate Swaps” under the heading “Long-term Debt” in the accompanying interim Consolidated Balance Sheet.

In association with our proposed acquisition of Terasen, we have entered into foreign currency derivative contracts to mitigate risks associated with our obligation to finance the cash portion of the transaction in Canadian dollars. At September 30, 2005, we had foreign currency option contacts with a notional amount of C$420 million outstanding. These options do not qualify for hedge accounting under SFAS No. 133. Accordingly, the carrying value of the options are adjusted to fair value as of the end of

each reporting period, with any gain or loss on the derivative instrument recognized currently in earnings. The fair value of the options of $0.4 million is included in the caption Current Assets: “Other” in the accompanying interim Consolidated Balance Sheet. We recognized a pre-tax loss of $0.04 million in the three and nine month periods ended September 30, 2005, which amounts are reported within the caption “Other, Net” in the accompanying interim Consolidated Statements of Operations.

The components of net periodic pension cost for our retirement plans are as follows:

We previously disclosed in our 2004 Form 10-K that we expect to make contributions of approximately $25 million to our retirement plans during 2005. As of September 30, 2005, contributions of approximately $25 million have been made. We expect that additional contributions, if any, made during 2005 will not be significant.

The components of net periodic benefit cost for our postretirement benefit plan are as follows:

We previously disclosed in our 2004 Form 10-K that we expect to make contributions of approximately $8.5 million to our postretirement benefit plan during 2005. As of September 30, 2005, contributions of approximately $8.5 million have been made. We expect that additional contributions, if any, to our postretirement benefit plan during 2005 will not be significant.

On August 29, 2005, NGPL filed with the Federal Energy Regulatory Commission (“FERC”) a certificate application in Docket No. CP05-405-000 for authorization to construct and operate facilities at NGPL’s North Lansing storage facility in Harrison County, Texas to enable NGPL to provide an additional 10 billion cubic feet (“Bcf”) of cycled working gas and storage service under NGPL’s existing Rate Schedule NSS (i.e., firm storage service). Specifically, NGPL proposed to construct and operate: (i) twelve new injection/withdrawal wells, (ii) one 13,000 horsepower (“hp”) compressor unit at NGPL’s Compressor Station No. 388, (iii) 8.7 miles of 30-inch pipeline to loop a portion of the existing lateral between Compressor Station No. 388 and NGPL’s Gulf Coast mainline, along with a 30-inch tap that would be added to the mainline, (iv) looping on various field pipes and (v) new and upgraded metering facilities. In conjunction with its request to construct facilities, NGPL also requested authority to rework sixteen existing injection/withdrawal wells and to increase the peak day withdrawal level at North Lansing from 1,100 million cubic feet (“MMcf”) to 1,240 MMcf. The total estimated cost for the jurisdictional facilities proposed is approximately $49.2 million with an additional $13.4 million to be spent on non-jurisdictional work that is also part of this storage expansion project. Assuming timely receipt of a FERC certificate, NGPL anticipates that the additional Rate Schedule NSS service sought by customers will be available by the spring of 2007.

On November 22, 2004, the FERC issued a Notice of Inquiry seeking comments on its policy of selective discounting. Specifically, the FERC asked parties to submit comments and respond to inquiries regarding the FERC’s practice of permitting pipelines to adjust their ratemaking throughput downward in rate cases to reflect discounts given by pipelines for competitive reasons – when the discount is given to meet competition from another gas pipeline. After reviewing the comments, the FERC found that its current policy on selective discounting is an integral and essential part of the FERC’s policies furthering the goal of developing a competitive national natural gas transportation market. The FERC further found that the selective discounting policy provides for safeguards to protect captive customers. If there are circumstances on a particular pipeline that may warrant special consideration or additional protections for captive customers, those issues can be considered in individual cases. The FERC stated that this order is in the public interest because it promotes a competitive natural gas market and also protects the interests of captive customers. By an order issued on May 31, 2005, the FERC reaffirmed its existing policy on selective discounting by interstate pipelines without change. Two entities have filed for rehearing.

On November 5, 2004, the FERC issued a Notice of Proposed Accounting Release that would require FERC jurisdictional entities to recognize costs incurred in performing pipeline assessments that are a part of a pipeline integrity management program as maintenance expense in the period incurred. The proposed accounting ruling is in response to the FERC’s finding of diverse practices within the pipeline industry in accounting for pipeline assessment activities. The proposed ruling would standardize these practices. Specifically, the proposed ruling clarifies the distinction between costs for a “one-time rehabilitation project to extend the useful life of the system,” which could be capitalized, and costs for an “on-going inspection and testing or maintenance program,” which would be accounted for as maintenance and charged to expense in the period incurred.

On June 30, 2005, the FERC issued an order providing guidance to the industry on accounting for costs associated with pipeline integrity management requirements. The order is effective prospectively from January 1, 2006. Under the order, the costs to be expensed include those to: prepare a plan to implement the program; identify high consequence areas; develop and maintain a record keeping system; and inspect affected pipeline segments. The costs of modifying the pipeline to permit in-line inspections, such as installing pig launchers and receivers, are to be capitalized, as are certain costs associated with developing or enhancing computer software or adding or replacing other items of plant. The Interstate

Natural Gas Association has sought rehearing of the FERC’s June 30 order. On September 19, 2005, the FERC denied the Interstate Natural Gas Association’s request for rehearing. We are currently reviewing the effects of this order on our financial statements.

In April 2004, we were advised that, as part of an audit of the FERC Form No. 2s, the FERC would be conducting a compliance audit of NGPL’s Form No. 2s for the period January 1, 2000 through December 31, 2003. On May 4, 2005, the FERC issued their audit report recommending that NGPL (i) revise its procedures to ensure that fines and penalties are recorded in the proper accounts as required by the FERC’s Uniform System of Accounts, (ii) make a correcting entry in the amount of $215,000 to properly record a penalty that was paid in 2000 and (iii) implement procedures to ensure that inactive projects are cleared from construction work in progress on a timely basis. In addition, the FERC audit team identified approximately $20.6 million of costs associated with pipeline assessment that were capitalized by NGPL in accordance with its capitalization policies during the audit period. As described previously, the Chief Accountant of the FERC has issued a Notice of Proposed Accounting Release that is intended to provide industry guidance on accounting for pipeline assessment activities. The FERC audit report indicates that appropriate accounting for these costs will be further considered when this industry-wide proceeding is concluded and a final Accounting Release is approved by the FERC. The FERC final Accounting Release was issued June 30, 2005 and the new accounting guidelines will be effective January 1, 2006, as further described above.

The FERC has commenced an audit of NGPL, as well as a number of other interstate natural gas pipelines, to test compliance with the FERC’s requirements related to the filings and postings of the Index of Customers.

On November 25, 2003, the FERC issued Order No. 2004, adopting new Standards of Conduct to become effective February 9, 2004. Every interstate natural gas pipeline was required to file a compliance plan by that date and was required to be in full compliance with the Standards of Conduct by June 1, 2004. The primary change from existing regulation is to make such standards applicable to an interstate pipeline’s interaction with many more affiliates (termed “Energy Affiliates”), including intrastate/Hinshaw pipelines (in general, a Hinshaw pipeline is a pipeline that receives gas at or within a state boundary, is regulated by an agency of that state, and all the gas it transports is consumed within that state), processors and gatherers and any company involved in gas or electric markets (such as electric generators and electric or gas marketers) even if they do not ship on the affiliated interstate pipeline. Local distribution companies (“LDCs”) are excluded, however, if they do not make any off-system sales. The Standards of Conduct require, inter alia, separate staffing of interstate pipelines and their Energy Affiliates (but certain support functions and senior management at the central corporate level may be shared) and strict limitations on communications from an interstate pipeline to an Energy Affiliate. NGPL and Kinder Morgan Interstate Gas Transmission LLC, a subsidiary of Kinder Morgan Energy Partners, filed for clarification and rehearing of Order No. 2004 on December 29, 2003, and numerous other rehearing requests have been submitted. In the request for rehearing, NGPL and Kinder Morgan Interstate Gas Transmission LLC asked that intrastate/Hinshaw pipeline affiliates not be included in the definition of Energy Affiliates. On February 9, 2004, the interstate pipelines owned by Kinder Morgan, Inc. and Kinder Morgan Energy Partners filed their compliance plans under Order No. 2004. In addition, on February 19, 2004, the Kinder Morgan interstate pipelines filed a joint request asking that their interaction with intrastate/Hinshaw pipeline affiliates be exempted from the Standards of Conduct. Separation from these entities would be the most burdensome requirement of the new rules for the Kinder Morgan interstate pipelines.

On April 16, 2004, the FERC issued Order No. 2004-A. The FERC extended the effective date of the new Standards of Conduct from June 1, 2004, to September 1, 2004. Otherwise, the FERC largely denied rehearing of Order No. 2004, but provided further clarification or adjustment in several areas.

The FERC continued the exemption for LDCs that do not make off-system sales, but clarified that the LDC exemption still applies if the LDC is also a Hinshaw pipeline. The FERC also clarified that an LDC can engage in certain sales and other Energy Affiliate activities to the limited extent necessary to support sales to customers located on its distribution system, and sales necessary to remain in balance under pipeline tariffs, without becoming an Energy Affiliate. The FERC declined to exempt producers from the definition of Energy Affiliate. The FERC also declined to exempt intrastate and Hinshaw pipelines, processors and gatherers from the definition of Energy Affiliate, but did clarify that such entities will not be Energy Affiliates if they do not participate in gas or electric commodity markets or interstate capacity markets (as capacity holder, agent or manager) or in financial transactions related to such markets. The FERC also clarified further the personnel and functions that can be shared by interstate pipelines and their Energy Affiliates, including senior officers and risk management personnel and the permissible role of holding or parent companies and service companies. The FERC also clarified that day-to-day operating information can be shared by interconnecting entities. Finally, the FERC clarified that an interstate pipeline and its Energy Affiliate can discuss potential new interconnects to serve the Energy Affiliate, but subject to posting and record-keeping requirements. The Kinder Morgan interstate pipelines sought rehearing to clarify the applicability of the LDC and Parent Company exemptions to them.

On July 21, 2004, the Kinder Morgan interstate pipelines filed additional joint requests asking for limited exemptions from certain requirements of FERC Order No. 2004 and asking for an extension of the deadline for full compliance with Order No. 2004 until 90 days after the FERC has completed action on the pipelines’ various rehearing and exemption requests. The pipelines also requested that Rocky Mountain Natural Gas Company, one of Kinder Morgan, Inc.’s wholly owned subsidiaries, be classified as an exempt LDC for purposes of Order No. 2004. These exemptions requested relief from the independent functioning and information disclosure requirements of Order No. 2004. The exemption requests proposed to treat as Energy Affiliates within the meaning of Order No. 2004 two groups of employees, (i) individuals in the Choice Gas Commodity Group within Kinder Morgan, Inc.’s Retail operations and (ii) commodity sales and purchasing personnel within Kinder Morgan Energy Partners’ Texas intrastate operations. Order No. 2004 regulations governing relationships between interstate pipelines and their Energy Affiliates would apply to relationships with these two groups. Under these proposals, certain critical operating functions could continue to be shared.

On August 2, 2004, the FERC issued Order No. 2004-B. In this order, the FERC extended the effective date of the new Standards of Conduct from September 1, 2004 to September 22, 2004. Also in this order, among other actions, the FERC denied the request for rehearing made by the Kinder Morgan interstate pipelines to clarify the applicability of the LDC and Parent Company exemptions to them.

On September 20, 2004, the FERC issued an order that conditionally granted the July 21, 2004 joint requests for limited exemptions from the requirements of the Standards of Conduct described above. In that order, the FERC directed the Kinder Morgan interstate pipelines to submit compliance plans regarding these filings within 30 days. These compliance plans were filed on October 19, 2004 and set out certain steps taken by the Kinder Morgan interstate pipelines to assure that employees in the Choice Gas Commodity Group within Kinder Morgan, Inc.’s Retail operations and the commodity sales and purchasing personnel of Kinder Morgan Energy Partners’ Texas intrastate operations do not have access to restricted interstate pipeline information or receive preferential treatment as to interstate pipeline services. The FERC will not enforce compliance of the independent functioning requirement of the Standards of Conduct as to these employees until 30 days after it acts on these compliance filings. In all other respects, the Kinder Morgan interstate pipelines were required to comply with Order No. 2004 by September 22, 2004.

The Kinder Morgan interstate pipelines have implemented compliance with the Standards of Conduct as of September 22, 2004, subject to the exemptions described in the prior paragraph. Compliance includes, inter alia, the posting of compliance procedures and organizational information for each interstate pipeline on its internet website, the posting of discount and tariff discretion information and the implementation of independent functioning for Energy Affiliates not covered by the prior paragraph (electric and gas gathering, processing or production affiliates).

On December 21, 2004, the FERC issued Order No. 2004-C, an order granting rehearing on certain issues and also clarifying certain provisions in the previous orders. The primary impact on the Kinder Morgan interstate pipelines from Order No. 2004-C is the granting of rehearing and allowing LDCs to participate in hedging activity related to on-system sales and still qualify for exemption from Energy Affiliate.

By an order issued on April 19, 2005, the FERC accepted the compliance plans filed by the Kinder Morgan interstate pipelines without modification, but subject to further amplification and clarification as to the intrastate group in three areas: (i) further description of the matters the shared transmission function personnel may discuss with the commodity sales and purchasing personnel within Kinder Morgan Energy Partners’ Texas intrastate operations; (ii) additional posting of organizational information about the commodity sales and purchasing personnel within Kinder Morgan Energy Partners’ Texas intrastate operations; and (iii) clarification that the President of Kinder Morgan Energy Partners’ intrastate pipeline group has received proper training and will not be a conduit for improperly sharing transmission or customer information with the commodity sales and purchasing personnel within Kinder Morgan Energy Partners’ Texas intrastate natural gas operations. The FERC also approved treatment of Rocky Mountain Natural Gas Company as an exempt LDC. The Kinder Morgan interstate pipelines made a compliance filing on May 18, 2005.

On July 25, 2003, the FERC issued a Modification to Policy Statement stating that FERC-regulated natural gas pipelines will, on a prospective basis, no longer be permitted to use gas basis differentials to price negotiated rate transactions. Effectively, interstate pipelines will no longer be permitted to use commodity price indices to structure transactions. Negotiated rates based on commodity price indices in existing contracts will be permitted to remain in effect until the end of the contract period for which such rates were negotiated. Price indexed contracts currently constitute an insignificant portion of the contracts on the interstate pipelines owned by Kinder Morgan, Inc. and Kinder Morgan Energy Partners. Moreover, in subsequent orders in individual pipeline cases, the FERC has allowed negotiated rate transactions using pricing indices so long as revenue is capped by the applicable maximum rate(s). Rehearing on this aspect of the Modification to Policy Statement has been sought by several pipelines, but the FERC has not yet acted on rehearing.

See Note 8 of Notes to Consolidated Financial Statements included in our 2004 Form 10-K for additional information regarding regulatory matters. Among other matters disclosed there (and elsewhere in our 2004 Form 10-K), we indicate that shippers on our pipelines have rights, under certain circumstances prescribed by applicable regulations, to challenge the rates we charge. There can be no assurance that we will not face challenges to the rates we charge for service on our pipeline systems, or that our future revenues and net income would not be materially adversely affected by a successful challenge.

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. Additionally, we have established reserves totaling $11.4 million at September 30, 2005 to address known environmental remediation sites. After consideration of reserves established, we believe that costs for environmental remediation and ongoing compliance with these regulations will not have a material adverse effect on our cash flows, financial position or results of operations or diminish our ability to operate our businesses. 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.

See Note 9(A) of Notes to Consolidated Financial Statements included in our 2004 Form 10-K for additional information regarding environmental matters.

United States of America, ex rel., Jack J. Grynberg v. K N Energy, Civil Action No. 97-D-1233, filed in the U.S. District Court, District of Colorado. This action was filed on June 9, 1997 pursuant to the federal False Claims Act and involves allegations of mismeasurement of natural gas produced from federal and Indian lands. The complaint asks to recover all royalties the Government allegedly should have received had the volume and heating content of the natural gas been valued properly, along with treble damages and civil penalties as provided for in the False Claims Act. Mr. Grynberg, as relator, seeks his statutory share of any recovery, plus expenses and attorney fees and costs. The Department of Justice has decided not to intervene in support of the action. The complaint is part of a larger series of similar complaints filed by Mr. Grynberg against 77 natural gas pipelines (approximately 330 other defendants). An earlier single action making substantially similar allegations against the pipeline industry was dismissed by Judge Hogan of the U.S. District Court for the District of Columbia on grounds of improper joinder and lack of jurisdiction. As a result, Mr. Grynberg filed individual complaints in various courts throughout the country. In 1999, these cases were consolidated by the Judicial Panel for Multidistrict Litigation (“MDL”), and transferred to the District of Wyoming. The MDL case is called In Re Natural Gas Royalties Qui Tam Litigation, Docket No. 1293. Motions to dismiss were filed and an oral argument on the motion to dismiss occurred on March 17, 2000. On July 20, 2000, the United States of America filed a motion to dismiss those claims by Mr. Grynberg that deal with the manner in which defendants valued gas produced from federal leases (referred to as valuation claims). Judge Downes denied the defendant’s motion to dismiss on May 18, 2001. The United States’ motion to dismiss most of the plaintiff’s valuation claims has been granted by the Court. Mr. Grynberg appealed that dismissal to the 10^th Circuit, which requested briefing regarding its jurisdiction over that appeal. Mr. Grynberg’s appeal was dismissed for lack of appellate jurisdiction. Discovery to determine issues related to the Court’s subject matter jurisdiction, arising out of the False Claims Act, is complete. Briefing has been completed and oral argument on jurisdictional issues was held before the Special Master on March 17 and 18, 2005. On May 7, 2003, Mr. Grynberg sought leave to file a Third Amended Complaint, which adds allegations of undermeasurement related to CO₂ production. Defendants have filed briefs opposing leave to amend. Neither the Court nor the Special Master have ruled on Mr. Grynberg’s motion to amend. On May 13, 2005, the Special Master issued his Report and Recommendations to Judge Downes in the In Re Natural Gas Royalties Qui Tam Litigation, Docket No. 1293. The Special Master found that there was a prior public disclosure of the mismeasurement fraud Mr. Grynberg alleged, and that Mr. Grynberg was not an original source of the allegations. As a result, the Special Master recommended dismissal on jurisdictional grounds of the Kinder Morgan defendants. On June 27, 2005, Mr. Grynberg filed a motion to modify and partially reverse the Special Master’s recommendations, and the Defendants filed a motion to adopt the Special Master’s recommendations with modifications. The District Court has scheduled an oral argument for December 9, 2005 on the motions concerning the Special Master’s recommendations. We expect that the Federal Court in Wyoming may adopt the recommendations in the Special Master’s report and enter the formal dismissal

order in the fourth quarter or by early next year. It is likely that Mr. Grynberg will appeal any dismissal to the 10^th Circuit Court of Appeals.

Darrell Sargent d/b/a Double D Production v. Parker & Parsley Gas Processing Co., American Processing, L.P. and Cesell B. Cheatham, et al., Cause No. 878, filed in the 100^th Judicial District Court, Carson County, Texas. The plaintiff filed a purported class action suit in 1999 and amended its petition in late 2002 to assert claims on behalf of over 1,000 producers who process gas through as many as ten gas processing plants formerly owned by American Processing, L.P. (“American Processing”), a former wholly owned subsidiary of Kinder Morgan, Inc., in Carson and Gray counties and other surrounding Texas counties. The plaintiff claims that American Processing (and subsequently, ONEOK, Inc. “ONEOK,” which purchased American Processing from us in 2000) improperly allocated liquids and gas proceeds to the producers. In particular, among other claims, the plaintiff challenges the methods and assumptions used at the plants to allocate liquids and gas proceeds among the producers and processors. The petition asserts claims for breach of contract and Natural Resources Code violations relating to the period from 1994 to the present. The plaintiff alleged generally in the petition that damages are “not to exceed $200 million” plus attorneys fees, costs and interest. The defendants filed a counterclaim for overpayments made to producers.

Pioneer Natural Resources USA, Inc., formerly known as Parker & Parsley Gas Processing Company (“Parker & Parsley”), is a co-defendant. Parker & Parsley claimed indemnity from American Processing based on its sale of assets to American Processing on October 4, 1995. We accepted indemnity and defense subject to a reservation of rights pending resolution of the suit. The plaintiff also named ONEOK as a defendant. We and ONEOK are defending the case pursuant to an agreement whereby ONEOK is responsible for any damages that may be attributable to the period following ONEOK’s acquisition of American Processing from us in 2000.

On or about January 21, 2003, Benson-McCown & Company (“Benson-McCown”), another producer who sold gas to American Processing and ONEOK, filed a “Plea in Intervention” in which it essentially duplicated the plaintiff’s claims and also asserted the right to bring a class action and serve as one of the class representatives. Defendants denied Benson-McCown’s claim and filed a counterclaim for overpayments made to Benson-McCown over the years.

On January 14, 2005, Defendants filed a motion to deny class certification. Subsequently, the plaintiffs agreed to dismiss and withdraw their class claims. An Agreed Order Dismissing all class claims, with prejudice, was entered by the Court on January 19, 2005. After the class claims were dismissed with prejudice, defendants settled the individual claims asserted by Darrell Sargent. The sole remaining claims are those asserted by Benson-McCown, individually, and defendants’ counterclaims with respect thereto.

On May 13, 2005, NGPL experienced a rupture on its 36-inch diameter Gulf Coast #3 natural gas pipeline in Harrison County, Texas. The pipeline rupture resulted in an explosion and fire that severely damaged an adjacent power plant co-owned by EWO Marketing, L.P. and others. In addition, local residents within an approximate one-mile radius were evacuated by local authorities until the site was secured. According to published reports, injuries were limited to one employee at the power plant who was treated for minor injuries and released. Although we are not aware of any litigation related to this matter which has been commenced as of the date hereof, NGPL has received claims for damages to nearby homes and buildings which allegedly resulted from the explosion. NGPL and its insurers are investigating such claims and processing them in due course.

Although no assurances can be given, we believe that we have meritorious defenses to all lawsuits and legal proceedings in which we are defendants. Based on our evaluation of the above matters, and after consideration of reserves established, we believe that the resolution of such matters will not have a material adverse effect on our business, cash flows, financial position or results of operations.

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

In December 2004, the FASB issued SFAS No. 123R (revised 2004), Share-Based Payment. This Statement amends SFAS No. 123, Accounting for Stock-Based Compensation, and requires companies to expense the value of employee stock options and similar awards. Significant provisions of SFAS No. 123R include the following:

share-based payment awards result in a cost that will be measured at fair value on the awards’ grant date, based on the estimated number of awards that are expected to vest. Compensation cost for awards that vest would not be reversed if the awards expire without being exercised;

when measuring fair value, companies can choose an option-pricing model that appropriately reflects their specific circumstances and the economics of their transactions;

companies will recognize compensation cost for share-based payment awards as they vest, including the related tax effects. Upon settlement of share-based payment awards, the tax effects will be recognized in the income statement or additional paid-in capital; and

public companies are allowed to select from three alternative transition methods – each having different reporting implications.

In April 2005, the Securities and Exchange Commission extended the effective date for public companies to implement SFAS No. 123R (revised 2004). The new Statement is now effective for non-small business entities starting with the first interim or annual period of the company’s first fiscal year beginning on or after June 15, 2005 (January 1, 2006, for us). We do not expect the implementation of this Statement to have a material adverse impact on our financial position or results of operations.

In March 2005, the FASB issued Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations—an interpretation of FASB Statement No. 143. This Interpretation clarifies that the term “conditional asset retirement obligation” as used in SFAS No. 143, Accounting for Asset Retirement Obligations, refers to a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and (or) method of settlement. Thus, the timing and (or) method of settlement may be conditional on a future event.

Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. The fair value of a liability for the conditional asset retirement obligation should be recognized when incurred – generally upon acquisition, construction, or development and (or) through the normal operation of the asset. Uncertainty about the timing and (or) method of settlement of a conditional asset retirement obligation

should be factored into the measurement of the liability when sufficient information exists. This Interpretation also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation.

This Interpretation is effective no later than the end of fiscal years ending after December 15, 2005 (December 31, 2005, for us). We are currently reviewing the effects of this Interpretation.

In June 2005, the FASB issued SFAS No. 154, Accounting Changes and Error Corrections. This Statement replaces Accounting Principles Board Opinion (“APB”) No. 20, Accounting Changes and SFAS No. 3, Reporting Accounting Changes in Interim Financial Statements. SFAS No. 154 applies to all voluntary changes in accounting principle, and changes the requirements for accounting for and reporting of a change in accounting principle.

SFAS No. 154 requires retrospective application to prior periods’ financial statements of a voluntary change in accounting principle unless it is impracticable. In contrast, APB No. 20 previously required that most voluntary changes in accounting principle be recognized by including in net income of the period of the change the cumulative effect of changing to the new accounting principle.

The provisions of this Statement will be effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005 (January 1, 2006 for us). Earlier application is permitted for accounting changes and corrections of errors made occurring in fiscal years beginning after June 1, 2005. The Statement does not change the transition provisions of any existing accounting pronouncements, including those that are in a transition phase as of the effective date of this Statement. Adoption of this Statement will not have any immediate effect on our consolidated financial statements, and we will apply this guidance prospectively.

In June 2005, the Emerging Issues Task Force reached a consensus on Issue No. 04-5, or EITF 04-5, Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights. EITF 04-5 generally provides that a sole general partner is presumed to control a limited partnership and provides guidance for purposes of assessing whether certain limited partners rights might preclude a general partner from controlling a limited partnership.

For general partners of all new limited partnerships formed, and for existing limited partnerships for which the partnership agreements are modified, the guidance in EITF 04-5 is effective after June 29, 2005. For general partners in all other limited partnerships, the guidance is effective no later than the beginning of the first reporting period in fiscal years beginning after December 15, 2005 (January 1, 2006, for us). We are currently reviewing the effects of this Issue.

On October 31, 2005, we sold 1,586,965 Kinder Morgan Management shares that we owned for approximately $75.1 million. This sale resulted in a capital gain for tax purposes of $36.4 million, reducing our capital loss carryforward to $46.6 million, which expires $42.4 million in 2005, $1.6 million in 2006, $2.0 million in 2008 and $0.6 million in 2009.

On October 6, 2005, we amended our $800 million five-year senior unsecured revolving credit facility to make administrative changes and, subject to the closing of our acquisition of Terasen, to change definitions and covenants to reflect the inclusion of Terasen as a subsidiary of ours.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

The following discussion should be read in conjunction with (i) the accompanying interim Consolidated Financial Statements and related Notes and (ii) our 2004 Form 10-K, including the Consolidated Financial Statements, related Notes and Management’s Discussion and Analysis of Financial Condition and Results of Operations. The following interim results may not be indicative of the results to be expected over the course of an entire year. In this report Kinder Morgan Energy Partners, L.P., a publicly traded pipeline master limited partnership in which we own the general partner interest and significant limited partner interests, is referred to as “Kinder Morgan Energy Partners.” Additional information on Kinder Morgan Energy Partners is contained in its report on Form 10-K for the year ended December 31, 2004 and in its report on Form 10-Q for the quarter ended September 30, 2005.

Our discussion and analysis of financial condition and results of operations are based on our interim consolidated financial statements, prepared in accordance with accounting principles generally accepted in the United States of America as applicable to interim financial statements to be filed with the Securities and Exchange Commission and contained within this report. Certain amounts included in or affecting our financial statements and related disclosure must be estimated, requiring us to make certain assumptions with respect to values or conditions 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 and other methods we consider reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from our estimates.

In preparing our financial statements and related disclosures, we must use estimates in determining the economic useful lives of our assets, the effective income tax rate to apply to our pre-tax income, obligations under our employee benefit plans, provisions for uncollectible accounts receivable, unbilled revenues for our natural gas distribution deliveries for which meters have not yet been read, cost and timing of environmental remediation efforts, potential exposure to adverse outcomes from judgments or litigation settlements, exposures under contractual indemnifications and various other recorded or disclosed amounts. Certain of these accounting estimates are of more significance in our financial statement preparation process than others. Information regarding our accounting policies and estimates that we consider to be “critical” can be found in our 2004 Form 10-K. There have not been any significant changes in these policies and estimates during the first nine months of 2005.

committee of independent Terasen directors created by the Terasen board to oversee the process. On October 18, 2005, the transaction was approved by a vote of Terasen shareholders. The transaction is also subject to regulatory approvals and other conditions, and is expected to close by year-end 2005.

We expect to issue approximately 12 million common shares and pay approximately US$2 billion in cash to acquire all of the outstanding shares of Terasen Inc. The actual number of our common shares issued and cash paid to acquire Terasen will depend on the actual number of Terasen shares and Terasen stock options outstanding upon closing of the transaction and the elections made by the Terasen shareholders described above. We expect to issue incremental long-term debt to fund the cash portion of the purchase price. We anticipate that the long-term debt we issue to fund the cash portion of the acquisition consideration will be fixed-rate and a portion will be swapped to floating-rate interest in order to attain an approximate 50% fixed/50% floating debt ratio. A bridge facility may be used prior to the issuance of the long-term debt.

Terasen owns two core businesses: (i) a natural gas distribution business serving approximately 875,000 customers in British Columbia and (ii) a refined products and crude oil transportation pipeline business with three pipelines, (a) Trans Mountain Pipeline, extending from Edmonton to Vancouver and Washington State, (b) Corridor Pipeline, extending from the Athabasca oilsands to Edmonton and (c) a one-third interest in the Express and Platte pipeline systems extending from Alberta to the U.S. Rocky Mountain region and Midwest. In addition, Terasen owns a water and utility services business that operates 90 water and wastewater systems in over 50 communities throughout British Columbia, Alberta and Alaska.

Our net income decreased by approximately 2.5% from $111.9 million in the third quarter of 2004 to $109.2 million in the third quarter of 2005. Our 2005 results for the third quarter and first nine months of 2005 include pre-tax losses of $24.6 million and $26.4 million, respectively, to record hedge ineffectiveness (see Note 14 of the accompanying Notes to Consolidated Financial Statements), which are recorded as reductions within the caption “Operating Revenues: Natural Gas Sales” in the accompanying interim Consolidated Statements of Operations. The third quarter loss was largely the result of significant changes in the values of various natural gas price indices relative to the value of the Henry Hub index used by the NYMEX in the valuation of derivative instruments, caused by hurricane-related supply disruptions in the Gulf of Mexico area. The majority of these unrealized losses relate to hedges that will be closed out in the fourth quarter of 2005. The losses from the settlement of the derivative contracts and gains from the physical gas sales transactions related to them were factored into our total year 2005 expectations discussed in our third quarter earnings release. As a result, based on our market expectations, the unrealized losses in the third quarter will largely be a positive impact in the fourth quarter versus our forecast. Our income from continuing operations increased by approximately 9.5% from $343.4 million in the first nine months of 2004 to $375.8 million in the first nine months of 2005. In addition to the hedge ineffectiveness discussed above, 2005 year-to-date results include a net increase of $4.7 million, primarily related to gains on the sale of Kinder Morgan Management shares during the second quarter of 2005, net of income taxes (see Note 8 of the accompanying Notes to Consolidated Financial Statements). Net income for the first nine months of 2005 also includes a $1.4 million charge, net of tax, related to the disposal of discontinued operations (see Note 10 of the accompanying Notes to Consolidated Financial Statements). Following is a discussion of items affecting operating income, other income and expenses and earnings per share. Please refer to the individual business segment discussions included elsewhere herein for additional information regarding business segment results. Refer to the headings “Other Income and (Expenses),” “Income Taxes – Continuing Operations” and “Discontinued Operations” included elsewhere herein for additional information regarding these items.

Our results for the third quarter of 2005, in comparison to 2004, reflect an increase of $43.5 million (17%) in operating revenues and a decrease of $16.6 million (17%) in operating income. The increase in operating revenues in the third quarter of 2005 was principally attributable to the net effects of (i) increased revenues in our NGPL business segment, partially offset by the above-mentioned loss for hedge ineffectiveness, (ii) approximately $3.8 million of 2005 revenues from KM Insurance Ltd. (which is largely offset by operating expenses), our wholly owned subsidiary formed during the second quarter of 2005 for the purpose of providing insurance services to Kinder Morgan Energy Partners and us and (iii) our contribution of TransColorado to Kinder Morgan Energy Partners, effective November 1, 2004. Operating income was positively impacted in the third quarter of 2005, relative to 2004, by (i) increased segment earnings from our NGPL business segment and (ii) reduced general and administrative expenses. These positive impacts were offset by (i) the $24.6 million pre-tax loss for hedge ineffectiveness, as discussed above, (ii) our contribution of TransColorado to Kinder Morgan Energy Partners and (iii) reduced earnings from our Kinder Morgan Retail business segment. Refer to the individual business segment discussions following for additional information regarding business segment results.

Our results for the first nine months of 2005, in comparison to 2004, reflect an increase of $83.6 million (10%) in operating revenues and a decrease of $8.4 million (3%) in operating income. The increase in operating revenues in the first nine months of 2005 was principally attributable to the net effects of (i) increased revenues in our NGPL and Kinder Morgan Retail business segments, partially offset by the above-mentioned $26.4 million loss for hedge ineffectiveness, (ii) $6.3 million of 2005 revenues from KM Insurance Ltd. (which is largely offset by operating expenses) and (iii) our contribution of TransColorado to Kinder Morgan Energy Partners. Operating income was affected in the first nine months of 2005, relative to 2004, principally by the same factors affecting third quarter results, as discussed above.

“Other Income and (Expenses)” increased from income of $88.1 million in the third quarter of 2004 to income of $104.4 million in the third quarter of 2005, an increase of $16.3 million (18%). This increase was primarily attributable to the net effects of (i) increased equity in earnings of Kinder Morgan Energy Partners in 2005, due in part to the strong performance from the assets held by Kinder Morgan Energy Partners, partially offset by an increase in minority interest expense attributable to the minority interests in Kinder Morgan Management and (ii) increased interest expense due largely to increased interest rates. “Other Income and (Expenses)” increased from income of $256.6 million in the first nine months of 2004 to income of $334.9 million in the first nine months of 2005, an increase of $78.3 million (31%). Results for the first nine months of 2005, relative to 2004, were affected principally by the same factors affecting third quarter results, as discussed above. In addition, year-to-date results include $26.5 million of pre-tax gains from the sales of Kinder Morgan Management shares that we owned (see Note 8 of the accompanying Notes to Consolidated Financial Statements). Refer to the heading “Other Income and (Expenses)” included elsewhere herein for additional information regarding these items.

Diluted earnings per common share decreased from $0.90 in the third quarter of 2004 to $0.88 in the third quarter of 2005, a decrease of $0.02 (2%), reflecting, in addition to the financial and operating impacts discussed preceding, a decrease of 1.0 million (0.8%) in average diluted shares outstanding resulting principally from the net effect of (i) a decrease in shares due to our share repurchase program (see Note 12 of the accompanying Notes to Consolidated Financial Statements), (ii) an increase in shares due to the exercise of stock options by employees and the issuance of restricted shares to employees and (iii) the increased dilutive effect of stock options resulting from the increase in the market price of our shares.

Diluted earnings per common share from continuing operations increased from $2.75 in the first nine months of 2004 to $3.04 in the first nine months of 2005, an increase of $0.29 (11%), reflecting, in

addition to the financial and operating impacts discussed preceding, a decrease of 1.1 million (0.9%) in average diluted shares outstanding due principally to the same factors affecting the third quarter, as discussed above. In addition, in the first nine months of 2005, we recorded a loss on disposal of discontinued operations of $1.4 million, net of tax, or $0.01 per diluted common share (see “Discontinued Operations” included elsewhere herein).

The following comparative discussion of our results of operations is by segment for factors affecting segment earnings, and on a consolidated basis for other factors.

We manage our various businesses by, among other things, allocating capital and monitoring operating performance. This management process includes dividing the company into business segments so that performance can be effectively monitored and reported for a limited number of discrete businesses.

Effective November 1, 2004, we contributed TransColorado Gas Transmission Company to Kinder Morgan Energy Partners. Effective with the contribution, the results of operations of TransColorado Gas Transmission Company are no longer included in our consolidated results of operations. In addition to our three remaining business segments, we derive a substantial portion of earnings from our investment in Kinder Morgan Energy Partners, which is discussed under “Earnings from Our Investment in Kinder Morgan Energy Partners” following.

The accounting policies we apply in the generation of business segment earnings are generally the same as those applied to our consolidated operations and described in Note 1 of Notes to Consolidated Financial Statements included in our 2004 Form 10-K, except that (i) certain items below the “Operating

Income” line (such as interest expense) are either not allocated to business segments or are not considered by management in its evaluation of business segment performance and (ii) equity in earnings of equity method investees, other than Kinder Morgan Energy Partners, are included in segment earnings. These equity method earnings are included in “Other Income and (Expenses)” in the accompanying interim Consolidated Statements of Operations. In addition, (i) certain items included in operating income (such as general and administrative expenses) are not considered by management in its evaluation of business segment performance and (ii) gains and losses from incidental sales of assets are included in segment earnings. With adjustment for these items, we currently evaluate business segment performance primarily based on operating income in relation to the level of capital employed. We account for intersegment sales at market prices, while we account for asset transfers at either market value or, in some instances, book value.

Following are operating results by individual business segment (before intersegment eliminations), including explanations of significant variances between the periods presented.

NGPL’s segment earnings for the third quarter and first nine months of 2005 include pre-tax losses of $24.6 million and $26.4 million, respectively, due to hedge ineffectiveness, which are recorded as reductions to operating revenues. The third quarter loss was largely the result of significant changes in the values of various natural gas price indices relative to the value of the Henry Hub index used by the NYMEX in the valuation of derivative instruments, caused by hurricane-related supply disruptions in the Gulf of Mexico area. The majority of these unrealized losses relate to hedges that will be closed out in the fourth quarter of 2005. The losses from the settlement of the derivative contracts and gains from

the physical gas sales transactions related to them were factored into our total year 2005 expectations discussed in our third quarter earnings release. As a result, based on our market expectations, the unrealized losses in the third quarter will largely be a positive impact in the fourth quarter versus our forecast. NGPL’s segment earnings decreased by 7% from $94.8 million in the third quarter of 2004 to $88.6 million in the third quarter of 2005. Segment earnings for the third quarter of 2005 were positively impacted, relative to 2004, by (i) increased transportation and storage service revenues in 2005 resulting, in part, from increased firm demand revenues, the recent expansion of our storage system and the acquisition of the Black Marlin Pipeline (see discussion below), (ii) increased operational gas sales and (iii) reduced operations and maintenance expenses for hydrostatic testing. These positive impacts were offset by (i) a $24.6 million pre-tax loss for hedge ineffectiveness, as discussed above, (ii) increased depreciation expense and (iii) increased property tax expenses. The increase in overall operating revenues in the third quarter of 2005, relative to 2004, was largely the result of (i) increased transportation and storage service revenues, as discussed above and (ii) increased operational gas sales volumes and increased natural gas prices in 2005. These revenue increases were offset by a $24.6 million reduction in 2005 revenues to record a pre-tax loss for hedge ineffectiveness. NGPL’s operational gas sales are primarily made possible by its collection of fuel in-kind pursuant to its transportation tariffs and recovery of storage cushion gas volumes. The increase in systems throughput in the third quarter of 2005, relative to 2004, was due principally to higher utilization of the Amarillo and Louisiana lines and warmer weather. The increase in systems throughput in the third quarter of 2005, relative to 2004, did not have a significant direct impact on revenues or segment earnings due to the fact that transportation revenues are derived primarily from “demand” contracts in which shippers pay a fee to reserve a set amount of system capacity for their use.

NGPL’s segment earnings increased from $294.9 million in the first nine months of 2004 to $302.2 million in the first nine months of 2005, an increase of $7.3 million (2%). Segment revenues and earnings for the first nine months of 2005 were impacted, relative to 2004, by principally the same factors affecting third quarter results, as discussed above, except that, on a year-to-date basis, operations and maintenance expenses were higher, due largely to higher costs for electric compression.

In October 2005, we announced that NGPL has extended long-term, firm transportation and storage contracts with Northern Illinois Gas Company (“Nicor”) and BP Canada Energy Marketing (“BP”). Combined, the contracts represent approximately 1.1 million Dth per day of firm transportation service. Under the terms of the transportation agreement with Nicor, which extends into the first quarter of 2009, NGPL will provide its largest shipper with up to 917,865 Dth per day of firm transportation service. The new agreement replaces a contract that was due to expire March 31, 2006. In addition, Nicor has extended firm storage contracts totaling 42 Bcf that were scheduled to expire March 31, 2006, and March 31, 2007. A total of 16.5 Bcf has been extended until March 31, 2009, with the remaining 25.5 Bcf extended until March 31, 2010. As part of the agreement with BP, NGPL will provide as much as 200,000 Dth per day of firm transportation capacity through April 30, 2007.

In August 2005, NGPL filed a certificate application with the FERC for an additional 10 Bcf expansion of its North Lansing storage facility in east Texas, which is expected to be completed in 2007 at a cost of approximately $63 million. NGPL recently completed an open season for this expansion and binding long-term precedent agreements have been executed on all of the additional capacity. In June 2005, NGPL received a certificate from the FERC for its Amarillo-Gulf Coast cross-haul expansion. The $16.5 million project will add 51,000 Dth per day of capacity and is expected to be in service in April 2006. In addition, NGPL began drilling storage injection/withdrawal wells during the third quarter of 2005 to expand its Sayre storage field in Oklahoma by 10 Bcf. The $35 million project is expected to begin service in the spring of 2006 and all of the expansion capacity has been contracted for under long-term agreements.

In the second quarter of 2004, NGPL completed construction of 10.7 Bcf of storage service expansion at its existing North Lansing storage facility in east Texas, all of which is fully subscribed under long-term contracts. Effective September 1, 2004, NGPL acquired the Black Marlin Pipeline, a 38-mile, 30-inch pipeline that runs from Bryan County, Oklahoma to Lamar County, Texas. The Black Marlin Pipeline ties into NGPL’s Amarillo/Gulf Coast line and increased this line’s capacity by 38,000 Dth per day. This incremental capacity was fully subscribed in an open season under long-term contracts. Please refer to our 2004 Form 10-K for additional information regarding NGPL.

Effective November 1, 2004, we contributed TransColorado Gas Transmission Company to Kinder Morgan Energy Partners for total consideration of $275.0 million (approximately $210.8 million in cash and 1.4 million Kinder Morgan Energy Partners common units). In conjunction with this contribution, we recorded a pre-tax loss of $0.6 million. As of November 1, 2004, we no longer include the results of operations of TransColorado Gas Transmission Company in our consolidated results of operations.

Kinder Morgan Retail’s segment results decreased from earnings of $4.8 million in the third quarter of 2004 to a loss of $1.1 million in the third quarter of 2005. Results for the third quarter of 2005 were

negatively impacted, relative to 2004, by (i) a $4.8 million adjustment to accrued natural gas sales related to volume estimates and (ii) increased operating expenses due, in part, to system expansion. These negative impacts were partially offset by continued customer growth, principally in Colorado. The $0.1 million increase in operating revenues in the third quarter of 2005, relative to 2004, was principally due to the net effects of (i) the adjustment to accrued natural gas sales volumes as discussed above, (ii) increased natural gas commodity sales prices in 2005 (which is accompanied by a corresponding increase in gas purchase costs), (iii) a higher percentage of our Wyoming customers choosing our pass-on commodity rates in 2005 rather than transportation only service (which increases natural gas sales revenues and is also accompanied by a corresponding increase in gas purchase costs) and (iv) continued customer growth, principally in Colorado.

Kinder Morgan Retail’s segment earnings decreased by 15% from $43.5 million in the first nine months of 2004 to $36.9 million in the first nine months of 2005. Segment results for the first nine months of 2005, relative to 2004, were principally impacted by (i) reduced space heating and agricultural demand in 2005 and (ii) increased operating expenses in 2005 due, in part, to system expansion. These negative impacts were partially offset by continued customer growth, principally in Colorado. The $25.9 million increase in operating revenues in the first nine months of 2005, relative to 2004, was principally due to the net effects of (i) increased natural gas commodity sales prices in 2005 (which is accompanied by a corresponding increase in gas purchase costs), (ii) a higher percentage of our Wyoming customers choosing our pass-on commodity rates in 2005 rather than transportation only service (which increases natural gas sales revenues and is also accompanied by a corresponding increase in gas purchase costs), (iii) continued customer growth, principally in Colorado and (iv) reduced space heating and agricultural demand in 2005. We currently expect our Kinder Morgan Retail business segment to fall short of its full-year 2005 budgeted segment earnings of $70.7 million. Please refer to our 2004 Form 10-K for additional information regarding Kinder Morgan Retail.

Power’s segment earnings increased from $4.1 million in the third quarter of 2004 to $4.6 million in the third quarter of 2005, an increase of $0.5 million (11%). Segment earnings for the third quarter of 2005 were positively impacted, relative to 2004, principally by (i) the first full quarter of providing operating and maintenance management services at a new 103-megawatt combined-cycle natural gas-fired power plant in Snyder, Texas, which is generating electricity for Kinder Morgan Energy Partners’ SACROC

operations and (ii) increased equity in earnings of Thermo Cogeneration Partnership due to (1) third quarter 2004 results included the impact of a turbine failure and (2) reduced 2005 interest expense resulting from the repayment of notes payable.

Power’s segment earnings increased by approximately 14% from $11.7 million in the first nine months of 2004 to $13.4 million in the first nine months of 2005. Segment earnings for the first nine months of 2005 were positively impacted, relative to 2004, principally by increased equity in earnings of Thermo Cogeneration Partnership due to (i) the favorable resolution of claims in the Enron bankruptcy proceeding, (ii) higher capacity revenues and (iii) reduced 2005 interest expense resulting from the repayment of notes payable. These positive impacts were partially offset by legal costs incurred in 2005 relating to the Wrightsville power facility, which was placed into bankruptcy by Mirant in 2003. Please refer to our 2004 Form 10-K for additional information regarding Power.

The impact on our pre-tax earnings from our investment in Kinder Morgan Energy Partners was as follows:

The increases in our earnings from this investment in the third quarter and first nine months of 2005, in comparison to the corresponding periods of 2004, are principally due to improved operating results from Kinder Morgan Energy Partners’ various businesses. For 2005, pre-tax earnings attributable to our investment in Kinder Morgan Energy Partners are expected to increase by approximately 18% due to, among other factors, improved performance from its existing assets. However, there are factors beyond

the control of Kinder Morgan Energy Partners that may affect its results, including developments in the regulatory arena and as yet unforeseen competitive developments or acquisitions. Additional information about Kinder Morgan Energy Partners is contained in its Quarterly Report on Form 10-Q for the three months ended September 30, 2005 and its Annual Report on Form 10-K for the year ended December 31, 2004.

“Other Income and (Expenses)” increased from income of $256.6 million in the first nine months of 2004 to income of $334.9 million in the first nine months of 2005, an increase of $78.3 million (31%). This increase was principally due to (i) increased equity in the earnings of Kinder Morgan Energy Partners in 2005, due in part to the strong performance from the assets held by Kinder Morgan Energy Partners, partially offset by an increase of $9.5 million in minority interest expense, of which $10.1 million was attributable to the minority interests in Kinder Morgan Management and (ii) $26.5 million of pre-tax gains from the sale of Kinder Morgan Management shares that we owned (see Note 8 of the accompanying Notes to Consolidated Financial Statements). These positive impacts were partially offset by an increase of $15.3 million in interest expense due to higher interest rates, partially offset by lower

The income tax provision increased from $72.1 million in the third quarter of 2004 to $74.6 million in the third quarter of 2005, an increase of $2.5 million (3%) due principally to differences in estimates between the income tax return and the income tax provision, partially offset by a decrease in the estimated state effective tax rate used in computing our income tax provision.

The income tax provision increased from $220.6 million in the first nine months of 2004 to $258.1 million in the first nine months of 2005, an increase of $37.5 million (17%) due principally to (i) an increase in pre-tax income from continuing operations and (ii) the additional tax provision due to our gains from sales of Kinder Morgan Management shares that we owned (see Notes 4 and 8 of the accompanying Notes to Consolidated Financial Statements), partially offset by a decrease in the estimated state effective tax rate used in computing our income tax provision.

Our income tax provision for the first nine months of 2005 contains three primary components: (i) tax on income from continuing operations, (ii) tax on minority interest earnings (i.e., Kinder Morgan Management units not owned by us) and (iii) tax on the gains from the sale of Kinder Morgan Management shares owned by us.

At December 31, 2004, we had a capital loss carryforward of approximately $56.1 million. A capital loss carryforward can be utilized to reduce capital gain during the five years succeeding the year in which a capital loss is incurred. The amounts and the years in which our capital loss carryforward expires are $52.5 million during 2005, $1.6 million during 2006 and $2.0 million during 2008.

We have concluded that it is more likely than not that this deferred tax asset will be realized through the sale of assets that will generate sufficient capital gain to fully utilize the capital loss carryforward during the periods specified above. Our ownership of Kinder Morgan Energy Partners common units and Kinder Morgan Management shares are specific assets that could be sold to generate capital gain. We sold approximately 2.1 million Kinder Morgan Management shares during the first nine months of 2005, generating a gain for tax purposes of approximately $41.8 million. On October 31, 2005, we sold 1,586,965 Kinder Morgan Management shares that we owned, generating a gain for tax purposes of $36.4 million. We owned approximately 11.7 million Kinder Morgan Management shares at November 1, 2005.

During the third quarter of 2005, the Wrightsville power facility (in which we owned an interest) was sold to Arkansas Electric Cooperative Corporation. We estimate that, as a result of this sale, we will realize a capital loss for tax purposes of $68.7 million. We did not record a loss for book purposes due to the fact that, for book purposes, we wrote off the carrying value of our investment in the Wrightsville power facility in 2003. For tax purposes, we are required to apply our 2005 capital gains from the sale of Kinder Morgan Management shares to the 2005 capital loss from the Wrightsville power facility first, before applying them to our capital loss carryforwards. We plan to sell additional Kinder Morgan Management shares that we own to offset the remaining capital loss carryforward as of November 1, 2005, of which approximately $42.4 million expires this year.

No valuation allowance has been provided with respect to this deferred tax asset.

During 1999, we adopted and implemented a plan to discontinue a number of lines of business. During 2000, we essentially completed the disposition of these discontinued operations. For the three months ended September 30, 2005, no incremental losses were recorded. For the nine months ended September 30, 2005, incremental losses of approximately $1.4 million (net of tax benefits of $0.8 million) were recorded to increase previously recorded liabilities to reflect updated estimates. The cash flow impacts associated with discontinued operations are discussed under “Cash Flows” following. Note 10 of the accompanying Notes to Consolidated Financial Statements contains additional information on these matters.

Our primary cash requirements, in addition to normal operating, general and administrative expenses, are for debt service, capital expenditures, common stock repurchases and quarterly cash dividends to our common shareholders. Our capital expenditures (other than sustaining capital expenditures), our common stock repurchases and our quarterly cash dividends to our common shareholders are discretionary. We expect to fund these expenditures with existing cash and cash flows from operating activities and by issuing short-term commercial paper. In addition, we could meet these cash requirements through borrowings under our credit facilities or by issuing long-term notes or additional shares of common stock. We expect to issue approximately 12 million common shares and approximately $2 billion of incremental long-term debt to fund our proposed acquisition of Terasen. See “Proposed Acquisition of Terasen” included elsewhere herein.

The following table illustrates the sources of our invested capital. The decline in our ratio of total debt to total capital from 2002 through 2004 has resulted from a number of factors, including our increased cash flows from operations. In recent periods, we have significantly increased our dividends per common share and have announced our intention to consider further increases on a periodic basis, and we maintain an ongoing program to repurchase outstanding shares of our common stock. Upon the closing of our proposed acquisition of Terasen, we expect our ratio of total debt to total capital to increase to approximately 56 percent. See “Proposed Acquisition of Terasen” included elsewhere herein. Although we are currently reviewing the effects of EITF 04-5, we expect our ratio of total debt to total capital to increase further if the implementation of EITF 04-5 results in including the accounts and balances of Kinder Morgan Energy Partners in our consolidated financial statements in 2006. See Note 18 of the accompanying Notes to Consolidated Financial Statements for information regarding EITF 04-5.

In addition to the direct sources of debt and equity financing shown in the following table, we obtain financing indirectly through our ownership interests in unconsolidated entities. Our largest such unconsolidated investment is in Kinder Morgan Energy Partners. See “Investment in Kinder Morgan Energy Partners” following.

The discussion under the heading “Liquidity and Capital Resources” in Management’s Discussion and Analysis of Financial Condition and Results of Operations included in our 2004 Form 10-K includes a comprehensive discussion of (i) our investments in and obligations to unconsolidated entities, (ii) our contractual obligations and (iii) our contingent liabilities. These disclosures, which reflected balances and contractual arrangements existing as of December 31, 2004, also reflect current balances and contractual arrangements except for changes discussed following. Changes in our long-term debt and

commercial paper are discussed under “Net Cash Flows from Financing Activities” following and in Note 11 of the accompanying Notes to Consolidated Financial Statements.

As a result of our adoption of FASB Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest Entities, effective December 31, 2003, the subsidiary trusts associated with these securities are no longer consolidated.

Cash and cash equivalents netted against short-term debt were $10,966, $176,520, $11,076 and $35,653 for September 30, 2005 and December 31, 2004, 2003 and 2002, respectively.

Outstanding notes and debentures plus short-term debt, less cash and cash equivalents.

Our principal sources of short-term liquidity are our revolving bank facility, our commercial paper program (which is supported by our revolving bank facility) and cash provided by operations. As of September 30, 2005, we had available an $800 million five-year senior unsecured revolving credit facility dated August 5, 2005. This credit facility can be used for general corporate purposes, including as backup for our commercial paper program. At September 30, 2005 and October 28, 2005, we had $269.3 million and $292.8 million, respectively, of commercial paper issued and outstanding. After inclusion of applicable outstanding letters of credit, which reduce borrowing capacity, the remaining available borrowing capacity under the bank facility was $442.0 million and $418.5 million at September 30, 2005 and October 28, 2005, respectively.

Our current maturities of long-term debt of $5 million at September 30, 2005 represented $5 million of current maturities of our 6.50% Series Debentures due September 1, 2013. Apart from our notes payable and current maturities of long-term debt, our current assets exceed our current liabilities by approximately $189.5 million at September 30, 2005. Given our expected cash flows from operations and our unused debt capacity as discussed preceding, including our five-year credit facility, and based on our projected cash needs in the near term, we do not expect any liquidity issues to arise. Our next significant debt maturity is our $300 million of 6.80% Senior Notes in 2008.

On July 20, 2005, our board of directors declared an increase in our quarterly dividend from $0.70 per common share ($2.80 annualized) to $0.75 per common share ($3.00 annualized). On October 19, 2005, our Board of Directors approved a cash dividend of $0.75 per common share payable on November 14, 2005 to shareholders of record as of October 31, 2005.

We had outstanding fixed-to-floating interest rate swap agreements with a notional principal amount of $1.25 billion at September 30, 2005. These agreements effectively convert the interest expense associated with our 7.25% Series Debentures due in 2028 and $750 million of our 6.50% Senior Notes due in 2012 from fixed to floating rates based on the three-month London Interbank Offered Rate (“LIBOR”) plus a credit spread. These swaps are accounted for as fair value hedges under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. These agreements are further described under “Risk Management” in Item 7A of our 2004 Form 10-K.

On March 25, 2004, Kinder Morgan Management closed the issuance and sale of 360,664 listed shares in a limited registered offering. We purchased none of the shares from the offering. Kinder Morgan Management used the net proceeds of approximately $14.9 million from the offering to buy additional i-units from Kinder Morgan Energy Partners.

On March 1, 2005, our $500 million of 6.65% Senior Notes matured, and we paid the holders of the notes, utilizing a combination of cash and incremental short-term borrowings.

On August 5, 2005, we entered into an $800 million five-year senior unsecured revolving credit facility dated August 5, 2005. This credit facility replaced an $800 million five-year senior unsecured revolving

credit agreement dated August 18, 2004, effectively extending the maturity of our credit facility by one year, and includes covenants and requires payment of facility fees that are similar in nature to the covenants and facility fees required by the revolving bank facility it replaced, which are discussed in our 2004 Form 10-K. In this credit facility, the definition of consolidated net worth, which is a component of total capitalization, was revised to exclude other comprehensive income/loss, and the definition of consolidated indebtedness was revised to exclude the debt of Kinder Morgan Energy Partners that is guaranteed by us. On October 6, 2005, we amended our $800 million five-year senior unsecured revolving credit facility to make administrative changes and, subject to the closing of our acquisition of Terasen, to change definitions and covenants to reflect the inclusion of Terasen as a subsidiary of ours.

Certain of our customers are experiencing financial problems that have had a significant impact on their creditworthiness. We have implemented and will continue to work to implement, as appropriate in the future, to the extent allowable under applicable laws, tariffs and regulations, prepayments and other security requirements such as letters of credit to enhance our credit position relating to amounts owed from these customers. We cannot assure that one or more of our financially distressed customers will not default on their obligations to us or that such a default or defaults will not have a material adverse effect on our business.

Pursuant to our continuing commitment to operational excellence and our focus on safe, reliable operations, we have implemented, and intend to implement in the future, enhancements to certain of our operational practices in order to strengthen our environmental and asset integrity performance. The repairs resulting from these enhancements have resulted and we expect that they will result in higher capital and/or operating costs and expenses; however, we believe these enhancements and repairs will provide us the greater long-term benefits of improved environmental and asset integrity performance.

At September 30, 2005, we owned, directly, and indirectly in the form of i-units corresponding to the number of shares of Kinder Morgan Management we owned, approximately 33.0 million limited partner units of Kinder Morgan Energy Partners. These units, which consist of 14.4 million common units, 5.3 million Class B units and 13.3 million i-units, represent approximately 15.2 percent of the total limited partner interests of Kinder Morgan Energy Partners. In addition, we are the sole stockholder of the general partner of Kinder Morgan Energy Partners, which holds an effective 2 percent interest in Kinder Morgan Energy Partners and its operating partnerships. Together, our limited partner and general partner interests represented approximately 16.9 percent of Kinder Morgan Energy Partners’ total equity interests at September 30, 2005. We receive quarterly distributions on the i-units owned by Kinder Morgan Management in additional i-units and distributions on our other units in cash.

In addition to distributions received on our limited partner interests as discussed above, we also receive an incentive distribution from Kinder Morgan Energy Partners as a result of our ownership of the general partner interest in Kinder Morgan Energy Partners. This incentive distribution is calculated in increments based on the amount by which quarterly distributions to unit holders exceed specified target levels as set forth in Kinder Morgan Energy Partners’ partnership agreement, reaching a maximum of 50% of distributions allocated to the general partner for distributions above $0.23375 per limited partner unit.

We reflect our investment in Kinder Morgan Energy Partners under the equity method of accounting and, accordingly, report our share of Kinder Morgan Energy Partners’ earnings as “Equity in Earnings” in our interim Consolidated Statement of Operations in the period in which such earnings are reported by Kinder Morgan Energy Partners. See Notes 8 and 9 of the accompanying Notes to Consolidated Financial Statements for additional information regarding our investment in Kinder Morgan Energy

The following discussion of cash flows should be read in conjunction with the accompanying interim Consolidated Statements of Cash Flows and related supplemental disclosures, and the Consolidated Statements of Cash Flows and related supplemental disclosures included in our 2004 Form 10-K.

“Net Cash Flows Provided by Operating Activities” decreased from $418.9 million for the nine months ended September 30, 2004 to $247.4 million for the nine months ended September 30, 2005, a decrease of $171.5 million (40.9%). This negative variance is principally due to (i) an $110.7 million increased use of working capital cash for hedging activities, due to increases in NGPL hedge volumes and natural gas prices, (ii) a $25.0 million pension payment and an $8.5 million postretirement benefit plan payment, both made during 2005, (iii) an $83.7 million increase in cash paid for income taxes during 2005 and (iv) a net increased use of cash of $24.4 million for gas in underground storage. Significant period-to-period variations in cash used or generated from gas in storage transactions are due to changes in injection and withdrawal volumes as well as fluctuations in natural gas prices. These negative impacts were partially offset by (i) a $70.2 million increase in cash distributions received in 2005 attributable to our interest in Kinder Morgan Energy Partners and (ii) an increase of $11.3 million in 2005 cash attributable to deferred purchased gas costs.

“Net Cash Flows Used in Investing Activities” decreased from $98.4 million for the nine months ended September 30, 2004 to $16.9 million for the nine months ended September 30, 2005, a decrease of $81.5 million. This decreased use of cash is principally due to (i) $10.5 million net decreased 2005 investments in margin deposits associated with hedging activities utilizing energy derivative instruments, (ii) $92.5 million of proceeds received in 2005 from the sale of Kinder Morgan Management shares, (see Note 8 of the accompanying Notes to Consolidated Financial Statements) and (iii) the fact that the nine months ended September 30, 2004 included an additional $17.5 million investment in Kinder Morgan Energy Partners. Partially offsetting these factors is the fact that the nine months ended September 30, 2004 included $40.8 million of proceeds from the sales of turbines.

“Net Cash Flows Used in Financing Activities” increased from $319.4 million for the nine months ended September 30, 2004 to $396.1 million for the nine months ended September 30, 2005, an increase of $76.7 million (24.0%). This increase is principally due to (i) $500 million of cash used in 2005 to retire our $500 million 6.65% Senior Notes, (ii) an $143.9 million increase in cash paid during 2005 to repurchase our common shares, (iii) a $54.6 million increase in cash paid for dividends in 2005, principally due to the increased dividends declared per share and (iv) the fact that the nine months ended September 30, 2004 included $14.9 million of proceeds, net of issuance costs, from the issuance of Kinder Morgan Management shares. Partially offsetting these factors were (i) $248.5 million of proceeds, net of issuance costs, received in 2005 from the issuance of our 5.15% Senior Notes due March 1, 2015 (See Note 11 of the accompanying Notes to Consolidated Financial Statements), (ii) a $90.3 million reduction in short-term debt during the nine months ended September 30, 2004 versus incremental short-term borrowings of $269.3 million during the nine months ended September 30, 2005 and (iii) a $14.4 million reduction in short-term advances to unconsolidated affiliates, principally Kinder Morgan Energy Partners, during 2005.

Refer to Note 18 of the accompanying Notes to Consolidated Financial Statements for information regarding recent accounting pronouncements.

This filing includes forward-looking statements. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. They use words such as “anticipate,” “believe,” “intend,” “plan,” “projection,” “forecast,” “strategy,” “position,” “continue,” “estimate,” “expect,” “may,” or the negative of those terms or other variations of them or comparable terminology. In particular, statements, express or implied, concerning future actions, conditions or events, future operating results or the ability to generate sales, income or cash flow or to pay dividends are forward-looking statements. Forward-looking statements are not guarantees of 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 which could cause actual results to differ from those in the forward-looking statements include:

price trends and overall demand for natural gas liquids, refined petroleum products, oil, carbon dioxide, natural gas, electricity, coal and other bulk materials and chemicals 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 or those of Kinder Morgan Energy Partners implemented by the FERC or another regulatory agency or, with respect to Kinder Morgan Energy Partners, the California Public Utilities Commission;

Kinder Morgan Energy Partners’ ability and our ability to acquire new businesses and assets and integrate those operations into existing operations, as well as the ability to make expansions to our respective facilities;

difficulties or delays experienced by railroads, barges, trucks, ships or pipelines in delivering products to or from Kinder Morgan Energy Partners’ terminals or pipelines or our pipelines;

Kinder Morgan Energy Partners’ ability and our ability to successfully identify and close acquisitions and make cost-saving changes in operations;

shut-downs or cutbacks at major refineries, petrochemical or chemical plants, ports, utilities, military bases or other businesses that use Kinder Morgan Energy Partners’ or our services or provide services or products to Kinder Morgan Energy Partners or us;

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;

changes in accounting pronouncements that impact the measurement of our results of operations, the timing of when such measurements are to be made and recorded, and the disclosures surrounding these activities;

our ability to offer and sell equity securities and debt securities or obtain debt financing in sufficient amounts to implement that portion of our business plan that contemplates growth through acquisitions of operating businesses and assets and expansions of our facilities;

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

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

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

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

national, international, regional and local economic, competitive and regulatory conditions and developments;

the timing and extent of changes in commodity prices for oil, natural gas, electricity and certain agricultural products;

unfavorable results of litigation involving Kinder Morgan Energy Partners and the fruition of contingencies referred to in Kinder Morgan Energy Partners’ Quarterly Report on Form 10-Q for the quarter ended September 30, 2005. Our future results also could be adversely impacted by unfavorable results of litigation and the fruition of contingencies referred to in Notes 16 and 17 of the accompanying Notes to Consolidated Financial Statements.

You should not put undue reliance on any forward-looking statements. See Items 1 and 2 “Business and Properties – Risk Factors” of our annual report filed on Form 10-K for the year ended December 31, 2004, for a more detailed description of these and other factors that may affect the forward-looking statements. When considering forward-looking statements, one should keep in mind the risk factors described in “Risk Factors” above. The risk factors could cause our actual results to differ materially from those contained in any forward-looking statement. 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.

There have been no material changes in market risk exposures that would affect the quantitative and qualitative disclosures presented as of December 31, 2004, in Item 7A “Quantitative and Qualitative Disclosures About Market Risk” contained in our 2004 Form 10-K. See also Note 14 of the accompanying Notes to Consolidated Financial Statements.

As of September 30, 2005, our management, including our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. Based upon and as of the date of the evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the design and operation of our disclosure controls and procedures were effective in all material respects to provide reasonable assurance that information required to be disclosed in the reports we file and submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported as and when required, and is accumulated and communicated to our management, including our Chief Executive Officer and our Chief Financial Officer, to allow timely decisions regarding required disclosure. There has been no change in our internal control over financial reporting during the quarter ended September 30, 2005 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

See Note 17 of the accompanying Notes to Consolidated Financial Statements in Part I, Item 1, which is incorporated herein by reference.

During the quarter ended September 30, 2005, we did not sell any equity securities that were not registered under the Securities Act of 1933, as amended.

On August 14, 2001, we announced a plan to repurchase $300 million of our outstanding common stock, which program was increased to $400 million, $450 million, $500 million, $550 million, $750 million and $800 million in February 2002, July 2002, November 2003, April 2004, November 2004 and April 2005, respectively.

At its July 20, 2005 meeting, the compensation committee of our board of directors approved a special contribution of an additional 1% of base pay into the Kinder Morgan Savings Plan (a defined contribution 401(k) plan) for each eligible employee. Each eligible employee started to receive an additional 1% company contribution based on eligible base pay to his or her Savings Plan account each pay period beginning with the first pay period of August 2005 and continuing through the last pay period of July 2006.

The 1% contribution is in the form of our common stock (the same as the current 4% contribution). The 1% contribution is in addition to, and does not change or otherwise impact, the 4% contribution that eligible employees currently receive. It may be converted to any other Savings Plan investment fund at any time and it will vest on the second anniversary of the employee’s date of hire. Since this additional

1% company contribution is discretionary, compensation committee approval will be required annually for each special contribution.

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

		Page Number
PART I.	FINANCIAL INFORMATION

Item 1.	Financial Statements. (Unaudited)

	Consolidated Balance Sheets	3-4
	Consolidated Statements of Operations	5
	Consolidated Statements of Cash Flows	6
	Notes to Consolidated Financial Statements	7-26

Item 2.	Management’s Discussion and Analysis of Financial
	Condition and Results of Operations.	27-45

Item 3.	Quantitative and Qualitative Disclosures About Market Risk.	46

Item 4.	Controls and Procedures.	46

PART II.	OTHER INFORMATION

Item 1.	Legal Proceedings.	47

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds.	47

Item 3.	Defaults Upon Senior Securities.	47

Item 4.	Submission of Matters to a Vote of Security Holders.	47

Item 5.	Other Information.	47-48

Item 6.	Exhibits.	48

SIGNATURE		49

	September 30,	December 31,
	2005	2004
	(In thousands)
ASSETS:
Current Assets:
Cash and Cash Equivalents	$ 10,966	$ 176,520
Restricted Deposits	38,558	38,049
Accounts Receivable, Net:
Trade	63,892	82,544
Related Parties	6,783	5,859
Note Receivable	1,128	4,594
Inventories	90,023	41,781
Gas Imbalances	8,219	5,625
Other	375,407	114,286
	594,976	469,258

Investments:
Kinder Morgan Energy Partners	2,157,443	2,305,212
Goodwill	893,234	918,076
Other	180,515	176,143
	3,231,192	3,399,431

Property, Plant and Equipment, Net	5,847,165	5,851,965

Deferred Charges and Other Assets	395,406	396,247

Total Assets	$10,068,739	$10,116,901

	September 30, 2005		December 31, 2004
	(In thousands except shares)
LIABILITIES AND STOCKHOLDERS’ EQUITY:
Current Liabilities:
Current Maturities of Long-term Debt	$ 5,000		$ 505,000
Notes Payable	269,300		-
Accounts Payable:
Trade	46,524		58,119
Related Parties	1,192		180
Accrued Interest	28,914		67,206
Accrued Taxes	39,229		32,547
Gas Imbalances	15,740		18,254
Other	273,857		157,503
	679,756		838,809

Other Liabilities and Deferred Credits:
Deferred Income Taxes	2,518,832		2,530,065
Other	136,133		148,044
	2,654,965		2,678,109

Long-term Debt:
Outstanding Notes and Debentures	2,502,891		2,257,950
Deferrable Interest Debentures Issued to Subsidiary Trusts	283,600		283,600
Value of Interest Rate Swaps	62,386		88,243
	2,848,877		2,629,793

Minority Interests in Equity of Subsidiaries	1,137,152		1,105,436

Stockholders’ Equity:
Common Stock-
Authorized - 300,000,000 Shares, Par Value $5 Per Share
Outstanding - 135,895,616 and 134,198,905 Shares,
Respectively, Before Deducting 13,387,251 and 10,666,801
Shares Held in Treasury	679,478		670,995
Additional Paid-in Capital	1,963,924		1,863,145
Retained Earnings	1,086,771		975,912
Treasury Stock	(765,846	)	(558,844	)
Deferred Compensation	(39,991	)	(31,712	)
Accumulated Other Comprehensive Loss	(176,347	)	(54,742	)
Total Stockholders’ Equity	2,747,989		2,864,754

Total Liabilities and Stockholders’ Equity	$10,068,739		$10,116,901

	Nine Months Ended September 30,
	2005		2004
	(In thousands)
Cash Flows From Operating Activities:
Net Income	$ 374,439		$ 343,362
Adjustments to Reconcile Net Income to Net Cash Flows
from Operating Activities:
Loss on Disposal of Discontinued Operations, Net of Tax	1,389		-
Depreciation and Amortization	89,883		89,137
Deferred Income Taxes	113,652		79,931
Equity in Earnings of Kinder Morgan Energy Partners	(480,399	)	(405,548	)
Distributions from Kinder Morgan Energy Partners	389,496		319,271
Equity in Earnings of Other Investments	(10,259	)	(8,467	)
Minority Interests in Income of Consolidated Subsidiaries	55,022		45,511
Deferred Purchased Gas Costs	15,618		4,343
Net Gains on Sales of Assets	(27,152	)	(2,055	)
Pension Contribution in Excess of Expense	(24,027	)	(116	)
Changes in Gas in Underground Storage	(34,786	)	(10,397	)
Changes in Working Capital Items	(234,215	)	(18,687	)
Payment to Terminate Interest Rate Swap	(3,543	)	-
Hedge Ineffectiveness	26,407		783
Other, Net	(2,115	)	(17,660	)
Net Cash Flows Provided by Continuing Operations	249,410		419,408
Net Cash Flows Used in Discontinued Operations	(2,007	)	(487	)
Net Cash Flows Provided by Operating Activities	247,403		418,921

Cash Flows From Investing Activities:
Capital Expenditures	(104,338	)	(110,306	)
Investment in Kinder Morgan Energy Partners (Note 8)	(3,176	)	(17,504	)
Net Investments in Margin Deposits	(509	)	(10,987	)
Other Investments	(404	)	-
Sale of Kinder Morgan Management Shares	92,500		-
Proceeds from Sales of Turbines	-		40,809
Net Cost of Removal from Sales of Other Assets	(977	)	(440	)
Net Cash Flows Used in Investing Activities	(16,904	)	(98,428	)

Cash Flows From Financing Activities:
Short-term Debt, Net	269,300		(90,300	)
Long-term Debt Issued	250,000		-
Long-term Debt Retired	(505,000	)	(5,000	)
Issuance of Shares by Kinder Morgan Management	-		15,000
Common Stock Issued	55,421		40,051
Short-term Advances From (To) Unconsolidated Affiliates	88		(14,354	)
Treasury Stock Acquired	(198,994	)	(55,109	)
Cash Dividends, Common Stock	(263,580	)	(208,981	)
Minority Interests, Net	(1,775	)	(627	)
Debt Issuance Costs	(1,513	)	-
Securities Issuance Costs	-		(75	)
Net Cash Flows Used in Financing Activities	(396,053	)	(319,395	)

Net (Decrease) Increase in Cash and Cash Equivalents	(165,554	)	1,098
Cash and Cash Equivalents at Beginning of Period	176,520		11,076
Cash and Cash Equivalents at End of Period	$ 10,966		$ 12,174

	Three Months Ended September 30,				Nine Months Ended September 30,
	2005		2004		2005		2004
	(In thousands, except per share amounts)
Net Income, As Reported	$ 109,164		$ 111,930		$ 374,439		$ 343,362
Add: Stock-based Employee Compensation
Expense Included in Reported Net Income,
Net of Related Tax Effects	1,000		671		3,448		2,221
Deduct: Total Stock-based Employee
Compensation Expense Determined under
the Fair Value Method for All Awards,
Net of Related Tax Effects	(2,614	)	(3,644	)	(9,082	)	(11,737	)
Net Income, Pro Forma	$ 107,550		$ 108,957		$ 368,805		$ 333,846

Basic Earnings Per Share:
As Reported	$ 0.89		$ 0.91		$ 3.05		$ 2.77
Pro Forma	$ 0.88		$ 0.88		$ 3.01		$ 2.70

Diluted Earnings Per Share:
As Reported	$ 0.88		$ 0.90		$ 3.03		$ 2.75
Pro Forma	$ 0.87		$ 0.87		$ 2.98		$ 2.67

	Three Months Ended September 30, 2005					September 30, 2005
	Segment Earnings		Revenues From External Customers¹	Depreciation And Amortization	Capital Expenditures	Segment Assets
	(In thousands)
Natural Gas Pipeline Company of America	$ 88,609	²	$ 222,834	$ 25,186	$ 42,666	$ 5,633,649
Kinder Morgan Retail	(1,068	)	46,347	4,386	12,677	494,047
Power	4,573		20,116	740	-	384,215
Segment Totals	92,114		289,297	$ 30,312	$ 55,343	6,511,911
Other Revenues³			3,809
Total Revenues			$ 293,106
Earnings from Investment in Kinder
Morgan Energy Partners	169,192			Investment in Kinder Morgan
General and Administrative Expenses	(16,942	)		Energy Partners		2,157,443
Other Income and (Expenses)	(60,623	)		Goodwill		893,234
Income from Continuing Operations				Other⁴		506,151
Before Income Taxes	$ 183,741			Consolidated		$10,068,739

	Three Months Ended September 30, 2004
	Segment Earnings		Revenues From External Customers¹	Depreciation And Amortization	Capital Expenditures
	(In thousands)
Natural Gas Pipeline Company of America	$ 94,775		$ 174,943	$ 23,735	$ 23,197
TransColorado	7,128		9,663	1,096	9,095
Kinder Morgan Retail	4,839		46,210	4,245	16,633
Power	4,113		18,826	873	-
Segment Totals	110,855		$ 249,642	$ 29,949	$ 48,925
Earnings from Investment in Kinder
Morgan Energy Partners	143,979
General and Administrative Expenses	(18,334	)
Other Income and (Expenses)	(52,447	)
Income from Continuing Operations
Before Income Taxes	$ 184,053

	Nine Months Ended September 30, 2005
	Segment Earnings		Revenues From External Customers¹	Depreciation And Amortization	Capital Expenditures
	(In thousands)
Natural Gas Pipeline Company of America	$ 302,218	²	$ 645,550	$ 73,884	$ 79,465
Kinder Morgan Retail	36,943		226,176	13,414	24,873
Power	13,416		44,606	2,585	-
Segment Totals	352,577		916,332	$ 89,883	$ 104,338
Other Revenues³			6,348
Total Revenues			$ 922,680
Earnings from Investment in Kinder
Morgan Energy Partners	480,399
General and Administrative Expenses	(52,181	)
Other Income and (Expenses)	(146,916	)
Income from Continuing Operations
Before Income Taxes	$ 633,879

	Nine Months Ended September 30, 2004
	Segment Earnings		Revenues From External Customers¹	Depreciation And Amortization	Capital Expenditures
	(In thousands)
Natural Gas Pipeline Company of America	$ 294,948		$ 570,627	$ 70,679	$ 56,395
TransColorado	18,139		25,344	3,217	14,506
Kinder Morgan Retail	43,491		200,299	12,623	39,405
Power	11,744		42,825	2,618	-
Segment Totals	368,322		$ 839,095	$ 89,137	$ 110,306
Earnings from Investment in Kinder
Morgan Energy Partners	405,548
General and Administrative Expenses	(60,501	)
Other Income and (Expenses)	(149,415	)
Income from Continuing Operations
Before Income Taxes	$ 563,954

	Three Months Ended September 30,				Earnings Increase
	2005		2004		(Decrease)
	(In thousands except per share amounts)
Operating Revenues	$ 293,106		$ 249,642		$ 43,464
Gas Purchases and Other Costs of Sales	(113,007	)	(55,821	)	(57,186	)
General and Administrative Expenses	(16,942	)	(18,334	)	1,392
Other Operating Expenses	(83,800	)	(79,552	)	(4,248	)
Operating Income	79,357		95,935		(16,578	)
Other Income and (Expenses)	104,384		88,118		16,266
Income Taxes	(74,577	)	(72,123	)	(2,454	)
Income from Continuing Operations	109,164		111,930		(2,766	)
Loss on Disposal of Discontinued
Operations, Net of Tax	-		-		-
Net Income	$ 109,164		$ 111,930		$ (2,766	)

Diluted Earnings Per Common Share	$ 0.88		$ 0.90		$ (0.02	)

Number of Shares Used in Computing Diluted
Earnings Per Common Share	123,684		124,683		(999	)

	Three Months Ended September 30,			Increase
	2005		2004	(Decrease)
	(In thousands except systems throughput)
Total Operating Revenues	$ 222,834		$ 174,943	$ 47,891

Gas Purchases and Other
Costs of Sales	$ 80,904		$ 29,037	$ 51,867

Segment Earnings	$ 88,609	¹	$ 94,775	$ (6,166	)


Systems Throughput (Trillion Btus)	379.6		336.3	43.3

	Three Months Ended September 30, 2004		Nine Months Ended September 30, 2004
	(In thousands)
Total Operating Revenues		$ 9,663		$ 25,344

Segment Earnings		$ 7,128		$ 18,139

¹	Included in Power segment earnings.
²	Included in Natural Gas Pipeline Company of America segment earnings.

Period	Total Number of Shares Purchased¹		Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs²		Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs
July 1 to July 31, 2005		-		$ -		-		$ 55,083,777
August 1 to August 31, 2005		95,600		$ 92.69		95,600		$ 46,221,121
September 1 to September 30, 2005		6,000		$ 92.90		6,000		$ 45,663,586

Total		101,600		$ 92.70		101,600		$ 45,663,586

	Three Months Ended September 30,				Nine Months Ended September 30,
	2005		2004		2005		2004
	(In thousands)
Service Cost	$ 2,493		$ 2,148		$ 7,480		$ 6,445
Interest Cost	2,993		2,858		8,980		8,575
Expected Return on Assets	(5,101	)	(4,111	)	(15,303	)	(12,252	)
Amortization of:
Transition Asset	(8	)	(41	)	(24	)	(122	)
Prior Service Cost	44		44		133		133
Loss	179		70		534		214
Net Periodic Pension Cost	$ 600		$ 968		$ 1,800		$ 2,993

	Three Months Ended September 30,				Nine Months Ended September 30,
	2005		2004		2005		2004
	(In thousands)
Service Cost	$ 110		$ (10	)	$ 330		$ 219
Interest Cost	1,302		760		3,905		4,066
Expected Return on Assets	(1,428	)	(1,407	)	(4,285	)	(3,880	)
Amortization of:
Transition Obligation	-		232		-		697
Prior Service Cost	(415	)	(1,042	)	(1,246	)	(923	)
Loss	1,206		1,286		3,621		2,808
Net Periodic Postretirement Benefit Cost	$ 775		$ (181	)	$ 2,325		$ 2,987