10-K 1 knight10k2008.htm KNIGHT INC. 2008 FORM 10-K knight10k2008.htm
Knight Inc. Form 10-K
 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM 10-K
 
þ
  
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2008
or
 
o
  
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _____to_____
 
Commission File Number 1-06446
Knight Inc.
(Exact name of registrant as specified in its charter)
 
Kansas
  
48-0290000
(State or other jurisdiction of incorporation or organization)
  
(I.R.S. Employer Identification No.)

500 Dallas Street, Suite 1000, Houston, Texas 77002
(Address of principal executive offices, including zip code)

Registrant’s telephone number, including area code (713) 369-9000
 
Securities registered pursuant to Section 12(b) of the Act:
 
None
 
Securities registered pursuant to section 12(g) of the Act:
 
None
 
Indicate by checkmark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act:
Yeso  No þ
 
Indicate by checkmark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act:
Yes þ  No o
 
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:  Yes o   No þ
 
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  þ
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):  Large accelerated filer o  Accelerated filer o  Non-accelerated filer þ  Smaller reporting company o
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o  No þ
 
The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant was $0 at June 30, 2008.
 
The number of shares outstanding of the registrant’s common stock, $0.01 par value, as of January 30, 2009 was 100 shares.

 
 
 
Knight Inc. Form 10-K


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2
 
Knight Inc. Form 10-K



KNIGHT INC. AND SUBSIDIARIES
CONTENTS (Continued)
 
____________
Note:  Individual financial statements of the parent company are omitted pursuant to the provisions of Accounting Series Release No. 302.

 
3
 
 
Knight Form 10-K


 
 
In this report, unless the context requires otherwise, references to “we,” “us,” “our,” or the “Company” are intended to mean Knight Inc. (a private Kansas corporation incorporated on May 18, 1927, formerly known as Kinder Morgan, Inc.) and its consolidated subsidiaries. All dollars are United States dollars, except where stated otherwise. Canadian dollars are designated as C$. Unless otherwise indicated, all volumes of natural gas are stated at a pressure base of 14.73 pounds per square inch absolute and at 60 degrees Fahrenheit and, in most instances, are rounded to the nearest major multiple. In this report, the term “MMcf” means million cubic feet, the term “Bcf” means billion cubic feet, the term “MBbl/d” means million barrels per day, the term “Bbl” means barrels, the term “bpd” means barrels per day and the terms “Dth” (dekatherms) and “MMBtus” mean million British Thermal Units (“Btus”). Natural gas liquids consist of ethane, propane, butane, iso-butane and natural gasoline. The following discussion should be read in conjunction with the accompanying Consolidated Financial Statements and related Notes.
 
(A) General Development of Business
 
We are a large energy transportation and storage company, operating or owning an interest in approximately 36,000 miles of pipelines and approximately 170 terminals. Our pipelines transport natural gas, gasoline, crude oil, carbon dioxide and other products, and our terminals store petroleum products and chemicals and handle bulk materials like coal and petroleum coke. We are also the leading provider of carbon dioxide, commonly called “CO2,” for enhanced oil recovery projects in North America. We have both regulated and nonregulated operations. Our executive offices are located at 500 Dallas Street, Suite 1000, Houston, Texas 77002 and our telephone number is (713) 369-9000.
 
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., of which we indirectly own all of the outstanding common equity, owns all of Kinder Morgan Management’s voting shares. 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., (“Kinder Morgan Energy Partners”) subject to Kinder Morgan G.P., Inc.’s right to approve certain transactions. Kinder Morgan Management also owns all of the i-units of Kinder Morgan Energy Partners. The i-units are a class of Kinder Morgan Energy Partners’ limited partner interests that have been, and will be, issued only to Kinder Morgan Management. We have certain rights and obligations with respect to these securities.
 
Kinder Morgan Energy Partners is a publicly traded pipeline limited partnership whose limited partnership units are traded on the New York Stock Exchange under the ticker symbol “KMP.” Kinder Morgan Management’s shares (other than the voting shares held by Kinder Morgan G.P., Inc.) are traded on the New York Stock Exchange under the ticker symbol “KMR.”
 
The equity interests in Kinder Morgan Energy Partners and Kinder Morgan Management (which are both consolidated in our financial statements) owned by the public are reflected within “minority interest” on our consolidated balance sheet. The earnings recorded by Kinder Morgan Energy Partners and Kinder Morgan Management that are attributed to their units and shares, respectively, held by the public are reported as “minority interest” in the accompanying Consolidated Statements of Operations.
 
On May 30, 2007, Kinder Morgan, Inc. merged with a wholly owned subsidiary of Knight Holdco LLC, with Kinder Morgan, Inc. continuing as the surviving legal entity and subsequently renamed Knight Inc. Knight Holdco LLC is a private company owned by Richard D. Kinder, our Chairman and Chief Executive Officer; our co-founder William V. Morgan; former Kinder Morgan, Inc. board members Fayez Sarofim and Michael C. Morgan; other members of our senior management, most of whom are also senior officers of Kinder Morgan G.P., Inc. and Kinder Morgan Management; and affiliates of (i) Goldman Sachs Capital Partners, (ii) Highstar Capital, (iii) The Carlyle Group and (iv) Riverstone Holdings LLC. This transaction is referred to in this report as “the Going Private transaction.” As a result of the Going Private transaction, we are now privately owned, our stock is no longer traded on the New York Stock Exchange and we have adopted a new basis of accounting for our assets and liabilities.
 
Additional information concerning the business of, and our investment in and obligations to, Kinder Morgan Energy Partners and Kinder Morgan Management is contained in Notes 2 and 9 of the accompanying Notes to Consolidated Financial Statements and in Kinder Morgan Energy Partners’ and Kinder Morgan Management’s Annual Reports on Form 10-K for the year ended December 31, 2008.
 
 
The following is a brief listing of significant developments since December 31, 2007. We begin with developments pertaining to our seven reportable business segments, described more fully below in “(C) Narrative Description of 
 

 
4
 
Items 1. and 2.   Business and Properties. (continued)
Knight Form 10-K


Business—Business Segments.” Additional information regarding most of these items may be found elsewhere in this report.
 
Natural Gas Pipeline Company of America (“NGPL”)
 
 
·
On February 15, 2008, we sold an 80% ownership interest in our NGPL business segment to Myria Acquisition Inc. (“Myria”) for approximately $5.9 billion. The $5.9 billion of proceeds from this sale, along with cash on hand, were used to: (i) payoff the outstanding $4.2 billion balance on our senior secured credit facility’s Tranche A and Tranche B term loans that had been incurred to help finance the Going Private transaction discussed above, (ii) repurchase $1.67 billion of outstanding debt securities and (iii) reduce the outstanding debt under our $1.0 billion revolving credit facility. We continue to operate NGPL’s assets pursuant to a 15-year operating agreement. Myria is owned by a syndicate of investors led by Babcock & Brown, an international investment and specialized fund and asset management group.
 
Power
 
 
·
Effective January 1, 2008, we sold our interests in three natural gas-fired power plants in Colorado to Bear Stearns and we received net proceeds of $63.1 million.
 
Products Pipelines–KMP
 
 
·
In October 2008, Kinder Morgan Energy Partners successfully completed a series of tests demonstrating the commercial feasibility of transporting batched denatured ethanol on our 16-inch diameter gasoline pipeline that extends between Tampa and Orlando, Florida. After making certain mechanical modifications to the pipeline in late-November, Kinder Morgan Energy Partners began batching denatured ethanol shipments along with gasoline shipments for its customers, making our Central Florida Pipeline the first gasoline pipeline in the U.S. capable of also handling ethanol in commercial movements.
 
In addition to the Central Florida Pipeline ethanol project, Kinder Morgan Energy Partners has approved over $90 million in ethanol and biofuel related capital expenditure projects, including modifications to tanks, truck racks and related infrastructure for new or expanded ethanol and biodiesel service at various owned, operated and/or third party terminal facilities located in the Southeast and the Pacific Northwest. Kinder Morgan Energy Partners plans on offering ethanol blending capabilities in twelve of fifteen markets served by its Southeast terminals by the end of 2009.
 
 
·
In October 2008, Plantation Pipe Line Company successfully shipped a 20,000 barrel batch of blended biodiesel (a 5% blend commonly referred to as B5). The shipment originated at Collins, Mississippi and was delivered to a customer terminal located in Spartanburg, South Carolina. Plantation is currently developing plans to expand its capability to deliver biodiesel to at least ten markets served by its pipeline system in the Southeast. Assuming sufficient commercial support, Plantation Pipe Line Company expects to be moving forward with investments to provide this service during the second quarter of 2009.
 
 
·
In November 2008, Kinder Morgan Energy Partners’ West Coast Products Pipelines completed an approximate $25 million expansion project that included the construction of four 80,000 barrel tanks and ancillary facilities that provide military jet fuel and marine diesel fuel service to the U.S. Marine Corps Naval Air Station in Miramar, California and the Naval Air Station in Point Loma, California.
 
 
·
On December 10, 2008, Kinder Morgan Energy Partners’ West Coast Products Pipelines operations purchased a 200,000 barrel refined petroleum products terminal located in Phoenix, Arizona from ConocoPhillips for approximately $27.5 million in cash.
 
Natural Gas Pipelines–KMP
 
 
·
Effective April 1, 2008, Kinder Morgan Energy Partners sold its 25% equity ownership interest in Thunder Creek Gas Services, LLC to PVR Midstream LLC, a subsidiary of Penn Virginia Corporation, for approximately $50.7 million in cash.
 
 
·
On May 20, 2008, transportation service on the final 210 miles of the Rockies Express-West pipeline segment commenced. Interim service for up to 1.4 billion cubic feet per day of natural gas on the segment’s first 503 miles of pipe began on January 12, 2008. The Rockies Express-West pipeline segment is the second phase of the Rockies Express Pipeline and consists of a 713-mile, 42-inch diameter pipeline that extends from the Cheyenne Hub in Weld County, Colorado to an interconnect with Panhandle Eastern Pipeline Company in Audrain County, Missouri. Now fully operational, Rockies Express-West has the capacity to transport up to 1.5 billion cubic feet of natural gas per day and can make deliveries to interconnects with Kinder Morgan Interstate Gas Transmission Pipeline LLC,
 

 
5
 
Items 1. and 2.   Business and Properties. (continued)
Knight Form 10-K


 
 
Northern Natural Gas Company, Natural Gas Pipeline Company of America LLC, ANR Pipeline Company and Panhandle Eastern Pipeline Company.
 
 
·
On May 30, 2008, the Federal Energy Regulatory Commission (“FERC”) issued an order authorizing construction of the Rockies Express-East pipeline segment, the third phase of the Rockies Express Pipeline. Rockies Express-East is a 639-mile, 42-inch diameter pipeline that will extend from Audrain County, Missouri to Clarington, Ohio. When fully completed, the 1,679-mile Rockies Express Pipeline will have the capability to transport 1.8 billion cubic feet per day of natural gas and binding firm commitments from creditworthy shippers have been secured for all of the pipeline capacity. Kinder Morgan Energy Partners is a 51% owner in the Rockies Express Pipeline, which is estimated to cost approximately $6.3 billion including expansion when completed (consistent with Kinder Morgan Energy Partners’ January 21, 2009 fourth quarter earnings release).
 
Construction of the Rockies Express-East pipeline segment is in progress and subject to the receipt of regulatory approvals, initial service on the pipeline is projected to commence April 1, 2009. The initial service will provide for capacity of up to 1.6 billion cubic feet per day to interconnects upstream of Lebanon, Ohio, followed by service to the Lebanon Hub in Warren County, Ohio beginning June 15, 2009. Final pipeline completions and fully powered deliveries to Clarington, Ohio are expected to commence by November 1, 2009.
 
 
·
Rockies Express Pipeline LLC is requesting authorization to construct and operate certain facilities that upon completion will comprise its Meeker, Colorado to Cheyenne, Wyoming expansion project. The proposed expansion will consist of additional natural gas compression at its Big Hole compressor station located in Moffat County, Colorado and its Arlington compressor station located in Carbon County, Wyoming. Upon completion, the additional compression will permit the transportation of an additional 200 million cubic feet per day of natural gas from (i) the Meeker Hub located in Rio Blanco County, Colorado northward to the Wamsutter Hub located in Sweetwater County, Wyoming; and (ii) from the Wamsutter Hub eastward to the Cheyenne Hub located in Weld County, Colorado. The expansion is fully supported by long-term contracts and is expected to be operational in April 2010. The total estimated cost for the proposed project is approximately $78 million. Rockies Express Pipeline LLC submitted an application to the FERC seeking approval to construct and operate this expansion on February 3, 2009.
 
 
·
In June 2008, Kinder Morgan Energy Partners’ Texas intrastate group began gas injections into a fifth cavern at its salt dome storage facility located near Markham, Texas as part of an $84 million expansion. After final developments were completed in January 2009, the project added 7.5 billion cubic feet of natural gas working storage capacity, and gas injection capacity will increase by approximately 110 million cubic feet per day upon completion of compression installation in spring 2009. In addition, the Texas intrastate pipeline group’s approximately $13 million Texas Hill Country natural gas compression project was completed in January 2009, resulting in 45 million cubic feet of incremental pipeline capacity out of West Texas, primarily serving the Austin, Texas market.
 
 
·
On July 25, 2008, the FERC approved the application made by Midcontinent Express Pipeline LLC to construct and operate the approximately 500-mile Midcontinent Express Pipeline natural gas transmission system and to lease 272 million cubic feet of capacity on the Oklahoma intrastate system of Enogex Inc. Kinder Morgan Energy Partners and Energy Transfer Partners, L.P. each own a 50% interest in Midcontinent Express Pipeline LLC, the sole owner of the Midcontinent Express Pipeline.
 
The project is expected to cost approximately $2.2 billion, including previously announced expansions. This is an increase from the $1.9 billion previous forecast. Much of the increase is attributable to increased construction cost. Midcontinent Express Pipeline LLC is currently finalizing negotiations with contractors for construction of the final segment. Those contracts will fix the per unit prices, providing greater cost certainty on that portion of the project and those construction costs are incorporated into the current forecast.
 
Interim service on the first portion of the pipeline from Bryan County, Oklahoma to an interconnection with Columbia Gulf Transmission Corporation near Perryville, Louisiana is expected commence in April 2009. The second construction phase, to the Transco Pipeline near Butler, Alabama, is expected to be completed by August 1, 2009. The Midcontinent Express Pipeline’s capacity is fully subscribed with long-term binding commitments from creditworthy shippers.
 
 
·
Construction continues on the fully-owned Kinder Morgan Louisiana Pipeline and the current cost estimate for this natural gas transmission system is approximately $950 million. The project is supported by fully subscribed capacity and long-term customer commitments with Chevron and Total and it is anticipated that the pipeline will become fully operational during the second quarter of 2009.
 

 
6
 
Items 1. and 2.   Business and Properties. (continued)
Knight Form 10-K


 
·
In September 2008, Kinder Morgan Energy Partners completed construction of an approximately $75 million natural gas pipeline that transports additional East Texas natural gas supplies to markets in the Houston and Beaumont, Texas areas. The new pipeline connects the Kinder Morgan Tejas system in Houston County, Texas to the Kinder Morgan Texas Pipeline system in Polk County near Goodrich, Texas. Kinder Morgan Energy Partners entered into a long-term binding agreement with CenterPoint Energy Services, Inc. to provide firm transportation for a significant portion of the initial project capacity, which consists of approximately 225 million cubic feet per day of natural gas.
 
 
·
On October 1, 2008, Kinder Morgan Energy Partners and Energy Transfer Partners, L.P. announced a joint venture to build and develop the Fayetteville Express Pipeline, a new $1.2 billion natural gas pipeline that will provide shippers in the Arkansas Fayetteville Shale area with takeaway natural gas capacity and further access to growing markets. The project is expected to be in service in 2010 or early 2011 and has secured binding 10-year commitments totaling 1.85 billion cubic feet per day.
 
 
·
In October 2008, Kinder Morgan Energy Partners completed construction of an approximately $22 million expansion project on the Kinder Morgan Interstate Gas Transmission LLC pipeline system that provides for the delivery of natural gas to five separate industrial plants (four of which produce ethanol) located near Grand Island, Nebraska. The project is fully subscribed with long-term customer contracts.
 
 
·
On November 24, 2008, Kinder Morgan Interstate Gas Transmission LLC completed construction and placed into service its previously announced Colorado Lateral Pipeline. The approximately $39 million expansion project extends from the Cheyenne Hub to interconnects with Atmos Energy’s pipeline near Greeley, Colorado. The pipeline provides firm natural gas transportation of up to 74 million cubic feet per day to local distribution companies and to industrial end users.
 
CO2–KMP
 
 
·
As of February 1, 2009, the CO2–KMP business segment was nearing completion of its previously announced southwest Colorado carbon dioxide expansion project. Combined, the expansion will cost its owners approximately $290 million and includes developing a new carbon dioxide source field (named the Doe Canyon Deep Unit), drilling new wells and expanding infrastructure at both the McElmo Dome Unit and the Cortez pipeline. The entire expansion increases carbon dioxide supplies by approximately 300 million cubic feet per day to its customers.
 
The Doe Canyon source field began operations in January 2008 and is currently delivering 120 million cubic feet per day of carbon dioxide. The first compression train of the Goodman Point expansion at the McElmo Dome source field was placed in service in June 2008 at a rate of 108 million cubic feet per day of carbon dioxide. The second compression train was brought on in October 2008 (after the activation of the Blanco pump station on the Cortez Pipeline) and increased the production rate to 207 million cubic feet per day of carbon dioxide. In 2009, the Goodman Point plant has averaged 232 million cubic feet per day of carbon dioxide. In October of 2008, Kinder Morgan Energy Partners activated the Blanco pump station on the Cortez Pipeline utilizing power from diesel generators and in January 2009, it began construction on a new power line that will connect the Blanco pumps to the power grid. The new power line is expected to be in service by the end of the third quarter of 2009. Kinder Morgan Energy Partners owns a 50% interest in the Cortez pipeline, which currently delivers approximately 1.3 billion cubic feet per day of carbon dioxide.
 
Terminals–KMP
 
 
·
On January 16, 2008, Kinder Morgan Energy Partners announced plans to invest approximately $56 million to construct a petroleum coke terminal at the BP refinery located in Whiting, Indiana. Kinder Morgan Energy Partners has entered into a long-term contract to build and operate the facility, which will handle approximately 2.2 million tons of petroleum coke per year from a coker unit BP plans to construct to process heavy crude oil from Canada. The facility is expected to be in service in mid-year 2011.
 
 
·
On March 20, 2008, Kinder Morgan Energy Partners announced the completion of several expansion projects representing total investment of more than $500 million at various bulk and liquids terminal facilities. The primary investment projects included (i) an approximately $195 million expansion for additional tankage at the combined Galena Park/Pasadena, Texas liquids terminal facilities located on the Houston, Texas Ship Channel; (ii) an approximately $170 million investment to construct the Kinder Morgan North 40 terminal, a crude oil tank farm situated on approximately 24 acres near Edmonton, Alberta, Canada; (iii) an approximately $70 million capital improvement project at the Pier IX bulk terminal located in Newport News, Virginia; and (iv) an approximately $68 million for the construction of nine new liquid storage tanks at the Perth Amboy, New Jersey liquids terminal located on the New York Harbor.
 

 
7
 
Items 1. and 2.   Business and Properties. (continued)
Knight Form 10-K


 
 
The storage expansion at the Galena Park/Pasadena terminals brings total capacity of the combined complex to approximately 25 million barrels. As previously announced, the building of the Kinder Morgan North 40 terminal included the construction of nine storage tanks with a combined capacity of approximately 2.15 million barrels for crude oil, all of which is subscribed by shippers under long-term contracts. The Pier IX project involved the construction of a new ship dock and the installation of a new import coal facility that is expected to increase terminal throughput by 30% to about nine million tons a year. The expansion at Perth Amboy included the building of nine new liquid storage tanks, which increased capacity for refined petroleum products and chemicals by 1.4 million barrels, bringing total terminal capacity to approximately 3.7 million barrels.
 
 
·
Effective August 5, 2008, Kinder Morgan Energy Partners acquired certain terminal assets from Chemserv, Inc. for an aggregate consideration of approximately $12.7 million, consisting of $11.8 million in cash and $0.9 million in assumed liabilities. The acquired assets are primarily involved in the storage of petroleum products and chemicals.
 
 
·
In December 2008, Kinder Morgan Energy Partners began operations at its approximately $47 million terminal, which offers liquids, storage, transfer and packaging facilities at the Rubicon Plant site located in Geismar, Louisiana. The newly constructed terminal has liquids storage capacity of approximately 123,500 barrels and has approximately 144,000 square feet of warehouse space.
 
 
·
Construction continues on an approximately $13 million expansion at Kinder Morgan Energy Partners’ Cora coal terminal, located in Rockwood, Illinois along the upper Mississippi River. The project will increase terminal storage capacity by approximately 250,000 tons (to 1.25 million tons) and will expand maximum throughput at the terminal to approximately 13 million tons annually. It is expected that the Cora expansion project will be completed in the second quarter of 2009.
 
Kinder Morgan Canada–KMP
 
 
·
Effective August 28, 2008, we sold our one-third equity ownership interest in the Express crude oil pipeline system, as well as full ownership of the Jet Fuel pipeline system that serves the Vancouver (Canada) International Airport to Kinder Morgan Energy Partners. As consideration for these assets, Kinder Morgan Energy Partners issued approximately two million of its common units to us, valued at $116.0 million. For additional information regarding this transaction, see Note 10 of the accompanying Notes to Consolidated Financial Statements.
 
 
·
On October 30, 2008, Kinder Morgan Energy Partners completed the construction and commissioning of its approximately $544 million Anchor Loop project, the second and final phase of a Trans Mountain pipeline system expansion that in total, increased pipeline capacity from approximately 225,000 to 300,000 barrels of crude oil per day.
 
The Anchor Loop project involved twinning (or looping) a 158-kilometer section of the existing pipeline system between Hinton, Alberta and Hargreaves, British Columbia and was completed in two phases, (i) 97 kilometers of 30-inch and 36-inch diameter pipeline and two new pump stations that increased the capacity of the pipeline system by 25,000 barrels per day (the Jasper spread completed on April 28, 2008) and (ii) 61 kilometers of 36-inch diameter pipeline that increased the capacity of the pipeline system by an incremental 15,000 barrels per day (the Mount Robson spread in British Columbia completed on October 30, 2008). The pipeline system is currently operating at full capacity and only final right-of-way restoration on the Mount Robson spread remains to be completed in the summer of 2009.
 
Debt and Equity Offerings, Swap Agreements, Cash Distributions and Debt Retirements
 
 
·
On February 12, 2008, Kinder Morgan Energy Partners completed a public offering of senior notes. A total of $900 million in principal amount of senior notes was issued, consisting of $600 million of 5.95% notes due February 15, 2018 and $300 million of 6.95% notes due January 15, 2038. Kinder Morgan Energy Partners used the net proceeds of $894.1 million to reduce the borrowings under its commercial paper program.
 
 
·
Also on this date, Kinder Morgan Energy Partners completed an offering of 1,080,000 of its common units at a price of $55.65 per unit in a privately negotiated transaction and used the net proceeds of $60.1 million to reduce the borrowings under its commercial paper program.
 
 
·
In March 2008, Kinder Morgan Energy Partners completed a public offering of 5,750,000 of its common units at a price of $57.70 per unit and used the net proceeds of $324.2 million to reduce the borrowings under its commercial paper program.
 
 
·
On June 6, 2008, Kinder Morgan Energy Partners completed a $700 million public offering of senior notes and used the net proceeds of $687.7 million to reduce the borrowings under its commercial paper program.
 

 
8
 
Items 1. and 2.   Business and Properties. (continued)
Knight Form 10-K


 
·
On November 24, 2008, Kinder Morgan Energy Partners announced that it expected to declare cash distributions of $4.20 per unit for 2009, a 4.5% increase over its cash distributions of $4.02 per unit for 2008. Kinder Morgan Energy Partners’ expected growth in distributions in 2009 assumes an average West Texas Intermediate (“WTI”) crude oil price of $68 per barrel in 2009 with some minor adjustments for timing, quality and location differences. Based on actual prices received through the first seven weeks of 2009 and the forward curve, adjusted for the same factors as the budget, our average realized price for 2009 is currently projected to be $49 per barrel. Although the majority of the cash generated by Kinder Morgan Energy Partners’ assets is fee based and is not sensitive to commodity prices, the CO2–KMP business segment is exposed to commodity price risk related to the price volatility of crude oil and natural gas liquids. Kinder Morgan Energy Partners hedges the majority of its crude oil production, but does have exposure to unhedged volumes, the majority of which are natural gas liquids volumes. For 2009, Kinder Morgan Energy Partners expects that every $1 change in the average WTI crude oil price per barrel will impact the CO2–KMP segment’s cash flows by approximately $6 million (or approximately 0.2% of Kinder Morgan Energy Partners’ combined business segments’ anticipated distributable cash flow). This sensitivity to the average WTI crude oil price is very similar to what was experienced in 2008. The 2009 Kinder Morgan Energy Partners cash distribution expectations do not take into account any capital costs associated with financing any payment Kinder Morgan Energy Partners may make of reparations sought by shippers on its West Coast Products Pipelines operations’ interstate pipelines.
 
 
·
On December 19, 2008, Kinder Morgan Energy Partners closed a public offering of $500 million in principal amount of senior notes and used the net proceeds of $498.4 million to reduce the borrowings under its five-year unsecured revolving bank credit facility.
 
 
·
On December 22, 2008, Kinder Morgan Energy Partners completed a public offering of 3,900,000 of its common units at a price of $46.75 per unit, less commissions and underwriting expenses and used the net proceeds of $176.6 million to reduce the borrowings under its five-year unsecured revolving bank credit facility.
 
 
·
In December 2008 and January 2009, Kinder Morgan Energy Partners terminated three existing fixed-to-variable interest rate swap agreements in three separate transactions. These swap agreements had a combined notional principal amount of $1.0 billion and Kinder Morgan Energy Partners received combined proceeds of $338.7 million from the early termination of these swap agreements.
 
 
·
On February 2, 2009, Kinder Morgan Energy Partners paid $250 million to retire the principal amount of its 6.3% senior notes that matured on that date.
 
 
·
In February and March 2009, Kinder Morgan Energy Partners sold 5,666,000 of its common units in a public offering at a price of $46.95 per unit. Kinder Morgan Energy Partners received net proceeds, after commissions and underwriting expenses, of approximately $260 million for the issuance of these 5,666,000 common units and used the proceeds to reduce the borrowings under its bank credit facility.·On February 25, 2009, Kinder Morgan Energy Partners entered into four additional fixed-to-floating interest rate swap agreements having a combined notional principal amount of $1.0 billion related to (i) $200 million 6% senior notes due 2017, (ii) $300 million of 5.125% senior notes due 2014, (iii) $25 million 5% senior notes due 2013 and (iv) $475 million of 5.95% senior notes due 2018.
 
Capital Expansion Projects
 
Kinder Morgan Energy Partners’ capital expansion program in 2008 was approximately $2.9 billion (for both maintenance/sustaining and expansion/discretionary capital spending, and including its equity contributions to the Rockies Express Pipeline, the Midcontinent Express Pipeline and the Fayetteville Express Pipeline natural gas pipeline projects). In 2009, Kinder Morgan Energy Partners expects its capital expansion program to be approximately $2.8 billion (including its equity contributions to the Rockies Express Pipeline and Midcontinent Express Pipeline projects), which will help contribute to earnings and cash flow growth in 2009 and beyond.
 
(B) Financial Information About Segments
 
Note 19 of the accompanying Notes to Consolidated Financial Statements contains financial information about our business segments.
 

 
9
 
Items 1. and 2.   Business and Properties. (continued)
Knight Form 10-K


(C) Narrative Description of Business
 
 
The objective of our business strategy is to grow our portfolio of businesses by:
 
 
·
focusing on stable, fee-based energy transportation and storage assets that are core to the energy infrastructure of growing markets within North America;
 
·
increasing utilization of our existing assets while controlling costs, operating safely and employing environmentally sound operating practices;
 
·
leveraging economies of scale from incremental acquisitions and expansions of assets that fit within our strategy and are accretive to cash flow and earnings; and
 
·
maximizing the benefits of our financial structure to create and return value to our stockholders.
 
We (primarily through Kinder Morgan Energy Partners) regularly consider and enter into discussions regarding potential acquisitions and are currently contemplating potential acquisitions. Any such transaction would be subject to negotiation of mutually agreeable terms and conditions, receipt of fairness opinions and approval of the respective boards of directors, if required. While there are currently no unannounced purchase agreements for the acquisition of any material business or assets, such transactions can be effected quickly, may occur at any time and may be significant in size relative to our existing assets or operations.
 
It is our intention to carry out the above business strategy, modified as necessary to reflect changing economic conditions and other circumstances. However, as discussed under “Risk Factors” elsewhere in this report, there are factors that could affect our ability to carry out our strategy or affect its level of success even if carried out.
 
 
Our operations are conducted through our subsidiaries and are grouped into seven business segments, the last five of which are also business segments of Kinder Morgan Energy Partners:
 
 
·
Natural Gas Pipeline Company of America—which consists of our 20% interest in NGPL PipeCo LLC, the owner of Natural Gas Pipeline Company of America LLC and certain affiliates, collectively referred to as Natural Gas Pipeline Company of America or NGPL, a major interstate natural gas pipeline and storage system which we operate;
 
·
Power—which consists of two natural gas-fired electric generation facilities;
 
·
Products Pipelines–KMP—which consists of approximately 8,300 miles of refined petroleum products pipelines that deliver gasoline, diesel fuel, jet fuel and natural gas liquids to various markets; plus approximately 60 associated product terminals and petroleum pipeline transmix processing facilities serving customers across the United States;
 
·
Natural Gas Pipelines–KMP—which consists of over 14,300 miles of natural gas transmission pipelines and gathering lines, plus natural gas storage, treating and processing facilities, through which natural gas is gathered, transported, stored, treated, processed and sold;
 
·
CO2–KMP—which produces, markets and transports, through approximately 1,300 miles of pipelines, carbon dioxide to oil fields that use carbon dioxide to increase production of oil; owns interests in and/or operates ten oil fields in West Texas; and owns and operates a 450-mile crude oil pipeline system in West Texas;
 
·
Terminals–KMP—which consists of approximately 110 owned or operated liquids and bulk terminal facilities and more than 45 rail transloading and materials handling facilities located throughout the United States and portions of Canada, which together transload, store and deliver a wide variety of bulk, petroleum, petrochemical and other liquids products for customers across the United States and Canada; and
 
·
Kinder Morgan Canada–KMP—which consists of over 700 miles of common carrier pipelines, originating at Edmonton, Alberta, for the transportation of crude oil and refined petroleum to the interior of British Columbia and to marketing terminals and refineries located in the greater Vancouver, British Columbia area and Puget Sound in Washington State; plus five associated product terminals. This segment also includes a one-third interest in an approximately 1,700-mile integrated crude oil pipeline and a 25-mile aviation turbine fuel pipeline serving the Vancouver International Airport.
 
Generally, as utilization of our pipelines and terminals increases, our fee-based revenues increase. We do not face significant risks relating directly to short-term movements in commodity prices for two principal reasons. First, we primarily transport and/or handle products for a fee and are not engaged in significant unmatched purchases and resales of commodity products. Second, in those areas of our business where we do face exposure to fluctuations in commodity prices, primarily oil production in the CO2–KMP business segment, we engage in a hedging program to mitigate this exposure.
 

 
10
 
Items 1. and 2.   Business and Properties. (continued)
Knight Form 10-K


 
In February 2008, we completed the sale of an 80% ownership interest in NGPL for approximately $5.9 billion. We account for our 20% ownership interest as an equity method investment. We continue to operate NGPL’s assets pursuant to a 15-year operating agreement. NGPL owns and operates approximately 9,700 miles of interstate natural gas pipelines, storage fields, field system lines and related facilities, consisting primarily of two major interconnected natural gas transmission pipelines terminating in the Chicago, Illinois metropolitan area. NGPL’s Amarillo Line originates in the West Texas and New Mexico producing areas and is comprised of approximately 4,400 miles of mainline and various small-diameter pipelines. Its other major pipeline, the Gulf Coast Line, originates in the Gulf Coast areas of Texas and Louisiana and consists of approximately 4,100 miles of mainline and various small-diameter pipelines. These two main pipelines are connected at points in Texas and Oklahoma by NGPL’s approximately 800-mile Amarillo/Gulf Coast pipeline. NGPL’s system has 813 points of interconnection with 34 interstate pipelines, 34 intrastate pipelines, 38 local distribution companies, 32 end users including power plants and a number of gas producers, thereby providing significant flexibility in the receipt and delivery of natural gas.
 
NGPL is one of the nation’s largest natural gas storage operators with approximately 600 billion cubic feet of total natural gas storage capacity, approximately 258 billion cubic feet of working gas capacity and over 4.3 billion cubic feet per day of peak deliverability from its storage facilities, which are located in major supply areas and near the markets it serves. NGPL owns and operates 13 underground storage reservoirs in eight field locations in four states. These storage assets complement its pipeline facilities and allow it to optimize pipeline deliveries and meet peak delivery requirements in its principal markets.
 
Competition.  NGPL competes with other transporters of natural gas in virtually all of the markets it serves and, in particular, in the Chicago area, which is the northern terminus of NGPL’s two major pipeline segments and its largest market. These competitors include both interstate and intrastate natural gas pipelines that transport United States produced natural gas along with the Alliance Pipeline, which transports Canada-produced natural gas, into the Chicago area. The Vector Pipeline provides the ability to transport Chicago area natural gas supplies to additional markets that are farther north and farther east. The overall impact of the considerable pipeline capacity into the Chicago area, combined with additional take-away capacity and the increased demand in the area, has created a situation that remains dynamic with respect to the ultimate impact on individual transporters such as NGPL. From time to time, other pipelines are proposed that would compete with NGPL. We cannot predict whether or when any such pipeline might be built, or its impact on NGPL’s operations or profitability.
 
 
In January 2008, we sold our interests in three natural gas-fired power plants in Colorado. Our remaining Power operations consist of (i) an ownership interest in and operations of a 550-megawatt natural gas-fired electricity generation facility in Michigan and (ii) operating and maintaining a 103-megawatt natural gas-fired power plant in Snyder, Texas. During 2008, approximately 76% of Power’s operating revenues represented tolling revenues of the Michigan facility, the remaining 24% was primarily for operating the Snyder, Texas power facility, which provides electricity to Kinder Morgan Energy Partners’ SACROC operations within the CO2–KMP segment.
 
The principal impact of competition at the Michigan facility is the level of dispatch of the plant and the related, but minor, effect on profitability.
 
 
The Products Pipelines–KMP segment consists of Kinder Morgan Energy Partners’ refined petroleum products and natural gas liquids pipelines and associated terminals, Southeast terminals and transmix processing facilities.
 
West Coast Products Pipelines
 
The West Coast Products Pipelines include the Pacific operations (including SFPP, L.P.), CALNEV Pipe Line LLC (“Calnev”) and the West Coast Terminals operations. The assets include interstate common carrier pipelines regulated by the FERC, intrastate pipelines in the state of California regulated by the California Public Utilities Commission and certain non rate-regulated operations and terminal facilities.
 
SFPP, L.P. serves six western states with approximately 3,100 miles of refined petroleum products pipelines and related terminal facilities that provide refined products to major population centers in the United States, including California; Las Vegas and Reno, Nevada; and the Phoenix-Tucson, Arizona corridor. For 2008, the three main product types transported were gasoline (59%), diesel fuel (23%) and jet fuel (18%).
 
Calnev consists of two parallel 248-mile, 14-inch and 8-inch diameter pipelines that run from Kinder Morgan Energy Partners’ facilities at Colton, California to Las Vegas, Nevada. The pipeline serves the Mojave Desert through deliveries to a terminal at Barstow, California and two nearby major railroad yards. It also serves Nellis Air Force Base, located in Las
 

 
11
 
Items 1. and 2.   Business and Properties. (continued)
Knight Form 10-K


Vegas and also includes approximately 55 miles of pipeline serving Edwards Air Force Base.
 
The West Coast Products Pipelines include 15 truck-loading terminals (13 on SFPP, L.P. and two on Calnev) with an aggregate usable tankage capacity of approximately 14.9 million barrels. The truck terminals provide services including short-term product storage, truck loading, vapor handling, additive injection, dye injection and ethanol blending.
 
The West Coast Terminals are fee-based terminals located in the Seattle, Portland, San Francisco and Los Angeles areas along the west coast of the United States with a combined total capacity of approximately 8.4 million barrels of storage for both petroleum products and chemicals.
 
Markets.  Combined, the West Coast Products Pipelines’ pipelines transport approximately 1.3 million barrels per day of refined petroleum products, providing pipeline service to approximately 31 customer-owned terminals, 11 commercial airports and 15 military bases. Currently, the West Coast Products Pipelines serve approximately 100 shippers in the refined petroleum products market; the largest customers being major petroleum companies, independent refiners, and the United States military.
 
A substantial portion of the product volume transported is gasoline. Demand for gasoline depends on such factors as prevailing economic conditions, vehicular use and purchase patterns and demographic changes in the markets served. Certain product volumes can experience seasonal variations and, consequently, overall volumes may be lower during the first and fourth quarters of each year.
 
Supply.  The majority of refined products supplied to the West Coast Products Pipelines come from the major refining centers around Los Angeles, San Francisco, El Paso and Puget Sound, as well as from waterborne terminals and connecting pipelines located near these refining centers.
 
Competition.  The two most significant competitors of the West Coast Products Pipelines’ are proprietary pipelines owned and operated by major oil companies in the area where it delivers products and also refineries with terminals that have trucking arrangements within the West Coast Products Pipelines’ areas. We believe that high capital costs, tariff regulation and environmental and right-of-way permitting considerations make it unlikely that a competing pipeline system comparable in size and scope to the pipeline systems owned and operated by the West Coast Products Pipelines will be built in the foreseeable future. However, the possibility of individual pipelines (such as the Holly pipeline to Las Vegas, Nevada) being constructed or expanded to serve specific markets is a continuing competitive factor.
 
The use of trucks for product distribution from either shipper-owned proprietary terminals or from their refining centers continues to compete for short haul movements by pipeline. The West Coast Terminals compete with terminals owned by its shippers and by third-party terminal operators in California, Arizona and Nevada. Competitors include Shell Oil Products U.S., BP (formerly Arco Terminal Services Company), Wilmington Liquid Bulk Terminals (Vopak), NuStar and Chevron. We cannot predict with any certainty whether the use of short haul trucking will decrease or increase in the future.
 
Plantation Pipe Line Company
 
Kinder Morgan Energy Partners owns approximately 51% of Plantation Pipe Line Company (“Plantation”), a 3,100-mile refined petroleum products pipeline system serving the southeastern United States. An affiliate of ExxonMobil Corporation owns the remaining 49% ownership interest. ExxonMobil is the largest shipper on the Plantation system both in terms of volumes and revenues. Kinder Morgan Energy Partners operates the system pursuant to agreements with Plantation Services LLC and Plantation. Plantation serves as a common carrier of refined petroleum products to various metropolitan areas, including Birmingham, Alabama; Atlanta, Georgia; Charlotte, North Carolina; and the Washington, D.C. area.
 
For the year 2008, Plantation delivered an average of 480,341 barrels per day of refined petroleum products. These delivered volumes were comprised of gasoline (61%), diesel/heating oil (25%) and jet fuel (14%). Average delivery volumes for 2008 were 10.3% lower than the 535,672 barrels per day delivered during 2007 and 13.5% lower than 555,063 barrels per day delivered during 2006. The decrease was predominantly driven by (i) changes in production patterns from Louisiana refineries related to refiners directing higher margin products (such as reformulated gasoline blendstock for oxygenate blending) into markets not directly served by Plantation, (ii) a rapid increase in ethanol blending in the Southeast resulting in lower pipeline-delivered gasoline volumes and (iii) lower regional demand as a result of high product prices during the first six months of the year and a slowing economy.
 
Markets.  Plantation ships products for approximately 30 companies to terminals throughout the southeastern United States. Plantation’s principal customers are Gulf Coast refining and marketing companies, fuel wholesalers, and the United States Department of Defense. Plantation’s top five shippers represent approximately 80% of total system volumes.
 

 
12
 
Items 1. and 2.   Business and Properties. (continued)
Knight Form 10-K


The eight states in which Plantation operates represent a collective pipeline demand of approximately two million barrels per day of refined petroleum products. Plantation currently has direct access to about 1.5 million barrels per day of this overall market. The remaining 0.5 million barrels per day of demand lies in markets (e.g., Nashville, Tennessee; North Augusta, South Carolina; Bainbridge, Georgia; and Selma, North Carolina) currently served by another pipeline company. Plantation also delivers jet fuel to the Atlanta, Georgia; Charlotte, North Carolina; and Washington, D.C. airports (Ronald Reagan National and Dulles). Combined jet fuel shipments to these four major airports decreased 12% in 2008 compared to 2007, with the majority of this decline occurring at Dulles Airport.
 
Supply.  Products shipped on Plantation originate at various Gulf Coast refineries from which major integrated oil companies and independent refineries and wholesalers ship refined petroleum products. Plantation is directly connected to and supplied by a total of ten major refineries representing approximately 2.3 million barrels per day of refining capacity.
 
Competition.  Plantation competes primarily with the Colonial pipeline system, which also runs from Gulf Coast refineries throughout the southeastern United States and extends into the northeastern states.
 
Central Florida Pipeline
 
The Central Florida pipeline system consists of a 110-mile, 16-inch diameter pipeline that transports gasoline and ethanol (beginning in November 2008) and an 85-mile, 10-inch diameter pipeline that transports diesel fuel and jet fuel from Tampa to Orlando, with an intermediate delivery point on the 10-inch pipeline at Intercession City, Florida. In addition to being connected to Kinder Morgan Energy Partners’ Tampa terminal, the pipeline system is connected to terminals owned and operated by TransMontaigne, Citgo, BP and Marathon Petroleum. The 10-inch diameter pipeline is connected to Kinder Morgan Energy Partners’ Taft, Florida terminal (located near Orlando) and is also the sole pipeline supplying jet fuel to the Orlando International Airport in Orlando, Florida. In 2008, the pipeline system transported approximately 106,700 barrels per day of refined products, with the product mix being approximately 68% gasoline, 12% diesel fuel and 20% jet fuel.
 
Kinder Morgan Energy Partners owns and operates liquids terminals in Tampa and Taft, Florida. The Tampa terminal contains approximately 1.5 million barrels of storage capacity and is connected to two ship dock facilities in the Port of Tampa. The Tampa terminal provides storage for gasoline, ethanol, diesel fuel and jet fuel for further movement into either trucks or into the Central Florida pipeline system. The Tampa terminal also provides storage and truck rack blending services for ethanol and bio-diesel. The Taft terminal contains approximately 0.7 million barrels of storage capacity, for gasoline, ethanol and diesel fuel, for further movement into trucks.
 
Markets.  The estimated total refined petroleum products demand in the state of Florida is approximately 800,000 barrels per day. Gasoline is, by far, the largest component of that demand at approximately 545,000 barrels per day. The total refined petroleum products demand for the Central Florida region of the state, which includes the Tampa and Orlando markets, is estimated to be approximately 360,000 barrels per day, or 45% of the consumption of refined products in the state. Kinder Morgan Energy Partners distributes approximately 150,000 barrels of refined petroleum products per day, including the Tampa terminal truck loadings. The balance of the market is supplied primarily by trucking firms and marine transportation firms. Most of the jet fuel used at Orlando International Airport is moved through Kinder Morgan Energy Partners’ Tampa terminal and the Central Florida pipeline system. The market in Central Florida is seasonal, with demand peaks in March and April during spring break and again in the summer vacation season and is also heavily influenced by tourism, with Disney World and other attractions located near Orlando.
 
Supply.  The vast majority of refined petroleum products consumed in Florida are supplied via marine vessels from major refining centers in the Gulf Coast of Louisiana and Mississippi and refineries in the Caribbean basin. A lesser amount of refined petroleum products is being supplied by refineries in Alabama and by Texas Gulf Coast refineries via marine vessels and through pipeline networks that extend to Bainbridge, Georgia. The supply into Florida is generally transported by ocean-going vessels to the larger metropolitan ports, such as Tampa, Port Everglades near Miami and Jacksonville. Individual markets are then supplied from terminals at these ports and other smaller ports, predominately by trucks, except the Central Florida region, which is served by a combination of trucks and pipelines.
 
Competition.  With respect to the Central Florida pipeline system, the most significant competitors are trucking firms and marine transportation firms. Trucking transportation is more competitive in serving markets close to the marine terminals on the east and west coasts of Florida. Kinder Morgan Energy Partners is utilizing tariff incentives to attract volumes to the pipeline that might otherwise enter the Orlando market area by truck from Tampa or by marine vessel into Cape Canaveral. We believe it is unlikely that a new pipeline system comparable in size and scope to the Central Florida Pipeline system will be constructed, due to the high cost of pipeline construction, tariff regulation and environmental and right-of-way permitting in Florida. However, the possibility of such a pipeline or a smaller capacity pipeline being built is a continuing competitive factor.
 

 
13
 
Items 1. and 2.   Business and Properties. (continued)
Knight Form 10-K


With respect to the terminal operations at Tampa, the most significant competitors are proprietary terminals owned and operated by major oil companies, such as Marathon Petroleum, BP and Citgo, located along the Port of Tampa and the Chevron and Motiva terminals in Port Tampa. These terminals generally support the storage requirements of their parent or affiliated companies’ refining and marketing operations and provide a mechanism for an oil company to enter into exchange contracts with third parties to serve its storage needs in markets where the oil company may not have terminal assets.
 
Federal regulation of marine vessels, including the requirement under the Jones Act that United States-flagged vessels contain double-hulls, is a significant factor influencing the availability of vessels that transport refined petroleum products. Marine vessel owners are phasing in the requirement based on the age of the vessel and some older vessels are being redeployed into use in other jurisdictions rather than being retrofitted with a double-hull for use in the United States.
 
Cochin Pipeline System
 
The Cochin pipeline system consists of an approximate 1,900-mile, 12-inch diameter multi-product pipeline operating between Fort Saskatchewan, Alberta and Windsor, Ontario, including five terminals.
 
The pipeline operates on a batched basis and has an estimated system capacity of approximately 70,000 barrels per day. It includes 31 pump stations spaced at 60-mile intervals and five United States propane terminals. Underground storage is available at Fort Saskatchewan, Alberta and Windsor, Ontario through third parties. In 2008, the pipeline system transported approximately 30,800 barrels per day of natural gas liquids.
 
Markets.  The pipeline traverses three provinces in Canada and seven states in the United States and can transport propane, butane and natural gas liquids to the Midwestern United States and eastern Canadian petrochemical and fuel markets. Current operations involve only the transportation of propane on Cochin.
 
Supply. Injection into the system can occur from BP, Provident, Keyera or Dow facilities, with connections at Fort Saskatchewan, Alberta and from Spectra at interconnects at Regina and Richardson, Saskatchewan.
 
Competition.  The pipeline competes with railcars and Enbridge Energy Partners for natural gas liquids long-haul business from Fort Saskatchewan, Alberta and Windsor, Ontario. The pipeline’s primary competition in the Chicago natural gas liquids market comes from the combination of the Alliance pipeline system, which brings unprocessed gas into the United States from Canada and from Aux Sable, which processes and markets the natural gas liquids in the Chicago market.
 
Cypress Pipeline
 
Kinder Morgan Energy Partners’ Cypress pipeline is an interstate common carrier natural gas liquids pipeline originating at storage facilities in Mont Belvieu, Texas and extending 104 miles east to a major petrochemical producer in the Lake Charles, Louisiana area. Mont Belvieu, located approximately 20 miles east of Houston, is the largest hub for natural gas liquids gathering, transportation, fractionation and storage in the United States. In 2008, the pipeline system transported approximately 43,900 barrels per day of refined petroleum products.
 
Markets.  The pipeline was built to service Westlake Petrochemicals Corporation in the Lake Charles, Louisiana area under a 20-year ship-or-pay agreement that expires in 2011. The contract requires a minimum volume of 30,000 barrels per day.
 
Supply.  The Cypress pipeline originates in Mont Belvieu where it is able to receive ethane and ethane/propane mix from local storage facilities. Mont Belvieu has facilities to fractionate natural gas liquids received from several pipelines into ethane and other components. Additionally, pipeline systems that transport natural gas liquids from major producing areas in Texas, New Mexico, Louisiana, Oklahoma and the Mid-Continent region supply ethane and ethane/propane mix to Mont Belvieu.
 
Competition.  The pipeline’s primary competition into the Lake Charles market comes from Louisiana onshore and offshore natural gas liquids.
 
Southeast Terminals
 
Kinder Morgan Energy Partners’ Southeast terminal operations consist of Kinder Morgan Southeast Terminals LLC and its consolidated affiliate, Guilford County Terminal Company, LLC. Kinder Morgan Southeast Terminals LLC, Kinder Morgan Energy Partners’ wholly owned subsidiary referred to in this report as KMST, was formed for the purpose of acquiring and operating high-quality liquid petroleum products terminals located primarily along the Plantation/Colonial pipeline corridor in the southeastern United States.
 
The Southeast terminal operations consist of 24 petroleum products terminals with a total storage capacity of approximately 8.0 million barrels. These terminals transferred approximately 351,000 barrels of refined products per day during 2008 and approximately 361,000 barrels of refined products per day during 2007.
 

 
14
 
Items 1. and 2.   Business and Properties. (continued)
Knight Form 10-K


Markets.  KMST’s acquisition and marketing activities are focused on the southeastern United States from Mississippi through Virginia, including Tennessee. The primary function involves the receipt of petroleum products from common carrier pipelines, short-term storage in terminal tankage and subsequent loading onto tank trucks. During 2008, KMST expanded its ethanol blending and storage services beyond northern Virginia into several conventional gasoline markets. The new ethanol blending facilities are located in Athens, Georgia, Doralville, Georgia, North Augusta, South Carolina, Charlotte, North Carolina, Greensboro, North Carolina and Selma, North Carolina. Longer term storage is available at many of the terminals. KMST has a physical presence in markets representing almost 80% of the pipeline-supplied demand in the Southeast and offers a competitive alternative to marketers seeking a relationship with a truly independent truck terminal service provider.
 
Supply.  Product supply is predominately from Plantation and Colonial pipelines, with a number of terminals connected to both pipelines. To the maximum extent practicable, we endeavor to connect KMST terminals to both Plantation and Colonial.
 
Competition.  There are relatively few independent terminal operators in the Southeast. Most of the refined petroleum products terminals in this region are owned by large oil companies (BP, Motiva, Citgo, Marathon and Chevron) who use these assets to support their own proprietary market demands as well as product exchange activity. These oil companies are not generally seeking third-party throughput customers. Magellan Midstream Partners and TransMontaigne Product Services represent the other significant independent terminal operators in this region.
 
Transmix Operations
 
Kinder Morgan Energy Partners’ Transmix operations include the processing of petroleum pipeline transmix, a blend of dissimilar refined petroleum products that have become co-mingled in the pipeline transportation process. During pipeline transportation, different products are transported through the pipelines abutting each other, and generate a volume of different mixed products called transmix. At transmix processing facilities, pipeline transmix is processed and separated into pipeline-quality gasoline and light distillate products. Kinder Morgan Energy Partners processes transmix at six separate processing facilities located in Colton, California; Richmond, Virginia; Dorsey Junction, Maryland; Indianola, Pennsylvania; Wood River, Illinois; and Greensboro, North Carolina. Combined, its transmix facilities processed approximately 10.4 million barrels of transmix in both 2008 and 2007.
 
Markets.  The Gulf and East Coast refined petroleum products distribution system, particularly the Mid-Atlantic region, is the target market for Kinder Morgan Energy Partners’ East Coast transmix processing operations. The Mid-Continent area and the New York Harbor are the target markets for Kinder Morgan Energy Partners’ Illinois and Pennsylvania assets, respectively. Kinder Morgan Energy Partners’ West Coast transmix processing operations support the markets served by its West Coast Products Pipelines in Southern California.
 
Supply.  Transmix generated by Plantation, Colonial, Explorer, Sun, Teppco and Kinder Morgan Energy Partners’ West Coast Products Pipelines provide the vast majority of the supply. These suppliers are committed to the use of Kinder Morgan Energy Partners’ transmix facilities under long-term contracts. Individual shippers and terminal operators provide additional supply. Shell acquires transmix for processing at Indianola, Richmond and Wood River; Colton is supplied by pipeline shippers of Kinder Morgan Energy Partners’ West Coast Products Pipelines; Dorsey Junction is supplied by Colonial Pipeline Company and Greensboro is supplied by Plantation.
 
Competition.  Placid Refining is Kinder Morgan Energy Partners’ main competitor for transmix business in the Gulf Coast area. There are various processors in the Mid-Continent area, primarily ConocoPhillips, Gladieux Refining and Williams Energy Services, who compete with Kinder Morgan Energy Partners’ transmix facilities. Motiva Enterprises’ transmix facility located near Linden, New Jersey is the principal competition for New York Harbor transmix supply and for the Indianola facility. A number of smaller organizations operate transmix processing facilities in the West and Southwest. These operations compete for supply that we envision as the basis for growth in the West and Southwest. The Colton processing facility also competes with major oil company refineries in California.
 
 
The Natural Gas Pipelines–KMP segment has both interstate and intrastate pipeline assets and performs natural gas sales, transportation, storage, gathering, processing and treating services. Within this segment, Kinder Morgan Energy Partners owns approximately 14,300 miles of natural gas pipelines and associated storage and supply lines that are strategically located at the center of the North American pipeline grid. The transportation network provides access to the major gas supply areas in the western United States, Texas and the Midwest, as well as major consumer markets.
 

 
15
 
Items 1. and 2.   Business and Properties. (continued)
Knight Form 10-K


Texas Intrastate Natural Gas Pipeline Group
 
The group, which operates primarily along the Texas Gulf Coast, consists of the following four natural gas pipeline systems:
 
 
·
Kinder Morgan Texas Pipeline;
 
·
Kinder Morgan Tejas Pipeline;
 
·
Mier-Monterrey Mexico Pipeline; and
 
·
Kinder Morgan North Texas Pipeline.
 
The two largest systems in the group are Kinder Morgan Texas Pipeline and Kinder Morgan Tejas Pipeline. These pipelines essentially operate as a single pipeline system, providing customers and suppliers with improved flexibility and reliability. The combined system includes approximately 6,000 miles of intrastate natural gas pipelines with a peak transport and sales capacity of approximately 5.2 billion cubic feet per day of natural gas and approximately 126 billion cubic feet of system natural gas storage capacity. In addition, the combined system, through owned assets and contractual arrangements with third parties, has the capability to process 685 million cubic feet per day of natural gas for liquids extraction and to treat approximately 180 million cubic feet per day of natural gas for carbon dioxide removal.
 
Collectively, the combined system primarily serves the Texas Gulf Coast by selling, transporting, processing and treating gas from multiple onshore and offshore supply sources to serve the Houston/Beaumont/Port Arthur/Austin industrial markets, local gas distribution utilities, electric utilities and merchant power generation markets. It serves as a buyer and seller of natural gas, as well as a transporter. The purchases and sales of natural gas are primarily priced with reference to market prices in the consuming region of its system. The difference between the purchase and sale prices is the rough equivalent of a transportation fee and fuel costs.
 
Included in the operations of the Kinder Morgan Tejas system is the Kinder Morgan Border Pipeline system. Kinder Morgan Border owns and operates an approximately 97-mile, 24-inch diameter pipeline that extends from a point of interconnection with the pipeline facilities of Pemex Gas Y Petroquimica Basica (“Pemex”) at the international border between the United States (Hidalgo, County, Texas) and Mexico, to a point of interconnection with other intrastate pipeline facilities of Kinder Morgan Tejas located at King Ranch, Kleburg County, Texas. The pipeline has a capacity of approximately 300 million cubic feet of natural gas per day and is capable of importing this volume of Mexican gas into the United States or exporting this volume of gas to Mexico.
 
The Mier-Monterrey Pipeline consists of a 95-mile natural gas pipeline between Starr County, Texas and Monterrey, Mexico and can transport up to 375 million cubic feet per day. The pipeline connects to a 1,000-megawatt power plant complex and to the Pemex natural gas transportation system. Kinder Morgan Energy Partners has entered into a long-term contract (expiring in 2018) with Pemex, which has subscribed for all of the pipeline’s capacity.
 
The Kinder Morgan North Texas Pipeline consists of an 82-mile natural gas pipeline that transports natural gas from an interconnect with the facilities of NGPL in Lamar County, Texas to a 1,750-megawatt electric generating facility located in Forney, Texas, 15 miles east of Dallas, Texas. It has the capacity to transport 325 million cubic feet per day of natural gas and is fully subscribed under a long-term contract that expires in 2032. The existing system is bi-directional, permitting deliveries of additional supply from the Barnett Shale area into NGPL’s pipeline as well as power plants in the area.
 
Kinder Morgan Energy Partners also owns and operates various gathering systems in South and East Texas. These systems aggregate natural gas supplies into Kinder Morgan Energy Partners’ main transmission pipelines and in certain cases, aggregate natural gas that must be processed or treated at its own or third-party facilities. Kinder Morgan Energy Partners owns plants that can process up to 135 million cubic feet per day of natural gas for liquids extraction. Kinder Morgan Energy Partners has contractual rights to process approximately 550 million cubic feet per day of natural gas at third-party owned facilities. Kinder Morgan Energy Partners also shares in gas processing margins on gas processed at certain third-party owned facilities. Additionally, it owns and operates three natural gas treating plants that provide carbon dioxide and/or hydrogen sulfide removal. Kinder Morgan Energy Partners can treat up to 85 million cubic feet per day of natural gas for carbon dioxide removal at the Fandango Complex in Zapata County, Texas, 50 million cubic feet per day of natural gas at the Indian Rock Plant in Upshur County, Texas and approximately 45 million cubic feet per day of natural gas at the Thompsonville Facility located in Jim Hogg County, Texas.
 
The North Dayton natural gas storage facility, located in Liberty County, Texas, has two existing storage caverns providing approximately 6.3 billion cubic feet of total capacity, consisting of 4.2 billion cubic feet of working capacity and 2.1 billion cubic feet of cushion gas. Kinder Morgan Energy Partners entered into a long-term storage capacity and transportation agreement with NRG Energy, Inc. covering two billion cubic feet of natural gas working capacity that expires in March 2017. In June 2006, Kinder Morgan Energy Partners announced an expansion project that will significantly increase natural gas storage capacity at the North Dayton facility. The project is now expected to cost between $105 million and $115 million and
 

 
16
 
Items 1. and 2.   Business and Properties. (continued)
Knight Form 10-K


involves the development of a new underground storage cavern that will add an estimated 6.5 billion cubic feet of incremental working natural gas storage capacity. The additional capacity is expected to be available in mid-2010.
 
Kinder Morgan Energy Partners also owns the West Clear Lake natural gas storage facility located in Harris County, Texas. Under a long term contract that expires in 2012, Shell Energy North American (US) L.P. operates the facility and controls the 96 billion cubic feet of natural gas working capacity, and Kinder Morgan Energy Partners provides transportation service into and out of the facility.
 
Additionally, Kinder Morgan Energy Partners leases a salt dome storage facility located near Markham, Texas, according to the provisions of an operating lease that expires in March 2013. Kinder Morgan Energy Partners can, at its sole option, extend the term of this lease for two additional ten-year periods. The facility was expanded in 2008 and now consists of five salt dome caverns with approximately 24.8 billion cubic feet of working natural gas capacity and up to 1.1 billion cubic feet per day of peak deliverability. Kinder Morgan Energy Partners also leases two salt dome caverns, known as the Stratton Ridge Facilities, from Ineos USA, LLC in Brazoria County, Texas. The Stratton Ridge Facilities have a combined working natural gas capacity of 1.4 billion cubic feet and a peak day deliverability of 150 million cubic feet per day. In addition to the aforementioned storage facilities, Kinder Morgan Energy Partners contracts for storage services from third parties which it then sells to customers on its pipeline system.
 
Markets. Texas is one of the largest natural gas consuming states in the country. The natural gas demand profile in Kinder Morgan Energy Partners’ Texas intrastate pipeline group’s market area is primarily composed of industrial (including on-site cogeneration facilities), merchant and utility power and local natural gas distribution consumption. The industrial demand is primarily year-round load. Merchant and utility power demand peaks in the summer months and is complemented by local natural gas distribution demand that peaks in the winter months. As new merchant gas-fired generation has come online and displaced traditional utility generation, Kinder Morgan Energy Partners has successfully attached many of these new generation facilities to its pipeline systems in order to maintain and grow its share of natural gas supply for power generation.
 
Kinder Morgan Energy Partners serves the Mexico market through interconnection with the facilities of Pemex at the United States-Mexico border near Arguellas, Mexico and Kinder Morgan Energy Partners’ Meir-Monterrey Mexico pipeline. In 2008, deliveries through the existing interconnection near Arguellas fluctuated from zero to approximately 295 million cubic feet per day of natural gas, and there were several days of exports to the United States that ranged up to 288 million cubic feet per day. Deliveries to Monterrey also ranged from zero to 321 million cubic feet per day. Kinder Morgan Energy Partners primarily provides transport service to these markets on a fee for service basis, including a significant demand component, which is paid regardless of actual throughput. Revenues earned from Kinder Morgan Energy Partners’ activities in Mexico are paid in U.S. dollar equivalent.
 
Supply.  Kinder Morgan Energy Partners purchases its natural gas directly from producers attached to its system in South Texas, East Texas, West Texas and along the Texas Gulf Coast. In addition, Kinder Morgan Energy Partners also purchases gas at interconnects with third-party interstate and intrastate pipelines. While the intrastate group does not produce gas, it does maintain an active well connection program in order to offset natural declines in production along its system and to secure supplies for additional demand in its market area. The intrastate system has access to both onshore and offshore sources of supply and liquefied natural gas from the Freeport LNG Terminal near Freeport, Texas and from the Golden Pass Terminal currently under development by ExxonMobil south of Beaumont, Texas.
 
Competition. The Texas intrastate natural gas market is highly competitive, with many markets connected to multiple pipeline companies. Kinder Morgan Energy Partners competes with interstate and intrastate pipelines, and their shippers, for attachments to new markets and supplies and for transportation, processing and treating services.
 
Western Interstate Natural Gas Pipeline Group
 
The group, which operates primarily along the Rocky Mountain region of the western portion of the United States, consists of the following four natural gas pipeline systems:
 
 
·
Kinder Morgan Interstate Gas Transmission (“KMIGT”) Pipeline;
 
·
Trailblazer Pipeline Company LLC (“Trailblazer”);
 
·
TransColorado Gas Transmission Company LLC (“TransColorado”) Pipeline; and
 
·
51% ownership interest in the Rockies Express Pipeline LLC.
 
KMIGT owns approximately 5,100 miles of transmission lines in Wyoming, Colorado, Kansas, Missouri and Nebraska. The pipeline system is powered by 26 transmission and storage compressor stations with approximately 160,000 horsepower. KMIGT also owns the Huntsman natural gas storage facility, located in Cheyenne County, Nebraska, which has approximately 10 billion cubic feet of firm capacity commitments and provides for withdrawal of up to 169 million cubic feet per day of natural gas.
 

 
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Items 1. and 2.   Business and Properties. (continued)
Knight Form 10-K


Under transportation agreements and FERC tariff provisions, KMIGT offers its customers firm and interruptible transportation and storage services, including no-notice service and park and loan services. For these services, KMIGT charges rates that include the retention of fuel and gas lost and unaccounted for in-kind. Under KMIGT’s tariffs, firm transportation and storage customers pay reservation charges each month plus a commodity charge based on the actual transported or stored volumes. In contrast, interruptible transportation and storage customers pay a commodity charge based upon actual transported and/or stored volumes. Under the no-notice service, customers pay a fee for the right to use a combination of firm storage and firm transportation to effect deliveries of natural gas up to a specified volume without making specific nominations. KMIGT also has the authority to make gas purchases and sales, as needed for system operations, pursuant to its currently effective FERC gas tariff.
 
KMIGT also offers its Cheyenne Market Center service, which provides nominated storage and transportation service between its Huntsman storage field and multiple interconnecting pipelines at the Cheyenne Hub, located in Weld County, Colorado. This service is fully subscribed through May 2014.
 
Markets.  Markets served by KMIGT provide a stable customer base with expansion opportunities due to the system’s access to growing Rocky Mountain supply sources. Markets served by KMIGT are comprised mainly of local natural gas distribution companies and interconnecting interstate pipelines in the Mid-Continent area. End users of the local natural gas distribution companies typically include residential, commercial, industrial and agricultural customers. The pipelines interconnecting with KMIGT in turn deliver gas into multiple markets including some of the largest population centers in the Midwest. Natural gas demand to power pumps for crop irrigation during the summer from time-to-time exceeds heating season demand and provides KMIGT relatively consistent volumes throughout the year. KMIGT has seen a significant increase in demand from ethanol producers, and has expanded its system to meet the demands from the ethanol producing community. Additionally, in November 2008, KMIGT completed the construction of the Colorado Lateral Pipeline, which is a 41-mile, 12-inch pipeline from the Cheyenne Hub southward to the Greeley, Colorado area. Atmos Energy is served by this pipeline under a long-term firm transportation contract, and KMIGT is marketing additional capacity along its route.
 
Supply.  Approximately 11%, by volume, of KMIGT’s firm contracts expire within one year and 57% expire within one to five years. Over 95% of the system’s total firm transport capacity is currently subscribed, with 69% of the total contracted capacity held by KMIGT’s top ten shippers.
 
Competition.  KMIGT competes with other interstate and intrastate natural gas pipelines transporting natural gas from the supply sources in the Rocky Mountain and Hugoton Basins to Mid-Continent pipelines and market centers.
 
Trailblazer owns a 436-mile natural gas pipeline system. Trailblazer’s pipeline originates at an interconnection with Wyoming Interstate Company Ltd.’s pipeline system near Rockport, Colorado and runs through southeastern Wyoming to a terminus near Beatrice, Nebraska where it interconnects with NGPL’s and Northern Natural Gas Company’s pipeline systems. NGPL manages, maintains and operates Trailblazer, for which it is reimbursed at cost.
 
Trailblazer offers its customers firm and interruptible transportation services.
 
Markets.  Significant growth in Rocky Mountain natural gas supplies has prompted a need for additional pipeline transportation service. Trailblazer has a certificated capacity of 846 million cubic feet per day of natural gas.
 
Supply.  As of December 31, 2008, approximately 6% of Trailblazer’s firm contracts, by volume, expire within one year and 53%, by volume, expire within one to five years. Affiliated entities have contracted for less than 1% of the total firm transportation capacity. All of the system’s firm transport capacity is currently subscribed.
 
Competition.   The main competition that Trailblazer currently faces is that the gas supply in the Rocky Mountain area is transported on competing pipelines to the west or east. El Paso’s Cheyenne Plains Pipeline can transport approximately 730 million cubic feet per day of natural gas from Weld County, Colorado to Greensburg, Kansas and Rockies Express Pipeline can transport approximately 1.6 billion cubic feet per day of natural gas from the Rocky Mountain area to Midwest markets. These systems compete with Trailblazer for natural gas pipeline transportation demand from the Rocky Mountain area. Additional competition could come from other proposed pipeline projects. No assurance can be given that additional competing pipelines will not be developed in the future.
 
TransColorado owns a 300-mile interstate natural gas pipeline that extends from approximately 20 miles southwest of Meeker, Colorado to Bloomfield, New Mexico. It has multiple points of interconnection with various interstate and intrastate pipelines, gathering systems and local distribution companies. The pipeline system is powered by eight compressor stations having an aggregate of approximately 40,000 horsepower.
 
TransColorado has the ability to flow gas south or north. TransColorado receives gas from one coal seam natural gas treating plant located in the San Juan Basin of Colorado and from pipeline, processing plant and gathering system interconnections within the Paradox and Piceance Basins of western Colorado. Gas flowing south through the pipeline moves onto the El
 

 
18
 
Items 1. and 2.   Business and Properties. (continued)
Knight Form 10-K


Paso, Transwestern and Questar Southern Trail pipeline systems. Gas moving north flows into the Colorado Interstate, Wyoming Interstate and Questar pipeline systems at the Greasewood Hub and the Rockies Express Pipeline system at the Meeker Hub. TransColorado provides transportation services to third-party natural gas producers, marketers, gathering companies, local distribution companies and other shippers.
 
Pursuant to transportation agreements and FERC tariff provisions, TransColorado offers its customers firm and interruptible transportation and interruptible park and loan services. The underlying reservation and commodity charges are assessed pursuant to a maximum recourse rate structure, which does not vary based on the distance gas is transported. TransColorado has the authority to negotiate rates with customers if it has first offered service to those customers under its reservation and commodity charge rate structure.
 
TransColorado’s approximately $50 million Blanco-Meeker Expansion Project was placed into service on January 1, 2008. The project increased capacity on the pipeline by approximately 250 million cubic feet per day of natural gas from the Blanco Hub area in San Juan County, New Mexico through TransColorado’s existing pipeline for deliveries to the Rockies Express Pipeline system at an existing point of interconnection located at the Meeker Hub in Rio Blanco County, Colorado. All of the incremental capacity is subscribed under a long-term contract with ConocoPhillips.
 
Markets.  TransColorado acts principally as a feeder pipeline system from the developing natural gas supply basins on the Western Slope of Colorado into the interstate natural gas pipelines that lead away from the Blanco Hub area of New Mexico and the interstate natural gas pipelines that lead away eastward from northwestern Colorado and southwestern Wyoming. TransColorado is one of the largest transporters of natural gas from the Western Slope supply basins of Colorado and provides a competitively attractive outlet for that developing natural gas resource. In 2008, TransColorado transported an average of approximately 675 million cubic feet per day of natural gas from these supply basins.
 
Supply.  During 2008, 93% of TransColorado’s transport business was with processors or producers or their own marketing affiliates, and 7% was with marketing companies and various gas marketers. Approximately 69% of TransColorado’s transport business in 2008 was conducted with its three largest customers. All of TransColorado’s long-haul southbound pipeline capacity is committed under firm transportation contracts that extend at least through year-end 2009. Of TransColorado’s transportation contracts, 41%, by volume, expire between one and five years from now, and TransColorado is actively pursuing contract extensions and or replacement contracts to increase firm subscription levels beyond 2009.
 
Competition.  TransColorado competes with other transporters of natural gas in each of the natural gas supply basins it serves. These competitors include both interstate and intrastate natural gas pipelines and natural gas gathering systems. TransColorado’s shippers compete for market share with shippers drawing upon gas production facilities within the New Mexico portion of the San Juan Basin. TransColorado has phased its past construction and expansion efforts to coincide with the ability of the interstate pipeline grid at Blanco, New Mexico and at the north end of its system to accommodate greater natural gas volumes. In addition, there are pipelines that are proposed to use Rocky Mountain gas to supply markets on the West Coast, including Ruby Pipeline, which filed in January 2009 for FERC authority to build pipeline from Opal, Wyoming to Malin, Oregon, with a planned in-service date of March 2011.
 
Historically, the competition faced by TransColorado with respect to its natural gas transportation services has generally been based upon the price differential between the San Juan and Rocky Mountain basins. New pipelines servicing these producing basins have had the effect of reducing that price differential; however, given the growth in the Piceance basin and the direct accessibility of the TransColorado system to these basins, we believe TransColorado’s transport business to be sustainable and not significantly affected by any new competitors.
 
Kinder Morgan Energy Partners operates and currently owns 51% of the 1,679-mile Rockies Express pipeline system, which when fully completed will be one of the largest natural gas pipelines ever constructed in North America. The project is expected to cost $6.3 billion, including a previously announced expansion and will have the capability to transport 1.8 billion cubic feet per day of natural gas. Binding firm commitments have been secured for all of the pipeline capacity.
 
Kinder Morgan Energy Partners’ ownership is through its 51% interest in West2East Pipeline LLC, the sole owner of Rockies Express Pipeline LLC, which owns the Rockies Express Pipeline. Sempra Pipelines & Storage, a unit of Sempra Energy and ConocoPhillips hold the remaining ownership interests in the Rockies Express Pipeline project. Kinder Morgan Energy Partners accounts for its investment under the equity method of accounting because its ownership interest will be reduced to 50% when construction of the entire project is completed. At that time, the capital accounts of West2East Pipeline LLC will be trued up to reflect Kinder Morgan Energy Partners’ 50% economic interest in the project.
 
On August 9, 2005, the FERC approved Rockies Express Pipeline LLC’s application to construct 327 miles of pipeline facilities in two phases. Phase I consisted of the following two pipeline segments: (i) a 136-mile, 36-inch diameter pipeline that extends from the Meeker Hub in Rio Blanco County, Colorado to the Wamsutter Hub in Sweetwater County, Wyoming; and (ii) a 191-mile, 42-inch diameter pipeline that extends from the Wamsutter Hub to the Cheyenne Hub in Weld County, Colorado. Phase II of the project includes the construction of three compressor stations referred to as the Meeker, Big Hole
 

 
19
 
Items 1. and 2.   Business and Properties. (continued)
Knight Form 10-K


and Wamsutter compressor stations. The Meeker and Wamsutter stations were completed and placed in-service in January 2008. Construction of the Big Hole compressor station was completed in the fourth quarter of 2008 in order to meet an expected in-service date in April 2009.
 
On April 19, 2007, the FERC issued a final order approving Rockies Express Pipeline LLC’s application for authorization to construct and operate certain facilities comprising its proposed Rockies Express-West project. This project is the first planned segment extension of the Rockies Express Pipeline LLC’s original certificated facilities, and is comprised of approximately 713 miles of 42-inch diameter pipeline extending eastward from the Cheyenne Hub to an interconnection with Panhandle Eastern Pipe Line located in Audrain County, Missouri. The segment extension transports approximately 1.5 billion cubic feet per day of natural gas across the following five states: Wyoming, Colorado, Nebraska, Kansas and Missouri, and includes certain improvements to pre-existing Rockies Express Pipeline facilities located to the west of the Cheyenne Hub. Construction of the Rockies Express-West project commenced on May 21, 2007, and interim firm transportation service with capacity of approximately 1.4 billion cubic feet per day began January 12, 2008. The entire project (Rockies Express-West pipeline segment) became fully operational on May 20, 2008.
 
On April 30, 2007, Rockies Express Pipeline LLC filed an application with the FERC requesting approval to construct and operate the Rockies Express-East Project, the third segment of the Rockies Express Pipeline system. The Rockies Express-East Project will be comprised of approximately 639 miles of 42-inch diameter pipeline commencing from the terminus of the Rockies Express-West pipeline in Audrain County, Missouri to a terminus near the town of Clarington in Monroe County, Ohio. The pipeline segment will be capable of transporting approximately 1.8 billion cubic feet per day of natural gas. The FERC approved the application on May 30, 2008 and construction commenced on the Rockies Express-East Project on June 26, 2008. Rockies Express-East is currently projected to commence service on April 1, 2009 to interconnects upstream of Lebanon, followed by service to the Lebanon Hub in Warren County, Ohio beginning June 15, 2009. Final completion and deliveries to Clarington, Ohio are expected to commence by November 1, 2009.
 
Markets.  The Rockies Express Pipeline is capable of delivering gas to multiple markets along its pipeline system, primarily through interconnects with other interstate pipeline companies and direct connects to local distribution companies. Rockies Express Pipeline’s Zone 1 encompasses receipts and deliveries of natural gas west of the Cheyenne Hub, located in northern Colorado near Cheyenne, Wyoming. Through the Zone 1 facilities, Rockies Express Pipeline can deliver gas to TransColorado Gas Transmission Company LLC in northwestern Colorado, which can in turn transport the gas farther south for delivery into the San Juan Basin area. In Zone 1, Rockies Express Pipeline can also deliver gas into western Wyoming through leased capacity on the Overthrust Pipeline Company system, or through its interconnections with Colorado Interstate Gas Company and Wyoming Interstate Company in southern Wyoming. In addition, through the pipeline’s Zone 1 facilities, shippers have the ability to deliver natural gas to points at the Cheyenne Hub, which could be used in markets along the Front Range of Colorado, or could be transported farther east through either Rockies Express Pipeline’s Zone 2 and/or Zone 3 facilities into other pipeline systems.
 
Rockies Express Pipeline’s Zone 2 extends from the Cheyenne Hub to an interconnect with Panhandle Eastern Pipeline in Audrain County, Missouri. Through the Zone 2 facilities, Rockies Express Pipeline facilitates the delivery of natural gas into the Mid-Continent area of the Unites States through various interconnects with other major interstate pipelines in Nebraska (Northern Natural Gas Pipeline and NGPL), Kansas (ANR Pipeline) and Missouri (Panhandle Eastern Pipeline). Rockies Express Pipeline’s transportation is capable of delivering 1.5 billion cubic feet per day through these interconnects to the Mid-Continent market.
 
The Zone 3 facilities covered by the Rockies Express-East project extend eastward from the Rockies Express-West facilities and will permit delivery to pipelines and local distribution companies providing service in the South, Midwest and eastern seaboard. The interconnecting interstate pipelines include Midwestern Gas Transmission, Trunkline, ANR, Columbia Gas, Dominion Transmission, Tennessee Gas, Texas Eastern, Texas Gas and Dominion East Ohio and the local distribution companies include Ameren and Vectren.
 
Supply.  Rockies Express Pipeline directly accesses major gas supply basins in western Colorado and western Wyoming. In western Colorado, Rockies Express Pipeline has access to gas supply from the Uinta and Piceance basins in eastern Utah and western Colorado. In western Wyoming, Rockies Express Pipeline accesses the Green River Basin through its facilities that are leased from Overthrust Pipeline Company. With its connections to numerous other pipeline systems along its route, Rockies Express Pipeline has access to almost all of the major gas supply basins in Wyoming, Colorado and eastern Utah.
 
Competition.  Although there are some competitors to the Rockies Express Pipeline system that provide a similar service, there are none that can compete with the economy-of-scale that Rockies Express Pipeline provides to its shippers to transport gas from the Rocky Mountain region to the Mid-Continent markets. The Rockies Express-East Project, noted above, will put the Rockies Express Pipeline system in a very unique position of being the only pipeline capable of offering a large volume of transportation service from Rocky Mountain gas supply directly to interstate pipelines and local distribution companies with facilities in Ohio and beyond.
 

 
20
 
Items 1. and 2.   Business and Properties. (continued)
Knight Form 10-K


Rockies Express Pipeline could also experience competition for its Rocky Mountain gas supply from both existing and proposed systems. Questar Pipeline Company accesses many of the same basins as Rockies Express Pipeline and transports gas to its markets in Utah and to other interconnects, which have access to the California market. In addition, there are pipelines that are proposed to use Rocky Mountain gas to supply markets on the West Coast, including Ruby Pipeline, which filed in January 2009 for FERC authority to build a pipeline from Opal, Wyoming to Malin, Oregon, with a planned in-service date of March 2011.
 
Central Interstate Natural Gas Pipeline Group
 
In September 2006, Kinder Morgan Energy Partners filed an application with the FERC requesting approval to construct and operate the Kinder Morgan Louisiana Pipeline. The natural gas pipeline project is expected to cost approximately $950 million and will provide approximately 3.2 billion cubic feet per day of take-away natural gas capacity from the Cheniere Sabine Pass liquefied natural gas terminal located in Cameron Parish, Louisiana. The project is supported by fully subscribed capacity and 20-year take-or-pay customer commitments with Chevron and Total.
 
The Kinder Morgan Louisiana Pipeline will consist of two segments:
 
 
·
a 132-mile, 42-inch diameter pipeline with firm capacity of approximately 2.0 billion cubic feet per day of natural gas that will extend from the Sabine Pass terminal to a point of interconnection with an existing Columbia Gulf Transmission line in Evangeline Parish, Louisiana (an offshoot will consist of approximately 2.3 miles of 24-inch diameter pipeline with firm peak day capacity of approximately 300 million cubic feet per day extending away from the 42-inch diameter line to the existing Florida Gas Transmission Company compressor station in Acadia Parish, Louisiana); and
 
·
a 1-mile, 36-inch diameter pipeline with firm capacity of approximately 1.2 billion cubic feet per day that will extend from the Sabine Pass terminal and connect to NGPL’s natural gas pipeline. Kinder Morgan Louisiana Pipeline is expected to be operational during the third quarter of 2009.
 
Kinder Morgan Energy Partners has designed and will construct the Kinder Morgan Louisiana Pipeline in a manner that will minimize environmental impacts and where possible, existing pipeline corridors will be used to minimize impacts to communities and to the environment. As of December 31, 2008, there were no major pipeline re-routes as a result of any landowner requests.
 
On October 9, 2007, Midcontinent Express Pipeline LLC filed an application with the FERC requesting a certificate of public convenience and necessity that would authorize construction and operation of the approximate 500-mile Midcontinent Express Pipeline natural gas transmission system. Kinder Morgan Energy Partners currently owns a 50% interest in Midcontinent Express Pipeline LLC and accounts for its investment under the equity method of accounting. Energy Transfer Partners, L.P. owns the remaining 50% interest. The Midcontinent Express Pipeline LLC will create long-haul, firm natural gas transportation takeaway capacity, either directly or indirectly, from natural gas producing regions located in Texas, Oklahoma and Arkansas. The project is expected to cost approximately $2.2 billion, including previously announced expansions. This is an increase from the $1.9 billion previous forecast. Much of the increase is attributable to increased construction cost. Midcontinent Express Pipeline LLC is currently finalizing negotiations with contractors for construction of the final segment. Those contracts will fix the per unit prices, providing greater cost certainty on that portion of the project and those construction costs are incorporated into the current forecast.
 
In July 2008, a successful binding open season was completed that increased commitments on the main segment of the pipeline’s Zone 1 from 1.5 billion to 1.8 billon cubic feet per day of natural gas. The pipeline capacity is fully subscribed with long-term binding commitments from creditworthy shippers.
 
In January 2008, in conjunction with the signing of additional binding transportation commitments, Midcontinent Express Pipeline LLC and Mark West Energy Partners L.P. entered into an option agreement, which provides Mark West Energy Partners L.P. a one-time right to purchase a 10% ownership interest in Midcontinent Express Pipeline LLC after the pipeline is fully constructed and placed into service. If the option is exercised, Kinder Morgan Energy Partners and Energy Transfer Partners will each own 45% of Midcontinent Express Pipeline LLC, while Mark West Energy Partners L.P. will own the remaining 10%.
 
The Fayetteville Express Pipeline, when completed, will be a 187-mile, 42-inch diameter pipeline that originates in Conway County, Arkansas, continues eastward through White County, Arkansas and terminates at an interconnect with Trunkline Gas Company’s pipeline in Quitman County, Mississippi. We own a 50% interest in Fayetteville Express Pipeline LLC and Energy Transfer Partners L.P. owns the remaining interest.
 
The Fayetteville Express Pipeline will also interconnect with Natural Gas Pipeline Company of America LLC’s pipeline in White County, Arkansas, Texas Gas Transmission LLC’s pipeline in Coahoma County, Mississippi, and ANR Pipeline Company’s pipeline in Quitman County, Mississippi. The Fayetteville Express Pipeline will have an initial capacity of 2.0
 

 
21
 
Items 1. and 2.   Business and Properties. (continued)
Knight Form 10-K


billion cubic feet of natural gas per day. Pending necessary regulatory approvals, the approximate $1.2 billion pipeline project is expected to be in service by late 2010 or early 2011. Fayetteville Express Pipeline LLC has secured binding 10-year commitments totaling approximately 1.85 billion cubic feet per day and completed a successful binding open season for shippers on November 7, 2008.
 
Kinder Morgan Energy Partners owns and operates the Casper and Douglas natural gas processing systems, which have the capacity to process up to 185 million cubic feet per day of natural gas depending on raw gas quality.
 
Markets.  Casper and Douglas are processing plants servicing gas streams flowing into KMIGT. Natural gas liquids processed by the Casper plant are sold into local markets consisting primarily of retail propane dealers and oil refiners. Natural gas liquids processed by the Douglas plant are sold to ConocoPhillips via their Powder River natural gas liquids pipeline for either ultimate consumption at the Borger refinery or for further disposition to the natural gas liquids trading hubs located in Conway, Kansas and Mont Belvieu, Texas.
 
Competition.  Other regional facilities in the Greater Powder River Basin include the Hilight plant (80 million cubic feet per day) owned and operated by Anadarko, the Sage Creek plant (50 million cubic feet per day) owned and operated by Merit Energy, and the Rawlins plant (230 million cubic feet per day) owned and operated by El Paso. Casper and Douglas, however, are the only plants which provide straddle processing of natural gas flowing into KMIGT.
 
Kinder Morgan Energy Partners owns a 49% equity interest in the Red Cedar Gathering Company, a joint venture organized in August 1994 and referred to in this report as Red Cedar. The remaining 51% interest in Red Cedar is owned by the Southern Ute Indian Tribe. Red Cedar owns and operates natural gas gathering, compression and treating facilities in the Ignacio Blanco Field in La Plata County, Colorado. The Ignacio Blanco Field lies within the Colorado portion of the San Juan Basin, most of which is located within the exterior boundaries of the Southern Ute Indian Tribe Reservation. Red Cedar gathers coal seam and conventional natural gas at wellheads and several central delivery points, for treating, compression and delivery into three major interstate natural gas pipeline systems and an intrastate pipeline.
 
Red Cedar also owns Coyote Gas Treating, LLC, referred to in this report as Coyote Gulch. The sole asset owned by Coyote Gulch is a 250 million cubic feet per day natural gas treating facility located in La Plata County, Colorado. The inlet gas stream treated by Coyote Gulch contains an average carbon dioxide content of between 12% and 13%. The plant treats the gas down to a carbon dioxide concentration of 2% in order to meet interstate natural gas pipeline quality specifications and then compresses the natural gas into the TransColorado pipeline for transport to the Blanco, New Mexico-San Juan Basin Hub.
 
Red Cedar’s gas gathering system currently consists of over 1,100 miles of gathering pipeline connecting more than 1,200 producing wells, 85,000 horsepower of compression at 21 field compressor stations and two carbon dioxide treating plants. The capacity and throughput of the Red Cedar system as currently configured is approximately 750 million cubic feet per day of natural gas.
 
 
The CO2–KMP segment consists of Kinder Morgan CO2 Company, L.P. and its consolidated affiliates, referred to in this report as KMCO2. Carbon dioxide is used in enhanced oil recovery projects as a flooding medium for recovering crude oil from mature oil fields. KMCO2’s carbon dioxide pipelines and related assets allow Kinder Morgan Energy Partners to market a complete package of carbon dioxide supply, transportation and technical expertise to the customer. Together, the CO2–KMP business segment produces, transports and markets carbon dioxide for use in enhanced oil recovery operations. Kinder Morgan Energy Partners also holds ownership interests in several oil-producing fields and owns a 450-mile crude oil pipeline, all located in the Permian Basin region of West Texas.
 
Carbon Dioxide Reserves
 
Kinder Morgan Energy Partners owns approximately 45% of, and operates, the McElmo Dome unit near Cortez, Colorado, which contains more than nine trillion cubic feet of recoverable carbon dioxide. Deliverability and compression capacity exceeds one billion cubic feet per day. Kinder Morgan Energy Partners completed the installation of facilities and drilled eight wells that have increased the production capacity from McElmo Dome by over 200 million cubic feet per day. Kinder Morgan Energy Partners also owns approximately 11% of the Bravo Dome unit in New Mexico, which contains more than one trillion cubic feet of recoverable carbon dioxide and produces approximately 290 million cubic feet per day.
 
Kinder Morgan Energy Partners also owns approximately 87% of the Doe Canyon Deep unit in southwest Colorado, which contains more than 1.5 trillion cubic feet of carbon dioxide. During 2008, Kinder Morgan Energy Partners completed the installation of facilities and drilled six wells that began to produce over 100 million cubic feet per day of carbon dioxide.
 

 
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Items 1. and 2.   Business and Properties. (continued)
Knight Form 10-K


Markets.  Kinder Morgan Energy Partners’ principal market for carbon dioxide is for injection into mature oil fields in the Permian Basin, where industry demand is expected to grow modestly for the next several years. Kinder Morgan Energy Partners is exploring additional potential markets, including enhanced oil recovery targets in California, Wyoming, the Gulf Coast, Mexico, and Canada, and coal bed methane production in the San Juan Basin of New Mexico.
 
Competition.  Kinder Morgan Energy Partners’ primary competitors for the sale of carbon dioxide include suppliers that have an ownership interest in McElmo Dome, Bravo Dome and Sheep Mountain carbon dioxide reserves, and PetroSource Energy Company, a wholly owned subsidiary of SandRidge Energy, Inc., which gathers waste carbon dioxide from natural gas production in the Val Verde Basin of West Texas. There is no assurance that new carbon dioxide sources will not be discovered or developed, which could compete with Kinder Morgan Energy Partners or that new methodologies for enhanced oil recovery will not replace carbon dioxide flooding.
 
Carbon Dioxide Pipelines
 
As a result of its 50% ownership interest in Cortez Pipeline Company, Kinder Morgan Energy Partners owns a 50% equity interest in and operates the approximate 500-mile, Cortez pipeline. The pipeline carries carbon dioxide from the McElmo Dome and Doe Canyon Deep source fields near Cortez, Colorado to the Denver City, Texas hub. The Cortez pipeline currently transports over one billion cubic feet of carbon dioxide per day, including approximately 99% of the carbon dioxide transported downstream on the Central Basin pipeline and the Centerline pipeline. The tariffs charged by Cortez Pipeline Company are not regulated.
 
Kinder Morgan Energy Partners’ Central Basin pipeline consists of approximately 143 miles of pipe and 177 miles of lateral supply lines located in the Permian Basin between Denver City, Texas and McCamey, Texas, with a throughput capacity of 700 million cubic feet per day. At its origination point in Denver City, the Central Basin pipeline interconnects with all three major carbon dioxide supply pipelines from Colorado and New Mexico, namely the Cortez pipeline (operated by KMCO2) and the Bravo and Sheep Mountain pipelines (operated by Oxy Permian). Central Basin’s mainline terminates near McCamey where it interconnects with the Canyon Reef Carriers pipeline and the Pecos pipeline. The tariffs charged by the Central Basin pipeline are not regulated.
 
Kinder Morgan Energy Partners’ Centerline pipeline consists of approximately 113 miles of pipe located in the Permian Basin between Denver City, Texas and Snyder, Texas. The pipeline has a capacity of 300 million cubic feet per day. The tariffs charged by the Centerline pipeline are not regulated.
 
Kinder Morgan Energy Partners owns a 13% undivided interest in the 218-mile Bravo pipeline, which delivers carbon dioxide from the Bravo Dome source field in northeast New Mexico to the Denver City hub and has a capacity of more than 350 million cubic feet per day. Tariffs on the Bravo pipeline are not regulated.
 
In addition, Kinder Morgan Energy Partners owns approximately 98% of the Canyon Reef Carriers pipeline and approximately 69% of the Pecos pipeline. The Canyon Reef Carriers pipeline extends 139 miles from McCamey, Texas, to the SACROC unit. The pipeline has a capacity of approximately 290 million cubic feet per day and makes deliveries to the SACROC, Sharon Ridge, Cogdell and Reinecke units. The Pecos pipeline is a 25-mile pipeline that runs from McCamey to Iraan, Texas. It has a capacity of approximately 120 million cubic feet per day of carbon dioxide and makes deliveries to the Yates unit. The tariffs charged on the Canyon Reef Carriers and Pecos pipelines are not regulated.
 
Markets.  The principal market for transportation on KMCO2’s carbon dioxide pipelines is to customers, including Kinder Morgan Energy Partners, using carbon dioxide for enhanced recovery operations in mature oil fields in the Permian Basin, where industry demand is expected to grow modestly for the next several years.
 
Competition.  Kinder Morgan Energy Partners’ ownership interests in the Central Basin, Cortez and Bravo pipelines are in direct competition with other carbon dioxide pipelines. Kinder Morgan Energy Partners also competes with other interest owners in McElmo Dome and Bravo Dome for transportation of carbon dioxide to the Denver City, Texas market area.
 
Oil Acreage and Wells
 
KMCO2 also holds ownership interests in oil-producing fields, including an approximate 97% working interest in the SACROC unit, an approximate 50% working interest in the Yates unit, an approximate 21% net profits interest in the H.T. Boyd unit, an approximate 65% working interest in the Claytonville unit, an approximate 95% working interest in the Katz CB Long unit, an approximate 64% working interest in the Katz SW River unit, a 100% working interest in the Katz East River unit, and lesser interests in the Sharon Ridge unit, the Reinecke unit and the MidCross unit, all of which are located in the Permian Basin of West Texas.
 

 
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Items 1. and 2.   Business and Properties. (continued)
Knight Form 10-K


The SACROC unit is one of the largest and oldest oil fields in the United States using carbon dioxide flooding technology. The field is comprised of approximately 56,000 acres located in the Permian Basin in Scurry County, Texas. SACROC was discovered in 1948 and has produced over 1.31 billion barrels of oil since inception. It is estimated that SACROC originally held approximately 2.7 billion barrels of oil. We have expanded the development of the carbon dioxide project initiated by the previous owners and increased production over the last several years. The Yates unit is also one of the largest oil fields ever discovered in the United States. It is estimated that it originally held more than five billion barrels of oil, of which about 29% has been produced. The field, discovered in 1926, is comprised of approximately 26,000 acres located about 90 miles south of Midland, Texas.
 
In 2008, the average purchased CO2 injection rate was 259 million cubic feet per day, up from an average of 212 million cubic feet per day in 2007. The average oil production rate for 2008 was approximately 28,000 barrels of oil per day, up from an average of approximately 27,600 barrels of oil per day during 2007. The average natural gas liquids production rate (net of the processing plant share) for 2008 was approximately 5,500 barrels per day, a decrease from an average of approximately 6,300 barrels per day during 2007.
 
Kinder Morgan Energy Partners’ plan has been to increase the production rate and ultimate oil recovery from Yates by combining horizontal drilling with carbon dioxide injection to ensure a relatively steady production profile over the next several years. Kinder Morgan Energy Partners is implementing its plan and during 2008, the Yates unit produced about 27,600 barrels of oil per day, up from an average of approximately 27,000 barrels of oil per day in 2007. Unlike operations at SACROC, where carbon dioxide and water is used to drive oil to the producing wells, Kinder Morgan Energy Partners is using carbon dioxide injection to replace nitrogen injection at Yates in order to enhance the gravity drainage process, as well as to maintain reservoir pressure. The differences in geology and reservoir mechanics between the two fields mean that substantially less capital will be needed to develop the reserves at Yates than is required at SACROC.
 
Kinder Morgan Energy Partners also operates and owns an approximate 65% gross working interest in the Claytonville oil field unit located in Fisher County, Texas. The Claytonville unit is located nearly 30 miles east of the SACROC unit in the Permian Basin of West Texas and producing 235 barrels of oil per day during 2008, up from an average of 218 barrels of oil per day during 2007. Kinder Morgan Energy Partners is presently evaluating operating and subsurface technical data from the Claytonville unit to further assess redevelopment opportunities including carbon dioxide flood operations.
 
Kinder Morgan Energy Partners also operates and owns working interests in the Katz CB Long unit, the Katz Southwest River unit and Katz East River unit. The Katz field is located in the Permian Basin area of West Texas and during 2008, produced 425 barrels of oil per day, up from an average of 408 barrels of oil per day during 2007. Kinder Morgan Energy Partners is presently evaluating operating and subsurface technical data to further assess redevelopment opportunities for the Katz field including the potential for carbon dioxide flood operations.
 
The following table sets forth productive wells, service wells and drilling wells in the oil and gas fields in which Kinder Morgan Energy Partners owns interests as of December 31, 2007. When used with respect to acres or wells, gross refers to the total acres or wells in which Kinder Morgan Energy Partners has a working interest; net refers to gross acres or wells multiplied, in each case, by the percentage working interest owned by Kinder Morgan Energy Partners:
 
 
Productive Wells1
  
Service Wells2
  
Drilling Wells3
 
Gross
  
Net
  
Gross
  
Net
  
Gross
  
Net
Crude Oil                           
2,906
  
2,029
  
895
  
700
  
4
  
4
Natural Gas                           
6
  
3
  
36
  
18
  
─
  
─
Total Wells
2,912
  
2,032
  
931
  
718
  
4
  
4
__________
1
Includes active wells and wells temporarily shut-in. As of December 31, 2007, Kinder Morgan Energy Partners did not operate any productive wells with multiple completions.
2
Consists of injection, water supply, disposal wells and service wells temporarily shut-in. A disposal well is used for disposal of saltwater into an underground formation; a service well is a well drilled in a known oil field in order to inject liquids that enhance recovery or dispose of salt water.
3
Consists of development wells in the process of being drilled as of December 31, 2008. A development well is a well drilled in an already discovered oil field.
 

 
24
 
Items 1. and 2.   Business and Properties. (continued)
Knight Form 10-K


The oil and gas producing fields in which Kinder Morgan Energy Partners owns interests are located in the Permian Basin area of West Texas. The following table reflects Kinder Morgan Energy Partners’ net productive and dry wells that were completed in each of the three years ended December 31, 2008, 2007 and 2006:
 
 
2008
  
2007
  
2006
Productive
          
Development                                  
47
  
31
  
37
Exploratory                                  
-
  
-
  
-
Dry
          
Development                                  
-
  
-
  
-
Exploratory                                  
-
  
-
  
-
Total Wells                                   
47
  
31
  
37
__________
Notes:
The above table includes wells that were completed during each year regardless of the year in which drilling was initiated and does not include any wells where drilling operations were not completed as of the end of the applicable year. Development wells include wells drilled in the proved area of an oil or gas reservoir.
 
The following table reflects the developed and undeveloped oil and gas acreage that Kinder Morgan Energy Partners held as of December 31, 2008:
 
 
Gross
  
Net
Developed  Acres  
72,435
  
67,731
Undeveloped Acres 
9,555
  
8,896
Total                                  
81,990
  
76,627

Operating Statistics
 
Operating statistics from Kinder Morgan Energy Partners’ oil and gas producing activities for each of the years 2008, 2007 and 2006 are shown in the following table:
 
Results of Operations for Oil and Gas Producing Activities – Unit Prices and Costs
 
 
Successor Company
    
Predecessor Company
 
Year Ended
December 31,
  
Seven Months Ended
December 31,
    
Five Months Ended
May 31,
  
Year Ended December 31,
 
2008
  
2007
    
2007
  
2006
Consolidated Companies1
                                
Production Costs per Barrel of Oil Equivalent2,3,4
$
20.44
      
$
17.00
    
$
15.15
    
$
13.30
  
Crude Oil Production (MBbl/d)
  
36.2
        
34.9
      
36.6
      
37.8
  
Natural Gas Liquids Production (MBbl/d)4
  
4.8
        
5.4
      
5.6
      
5.0
  
Natural Gas Liquids Production from Gas Plants (MBbl/d)5
  
3.5
        
4.2
      
4.1
      
3.9
  
Total Natural Gas Liquids Production (MBbl/d)
  
8.3
        
9.6
      
9.7
      
8.9
  
Natural Gas Production (MMcf/d)4,6
  
1.4
        
0.8
      
0.8
      
1.3
  
Natural Gas Production from Gas Plants (MMcf/d)5,6
  
0.2
        
0.3
      
0.2
      
0.3
  
Total Natural Gas Production (MMcf/d)6
  
1.6
        
1.1
      
1.0
      
1.6
  
Average Sales Prices Including Hedge Gains/Losses:
                                
Crude Oil Price per Bbl7
$
49.42
      
$
36.80
    
$
35.03
    
$
31.42
  
Natural Gas Liquids Price per Bbl7
$
63.48
      
$
57.78
    
$
44.55
    
$
43.52
  
Natural Gas Price per Mcf8
$
7.73
      
$
5.86
    
$
6.41
    
$
6.36
  
Total Natural Gas Liquids Price per Bbl5
$
63.00
      
$
58.55
    
$
45.04
    
$
43.90
  
Total Natural Gas Price per Mcf5
$
7.63
      
$
5.65
    
$
6.27
    
$
7.02
  
Average Sales Prices Excluding Hedge Gains/Losses:
                                
Crude Oil Price per Bbl7
$
97.70
      
$
78.65
    
$
57.43
    
$
63.27
  
Natural Gas Liquids Price per Bbl7
$
63.48
      
$
57.78
    
$
44.55
    
$
43.52
  
Natural Gas Price per Mcf8
$
7.73
      
$
5.86
    
$
6.41
    
$
6.36
  
____________
1
Amounts relate to Kinder Morgan CO2 Company, L.P. and its consolidated subsidaries.
2
Computed using production costs, excluding transportation costs, as defined by the Securities and Exchange Commisson. Natural gas volumes were converted to barrels of oil equivalent (BOE) using a conversion factor of six mcf of natural gas to one barrel of oil.

 
25
 
Items 1. and 2.   Business and Properties. (continued)
Knight Form 10-K


3
Production costs include labor, repairs and maintenance, materials, supplies, fuel and power, property taxes, severance taxes and general and administrative expenses directly related to oil and gas producing activities.
4
Includes only production attributable to leasehold ownership.
5
Includes production attributable to Kinder Morgan Energy Partners’ ownership in processing plants and third-party processing agreements.
6
Excludes natural gas production used as fuel.
7
Hedge gains/losses for crude oil and natural gas liquids are included with crude oil.
8
Natural gas sales were not hedged.
 
See Supplemental Information on Oil and Gas Producing Activities (Unaudited) to our Consolidated Financial Statements included in this report for additional information with respect to operating statistics and supplemental information on Kinder Morgan Energy Partners’ oil and gas producing activities.
 
Gas and Gasoline Plant Interests
 
Kinder Morgan Energy Partners operates and owns an approximate 22% working interest plus an additional 28% net profits interest in the Snyder gasoline plant. Kinder Morgan Energy Partners also operates and owns a 51% ownership interest in the Diamond M gas plant and a 100% ownership interest in the North Snyder plant, all of which are located in the Permian Basin of West Texas. The Snyder gasoline plant processes gas produced from the SACROC unit and neighboring carbon dioxide projects, specifically the Sharon Ridge and Cogdell units, all of which are located in the Permian Basin area of West Texas. The Diamond M and the North Snyder plants contract with the Snyder plant to process gas. Production of natural gas liquids at the Snyder gasoline plant as of December 2008 was approximately 13,900 barrels per day as compared to 15,500 barrels per day as of December 2007.
 
Crude Oil Pipeline
 
Kinder Morgan Energy Partners owns the Kinder Morgan Wink Pipeline, a 450-mile Texas intrastate crude oil pipeline system consisting of three mainline sections, two gathering systems and numerous truck delivery stations. The segment that runs from Wink to El Paso has a total capacity of 130,000 barrels of crude oil per day. The pipeline allows Kinder Morgan Energy Partners to better manage crude oil deliveries from its oil field interests in West Texas, and Kinder Morgan Energy Partners has entered into a long-term throughput agreement with Western Refining Company, L.P. to transport crude oil into Western’s 120,000 barrel per day refinery in El Paso, Texas. The 20-inch pipeline segment transported approximately 118,000 barrels of oil per day in 2008 and approximately 119,000 barrels of oil per day in 2007. The Kinder Morgan Wink Pipeline is regulated by both the FERC and the Texas Railroad Commission.
 
 
 
Liquids Terminals
 
The liquids terminals operations primarily store refined petroleum products, petrochemicals, industrial chemicals and vegetable oil products in aboveground storage tanks and transfer products to and from pipelines, vessels, tank trucks, tank barges and tank railcars. Combined, the liquids terminals facilities possess liquids storage capacity of approximately 54.2 million barrels, and in 2008, these terminals handled approximately 596 million barrels of petroleum, chemicals and vegetable oil products.
 
In the first quarter of 2008, Kinder Morgan Energy Partners completed the Phase III expansions at its Pasadena and Galena Park, Texas liquids terminal facilities. The expansions provided additional infrastructure to help meet the growing need for refined petroleum products storage capacity along the Gulf Coast. The investment of approximately $195 million included the construction of the following: (i) new storage tanks at both the Pasadena and Galena Park terminals; (ii) an additional cross-channel pipeline to increase the connectivity between the two terminals; (iii) a new ship dock at Galena Park; and (iv) an additional loading bay at its fully automated truck loading rack with ethanol handling infrastructure located at its Pasadena terminal. All of the expansions are supported by long-term customer commitments. With the completion of this expansion, the Pasadena and Galena Park terminal facilities will have a storage capacity of approximately 25 million barrels.
 
In 2008, Kinder Morgan Energy Partners announced future additional expansions at its Pasadena and Galena Park terminal facilities. The investment of approximately $114 million includes the construction of the following: (i) 12 new storage tanks at its Pasadena and Galena Park terminals, (ii) a barge dock that will be capable of handling two 300-foot barges with an
 

 
26
 
Items 1. and 2.   Business and Properties. (continued)
Knight Form 10-K


operating crane for each location and (iii) a 20-inch, cross-channel line connecting the two facilities. All of the expansions are supported by long-term customer commitments.
 
In the second quarter of 2008, Kinder Morgan Energy Partners completed and put into service approximately 2.15 million barrels of new crude oil storage capacity at its Kinder Morgan North 40 terminal located near Edmonton, Alberta, Canada. The entire capacity of this terminal is contracted with long-term contracts. The tank farm serves as a premier blending and storage hub for Canadian crude oil. Originally estimated at C$132.6 million, the total investment in this tank farm is now projected to be approximately C$170 million due primarily to additional labor costs. The tank farm has access to more than 20 incoming pipelines and several major outbound systems, including a connection with the Trans Mountain pipeline system, which currently transports up to 300,000 barrels per day of heavy crude oil and refined products from Edmonton to marketing terminals and refineries located in the greater Vancouver, British Columbia area and Puget Sound in Washington state.
 
In the first quarter of 2008, Kinder Morgan Energy Partners completed construction and placed into service nine new storage tanks at its Perth Amboy, New Jersey liquids terminal. The tanks have a combined storage capacity of 1.4 million barrels for gasoline, diesel and jet fuel. These tanks have been leased on a long-term basis to two customers. The total investment for this expansion was approximately $68 million.
 
In the third quarter of 2008, the Terminals-KMP segment completed and put into service approximately 320,000 barrels of additional gasoline capacity at its Shipyard River Terminal located in Charleston, South Carolina. This increase will bring the terminal storage capacity to approximately 1.9 million barrels for petroleum, ethanol and other liquid chemicals.
 
On August 15, 2008, Kinder Morgan Energy Partners purchased the Kinder Morgan Wilmington terminal, located in Wilmington, North Carolina, which has approximately 1.1 million barrels of liquids storage capacity. The facility has significant transportation infrastructure and provides liquid and heated storage and custom tank blending capabilities for agricultural and chemical products.
 
Competition. Kinder Morgan Energy Partners is one of the largest independent operators of liquids terminals in North America. Its primary competitors are IMTT, Magellan, Morgan Stanley, NuStar, Oil Tanking, Teppco and Vopak.
 
Bulk Terminals
 
The bulk terminal operations primarily involve dry-bulk material handling services; however, it also provides conveyor manufacturing and installation, engineering and design services and in-plant services covering material handling, conveying, maintenance and repair, railcar switching and miscellaneous marine services. Combined, the dry-bulk and material transloading facilities handled approximately 99.1 million tons of coal, petroleum coke, fertilizers, steel, ores and other dry-bulk materials in 2008. Kinder Morgan Energy Partners owns or operates approximately 100 dry-bulk terminals in the United States, Canada and the Netherlands.
 
In May 2007, Kinder Morgan Energy Partners purchased certain buildings and equipment and entered into a 40-year agreement to operate Vancouver Wharves, a bulk marine terminal located at the entrance to the Port of Vancouver, British Columbia. To acquire the terminal assets, Kinder Morgan Energy Partners paid an aggregate consideration of $59.5 million, consisting of $38.8 million in cash and $20.7 million in assumed liabilities. The facility consists of five vessel berths situated on a 139-acre site, extensive rail infrastructure, dry-bulk and liquids storage and material handling systems, which allow the terminal to handle over 3.5 million tons of cargo annually.  Vancouver Wharves has access to three major rail carriers connecting to shippers in western and central Canada and the U.S. Pacific Northwest. Vancouver Wharves offers a variety of inbound, outbound and value-added services for mineral concentrates, wood products, agri-products and sulfur.
 
In addition to the original purchase price, Kinder Morgan Energy Partners plans to spend an additional C$57 million at Vancouver Wharves to upgrade and/or relocate certain rail track and transloading systems, buildings and a shiploader.  The rail track and transloading relocations are on schedule to be completed in the second quarter of 2009. The shiploader project is expected to be completed in the fourth quarter of 2009.
 
Effective September 1, 2007, Kinder Morgan Energy Partners purchased the assets of Marine Terminals, Inc. for an aggregate consideration of approximately $102.1 million. Combined, the assets handle approximately 13.5 million tons of alloys and steel products annually from five facilities located in the southeast United States. These strategically located terminals provide handling, processing, harboring and warehousing services primarily to Nucor Corporation, one of the largest steel and steel products companies in the world, under long-term contracts.
 
In the first quarter of 2008, Kinder Morgan Energy Partners completed and put into service a barge unloading terminal located on 30 acres in Columbus, Mississippi. The Columbus terminal provides for approximately 900,000 tons of capacity and handles scrap metal, pig iron and hot briquetted iron that is brought in by barge, unloaded and then trucked to the Severstal Steel Mill, which is also located in Columbus.
 

 
27
 
Items 1. and 2.   Business and Properties. (continued)
Knight Form 10-K


In the first quarter of 2008, Kinder Morgan Energy Partners also completed and put into service the Pier X expansion at its bulk handling facility located in Newport News, Virginia. The expansion involved the construction of a new dock and installation of additional equipment that increased throughput by approximately 30%, to approximately nine million tons of bulk products per year. The expansion allows the facility, which primarily handles coal, to now receive product via vessel in addition to rail.
 
On October 2, 2008, Kinder Morgan Energy Partners acquired certain terminal assets from LPC Packaging, a California corporation, for an aggregate consideration of $5.1 million. The acquired assets included state-of-the-art packaging machinery, conveyors and mobile equipment and consist of two facilities located in Stockton, California and a single facility located in San Diego, California. Services provided by these locations include packaging 50 pound bags and super sacks of fertilizer and starch, warehousing and storage of bags and bulk, and inventory management. All three facilities benefit from strong relationships with large customers, having term commitments averaging between three and five years.
 
Competition. The bulk terminals compete with numerous independent terminal operators, other terminals owned by oil companies, stevedoring companies and other industrials opting not to outsource terminal services. Many of the bulk terminals were constructed pursuant to long-term contracts for specific customers. As a result, other terminal operators could face a significant disadvantage in competing for this business.
 
Materials Services (rail transloading)
 
The materials services operations include rail or truck transloading operations conducted at 32 owned and non-owned facilities. The Burlington Northern Santa Fe, CSX, Norfolk Southern, Union Pacific, Kansas City Southern and A&W railroads provide rail service for these terminal facilities. Approximately 50% of the products handled are liquids, including an entire spectrum of liquid chemicals, and 50% are dry-bulk products. Many of the facilities are equipped for bi-modal operation (rail-to-truck, and truck-to-rail) or connect via pipeline to storage facilities. Several facilities provide railcar storage services. Kinder Morgan Energy Partners also designs and builds transloading facilities, performs inventory management services and provides value-added services such as blending, heating and sparging. In 2008, the materials services operations handled approximately 348,000 railcars.
 
Competition. The material services operations compete with a variety of national transload and terminal operators across the United States, including Savage Services, Watco and Bulk Plus Logistics. Additionally, single or multi-site terminal operators are often entrenched in the network of Class 1 rail carriers.
 
 
 
Trans Mountain Pipeline System
 
The Trans Mountain common carrier pipeline system originates at Edmonton, Alberta and transports crude oil and refined petroleum to destinations in the interior and on the west coast of British Columbia. A connecting pipeline owned by Kinder Morgan Energy Partners delivers petroleum to refineries in the state of Washington.
 
Trans Mountain’s pipeline is 715 miles in length. The capacity of the line at Edmonton ranges from 300,000 barrels per day when heavy crude represents 20% of the total throughput (which is a historically normal heavy crude percentage) to 400,000 barrels per day with no heavy crude. As discussed above in “—Recent Developments,” the construction of the Anchor Loop expansion project, which increased pipeline capacity from approximately 260,000 to 300,000 barrels of crude oil per day was completed on October 30, 2008. The current Trans Mountain pipeline system was already looped with a 30-inch diameter pipe between Darfield and Kamloops, British Columbia and a 30-inch diameter pipe between Edson and Hinton, Alberta.
 
Trans Mountain also operates a 5.3-mile spur line from its Sumas Pump Station to the U.S. – Canada international border where it connects with a 63-mile pipeline system owned and operated by Kinder Morgan Energy Partners. The pipeline system in Washington State has a sustainable throughput capacity of approximately 135,000 barrels per day when heavy crude represents approximately 25% of throughput and connects to four refineries located in northwestern Washington State. The volumes of petroleum shipped to Washington State fluctuate in response to the price levels of Canadian crude oil in relation to petroleum produced in Alaska and other offshore sources.
 
In 2008, deliveries on Trans Mountain averaged 237,172 barrels per day. This was a decrease of 8% from average 2007 deliveries of 258,540 barrels per day. Shipments of refined petroleum represent a significant portion of Trans Mountain’s throughput. In 2008 and 2007, shipments of refined petroleum and iso-octane represented 20% and 25% of throughput, respectively. In April 2007, ten new pump stations were commissioned that boosted capacity on Trans Mountain from 225,000 to approximately 260,000 barrels per day. An additional 40,000 barrel per day expansion that increased capacity on
 

 
28
 
Items 1. and 2.   Business and Properties. (continued)
Knight Form 10-K


the pipeline to approximately 300,000 barrels per day was completed in 2008. Service on the first 25,000 barrels per day of this capacity increase began in May 2008, and the remaining 15,000 barrels per day increase began in November 2008. The crude oil and refined petroleum transported through Trans Mountain’s pipeline system originates in Alberta and British Columbia. The refined and partially refined petroleum transported to Kamloops, British Columbia and Vancouver originates from oil refineries located in Edmonton. Petroleum products delivered through Trans Mountain’s pipeline system are used in markets in British Columbia, Washington state and elsewhere.
 
Supply.  Overall Alberta crude oil supply has been increasing steadily over the past few years as a result of significant oil sands development with projects led by firms including Royal Dutch Shell, Suncor Energy and Syncrude Canada. Notwithstanding current economic factors and some announced project delays, further development is expected to continue into the future with expansions to existing oil sands production facilities as well as with new projects. In its moderate growth case, the Canadian Association of Petroleum Producers forecasts Western Canadian crude oil production to increase by over 1.4 million barrels per day by 2015. This increasing supply will likely result in constrained export pipeline capacity from Western Canada, which supports our view that both the demand for transportation services provided by Trans Mountain’s pipeline and the supply of crude oil will remain strong for the foreseeable future.
 
Shipments of refined petroleum represent a significant portion of Trans Mountain’s throughput. In 2008 and 2007, shipments of refined petroleum and iso-octane represented 20% and 25% of throughput, respectively.
 
Competition. Trans Mountain’s pipeline to the West Coast of North America is one of several pipeline alternatives for Western Canadian petroleum production. This pipeline, like the other Kinder Morgan Energy Partners’ petroleum pipelines, competes against other pipeline companies who could be in a position to offer different tolling structures.
 
Express and Jet Fuel Pipeline Systems
 
Kinder Morgan Energy Partners owns a one-third ownership interest in and operates the Express pipeline system, and we own a long-term investment with a C$113.6 million face value in a debt security issued by Express US Holdings LP (the obligor) the partnership that maintains ownership of the U.S. portion of the Express pipeline system. The Express pipeline system investment is accounted for under the equity method of accounting. The Express pipeline system is a batch-mode, common carrier crude oil pipeline system comprised of the Express Pipeline and the Platte Pipeline, collectively referred to in this report as the Express pipeline system. The approximate 1,700-mile integrated oil transportation pipeline connects Canadian and United States producers to refineries located in the U.S. Rocky Mountain and Midwest regions.
 
The Express Pipeline is a 780-mile long, 24-inch diameter pipeline that begins at the crude pipeline hub at Hardisty, Alberta and terminates at the Casper, Wyoming facilities of the Platte Pipeline. At the Hardisty, Canada oil hub, the Express Pipeline receives a variety of light, medium and heavy crude oil produced in Western Canada and makes deliveries to markets in Montana, Wyoming, Utah and Colorado. The Express Pipeline has a design capacity of 280,000 barrels per day. Receipts at Hardisty averaged 196,160 barrels per day during the year ended December 31, 2008, compared with 213,477 barrels per day during the year ended December 31, 2007.
 
The Platte Pipeline is a 926-mile long, 20-inch diameter pipeline that runs from the crude oil pipeline hub at Casper, Wyoming to refineries and interconnecting pipelines in the Wood River, Illinois area and includes related pumping and storage facilities (including tanks). The Platte Pipeline transports crude oil shipped on the Express Pipeline and crude oil produced from the Rocky Mountain area of the U.S. to markets located in Kansas and Illinois, and to other interconnecting carriers in those areas. The Platte Pipeline has a capacity of 150,000 barrels per day when shipping heavy oil and averaged 133,637 barrels per day east of Casper, Wyoming during the year ended December 31, 2008 as compared to 110,757 barrels per day for the year ended December 31, 2007.
 
The current Express pipeline system rate structure is a combination of committed rates and uncommitted rates. The committed rates apply to those shippers who have signed long-term (10 or 15 year) contracts with the Express pipeline system to transport crude oil on a ship-or-pay basis.
 
As of December 31, 2008, the Express pipeline system had total firm commitments of approximately 231,000 barrels per day, or 83% of its total capacity. These contracts expire in 2012, 2014 and 2015 in amounts of 40%, 11% and 32% of total capacity, respectively. The remaining contracts provide for committed tolls for transportation on the Express pipeline system, which can be increased each year by up to 2%. The capacity in excess of 231,000 barrels per day is made available to shippers as uncommitted capacity.
 
Kinder Morgan Energy Partners also owns and operates the approximate 25-mile aviation turbine fuel pipeline that serves the Vancouver International Airport, located in Vancouver, British Columbia, Canada (referred to in this report as the Jet Fuel pipeline system). In addition to its receiving and storage facilities located at the Westridge Marine terminal, located in the Port of Vancouver, the aviation turbine fuel operations include a terminal at the Vancouver airport that consists of five jet fuel storage tanks with an overall volume of 15,000 barrels.
 

 
29
 
Items 1. and 2.   Business and Properties. (continued)
Knight Form 10-K


Competition: The Express pipeline system, serving the U.S. Rocky Mountains and Midwest, is one of several pipeline alternatives for Western Canadian petroleum production, and throughput on the Express pipeline system may decline if overall petroleum production in Alberta declines, demand in the U.S. Rocky Mountains decreases, new pipelines are built, or if tolls become uncompetitive compared to alternatives. The Express pipeline system competes against other pipeline providers who could be in a position to establish and offer lower tolls.
 
 
Our total operating revenues are derived from a wide customer base. In 2008, the seven months ended December 31, 2007, five months ended May 31, 2007 and in 2006, no revenues from transactions with a single external customer accounted for 10% or more of our total consolidated revenues. Kinder Morgan Energy Partners’ Texas Intrastate Natural Gas Pipeline Group buys and sells significant volumes of natural gas within the state of Texas and, to a far lesser extent, the CO2–KMP and NGPL business segments also sell natural gas. Combined, total revenues from the sales of natural gas from the Natural Gas Pipelines–KMP, CO2–KMP and NGPL business segments accounted for approximately 63.7%, 56.7%, 58.4% and 61.0% of our consolidated revenues in 2008, the seven months ended December 31, 2007, five months ended May 31, 2007 and in 2006, respectively.
 
As a result of Kinder Morgan Energy Partners’ Texas Intrastate Natural Gas Pipeline Group selling natural gas in the same price environment in which it is purchased, both its total consolidated revenues and its total consolidated purchases (cost of sales) increase considerably due to the inclusion of the cost of gas in both financial statement line items. However, these higher revenues and higher purchased gas costs do not necessarily translate into increased margins in comparison to those situations in which Kinder Morgan Energy Partners charges a fee to transport gas owned by others. To the extent possible, Kinder Morgan Energy Partners attempts to balance the pricing and timing of its natural gas purchases to its natural gas sales, and these contracts are often settled in terms of an index price for both purchases and sales. We do not believe that a loss of revenues from any single customer would have a material adverse effect on our business, financial position, results of operations or cash flows.
 
 
Interstate Common Carrier Refined Petroleum Products and Oil Pipeline Rate Regulation—U.S. Operations
 
Some of our pipelines are interstate common carrier pipelines, subject to regulation by the FERC under the Interstate Commerce Act, or ICA. The ICA requires that we maintain our tariffs on file with the FERC. Those tariffs set forth the rates we charge for providing transportation services on our interstate common carrier pipelines as well as the rules and regulations governing these services. The ICA requires, among other things, that such rates on interstate common carrier pipelines be “just and reasonable” and nondiscriminatory. The ICA permits interested persons to challenge newly proposed or changed rates and authorizes the FERC to suspend the effectiveness of such rates for a period of up to seven months and to investigate such rates. If, upon completion of an investigation, the FERC finds that the new or changed rate is unlawful, it is authorized to require the carrier to refund the revenues in excess of the prior tariff collected during the pendency of the investigation. The FERC may also investigate, upon complaint or on its own motion, rates that are already in effect and may order a carrier to change its rates prospectively. Upon an appropriate showing, a shipper may obtain reparations for damages sustained during the two years prior to the filing of a complaint.
 
On October 24, 1992, Congress passed the Energy Policy Act of 1992. The Energy Policy Act deemed petroleum products pipeline tariff rates that were in effect for the 365-day period ending on the date of enactment or that were in effect on the 365th day preceding enactment and had not been subject to complaint, protest or investigation during the 365-day period to be just and reasonable or “grandfathered” under the ICA. The Energy Policy Act also limited the circumstances under which a complaint can be made against such grandfathered rates. The rates Kinder Morgan Energy Partners charged for transportation service on its Cypress Pipeline were not suspended or subject to protest or complaint during the relevant 365-day period established by the Energy Policy Act. For this reason, we believe these rates should be grandfathered under the Energy Policy Act. Certain rates on Kinder Morgan Energy Partners’ West Coast Products Pipelines were subject to protest during the 365-day period established by the Energy Policy Act. Accordingly, certain of the West Coast Products Pipelines rates have been, and continue to be, subject to complaints with the FERC, as is more fully described in Note 20 of the accompanying Notes to Consolidated Financial Statements.
 
Petroleum products pipelines may change their rates within prescribed ceiling levels that are tied to an inflation index. Shippers may protest rate increases made within the ceiling levels, but such protests must show that the portion of the rate increase resulting from application of the index is substantially in excess of the pipeline’s increase in costs from the previous year. A pipeline must, as a general rule, utilize the indexing methodology to change its rates. The FERC, however, uses cost-of-service ratemaking, market-based rates and settlement rates as alternatives to the indexing approach in certain specified circumstances.
 

 
30
 
Items 1. and 2.   Business and Properties. (continued)
Knight Form 10-K


Common Carrier Pipeline Rate Regulation—Canadian Operations
 
The Canadian portion of our crude oil and refined petroleum products pipeline systems is under the regulatory jurisdiction of Canada’s National Energy Board, referred to in this report as the NEB. The National Energy Board Act gives the NEB power to authorize pipeline construction and to establish tolls and conditions of service.
 
Trans Mountain
 
In November 2004, Trans Mountain entered into negotiations with the Canadian Association of Petroleum Producers and principal shippers for a new incentive toll settlement to be effective for the period starting January 1, 2006 and ending December 31, 2010. In January 2006, Trans Mountain reached agreement in principle, which was reduced to a memorandum of understanding for the 2006 toll settlement. A final agreement was reached with the Canadian Association of Petroleum Producers in October 2006 and NEB approval was received in November 2006.
 
The 2006 toll settlement incorporates an incentive toll mechanism that is intended to provide Trans Mountain with the opportunity to earn a return on equity greater than that calculated using the formula established by the NEB. In return for this opportunity, Trans Mountain has agreed to assume certain risks and provide cost certainty in certain areas. Part of the incentive toll mechanism specifies that Trans Mountain is allowed to keep 75% of the net revenue generated by throughput in excess of 92.5% of the capacity of the pipeline. The 2006 incentive toll settlement provides for base tolls which will, other than recalculation or adjustment in certain specified circumstances, remain in effect for the five-year period. The toll settlement also governs the financial arrangements for Trans Mountain’s two expansion projects totaling C$765 million, which were completed during 2007 and 2008. In total, the two projects added 75,000 barrels per day of incremental capacity to the system, increasing pipeline capacity to approximately 300,000 barrels per day. The toll charged for the portion of Trans Mountain’s pipeline system located in the United States falls under the jurisdiction of the FERC. See “Interstate Common Carrier Refined Petroleum Products and Oil Pipeline Rate Regulation—U.S. Operations” preceding.
 
Express Pipeline System
 
The Canadian segment of the Express pipeline system is regulated by the NEB as a Group 2 pipeline, which results in rates and terms of service being regulated on a complaint basis only. Express pipeline system’s committed rates are subject to a 2% inflation adjustment April 1 of each year. The U.S. segment of the Express Pipeline and the Platte Pipeline are regulated by the FERC. See “Interstate Common Carrier Refined Petroleum Products and Oil Pipeline Rate Regulation—U.S. Operations.” Additionally, movements on the Platte Pipeline within the State of Wyoming are regulated by the Wyoming Public Service Commission, which regulates the tariffs and terms of service of public utilities that operate in the state of Wyoming. The Wyoming Public Service Commission standards applicable to rates are similar to those of the FERC and the NEB.
 
Interstate Natural Gas Transportation and Storage Regulation
 
The FERC regulates the rates, terms and conditions of service, construction and abandonment of facilities by companies performing interstate natural gas transportation and storage services under the Natural Gas Act. To a lesser extent, the FERC regulates interstate transportation rates, terms and conditions of service under the Natural Gas Policy Act of 1978. Beginning in the mid-1980’s, the FERC initiated a number of regulatory changes intended to create a more competitive environment in the natural gas marketplace. Among the most important of these changes were:
 
 
·
Order No. 436 (1985), which required open-access, nondiscriminatory transportation of natural gas;
 
·
Order No. 497 (1988), which set forth new standards and guidelines imposing certain constraints on the interaction between interstate natural gas pipelines and their marketing affiliates and imposing certain disclosure requirements regarding that interaction; and
 
·
Order No. 636 (1992), which required interstate natural gas pipelines that perform open-access transportation under blanket certificates to ‘‘unbundle’’ or separate their traditional merchant sales services from their transportation and storage services and to provide comparable transportation and storage services with respect to all natural gas supplies;
 
·
Natural gas pipelines must now separately state the applicable rates for each unbundled service they provide (i.e., for natural gas commodity, transportation and storage). Order No. 636 contains a number of procedures designed to increase competition in the interstate natural gas industry, including:
 
 
·
requiring the unbundling of sales services from other services;
 
·
permitting holders of firm capacity on interstate natural gas pipelines to release all or a part of their capacity for resale by the pipeline; and the issuance of blanket sales certificates to interstate pipelines for unbundled services.
 
Order No. 636 has been affirmed in all material respects upon judicial review, and our own FERC orders approving
 

 
31
 
Items 1. and 2.   Business and Properties. (continued)
Knight Form 10-K


our unbundling plans are final and not subject to any pending judicial review.
 
 
·
Order No. 717 (2008), which prohibits transmission providers from disclosing to a marketing function employee non-public information about the transmission system or a transmission customer. The final rule also retains the long-standing no-conduit rule, which prohibits a transmission function provider from disclosing non-public information to marketing function employees by using a third party conduit. Additionally, the final rule requires that a transmission provider provide annual training on the Standards of Conduct to all transmission function employees, marketing function employees, officers, directors, supervisory employees and any other employees likely to become privy to transmission function information.
 
Please refer to Note 20 of the accompanying Notes to Consolidated Financial Statements for additional information regarding FERC regulatory requirements.
 
On August 8, 2005, Congress enacted the Energy Policy Act of 2005. The Energy Policy Act, among other things, amended the Natural Gas Act to prohibit market manipulation by any entity, directed the FERC to facilitate market transparency in the market for sale or transportation of physical natural gas in interstate commerce and significantly increased the penalties for violations of the Natural Gas Act, the Natural Gas Policy Act of 1978, or FERC rules, regulations or orders thereunder.
 
Posted tariff rates set the general range of maximum and minimum rates we charge shippers on our interstate natural gas pipelines. Within that range, each pipeline is permitted to charge discounted rates to meet competition, so long as such discounts are offered to all similarly situated shippers and granted without undue discrimination. Apart from discounted rates offered within the range of tariff maximums and minimums, the pipeline is permitted to offer negotiated rates where the pipeline and shippers want rate certainty, irrespective of changes that may occur to the range of tariff-based maximum and minimum rate levels. Accordingly, there are a variety of rates that different shippers may pay. For example, some shippers may pay a negotiated rate that is different than the posted tariff rate and some may pay the posted maximum tariff rate or a discounted rate that is limited by the posted maximum and minimum tariff rates. Most of the rates we charge shippers on our greenfield projects, like the Rockies Express Pipeline or the Midcontinent Express Pipeline, are pursuant to negotiated rate long-term transportation agreements. As such, negotiated rates provide certainty to the pipeline and the shipper of a fixed rate during the term of the transportation agreement, regardless of changes to the posted tariff rates. While rates may vary by shipper and circumstance, the terms and conditions of pipeline transportation and storage services are not generally negotiable.
 
California Public Utilities Commission Rate Regulation
 
The intrastate common carrier operations of the West Coast Products Pipelines’ operations in California are subject to regulation by the California Public Utilities Commission, referred to in this report as the CPUC, under a “depreciated book plant” methodology, which is based on an original cost measure of investment. Intrastate tariffs filed by us with the CPUC have been established on the basis of revenues, expenses and investments allocated as applicable to the California intrastate portion of the West Coast Products Pipelines’ business. Tariff rates with respect to intrastate pipeline service in California are subject to challenge by complaint by interested parties or by independent action of the CPUC. A variety of factors can affect the rates of return permitted by the CPUC, and certain other issues similar to those which have arisen with respect to our FERC regulated rates could also arise with respect to our intrastate rates. Certain of the West Coast Products Pipelines’ pipeline rates have been, and continue to be, subject to complaints with the CPUC, as is more fully described in Note 20 of the accompanying Notes to Consolidated Financial Statements.
 
Texas Railroad Commission Rate Regulation
 
The intrastate operations of our natural gas and crude oil pipelines in Texas are subject to certain regulation with respect to such intrastate transportation by the Texas Railroad Commission. The Texas Railroad Commission has the authority to regulate our transportation rates, though it generally has not investigated the rates or practices of our intrastate pipelines in the absence of shipper complaints.
 
Safety Regulation
 
Our interstate pipelines are subject to regulation by the United States Department of Transportation (“U.S. DOT”) and our intrastate pipelines and other operations are subject to comparable state regulations with respect to their design, installation, testing, construction, operation, replacement and management. Comparable regulation exists in some states in which we conduct pipeline operations. In addition, our truck and terminal loading facilities are subject to U.S. DOT regulations dealing with the transportation of hazardous materials by motor vehicles and railcars.
 
The Pipeline Safety Improvement Act of 2002 provides guidelines in the areas of testing, education, training and communication. The Pipeline Safety Act requires pipeline companies to perform integrity tests on natural gas transmission pipelines that exist in high population density areas that are designated as High Consequence Areas. Testing consists of
 

 
32
 
Items 1. and 2.   Business and Properties. (continued)
Knight Form 10-K


hydrostatic testing, internal magnetic flux or ultrasonic testing, or direct assessment of the piping. In addition to the pipeline integrity tests, pipeline companies must implement a qualification program to make certain that employees are properly trained. A similar integrity management rule for refined petroleum products pipelines became effective May 29, 2001.
 
We are also subject to the requirements of the Federal Occupational Safety and Health Act and other comparable federal and state statutes that address employee health and safety.
 
In general, we expect to increase expenditures in the future to comply with higher industry and regulatory safety standards. Some of these changes, such as U.S. DOT implementation of additional hydrostatic testing requirements, could significantly increase the amount of these expenditures. Such increases in our expenditures cannot be accurately estimated at this time.
 
State and Local Regulation
 
Our activities are subject to various state and local laws and regulations, as well as orders of regulatory bodies, governing a wide variety of matters, including marketing, production, pricing, pollution, protection of the environment and safety.
 
 
Our business operations are subject to federal, state, provincial and local laws and regulations relating to environmental protection, pollution and human health and safety in the United States and Canada. For example, if an accidental leak, release or spill of liquid petroleum products, chemicals or other hazardous substances occurs at or from our pipelines, or at or from our storage or other facilities, we may experience significant operational disruptions and we may have to pay a significant amount to clean up the leak, release or spill, pay for government penalties, address natural resource damages, compensate for human exposure or property damage, install costly pollution control equipment or a combination of these and other measures. The resulting costs and liabilities could materially and negatively affect our business, financial condition, results of operations and cash flows. In addition, emission controls required under federal, state and provincial environmental laws could require significant capital expenditures at our facilities.
 
Environmental and human health and safety laws and regulations are subject to change. The clear trend in environmental regulation is to place more restrictions and limitations on activities that may be perceived to affect the environment, wildlife, natural resources and human health, and there can be no assurance as to the amount or timing of future expenditures for environmental regulation compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from our customers, could have a material adverse effect on our business, financial position, results of operations and cash flows.
 
In accordance with GAAP, we accrue liabilities for environmental matters when it is probable that obligations have been incurred and the amounts can be reasonably estimated. This policy applies to assets or businesses currently owned or previously disposed. We have accrued liabilities for probable environmental remediation obligations at various sites, including multiparty sites where the U.S. Environmental Protection Agency, referred to as the U.S. EPA, or similar state agency has identified us as one of the potentially responsible parties. The involvement of other financially responsible companies at these multiparty sites could increase or mitigate our actual joint and several liability exposures. Although no assurance can be given, we believe that the ultimate resolution of these environmental matters will not have a material adverse effect on our business, financial position or results of operations. We have accrued an environmental reserve in the amount of $85.0 million as of December 31, 2008. Our reserve estimates range in value from approximately $85.0 million to approximately $121.4 million and we recorded our liability equal to the low end of the range, as we did not identify any amounts within the range as a better estimate of the liability. For additional information related to environmental matters, see Note 21 to the accompanying Notes to Consolidated Financial Statements.
 
Hazardous and Non-Hazardous Waste
 
We generate both hazardous and non-hazardous solid wastes that are subject to the requirements of the Federal Resource Conservation and Recovery Act and comparable state statutes. From time to time, state regulators and the U.S. EPA consider the adoption of stricter disposal standards for non-hazardous waste. Furthermore, it is possible that some wastes that are currently classified as non-hazardous, which could include wastes currently generated during our pipeline or liquids or bulk terminal operations, may in the future be designated as “hazardous wastes.” Hazardous wastes are subject to more rigorous and costly handling and disposal requirements than non-hazardous wastes. Such changes in the regulations may result in additional capital expenditures or operating expenses for us.
 
Superfund
 
The Comprehensive Environmental Response, Compensation and Liability Act, also known as the “Superfund” law or “CERCLA,” and analogous state laws, impose joint and several liability, without regard to fault or the legality of the original
 

 
33
 
Items 1. and 2.   Business and Properties. (continued)
Knight Form 10-K


conduct, on certain classes of “potentially responsible persons” for releases of “hazardous substances” into the environment. These persons include the owner or operator of a site and companies that disposed or arranged for the disposal of the hazardous substances found at the site. CERCLA authorizes the U.S. EPA and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur, in addition to compensation for natural resource damages, if any. Although “petroleum” is excluded from CERCLA’s definition of a “hazardous substance,” in the course of our ordinary operations, we have and will generate materials that may fall within the definition of “hazardous substance.” By operation of law, if we are determined to be a potentially responsible person, we may be responsible under CERCLA for all or part of the costs required to clean up sites at which such materials are present, in addition to compensation for natural resource damages, if any.
 
Clean Air Act
 
Our operations are subject to the Clean Air Act, its implementing regulations, and analogous state statutes and regulations. We believe that the operations of our pipelines, storage facilities and terminals are in substantial compliance with such statutes. The Clean Air Act regulations contain lengthy, complex provisions that may result in the imposition over the next several years of certain pollution control requirements with respect to air emissions from the operations of our pipelines, treating facilities, storage facilities and terminals. Depending on the nature of those requirements and any additional requirements that may be imposed by state and local regulatory authorities, we may be required to incur certain capital and operating expenditures over the next several years for air pollution control equipment in connection with maintaining or obtaining operating permits and approvals and addressing other air emission-related issues. We are unable to fully estimate the effect on earnings or operations or the amount and timing of such required capital expenditures. At this time, however, we do not believe that we will be materially adversely affected by any such requirements.
 
We are aware of the increasing focus of national and international regulatory bodies on greenhouse gas emissions and climate change issues. We are also aware of legislation, recently proposed by the Canadian legislature, to reduce greenhouse gas emissions.
 
Clean Water Act
 
Our operations can result in the discharge of pollutants. The Federal Water Pollution Control Act of 1972, as amended, its implementing regulations, also known as the Clean Water Act, and analogous state laws and regulations impose restrictions and controls regarding the discharge of pollutants into state waters or waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by applicable federal or state authorities. The Oil Pollution Act was enacted in 1990 and amends provisions of the Clean Water Act as they pertain to prevention and response to oil spills. Spill prevention control and countermeasure requirements of the Clean Water Act and some state laws require containment and similar structures to help prevent contamination of navigable waters in the event of an overflow or release.
 
Climate Change
 
Studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases,” may be contributing to warming of the Earth’s atmosphere. Methane, a primary component of natural gas, and carbon dioxide, which is naturally occurring and also a byproduct of burning of natural gas, are examples of greenhouse gases. The U.S. Congress is actively considering legislation to reduce emissions of greenhouse gases. In addition, several states have developed initiatives to regulate emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. The EPA is separately considering whether it will regulate greenhouse gases as “air pollutants” under the existing federal Clean Air Act. Passage of climate control legislation or other regulatory initiatives by Congress or various states of the U.S. or provinces of Canada or the adoption of regulations by the EPA or analogous state agencies that regulate or restrict emissions of greenhouse gases including methane or carbon dioxide in areas in which we conduct business, could result in changes to the consumption and demand for natural gas and carbon dioxide produced from our source fields and could have adverse effects on our business, financial position, results of operations and prospects.
 
Such changes could increase the costs of our operations, including costs to operate and maintain our facilities, install new emission controls on our facilities, acquire allowances to authorize our greenhouse gas emissions, pay any taxes related to our greenhouse gas emissions and administer and manage a greenhouse gas emissions program. While we may be able to include some or all of such increased costs in the rates charged by our pipelines to our customers, such recovery of costs is uncertain and may depend on events beyond our control including the outcome of future rate proceedings before the FERC or comparable state regulatory commissions and the provisions of any final legislation.
 

 
34
 
Items 1. and 2.   Business and Properties. (continued)
Knight Form 10-K


Department of Homeland Security
 
In Section 550 of the Homeland Security Appropriations Act of 2007 (P.L. 109-295) (Act), Congress gave the Department of Homeland Security (“DHS”) regulatory authority over security at certain high-risk chemical facilities. Pursuant to its congressional mandate, on April 9, 2007, DHS promulgated the Chemical Facility Anti-Terrorism Standards (“CFATS”), 6 CFR Part 27.
 
In the CFATS regulation, DHS requires all high-risk chemical and industrial facilities, including oil and gas facilities, to complete security vulnerability assessments, develop site security plans and implement protective measures necessary to meet DHS-defined risk-based performance standards. DHS has not provided final notice to all facilities that DHS determines to be high risk and subject to the rule. Therefore, neither the extent to which our facilities may be subject to coverage by the rules nor the associated costs to comply can currently be determined, but it is possible that such costs could be substantial.
 
 
Amounts we spent during 2008, 2007 and 2006 on research and development activities were not material. We employed approximately 7,800 full-time people at December 31, 2008, including employees of our indirect subsidiary KMGP Services Company, Inc., who are dedicated to the operations of Kinder Morgan Energy Partners, and employees of Kinder Morgan Canada Inc. Approximately 920 full-time hourly personnel at certain terminals and pipelines are represented by labor unions under collective bargaining agreements that expire between 2009 and 2013. KMGP Services Company, Inc., Knight Inc. and Kinder Morgan Canada Inc. each consider relations with their employees to be good. For more information on our related party transactions, see Note 7 of the accompanying Notes to Consolidated Financial Statements.
 
KMGP Services Company, Inc., a subsidiary of Kinder Morgan G.P., Inc., provides employees and Kinder Morgan Services LLC, a subsidiary of Kinder Morgan Management, provides centralized payroll and employee benefits services to Kinder Morgan Management, Kinder Morgan Energy Partners and Kinder Morgan Energy Partners’ operating partnerships and subsidiaries (collectively, “the Group”). Employees of KMGP Services Company, Inc. are assigned to work for one or more members of the Group. The direct costs of compensation, benefits expenses, employer taxes and other employer expenses for these employees are allocated and charged by Kinder Morgan Services LLC to the appropriate members of the Group, and the members of the Group reimburse their allocated shares of these direct costs. No profit or margin is charged by Kinder Morgan Services LLC to the members of the Group. Our human resources department provides the administrative support necessary to implement these payroll and benefits services, and the related administrative costs are allocated to members of the Group in accordance with existing expense allocation procedures. The effect of these arrangements is that each member of the Group bears the direct compensation and employee benefits costs of its assigned or partially assigned employees, as the case may be, while also bearing its allocable share of administrative costs. Pursuant to the limited partnership agreement, Kinder Morgan Energy Partners provides reimbursement for its share of these administrative costs and such reimbursements are accounted for as described above. Kinder Morgan Energy Partners reimburses Kinder Morgan Management with respect to the costs incurred or allocated to Kinder Morgan Management in accordance with Kinder Morgan Energy Partners’ limited partnership agreement, the Delegation of Control Agreement among Kinder Morgan G.P., Inc., Kinder Morgan Management, Kinder Morgan Energy Partners and others, and Kinder Morgan Management’s limited liability company agreement.
 
Our named executive officers and other employees that provide management or services to both us and the Group are employed by us. Additionally, other of our employees assist Kinder Morgan Energy Partners in the operation of its Natural Gas Pipeline assets. These employees’ expenses are allocated without a profit component between us and the appropriate members of the Group.
 
We believe that we have generally satisfactory title to the properties we own and use in our businesses, subject to liens on the assets of Knight Inc. and its subsidiaries (excluding Kinder Morgan Energy Partners and its subsidiaries) incurred in connection with the financing of the Going Private transaction, liens for current taxes, liens incident to minor encumbrances, and easements and restrictions that do not materially detract from the value of such property or the interests in those properties or the use of such properties in our businesses. We generally do not own the land on which our pipelines are constructed. Instead, we obtain the right to construct and operate the pipelines on other people’s land for a period of time. Substantially all of our pipelines are constructed on rights-of-way granted by the apparent record owners of such property. In many instances, lands over which rights-of-way have been obtained are subject to prior liens that have not been subordinated to the right-of-way grants. In some cases, not all of the apparent record owners have joined in the right-of-way grants, but in substantially all such cases, signatures of the owners of majority interests have been obtained. Permits have been obtained from public authorities to cross over or under, or to lay facilities in or along, water courses, county roads, municipal streets and state highways, and in some instances, such permits are revocable at the election of the grantor, or, the pipeline may be required to move its facilities at its own expense. Permits have also been obtained from railroad companies to cross over or under lands or rights-of-way, many of which are also revocable at the grantor's election. Some such permits require annual or other periodic payments. In a few minor cases, property for pipeline purposes was purchased in fee.
 

 
35
 
Items 1. and 2.   Business and Properties. (continued)
Knight Form 10-K


Our terminals, storage facilities, processing plants, regulator and compressor stations, offices and related facilities are located on real property owned or leased by us. In some cases, the real property we lease is on federal, state, provincial or local government land.
 
(D) Financial Information about Geographic Areas
 
For information concerning our assets and operations that are located outside of the continental United States of America, see Note 19 of the accompanying Notes to Consolidated Financial Statements.
 
(E) Available Information
 
We make available free of charge on or through our internet website, at www.kindermorgan.com, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission.
 
 
You should carefully consider the risks described below, in addition to the other information contained in this document. Realization of any of the following risks could have a material adverse effect on our business, financial condition, cash flows and results of operations.
 
Our business is subject to extensive regulation that affects our operations and costs.
 
Our assets and operations are subject to regulation by federal, state, provincial and local authorities, including regulation by the FERC, and by various authorities under federal, state and local environmental, human health and safety and pipeline safety laws. Regulation affects almost every aspect of our business, including, among other things, our ability to determine terms and rates for our interstate pipeline services, to make acquisitions or to build extensions of existing facilities. The costs of complying with such laws and regulations are already significant, and additional or more stringent regulation could have a material adverse impact on our business, financial condition and results of operations.
 
In addition, regulators have taken actions designed to enhance market forces in the gas pipeline industry, which have led to increased competition. In a number of U.S. markets, natural gas interstate pipelines face competitive pressure from a number of new industry participants, such as alternative suppliers, as well as traditional pipeline competitors. Increased competition driven by regulatory changes could have a material impact on business in our markets and therefore adversely affect our financial condition and results of operations.
 
Pending Federal Energy Regulatory Commission (“FERC”) and California Public Utilities Commission proceedings seek substantial refunds and reductions in tariff rates on some of Kinder Morgan Energy Partners’ pipelines. If the proceedings are determined adversely to Kinder Morgan Energy Partners, they could have a material adverse impact on us.
 
Regulators and shippers on our pipelines have rights to challenge the rates we charge under certain circumstances prescribed by applicable regulations. Some shippers on Kinder Morgan Energy Partners’ pipelines have filed complaints with the FERC and California Public Utilities Commission that seek substantial refunds for alleged overcharges during the years in question and prospective reductions in the tariff rates on Kinder Morgan Energy Partners’ West Coast Products Pipelines. We may face challenges, similar to those described in Note 20 of the accompanying Notes to Consolidated Financial Statements, to the rates we receive on our pipelines in the future. Any successful challenge could adversely and materially affect our future earnings and cash flows.
 
Rulemaking and oversight, as well as changes in regulations, by the Federal Energy Regulatory Commission or other regulatory agencies having jurisdiction over our operations could adversely impact our income and operations.
 
The rates (which include reservation, commodity, surcharges, fuel and gas lost and unaccounted for) we charge shippers on our natural gas pipeline systems are subject to regulatory approval and oversight. Furthermore, regulators and shippers on our natural gas pipelines have rights to challenge the rates shippers are charged under certain circumstances prescribed by applicable regulations. We can provide no assurance that we will not face challenges to the rates we receive on our pipeline systems in the future. Any successful challenge could materially adversely affect our future earnings and cash flows. New laws or regulations or different interpretations of existing laws or regulations applicable to our assets, including unexpected policy changes that sometimes occur following a change of presidential administration, could have a material adverse impact on our business, financial condition and results of operations.
 

 
36
 
Item 1A.  Risk Factors. (continued)
Knight Form 10-K


Increased regulatory requirements relating to the integrity of our pipelines will require us to spend additional money to comply with these requirements.
 
Through our regulated pipeline subsidiaries, we are subject to extensive laws and regulations related to pipeline integrity. There are, for example, federal guidelines for the U.S. Department of Transportation and pipeline companies in the areas of testing, education, training and communication. Compliance with laws and regulations requires significant expenditures. We have increased our capital expenditures to address these matters and expect to significantly increase these expenditures in the foreseeable future. Additional laws and regulations that may be enacted in the future or a new interpretation of existing laws and regulations could significantly increase the amount of these expenditures.
 
Environmental laws and regulations could expose us to significant costs and liabilities.
 
Our operations are subject to federal, state, provincial and local laws, regulations and potential liabilities arising under or relating to the protection or preservation of the environment, natural resources and human health and safety. Such laws and regulations affect many aspects of our present and future operations, and generally require us to obtain and comply with various environmental registrations, licenses, permits, inspections and other approvals. Liability under such laws and regulations may be incurred without regard to fault under the Comprehensive Environmental Response, Compensation, and Liability Act, commonly known as CERCLA or Superfund, the Resource Conservation and Recovery Act, commonly known as RCRA, or analogous state laws for the remediation of contaminated areas. Private parties, including the owners of properties through which our pipelines pass may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with such laws and regulations or for personal injury or property damage. Our insurance may not cover all environmental risks and costs or may not provide sufficient coverage in the event an environmental claim is made against us.
 
Failure to comply with these laws and regulations may expose us to civil, criminal and administrative fines, penalties and/or interruptions in our operations that could influence our results of operations. For example, if an accidental leak, release or spill of liquid petroleum products, chemicals or other hazardous substances occurs at or from our pipelines or our storage or other facilities, we may experience significant operational disruptions and we may have to pay a significant amount to clean up the leak, release or spill, pay for government penalties, address natural resource damage, compensate for human exposure or property damage, install costly pollution control equipment or a combination of these and other measures. The resulting costs and liabilities could materially and negatively affect our level of earnings and cash flows. In addition, emission controls required under the Federal Clean Air Act and other similar federal, state and provincial laws could require significant capital expenditures at our facilities.
 
We own and/or operate numerous properties that have been used for many years in connection with our business activities. While we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other hazardous substances may have been released at or from properties owned, operated or used by us or our predecessors, or at or from properties where our or our predecessors’ wastes have been taken for disposal. In addition, many of these properties have been owned and/or operated by third parties whose management, handling and disposal of hydrocarbons or other hazardous substances were not under our control. These properties and the hazardous substances released and wastes disposed on them may be subject to laws in the United States such as CERCLA, which impose joint and several liability without regard to fault or the legality of the original conduct. Under the regulatory schemes of the various Canadian provinces, such as British Columbia’s Environmental Management Act, Canada has similar laws with respect to properties owned, operated or used by us or our predecessors. Under such laws and implementing regulations, we could be required to remove or remediate previously disposed wastes or property contamination, including contamination caused by prior owners or operators. Imposition of such liability schemes could have a material adverse impact on our operations and financial position.
 
In addition, our oil and gas development and production activities are subject to numerous federal, state and local laws and regulations relating to environmental quality and pollution control. These laws and regulations increase the costs of these activities and may prevent or delay the commencement or continuance of a given operation. Specifically, these activities are subject to laws and regulations regarding the acquisition of permits before drilling, restrictions on drilling activities in restricted areas, emissions into the environment, water discharges, and storage and disposition of wastes. In addition, legislation has been enacted that requires well and facility sites to be abandoned and reclaimed to the satisfaction of state authorities.
 
Further, we cannot ensure that such existing laws and regulations will not be revised or that new laws or regulations will not be adopted or become applicable to us. The clear trend in environmental regulation is to place more restrictions and limitations on activities that may be perceived to affect the environment and thus, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from our customers, could have a
 

 
37
 
Item 1A.  Risk Factors. (continued)
Knight Form 10-K


material adverse effect on our business, financial position, results of operations and prospects.
 
Cost overruns and delays on our expansion and new build projects could adversely affect our business.
 
Kinder Morgan Energy Partners currently has several major expansion and new build projects planned or underway, including the Rockies Express Pipeline, which is expected to cost $6.3 billion, the Midcontinent Express Pipeline, which is expected to cost $2.2 billion, the Fayetteville Express Pipeline, which is expected to cost $1.2 billion and the Kinder Morgan Louisiana Pipeline, which is expected to cost $950 million. The cost estimates for the Rockies Express and Midcontinent Express pipelines include expansions of the base projects. A variety of factors outside our control, such as weather, natural disasters and difficulties in obtaining permits and rights-of-way or other regulatory approvals, as well as the performance by third-party contractors, has resulted in, and may continue to result in, increased costs or delays in construction. Cost overruns or delays in completing a project could have a material adverse effect on our return on investment, results of operations and cash flows.
 
Climate change regulation at the federal, state, provincial or regional levels and/or new regulations issued by the Department of Homeland Security could result in increased operating and capital costs for us.
 
Studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases,” may be contributing to warming of the Earth’s atmosphere. Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of natural gas, are examples of greenhouse gases. The U.S. Congress is actively considering legislation to reduce emissions of greenhouse gases. In addition, at least nine states in the Northeast and five states in the West have developed initiatives to regulate emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. The EPA is separately considering whether it will regulate greenhouse gases as “air pollutants” under the existing federal Clean Air Act. Passage of climate control legislation or other regulatory initiatives by Congress or various states of the U.S. or provinces of Canada or the adoption of regulations by the EPA or analogous state or provincial agencies that regulate or restrict emissions of greenhouse gases including methane or carbon dioxide in areas in which we conduct business, could result in changes to the consumption and demand for natural gas and carbon dioxide produced from our source fields and could have adverse effects on our business, financial position, results of operations and prospects.
 
Such changes could increase the costs of our operations, including costs to operate and maintain our facilities, install new emission controls on our facilities, acquire allowances to authorize our greenhouse gas emissions, pay any taxes related to our greenhouse gas emissions and administer and manage a greenhouse gas emissions program. While we may be able to include some or all of such increased costs in the rates charged by some of our pipelines or to our customers, such recovery of costs is uncertain and may depend on events beyond our control including the outcome of future rate proceedings before the FERC and the provisions of any final legislation.
 
The Department of Homeland Security Appropriation Act of 2007 requires the Department of Homeland Security, or the DHS, to issue regulations establishing risk-based performance standards for the security of chemical and industrial facilities, including oil and gas facilities that are deemed to present “high levels of security risk.” The DHS has issued rules that establish chemicals of interest and their respective threshold quantities that will trigger compliance with these standards. Covered facilities that are determined by the DHS to pose a high level of security risk will be required to prepare and submit Security Vulnerability Assessments and Site Security Plans as well as comply with other regulatory requirements, including those regarding inspections, audits, recordkeeping and protection of chemical-terrorism vulnerability information. We have not yet determined the extent of the costs to bring our facilities into compliance, but it is possible that such costs could be substantial.
 
Our rapid growth may cause difficulties integrating and constructing new operations, and we may not be able to achieve the expected benefits from any future acquisitions.
 
Part of our business strategy includes acquiring additional businesses, expanding existing assets, or constructing new facilities. If we do not successfully integrate acquisitions, expansions, or newly constructed facilities, we may not realize anticipated operating advantages and cost savings. The integration of companies that have previously operated separately involves a number of risks, including:
 
 
·
demands on management related to the increase in our size after an acquisition, an expansion, or a completed construction project;
 
·
the diversion of our management’s attention from the management of daily operations;
 
·
difficulties in implementing or unanticipated costs of accounting, estimating, reporting and other systems;
 
·
goodwill and intangible assets that are subject to impairment testing and potential periodic impairment charges;
 
·
difficulties in the assimilation and retention of necessary employees; and
 
·
potential adverse effects on operating results.
 

 
38
 
Item 1A.  Risk Factors. (continued)
Knight Form 10-K

 
We may not be able to maintain the levels of operating efficiency that acquired companies have achieved or might achieve separately. Successful integration of each acquisition, expansion, or construction project will depend upon our ability to manage those operations and to eliminate redundant and excess costs. Because of difficulties in combining and expanding operations, we may not be able to achieve the cost savings and other size-related benefits that we hoped to achieve after these acquisitions, which would harm our financial condition and results of operations.

Our acquisition strategy and expansion programs require access to new capital. Tightened capital markets or more expensive capital would impair our ability to grow.
 
Part of our business strategy includes acquiring additional businesses and expanding our assets. We may need to raise debt and equity to finance these acquisitions and expansions. Limitations on our access to capital will impair our ability to execute this strategy. We normally fund acquisitions and expansions with short-term debt and repay such debt through the issuance of equity and long-term debt. An inability to access the capital markets may result in a substantial increase in our leverage and have a detrimental impact on our credit profile.
 
Energy commodity transportation and storage activities involve numerous risks that may result in accidents or otherwise adversely affect operations.
 
There are a variety of hazards and operating risks inherent to natural gas transmission and storage activities, and refined petroleum products and carbon dioxide transportation activities—such as leaks, explosions and mechanical problems that could result in substantial financial losses. In addition, these risks could result in loss of human life, significant damage to property, environmental pollution and impairment of operations, any of which also could result in substantial losses. For pipeline and storage assets located near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering areas, the level of damage resulting from these risks could be greater. If losses in excess of our insurance coverage were to occur, they could have a material adverse effect on our business, financial condition and results of operations.
 
The development of oil and gas properties involves risks that may result in a total loss of investment.
 
The business of developing and operating oil and gas properties involves a high degree of business and financial risk that even a combination of experience, knowledge and careful evaluation may not be able to overcome. Acquisition and development decisions generally are based on subjective judgments and assumptions that, while they may be reasonable, are by their nature speculative. It is impossible to predict with certainty the production potential of a particular property or well. Furthermore, a successful completion of a well does not ensure a profitable return on the investment. A variety of geological, operational, or market-related factors, including, but not limited to, unusual or unexpected geological formations, pressures, equipment failures or accidents, fires, explosions, blowouts, cratering, pollution and other environmental risks, shortages or delays in the availability of drilling rigs and the delivery of equipment, loss of circulation of drilling fluids or other conditions may substantially delay or prevent completion of any well, or otherwise prevent a property or well from being profitable. A productive well may become uneconomic in the event water or other deleterious substances are encountered, which impair or prevent the production of oil and/or gas from the well. In addition, production from any well may be unmarketable if it is contaminated with water or other deleterious substances.
 
The volatility of natural gas and oil prices could have a material adverse effect on our business.
 
The revenues, profitability and future growth of Kinder Morgan Energy Partners’ CO2 business segment and the carrying value of its oil, natural gas liquids and natural gas properties depend to a large degree on prevailing oil and gas prices. Prices for oil, natural gas liquids and natural gas are subject to large fluctuations in response to relatively minor changes in the supply and demand for oil and natural gas, uncertainties within the market and a variety of other factors beyond our control. These factors include, among other things, weather conditions and events such as hurricanes in the United States; the condition of the United States economy; the activities of the Organization of Petroleum Exporting Countries; governmental regulation; political stability in the Middle East and elsewhere; the foreign supply of oil and natural gas; the price of foreign imports; and the availability of alternative fuel sources.
 
A sharp decline in the price of natural gas, natural gas liquids or oil prices would result in a commensurate reduction in our revenues, income and cash flows from the production of oil and natural gas and could have a material adverse effect on the carrying value of Kinder Morgan Energy Partners’ proved reserves. In the event prices fall substantially, Kinder Morgan Energy Partners may not be able to realize a profit from its production and would operate at a loss. In recent decades, there have been periods of both worldwide overproduction and underproduction of hydrocarbons and periods of both increased and relaxed energy conservation efforts. Such conditions have resulted in periods of excess supply of, and reduced demand for, crude oil on a worldwide basis and for natural gas on a domestic basis. These periods have been followed by periods of short supply of, and increased demand for, crude oil and natural gas. The excess or short supply of crude oil or natural gas has placed pressures on prices and has resulted in dramatic price fluctuations even during relatively short periods of seasonal market demand. These fluctuations necessarily impact the accuracy of assumptions used in our budgeting process.
 

 
39
 
Item 1A.  Risk Factors. (continued)
Knight Form 10-K


Our use of hedging arrangements could result in financial losses or reduce our income.
 
We currently engage in hedging arrangements to reduce our exposure to fluctuations in the prices of oil and natural gas. These hedging arrangements expose us to risk of financial loss in some circumstances, including when production is less than expected, when the counterparty to the hedging contract defaults on its contract obligations, or when there is a change in the expected differential between the underlying price in the hedging agreement and the actual prices received. In addition, these hedging arrangements may limit the benefit we would otherwise receive from increases in prices for oil and natural gas.
 
The accounting standards regarding hedge accounting are very complex, and even when we engage in hedging transactions (for example, to mitigate our exposure to fluctuations in commodity prices or currency exchange rates or to balance our exposure to fixed and variable interest rates) that are effective economically, these transactions may not be considered effective for accounting purposes. Accordingly, our financial statements may reflect some volatility due to these hedges, even when there is no underlying economic impact at that point. In addition, it is not always possible for us to engage in a hedging transaction that completely mitigates our exposure to commodity prices. Our financial statements may reflect a gain or loss arising from an exposure to commodity prices for which we are unable to enter into a completely effective hedge.
 
Kinder Morgan Energy Partners must either obtain the right from landowners or exercise the power of eminent domain in order to use most of the land on which its pipelines are constructed, and it is subject to the possibility of increased costs to retain necessary land use.
 
Kinder Morgan Energy Partners obtains the right to construct and operate pipelines on other owners’ land for a period of time. If it were to lose these rights or be required to relocate its pipelines, its business could be affected negatively. In addition, Kinder Morgan Energy Partners is subject to the possibility of increased costs under its rental agreements with landowners, primarily through rental increases and renewals of expired agreements.
 
Whether Kinder Morgan Energy Partners has the power of eminent domain for its pipelines, other than interstate natural gas pipelines, varies from state to state depending upon the type of pipeline—petroleum liquids, natural gas or carbon dioxide—and the laws of the particular state. Kinder Morgan Energy Partners’ interstate natural gas pipelines have federal eminent domain authority. In either case, Kinder Morgan Energy Partners must compensate landowners for the use of their property and, in eminent domain actions, such compensation may be determined by a court. The inability to exercise the power of eminent domain could negatively affect Kinder Morgan Energy Partners’ business if it were to lose the right to use or occupy the property on which its pipelines are located.
 
Our substantial debt could adversely affect our financial health and make us more vulnerable to adverse economic conditions.
 
As of December 31, 2008, we had outstanding $11.5 billion of consolidated debt (excluding the fair value of interest rate swaps). Of this amount, $8.6 billion was debt of Kinder Morgan Energy Partners and its subsidiaries, and the remaining $2.9 billion was debt of Knight Inc. and its subsidiaries, other than Kinder Morgan Energy Partners and its subsidiaries. Knight Inc.’s debt is currently secured by most of the assets of Knight Inc. and its subsidiaries, but the security interest does not apply to the assets of Kinder Morgan G.P., Inc., Kinder Morgan Energy Partners, Kinder Morgan Management and their respective subsidiaries. This level of debt could have important consequences, such as:
 
 
·
limiting our ability to obtain additional financing to fund our working capital, capital expenditures, debt service requirements or potential growth or for other purposes;
 
·
limiting our ability to use operating cash flow in other areas of our business because we must dedicate a substantial portion of these funds to make payments on our debt;
 
·
placing us at a competitive disadvantage compared to competitors with less debt; and
 
·
increasing our vulnerability to adverse economic and industry conditions.
 
Each of these factors is to a large extent dependent on economic, financial, competitive and other factors beyond our control.
 
Our variable rate debt makes us vulnerable to increases in interest rates.
 
As of December 31, 2008, we had outstanding $11.5 billion of consolidated debt (excluding the fair value of interest rate swaps). Of this amount, approximately 25.3% was subject to variable interest rates, either as short-term or long-term debt of variable rate credit facilities or as long-term fixed-rate debt converted to variable rates through the use of interest rate swaps. In addition, subsequent to December 31, 2008 Kinder Morgan Energy Partners entered into four fixed-to-floating interest rate swap agreements having a combined notional principal amount of $1.0 billion. Should interest rates increase significantly, the amount of cash required to service our debt would increase and our earnings could be adversely affected. For information on our interest rate risk, see Item 7A “Quantitative and Qualitative Disclosures About Market Risk—Interest Rate Risk.”

 
40
 
Item 1A.  Risk Factors. (continued)
Knight Form 10-K


Current or future distressed financial conditions of customers could have an adverse impact on us in the event these customers are unable to pay us for the products or services we provide.
 
Some of our customers are experiencing, or may experience in the future, severe financial problems that have had or may have a significant impact on their creditworthiness. We cannot provide assurance 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, financial position, future results of operations, or future cash flows. Furthermore, the bankruptcy of one or more of our customers, or some other similar proceeding or liquidity constraint, might make it unlikely that we would be able to collect all or a significant portion of amounts owed by the distressed entity or entities. In addition, such events might force such customers to reduce or curtail their future use of our products and services, which could have a material adverse effect on our results of operations and financial condition.
 
Our debt instruments may limit our financial flexibility and increase our financing costs.
 
The instruments governing our debt contain restrictive covenants that may prevent us from engaging in certain transactions that we deem beneficial and that may be beneficial to us. The agreements governing our debt generally require us to comply with various affirmative and negative covenants, including the maintenance of certain financial ratios and restrictions on (i) incurring additional debt; (ii) entering into mergers, consolidations and sales of assets; (iii) granting liens; and (iv) entering into sale-leaseback transactions. The instruments governing any future debt may contain similar or more restrictive restrictions. Our ability to respond to changes in business and economic conditions and to obtain additional financing, if needed, may be restricted.
 
Current levels of market volatility are unprecedented.
 
The capital and credit markets have been experiencing extreme volatility and disruption for more than twelve months. In some cases, the markets have exerted downward pressure on stock prices and credit capacity for certain issuers. Our plans for growth require regular access to the capital and credit markets. If current levels of market disruption and volatility continue or worsen, access to capital and credit markets could be disrupted making growth through acquisitions and development projects difficult or impractical to pursue until such time as markets stabilize.
 
Our operating results may be adversely affected by unfavorable economic and market conditions.
 
Economic conditions worldwide have from time to time contributed to slowdowns in the oil and gas industry, as well as in the specific segments and markets in which we operate, resulting in reduced demand and increased price competition for our products and services. Our operating results in one or more geographic regions may also be affected by uncertain or changing economic conditions within that region, such as the challenges that are currently affecting economic conditions in the United States. Volatility in commodity prices might have an impact on many of our customers, which in turn could have a negative impact on their ability to meet their obligations to us. In addition, decreases in the prices of crude oil and natural gas liquids will have a negative impact on the results of the CO2–KMP business segment. If global economic and market conditions (including volatility in commodity markets), or economic conditions in the United States or other key markets, remain uncertain or persist, spread or deteriorate further, we may experience material impacts on our business, financial condition and results of operations.
 
The recent downturn in the credit markets has increased the cost of borrowing and has made financing difficult to obtain, each of which may have a material adverse effect on our results of operations and business.
 
Recent events in the financial markets have had an adverse impact on the credit markets and, as a result, the availability of credit has become more expensive and difficult to obtain. Some lenders are imposing more stringent restrictions on the terms of credit and there may be a general reduction in the amount of credit available in the markets in which we conduct business. In addition, as a result of the current credit market conditions and the recent downgrade of Kinder Morgan Energy Partners’ short-term credit ratings by Standard & Poor’s Rating Services, it is currently unable to access commercial paper borrowings and instead is meeting its short-term financing and liquidity needs through borrowings under its bank credit facility. The negative impact on the tightening of the credit markets may have a material adverse effect on Kinder Morgan Energy Partners resulting from, but not limited to, an inability to expand facilities or finance the acquisition of assets on favorable terms, if at all, increased financing costs or financing with increasingly restrictive covenants.
 
The failure of any bank in which we deposit our funds could reduce the amount of cash available for operations and investments and for Kinder Morgan Energy Partners to pay distributions.
 
We have diversified our cash and cash equivalents between several banking institutions in an attempt to minimize exposure to any one of these entities. However, the Federal Deposit Insurance Corporation, or “FDIC,” only insures amounts up to $250,000 per depositor per insured bank until January 1, 2010 when the standard coverage limit will decrease to $100,000. We currently have cash and cash equivalents and restricted cash deposited in certain financial institutions in excess of
 

 
41
 
Item 1A.  Risk Factors. (continued)
Knight Form 10-K


federally insured levels. If any of the banking institutions in which we have deposited funds ultimately fails, we may lose our deposits over $250,000. The loss of our deposits could reduce the amount of cash available for operations and investments and that Kinder Morgan Energy Partners has available to distribute, which could result in a decline in the value of our investment in Kinder Morgan Energy Partners.
 
There can be no assurance as to the impact on the financial markets of the United States government’s plans to purchase large amounts of illiquid, mortgage-backed and other securities from financial institutions.
 
In response to the financial crises affecting the banking system and financial markets and going concern threats to investment banks and other financial institutions, the U.S. Treasury has announced plans to purchase mortgage-backed and other securities from financial institutions for the purpose of stabilizing the financial markets. There can be no assurance what impact these purchases or similar actions by the United States government will have on the financial markets. Although we are not one of the institutions that would sell securities to the United States Treasury, the ultimate effects of these actions on the financial markets and the economy in general could materially and adversely affect our business, financial condition and results of operations.
 
The Going Private transaction resulted in substantially more debt to us and a downgrade of the ratings of our debt securities, which has increased our cost of capital.
 
In connection with the Going Private transaction, Standard & Poor’s Rating Services and Moody’s Investors Service, Inc. downgraded the ratings assigned to Knight Inc.’s senior unsecured debt to BB- and Ba2, respectively. Upon the February 2008 80% ownership interest sale of our NGPL business segment, which resulted in Knight Inc.’s repayment of a substantial amount of debt; Standard & Poor’s Rating Services and Moody’s Investors Service, Inc. upgraded Knight Inc.’s senior unsecured debt to BB and Ba1, respectively. However, these ratings are still below investment grade. Since the Going Private transaction, Knight Inc. has not had access to the commercial paper market and is currently utilizing its $1.0 billion revolving credit facility for its short-term borrowing needs.
 
The future success of Kinder Morgan Energy Partners’ oil and gas development and production operations depends in part upon its ability to develop additional oil and gas reserves that are economically recoverable.
 
The rate of production from oil and natural gas properties declines as reserves are depleted. Without successful development activities, the reserves and revenues of the oil producing assets within Kinder Morgan Energy Partners’ CO2 business segment will decline. Kinder Morgan Energy Partners may not be able to develop or acquire additional reserves at an acceptable cost or have necessary financing for these activities in the future. Additionally, if Kinder Morgan Energy Partners does not realize production volumes greater than, or equal to, its hedged volumes, Kinder Morgan Energy Partners may suffer financial losses not offset by physical transactions.
 
Competition could ultimately lead to lower levels of profits and adversely impact our ability to recontract for expiring transportation capacity at favorable rates or maintain existing customers.
 
In the past, competitors to our interstate natural gas pipelines have constructed or expanded pipeline capacity into the areas served by our pipelines. To the extent that an excess of supply into these market areas is created and persists, our ability to recontract for expiring transportation capacity at favorable rates or to maintain existing customers could be impaired. In addition, our products pipelines compete against proprietary pipelines owned and operated by major oil companies, other independent products pipelines, trucking and marine transportation firms (for short-haul movements of products) and railcars. Throughput on our products pipelines may decline if the rates we charge become uncompetitive compared to alternatives.
 
Future business development of our products, crude oil and natural gas pipelines is dependent on the supply of and demand for those commodities.
 
Our pipelines depend on production of natural gas, oil and other products in the areas serviced by our pipelines. Without reserve additions, production will decline over time as reserves are depleted and production costs may rise. Producers may shut down production at lower product prices or higher production costs, especially where the existing cost of production exceeds other extraction methodologies, such as at the Alberta oil sands. Producers in areas serviced by us may not be successful in exploring for and developing additional reserves, and the gas plants and the pipelines may not be able to maintain existing volumes of throughput. Commodity prices and tax incentives may not remain at a level which encourages producers to explore for and develop additional reserves, produce existing marginal reserves or renew transportation contracts as they expire.
 
Changes in the business environment, such as a decline in crude oil or natural gas prices, an increase in production costs from higher feedstock prices, supply disruptions, or higher development costs, could result in a slowing of supply from the Alberta oil sands. In addition, changes in the regulatory environment or governmental policies may have an impact on the supply of crude oil. Each of these factors impact our customers shipping through our pipelines, which in turn could impact the
 

 
42
 
Item 1A.  Risk Factors. (continued)
Knight Form 10-K


prospects of new transportation contracts or renewals of existing contracts.
 
Throughput on our products pipelines may also decline as a result of changes in business conditions. Over the long term, business will depend, in part, on the level of demand for oil and natural gas in the geographic areas in which deliveries are made by pipelines and the ability and willingness of shippers having access or rights to utilize the pipelines to supply such demand. The implementation of new regulations or the modification of existing regulations affecting the oil and gas industry could reduce demand for natural gas and crude oil, increase our costs and may have a material adverse effect on our results of operations and financial condition. We cannot predict the impact of future economic conditions, fuel conservation measures, alternative fuel requirements, governmental regulation or technological advances in fuel economy and energy generation devices, all of which could reduce the demand for natural gas and oil.
 
We are subject to U.S. dollar/Canadian dollar exchange rate fluctuations.
 
As a result of the operations of the Kinder Morgan Canada—KMP segment, a portion of our assets, liabilities, revenues and expenses are denominated in Canadian dollars. We are a U.S. dollar reporting company. Fluctuations in the exchange rate between United States and Canadian dollars could expose us to reductions in the U.S. dollar value of our earnings and cash flows and a reduction in our stockholder’s equity under applicable accounting rules.
 
Terrorist attacks, or the threat of them, may adversely affect our business.
 
The U.S. government has issued public warnings that indicate that pipelines and other energy assets might be specific targets of terrorist organizations. These potential targets might include our pipeline systems or storage facilities. Our operations could become subject to increased governmental scrutiny that would require increased security measures. Recent federal legislation provides an insurance framework that should cause current insurers to continue to provide sabotage and terrorism coverage under standard property insurance policies. Nonetheless, there is no assurance that adequate sabotage and terrorism insurance will be available at rates we believe are reasonable in the near future. These developments may subject our operations to increased risks, as well as increased costs, and, depending on their ultimate magnitude, could have a material adverse effect on our business, results of operations and financial condition.
 
 
Some of our pipelines, terminals and other assets are located in areas that are susceptible to hurricanes and other natural disasters. These natural disasters could potentially damage or destroy our pipelines, terminals and other assets and disrupt the supply of the products we transport through our pipelines, which could have a material adverse effect our business, financial condition and results of operations.
 
There is the potential for a change of control of the general partner of Kinder Morgan Energy Partners if we default on debt.
 
We own all of the common equity of Kinder Morgan G.P., Inc., the general partner of Kinder Morgan Energy Partners. If we default on our debt, in exercising their rights as lenders, our lenders could acquire control of Kinder Morgan G.P., Inc. or otherwise influence Kinder Morgan G.P., Inc. through their control of us. While our operations provide cash independent of the dividends we receive from Kinder Morgan G.P., Inc., a change in control could materially affect our cash flow and earnings.
 
The tax treatment applied to Kinder Morgan Energy Partners depends on its status as a partnership for United States federal income tax purposes, as well as it not being subject to a material amount of entity-level taxation by individual states. If the IRS treats it as a corporation or if it becomes subject to a material amount of entity-level taxation for state tax purposes, it would substantially reduce the amount of cash available for distribution to its partners, including us.
 
The anticipated after-tax economic benefit of an investment in Kinder Morgan Energy Partners depends largely on it being treated as a partnership for United States federal income tax purposes. In order for it to be treated as a partnership for United States federal income tax purposes, current law requires that 90% or more of its gross income for every taxable year consist of “qualifying income,” as defined in Section 7704 of the Internal Revenue Code. Kinder Morgan Energy Partners may not meet this requirement or current law may change so as to cause, in either event, it to be treated as a corporation for United States federal income tax purposes or otherwise subject to United States federal income tax. Kinder Morgan Energy Partners has not requested, and does not plan to request, a ruling from the IRS on this or any other matter affecting it.
 
If Kinder Morgan Energy Partners were to be treated as a corporation for United States federal income tax purposes, it would pay United States federal income tax on its income at the corporate tax rate, which is currently a maximum of 35%, and would pay state income taxes at varying rates. Under current law, distributions to its partners would generally be taxed again as corporate distributions, and no income, gain, losses or deductions would flow through to its partners. Because a tax would be imposed on Kinder Morgan Energy Partners as a corporation, its cash available for distribution would be substantially
 

 
43
 
Item 1A.  Risk Factors. (continued)
Knight Form 10-K


reduced. Therefore, treatment of Kinder Morgan Energy Partners as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to its partners, likely causing a substantial reduction in the value of our interest in Kinder Morgan Energy Partners.
 
Current law or the business of Kinder Morgan Energy Partners may change so as to cause it to be treated as a corporation for United States federal income tax purposes or otherwise subject it to entity level taxation. Members of Congress are considering substantive changes to the existing United States federal income tax laws that affect certain publicly-traded partnerships. For example, United States federal income tax legislation has been proposed that would eliminate partnership tax treatment for certain publicly-traded partnerships. Although the currently proposed legislation would not appear to affect Kinder Morgan Energy Partners, L.P.’s tax treatment as a partnership, we are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any such changes could negatively impact the value of our interest in Kinder Morgan Energy Partners.
 
In addition, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. For example, Kinder Morgan Energy Partners is now subject to an entity-level tax on the portion of its total revenue that is generated in Texas. Imposition of such a tax on Kinder Morgan Energy Partners by Texas, or any other state, will reduce its cash available for distribution to its partners, including us.
 
The Kinder Morgan Energy Partners partnership agreement provides that if a law is enacted that subjects Kinder Morgan Energy Partners to taxation as a corporation or otherwise subjects it to entity-level taxation for United States federal income tax purposes, the minimum quarterly distribution and the target distribution levels will be adjusted to reflect the impact of that law on Kinder Morgan Energy Partners.
 
Kinder Morgan Energy Partners adopted certain valuation methodologies that may result in a shift of income, gain, loss and deduction between it and its unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.
 
When Kinder Morgan Energy Partners issues additional units or engages in certain other transactions, it determines the fair market value of its assets and allocates any unrealized gain or loss attributable to its assets to the capital accounts of its unitholders and us. This methodology may be viewed as understating the value of Kinder Morgan Energy Partners’ assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and us, which may be unfavorable to such unitholders. Moreover, under Kinder Morgan Energy Partners’ current valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to its tangible assets and a lesser portion allocated to its intangible assets. The IRS may challenge these valuation methods, or Kinder Morgan Energy Partners’ allocation of the Section 743(b) adjustment attributable to its tangible and intangible assets, and allocations of income, gain, loss and deduction between it and certain of its unitholders. A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to Kinder Morgan Energy Partners’ partners, including us. It also could affect the amount of gain from Kinder Morgan Energy Partners’ unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to its unitholders’ tax returns without the benefit of additional deductions.
 
Kinder Morgan Energy Partners’ treatment of a purchaser of common units as having the same tax benefits as the seller could be challenged, resulting in a reduction in value of the common units.
 
Because Kinder Morgan Energy Partners cannot match transferors and transferees of common units, it is required to maintain the uniformity of the economic and tax characteristics of these units in the hands of the purchasers and sellers of these units. It does so by adopting certain depreciation conventions that do not conform to all aspects of the United States Treasury regulations. A successful IRS challenge to these conventions could adversely affect the tax benefits to a unitholder of ownership of the common units and could have a negative impact on their value or result in audit adjustments to unitholders’ tax returns.
 
 
None.
 
 
See Note 21 of the accompanying Notes to Consolidated Financial Statements.
 
 
None.
 

 
44
 
 
Knight Form 10-K


 
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.  

Prior to the Going Private transaction, our common stock was listed for trading on the New York Stock Exchange under the symbol “KMI.” Dividends paid and the high and low sale prices per share, as reported on the New York Stock Exchange, of our common stock by quarter for the last two years are provided below.
 
 
Market Price Per Share1
 
2008
  
2007
 
Low
  
High
  
Low
  
High
Quarter Ended
              
March 31                                                     
n/a
  
n/a
  
$104.97
  
$107.02
June 30                                                     
n/a
  
n/a
  
$105.32
  
$108.14
September 30          
n/a
  
n/a
  
n/a
  
n/a
December 31              
n/a
  
n/a
  
n/a
  
n/a
  
 
Dividends Paid Per Share
 
2008
  
2007
Quarter Ended
      
March 31                                                     
n/a
  
$0.8750
June 30                                                     
n/a
  
$0.8750
September 30  
n/a
  
n/a
December 31 
n/a
  
n/a
__________
1
As a result of the Going Private transaction, our common stock ceased trading on May 30, 2007.
 
For information regarding our equity compensation plans, please refer to Part III, Item 12, included elsewhere in this report.
 
Selected Financial Data.

Five-Year Review
Knight Inc. and Subsidiaries
 
 
Successor Company
    
Predecessor Company
 
Year Ended
December 31,
  
Seven Months
Ended
December 31,
    
Five Months
Ended
May 31,
  
Year Ended December 31,
 
20081,2
  
20071,2
    
20072,3
  
20062,3
  
20053
  
2004
 
(In millions)
    
(In millions)
Operating Revenues
$
12,094.8
    
$
6,394.7
      
$
4,165.1
    
$
10,208.6
    
$
1,025.6
    
$
877.7
  
Gas Purchases and Other Costs of Sales
  
7,744.0
      
3,656.6
        
2,490.4
      
6,339.4
      
302.6
      
194.2
  
Other Operating Expenses4,5,6,7
  
6,822.9
      
1,695.3
        
1,469.9
      
2,124.0
      
341.7
      
342.5
  
Operating Income (Loss)
  
(2,472.1
)
    
1,042.8
        
204.8
      
1,745.2
      
381.3
      
341.0
  
Other Income and (Expenses)
  
(822.0
)
    
(566.9
)
      
(302.0
)
    
(858.9
)
    
470.0
      
365.2
  
Income (Loss) from Continuing Operations Before Income Taxes
  
(3,294.1
)
    
475.9
        
(97.2
)
    
886.3
      
851.3
      
706.2
  
Income Taxes
  
304.3
      
227.4
        
135.5
      
285.9
      
337.1
      
208.0
  
Income (Loss) from Continuing Operations
  
(3,598.4
)
    
248.5
        
(232.7
)
    
600.4
      
514.2
      
498.2
  
Income (Loss) from Discontinued Operations, Net of Tax8
  
(0.9
)
    
(1.5
)
      
298.6
      
(528.5
)
    
40.4
      
23.9
  
Net Income (Loss)
$
(3,599.3
)
  
$
247.0
      
$
65.9
    
$
71.9
    
$
554.6
    
$
522.1
  
  
                                                
Capital Expenditures9
$
2,545.3
    
$
1,287.0
      
$
652.8
    
$
1,375.6
    
$
134.1
    
$
103.2
  
__________
1
Includes significant impacts resulting from the Going Private transaction. See Note 1 of the accompanying Notes to Consolidated Financial Statements for additional information.
2
Due to our adoption of EITF No. 04-5, effective January 1, 2006 the accounts, balances and results of operations of Kinder Morgan Energy Partners are included in our financial statements and we no longer apply the equity method of accounting to our investments in Kinder Morgan Energy Partners. See Note 1 of the accompanying Notes to Consolidated Financial Statements.
3
Includes the results of Terasen Inc. subsequent to its November 30, 2005 acquisition by us. See Notes 10 and 11 of the accompanying Notes to Consolidated Financial Statements for information regarding Terasen.

 
45
 
Item 6.   Selected Financial Data  (continued)
Knight Form 10-K


4
Includes non-cash goodwill charges of $4,033.3 million in the year ended December 31, 2008.
5
Includes charges of $1.2 million, $6.5 million and $33.5 million in 2006, 2005 and 2004, respectively, to reduce the carrying value of certain power assets.
6
Includes an impairment charge of $377.1 million in the five months ended May 31, 2007 relating to Kinder Morgan Energy Partners’ acquisition of Trans Mountain pipeline from us on April 30, 2007. See Note 3 of the accompanying Notes to Consolidated Financial Statements.
8
Includes a charge of $650.5 million in 2006 to reduce the carrying value of Terasen Inc.; see Note 3 of the accompanying Notes to Consolidated Financial Statements.
9
Capital expenditures shown are for continuing operations only.
 
 
As of December 31,
 
Successor Company
    
Predecessor Company
 
2008
  
20071
    
20062
  
20053
  
2004
 
(In millions, except percentages)
    
(In millions, except percentages)
Total Assets
$
25,444.9
        
$
36,101.0
          
$
26,795.6
        
$
17,451.6
        
$
10,116.9
      
  
                                                            
Capitalization:
                                                            
Common Equity4
$
4,457.7
  
23
%
  
$
8,069.2
  
30
%
    
$
3,657.5
  
20
%
  
$
4,051.4
  
34
%
  
$
2,919.5
  
45
%
Deferrable Interest Debentures
  
35.7
  
-
      
283.1
  
1
%
      
283.6
  
2
%
    
283.6
  
2
%
    
283.6
  
4
%
Capital Securities
  
-
  
-
      
-
  
-
        
106.9
  
1
%
    
107.2
  
1
%
    
-
  
-
  
Minority Interests
  
4,072.6
  
21
%
    
3,314.0
  
13
%
      
3,095.5
  
17
%
    
1,247.3
  
10
%
    
1,105.4
  
17
%
Outstanding Notes and Debentures5
  
11,120.1
  
56
%
    
14,814.6
  
56
%
      
10,623.9
  
60
%
    
6,286.8
  
53
%
    
2,258.0
  
34
%
Total Capitalization
$
19,686.1
  
100
%
  
$
26,480.9
  
100
%
    
$
17,767.4
  
100
%
  
$
11,976.3
  
100
%
  
$
6,566.5
  
100
%
__________
1
Includes significant impacts resulting from the Going Private transaction. See Note 1 of the accompanying Notes to Consolidated Financial Statements for additional information.
2
Due to our adoption of EITF No. 04-5, effective January 1, 2006 the accounts, balances and results of operations of Kinder Morgan Energy Partners are included in our financial statements and we no longer apply the equity method of accounting to our investments in Kinder Morgan Energy Partners.
3
Reflects the acquisition of Terasen Inc. on November 30, 2005. See Notes 10 and 11 of the accompanying Notes to Consolidated Financial Statements for information regarding this acquisition.
4
Excluding Accumulated Other Comprehensive Loss balances of $53.4 million, $247.7 million, $135.9 million, $127.0 million, and $54.7 million as of December 31, 2008, 2007, 2006, 2005, and 2004, respectively.
5
Excluding the value of interest rate swaps and short-term debt. See Note 14 of the accompanying Notes to Consolidated Financial Statements.

 

 
46
 
Knight Form 10-K


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

 
The following discussion should be read in conjunction with the accompanying Consolidated Financial Statements and related Notes.
 
We are an energy infrastructure provider through our direct ownership and operation of energy related assets, and through our ownership interests in and operation of Kinder Morgan Energy Partners. Our strategy and focus are on ownership of fee-based energy-related assets which are core to the energy infrastructure of North America and serve growing markets. These assets tend to have relatively stable cash flows while presenting us with opportunities to expand our facilities to serve additional customers and nearby markets. We evaluate the performance of our investment in these assets using, among other measures, segment earnings before depreciation, depletion and amortization.
 
Our principal business segments are:
 
 
·
Natural Gas Pipeline Company of America LLC—which consists of our 20% interest in NGPL PipeCo LLC, the owner of Natural Gas Pipeline Company of America and certain affiliates, collectively referred to as Natural Gas Pipeline Company of America or NGPL, a major interstate natural gas pipeline and storage system which we operate;
 
·
Power—which consists of two natural gas-fired electric generation facilities;
 
·
Products Pipelines–KMP—which consists of approximately 8,300 miles of refined petroleum products pipelines that deliver gasoline, diesel fuel, jet fuel and natural gas liquids to various markets; plus approximately 60 associated product terminals and petroleum pipeline transmix processing facilities serving customers across the United States;
 
·
Natural Gas Pipelines–KMP—which consists of over 14,300 miles of natural gas transmission pipelines and gathering lines, plus natural gas storage, treating and processing facilities, through which natural gas is gathered, transported, stored, treated, processed and sold;
 
·
CO2–KMP—which produces, markets and transports, through approximately 1,300 miles of pipelines, carbon dioxide to oil fields that use carbon dioxide to increase production of oil; owns interests in and/or operates ten oil fields in West Texas; and owns and operates a 450-mile crude oil pipeline system in West Texas;
 
·
Terminals–KMP—which consists of approximately 110 owned or operated liquids and bulk terminal facilities and more than 45 rail transloading and materials handling facilities located throughout the United States and portions of Canada, which together transload, store and deliver a wide variety of bulk, petroleum, petrochemical and other liquids products for customers across the United States and Canada; and
 
·
Kinder Morgan Canada–KMP—which consists of over 700 miles of common carrier pipelines, originating at Edmonton, Alberta, for the transportation of crude oil and refined petroleum to the interior of British Columbia and to marketing terminals and refineries located in the greater Vancouver, British Columbia area and Puget Sound in Washington state; plus five associated product terminals. This segment also includes a one-third interest in an approximately 1,700-mile integrated crude oil pipeline and a 25-mile aviation turbine fuel pipeline serving the Vancouver International Airport.
 
As an energy infrastructure owner and operator in multiple facets of the United States’ and Canada’s various energy businesses and markets, we examine a number of variables and factors on a routine basis to evaluate our current performance and our prospects for the future. The profitability of our products pipeline transportation business is generally driven by the utilization of our facilities in relation to their capacity, as well as the prices we receive for our services. Transportation volume levels are primarily driven by the demand for the petroleum products being shipped or stored. The prices for shipping are generally based on regulated tariffs that are adjusted annually based on changes in the Producer Price Index. Because of the overall effect of utilization on our products pipeline transportation business, we seek to own refined products pipelines located in or that transport to stable or growing markets and population centers.
 
With respect to our interstate natural gas pipelines and related storage facilities, the revenues from these assets tend to be received under contracts with terms that are fixed for various periods of time. To the extent practicable and economically feasible in light of our strategic plans and other factors, we generally attempt to mitigate risk of reduced volumes and prices by negotiating contracts with longer terms, with higher per-unit pricing and for a greater percentage of our available capacity. However, changes, either positive or negative, in actual quantities transported on our interstate natural gas pipelines may not accurately measure or predict associated changes in profitability because many of the underlying transportation contracts, sometimes referred to as take-or-pay contracts, specify that we receive the majority of our fee for making the capacity available, whether or not the customer actually chooses to utilize the capacity.
 
The CO2–KMP business segment sales and transportation business, like the natural gas pipelines business, generally has take-or-pay contracts, although the contracts in the CO2–KMP business segment typically have minimum volume requirements. In the long term, the success in this business is driven by the demand for CO2. However, short-term changes in the demand for 
 
 
 
47
 
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)
Knight Form 10-K


CO2 typically do not have a significant impact on us due to the required minimum volumes under many of our contracts. In the oil and gas producing activities within the CO2–KMP business segment, we monitor the amount of capital we expend in relation to the amount of production that is added or the amount of declines in production that are postponed. In that regard, our production during any period and the reserves that we add during that period are important measures. In addition, the revenues we receive from our crude oil, natural gas liquids and CO2 sales are affected by the prices we realize from the sale of these products. Over the long term, we will tend to receive prices that are dictated by the demand and overall market price for these products. In the shorter term, however, published market prices are likely not indicative of the revenues we will receive due to our risk management, or hedging, program in which the prices to be realized for certain of our future sales quantities are fixed, capped or bracketed through the use of financial derivatives, particularly for oil.
 
As with our products pipeline transportation businesses, the profitability of our terminals businesses is generally driven by the utilization of our terminals facilities in relation to their capacity, as well as the prices we receive for our services, which in turn are driven by the demand for the products being shipped or stored. The extent to which changes in these variables affect this business in the near term is a function of the length of the underlying service contracts, the extent to which revenues under the contracts are a function of the amount of product stored or transported and the extent to which such contracts expire during any given period of time. To the extent practicable and economically feasible in light of our strategic plans and other factors, we generally attempt to mitigate the risk of reduced volumes and pricing by negotiating contracts with longer terms, with higher per-unit pricing and for a greater percentage of our available capacity. In addition, weather-related factors such as hurricanes, floods and droughts may impact our facilities and access to them and, thus, the profitability of certain terminals for limited periods of time or, in relatively rare cases of severe damage to facilities, for longer periods.
 
In our discussions of the operating results of individual businesses that follow, we generally identify the important fluctuations between periods that are attributable to acquisitions and dispositions separately from those that are attributable to businesses owned in both periods. Principally through Kinder Morgan Energy Partners, we have a history of making accretive acquisitions and economically advantageous expansions of existing businesses. Our ability to increase earnings and Kinder Morgan Energy Partners’ ability to increase distributions to us and other investors will, to some extent, be a function of Kinder Morgan Energy Partners’ success in acquisitions and expansions. Kinder Morgan Energy Partners continues to have opportunities for expansion of its facilities in many markets and expects to continue to have such opportunities in the future, although the level of such opportunities is difficult to predict.
 
Kinder Morgan Energy Partners’ ability to make accretive acquisitions is a function of the availability of suitable acquisition candidates and, to some extent, its ability to raise necessary capital to fund such acquisitions, factors over which it has limited or no control. Thus, it has no way to determine the extent to which it will be able to identify accretive acquisition candidates, or the number or size of such candidates, in the future, or whether it will complete the acquisition of any such candidates.
 
On November 24, 2008, Kinder Morgan Energy Partners announced that it expected to declare 2009 cash distributions of $4.20 per unit, a 4.5% increase over its 2008 cash distributions of $4.02 per unit. The expected growth in 2009 distributions assumes an average West Texas Intermediate crude oil price of $68 per barrel in 2009 with some minor adjustments for timing, quality and location differences. Based on actual prices received through the first seven weeks of 2009 and the forward curve, adjusted for the same factors as the budget, the average realized price for 2009 is currently projected to be $49 per barrel. Although the majority of the cash generated by Kinder Morgan Energy Partners’ assets is fee based and is not sensitive to commodity prices, the CO2–KMP business segment is exposed to commodity price risk related to the price volatility of crude oil and natural gas liquids. Kinder Morgan Energy Partners hedges the majority of its crude oil production, but does have exposure to unhedged volumes, the majority of which are natural gas liquids volumes. For 2009, Kinder Morgan Energy Partners expects that every $1 change in the average WTI crude oil price per barrel will impact its CO2–KMP segment’s cash flows by approximately $6 million (or approximately 0.2% of the combined Kinder Morgan Energy Partners business segments’ anticipated distributable cash flow). This sensitivity to the average WTI price is very similar to what was experienced in 2008. Kinder Morgan Energy Partners’ 2009 cash distribution expectations do not take into account any capital costs associated with financing any payment it may be required to make of reparations sought by shippers on its Pacific operations’ interstate pipelines.
 
In light of the above and other economic uncertainties we are taking cost reduction measures for 2009. We are reducing our travel costs and compensation costs, decreasing the use of outside consultants, reducing overtime where possible and reviewing capital and operating budgets to identify the costs we can reduce without compromising operating efficiency, maintenance or safety.
 
In addition to any uncertainties described in this discussion and analysis, we are subject to a variety of risks that could have a material adverse effect on our business, financial condition, cash flows and results of operations. See “Risk Factors” in Item 1A.
 

 
48
 
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)
Knight Form 10-K


During 2006 and 2007, we reached agreements to sell certain businesses and assets in which we no longer have any continuing interest, including Terasen Gas, Corridor, the North System and our Kinder Morgan Retail segment. Accordingly, the activities and assets related to these sales are presented as discontinued items in the accompanying Consolidated Financial Statements. As discussed following, many of our operations are regulated by various federal and state regulatory bodies.
 
In February 2007, we entered into a definitive agreement to sell our Canada-based retail natural gas distribution operations to Fortis Inc., for approximately C$3.7 billion including cash and assumed debt, and as a result of a redetermination of fair value in light of this proposed sale, we recorded an estimated goodwill impairment charge of approximately $650.5 million in 2006. This sale was completed in May 2007; see Note 3 of the accompanying Notes to Consolidated Financial Statements. Prior to its sale, we referred to these operations principally as the Terasen Gas business segment.
 
In March 2007, we entered into an agreement to sell the Corridor Pipeline System to Inter Pipeline Fund, a Canada-based company, for approximately C$760 million, including debt. This sale was completed in June 2007. Inter Pipeline Fund also assumed all of the debt associated with the expansion taking place on Corridor at the time of the sale. Prior to its sale, the Corridor Pipeline System was included in the business segment named Kinder Morgan Canada. Also in March 2007, we completed the sale of our U.S. retail natural gas distribution and related operations to GE Energy Financial Services, a subsidiary of General Electric Company and Alinda Investments LLC for $710 million and an adjustment for working capital. Prior to their sale, we referred to these operations as the Kinder Morgan Retail business segment. On October 5, 2007, Kinder Morgan Energy Partners announced that it had completed the sale of the North System and also its 50% ownership interest in the Heartland Pipeline Company to ONEOK Partners, L.P. for approximately $295.7 million in cash. Prior to its sale, the North System and the equity investment in the Heartland Pipeline were reported in the Products Pipelines–KMP business segment. In February 2008, we sold an 80% ownership interest in our NGPL business segment at a price equivalent to a total enterprise value of approximately $5.9 billion; see Note 10 of the accompanying Notes to Consolidated Financial Statements. In accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, the financial results of the Terasen Gas, Corridor, Kinder Morgan Retail operations, the North System operations and the equity investment in the Heartland Pipeline Company have been reclassified to discontinued operations for all periods presented, and 100% of the assets and liabilities associated with the NGPL business segment were reclassified to assets and liabilities held for sale, and the non-current assets and long-term debt held for sale balances were then reduced by our 20% ownership interest in the NGPL business segment, which was recorded as an investment as of December 31, 2008 and 2007, respectively.
 
On April 30, 2007, we sold the Trans Mountain pipeline system to Kinder Morgan Energy Partners for approximately $550 million. The transaction was approved by the independent members of our board of directors and those of Kinder Morgan Management following the receipt, by each board, of separate fairness opinions from different investment banks. The Trans Mountain pipeline system transports crude oil and refined products from Edmonton, Alberta, Canada to marketing terminals and refineries in British Columbia and the state of Washington. An impairment of the Trans Mountain pipeline system was recorded in the first quarter of 2007; see Note 3 of the accompanying Notes to Consolidated Financial Statements.
 
On November 20, 2007, we entered into a definitive agreement to sell our interests in three natural gas-fired power plants in Colorado to Bear Stearns. The closing of the sale occurred on January 25, 2008, effective January 1, 2008, and we received net proceeds of $63.1 million.
 
On August 28, 2008, we sold our one-third interest in the net assets of the Express pipeline system and the net assets of the Jet Fuel pipeline to Kinder Morgan Energy Partners for approximately 2 million Kinder Morgan Energy Partners’ common units worth approximately $116 million. The Express pipeline system transports crude oil from Alberta to Illinois. The Jet Fuel pipeline serves the Vancouver, British Columbia airport. Prior to the sales, we reported the results of the Trans Mountain pipeline system in the Trans Mountain–KMP segment, the equity investment in the Express pipeline system in the Express segment and the results of Jet Fuel were included in the “Other” caption in the Consolidated Financial Results table in the Management’s Discussion and Analysis of Financial Condition and Results of Operations. In order to present the prior periods consistent with the segments as now presented in 2008, these assets and their results are included in the Kinder Morgan Canada–KMP segment for all periods presented.
 
Notwithstanding the consolidation of Kinder Morgan Energy Partners and its subsidiaries into our financial statements, we are not liable for, and our assets are not available to satisfy, the obligations of Kinder Morgan Energy Partners and/or its subsidiaries and vice versa. Responsibility for payments of obligations reflected in our or Kinder Morgan Energy Partners’ financial statements is a legal determination based on the entity that incurs the liability.
 
 
Our discussion and analysis of financial condition and results of operations are based on our consolidated financial statements, prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and contained within this report. Certain amounts included in or affecting our consolidated financial statements and related disclosure must be estimated, requiring us to make certain assumptions with respect to values or conditions that cannot be
 

 
49
 
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)
Knight Form 10-K


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. Any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. In preparing our consolidated financial statements and related disclosures, we must use estimates in determining the economic useful lives of our assets, the fair values used to determine possible impairment charges, the effective income tax rate to apply to our pre-tax income, deferred income tax balances, obligations under our employee benefit plans, provisions for uncollectible accounts receivable, 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, which policies are discussed following. Our policies and estimation methodologies are generally the same in both the predecessor and successor company periods, except where explicitly discussed.
 
Environmental Matters
 
With respect to our environmental exposure, we utilize both internal staff and external experts to assist us in identifying environmental issues and in estimating the costs and timing of remediation efforts. We expense or capitalize, as appropriate, environmental expenditures that relate to current operations, and we record environmental liabilities when environmental assessments and/or remedial efforts are probable and we can reasonably estimate the costs. We do not discount environmental liabilities to a net present value, and we recognize receivables for anticipated associated insurance recoveries when such recoveries are deemed to be probable.
 
The recording of environmental accruals often coincides with the completion of a feasibility study or the commitment to a formal plan of action, but generally, we recognize and/or adjust our environmental liabilities following routine reviews of potential environmental issues and claims that could impact our assets or operations. These adjustments may result in increases in environmental expenses and primarily result from quarterly reviews of potential environmental issues and resulting changes in environmental liability estimates. The environmental liability adjustments are recorded pursuant to management’s requirement to recognize environmental liabilities wherever the associated environmental issue is likely to occur and where the amount of the liability can be reasonably estimated. In making these liability estimations, we consider the effect of environmental compliance, pending legal actions against us, and potential third-party liability claims. For more information on our environmental disclosures, see Note 21 of the accompanying Notes to Consolidated Financial Statements.
 
Legal Matters
 
We are subject to litigation and regulatory proceedings as a result of our business operations and transactions. We utilize both internal and external counsel in evaluating our potential exposure to adverse outcomes from orders, judgments or settlements. To the extent that actual outcomes differ from our estimates, or additional facts and circumstances cause us to revise our estimates, our earnings will be affected. In general, we expense legal costs as incurred. When we identify specific litigation that is expected to continue for a significant period of time and require substantial expenditures, we identify a range of possible costs expected to be required to litigate the matter to a conclusion or reach an acceptable settlement. If no amount within this range is a better estimate than any other amount, we record a liability equal to the low end of the range. Any such liability recorded is revised as better information becomes available.
 
As of December 31, 2008 and December 31, 2007, our most significant ongoing litigation proceedings involve Kinder Morgan Energy Partners’ West Coast Products Pipelines operations. Tariffs charged by certain of these pipeline systems are subject to certain proceedings at the Federal Energy Regulatory Commission (“FERC”) involving shippers’ complaints regarding the interstate rates, as well as practices and the jurisdictional nature of certain facilities and services. Generally, the interstate rates on Kinder Morgan Energy Partners’ West Coast Products Pipelines pipeline systems are “grandfathered” under the Energy Policy Act of 1992 unless “substantially changed circumstances” are found to exist. To the extent “substantially changed circumstances” are found to exist, the West Coast Products Pipelines pipeline systems may be subject to substantial exposure under these FERC complaints and could, therefore, owe reparations and/or refunds to complainants as mandated by the FERC or the United States’ judicial system. For more information on the West Coast Products Pipelines pipeline systems’ regulatory proceedings, see Note 20 of the accompanying Notes to Consolidated Financial Statements.
 
Intangible Assets
 
Intangible assets are those assets which provide future economic benefit but have no physical substance. We account for our intangible assets according to the provisions of SFAS No. 141, Business Combinations and SFAS No. 142, Goodwill and Other Intangible Assets. These accounting pronouncements introduced the concept of indefinite life intangible assets and provided that all identifiable intangible assets having indefinite useful economic lives, including goodwill, will not be subject to periodic amortization. Such assets are not to be amortized unless and until their lives are determined to be finite. Instead,
 

 
50
 
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)
Knight Form 10-K


the carrying amount of a recognized intangible asset with an indefinite useful life must be tested for impairment annually or on an interim basis if events or circumstances indicate that the fair value of the asset has decreased below its carrying value. For the Predecessor Company, an impairment measurement test date of January 1 of each year was selected; for the Successor Company, we use an annual impairment measurement date of May 31.
 
As of December 31, 2008 and December 31, 2007, our goodwill was $4,741.1 million and $8,174.0 million, respectively. Included in these goodwill balances is $250.1 million related to the Trans Mountain pipeline, which we sold to Kinder Morgan Energy Partners on April 30, 2007. This sale transaction caused us to reconsider the fair value of the Trans Mountain pipeline system in relation to its carrying value, and to make a determination as to whether the associated goodwill was impaired. As a result of our analysis, we recorded a goodwill impairment charge of $377.1 million in the first quarter of 2007.
 
Our remaining intangible assets, excluding goodwill, include customer relationships, contracts and agreements, technology-based assets and lease value. These intangible assets have definite lives, are being amortized on a straight-line basis over their estimated useful lives, and are reported separately as “Other Intangibles, Net” in the accompanying Consolidated Balance Sheets. As of December 31, 2008 and December 31, 2007, these intangibles totaled $251.5 million and $321.1 million, respectively.
 
In conjunction with our annual impairment test of the carrying value of goodwill, performed as of May 31, 2008, we determined that the fair value of certain reporting units that are part of our investment in Kinder Morgan Energy Partners were less than the carrying values. The fair value of each reporting unit was determined from the present value of the expected future cash flows from the applicable reporting unit (inclusive of a terminal value calculated using a market multiple for the individual assets). The implied fair value of goodwill within each reporting unit was then compared to the carrying value of goodwill of each such unit, resulting in the following goodwill impairments by reporting unit: Products Pipelines–KMP (excluding associated terminals) $1.20 billion, Products Pipelines Terminals–KMP (separate from Products Pipelines–KMP for goodwill impairment purposes)—$70 million, Natural Gas Pipelines–KMP—$2.09 billion, and Terminals–KMP $677 million, for a total impairment of $4.03 billion. The goodwill impairment is a non-cash charge and does not have any impact on our cash flow. While the fair value of the CO2–KMP segment exceeded its carrying value as of the date of our goodwill impairment test, decreases in the market value of crude oil led us to reconsider this analysis as of December 31, 2008 and at that time our analysis also determined that the fair value exceeded the carrying value. If the market price of crude oil continues to decline, we may need to record non-cash goodwill impairment charges on this reporting unit in future periods.
 
Estimated Net Recoverable Quantities of Oil and Gas
 
We use the successful efforts method of accounting for Kinder Morgan Energy Partners’ oil and gas producing activities. The successful efforts method inherently relies on the estimation of proved reserves, both developed and undeveloped. The existence and the estimated amount of proved reserves affect, among other things, whether certain costs are capitalized or expensed, the amount and timing of costs depleted or amortized into income and the presentation of supplemental information on oil and gas producing activities. The expected future cash flows to be generated by oil and gas producing properties used in testing for impairment of such properties also rely in part on estimates of net recoverable quantities of oil and gas. Proved reserves are the estimated quantities of oil and gas that geologic and engineering data demonstrates with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Estimates of proved reserves may change, either positively or negatively, as additional information becomes available and as contractual, economic and political conditions change.
 
Hedging Activities
 
We engage in a hedging program that utilizes derivative contracts to mitigate (offset in whole or in part) our exposure to fluctuations in energy commodity prices, fluctuations in currency exchange rates and to balance our exposure to fixed and variable interest rates, and we believe that these hedges are generally effective in realizing these objectives. However, the accounting standards regarding hedge accounting are complex, and even when we engage in hedging transactions that are effective economically, these transactions may not be considered effective for accounting purposes. According to the provisions of current accounting standards, to be considered effective, changes in the value of a derivative contract or its resulting cash flows must substantially offset changes in the value or cash flows of the item being hedged. A perfectly effective hedge is one in which changes in the value of the derivative contract exactly offset changes in the value of the hedged item or expected cash flow of the future transactions in reporting periods covered by the derivative contract. The ineffective portion of the gain or loss and any component excluded from the computation of the effectiveness of the derivative contract must be reported in earnings immediately; accordingly, our financial statements may reflect some volatility due to these hedges.
 

 
51
 
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)
Knight Form 10-K


In addition, it is not always possible for us to engage in a hedging transaction that completely mitigates our exposure to unfavorable changes in commodity prices. For example, when we purchase a commodity at one location and sell it at another, we may be unable to hedge completely our exposure to a differential in the price of the product between these two locations. Even when we cannot enter into a completely effective hedge, we often enter into hedges that are not completely effective in those instances where we believe to do so would be better than not hedging at all, but due to the fact that the part of the hedging transaction that is not effective in offsetting undesired changes in commodity prices (the ineffective portion) is required to be recognized currently in earnings, our financial statements may reflect a gain or loss arising from an exposure to commodity prices for which we are unable to enter into a completely effective hedge.
 
Employee Benefit Plans
 
With respect to the amount of income or expense we recognize in association with our pension and retiree medical plans, we must make a number of assumptions with respect to both future financial conditions (for example, medical costs, returns on fund assets and market interest rates) as well as future actions by plan participants (for example, when they will retire and how long they will live after retirement). Most of these assumptions have relatively minor impacts on the overall accounting recognition given to these plans, but two assumptions in particular, the discount rate and the assumed long-term rate of return on fund assets, can have significant effects on the amount of expense recorded and liability recognized. We review historical trends, future expectations, current and projected market conditions, the general interest rate environment and benefit payment obligations to select these assumptions. The discount rate represents the market rate for a high quality corporate bond. The selection of these assumptions is further discussed in Note 16 of the accompanying Notes to Consolidated Financial Statements. While we believe our choices for these assumptions are appropriate in the circumstances, other assumptions could also be reasonably applied and, therefore, we note that, at our current level of pension and retiree medical funding, a change of 1% in the long-term return assumption would increase (decrease) our annual retiree medical expense by approximately $0.5 million ($0.5 million) and would increase (decrease) our annual pension expense by $1.8 million ($1.8 million) in comparison to that recorded in 2008. Similarly, a 1% change in the discount rate would increase (decrease) our accumulated postretirement benefit obligation by $6.4 million ($5.9 million) and would increase (decrease) our projected pension benefit obligation by $29.3 million ($26.1 million) compared to those balances as of December 31, 2008.
 
Income Taxes
 
We record a valuation allowance to reduce our deferred tax assets to an amount that is more likely than not to be realized. While we have considered estimated future taxable income and prudent and feasible tax planning strategies in determining the amount of our valuation allowance, any change in the amount that we expect to ultimately realize will be included in income in the period in which such a determination is reached. In addition, we do business in a number of states with differing laws concerning how income subject to each state’s tax structure is measured and at what effective rate such income is taxed. Therefore, we must make estimates of how our income will be apportioned among the various states in order to arrive at an overall effective tax rate. Changes in our effective rate, including any effect on previously recorded deferred taxes, are recorded in the period in which the need for such change is identified.
 
 
The Going Private transaction was accounted for as a purchase business combination and, as a result of the application of the Securities and Exchange Commission’s “push-down” accounting requirements, this transaction has resulted in our adoption of a new basis of accounting for our assets and liabilities. Accordingly, our assets and liabilities have been recorded at their estimated fair values as of the date of the completion of the Going Private transaction, with the excess of the purchase price over these combined fair values recorded as goodwill.
 
Therefore, in the accompanying financial information, transactions and balances prior to the closing of the Going Private transaction (the amounts labeled “Predecessor Company”) reflect the historical basis of accounting for our assets and liabilities, while the amounts subsequent to the closing (the amounts labeled “Successor Company”) reflect the push-down of the investors’ new accounting basis to our financial statements. While the Going Private transaction closed on May 30, 2007, for convenience, the Predecessor Company is assumed to end on May 31, 2007 and the Successor Company is assumed to begin on June 1, 2007. The results for the two-day period, from May 30 to May 31, 2007, are not material to any of the periods presented. Additional information concerning the impact of the Going Private transaction on the accompanying financial information is contained under “Consolidated Financial Results” following.
 
Our adoption of a new basis of accounting for our assets and liabilities as a result of the Going Private transaction, the sale of our retail natural gas distribution and related operations, our Corridor operations, the North System, our 80% interest in NGPL PipeCo LLC (“PipeCo”), the goodwill impairments described above, and other acquisitions and divestitures (including the transfer of certain assets to Kinder Morgan Energy Partners), among other factors, affect comparisons of our financial position and results of operations between certain periods.
 

 
52
 
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)
Knight Form 10-K


 
The following discussion provides an analysis of material events that affected our operating results for the year ended December 31, 2008 (successor basis), seven months ended December 31, 2007 (successor basis) and five months ended May 31, 2007 (predecessor basis) and year ended December 31, 2006 (predecessor basis).
 
 
Successor Company
    
Predecessor Company
 
Year Ended
December 31,
2008
  
Seven Months
Ended
December 31,
2007
    
Five Months
Ended May 31,
2007
  
Year Ended
December 31,
2006
 
(In millions)
    
(In millions)
Segment Earnings (Loss) before Depreciation, Depletion and Amortization of Excess Cost of Equity Investments1
                                
NGPL2
$
129.8
    
$
422.8
      
$
267.4
    
$
603.5
  
Power
  
5.7
      
13.4
        
8.9
      
23.2
  
Products Pipelines–KMP3,8
  
(722.0
)
    
162.5
        
224.4
      
467.9
  
Natural Gas Pipelines–KMP4,8
  
(1,344.3
)
    
373.3
        
228.5
      
574.8
  
CO2–KMP8
  
896.1
      
433.0
        
210.0
      
488.2
  
Terminals–KMP5,8
  
(156.5
)
    
243.7
        
172.3
      
408.1
  
Kinder Morgan Canada–KMP6
  
152.0
      
58.8
        
(332.0
)
    
95.1
  
Segment Earnings (Loss) before Depreciation, Depletion and Amortization of Excess Cost of Equity Investments
  
(1,039.2
)
    
1,707.5
        
779.5
      
2,660.8
  
Depreciation, Depletion and Amortization Expense
  
(918.4
)
    
(472.3
)
      
(261.0
)
    
(531.4
)
Amortization of Excess Cost of Equity Investments
  
(5.7
)
    
(3.4
)
      
(2.4
)
    
(5.6
)
Other Operating Income (Loss)
  
39.0
      
(0.3
)
      
2.9
      
6.8
  
General and Administrative Expenses
  
(352.5
)
    
(175.6
)
      
(283.6
)
    
(305.1
)
Interest and Other, Net
  
(1,019.7
)
    
(624.0
)
      
(348.2
)
    
(968.2
)
Income (Loss) From Continuing Operations Before Income Taxes1
  
(3,296.5
)
    
431.9
        
(112.8
)
    
857.3
  
Income Taxes1
  
(301.9
)
    
(183.4
)
      
(119.9
)
    
(256.9
)
Income (Loss) From Continuing Operations
  
(3,598.4
)
    
248.5
        
(232.7
)
    
600.4
  
Income (Loss) From Discontinued Operations, Net of Tax7
  
(0.9
)
    
(1.5
)
      
298.6
      
(528.5
)
Net Income (Loss)
$
(3,599.3
)
  
$
247.0
      
$
65.9
    
$
71.9
  
__________
1
Kinder Morgan Energy Partners’ income taxes expenses for the year ended December 31, 2008, seven months ended September 30, 2007, five months ended May 31, 2007 and year ended December 31, 2006 were $2.4 million, $44.0 million, $15.6 million and $29.0 million, respectively, and are included in segment earnings.
2
Effective February 15, 2008, we sold an 80% ownership interest in NGPL PipeCo LLC. As a result of the sale, beginning February 15, 2008, we account for our 20% ownership interest in NGPL PipeCo LLC as an equity method investment.
3
2008 amount includes a non-cash goodwill impairment charge of $1,266.5 million.
4
2008 amount includes a non-cash goodwill impairment charge of $2,090.2 million.
5
2008 amount includes a non-cash goodwill impairment charge of $676.6 million.
6
Includes earnings of the Trans Mountain pipeline system, Kinder Morgan Energy Partners’ interest in the Express pipeline system and the Jet Fuel pipeline system and a non-cash goodwill impairment charge of $377.1 million for the five months ended May 31, 2007.
7
2006 includes a $650.5 million goodwill impairment associated with Terasen (see Note 3 of the accompanying Notes to Consolidated Financial Statements).
8
2008 amounts include a total of $18.3 million of expense associated with hurricanes Hanna, Gustav and Ike and three terminal fires among the Terminals–KMP, Products Pipelines–KMP, Natural Gas Pipelines–KMP and CO2–KMP business segments.
 
Year Ended December 31, 2008
 
The net loss primarily resulted from a $4.03 billion non-cash goodwill impairment charge that was recorded in the second quarter of 2008 (see Note 3 of the accompanying Notes to Consolidated Financial Statements). Other items negatively affecting results for the year ended December 31, 2008 include (i) reduced earning contributions from NGPL and Power as portions of these segments were sold in 2008, (ii) depreciation, depletion and amortization (“DD&A”) expense associated with expansion capital expenditures, (iii) general and administrative costs that included labor costs and associated costs for new hires during this period to support Kinder Morgan Energy Partners’ growing operations, (iv) $18.3 million of incremental expenses associated with hurricanes Hanna, Gustav and Ike and fires at three separate terminal locations and (v) lower crude oil, natural gas liquids and natural gas prices in the fourth quarter of 2008.
 

 
53
 
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)
Knight Form 10-K


The net loss was partially offset by (i) contributions from Rockies Express-West, which began service in January 2008 and reached full operations in May 2008, and increasing margins in the Texas Intrastate pipelines, (ii) favorable interest expense due to the February 2008 sale of an 80% ownership interest in NGPL PipeCo LLC for approximately $5.9 billion, with the proceeds from the sale used to pay down debt, (iii) strong CO2 sales and transport volumes in the CO2–KMP segment, as well as increases of the average crude oil sale prices, (iv) the completion of expansion projects at existing facilities and recent acquisitions within the Terminals–KMP segment and (v) the completion of the pump station expansion in April 2007 and Anchor Loop expansion, which was placed in service in April 2008 (partially) and October 2008 (fully) within Kinder Morgan Canada–KMP.
 
Seven Months Ended December 31, 2007
 
Net income for the period was driven by solid contributions from CO2–KMP, NGPL, Natural Gas Pipelines–KMP and Products Pipelines–KMP, which accounted for 25.4%, 24.7%, 21.9% and 9.5%, respectively, or 81.5% collectively, of segment earnings before DD&A. CO2–KMP was driven almost equally by our sales and transport and oil and gas producing activities. The Texas Intrastate Natural Gas Pipelines Group accounted for over 50% of the Natural Gas Pipelines–KMP performance and the West Coast Products Pipelines accounted for approximately 50% of the Product Pipelines–KMP segment earnings. NGPL contributed earnings of $422.8 million with incremental earnings coming from the re-contracting of transportation and storage services at higher rates, increased contract volumes, and recent transportation and storage expansions.
 
Net income was adversely impacted by (i) interest expenses related to the $4.8 billion of incremental debt resulting from the Going Private transaction (see discussion below on the impact of the purchase method of accounting on segment earnings) and (ii) DD&A expense associated with expansion capital expenditures.
 
Five Months Ended May 31, 2007
 
Net income was driven by solid performance from NGPL as well as all Kinder Morgan Energy Partners segments except Kinder Morgan Canada–KMP, as discussed below. NGPL contributed $267 million while Products Pipelines–KMP, Natural Gas Pipelines–KMP and CO2–KMP each contributed over $200 million.
 
Offsetting these positive factors were (i) a $377.1 million goodwill impairment charge associated with the Trans Mountain Pipeline (see Note 3 of the accompanying Notes to Consolidated Financial Statements) and (ii) $141.0 million in additional general and administrative expense associated with the Going Private transaction.
 
Year Ended December 31, 2006
 
Net income for the year ended December 31, 2006 was driven by solid contributions from NGPL, Natural Gas Pipelines–KMP, CO2–KMP and Products Pipelines–KMP, which accounted for 22.7%, 21.6%, 18.4% and 17.6%, respectively, or 80.3% collectively, of segment earnings before DD&A. NGPL was driven by successful re-contracting of transportation and storage services and increased gas sales prices. The Texas Intrastate Natural Gas Pipeline Group and the western interstate natural gas pipelines group accounted for 53.1% and 35.0%, respectively, of the Natural Gas Pipelines–KMP earnings. The TransColorado pipeline system improvements completed in 2005 contributed to the western interstate natural gas pipelines group 2006 earnings. In addition, the earnings from the Trans Mountain pipeline, purchased in 2005 and part of the Kinder Morgan Canada–KMP business segment, were accretive to earnings for 2006.
 
Impact of the Purchase Method of Accounting on Segment Earnings (Loss)
 
The impacts of the purchase method of accounting on segment earnings (loss) before DD&A relate primarily to the revaluation of the accumulated other comprehensive income related to derivatives accounted for as hedges in the CO2–KMP and Natural Gas Pipelines–KMP segments. Where there is an impact to segment earnings (loss) before DD&A from the Going Private transaction, the impact is described in the individual business segment discussions, which follow. The effects on DD&A expense result from changes in the carrying values of certain tangible and intangible assets to their estimated fair values as of May 30, 2007. This revaluation results in changes to DD&A expense in periods subsequent to May 30, 2007. The purchase accounting effects on “Interest and Other, Net” result principally from the revaluation of certain debt instruments to their estimated fair values as of May 30, 2007, resulting in changes to interest expense in subsequent periods.
 
Please refer to the individual business segment discussions included elsewhere in this management’s discussion and analysis for additional information regarding individual business segment results. Refer to the headings “General and Administrative Expense,” “Interest and Other, Net” and “Income Taxes—Continuing Operations” also included elsewhere herein, for additional information regarding these items.
 

 
54
 
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)
Knight Form 10-K


 
The following discussion of our results of operations is by segment for factors affecting segment earnings, and on a consolidated basis for other factors.
 
The variability of our operating results is attributable to a number of factors including (i) variability within U.S. and Canadian national and local markets for energy and related services, including the effects of competition, (ii) the impact of regulatory proceedings, (iii) the effect of weather on customer energy and related services usage, as well as our operation and construction activities, (iv) increases or decreases in interest rates, (v) the degree of our success in controlling costs, identifying and carrying out profitable expansion projects, and integrating new acquisitions into our operations and (vi) changes in taxation policy or regulated rates. Certain of these factors are beyond our direct control, but we operate a structured risk management program to mitigate certain of the risks associated with changes in the price of natural gas, interest rates and currency exchange rates. Also see Item 1A “Risk Factors” elsewhere in this report.
 
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.
 
The accounting policies we apply in the generation of business segment earnings are generally the same as those applied to the accompanying Consolidated Statements of Operations and described in Note 1 of the accompanying Notes to Consolidated Financial Statements. Certain items included in earnings from continuing operations are either not allocated to business segments or are not considered by management in its evaluation of business segment performance. In general, the items not included in segment results are interest expense, general and administrative expenses, DD&A and income taxes. We currently evaluate business segment performance primarily based on segment earnings before DD&A in relation to the level of capital employed. Because Kinder Morgan Energy Partners’ partnership agreement requires it to distribute 100% of its available cash to its partners on a quarterly basis (Kinder Morgan Energy Partners’ available cash consists primarily of all of its cash receipts, less cash disbursements and changes in reserves), we consider each period’s earnings before all non-cash depreciation, depletion and amortization expenses to be an important measure of business segment performance for our segments that are also segments of Kinder Morgan Energy Partners. We account for intersegment sales at market prices. We account for the transfer of net assets between entities under common control by carrying forward the net assets recognized in the balance sheets of each combining entity to the balance sheet of the combined entity, and no other assets or liabilities are recognized as a result of the combination. Transfers of net assets between entities under common control do not affect the income statement of the combined entity.
 
Natural Gas Pipeline Company of America
 
 
Successor Company
    
Predecessor Company
 
Year Ended
December 31,
2008
  
Seven Months
Ended
December 31,
2007
    
Five Months
Ended
May 31, 2007
  
Year Ended
December 31,
2006
 
(In millions)
    
(In millions)
Segment Earnings Before DD&A
$
129.8
    
$
422.8
      
$
267.4
    
$
603.5
  

On February 15, 2008, we sold an 80% ownership interest in our NGPL business segment to Myria Acquisition Inc. (“Myria”) for approximately $5.9 billion. As a result of the sale, beginning February 15, 2008, we account for our 20% ownership interest as an equity method investment. We continue to operate NGPL’s assets pursuant to a 15-year operating agreement. Myria is owned by a syndicate of investors led by Babcock & Brown, an international investment and specialized fund and asset management group.
 
Year Ended December 31, 2008
 
Although we have a 20% ownership interest in NGPL, at the 100% ownership level, NGPL’s earnings before depreciation, depletion and amortization expenses for the year ended December 31, 2008 was $702.0 million. Included in the earnings for this period were (i) $650.8 million of gross profit from transportation and storage revenues, which reflects the positive impact of re-contracting of transportation and storage services at higher rates and increased contract volumes, (ii) $226.5 million of gross profit from operational gas recoveries and sales, (iii) $5.0 million of gross profit from liquids sales, (iv) $0.6 million of other revenues, (v) $15.8 million of gross profit from working and cushion sales and (vi) $7.1 million from other activities. These gross profits were reduced by operation and maintenance expenses of $203.8 million.
 

 
55
 
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)
Knight Form 10-K


Seven Months Ended December 31, 2007
 
Segment revenues and earnings for the seven months ended December 31, 2007 were positively impacted primarily by (i) $334.4 million of gross profit from transportation and storage revenues, which reflects the positive impact of re-contracting of transportation and storage services at higher rates and increased contract volumes, and recent transportation and storage system expansions, (ii) $116.0 million of gross profit from operational gas recoveries and sales and (iii) $61.4 million of gross profit from cushion sales. Total system throughput volumes of 1,027.2 trillion Btus in 2007 during the seven months ended December 31, 2007 did not have a significant direct impact on revenues or segment earnings due to the fact that transportation revenues are derived primarily from “firm” contracts in which shippers pay a “demand” fee to reserve a set amount of system capacity for their use.
 
Five Months Ended May 31, 2007
 
Segment revenues and earnings for the five months ended May 31, 2007 were positively impacted primarily by (i) $245.9 million of gross profit from transportation and storage revenues, which reflects the positive impact of re-contracting of transportation and storage services at higher rates and increased contract volumes, and recent transportation and storage system expansions and (ii) $77.6 million of gross profit from operational gas recoveries and sales.
 
Year Ended December 31, 2006
 
Segment revenues and earnings for the year ended December 31, 2006 were positively impacted primarily by (i) $547.5 million of gross profit from transportation and storage revenues, which reflects the positive impact of re-contracting of transportation and storage services at higher rates and increased contract volumes, and recent transportation and storage system expansions and (ii) $189.4 million of gross profit from operational gas recoveries and sales.
 
 
As discussed in Note 10 of the accompanying Notes to Consolidated Financial Statements, on January 25, 2008, we sold our interests in three natural gas-fired power plants in Colorado to Bear Stearns, including the Thermo Cogeneration Partnership and the Thermo Greeley facility. The closing of the sale was effective January 1, 2008, and we received net proceeds of $63.1 million.
 
The remaining operations for the Power segment are (i) Triton Power Michigan LLC’s lease and operation of the Jackson, Michigan 550-megawatt natural gas-fired electric power plant and (ii) a 103-megawatt natural gas-fired power plant in Snyder, Texas that generates electricity for the CO2–KMP segment’s SACROC operations, the plant’s sole customer.
 
 
Successor Company
    
Predecessor Company
 
Year Ended
December 31,
2008
  
Seven Months
Ended
December 31,
2007
    
Five Months
Ended
May 31, 2007
  
Year Ended
December 31,
2006
 
(In millions)
    
(In millions)
Operating Revenues
$
44.0
    
$
40.2
      
$
19.9
    
$
60.0
  
Operating Expenses and Minority Interests
  
(38.3
)
    
(34.8
)
      
(16.1
)
    
(49.6
)
Other Income (Expense)1
  
-
      
-
        
-
      
(1.2
)
Equity in Earnings of Thermo Cogeneration Partnership2
  
-
      
8.0
        
5.1
      
11.3
  
Gain on Asset Sales
  
-
      
-
        
-
      
2.7
  
Segment Earnings Before DD&A
$
5.7
    
$
13.4
      
$
8.9
    
$
23.2
  
__________
1
To record the impairment of certain surplus equipment held for sale.
2
This interest was part of the sale effective January 1, 2008 as discussed above.
 
Year Ended December 31, 2008
 
Earnings before DD&A for 2008 reflect (i) $3.4 million in earnings from the lease and operations of the Triton Power Michigan facility, (ii) a $1.5 million property tax settlement received in 2008, (iii) $0.3 million in earnings from the Snyder, Texas operations and (iv) $0.5 million from other activities.
 
Seven Months Ended December 31, 2007
 
Earnings before DD&A for the seven months ended December 31, 2007 reflect the positive impacts of (i) contributions of $2.0 million of earnings before DD&A from our Jackson, Michigan facility, (ii) $8.0 million of equity earnings from our investment in Thermo Cogeneration Partnership and (iii) $1.4 million of earnings from the Thermo Greeley facility associated with gas purchase and sale agreements. These favorable impacts to earnings were partially offset by an
 

 
56
 
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)
Knight Form 10-K


unfavorable impact to operating revenues associated with 2006 equipment sales.
 
Five Months Ended May 31, 2007
 
Earnings before DD&A for the five months ended May 31, 2007 reflect an unfavorable impact to operating revenues associated with 2006 equipment sales. These unfavorable impacts to earnings were partially offset by (i) contributions of $1.3 million of earnings from our Jackson, Michigan facility, (ii) contributions of $1.2 million of earnings from the Thermo Greeley facility associated with gas purchase and sales agreements and (iii) our $5.1 million of equity earnings from our investment in Thermo Cogeneration Partnership.
 
Year Ended December 31, 2006
 
Earnings before DD&A for the year ended December 31, 2006 reflects the positive impacts of (i) contributions of $3.1 million of earnings before DD&A from our Jackson, Michigan facility, (ii) $11.3 million of equity earnings from our investment in Thermo Cogeneration Partnership and (iii) $4.2 million of earnings from the Thermo Greeley facility associated with gas purchase and sale agreements. These favorable impacts to earnings were partially offset by an unfavorable impact to operating revenues associated with $1.9 million of equipment sales.
 
 
 
Successor Company
    
Predecessor Company
 
Year Ended
December 31,
2008
  
Seven Months
Ended
December 31,
2007
    
Five Months
Ended
May 31, 2007
  
Year Ended
December 31,
2006
 
(In millions, except operating statistics)
    
(In millions, except operating statistics)
Operating Revenues
$
815.9
    
$
471.5
      
$
331.8
    
$
732.5
  
Operating Expenses
  
(291.0
)
    
(320.6
)
      
(116.4
)
    
(285.5
)
Other Income (Expense)
  
(3.0
)
    
0.8
        
(0.6
)
    
-
  
Goodwill Impairment Charge1
  
(1,266.5
)
    
-
        
-
      
-
  
Earnings from Equity Investments
  
15.7
      
11.5
        
12.4
      
14.2
  
Interest Income and Other Income, Net
  
2.0
      
4.7
        
4.7
      
11.9
  
Income Taxes Benefit (Expense)
  
4.9
      
(5.4
)
      
(7.5
)
    
(5.2
)
Segment Earnings (Loss) Before DD&A
$
(722.0
)
  
$
162.5
      
$
224.4
    
$
467.9
  
                                 
Operating Statistics
                                
Gasoline (MMBbl)
  
398.4
      
252.7
        
182.8
      
449.8
  
Diesel Fuel (MMBbl)
  
157.9
      
97.5
        
66.6
      
158.2
  
Jet Fuel (MMBbl)
  
117.3
      
73.8
        
51.3
      
119.5
  
Total Refined Products Volumes (MMBbl)
  
673.6
      
424.0
        
300.7
      
727.5
  
Natural Gas Liquids (MMBbl)
  
27.3
      
16.7
        
13.7
      
34.0
  
Total Delivery Volumes (MMBbl)2
  
700.9
      
440.7
        
314.4
      
761.5
  
____________
1
2008 amount represents a non-cash goodwill impairment charge; see Note 3 of the accompanying Notes to Consolidated Financial Statements.
2
Includes Pacific operations, Plantation, Calnev, Central Florida, Cochin and Cypress pipeline volumes.
 

 
57
 
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)
Knight Form 10-K


Earnings Before DD&A by Major Segment Asset
 
 
Successor Company
    
Predecessor Company
 
Year Ended
December 31,
2008
  
Seven Months
Ended
December 31,
2007
    
Five Months
Ended
May 31, 2007
  
Year Ended
December 31,
2006
 
(In millions)
    
(In millions)
Pacific Operations
$
233.6
    
$
(10.3
)
    
$
105.1
    
$
245.0
  
Calnev Pipeline
  
49.2
      
27.5
        
20.1
      
42.2
  
West Coast Terminals
  
50.7
      
24.3
        
19.3
      
36.3
  
Plantation Pipeline
  
37.1
      
22.2
        
18.2
      
28.4
  
Central Florida Pipeline
  
41.1
      
21.9
        
15.3
      
31.4
  
Cochin Pipeline System
  
46.7
      
30.6
        
15.3
      
14.1
  
Southeast Terminals
  
51.6
      
24.8
        
16.6
      
37.5
  
Transmix Operations
  
29.8
      
18.3
        
12.4
      
28.4
  
Goodwill Impairment Charge
  
(1,266.5
)
    
-
        
-
      
-
  
All Other
  
4.7
      
3.2
        
2.1
      
4.6
  
Segment Earnings (Loss) Before DD&A
$
(722.0
)
  
$
162.5
      
$
224.4
    
$
467.9
  

Revenues by Major Segment Asset
 
 
Successor Company
    
Predecessor Company
 
Year Ended
December 31,
2008
  
Seven Months
Ended
December 31,
2007
    
Five Months
Ended
May 31, 2007
  
Year Ended
December 31,
2006
 
(In millions)
    
(In millions)
Pacific Operations
$
374.6
    
$
224.4
      
$
156.0
    
$
362.0
  
Calnev Pipeline
  
71.4
      
41.9
        
27.7
      
66.2
  
West Coast Terminals
  
79.5
      
42.9
        
29.1
      
64.5
  
Plantation Pipeline
  
44.0
      
24.6
        
17.6
      
41.2
  
Central Florida Pipeline
  
52.4
      
27.1
        
19.3
      
43.1
  
Cochin Pipeline System
  
63.3
      
42.6
        
32.3
      
35.7
  
Southeast Terminals
  
81.9
      
38.4
        
29.9
      
81.1
  
Transmix Operations
  
42.4
      
25.8
        
17.5
      
32.8
  
All Other (Including Eliminations)
  
6.4
      
3.8
        
2.4
      
5.9
  
Total Segment Operating Revenues
$
815.9
    
$
471.5
      
$
331.8
    
$
732.5
  

Year Ended December 31, 2008
 
Earnings before DD&A were positively affected by strong earnings for the Southeast terminals, Cochin Pipeline, Central Florida Pipeline and West Coast Terminals operations that were principally from (i) favorable margins on liquids inventory sales, (ii) incremental terminal throughput and storage activity, (iii) solid demand for ethanol and (iv) incremental returns from the completion of a number of capital expansion projects that modified and upgraded terminal infrastructure, enabling Kinder Morgan Energy Partners to provide additional ethanol-related services to its customers. The Central Florida Pipeline also benefited from strong product delivery revenues, driven by an increase in the average tariff per barrel moved as a result of a mid-year 2007 tariff rate increase on product deliveries. The Cochin Pipeline also benefited from a year-end 2008 reduction in income tax expense, related to lower Canadian operating results in 2008 and from Canadian income tax liability adjustments. The decrease in income tax expense more than offset the drop in operating revenues.
 
Earnings before DD&A were adversely affected by (i) a $1,266.5 million goodwill impairment charge, (ii) $20.0 million for charges, net of tax related to settlement of certain litigation matters or environmental liability adjustments, mostly related to Pacific operations’ East Line pipeline and (iii) Pacific operations expenses for major maintenance and pipeline integrity expenses.
 
Seven Months Ended December 31, 2007
 
The results for the seven months were negatively impacted by $154.9 million of legal liability adjustments primarily associated with the Pacific operations. Offsetting the charges, earnings before DD&A for this segment were positively affected by (i) approximately $15.4 million associated with Kinder Morgan Energy Partners’ January 1, 2007 acquisition of
 

 
58
 
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)
Knight Form 10-K


the remaining ownership interest in Cochin (approximately 50.2%) that it did not already own, at which time Kinder Morgan Energy Partners became the pipeline operator, (ii) strong pipeline revenues from the Plantation Pipeline for the period, largely due to favorable oil loss allowance tariff rates, relative to pipeline operating expenses that included only minor pipeline integrity expenses, (iii) favorable margins and strong mainline delivery volumes from the 2006 East Line pipeline expansion and demand from West Coast military bases within the Pacific operations, (iv) military and commercial tariff rate increases in 2007 on the Calnev Pipeline, (v) strong demand for terminal services at the Carson/Los Angeles Harbor terminal system, recently expanded in 2006, and the Linnton and Willbridge terminals located in Portland, Oregon, included in the West Coast Terminals operations, (vi) $4.8 million of earnings before DD&A and $5.7 million of revenue generated by the Kinder Morgan Energy Partners’ approximate $11 million Greensboro facility, placed in service in 2006, which is used for petroleum pipeline transmix operations and (vii) the West Coast Terminals operation’s $3.6 million gain on the sale of its interest in the Black Oil pipeline system in Los Angeles, California in June 2007.
 
Five Months Ended May 31, 2007
 
The results for the five months were negatively impacted by a $2.2 million expense associated with Pacific operations’ East Line pipeline legal liability adjustments. Earnings before DD&A were positively affected by (i) approximately $7.7 million associated with Kinder Morgan Energy Partners’ January 1, 2007 acquisition of the remaining ownership interest in Cochin (approximately 50.2%) that it did not already own, at which time Kinder Morgan Energy Partners became the pipeline operator, (ii) an increase in average tariff rates and mainline delivery from the 2006 expansion of the East Line pipeline within the Pacific operations and demand from West Coast military bases, which contributed to the Pacific operations’ revenues and earnings, (iii) strong demand for throughput volumes at the combined Carson/Los Angeles Harbor terminal system and the Linnton and Willbridge terminals located in Portland, Oregon, for the West Coast Terminals operations and (iv) $2.8 million of earnings before DD&A and $3.3 million of revenue generated by the Kinder Morgan Energy Partners’ Greensboro facility discussed above.
 
Year Ended December 31, 2006
 
Earnings before DD&A for 2006 were positively impacted by (i) contributions from the Pacific operations and the Calnev operations with solid refined products deliveries and terminal and other fee revenues that more than offset operating costs for the period which were affected by high fuel and power expenses, (ii) positive performance from the Southeast Terminals products operations with strong demand for liquids throughput volumes at favorable rates and optimal margins on ethanol blending and sales activities and (iii) solid product delivery revenues in 2006 from other segment assets driven by Central Florida Pipeline’s increased average tariff and terminal rates during the period.
 
Partially offsetting these positive factors in 2006 were (i) $13.5 million of legal liability adjustments associated with the Pacific operations, (ii) incremental pipeline maintenance expenses recognized in the last half of the year, (iii) $6.2 million of environmental expenses recognized by the West Coast Terminals operations in 2006 and (iv) $3.0 million of environmental liability adjustments (net of tax benefits) on the Plantation Pipe Line Company. Beginning in the third quarter of 2006, the refined petroleum products pipelines and associated terminal operations included within the Products Pipelines–KMP segment (including Plantation Pipe Line Company, the 51%-owned equity investee) began recognizing certain costs incurred as part of its pipeline integrity management program as maintenance expense in the period incurred, and in addition, recorded an expense for costs previously capitalized during the first six months of 2006. Combined, this change reduced the segment’s earnings before DD&A by $24.2 million in 2006—increasing maintenance expenses by $20.1 million, decreasing earnings from equity investments by $6.6 million and decreasing income tax expenses by $2.5 million.
 
Pipeline integrity costs encompass those costs incurred as part of an overall pipeline integrity management program, which is a process for assessing and mitigating pipeline risks in order to reduce both the likelihood and consequences of incidents. The pipeline integrity program is designed to provide management with the information needed to effectively allocate resources for appropriate prevention, detection and mitigation activities.
 
Contributing to the total delivery volumes of refined petroleum products were (i) the East Line expansion, which was in service for the last seven months of 2006 and substantially increased pipeline capacity from El Paso, Texas to Tucson and Phoenix, Arizona and (ii) strong demand from the Southern California and Las Vegas, Nevada markets on the Calnev Pipeline. Partially offsetting these factors was shortened demand for throughput volumes on Plantation Pipeline, which was impacted by a competing pipeline that began service in mid-2006.
 
Other Products Pipelines – KMP Segment Events
 
Effective October 5, 2007, Kinder Morgan Energy Partners sold its North System common carrier natural gas liquids pipeline and its 50% ownership interest in the Heartland Pipeline Company to ONEOK Partners, L.P. for approximately $295.7 million in cash, and used the proceeds received to pay down short-term debt borrowings. The North System business results of operations are not included in the tables and discussion above and have been classified to Discontinued Operations on the accompanying Statements of Operations for the seven months ended December 31, 2007, five months ended May 31, 2007
 

 
59
 
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)
Knight Form 10-K


and year ended December 31, 2006.
 
 
 
Successor Company
    
Predecessor Company
 
Year Ended
December 31,
2008
  
Seven Months
Ended
December 31,
2007
    
Five Months
Ended
May 31, 2007
  
Year Ended
December 31,
2006
 
(In millions, except operating statistics)
    
(In millions, except operating statistics)
Operating Revenues
$
8,422.0
    
$
3,825.9
      
$
2,640.6
    
$
6,577.7
  
Operating Expenses
  
(7,803.3
)
    
(3,461.4
)
      
(2,418.5
)
    
(6,057.8
)
Other Income (Expense)
  
0.2
      
1.9
        
(0.1
)
    
15.1
  
Goodwill Impairment Charge1
  
(2,090.2
)
    
-
        
-
          
Earnings from Equity Investments
  
113.4
      
10.3
        
8.9
      
40.5
  
Interest Income and Other Income, Net
  
16.3
      
-
        
0.2
      
0.7
  
Income Taxes
  
(2.7
)
    
(3.4
)
      
(2.6
)
    
(1.4
)
Segment Earnings (Loss) Before DD&A
$
(1,344.3
)
  
$
373.3
      
$
228.5
    
$
574.8
  
  
                                
Operating Statistics
                                
Natural Gas Transport Volumes (Trillion Btus)2
  
2,156.3
      
1,067.0
        
645.6
      
1,440.9
  
Natural Gas Sales Volumes (Trillion Btus)3
  
866.9
      
519.7
        
345.8
      
909.3
  
__________
1
2008 amount represents a non-cash goodwill impairment charge; see Note 3 of the accompanying Notes to Consolidated Financial Statements.
2
Includes Kinder Morgan Interstate Gas Transmission LLC, Trailblazer Pipeline Company LLC, TransColorado Gas Transmission Company LLC, Rockies Express Pipeline LLC and Texas Intrastate Natural Gas Pipeline Group pipeline volumes.
3
Represents Texas Intrastate Natural Gas Pipeline Group volumes.
 
Earnings Before DD&A by Major Segment Asset
 
 
Successor Company
    
Predecessor Company
 
Year Ended
December 31,
2008
  
Seven Months
Ended
December 31,
2007
    
Five Months
Ended
May 31, 2007
  
Year Ended
December 31,
2006
 
(In millions)
    
(In millions)
Texas Intrastate Natural Gas Pipeline Group
$
385.6
    
$
221.1
      
$
133.0
    
$
305.5
  
Kinder Morgan Interstate Gas Transmission
  
114.4
      
65.7
        
43.1
      
107.4
  
Trailblazer Pipeline
  
44.4
      
31.9
        
18.1
      
50.8
  
TransColorado Pipeline
  
55.0
      
25.7
        
17.9
      
43.1
  
Rockies Express Pipeline
  
84.4
      
(8.3
)
      
(4.3
)
    
-
  
Kinder Morgan Louisiana Pipeline
  
11.3
      
-
        
-
      
-
  
Casper and Douglas Gas Processing
  
20.0
      
18.0
        
7.3
      
29.3
  
Goodwill Impairment Charge
  
(2,090.2
)
    
-
        
-
      
-
  
All Others
  
30.8
      
19.2
        
13.4
      
38.7
  
Segment Earnings (Loss) Before DD&A
$
(1,344.3
)
  
$
373.3
      
$
228.5
    
$
574.8
  


 
60
 
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)
Knight Form 10-K


Revenues by Major Segment Asset
 
 
Successor Company
    
Predecessor Company
 
Year Ended
December 31,
2008
  
Seven Months
Ended
December 31,
2007
    
Five Months
Ended
May 31, 2007
  
Year Ended
December 31,
2006
 
(In millions)
    
(In millions)
Texas Intrastate Natural Gas Pipeline Group
$
7,979.4
    
$
3,562.0
      
$
2,492.4
    
$
6,196.6
  
Kinder Morgan Interstate Gas Transmission
  
199.5
      
130.7
        
70.7
      
183.6
  
Trailblazer Pipeline
  
53.9
      
36.4
        
22.6
      
50.1
  
TransColorado Pipeline
  
63.5
      
30.3
        
20.7
      
47.9
  
Rockies Express Pipeline
  
-
      
-
        
-
      
0.7
  
Casper and Douglas Gas Processing
  
126.3
      
67.1
        
34.7
      
96.2
  
All Others
  
3.0
      
0.2
        
-
      
4.1
  
Eliminations
  
(3.6
)
    
(0.8
)
      
(0.5
)
    
(1.5
)
Segment Revenues
$
8,422.0
    
$
3,825.9
      
$
2,640.6
    
$
6,577.7
  

Year Ended December 31, 2008
 
The Natural Gas Pipelines–KMP segment’s earnings before DD&A in the year ended December 31, 2008 were driven by (i) a strong performance by the Texas Intrastate Natural Gas Pipeline Group due to (a) higher natural gas sales margins, (b) increased transportation service revenues due to long-term contract with a major customer that became effective April 1, 2007 and (c) greater natural gas processing revenues, (ii) contributions from Kinder Morgan Energy Partners’ 51% ownership interest in the Rockies Express Pipeline LLC, whose Rockies Express-West pipeline segment became fully operational in May 2008, (iii) a strong performance from the TransColorado Pipeline primarily due to contract improvements and expansions completed since the end of the third quarter of 2007, (iv) strong performance from the Kinder Morgan Interstate Gas Transmission system (“KMIGT”) primarily due to decreased electricity used and lower negotiated rates, lower natural gas purchase costs and lower tax expenses payable to the state of Texas in 2008. Also, in October 2008, KMIGT completed construction on an approximately $22 million expansion project that provides for the delivery of natural gas to five separate industrial plants (four of which produce ethanol) located near Grand Island, Nebraska. The project is fully subscribed with long-term customer contracts; and (v) earnings from the Kinder Morgan Louisiana Pipeline that benefited from FERC regulations governing allowances for capital funds that are used for pipeline construction costs (an equity cost of capital allowance).
 
Offsetting the above positive impacts to the segment’s earnings before DD&A were the following: (i) a $2,090.2 million goodwill impairment charge, (ii) the Casper and Douglas gas processing operations were adversely affected by higher natural gas purchase costs, due to increases in both prices and volumes, which more than offset revenue increases resulting from both higher average prices on natural gas liquids sales and higher revenues from sales of excess natural gas and (iii) the Trailblazer Pipeline’s earnings were affected by lower revenues from both natural gas transportation services and sales of excess natural gas.
 
Seven Months Ended December 31, 2007
 
Earnings before DD&A in the seven months ended December 31, 2007 were also positively affected by (i) strong performances by the Texas Intrastate Pipeline group due to (a) favorable natural gas sales margins on renewal contracts, (b) increased transportation service revenue due to a new long-term contract with a major customer that became effective April 1, 2007, (c) greater value from natural gas storage activities and natural gas processing margins, (d) sales of cushion gas due to the termination of a storage facility lease and (e) storage revenues from transportation and storage under a new long term contract with a major customer that became effective April 1,2007, (ii) strong performance from KMIGT, Trailblazer Pipeline and TransColorado Pipeline due mainly to solid earnings from transportation and natural gas park and loan services and (iii) earnings from Casper and Douglas gas processing operations that had solid natural gas liquids sales revenues driven by favorable prices and volumes.
 
Adversely affecting earnings before DD&A in the seven months ended December 31, 2007 was Kinder Morgan Energy Partners’ share of net losses from its equity investment in Rockies Express Pipeline LLC due to depreciation and interest expenses allocable to a segment of this project that was placed in service in February 2007, and until the completion of the Rockies Express-West project which became fully operational in May 2008, generated only limited natural gas reservation revenues and volumes. See Note 19 of the accompanying Notes to Consolidated Financial Statements for additional information on the Rockies Express Pipeline project.
 

 
61
 
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)
Knight Form 10-K


Five Months Ended May 31, 2007
 
Earnings before DD&A in the five months ended May 31, 2007 were positively affected by (i) strong performances by the Texas Intrastate Natural Gas Pipeline Group due to (a) favorable natural gas sales margins on renewal and incremental contracts, (b) strong demand for and favorable rates on transportation services, (c) greater value from natural gas storage activities and natural gas processing margins, (d) sales of cushion gas due to the termination of a storage facility lease and (e) storage revenues from a new long-term contract with a major customer that became effective April 1, 2007, (ii) strong performance from KMIGT, Trailblazer Pipeline and TransColorado Pipeline due mainly to solid earnings from transportation and natural gas park and loan services and (iii) earnings from Casper and Douglas gas processing operations that had solid natural gas liquids sales revenues driven by favorable prices and volumes.
 
Rockies Express Pipeline LLC operations adversely affected earnings before DD&A by $4.3 million for the five months ended May 31, 2007 as depreciation and interest expenses were in excess of gross profits realized on limited natural gas reservation revenues and volumes, as discussed above in the Seven Months Ended December 31, 2007 discussion.
 
Year Ended December 31, 2006
 
Combined, gains on sales of gas processing facilities and the revaluation of purchase/sale contracts increased earnings before DD&A by $21.4 million in the year ended December 31, 2006. Earnings before DD&A in 2006 were also positively impacted by (i) a strong revenue stream with favorable imbalance resolution from the Texas Intrastate Natural Gas Pipeline Group, (ii) revenues earned in 2006 from both operational sales of natural gas and natural gas park and loan services by KMIGT, (iii) natural gas transmission revenues earned by TransColorado Pipeline, chiefly related to strong natural gas delivery volumes resulting from both system improvements and the successful negotiation of incremental firm transportation contracts and (iv) increased prices during the period on incremental sales of excess fuel gas and strong natural gas gathering revenues from the 49% equity investment in the Red Cedar Gathering Company within the “All Others” assets group in the tables above.
 
KMIGT’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 TransColorado Pipeline system improvements were associated with a 2005 expansion on the northern portion of the pipeline.
 
 
 
Successor Company
    
Predecessor Company
 
Year Ended
December 31,
2008
  
Seven Months
Ended
December 31,
2007
    
Five Months
Ended
May 31, 2007
  
Year Ended
December 31,
2006
 
(In millions, except operating statistics)
    
(In millions, except operating statistics)
Operating Revenues
$
1,269.2
    
$
605.9
      
$
324.2
    
$
736.5
  
Operating Expenses
  
(391.8
)
    
(182.7
)
      
(121.5
)
    
(268.1
)
Earnings from Equity Investments
  
20.7
      
10.5
        
8.7
      
19.2
  
Other Income (Expense), Net
  
1.9
      
0.1
        
(0.1
)
    
0.8
  
Income Taxes
  
(3.9
)
    
(0.8
)
      
(1.3
)
    
(0.2
)
Segment Earnings Before DD&A
$
896.1
    
$
433.0
      
$
210.0
    
$
488.2
  
  
                                
Operating Statistics
                                
Carbon Dioxide Delivery Volumes (Bcf)1
  
732.1
      
365.0
        
272.3
      
669.2
  
SACROC Oil Production (Gross)(MBbl/d)2
  
28.0
      
26.5
        
29.1
      
30.8
  
SACROC Oil Production (Net)(MBbl/d)3
  
23.3
      
22.1
        
24.2
      
25.7
  
Yates Oil Production (Gross)(MBbl/d)2
  
27.6
      
27.4
        
26.4
      
26.1
  
Yates Oil Production (Net)(MBbl/d)3
  
12.3
      
12.2
        
11.7
      
11.6
  
Natural Gas Liquids Sales Volumes (Net)(MBbl/d)3
  
8.4
      
9.5
        
9.7
      
8.9
  
Realized Weighted-average Oil Price per Bbl4,5
$
49.42
    
$
36.80
      
$
35.03
    
$
31.42
  
Realized Weighted-average Natural Gas Liquids Price per Bbl5,6
$
63.00
    
$
58.55
      
$
45.04
    
$
43.90
  
__________
1
Includes Cortez, Central Basin, Canyon Reef Carriers, Centerline and Pecos pipeline volumes.
2
Represents 100% of the production from the field. Kinder Morgan Energy Partners owns an approximate 97% working interest in the SACROC unit and an approximate 50% working interest in the Yates unit.
3
Net to Kinder Morgan Energy Partners, after royalties and outside working interests.
4
Includes all Kinder Morgan Energy Partners crude oil production properties.

 
62
 
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)
Knight Form 10-K


5
Hedge gains/losses for crude oil and natural gas liquids are included with crude oil.
6
Includes production attributable to leasehold ownership and production attributable to Kinder Morgan Energy Partners’ ownership in processing plants and third-party processing agreements.
 
Because the CO2–KMP segment is exposed to commodity price risk related to the price volatility of crude oil and natural gas liquids, it mitigates this risk through a long-term hedging strategy that is intended to generate more stable realized prices by using derivative contracts as hedges to the exposure of fluctuating expected future cash flows produced by changes in commodity sales prices. All of the hedge gains and losses for crude oil and natural gas liquids are included in the realized weighted average price for oil. Had energy derivative contracts not been used to transfer commodity price risk, crude oil sales prices would have averaged $97.70 per barrel in 2008, $78.65 per barrel in the seven months ended December 31, 2007, $57.43 per barrel in the five months ended May 31, 2007 and $63.27 per barrel in 2006. For more information on hedging activities, see Note 15 of the accompanying Notes to Consolidated Financial Statements.
 
Additionally, the decline in crude oil production at the SACROC field unit in the seven months ended December 31, 2007, five months ended May 31, 2007 and year ended December 31, 2006 is attributable to lower observed recoveries from recent project areas and an intentional slow down in development pace given this reduction in recoveries. For more information on Kinder Morgan Energy Partners’ ownership interests in the net quantities of proved oil and gas reserves and its measures of discounted future net cash flows from oil and gas reserves, please see the caption titled “Supplemental Information on Oil and Gas Producing Activities (Unaudited)” in the Financial Statements and Supplementary Data included in Item 8 of this report.
 
Earnings Before DD&A by Major Segment Activities
 
 
Successor Company
    
Predecessor Company
 
Year Ended
December 31,
2008
  
Seven Months
Ended
December 31,
2007
    
Five Months
Ended
May 31, 2007
  
Year Ended
December 31,
2006
 
(In millions)
    
(In millions)
Sales and Transportation
$
301.0
    
$
110.4
      
$
67.2
    
$
186.8
  
Oil and Gas Production
  
595.1
      
322.6
        
142.8
      
301.4
  
Segment Earnings Before DD&A
$
896.1
    
$
433.0
      
$
210.0
    
$
488.2
  

Revenues by Major Segment Activities
 
 
Successor Company
    
Predecessor Company
 
Year Ended
December 31,
2008
  
Seven Months
Ended
December 31,
2007
    
Five Months
Ended
May 31, 2007
  
Year Ended
December 31,
2006
 
(In millions)
    
(In millions)
Sales and Transportation
$
334.7
    
$
116.1
      
$
71.3
    
$
196.3
  
Oil and Gas Production
  
1,019.2
      
518.7
        
271.7
      
601.0
  
Eliminations
  
(84.7
)
    
(28.9
)
      
(18.8
)
    
(60.8
)
Total Segment Operating Revenues
$
1,269.2
    
$
605.9
      
$
324.2
    
$
736.5
  

Year Ended December 31, 2008
 
The CO2–KMP segment’s earnings before DD&A in the year ended December 31, 2008 were positively affected by the realization of higher market and hedge prices for the sale of its crude oil, natural gas products and CO2 and an expansion project completed in its sales and transportation business, which increased CO2 delivery volumes. Another positive impact on the period’s earnings before DD&A of $136.3 million resulted from valuation adjustments related to derivative contracts on crude oil hedges in place at the time of the Going Private transaction and recorded in the application of the purchase method of accounting.
 
Earnings for the segment’s sales and transportation activities were positively impacted by factors affecting carbon dioxide sales revenues (both price and volume related) and carbon dioxide and crude oil pipeline transportation revenues. Transportation revenues were impacted by increased carbon dioxide delivery volume due to rising customer demand for carbon dioxide for use in oil recovery projects throughout the Permian Basin. Another positive impact during 2008 in carbon dioxide sales and delivery volumes was the January 17, 2008 start-up of the Doe Canyon Deep unit carbon dioxide source field located in Dolores County, Colorado. Kinder Morgan Energy Partners holds an approximately 87% working interest in
 

 
63
 
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)
Knight Form 10-K


the Doe Canyon Deep unit.
 
With respect to crude oil, overall sales volumes were essentially flat, but the segment benefited from an increase in its realized weighted-average price per barrel. With respect to natural gas liquids, a decrease in sales volumes was more than offset by increases in its realized weighted-average price per barrel. Sales volumes were adversely affected by Hurricane Ike, which resulted in pro-rationing (production allocation).
 
Seven Months Ended December 31, 2007
 
For the seven months ended December 31, 2007, SACROC’s gross production averaged 26.5 thousand barrels per day and Yates’ gross production averaged 27.4 thousand barrels per day. SACROC contributed approximately 56% of earnings before DD&A for the total oil and gas producing activities. The earnings before DD&A in the seven months ended December 31, 2007 were positively affected by (i) strong average crude oil and natural gas plant product prices, (ii) strong oil production at the Yates field unit and (iii) a favorable realized weighted-average price per barrel in the SACROC field unit gas processing operations. The period’s results were also positively affected by valuation adjustments of $106.0 million for derivative contracts on crude oil hedges as described above in the Year Ended December 31, 2008 discussion.
 
Partially offsetting these factors was a reduced average carbon dioxide realized sales price resulting from the December 2006 expiration of a large volume high-priced sales contract.
 
With respect to crude oil, overall sales volumes were stable, but the segment benefited from a strong realized weighted-average price per barrel. With respect to natural gas liquids, low sales volumes were more than offset by a favorable realized weighted-average price per barrel.
 
Five Months Ended May 31, 2007
 
The segment’s sales and transportation activities were adversely affected by a decrease in average carbon dioxide prices. A significant portion of the decrease in average carbon dioxide prices is timing related, as some of the segment’s carbon dioxide contracts are tied to crude oil prices in prior periods, and the 2007 contracts had been tied to lower crude oil prices, relative to 2006. These decreases in carbon dioxide prices were only partially offset by slightly higher carbon dioxide sales volumes related to increased carbon dioxide production from the McElmo Dome source field.
 
Highlights surrounding oil and gas producing activities for the five months ended May 31, 2007 include (i) increases in oil production at the Yates field unit, (ii) favorable weighted-average price per barrel and (iii) solid earnings from natural gas liquids sales volumes and prices, largely due to increased recoveries at the SACROC gas processing operations.
 
Year Ended December 31, 2006
 
Earnings before DD&A in 2006 were driven by strong earnings from carbon dioxide sales and transportation activities, largely due to solid revenues—from both carbon dioxide sales and deliveries, and from crude oil pipeline transportation, despite only modest earnings from oil and gas producing activities and equity earnings from the segment’s 50% ownership interest in Cortez Pipeline Company. Earnings from oil and gas producing activities were positively impacted during the period primarily by rising realized sales prices and partly from increased crude oil production at the Yates field unit, however partially offsetting these factors were increased operating and maintenance expenses (including well workover expenses), property and severance taxes, and fuel and power expenses.
 

 
64
 
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)
Knight Form 10-K


 
 
Successor Company
    
Predecessor Company
 
Year Ended
December 31,
2008
  
Seven Months
Ended
December 31,
2007
    
Five Months
Ended
May 31, 2007
  
Year Ended
December 31,
2006
 
(In millions, except operating statistics)
    
(In millions, except operating statistics)
Operating Revenues
$
1,173.6
    
$
599.2
      
$
364.5
    
$
864.8
  
Operating Expenses
  
(631.8
)
    
(344.2
)
      
(192.2
)
    
(461.9
)
Other Income (Expense)
  
(6.4
)
    
3.3
        
3.0
      
15.2
  
Goodwill Impairment Charge1
  
(676.6
)
    
-
        
-
      
-
  
Earnings from Equity Investments
  
2.7
      
0.6
        
-
      
0.2
  
Interest Income and Other Income, Net
  
1.7
      
0.7
        
0.3
      
2.1
  
Income Taxes
  
(19.7
)
    
(15.9
)
      
(3.3
)
    
(12.3
)
Segment Earnings (Loss) Before DD&A
$
(156.5
)
  
$
243.7
      
$
172.3
    
$
408.1
  
  
                                
Operating Statistics
                                
Bulk Transload Tonnage (MMtons)2
  
99.1
      
62.5
        
33.7
      
95.1
  
Liquids Leaseable Capacity (MMBbl)
  
54.2
      
47.5
        
43.6
      
43.5
  
Liquids Utilization %3
  
97.5
%
    
95.9
%
      
97.5
%
    
96.3
%
__________
2008 amounts include a non-cash goodwill impairment charge; see Note 3 of the accompanying Notes to Consolidated Financial Statements.
2
Volumes for acquired terminals are included for all periods.
3
Represents percentage of utilized available terminal storage capacity.
 
Kinder Morgan Energy Partners earnings have benefited from the incremental contributions attributable to the bulk and liquids terminal businesses it has built or acquired between 2005 and 2008. These transactions have included (among others):
 
 
·
the Texas Petcoke terminals acquisition on April 29, 2005;
 
·
three separate terminals located in New York, Kentucky and Arkansas, which were acquired in July 2005;
 
·
the purchase of all of the ownership interests in General Stevedores, L.P. on July 31, 2005;
 
·
the acquisition of the Kinder Morgan Blackhawk terminal located in Black Hawk County, Iowa, in August 2005;
 
·
the September 2005 purchase of a terminal-related repair shop located in Jefferson County, Texas;
 
·
three terminal operations, which were acquired separately in April 2006: terminal equipment and infrastructure located on the Houston Ship Channel, a rail terminal located at the Port of Houston and a rail ethanol terminal located in Carson, California;
 
·
all of the membership interests of Transload Services, LLC, which were acquired on November 20, 2006;
 
·
all of the membership interests of Devco USA L.L.C., which were purchased on December 1, 2006;
 
·
the Vancouver Wharves bulk marine terminals, acquired on May 30, 2007;
 
·
the terminal assets from Marine Terminals, Inc., purchased on September 1, 2007;
 
·
Phase III expansions completed and put into service at the Pasadena and Galena Park, Texas liquids terminal facilities in the first quarter of 2008;
 
·
nine new storage tanks at the Perth Amboy, New Jersey liquids terminal, which were completed and put into service in the first quarter of 2008;
 
·
a barge unloading terminal located on 30 acres in Columbus, Mississippi, completed and put into service in the first quarter of 2008;
 
·
our Pier X expansion at our bulk handling facility located in Newport News, Virginia, completed and put into service in the first quarter of 2008;
 
·
the approximately 2.15 million barrels of new crude oil capacity at the Kinder Morgan North 40 terminal located near Edmonton, Alberta, Canada, which was completed and put into service in the second quarter of 2008;
 
·
the approximately 320,000 barrels of additional gasoline capacity at the Shipyard River Terminal located in Charleston, South Carolina, which was completed and put into service in the third quarter of 2008;
 
·
the Kinder Morgan Wilmington terminal, purchased on August 15, 2008; and
 
·
the acquisition of certain terminal assets from LPC Packaging on October 2, 2008.
 
Year Ended December 31, 2008
 
Segment earnings before DD&A were positively affected by improved performance from existing assets such as $57.2 million of total 2008 earnings before DD&A from the Texas Petcoke terminal operations and assets acquired or expanded in
 

 
65
 
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)
Knight Form 10-K


the last eighteen months including (i) $8.3 million from the Vancouver Wharves bulk marine terminal, (ii) $22.1 million from Marine Terminals, Inc. and other acquired operations, (iii) $139.0 million from Kinder Morgan Energy Partners’ Gulf Coast terminals, primarily from its two expanded large liquids terminal facilities located along the Houston Ship Channel in Pasadena and Galena Park, Texas, (iv) $60.9 million from the Mid-Atlantic terminals, including strong coal transfer volumes primarily from its Pier IX bulk terminal (including earnings from the first quarter 2008 completion of construction of a new ship dock and installation of added terminal equipment) located in Newport News, Virginia and its Fairless Hills, Pennsylvania bulk terminal that began operations in the second quarter of 2008 with a new import fertilizer facility, (v) $30.5 million from the Western terminals, primarily from its recently completed North 40 terminal and (vi) $74.2 million from the Northeast terminals, primarily from its Perth Amboy, New Jersey liquids terminal, located in the New York Harbor area, driven by liquids throughput volumes as a result of an expansion completed at the end of the first quarter of 2008.
 
Segment earnings before DD&A for this period were adversely impacted by (i) a $676.6 million goodwill impairment charge and (ii) $12.9 million in hurricane and fire damage clean-up, repair and write-offs, net of income tax benefit.
 
Seven Months Ended December 31, 2007
 
Combined, the operations acquired in 2006 and 2007 referred to above contributed earnings before DD&A of $28.4 million, revenues of $73.3 million, operating expenses of $45.4 million and equity earnings of $0.5 million in the seven months ended December 31, 2007. This segment’s earnings benefited from the two large Gulf Coast liquids terminal facilities located along the Houston Ship Channel in Pasadena and Galena Park, Texas, which contributed $18.1 million of combined earnings before DD&A. The two terminals continued to benefit from both recent expansions that have added new liquids tank and truck loading rack capacity since 2006 and business from ethanol and biodiesel storage and transfer activity. Strong earnings during the period also resulted from (i) $12.1 million of earnings before DD&A contributed from the combined operations of the Argo and Chicago, Illinois liquids terminals, due to strong ethanol throughput and increased capacity in the liquids storage and handling business, (ii) $30.9 million of earnings before DD&A contributed from the Texas Petcoke terminals, due largely to strong demand for petroleum coke at the Port of Houston facility and (iii) $5.5 million of earnings before DD&A contributed from the Pier IX bulk terminal, located in Newport News, Virginia, largely due to a favorable demand for coal transfers and increasing rail incentives.
 
Five Months Ended May 31, 2007
 
Acquisitions in 2006 and 2007 as described above contributed $2.8 million in earnings before DD&A during the five months ended May 31, 2007 were composed of (i) $2.0 million from Transload Services, LLC and (ii) $0.8 million from Devco USA L.L.C. Segment earnings before DD&A also included strong earnings contributions consisting of (i) $5.9 million from Kinder Morgan Energy Partners’ Shipyard River terminal located in Charleston, South Carolina; (ii) $17.3 million from the Lower Mississippi (Louisiana) terminals (which include its 66 2/3% ownership interest in the International Marine Terminals partnership and the Port of New Orleans liquids facility located in Harvey, Louisiana) and (iii) $7.8 million from the combined operations of its Argo and Chicago, Illinois liquids terminals. The increases from the Shipyard River terminal related to completed expansion projects since the middle of 2006 that increased handling capacity for imported coal volumes and the earnings increases from the Chicago liquids facilities were driven by higher revenues, due to increased ethanol throughput and incremental liquids storage and handling business.
 
Year Ended December 31, 2006
 
Combined, the terminal acquisitions in 2005 and 2006, mentioned above, accounted for incremental amounts of earnings before DD&A of $33.5 million, revenues of $68.8 million and operating expenses of $35.3 million, respectively, in 2006. A majority of these increases in earnings, revenues, and expenses were attributable to the inclusion of the Texas petcoke terminals, which were acquired from Trans-Global Solutions, Inc. on April 29, 2005.
 
The segment’s earnings before DD&A also benefited from (i) a solid revenue stream from the Pasadena and Galena Park Gulf Coast liquids terminals, driven by new and incremental customer agreements, additional liquids tank capacity from capital expansions completed at the Pasadena terminal since the end of 2005, increased truck loading rack service fees during the period, strong demand from ethanol throughput and revenues from customer deficiency charges, (ii) strong revenues from liquids warehousing and coal and cement handling at the Shipyard River terminal, located in Charleston, South Carolina, (iii) strong demand for petroleum coke handling from the Texas Petcoke terminals and (iv) contributions from the Lower Mississippi River (Louisiana) terminals, primarily due to incremental earnings from the Amory and DeLisle Mississippi bulk terminals. The Amory terminal began operations in July 2005. The earnings from the DeLisle terminal resulted from solid bulk transfer revenues in 2006.
 

 
66
 
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)
Knight Form 10-K


 
 
Successor Company
    
Predecessor Company
 
Year Ended
December 31,
2008
  
Seven Months
Ended
December 31,
2007
    
Five Months
Ended
May 31, 2007
  
Year Ended
December 31,
2006
 
(In millions, except operating statistics)
    
(In millions, except operating statistics)
Operating Revenues
$
198.9
    
$
100.9
      
$
62.0
    
$
140.8
  
Operating Expenses
  
(68.0
)
    
(44.3
)
      
(23.1
)
    
(54.9
)
Earnings from Equity Investment
  
8.3
      
14.4
        
5.4
      
17.2
  
Other Income (Expense)1
  
-
      
-
        
(377.1
)
    
0.9
  
Interest Income and Other Income (Expense), Net2
  
(6.2
)
    
6.3
        
1.7
      
1.0
  
Income Tax Benefit (Expense)3
  
19.0
      
(18.5
)
      
(0.9
)
    
(9.9
)
Segment Earnings (Loss) Before DD&A
$
152.0
    
$
58.8
      
$
(332.0
)
  
$
95.1
  
  
                                
Operating Statistics
                                
Transport Volumes (MMBbl)
  
86.7
      
58.0
        
36.4
      
83.7
  
__________
1
Amount for the five months ended May 31, 2007 represents a non-cash goodwill impairment charge; see Note 3 of the accompanying Notes to Consolidated Financial Statements.
2
2008 amount includes a $12.3 million expense due to certain non-cash Trans Mountain regulatory accounting adjustments.
3
2008 amount includes a $19.3 million decrease in expense associated with favorable changes in Canadian income tax rates and a $6.6 million increase in expense due to certain non-cash Trans Mountain regulatory accounting adjustments.
 
The information in the table above reflects the results of operations for the seven months ended December 31, 2007, five months ended May 31, 2007 and year ended December 31, 2006 as though the transfer of the Trans Mountain one-third interest in Express and Jet Fuel to Kinder Morgan Energy Partners had occurred at the beginning of the period (January 1, 2006).
 
Year Ended December 31, 2008
 
In addition to the $12.7 million net favorable impact in Canadian income taxes described in footnote 3 to the table above, earnings before DD&A for the year ended December 31, 2008 include strong operating revenues resulting from the April 2007 completion of an expansion project that included the commissioning of ten new pump stations that boosted capacity on Trans Mountain from 225,000 to approximately 260,000 barrels per day, and to the April 28, 2008 partial completion of the first portion of the Anchor Loop expansion that boosted pipeline capacity from 260,000 to 285,000 barrels per day and resulted in higher period-to-period average toll rates. Kinder Morgan Energy Partners completed construction on a final 15,000 barrels per day expansion on October 30, 2008 and total pipeline capacity is now approximately 300,000 barrels per day.
 
Seven Months Ended December 31, 2007
 
During seven months ended December 31, 2007, segment earnings before DD&A were positively impacted by the completion of a pump station expansion on April 30, 2007 and its associated positive impact to revenue for the period.
 
Five Months Ended May 31, 2007
 
During the five months ended May 31, 2007, earnings before DD&A were adversely affected by a $377.1 million goodwill impairment charge recorded against the Trans Mountain asset. Slightly offsetting this negative impact to earnings was the completion of a pump station expansion on April 30, 2007 and its associated positive impact to revenue for the period.
 
Year Ended December 31, 2006
 
 
In 2006, Kinder Morgan Canada–KMP started the expansion of the Trans Mountain pipeline system, which is discussed above.
 

 
67
 
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)
Knight Form 10-K


 
 
Successor Company
    
Predecessor Company
 
Year Ended
December 31,
2008
  
Seven Months
Ended
December 31,
2007
    
Five Months
Ended
May 31, 2007
  
Year Ended
December 31,
2006
 
(In millions)
    
(In millions)
Knight Inc. General and Administrative Expense
$
(54.6
)
  
$
(33.2
)
    
$
(138.6
)
  
$
(36.9
)
Kinder Morgan Energy Partners General and Administrative Expense
  
(297.9
)
    
(142.4
)
      
(136.2
)
    
(238.4
)
Terasen General and Administrative Expenses
  
-
      
-
        
(8.8
)
    
(29.8
)
Consolidated General and Administrative Expense
$
(352.5
)
  
$
(175.6
)
    
$
(283.6
)
  
$
(305.1
)

Year Ended December 31, 2008
 
“General and Administrative Expense” for the year ended December 31, 2008 of $352.5 million primarily consists of (i) $209.7 million of Kinder Morgan Energy Partners compensation expense, (ii) $57.8 million of Kinder Morgan Energy Partners outside services and (iii) $45.1 million incurred by Knight, Inc. general and administrative expenses related to Natural Gas Pipeline Company of America LLC (“NGPL G&A”).  $6.2 million of the $45.1 million NGPL G&A was incurred during the period prior to the sale of an 80% interest in NGPL PipeCo LLC, January 1, 2008 through February 14, 2008, and the remaining $38.9 million was incurred subsequent to February 15, 2008 and billed to Natural Gas Pipeline Company of America LLC; see Note 7 in the accompanying Notes to Consolidated Statements for more information.
 
Seven Months Ended December 31, 2007
 
“General and Administrative Expense” for the seven months ended December 31, 2007 includes $33.2 million of Knight Inc. general and administrative expense, primarily associated with $19.4 million of compensation expense and $142.4 million of Kinder Morgan Energy Partners general and administrative expense, primarily associated with $108.6 million of compensation expense and $28.8 million of outside services.
 
Five Months Ended May 31, 2007
 
“General and Administrative Expense” for the five months ended May 31, 2007 includes a total of $141.0 million related to the going private transaction, consisting of $114.8 million expensed by Knight Inc. and $26.2 million allocated to Kinder Morgan Energy Partners. In addition, during the five months ended May 31, 2007 we incurred $4.3 million in selling expenses associated with the sale of our (i) U.S. based retail natural gas distribution and related operations, (ii) Terasen Gas business and (iii) Terasen Pipelines (Corridor) Inc.
 
Year Ended December 31, 2006
 
“General and Administrative Expense” for the year ended December 31, 2006 includes $36.9 million of Knight Inc. general and administrative expense, primarily associated with $19.5 million of compensation expense and $238.4 million of Kinder Morgan Energy Partners general and administrative expense, primarily associated with $144.3 million of compensation expense and $46.8 million of outside services.
 
Kinder Morgan Energy Partners’ and Knight Inc.’s general and administrative expenses tend to increase over time in large part because the expansion of their businesses through acquisitions and internal growth requires the hiring of additional employees, resulting in increased payroll and other employee-related expense.
 

 
68
 
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)
Knight Form 10-K


 
 
Successor Company
    
Predecessor Company
 
Year Ended
December 31,
2008
  
Seven Months
Ended
December 31,
2007
    
Five Months
Ended
May 31, 2007
  
Year Ended
December 31,
2006
 
(In millions)
    
(In millions)
Interest Expense, Net
$
(633.4
)
  
$
(581.5
)
    
$
(241.1
)
  
$
(552.8
)
Interest Income (Expense) – Deferrable Interest Debentures2
  
5.1
      
(12.8
)
      
(9.1
)
    
(21.9
)
Consolidated Interest Expense
  
(628.3
)
    
(594.3
)
      
(250.2
)
    
(574.7
)
                                 
Minority Interests
                                
Kinder Morgan Management
  
(80.5
)
    
(35.8
)
      
(17.1
)
    
(65.9
)
Kinder Morgan Energy Partners
  
(302.4
)
    
7.3
        
(75.1
)
    
(300.8
)
Triton
  
(13.0
)
    
(9.0
)
      
2.3
      
(7.3
)
Other
  
(0.2
)
    
(0.1
)
      
(0.8
)
    
(0.2
)
Consolidated Minority Interests Expense
  
(396.1
)
    
(37.6
)
      
(90.7
)
    
(374.2
)
                                 
Loss on Mark-to-market Interest Rate Swaps
  
-
      
-
        
-
      
(22.3
)
Other1
  
4.7
      
7.9
        
(7.3
)
    
3.0
  
 
$
(1,019.7
)
  
$
(624.0
)
    
$
(348.2
)
  
$
(968.2
)
__________
1
“Other” represents offset to minority interest and interest income shown above and included in segment earnings.
2
2008 amount includes $11.3 million gain on retirement, offset by $5.751 million interest expense and $0.5 million of accounting expense.
 
“Interest Expense, Net” for the year ended December 31, 2008 includes (i) $388.2 million of Kinder Morgan Energy Partners interest expense and (ii) $240.1 million of Knight Inc. interest expense. Kinder Morgan Energy Partners interest expense tends to increase over time as it incurs additional debt to fund its capital spending and its acquisition of new assets and businesses. Knight Inc.’s interest expense was affected by reduced debt levels, primarily related to the application of the proceeds from the sale of an 80% interest in NGPL PipeCo LLC to reduce outstanding debt.
 
“Interest Expense, Net” for the seven months ended December 31, 2007 includes (i) $179.6 million of interest expense related to additional debt incurred as part of the going private transaction, (ii) $236.4 million of Kinder Morgan Energy Partners interest expense and (iii) $165.5 million of Knight Inc. interest expense not related to the going private transaction.
 
“Interest Expense, Net” for the five months ended May 31, 2007 includes (i) $155.0 million of Kinder Morgan Energy Partners interest expense and (ii) $86.1 million of Knight Inc. interest expense.
 
“Interest Expense, Net” for the year ended December 31, 2006 includes (i) $333.4 million of Kinder Morgan Energy Partners interest expense, (ii) $157.8 million of Knight Inc. interest expense and (iii) $67.8 million related to Terasen.
 
During the first quarter of 2006, we recorded a pre-tax charge of $22.3 million ($14.1 million after tax) related to the financing of the Terasen acquisition. The charge was necessary because certain hedges put in place related to the debt financing for the acquisition did not qualify for hedge treatment under GAAP, thus requiring that they be marked-to-market, resulting in a non-cash charge to income. These hedges have now been effectively terminated (see Note 15 of the accompanying Notes to Consolidated Financial Statements).
 
Minority interest expense associated with Kinder Morgan Management for the year ended December 31, 2008, seven months ended December 31, 2007, five months ended May 31, 2007 and year ended December 31, 2006 was $80.5 million, $35.8 million, $17.1 million and $65.9 million, respectively. Minority interest expense reflects the earnings recorded by Kinder Morgan Management that are attributed to its shares held by the public. Kinder Morgan Management’s earnings are solely dependent on its ownership of Kinder Morgan Energy Partnership i-units. Therefore, our minority interest expense associated with Kinder Morgan Management is a function of Kinder Morgan Energy Partners’ earnings and the shares of Kinder Morgan Management, which are held by the public. As of December 31, 2008, December 31, 2007 and May 31, 2007 we owned approximately 14.3% of Kinder Morgan Managements’ outstanding shares. As of December 31, 2006 we owned approximately 16.5% of Kinder Morgan Managements’ outstanding shares.
 
Minority interest expense (income) associated with Kinder Morgan Energy Partners for the year ended December 31, 2008, seven months ended December 31, 2007, five months ended May 31, 2007 and year ended December 31, 2006 was $302.4 million, ($7.3) million, $75.1 million and $300.8 million, respectively. Minority interest expense (income) reflects the earnings (loss) from continuing operations recorded by Kinder Morgan Energy Partners that are attributed to its units held by
 

 
69
 
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)
Knight Form 10-K


the public. During the seven months ended December 31, 2007, $141.6 million of minority interest expense associated with Kinder Morgan Energy Partners’ North System, which was sold by Kinder Morgan Energy Partners in October 2007, was recorded in discontinued operations rather than minority interests from continuing operations. See Note 11 of the accompanying Notes to Consolidated Financial Statements.
 
 
Year Ended December 31, 2008
 
The year ended December 31, 2008 income tax expense from continuing operations of $304.3 million consists of (i) $261.4 million of federal income tax expense, (ii) $44.9 million related to Kinder Morgan Management minority interest income tax expense, (iii) $11.7 million attributable to the net tax effects of consolidating Kinder Morgan Energy Partners’ United States income tax provision, (iv) $22.2 million of prior period adjustments, (v) $17.0 million of state income taxes and (vi) $15.3 million of other income tax items. These income tax expenses were offset by $68.2 million benefit primarily due to the termination of certain of our subsidiaries’ presence in Canada, resulting in the elimination of future taxable gains and a reduction in Canadian foreign tax rates.
 
Seven Months Ended December 31, 2007
 
The seven months ended December 31, 2007 income tax expense from continuing operations of $227.4 million consists of (i) $166.5 million of federal income tax expense, (ii) $12.8 million related to Kinder Morgan Management minority interest income tax expense, (iii) $ 27.6 million due to income taxes on foreign earnings at different tax rates, (iv) $11.9 million attributable to the net tax effects of consolidating Kinder Morgan Energy Partners’ United States income tax provision and (v) $10.9 million of state income taxes. The above income tax expense is net of $2.3 million of other income tax items.
 
Five Months Ended May 31, 2007
 
The five months ended May 31, 2007 income tax expense from continuing operations of $135.5 million consists of (i) $34.0 million federal income tax benefit on the $97.2 million loss from continuing operations before income taxes, (ii) $16.6 million tax benefit from the Terasen acquisition financing structure and (iii) $2.0 million of other income tax items. These tax benefits and credits were offset by income tax expenses consisting of (i) $30.7 million of income taxes on non-deductible fees associated with the Going Private transaction, (ii) $132.1 million of expense related to the Trans Mountain goodwill impairment of $377.1 million, which is not deductible for tax purposes, (iii) $6.2 million related to Kinder Morgan Management minority interest income tax expense, (iv) $8.4 million due to income taxes on foreign earnings at different tax rates, (v) $4.0 million attributable to the net tax effects of consolidating Kinder Morgan Energy Partners’ United States income tax provision and (vi) $6.7 million of state income taxes.
 
Year Ended December 31, 2006
 
The year ended December 31, 2006 income tax expense from continuing operations of $285.9 million consists of (i) $309.8 million of federal income tax expense, (ii) $23.9 million related to Kinder Morgan Management minority interest income tax expense, (iii) $23.0 million due to income taxes on foreign earnings at different tax rates, (iv) $12.4 million attributable to the net tax effects of consolidating Kinder Morgan Energy Partners’ United States income tax provision and (v) $15.0 million of state income taxes. These income tax expenses were offset by the following tax benefits and credits: (i) a $45.1 million tax benefit from the Terasen acquisition financing structure, (ii) a $38.1 million tax benefit from a change in our deferred tax rates and (iii) a $15.0 million of other income tax items.
 
See Note 13 of the accompanying Notes to Consolidated Financial Statements for additional information on income taxes.
 
 
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. We closed the sale of Terasen Inc. to Fortis Inc. on May 17, 2007, for sales proceeds of approximately $3.4 billion (C$3.7 billion) including cash and assumed debt. We recorded a book gain on this disposition of $55.7 million in the second quarter of 2007. The sale resulted in a capital loss of $998.6 million for tax purposes. Approximately $223.3 million of the Terasen Inc. capital loss was utilized to reduce capital gain principally associated with the sale of our U.S.-based retail natural gas operations resulting in a tax benefit of approximately $82.2 million during 2007.
 
At December 31, 2007, we had a remaining capital loss carryforward of $775.1 million, all of which was utilized to reduce the capital gain associated with the sale of our 80% ownership interest in the NGPL business segment and other dispositions, resulting in a tax benefit of approximately $279.5 million during 2008.
 

 
70
 
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)
Knight Form 10-K


 
Liquidity
 
We believe that we and our subsidiaries and investments, including Kinder Morgan Energy Partners, have liquidity and access to financial resources as discussed below sufficient to meet future requirements for working capital, debt repayment and capital expenditures associated with existing and future expansion projects as follows:
 
 
·
Cash flow from operations
Our diverse set of energy infrastructure assets generated $1,397.6 million of cash flows from continuing operations for the year ended December 31, 2008. Additionally, Kinder Morgan Energy Partners expansion projects in aggregate are expected to generate positive returns on our investment, based on long-term contracted customer commitments and our current estimated expansion project costs.
 
·
Credit facility availability
As of December 31, 2008, Knight Inc. had available credit capacity of $929.2 million and Kinder Morgan Energy Partners had available credit capacity of $1,473.7 million after reduction for (i) our letters of credit, (ii) commercial paper outstanding (none at December 31, 2008) and (iii) lending commitments made by a Lehman Brothers related bank (see Customer and Capital Market Liquidity). Kinder Morgan Energy Partners’ joint venture projects, Rockies Express Pipeline LLC, Midcontinent Express Pipeline LLC and Cortez Capital Corporation, have undrawn capacity of $366.6 million, $429.2 million and $9.0 million, respectively, under their separate credit facilities, net of Lehman Brothers’ commitments (see Customer and Capital Market Liquidity).
 
·
Long-term debt and equity markets
During the year ended December 31, 2008, Kinder Morgan Energy Partners, for itself and for its equity investment, Rockies Express Pipeline LLC, collectively has raised $3.4 billion of long-term debt and $676.9 million of equity through the issuance of Kinder Morgan Energy Partners units. Including the quarterly share distributions paid by Kinder Morgan Management in 2008, which essentially constitute an automatic distribution re-investment program, a total of approximately $966.5 million in equity was raised during this timeframe.
 
·
Kinder Morgan Energy Partners equity infusion
Additionally, in October 2008, our board of directors indicated Knight Inc’s willingness to purchase up to $750 million of Kinder Morgan Energy Partners equity over the next 15 months, if necessary, to support its capital raising efforts.
 
·
Credit Ratings
On October 13, 2008, Standard and Poor’s Rating Services revised its outlook on Kinder Morgan Energy Partners’ long-term credit rating to negative from stable (but affirmed Kinder Morgan Energy Partners’ long-term credit rating at BBB), due to Kinder Morgan Energy Partners’ previously announced expected delay and cost increases associated with the completion of the Rockies Express Pipeline project. At the same time, Standard and Poor’s Rating Services lowered Kinder Morgan Energy Partners, Rockies Express Pipeline LLC and Cortez Capital Corporation’s short-term credit rating to A-3 from A-2. As a result of this revision and current commercial paper market conditions, Kinder Morgan Energy Partners, Rockies Express Pipeline LLC and Cortez Capital Corporation are unable to access commercial paper borrowings. However, Kinder Morgan Energy Partners, Rockies Express Pipeline LLC and Cortez Capital Corporation expect that short-term financing and liquidity needs will continue to be met through borrowings made under their respective bank credit facilities. Knight Inc.’s Standard and Poor’s Rating Services credit rating has not changed in the year ended December 31, 2008 and remains BB on its secured senior debt.
 
Customer and Capital Market Liquidity
 
Some of Kinder Morgan Energy Partners’ customers are experiencing, or may experience in the future, severe financial problems that have had or may have a significant impact on their creditworthiness. These financial problems may arise from the current credit market crisis, changes in commodity prices or otherwise. Kinder Morgan Energy Partners is working to implement, to the extent allowable under applicable contracts, tariffs and regulations, prepayments and other security requirements, such as letters of credit, to enhance their credit position relating to amounts owed from these customers. Knight Inc. and Kinder Morgan Energy Partners cannot provide assurance that one or more of Kinder Morgan Energy Partners’ financially distressed customers will not default on their obligations to them or that such a default or defaults will not have a material adverse effect on Kinder Morgan Energy Partners’ business, or Knight Inc.’s financial position, future results of operations, or future cash flows; however, Knight Inc. believes it has recorded adequate allowances for such customers.
 
On September 15, 2008, Lehman Brothers Holdings Inc. filed for bankruptcy protection under the provisions of Chapter 11 of the U.S. Bankruptcy Code. One Lehman entity was a lending institution that provided a portion of Kinder Morgan Energy Partners’, Rockies Express Pipeline LLC’s and Midcontinent Express Pipeline LLC’s respective credit facilities. Since Lehman Brothers declared bankruptcy, its affiliate, which is party to the credit facilities, has not met its obligations to lend under those agreements. As such, the commitments have been effectively reduced by $63 million, $41 million and $100
 

 
71
 
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)
Knight Form 10-K


million, respectively, to $1.8 billion, $2.0 billion and $1.3 billion. The commitments of the other banks remain unchanged, and the facilities are not defaulted.
 
Invested Capital
 
Our net debt (outstanding notes and debentures plus short-term debt, less cash and cash equivalents) to total capital, excluding accumulated other comprehensive income, for the years ended December 31, 2008 and 2007 was 56.4% and 56.9%, respectively. Our net debt to total capital ratio was principally impacted by debt reductions made possible by $5.9 billion in total proceeds related to the sale of an 80% ownership interest in NGPL PipeCo LLC, which proceeds were used to pay off the entire outstanding balances of our senior secured credit facility’s Tranche A and Tranche B term loans (approximately $4.2 billion), to repurchase $1.67 billion par value of our outstanding debt securities and to reduce borrowings outstanding under our $1.0 billion revolving credit facility. This increase was partially offset by a $4.03 billion non-cash goodwill impairment charge associated with the Going Private transaction (see Note 3 of the accompanying Notes to Consolidated Financial Statements) as well as $2.1 billion in additional borrowings by Kinder Morgan Energy Partners during 2008.
 
In addition to the direct sources of debt and equity financing, we obtain financing indirectly through our ownership interests in unconsolidated entities as discussed in Note 18 of the accompanying Notes to Consolidated Financial Statements. In addition to our results of operations, these balances are affected by our financing activities as discussed following.
 
Except for Kinder Morgan Energy Partners and its subsidiaries, we employ a centralized cash management program that essentially concentrates the cash assets of our subsidiaries in joint accounts for the purpose of providing financial flexibility and lowering the cost of borrowing. Our centralized cash management program provides that funds in excess of the daily needs of our subsidiaries be concentrated, consolidated, or otherwise made available for use by other entities within our consolidated group. We place no restrictions on the ability to move cash between entities, payment of intercompany balances or the ability to upstream dividends to parent companies other than restrictions that may be contained in agreements governing the indebtedness of those entities; provided that neither we nor our subsidiaries (other than Kinder Morgan Energy Partners and its subsidiaries) have rights with respect to the cash of Kinder Morgan Energy Partners or its subsidiaries except as permitted by Kinder Morgan Energy Partners’ partnership agreement.
 
In addition, certain of our operating subsidiaries are subject to FERC-enacted reporting requirements for oil and natural gas pipeline companies that participate in cash management programs. FERC-regulated entities subject to these rules must, among other things, place their cash management agreements in writing, maintain current copies of the documents authorizing and supporting their cash management agreements, and file documentation establishing the cash management program with the FERC.
 
Short-term Liquidity
 
Our principal sources of short-term liquidity are our revolving bank facilities and cash provided by operations. The following represents the revolving credit facilities that were available to Knight Inc. and its respective subsidiaries, short-term debt outstanding under the credit facilities and available borrowing capacity under the facilities after applicable letters of credit.
 
 
At December 31, 2008
  
At February 23, 2009
 
Short-term
Debt
Outstanding
  
Available
Borrowing
Capacity
  
Short-term
Debt
Outstanding
  
Available
Borrowing
Capacity
 
(In millions)
Credit Facilities
                      
Knight Inc.
                      
$1.0 billion, six-year secured revolver, due May 2013
$
8.8
  
$
929.2
  
$
23.0
  
$
914.1
Kinder Morgan Energy Partners
                      
$1.85 billion, five-year unsecured revolver, due August 2010
$
-
  
$
1,473.7
  
$
527.6
  
$
1,022.4

These facilities can be used for the respective entity’s general corporate or partnership purposes. Kinder Morgan Energy Partners’ facility is also used as backup for its commercial paper program. These facilities include financial covenants and events of default that are common in such arrangements. The terms of these credit facilities are discussed in Note 14 of the accompanying Notes to Consolidated Financial Statements.
 
Our current maturities of long-term debt of $293.7 million at December 31, 2008 represent (i) $250 million in principal amount of Kinder Morgan Energy Partners’ 6.30% senior notes due February 1, 2009, (ii) $23.7 million in principal amount of tax-exempt bonds that mature on April 1, 2024, but are due on demand pursuant to certain standby purchase agreement provisions contained in the bond indenture (Kinder Morgan Energy Partners’ subsidiary Kinder Morgan Operating L.P. “B” is the obligor on the bonds), (iii) $5.0 million of our 6.50% Series Debentures due September 1, 2013, (iv) $8.5 million of a
 

 
72
 
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)
Knight Form 10-K


5.40% long-term note of Kinder Morgan Operating L.P. “A” and Kinder Morgan Canada Company due March 31, 2009 and (v) $6.5 million of Kinder Morgan Texas Pipeline, L.P.’s 5.23% Series Notes due January 2, 2014. Apart from our notes payable, current maturities of long-term debt, and the fair value of derivative instruments, our current liabilities, net of our current assets, represent an additional short-term obligation of $380.7 million at December 31, 2008. Given our expected cash flows from operations, our unused debt capacity as discussed preceding, including our credit facilities, and based on our projected cash needs in the near term, we do not expect any liquidity issues to arise.
 
Significant Financing Transactions
 
For additional information on significant financing Transactions, see Note 14 of the accompanying Notes to Consolidated Financial Statements.
 
During 2008, we used the proceeds from the completed sale of an 80% ownership interest in our NGPL business segment to repurchase $1.67 billion par value debt securities and to pay off the balances of our Tranche A and Tranche B term loans, and amounts outstanding, at the time, of our $1.0 billion revolving credit facility totaling approximately $4.6 billion. In June 2007, we repaid the outstanding borrowings under the Tranche C term facility.
 
Kinder Morgan Energy Partners completed three offerings of senior notes during the year ended December 31, 2008, two offerings during the seven months ended December 31, 2007 and one offering during the five months ended May 31, 2007, raising a total (net of underwriting discounts and commissions) of $2,080.2 million, $1,041.7 million and $992.8 million, respectively. During the seven months ended December 31, 2007, Kinder Morgan Energy Partners also repaid $250 million of senior notes. Kinder Morgan Energy Partners used the proceeds from each of the three 2007 debt offerings and from the first two 2008 debt offerings to reduce the borrowings under Kinder Morgan Energy Partners’ commercial paper program. Kinder Morgan Energy Partners used the proceeds from its December 2008 debt offering to reduce the borrowings under its credit facility.
 
Kinder Morgan Energy Partners completed four offerings of common units during the year ended December 31, 2008, which raised a total of $676.9 million, net of underwriting discounts and commissions. For the seven months ended December 31, 2007 and five months ended May 31, 2007, Kinder Morgan Energy Partners raised a total (net of underwriting costs and commissions) of $342.9 million and $297.9 million, respectively, from the issuance of common units. Proceeds from these issuances were used to reduce borrowings under the commercial paper program and bank credit facility.
 
On July 27, 2007, Kinder Morgan G.P., Inc. sold 100,000 shares of its $1,000 Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock due 2057 to a single purchaser. We used the net proceeds of approximately $98.6 million after the initial purchaser’s discounts and commissions to reduce debt.
 
As discussed in Note 11 of the accompany Notes to Consolidated Financial Statements, on March 5, 2007 we entered into a definitive agreement to sell Terasen Pipelines (Corridor) Inc. and on February 26, 2007, we entered into a definitive agreement to sell Terasen Inc., which includes the assets of Terasen Gas Inc. and Terasen Gas (Vancouver Island) Inc. These transactions closed on June 15, 2007 and May 17, 2007, respectively. Our consolidated debt was reduced by the debt balances of Terasen Inc. and Terasen Pipelines (Corridor) Inc. of approximately $2.9 billion, including the Capital Securities, as a result of these sales transactions. For the period from January 1, 2007 to May 17, 2007, average borrowings under Terasen Gas Vancouver Island Inc.’s C$350 million credit facility were $255.1 million at a weighted-average rate of 4.43%. For the period from January 1, 2007 to May 17, 2007, average borrowings under the C$20 million demand facility were $3.3 million at a weighted-average rate of 5.31%.
 
On May 30, 2007, investors led by Richard D. Kinder, our Chairman and Chief Executive Officer, completed the Going Private transaction. In conjunction with the Going Private transaction, Knight Inc. entered into a $5.755 billion credit agreement dated May 30, 2007, which included three term credit facilities, which were subsequently retired, and one revolving credit facility. See Notes 1 and 14 of the accompanying Notes to Consolidated Financial Statements for additional information related to the Going Private transaction and the associated debt and debt retirement.
 
On May 7, 2007, we retired our $300 million 6.80% senior notes due March 1, 2008 at 101.39% of the face amount. We recorded a pre-tax loss of $4.2 million in connection with this early extinguishment of debt.
 
Effective January 1, 2007, Kinder Morgan Energy Partners acquired the remaining approximate 50.2% interest in the Cochin pipeline system that Kinder Morgan Energy Partners did not already own (see Note 10 of the accompanying Notes to Consolidated Financial Statements). As part of Kinder Morgan Energy Partners’ purchase price, two of its subsidiaries issued a long-term note payable to the seller having a fair value of $42.3 million. Kinder Morgan Energy Partners’ subsidiaries, Kinder Morgan Operating L.P. “A” and Kinder Morgan Canada Company, are the obligors on the note and, as of December 31, 2008, the outstanding balance under the note was $36.6 million.
 

 
73
 
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)
Knight Form 10-K


Capital Expenditures
 
Our sustaining capital expenditures for the year ended December 31, 2008 were $183.9 million, and we expect to spend $203.4 million during 2009. Our sustaining capital expenditures are funded with cash flows from operations.
 
Our expansion capital expenditures for the year ended December 31, 2008 were $2,361.4 million, primarily related to Kinder Morgan Energy Partners. Kinder Morgan Energy Partners expects to spend another $1,188.2 million during 2009. In addition to these amounts, Kinder Morgan Energy Partners contributed an aggregate amount of $333.5 million for both the Rockies Express and Midcontinent Express natural gas pipeline projects in 2008, and it expects to contribute, based on Kinder Morgan Energy Partners’ proportionate share of equity ownership interest in both projects, approximately $1.5 billion in the aggregate for both projects in 2009. Kinder Morgan Energy Partners will fund its 2009 capital expenditures and equity contributions through borrowings under its $1.85 billion revolving credit facility, proceeds from issuance of long term notes and common unit offerings.
 
Off Balance Sheet Arrangements
 
We have invested in entities that are not consolidated in our financial statements. As of December 31, 2008, our obligations with respect to these investments, as well as our obligations with respect to letters of credit, are summarized below (dollars in millions):
 
Entity
  
Investment
Type
  
Our
Ownership
Interest
  
Remaining Interest(s)
Ownership
  
Total Entity
Assets
  
Total Entity
Debt
  
Our
Contingent
Share of
Entity Debt
Cortez Pipeline Company
  
General
Partner
  
50%
  
1
  
$
95.7
2
  
$
169.6
    
$
84.8
3
                                     
West2East Pipeline LLC4
  
Limited
Liability
  
51%
  
ConocoPhillips and
Sempra Energy
  
$
4,787.0
2
  
$
3,458.9
5
  
$
1,102.1
6
  
                                    
Midcontinent Express Pipeline LLC7
  
Limited
Liability
  
50%
  
Energy Transfer
Partners, L.P.
  
$
998.5
2
  
$
837.5
    
$
418.8
8
  
                                    
Nassau County, Florida Ocean Highway And Port Authority9
  
N/A
  
N/A
  
Nassau County,
Florida Ocean
Highway and
Port Authority
    
N/A
      
N/A
    
$
10.2
  
  
                                    
NGPL PipeCo LLC
  
Equity
  
20%
  
Myria Acquisition Inc.
  
$
7,064.5
    
$
3,000.0
    
$
-
10
_________
1
The remaining general partner interests are owned by ExxonMobil Cortez Pipeline, Inc., an indirect wholly owned subsidiary of Exxon Mobil Corporation and Cortez Vickers Pipeline Company, an indirect subsidiary of M.E. Zuckerman Energy Investors Incorporated.
2
Principally property, plant and equipment.
3
We are severally liable for our percentage ownership share (50%) of the Cortez Pipeline Company debt. As of December 31, 2008, Shell Oil Company shares Kinder Morgan Energy Partners’ several guaranty obligations jointly and severally for $53.6 million of Cortez Pipeline Company’s debt balance; however, Kinder Morgan Energy Partners is obligated to indemnify Shell Oil Company for the liabilities Shell Oil Company incurs in connection with such guaranty. Accordingly, as of December 31, 2008 Kinder Morgan Energy Partners has a letter of credit in the amount of $26.8 million issued by JP Morgan Chase, in order to secure its indemnification obligations to Shell Oil Company for 50% of the Cortez Pipeline Company debt balance of $53.6 million.
Further, pursuant to a Throughput and Deficiency Agreement, the partners of Cortez Pipeline Company are required to contribute capital to Cortez Pipeline Company in the event of a cash deficiency. The agreement contractually supports the financings of Cortez Capital Corporation, a wholly owned subsidiary of Cortez Pipeline Company, by obligating the partners of Cortez Pipeline Company to fund cash deficiencies at Cortez Pipeline Company, including anticipated deficiencies and cash deficiencies relating to the repayment of principal and interest on the debt of Cortez Capital Corporation. The partners’ respective parent or other companies further severally guarantee the obligations of the Cortez Pipeline Company owners under this agreement.
4
West2East Pipeline LLC is a limited liability company and is the sole owner of Rockies Express Pipeline LLC. As of December 31, 2008, the remaining limited liability member interests in West2East Pipeline LLC are owned by ConocoPhillips (24%) and Sempra Energy (25%). Kinder Morgan Energy Partners owned a 66 2/3% ownership interest in West2East Pipeline LLC from October 21, 2005 until June 30, 2006, and included West2East Pipeline LLC’s results in its consolidated financial statements until June 30, 2006. On June 30, 2006, Kinder Morgan Energy Partners’ ownership interest was reduced to 51%, West2East Pipeline LLC was deconsolidated, and Kinder Morgan Energy Partners subsequently accounted for its investment under the equity method of accounting. Upon completion of the pipeline,

 
74
 
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)
Knight Form 10-K


 
Kinder Morgan Energy Partners’ ownership percentage is expected to be reduced to 50%.
5
Amount includes an aggregate of $1.3 billion in principal amount of fixed rate senior notes issued by Rockies Express Pipeline LLC in a private offering in June 2008. All payments of principal and interest in respect of these senior notes are the sole obligation of Rockies Express Pipeline LLC. Noteholders have no recourse against Kinder Morgan Energy Partners or the other member owners of West2East Pipeline LLC for any failure by Rockies Express Pipeline LLC to perform or comply with its obligations pursuant to the notes or the indenture.
6
In addition, there is a letter of credit outstanding to support the construction of the Rockies Express Pipeline. As of December 31, 2008, this letter of credit, issued by JPMorgan Chase, had a face amount of $31.4 million. Kinder Morgan Energy Partners’ contingent responsibility with regard to this outstanding letter of credit was $16.0 million (51% of the total face amount).
7
Midcontinent Express Pipeline LLC is a limited liability company and the owner of the Midcontinent Express Pipeline. In January 2008, in conjunction with the signing of additional binding pipeline transportation commitments, Midcontinent Express Pipeline LLC and MarkWest Pioneer, L.L.C. (a subsidiary of MarkWest Energy Partners, L.P.) entered into an option agreement that provides MarkWest Pioneer, L.L.C.  a one-time right to purchase a 10% ownership interest in Midcontinent Express Pipeline LLC after the pipeline is fully constructed and placed into service. If the option is exercised, Kinder Morgan Energy Partners and Energy Transfer Partners, L.P. will each own 45% of Midcontinent Express Pipeline LLC, while MarkWest Pioneer, L.L.C. will own the remaining 10%.
8
In addition, there is a letter of credit outstanding to support the construction of the Midcontinent Express Pipeline. As of December 31, 2008, this letter of credit, issued by the Royal Bank of Scotland plc, had a face amount of $33.3 million. Kinder Morgan Energy Partners’ contingent responsibility with regard to this outstanding letter of credit was $16.7 million (50% of the total face amount).
9
This arrangement rose from Kinder Morgan Energy Partners’ Vopak terminal acquisition in July 2001. Nassau County, Florida Ocean Highway and Port Authority is a political subdivision of the state of Florida. During 1990, Ocean Highway and Port Authority issued its Adjustable Demand Revenue Bonds in the aggregate principal amount of $38.5 million for the purpose of constructing certain port improvements located in Fernandino Beach, Nassau County, Florida. A letter of credit was issued as security for the Adjustable Demand Revenue Bonds and was guaranteed by the parent company of Nassau Terminals LLC, the operator of the port facilities. In July 2002, Kinder Morgan Energy Partners acquired Nassau Terminals LLC and became guarantor under the letter of credit agreement. In December 2002, Kinder Morgan Energy Partners issued a $28 million letter of credit under its credit facilities and the former letter of credit guarantee was terminated. As of December 31, 2008, the face amount of this letter of credit outstanding under Kinder Morgan Energy Partners’ credit facility was $10.2 million. Principal payments on the bonds are made on the first of December each year at which time reductions are made to the letter of credit.
10
Debtors have recourse only to the assets of the entity, not the owners.
 
 
Aggregate Contractual Obligations
 
 
Aggregate Contractual Obligations
At December 31, 2008
 
 
Total
  
Less than
1 year
  
2-3 years
  
4-5 years
  
After 5 years
 
(In millions)
Contractual Obligations
                            
Short-term Borrowings
$
8.8
  
$
8.8
  
$
-
  
$
-
  
$
-
Long-term Debt, Including Current Maturities:
                            
Principal Payments
  
11,514.5
    
293.7
    
1,743.8
    
2,814.8
    
6,662.2
Interest Payments1
  
9,252.5
    
717.5
    
1,349.4
    
1,062.4
    
6,123.2
Lease Obligations2,3
  
664.7
    
57.5
    
103.4
    
85.4
    
418.4
Pension and Postretirement Benefit Plans
  
90.5
    
25.1
    
10.7
    
12.2
    
42.5
Other Obligations6
  
15.1
    
8.3
    
6.8
    
-
    
-
Total Contractual Cash Obligations4
$
21,546.1
  
$
1,110.9
  
$
3,214.1
  
$
3,974.8
  
$
13,246.3
  
                            
Other Commercial Commitments
                            
Standby Letters of Credit5
$
405.8
  
$
335.3
  
$
25.7
  
$
26.8
  
$
18.0
Capital Expenditures7
$
581.0
  
$
581.0
  
$
-
  
$
-
  
$
-
__________
1
Interest payments have not been adjusted for any amounts receivable related to our interest rate swaps outstanding. See Item 7A, “Quantitative and Qualitative Disclosures About Market Risk.”
2
Represents commitments for operating leases.

 
75
 
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)
Knight Form 10-K


3
Approximately $437.6 million, $20.6 million, $41.4 million, $40.7 million and $334.9 million in each respective column is attributable to the lease obligation associated with the Jackson, Michigan power generation facility.
4
As of December 31, 2008, the liability for uncertain income tax positions, excluding associated interest and penalties, was $26.2 million pursuant to FASB Interpretation No. 48. This liability represents an estimate of tax positions that we have taken in our tax returns, which may ultimately not be sustained upon examination by the tax authorities. Since the ultimate amount and timing of any future cash settlements cannot be predicted with reasonable certainty, this estimated liability has been excluded from the Aggregate Contractual Obligations.
5
See Note 18 of the accompanying Notes to Consolidated Financial Statements for a listing of letters of credit outstanding as of December 31, 2008.
6
Consists of payments due under carbon dioxide take-or-pay contracts and, for the 1 Year or Less column only, Kinder Morgan Energy Partners’ purchase and sale agreement with LPC Packaging (a California corporation) for the acquisition of certain bulk terminal assets.
7
Represents commitments for the purchase of property, plant and equipment at December 31, 2008.
 
We expect to have sufficient liquidity to satisfy our near-term obligations through the combination of free cash flow and our credit facilities, including those of Kinder Morgan Energy Partners.
 
Contingent Liabilities:
  
Contingency
  
Amount of Contingent Liability
at December 31, 2008
Guarantor of the Bushton Gas Processing Plant Lease1
  
Default by ONEOK, Inc.
  
Total $78.8 million; Averages $26.3 million per year through 2011  
         
Jackson, Michigan Power Plant Incremental Investment
  
Operational Performance
  
$3 to $8 million per year for 10 years
         
Jackson, Michigan Power Plant Incremental Investment
  
Cash Flow Performance
  
Up to a total of $25 million beginning in 2018
___________
1
In conjunction with our sale of the Bushton gas processing facility to ONEOK, Inc., at December 31, 1999, ONEOK, Inc. became primarily liable under the associated operating lease and we became secondarily liable. Should ONEOK, Inc. fail to make payments as required under the lease, we would be required to make such payments, with recourse only to ONEOK, Inc.
 
 
At December 31, 2008, we owned, directly, and indirectly in the form of i-units corresponding to the number of shares of Kinder Morgan Management we owned, approximately 32.8 million limited partner units of Kinder Morgan Energy Partners. These units, which consist of 16.4 million common units, 5.3 million Class B units and 11.1 million i-units, represent approximately 12.3% of the total limited partner interests of Kinder Morgan Energy Partners. In addition, we are the sole common stockholder of the general partner of Kinder Morgan Energy Partners, which holds an effective 2% interest in Kinder Morgan Energy Partners and its operating partnerships. Together, our limited partner and general partner interests represented approximately 14.1% of Kinder Morgan Energy Partners’ total equity interests at December 31, 2008. As of the close of the Going Private transaction, our limited partner interests and our general partner interest represented an approximate 50% economic interest in Kinder Morgan Energy Partners. This difference results from the existence of incentive distribution rights held by the general partner shareholder.
 

 
76
 
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)
Knight Form 10-K


 
The following discussion of cash flows should be read in conjunction with the accompanying Consolidated Statements of Cash Flows and related supplemental disclosures. The following discussion is an analysis of the cash flows for the year ended December 31, 2008 and seven months ended December 31, 2007 (both successor basis) and the five months ended May 31, 2007 and year ended December 31, 2006 (both predecessor basis). All highly liquid investments purchased with an original maturity of three months or less are considered to be cash equivalents.
 
The following table summarizes our net cash flows from operating, investing and financing activities for each period presented.
 
 
Successor Company
    
Predecessor Company
 
Year Ended
December 31,
2008
  
Seven Months
Ended
December 31,
2007
    
Five Months
Ended
May 31, 2007
  
Year Ended
December 31,
2006
 
(In millions)
    
(In millions)
Net Cash Provided by (Used in)
                                
Operating Activities
$
1,396.8
    
$
1,044.5
      
$
603.0
    
$
1,707.3
  
Investing Activities
  
3,210.0
      
(15,751.1
)
      
723.7
      
(1,795.9
)
Financing Activities
  
(4,628.1
)
    
12,956.8
        
440.9
      
88.7
  
                                 
Effect of Exchange Rate Changes on Cash
  
(8.7
)
    
(2.8
)
      
7.6
      
6.6
  
  
                                
Effect of Accounting Change on Cash
  
-
      
-
        
-
      
12.1
  
  
                                
Cash Balance Included in Assets Held for Sale
  
-
      
(1.1
)
      
(2.7
)
    
(5.6
)
  
                                
Net (Decrease) Increase in Cash and Cash Equivalents
$
(30.0
)
  
$
(1,753.7
)
    
$
1,772.5
    
$
13.2
  

Year Ended December 31, 2008
 
Net cash flows from operating activities during the period were positively affected by (i) net income of $1,076.4 million, after adjustments for non-cash items including, among other things, a $4.0 billion goodwill impairment charge and $16.5 million of Kinder Morgan Energy Partners’ rate reserve adjustments, (ii) $192.0 million of net proceeds received for the early termination of interest rate swap agreements, primarily relating to agreements associated with Kinder Morgan Energy Partners and (iii) distributions received from equity investments of $241.6 million, comprised mainly of (a) $82.9 million of initial distributions received from West2East Pipeline LLC, (b) $43.0 million from Kinder Morgan Energy Partners’ investment in the Express pipeline system, (c) $40.1 million from NGPL PipeCo LLC and (d) $33.3 million from Kinder Morgan Energy Partners’ investment in Red Cedar Gathering Company.
 
Partially offsetting these cash inflows were (i) a $44.9 million use of cash for working capital items, primarily resulting from income tax payments made during the period related to our ongoing operations and the sale of an 80% ownership interest in NGPL PipeCo LLC, (ii) $30.2 million of FERC-mandated reparation payments to certain Kinder Morgan Energy Partners’ Pacific operations’ pipelines for settlements reached with certain shippers on its East Line pipeline and (iii) a $28.0 million increase of gas in underground storage. Significant period-to period variations in cash used or generated from gas in storage transactions are generally due to changes in injection and withdrawal volumes as well as fluctuations in natural gas prices.
 
Net cash flows from investing activities during the period were positively affected by (i) net proceeds of $2,899.3 million from the sale of an 80% ownership interest in NGPL PipeCo LLC, (ii) $3,106.4 million of proceeds received from NGPL PipeCo LLC restricted cash upon the sale to Myria (including approximately $110.0 million we escrowed at the time of the bond closing), (iii) return of capital from equity investments of $98.1 million consisting of $89.1 million and $9.0 million from Midcontinent Express Pipeline LLC and NGPL PipeCo LLC, respectively, (iv) net proceeds received of $111.1 million for the sale of other assets and (v) a $71.0 million decrease in margin deposits.
 
These positive impacts were partially offset by (i) capital expenditures of $2,545.3 million, primarily from Kinder Morgan Energy Partners’ natural gas pipeline projects, including the construction of Kinder Morgan Louisiana Pipeline, the expansion of the Trans Mountain crude oil and refined petroleum products pipeline system and additions to Kinder Morgan Energy Partners’ carbon dioxide producing and delivery operations, (ii) incremental contributions to equity investments of $366.2 million, consisting primarily of (a) a $306.0 million contribution to West2East Pipeline LLC made in February 2008 and (b) contributions of $27.5 million for Kinder Morgan Energy Partners’ share of Midcontinent Express Pipeline LLC construction costs, (iii) a $109.6 million loan to a single customer within Kinder Morgan Energy Partners’ Texas Intrastate Natural Gas Pipeline Group, (iv) acquisitions of $47.6 million and (v) a $7.2 million increase in underground natural gas storage volumes during the period.
 

 
77
 
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)
Knight Form 10-K


Net cash flows used in financing activities during the period were affected by (i) a use of cash of $5,805.4 million for the retirement of long-term debt, primarily for (a) $1.6 billion for a cash tender offer to purchase a portion of our outstanding long-term debt, (b) a $997.5 million use of cash for the retirement of our Tranche A term loan facilities and (c) a $3,191.8 million use of cash for the retirement of our Tranche B term loan facilities, (ii) a net $879.2 million decrease in short-term borrowings relating to our and Kinder Morgan Energy Partners’ credit facilities and (iii) minority interest distributions of $630.3 million, primarily resulting from Kinder Morgan Energy Partners’ distributions to common unit holders.
 
The impact of these factors were partially offset by (i) net proceeds of $2,097.3 million from Kinder Morgan Energy Partners’ debt issuances, (ii) minority interest contributions of $561.5 million, primarily from Kinder Morgan Energy Partners’ issuance of common units from its first and fourth quarter 2008 public offerings, (iii) an increase in cash book overdrafts of $14.5 million and (iv) a $2.7 million increase in short-term advances from unconsolidated affiliates.
 
Seven Months Ended December 31, 2007
 
Net cash flows from operating activities during the period were positively impacted by (i) net income of $762.3 million after adjustments for non-cash items including, among other things, Kinder Morgan Energy Partners’ reparations and reserve adjustments of $140.0 million, (ii) a $104.0 million source of cash for working capital items, (iii) $86.5 million of distributions received from equity investments, (iv) a $51.3 million decrease of gas in underground storage and (v) $49.1 million of payments received from Kinder Morgan Energy Partners’ pipeline customers for future service.
 
Partially offsetting these factors were (i) a $3.2 million use of cash attributable to discontinued operations and (ii) a $2.2 million payment for the termination of interest rate swap agreements.
 
Net cash flows used in investing activities during the period were affected by (i) $11,534.3 million of cash used to purchase Kinder Morgan, Inc. stock in the Going Private transaction, (ii) $3,030.0 million of cash used to invest in NGPL PipeCo LLC restricted deposits, (iii) $1,287.0 million in capital expenditures primarily attributable to Kinder Morgan Energy Partners, (iv) $122.0 million of other acquisitions, (v) incremental margin deposits of $39.3 million and (vi) contributions of $246.4 million to equity investments.
 
These negative impacts were partially offset by (i) $196.6 million of cash provided by discontinued investing activities, primarily from the sale of Corridor, (ii) $301.3 million of net proceeds from the sale of other assets, primarily from the sale of Kinder Morgan Energy Partners’ North System operations and (iii) $10.0 million of proceeds received from the sale of underground natural gas storage volumes.
 
Net cash flows provided by financing activities during the period were principally due to (i) $5,112.0 million of equity contributions from investors in the Going Private transaction, (ii) $4,696.2 million of proceeds, net of issuance costs, received from the issuance of senior secured credit facilities to partially finance the Going Private transaction, (iii) $2,986.3 million of net proceeds from NGPL PipeCo LLC’s issuance of senior notes, (iv) $1,041.7 million of net proceeds from Kinder Morgan Energy Partners’ public debt offerings, (v) $342.9 million of contributions from minority interest owners attributable to Kinder Morgan Energy Partners’ issuance of 7.13 million common units and (vi) $98.6 million of net proceeds from Kinder Morgan G.P., Inc.’s Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock.
 
The impact of these factors was partially offset by (i) a $455 million use of cash for the retirement of our senior secured Tranche C term loan facility, (ii) a $250 million use of cash for a required payment on senior notes of Kinder Morgan Energy Partners, (iii) a $110.75 million use of cash for (a) quarterly payments of $2.5 million on our Tranche A and $8.25 million on our Tranche B term loan facilities and (b) a $100 million voluntary payment on our Tranche B term loan facility, (iv) $181.1 million of cash paid to share-based award holders due to the Going Private transaction, (v) minority interest distributions of $259.6 million, primarily resulting from Kinder Morgan Energy Partners’ distributions to common unit holders, (vi) a net decrease of $52.6 million in short-term debt and (vii) a decrease of $14.0 million in cash book overdrafts.
 
Five months Ended May 31, 2007
 
Net cash flows from operating activities during the period were positively affected by (i) net income of $688.2 million, after adjustments for non-cash items, (ii) $109.8 of cash provided by discontinued operations, (iii) net proceeds of $51.9 million from the termination of interest rate swaps and (iv) $48.2 million of distributions from equity investments.
 
These positive factors were partially offset by (i) a use of cash of $202.9 million for working capital items and (ii) an $84.2 million increase in gas in underground storage.
 
Net cash flows from investing activities during the period were positively impacted by (i) $1,488.2 million of cash from discontinued investing activities, primarily from the sales of our discontinued Terasen and U.S.-based retail operations, (ii) $8.4 million of proceeds received from the sale of underground natural gas storage volumes and (iii) $8.0 million of cash received for property casualty indemnifications.
 

 
78
 
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)
Knight Form 10-K


Partially offsetting these factors were (i) $652.8 million of capital expenditures, (ii) a $54.8 million use of cash for margin deposits, (iii) incremental acquisitions of $42.1 million and (iv) $29.7 million of contributions to equity investments.
 
Net cash flows from financing activities during the period were positively impacted by (i) $992.8 million of net proceeds from Kinder Morgan Energy Partners’ public debt offerings, (ii) $297.9 million of proceeds from the issuance of Kinder Morgan Management shares, (iii) $140.1 million of cash provided from discontinued financing activities, (iii) $56.7 million of cash received for excess tax benefits from share-based payment arrangements and (iv) $9.9 million of proceeds received from the issuance of our predecessor’s common stock.
 
The impact of these positive factors was partially offset by (i) a $304.2 million use of cash for the early retirement of a portion of our senior notes, (ii) $248.9 million of minority interest distributions, primarily resulting from Kinder Morgan Energy Partners’ distributions to common unit holders, (iii) a net decrease of $247.5 million in short-term debt, (iii) $234.9 million paid for dividends on our predecessor’s common stock and (iv) a decrease of $14.9 million in cash book overdrafts.
 
Year Ended December 31, 2006
 
Net cash flows from operating activities during the period were positively affected by (i) net income of $1,425.7 million, after adjustments for non-cash items, (ii) $212.6 of cash provided by discontinued operations, (iii) an $80.0 million source of cash for working capital items and (iv) $74.8 million of distributions from equity investments.
 
These positive factors were partially offset by (i) a $35.3 million increase in gas in underground storage and (ii) $19.1 million of payments made to certain shippers on Kinder Morgan Energy Partners’ West Coast Products Pipelines as a result of a settlement agreement regarding delivery tariffs and gathering enhancement fees at its Watson Station.
 
Net cash flows used in investing activities during the period were affected by (i) $1,375.6 million in capital expenditures, (ii) $407.1 million of acquisitions, (iii) $251.0 million of cash used for discontinued investing activities, primarily attributable to Terasen’s capital expenditures, (iv) $12.9 million for investments in underground storage volumes and payments made for natural gas liquids line-fill and (v) contributions of $6.1 million to equity investments.
 
These negative impacts were partially offset by (i) $112.9 million of proceeds received for the sale of Terasen’s discontinued Water and Utility Services, (ii) $92.2 million of net proceeds from the sale of other assets, (iii) $38.6 million of net proceeds from the sale of margin deposits and (iv) $13.1 million of cash received for property casualty indemnifications.
 
Net cash flows from financing activities during the period were positively impacted by (i) a net increase of $1,009.5 million in short-term debt, (ii) $353.8 million of contributions from minority interest owners, primarily Kinder Morgan Energy Partners’ issuance of 5.75 million common units receiving net proceeds (after underwriting discount) of $248.0 million and Sempra Energy’s $104.2 million contribution for its 33 1/3 % share of the purchase price of Entrega Pipeline LLC, (iii) $38.7 million of proceeds received from the issuance of our predecessor’s common stock, (iv) $18.6 million of cash received for excess tax benefits from share-based payment arrangements and (v) an increase of $17.9 million in cash book overdrafts.
 
The impact of these positive factors was partially offset by (i) $575.0 million of minority interest distributions, primarily resulting from Kinder Morgan Energy Partners’ distributions to common unit holders, (ii) $468.5 million paid for dividends on our predecessor’s common stock, (iii) $125.0 million of cash used to retire our 7.35% Series debentures which were elected by the holders to be redeemed on August 1, 2006 as provided in the indenture governing the debentures, (iv) a $118.1 million use of cash related to our discontinued Terasen financing activities, (v) $34.3 million in cash paid to repurchase our predecessor’s common shares and (vi) a $4.9 million use of cash for short-term advances to unconsolidated affiliates.
 
 
Kinder Morgan Energy Partners’ partnership agreement requires that it distribute 100% of “Available Cash,” as defined in its partnership agreement, to its partners within 45 days following the end of each calendar quarter in accordance with their respective percentage interests. Available Cash consists generally of all of Kinder Morgan Energy Partners’ cash receipts, including cash received by its operating partnerships and net reductions in reserves, less cash disbursements and net additions to reserves and amounts payable to the former general partner of SFPP, L.P. (“SFPP”), in respect of its remaining 0.5% interest in SFPP.
 
Kinder Morgan Management, as the delegate of Kinder Morgan G.P., Inc., of which we indirectly own all of the outstanding common equity, and the general partner of Kinder Morgan Energy Partners, is granted discretion to establish, maintain and adjust reserves for future operating expenses, debt service, maintenance capital expenditures, rate refunds and distributions for the next four quarters. These reserves are not restricted by magnitude, but only by type of future cash requirements with which they can be associated. When Kinder Morgan Management determines Kinder Morgan Energy Partners’ quarterly distributions, it considers current and expected reserve needs along with current and expected cash flows to identify the appropriate sustainable distribution level.
 

 
79
 
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)
Knight Form 10-K


Available cash is initially distributed 98% to Kinder Morgan Energy Partners’ limited partners with 2% retained by Kinder Morgan G.P., Inc. as Kinder Morgan Energy Partners’ general partner. These distribution percentages are modified to provide for incentive distributions to be retained by Kinder Morgan G.P., Inc. as general partner of Kinder Morgan Energy Partners in the event that quarterly distributions to unitholders exceed certain specified targets.
 
Available cash for each quarter is distributed:
 
 
·
first, 98% to the owners of all classes of units pro rata and 2% to Kinder Morgan G.P., Inc. as general partner of Kinder Morgan Energy Partners until the owners of all classes of units have received a total of $0.15125 per unit in cash or equivalent i-units for such quarter;
 
·
second, 85% of any available cash then remaining to the owners of all classes of units pro rata and 15% to Kinder Morgan G.P., Inc. as general partner of Kinder Morgan Energy Partners until the owners of all classes of units have received a total of $0.17875 per unit in cash or equivalent i-units for such quarter;
 
·
third, 75% of any available cash then remaining to the owners of all classes of units pro rata and 25% to Kinder Morgan G.P., Inc. as general partner of Kinder Morgan Energy Partners until the owners of all classes of units have received a total of $0.23375 per unit in cash or equivalent i-units for such quarter; and
 
·
fourth, 50% of any available cash then remaining to the owners of all classes of units pro rata, to owners of common units in cash and to Kinder Morgan Management as owners of i-units in the equivalent number of i-units, and 50% to Kinder Morgan G.P., Inc. as general partner of Kinder Morgan Energy Partners.
 
During the year ended December 31, 2008, Kinder Morgan Energy Partners paid distributions of $3.89 per common unit, of which $626.6 million was paid to the public holders (represented in minority interests) of Kinder Morgan Energy Partners’ common units. On January 21, 2009, Kinder Morgan Energy Partners declared a quarterly distribution of $1.05 per common unit for the quarterly period ended December 31, 2008. The distribution was paid on February 13, 2009, to unitholders of record as of January 30, 2009.
 
 
SFAS No. 157, Fair Value Measurements establishes a hierarchal disclosure framework associated with the level of pricing observability utilized in measuring fair value. The hierarchy of valuation techniques is based upon whether the inputs to those valuation techniques reflect assumptions other market participants would use based upon market data obtained from independent sources (observable inputs) or reflect a company’s own assumptions of market participant valuation (unobservable inputs). This framework defines three levels of inputs to the fair value measurement process, and requires that each fair value measurement be assigned to a level corresponding to the lowest level input that is significant to the fair value measurement in its entirety. In accordance with SFAS No. 157, the lowest level of fair value hierarchy based on these two types of inputs is designated as Level 3 and is based on prices or valuations that require inputs that are both significant to the fair value measurement and unobservable.
 
As of December 31, 2008, the fair value of our derivative contracts classified as Level 3 under the established fair value hierarchy consisted primarily of West Texas Intermediate (“WTI”) crude oil options (costless collars) and West Texas Sour (“WTS”) crude oil hedges. Costless collars are designed to establish floor and ceiling prices on anticipated future oil production from the assets we own in the SACROC oil field unit. While the use of these derivative contracts limits the downside risk of adverse price movements, they may also limit future revenues from favorable price movements. In addition to these oil-commodity derivatives, our Level 3 derivative contracts included natural gas basis swaps and natural gas options. Basis swaps are used in connection with another derivative contract to reduce hedge ineffectiveness by reducing a basis difference between a hedged exposure and a derivative contract. Natural gas options are used to offset the exposure related to certain physical contracts.
 
The following table summarizes the total fair value asset and liability measurements of our Level 3 energy commodity derivative contracts in accordance with SFAS No. 157.
 
 
Significant Unobservable Inputs (Level 3)
 
Assets
  
Liabilities
 
December 31,
2008
  
December 31,
2007
  
Change
  
December 31,
2008
  
December 31,
2007
  
Change
                                               
WTI Options
$
34.3
    
$
—
    
$
34.3
    
$
(2.2
)
  
$
—
    
$
(2.2
)
WTS Oil Swaps
  
17.1
      
—
      
17.1
      
(0.2
)
    
(94.5
)
    
94.3
  
Natural Gas Basis Swaps
  
3.3
      
2.8
      
0.5
      
(5.2
)
    
(4.7
)
    
(0.5
)
Natural Gas Options
  
—
      
—
      
—
      
(2.7
)
    
—
      
(2.7
)
Other
  
0.5
      
1.0
      
(0.5
)
    
(0.8
)
    
(4.9
)
    
4.1
  
Total
$
55.2
    
$
3.8
    
$
51.4
    
$
(11.1
)
  
$
(104.1
)
  
$
93.0
  


 
80
 
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)
Knight Form 10-K


The largest changes in the fair value of our Level 3 assets and liabilities between December 31, 2007 and December 31, 2008 were related to West Texas Intermediate options and West Texas Sour hedges. We entered into the majority of our WTI option contracts during 2008, which accounts for the changes. The changes in value from our WTS swap contracts were largely due to favorable crude oil price changes since the end of 2007. There were no transfers into or out of Level 3 during the period.
 
The valuation techniques used for the above Level 3 input derivative contracts are as follows:
 
 
·
Option contracts—valued using internal model. Internal models incorporate the use of options pricing and estimates of the present value of cash flows based upon underlying contractual terms. The models reflect management’s estimates, taking into account observable market prices, estimated market prices in the absence of quoted market prices, the risk-free market discount rate, volatility factors, estimated correlations of commodity prices and contractual volumes;
 
·
WTS oil swaps—prices obtained from a broker using their proprietary model for similar assets and liabilities (quotes are non-binding); and
 
·
Natural gas basis swaps—values obtained through a pricing service, derived by combining raw inputs from the New York Mercantile Exchange (referred to in this report as NYMEX) with proprietary quantitative models and processes. Although the prices are originating from a liquid market (NYMEX), we believe the incremental effort to further validate these prices would take undue effort and would not materially alter the assumptions. As a result, we have classified the valuation of these derivatives as Level 3.
 
For our energy commodity derivative contracts, the most observable inputs available are used to determine the fair value of each contract. In the absence of a quoted price for an identical contract in an active market, we use broker quotes for identical or similar contracts, or internally prepared valuation models as primary inputs to determine fair value. No adjustments were made to quotes or prices obtained from brokers and pricing services, and our valuation methods have not changed during the year ended December 31, 2008.
 
When appropriate, valuations are adjusted for various factors including credit considerations. Such adjustments are generally based on available market evidence, including but not limited to our credit default swap quotes as of December 31, 2008. Collateral agreements with our counterparties serve to reduce our credit exposure and are considered in the adjustment. We adjust the fair value measurements of our energy commodity derivative contracts for credit risk in accordance with SFAS No. 157, and as of December 31, 2008, the net assets balance associated with these contracts recorded in the accompanying Consolidated Balance Sheet included a reduction of $2.2 million related to discounting the value of our energy commodity derivative net assets for the effect of credit risk.
 
With the exception of the Casper and Douglas natural gas processing plant hedges and the ineffective portion of our derivative contracts, our energy commodity derivative contracts are accounted for as cash flow hedges. In accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities and associated amendments (“SFAS No. 133”), gains and losses associated with cash flow hedges are reported in “Accumulated Other Comprehensive Loss” in the accompanying Consolidated Balance Sheets.
 
 
As of December 31, 2008, we have recorded a total reserve for environmental claims, without discounting and without regard to anticipated insurance recoveries, in the amount of $85.0 million. In addition, we have recorded a receivable of $20.9 million for expected cost recoveries that have been deemed probable. The reserve is primarily established to address and clean up soil and ground water impacts from former releases to the environment at facilities we have acquired or accidental spills or releases at facilities that we own. Reserves for each project are generally established by reviewing existing documents, conducting interviews and performing site inspections to determine the overall size and impact to the environment. Reviews are made on a quarterly basis to determine the status of the cleanup and the costs associated with the effort. In assessing environmental risks in conjunction with proposed acquisitions, we review records relating to environmental issues, conduct site inspections, interview employees and, if appropriate, collect soil and groundwater samples. As of December 31, 2007, our total reserve for environmental claims, without discounting and without regard to anticipated insurance recoveries, amounted to $102.6 million.
 
Additionally, as of December 31, 2008, we have recorded a total reserve for legal fees, transportation rate cases and other litigation liabilities in the amount of $234.8 million. The reserve is primarily related to various claims from lawsuits arising from Kinder Morgan Energy Partners’ West Coast Products Pipelines, and the recorded amount is based on both the estimated amount associated with possible outcomes and probabilities of occurrence associated with such outcomes. We regularly assess the likelihood of adverse outcomes resulting from these claims in order to determine the adequacy of our liability provision. As of December 31, 2007, our total reserve for legal fees, transportation rate cases and other litigation liabilities amounted to $249.4 million.
 

 
81
 
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)
Knight Form 10-K


Though no assurance can be given, we believe we have established adequate environmental and legal reserves such that the resolution of pending environmental matters and litigation will not have a material adverse impact on our business, cash flows, financial position or results of operations. However, changing circumstances could cause these matters to have a material adverse impact.
 
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. These enhancements have resulted and may result in higher operating costs and sustaining capital expenditures; however, we believe these enhancements will provide us the greater long-term benefits of improved environmental and asset integrity performance.
 
Please refer to Note 21 of the accompanying Notes to Consolidated Financial Statements for additional information regarding pending litigation and environmental matters.
 
 
The Pipeline Safety Improvement Act of 2002 requires pipeline companies to perform integrity tests on natural gas transmission pipelines that exist in high population density areas that are designated as High Consequence Areas. Pipeline companies are required to perform the integrity tests within ten years of December 17, 2002, the date of enactment, and must perform subsequent integrity tests on a seven-year cycle. At least 50% of the highest risk segments must be tested within five years of the enactment date. The risk ratings are based on numerous factors, including the population density in the geographic regions served by a particular pipeline, as well as the age and condition of the pipeline and its protective coating.  Testing may consist of hydrostatic testing, internal electronic testing, or direct assessment of the piping. A similar integrity management rule for refined petroleum products pipelines became effective May 29, 2001. All baseline assessments for products pipelines must be completed by March 31, 2008 and we met that deadline. We have included all incremental expenditures estimated to occur during 2009 associated with the Pipeline Safety Improvement Act of 2002 and the integrity management of our products pipelines in our 2009 budget and capital expenditure plan.
 
Please refer to Note 20 of the accompanying Notes to Consolidated Financial Statements for additional information regarding regulatory matters.
 
 
Refer to Note 22 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 service debt 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 that 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 North America;
 
·
economic activity, weather, alternative energy sources, conservation and technological advances that may affect price trends and demand;
 
·
changes in tariff rates charged by our or those of Kinder Morgan Energy Partners’ pipeline subsidiaries implemented by the Federal Energy Regulatory Commission, or other regulatory agencies or the California Public Utilities Commission;
 
·
our ability to acquire new businesses and assets and integrate those operations into our existing operations, as well as the ability to expand our 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;
 
·
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

 
82
 
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations (continued)
Knight Form 10-K


 
businesses that use our services or provide services or products to us;
 
·
crude oil and natural gas production from exploration and production areas that we or Kinder Morgan Energy Partners serve, such as the Permian Basin area of West Texas, the U.S. Rocky Mountains and the Alberta oil sands;
 
·
changes in laws or regulations, third-party relations and approvals and decisions of courts, regulators and governmental bodies that may adversely affect our business or 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 Kinder Morgan Energy Partners’ ability to offer and sell equity securities and its ability to sell debt securities or obtain debt financing in sufficient amounts to implement that portion of our or Kinder Morgan Energy Partners’ business plans that contemplates growth through acquisitions of operating businesses and assets and expansions of facilities;
 
·
our indebtedness, which 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 significant levels of self-retention of risk;
 
·
acts of nature, sabotage, terrorism or other similar acts causing damage greater than our insurance coverage limits;
 
·
capital and credit markets conditions, including availability of credit generally, as well as inflation and interest rates;
 
·
the political and economic stability of the oil producing nations of the world;
 
·
national, international, regional and local economic, competitive and regulatory conditions and developments;
 
·
our ability to achieve cost savings and revenue growth;
 
·
foreign exchange fluctuations;
 
·
the timing and extent of changes in commodity prices for oil, natural gas, electricity and certain agricultural products;
 
·
the extent of Kinder Morgan Energy Partners’ success in discovering, developing and producing oil and gas reserves, including the risks inherent in exploration and development drilling, well completion and other development activities;
 
·
engineering and mechanical or technological difficulties that Kinder Morgan Energy Partners may experience with operational equipment, in well completions and workovers, and in drilling new wells;
 
·
the uncertainty inherent in estimating future oil and natural gas production or reserves that Kinder Morgan Energy Partners may experience;
 
·
the ability to complete expansion projects on time and on budget;
 
·
the timing and success of Kinder Morgan Energy Partners’ and our business development efforts; and
 
·
unfavorable results of litigation and the fruition of contingencies referred to in the accompanying Notes to Consolidated Financial Statements.
 
The foregoing list should not be construed to be exhaustive. We believe the forward-looking statements in this report are reasonable. However, there is no assurance that any of the actions, events or results of the forward-looking statements will occur, or if any of them do, what impact they will have on our results of operations or financial condition. Because of these uncertainties, you should not put undue reliance on any forward-looking statements. See Item 1A “Risk Factors” 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. Other than as required by applicable law, 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.
 
 
Generally, our market risk sensitive instruments and positions have been determined to be “other than trading.” Our exposure to market risk as discussed below includes forward-looking statements and represents an estimate of possible changes in fair value or future earnings that would occur, assuming hypothetical future movements in interest rates or commodity prices. Our views on market risk are not necessarily indicative of actual results that may occur and do not represent the maximum possible gains and losses that may occur, since actual gains and losses will differ from those estimated based on actual fluctuations in commodity prices or interest rates and the timing of transactions.
 
Energy Commodity Market Risk
 
We are exposed to commodity market risk and other external risks, such as weather-related risk, in the ordinary course of business. However, we take steps to hedge, or limit our exposure to, these risks in order to maintain a more stable and
 

 
83
 
Item 7A.   Quantitative and Qualitative Disclosures About Market Risk. (continued)
Knight Form 10-K


predictable earnings stream. Stated another way, we execute a hedging strategy that seeks to protect us financially against adverse price movements and serves to minimize potential losses. Our strategy involves the use of certain energy commodity derivative contracts to reduce and minimize the risks associated with unfavorable changes in the market price of natural gas, natural gas liquids and crude oil. The derivative contracts we use include energy products traded on the New York Mercantile Exchange and over-the-counter markets, including, but not limited to, futures and options contracts, fixed price swaps and basis swaps.
 
Fundamentally, our hedging strategy involves taking a simultaneous position in the futures market that is equal and opposite to our position, or anticipated position in the cash market (or physical product) in order to minimize the risk of financial loss from an adverse price change. For example, as sellers of crude oil and natural gas, we often enter into fixed price swaps and/or futures contracts to guarantee or lock-in the sale price of our oil or the margin from the sale and purchase of our natural gas at the time of market delivery, thereby directly offsetting any change in prices, either positive or negative. A hedge is successful when gains or losses in the cash market are neutralized by losses or gains in the futures transaction.
 
Our policies require that we only enter into derivative contracts with carefully selected major financial institutions or similar counterparties based upon their credit ratings and other factors, and we maintain strict dollar and term limits that correspond to our counterparties’ credit ratings. While we enter into derivative transactions only with investment grade counterparties and actively monitor their credit ratings, it is nevertheless possible that losses will result from counterparty credit risk in the future. The credit ratings of the primary parties from whom we transact in energy commodity derivative contracts (based on contract market values) are as follows (credit ratings per Standard & Poor’s Rating Services):
 
 
Credit Rating
Citigroup
A
J. Aron & Company / Goldman Sachs
A
Morgan Stanley
A

However, as discussed above, our principal use of energy commodity derivative contracts is to mitigate the market price risk associated with anticipated transactions for the purchase and sale of natural gas, natural gas liquids and crude oil. Using derivative contracts for this purpose helps provide us increased certainty with regard to our operating cash flows and helps us undertake further capital improvement projects, attain budget results and meet distribution targets to our partners. SFAS No. 133 categorizes such use of energy commodity derivative contracts as cash flow hedges, because the derivative contract is used to hedge the anticipated future cash flow of a transaction that is expected to occur but whose value is uncertain. Cash flow hedges are defined as hedges made with the intention of decreasing the variability in cash flows related to future transactions, as opposed to the value of an asset, liability or firm commitment, and SFAS No. 133 prescribes special hedge accounting treatment for such derivatives.
 
In accounting for cash flow hedges, gains and losses on the derivative contracts are reported in other comprehensive income, outside “Net Income” reported in the accompanying Consolidated Statements of Operations, but only to the extent that the gains and losses from the change in value of the derivative contracts can later offset the loss or gain from the change in value of the hedged future cash flows during the period in which the hedged cash flows affect net income. That is, for cash flow hedges, all effective components of the derivative contracts’ gains and losses are recorded in other comprehensive income (loss), pending occurrence of the expected transaction. Other comprehensive income (loss) consists of those financial items that are included in “Accumulated Other Comprehensive Loss” in the accompanying Consolidated Balance Sheets but not included in our net income. Thus, in highly effective cash flow hedges, where there is no ineffectiveness, other comprehensive income changes by exactly as much as the derivative contracts and there is no impact on earnings until the expected transaction occurs.
 
All remaining gains and losses on the derivative contracts (the ineffective portion) are included in current net income. The ineffective portion of the gain or loss on the derivative contracts is the difference between the gain or loss from the change in value of the derivative contract and the effective portion of that gain or loss. In addition, when the hedged forecasted  transaction does take place and affects earnings, the effective part of the hedge is also recognized in the income statement, and the earlier recognized effective amounts are removed from “Accumulated Other Comprehensive Loss.” If the forecasted transaction results in an asset or liability, amounts in “Accumulated Other Comprehensive Loss” should be reclassified into earnings when the asset or liability affects earnings through cost of sales, depreciation, interest expense, etc.
 
The accumulated components of other comprehensive income are to be reported separately as accumulated other comprehensive income or loss in the stockholder’s equity section of the balance sheet. For us, the amounts included in “Accumulated Other Comprehensive Loss” in the accompanying Consolidated Balance Sheets primarily include (i) the effective portion of the gains and losses on cash flow hedging items, (ii) gains and losses and prior service costs or credits associated with our pension and postretirement plans and (iii) foreign currency translation adjustments. The gains and losses on hedging items primarily relate to the derivative contracts associated with our hedging of anticipated future cash flows from the sales and purchases of natural gas, natural gas liquids and crude oil. Amounts related to our pension and
 

 
84
 
Item 7A.   Quantitative and Qualitative Disclosures About Market Risk. (continued)
Knight Form 10-K


postretirement plans result from gains and losses and prior service costs or credits that have not been recognized as a component of net periodic benefit costs. The translation adjustments are a cumulative total, resulting from translating all of our foreign denominated assets and liabilities at current exchange rates, while equity is translated by using historical or weighted-average exchange rates.
 
The total “Accumulated Other Comprehensive Loss” balance of $53.4 million included in the accompanying Consolidated Balance Sheet at December 31, 2008 consisted of (i) $5.1 million representing unrecognized net gains on energy commodity price risk management activities, (ii) $35.8 million representing unrecognized net gains relating to foreign currency translation adjustments and (iii) $94.3 million representing unrecognized net losses relating to the employee benefit plans. The total “Accumulated Other Comprehensive Loss” balance of $247.7 million included in the accompanying Consolidated Balance Sheet at December 31, 2007 consisted of (i) $237.3 million representing unrecognized net losses on energy commodity price risk management activities, (ii) $18.4 million representing unrecognized net gains relating to foreign currency translation adjustments and (iii) $28.8 million representing unrecognized net losses relating to the employee benefit plans.
 
In future periods, as the hedged cash flows from our actual purchases and sales of energy commodities affect our net income, the related gains and losses included in our accumulated other comprehensive loss as a result of our hedging are transferred to the income statement as well, effectively offsetting the changes in cash flows stemming from the hedged risk.
 
We measure the risk of price changes in the natural gas, natural gas liquids and crude oil markets utilizing a value-at-risk model. Value-at-risk is a statistical measure indicating the minimum expected loss in a portfolio over a given time period, within a certain level of statistical confidence. We utilize a closed form model to evaluate risk on a daily basis. The value-at-risk computations utilize a confidence level of 97.7% for the resultant price movement and a holding period of one day is chosen for the calculation. The confidence level used means that there is a 97.7% probability that the mark-to-market losses for a single day will not exceed the value-at-risk number presented. Derivative contracts evaluated by the model include commodity futures and options contracts, fixed price swaps, basis swaps and over-the-counter options.
 
For each of the years ended December 31, 2008 and 2007, our value-at-risk reached a high of $1.8 million and $2.1 million, respectively, and a low of $0.7 million and $0.7 million, respectively. Value-at-risk as of December 31, 2008 was $0.7 million, and averaged $1.5 million for 2008. Value-at-risk as of December 31, 2007 was $1.7 million, and averaged $1.4 million for 2007.
 
Our calculated value-at-risk exposure represents an estimate of the reasonably possible net losses that would be recognized on our portfolio of derivative contracts assuming hypothetical movements in future market rates and is not necessarily indicative of actual results that may occur. It does not represent the maximum possible loss or any expected loss that may occur, since actual future gains and losses will differ from those estimated. Actual gains and losses may differ from estimates due to actual fluctuations in market rates, operating exposures and the timing thereof, as well as changes in our portfolio of derivatives during the year. In addition, as discussed above, we enter into these derivative contracts solely for the purpose of mitigating the risks that accompany certain of our business activities and, therefore, the change in the market value of our portfolio of derivative contracts, with the exception of a minor amount of hedging inefficiency, is offset by changes in the value of the underlying physical transactions. For more information on our risk management activities, see Note 15 of the accompanying Notes to Consolidated Financial Statements.
 
Interest Rate Risk
 
In order to maintain a cost effective capital structure, it is our policy to borrow funds using a mix of fixed rate debt and variable rate debt. The market risk inherent in our debt instruments and positions is the potential change arising from increases or decreases in interest rates as discussed below.
 
For fixed rate debt, changes in interest rates generally affect the fair value of the debt instrument, but not our earnings or cash flows. Conversely, for variable rate debt, changes in interest rates generally do not impact the fair value of the debt instrument, but may affect our future earnings and cash flows. We do not have an obligation to prepay fixed rate debt prior to maturity and, as a result, interest rate risk and changes in fair value should not have a significant impact on our fixed rate debt until we would be required to refinance such debt.
 
As of December 31, 2008 and 2007, the carrying values of our long-term fixed rate debt were approximately $9,232.8 million and $8,439.2 million, respectively. These amounts compare to fair values of $9,838.1 million and $10,651.3 million as of December 31, 2008 and 2007, respectively. A 100 basis point change of the average interest rates applicable to such debt for 2008 and 2007 would result in changes of approximately $98.4 million and $106.5 million, respectively, in the fair values of these instruments.
 

 
85
 
Item 7A.   Quantitative and Qualitative Disclosures About Market Risk. (continued)
Knight Form 10-K


The carrying value of our long-term variable rate debt, excluding the value of interest rate swap agreements (discussed below), was $2,894.0 million and $6,858.2 million as of December 31, 2008 and 2007, respectively. A 100 basis point change of the weighted-average interest rate applicable to such debt, when applied to our outstanding balance of variable rate debt as of December 31, 2008 and 2007, including adjustments for notional swap amounts, would result in changes of approximately $28.9 million and $68.6 million, respectively, in our 2008 and 2007 annual pre-tax earnings.
 
We adjusted the fair value measurement of our long-term debt in accordance with SFAS No. 157, and the estimated fair value of our debt as of December 31, 2008 includes a discount related to the effect of credit risk.
 
As of December 31, 2008, Kinder Morgan Energy Partners was a party to an interest rate swap agreement with a notional principal amount of $2.8 billion. As of December 31, 2007, we and our subsidiary Kinder Morgan Energy Partners were party to interest rate swap agreements with notional principal amounts of $275 million and $2.3 billion, respectively, for a consolidated total of $2.575 billion. An interest rate swap agreement is a contractual agreement entered into between two counterparties under which each agrees to make periodic interest payments to the other for an agreed period of time based upon a predetermined amount of principal, which is called the notional principal amount. Normally at each payment or settlement date, the party who owes more pays the net amount; so at any given settlement date only one party actually makes a payment. The principal amount is notional because there is no need to exchange actual amounts of principal.
 
We entered into our interest rate swap agreements for the purpose of transforming a portion of the underlying cash flows related to our long-term fixed rate debt securities into variable rate debt in order to achieve our desired mix of fixed and variable rate debt. Since the fair value of our fixed rate debt varies with changes in the market rate of interest, we enter into swap agreements to receive a fixed and pay a variable rate of interest. Such swap agreements result in future cash flows that vary with the market rate of interest and therefore, hedge against changes in the fair value of our fixed rate debt due to market rate changes.
 
As of both December 31, 2008 and 2007, all of our interest rate swap agreements represented fixed-for-variable rate swaps, where we agreed to pay our counterparties a variable rate of interest on a notional principal amount, comprised of principal amounts from various series of our long-term fixed rate senior notes. In exchange, our counterparties agreed to pay us a fixed rate of interest, thereby allowing us to transform our fixed rate liabilities into variable rate obligations without the incurrence of additional loan origination or conversion costs. We monitor our mix of fixed rate and variable rate debt obligations in light of changing market conditions and from time to time may alter that mix by, for example, refinancing balances outstanding under our variable rate debt with fixed rate debt (or vice versa) or by entering into interest rate swap agreements or other interest rate hedging agreements.
 
As of December 31, 2008, our cash and investment portfolio included approximately $13.2 million in fixed-income debt securities. Because our investment in debt securities was made and will be maintained in the future to directly offset the interest rate risk on a like amount of long-term debt, a hypothetical 10% increase in interest rates would not have a material effect on the fair market value of our portfolio; and because we have the ability to liquidate this portfolio, we do not expect our operating results or cash flows to be materially affected to any significant degree by the effect of a sudden change in market interest rates on our investment portfolio.
 
See Notes 14, 15 and 23 of the accompanying Notes to Consolidated Financial Statements for additional information on activity related to our debt instruments and interest rate swap agreements.
 
Foreign Currency Risk
 
We are exposed to foreign currency risk from our investments in businesses owned and operated outside the United States. To mitigate this risk, we have several receive-fixed-rate, pay-fixed-rate U.S. dollar to Canadian dollar cross-currency interest rate swap agreements that have been designated as a hedge of our net investment in Canadian operations in accordance with SFAS No. 133. A 1% change in the U.S. Dollar to Canadian Dollar exchange rate would impact the fair value of these swap agreements by approximately $1.09 million.
 

 
86
 
Knight Form 10-K


 
INDEX
 


 
87
 
Item 8:   Financial Statements and Supplementary Data.  (continued)
Knight Form 10-K



To the Board of Directors
and Stockholder of Knight Inc.:

In our opinion, the accompanying consolidated balance sheet and the related consolidated statements of operations, of comprehensive income, of stockholder’s equity and of cash flows present fairly, in all material respects, the financial position of Knight Inc. and its subsidiaries (the “Company”) at December 31, 2008 and 2007, and the results of their operations and their cash flows for the year ended December 31, 2008 and the period from June 1, 2007 to December 31, 2007 in conformity with accounting principles generally accepted in the United States of America.  Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).  The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control Over Financial Reporting appearing in item 9A.  Our responsibility is to express opinions on these financial statements and on the Company’s internal control over financial reporting based on our integrated audit. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects.  Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation.  Our audits of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk.  Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.  A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.  Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

As described in Management’s Report on Internal Control Over Financial Reporting, management has excluded:

 
·
The bulk terminal assets acquired from Chemserve, Inc., effective August 15, 2008; and

 
·
The refined petroleum products storage terminal acquired from ConocoPhillips, effective December 10, 2008,

(the “Acquired Businesses”) from its assessment of internal control over financial reporting as of December 31, 2008 because these businesses were each acquired by the Company in purchase business combinations during 2008.  We have also excluded the Acquired Businesses from our audit of internal control over financial reporting.  These Acquired Businesses are wholly-owned subsidiaries whose total assets and total revenues, in the aggregate, represent 0.23% and 0.01%, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2008.




PricewaterhouseCoopers LLP
Houston, Texas
March 31, 2009

 
88
 
Item 8:   Financial Statements and Supplementary Data.  (continued)
Knight Form 10-K







Report of Independent Registered Public Accounting Firm

To the Board of Directors
and Stockholder of Knight Inc.:

In our opinion, the accompanying consolidated balance sheet and the related consolidated statements of operations, of comprehensive income, of stockholder's equity and of cash flows present fairly, in all material respects, the financial position of Knight Inc. and its subsidiaries (the "Company") at December 31, 2006, and the results of their operations and their cash flows for the period from January 1, 2007 to May 31, 2007, and the years ended December 31, 2006 and 2005 in conformity with accounting principles generally accepted in the United States of America.  These financial statements are the responsibility of the Company’s management.  Our responsibility is to express an opinion on these financial statements based on our audits.  We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.




PricewaterhouseCoopers LLP
Houston, Texas
March 28, 2008, except as to Note 19,
    for which the date is January 8, 2009


 
89
 
Item 8:   Financial Statements and Supplementary Data.  (continued)
Knight Form 10-K


CONSOLIDATED STATEMENTS OF OPERATIONS
(In millions)
 
 
Successor Company
    
Predecessor Company
 
Year Ended
December 31,
2008
  
Seven Months
Ended
December 31,
2007
    
Five Months
Ended
May 31, 2007
  
Year Ended
December 31,
2006
Operating Revenues
                                
Natural Gas Sales
$
7,705.8
    
$
3,623.1
      
$
2,430.6
    
$
6,225.6
  
Services
  
2,904.0
      
2,049.8
        
1,350.5
      
3,082.3
  
Product Sales and Other
  
1,485.0
      
721.8
        
384.0
      
900.7
  
Total Operating Revenues
  
12,094.8
      
6,394.7
        
4,165.1
      
10,208.6
  
  
                                
Operating Costs and Expenses
                                
Gas Purchases and Other Costs of Sales
  
7,744.0
      
3,656.6
        
2,490.4
      
6,339.4
  
Operations and Maintenance
  
1,318.0
      
943.3
        
476.1
      
1,155.4
  
General and Administrative
  
352.5
      
175.6
        
283.6
      
305.1
  
Depreciation, Depletion and Amortization
  
918.4
      
472.3
        
261.0
      
531.4
  
Taxes, Other Than Income Taxes
  
191.4
      
110.1
        
74.4
      
165.0
  
Other Expenses (Income)
  
9.3
      
(6.0
)
      
(2.3
)
    
(34.1
)
Impairment of Assets
  
4,033.3
      
-
        
377.1
      
1.2
  
Total Operating Costs and Expenses
  
14,566.9
      
5,351.9
        
3,960.3
      
8,463.4
  
                                 
Operating Income (Loss)
  
(2,472.1
)
    
1,042.8
        
204.8
      
1,745.2
  
  
                                
Other Income and (Expenses)
                                
Earnings of Equity Investees
  
195.4
      
53.4
        
38.3
      
98.6
  
Interest Expense, Net
  
(633.4
)
    
(581.5
)
      
(241.1
)
    
(552.8
)
Interest Income (Expense)—Deferrable Interest Debentures
  
5.1
      
(12.8
)
      
(9.1
)
    
(21.9
)
Minority Interests
  
(396.1
)
    
(37.6
)
      
(90.7
)
    
(374.2
)
Other, Net
  
7.0
      
11.6
        
0.6
      
(8.6
)
Total Other Income and (Expenses)
  
(822.0
)
    
(566.9
)
      
(302.0
)
    
(858.9
)
                                 
Income (Loss) from Continuing Operations Before Income Taxes
  
(3,294.1
)
    
475.9
        
(97.2
)
    
886.3
  
Income Taxes
  
304.3
      
227.4
        
135.5
      
285.9
  
Income (Loss) from Continuing Operations
  
(3,598.4
)
    
248.5
        
(232.7
)
    
600.4
  
Income (Loss) from Discontinued Operations, Net of Tax
  
(0.9
)
    
(1.5
)
      
298.6
      
(528.5
)
Net Income (Loss)
$
(3,599.3
)
  
$
247.0
      
$
65.9
    
$
71.9
  

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

 
90
 
Item 8:   Financial Statements and Supplementary Data.  (continued)
Knight Form 10-K


CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In millions)
 
 
Successor Company
    
Predecessor Company
 
Year Ended
December 31,
2008
  
Seven Months
Ended
December 31,
2007
    
Five Months
Ended
May 31, 2007
  
Year Ended
December 31,
2006
                                 
Net Income (Loss)
$
(3,599.3
)
  
$
247.0
      
$
65.9
    
$
71.9
  
Other Comprehensive Income (Loss), Net of Tax:
                                
Change in Fair Value of Derivatives Utilized for Hedging Purposes (Net of Tax of $121.3, Tax Benefit of $140.8, $19.1, and Tax of $26.8, Respectively)
  
212.0
      
(249.6
)
      
(21.3
)
    
44.6
  
Reclassification of Change in Fair Value of Derivatives to Net Income (Net of Tax of $69.4, Tax Benefit of $0.6, Tax of $12.8 and $11.9, Respectively)
  
117.1
      
-
        
10.3
      
21.7
  
Employee Benefit Plans:
                                
Prior Service Cost Arising During Period (Net of Tax Benefit of $0.2 and $1.0, Respectively)
  
(0.3
)
    
-
        
(1.7
)
    
-
  
Net (Loss) Gain Arising During Period (Net of Tax Benefit of $37.5, $15.3, and Tax of $6.7, Respectively)
  
(66.2
)
    
(28.4
)
      
11.4
      
-
  
Amortization of Prior Service Cost Included in Net Periodic Benefit Costs (Net of Tax Benefit of $0.2)
  
-
      
-
        
(0.4
)
    
-
  
Amortization of Net Loss (Gain) Included in Net Periodic Benefit Costs (Net of Tax of $0.2, Tax Benefit of Less than $0.1, and Tax of $0.8, Respectively)
  
0.4
      
(0.2
)
      
1.4
      
-
  
Change in Foreign Currency Translation Adjustment (Net of Tax Benefit of $31.0, Tax of $8.3, $3.9 and Tax Benefit of $11.5, Respectively)
  
(68.7
)
    
27.6
        
40.1
      
(31.9
)
Adjustment to Recognize Minimum Pension Liability (Net of Tax of $1.7)
  
-
      
-
        
-
      
3.5
  
Total Other Comprehensive Income (Loss)
  
194.3
      
(250.6
)
      
39.8
      
37.9
  
  
                                
Comprehensive Income (Loss)
$
(3,405.0
)
  
$
(3.6
)
    
$
105.7
    
$
109.8
  

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

 
91
 
Item 8:   Financial Statements and Supplementary Data.  (continued)
Knight Form 10-K


CONSOLIDATED BALANCE SHEETS
(In millions)
 
 
December 31,
2008
  
December 31,
2007
ASSETS
              
Current Assets
              
Cash and Cash Equivalents
$
118.6
    
$
148.6
  
Restricted Deposits
  
-
      
67.9
  
Accounts, Notes and Interest Receivable, Net
  
992.5
      
975.2
  
Inventories
  
44.2
      
37.8
  
Gas Imbalances
  
14.1
      
26.9
  
Assets Held for Sale
  
-
      
3,353.3
  
Fair Value of Derivative Instruments
  
115.2
      
37.1
  
Other
  
32.6
      
36.8
  
   
1,317.2
      
4,683.6
  
   
              
Property, Plant and Equipment, Net
  
16,109.8
      
14,803.9
  
Notes Receivable—Related Parties
  
178.1
      
87.9
  
Investments
  
1,827.4
      
1,996.2
  
Goodwill
  
4,698.7
      
8,174.0
  
Other Intangibles, Net
  
251.5
      
321.1
  
Assets Held for Sale, Non-current
  
-
      
5,634.6
  
Fair Value of Derivative Instruments, Non-current
  
828.0
      
143.5
  
Deferred Charges and Other Assets
  
234.2
      
256.2
  
Total Assets
$
25,444.9
    
$
36,101.0
  


 
92
 
Item 8:   Financial Statements and Supplementary Data.  (continued)
Knight Form 10-K


KNIGHT INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (continued)
(In millions except share and per share amounts)
 
 
December 31,
2008
  
December 31,
2007
LIABILITIES AND STOCKHOLDER’S EQUITY
              
Current Liabilities
              
Current Maturities of Long-term Debt
$
293.7
    
$
79.8
  
Notes Payable
  
8.8
      
888.1
  
Cash Book Overdrafts
  
45.2
      
30.7
  
Accounts Payable
  
849.8
      
943.7
  
Accrued Interest
  
241.9
      
242.7
  
Accrued Taxes
  
152.1
      
728.2
  
Gas Imbalances
  
12.4
      
23.7
  
Liabilities Held for Sale
  
-
      
168.2
  
Fair Value of Derivative Instruments
  
129.5
      
594.7
  
Other
  
281.3
      
240.0
  
   
2,014.7
      
3,939.8
  
  
              
Long-term Debt
              
Outstanding Notes and Debentures
  
11,020.1
      
14,714.6
  
Deferrable Interest Debentures Issued to Subsidiary Trusts
  
35.7
      
283.1
  
Preferred Interest in General Partner of Kinder Morgan Energy Partners
  
100.0
      
100.0
  
Value of Interest Rate Swaps
  
971.0
      
199.7
  
  
  
12,126.8
      
15,297.4
  
  
              
Deferred Income Taxes, Non-current
  
2,081.3
      
1,849.4
  
Liabilities Held for Sale, Non-current
  
-
      
2,424.1
  
Fair Value of Derivative Instruments, Non-current
  
92.2
      
888.0
  
Other Long-term Liabilities and Deferred Credits
  
653.0
      
566.8
  
   
14,953.3
      
21,025.7
  
               
Minority Interests in Equity of Subsidiaries
  
4,072.6
      
3,314.0
  
               
Commitments and Contingencies (Notes 18 and 21)
              
  
              
Stockholder’s Equity
              
Common Stock – Authorized and Outstanding – 100 Shares, Par Value $0.01 Per Share
  
-
      
-
  
Additional Paid-in Capital
  
7,810.0
      
7,822.2
  
Retained Earnings (Deficit)
  
(3,352.3
)
    
247.0
  
Accumulated Other Comprehensive Loss
  
(53.4
)
    
(247.7
)
   
4,404.3
      
7,821.5
  
Total Liabilities and Stockholder’s Equity
$
25,444.9
    
$
36,101.0
  

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

 
93
 
Item 8:   Financial Statements and Supplementary Data.  (continued)
Knight Form 10-K


CONSOLIDATED STATEMENTS OF STOCKHOLDER’S EQUITY
(Dollars in millions)
 
 
Successor Company
 
Year Ended
December 31, 2008
  
Seven Months Ended
December 31, 2007
 
 
Shares
  
Amount
  
Shares
  
Amount
                               
Common Stock
  
100
    
$
-
      
100
    
$
-
  
  
                              
Additional Paid-in Capital
                              
Beginning Balance
          
7,822.2
              
-
  
MBO Purchase Price
          
-
              
7,831.2
  
Revaluation of Kinder Morgan Energy Partners (“KMP”) Investment (Note 14)
          
(19.8
)
            
(13.4
)
A-1 Unit Amortization
          
7.6
              
4.4
  
Ending Balance
          
7,810.0
              
7,822.2
  
  
                              
Retained Earnings (Deficit)
                              
Beginning Balance
          
247.0
              
-
  
Net (Loss) Income
          
(3,599.3
)
            
247.0
  
Ending Balance
          
(3,352.3
)
            
247.0
  
                               
Accumulated Other Comprehensive  Loss (Net of Tax)
                              
Derivatives
                              
Beginning Balance
          
(246.7
)
            
2.9
  
Change in Fair Value of Derivatives Utilized for Hedging Purposes
          
212.0
              
(249.6
)
Reclassification of Change in Fair Value of Derivatives to Net Income
          
117.1
              
-
  
Ending Balance
          
82.4
              
(246.7
)
Foreign Currency Translation
                              
Beginning Balance
          
27.6
              
-
  
Currency Translation Adjustment
          
(68.7
)
            
27.6
  
Ending Balance
          
(41.1
)
            
27.6
  
Employee Benefit Plans
                              
Beginning Balance
          
(28.6
)
            
-
  
Benefit Plan Adjustments
          
(66.5
)
            
(28.4
)
Benefit Plan Amortization
          
0.4
              
(0.2
)
Ending Balance
          
(94.7
)
            
(28.6
)
Total Accumulated Other Comprehensive Loss
          
(53.4
)
            
(247.7
)
  
                              
Total Stockholder’s Equity
  
100
    
$
4,404.3
      
100
    
$
7,821.5
  

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

 
94
 
Item 8:   Financial Statements and Supplementary Data.  (continued)
Knight Form 10-K


KNIGHT INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDER’S EQUITY (continued)
(Dollars in millions)
 
 
Predecessor Company
 
Five Months Ended
May 31, 2007
  
Year Ended
December 31, 2006
 
 
Shares
  
Amount
  
Shares
  
Amount
Common Stock
                              
Beginning Balance
  
149,166,709
    
$
745.8
      
148,479,863
    
$
742.4
  
Employee Benefit Plans
  
149,894
      
0.8
      
686,846
      
3.4
  
Ending Balance
  
149,316,603
      
746.6
      
149,166,709
      
745.8
  
Additional Paid-in Capital
                              
Beginning Balance
          
3,048.9
              
3,056.3
  
Revaluation of Kinder Morgan Energy Partners (“KMP”) Investment (Note 14)
          
3.4
              
(40.3
)
Employee Benefit Plans
          
7.7
              
33.2
  
Tax Benefits from Employee Benefit Plans
          
56.7
              
18.6
  
Implementation of SFAS No. 123(R) Deferred Compensation Balance
          
-
              
(36.9
)
Deferred Compensation (Note 17)
          
21.9
              
18.0
  
Ending Balance
          
3,138.6
              
3,048.9
  
Retained Earnings
                              
Beginning Balance
          
778.7
              
1,175.3
  
Net Income
          
65.9
              
71.9
  
Cash Dividends, Common Stock
          
(234.9
)
            
(468.5
)
Implementation of FIN No. 48 (Note 13)
          
(4.8
)
            
-
  
Ending Balance
          
604.9
              
778.7
  
Treasury Stock at Cost
                              
Beginning Balance
  
(15,022,751
)
    
(915.9
)
    
(14,712,901
)
    
(885.7
)
Treasury Stock Acquired
  
-
      
-
      
(339,800
)
    
(31.5
)
Employee Benefit Plans
  
(7,384
)
    
(0.5
)
    
29,950
      
1.3
  
Ending Balance
  
(15,030,135
)
    
(916.4
)
    
(15,022,751
)
    
(915.9
)
Deferred Compensation Plans
                              
Beginning Balance
          
-
              
(36.9
)
Implementation of SFAS No. 123(R) Balance Transfer to Additional Paid-in Capital
          
-
              
36.9
  
Ending Balance
          
-
              
-
  
Accumulated Other Comprehensive Loss (Net of Tax)
                              
Derivatives
                              
Beginning Balance
          
(60.8
)
            
(127.1
)
Change in Fair Value of Derivatives Utilized for Hedging Purposes
          
(21.3
)
            
44.6
  
Reclassification of Change in Fair Value of Derivatives to Net Income
          
10.3
              
21.7
  
Ending Balance
          
(71.8
)
            
(60.8
)
Foreign Currency Translation
                              
Beginning Balance
          
(24.5
)
            
7.4
  
Currency Translation Adjustment
          
40.1
              
(31.9
)
Ending Balance
          
15.6
              
(24.5
)
Minimum Pension Liability
                              
Beginning Balance
          
-
              
(7.3
)
Minimum Pension Liability Adjustments
          
-
              
7.3
  
Ending Balance
          
-
              
-
  
Employee Retirement Benefits
                              
Beginning Balance
          
(50.6
)
            
-
  
Benefit Plan Adjustments
          
-
              
(50.6
)
Benefit Plan Amortization
          
10.7
              
-
  
Ending Balance
          
(39.9
)
            
(50.6
)
                               
Total Accumulated Other Comprehensive Loss
          
(96.1
)
            
(135.9
)
  
                              
Total Stockholder’s Equity
  
134,286,468
    
$
3,477.6
      
134,143,958
    
$
3,521.6
  

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

 
95
 
Item 8:   Financial Statements and Supplementary Data.  (continued)
Knight Form 10-K


CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
 
 
Successor Company
    
Predecessor Company
 
Year Ended
December 31,
2008
  
Seven Months
Ended
December 31,
2007
    
Five Months
Ended
May 31,
2007
  
Year Ended
December 31,
2006
Cash Flows from Operating Activities
                                
Net (Loss) Income
$
(3,599.3
)
  
$
247.0
      
$
65.9
    
$
71.9
  
Adjustments to Reconcile Net (Loss) Income to Net Cash Flows from Operating Activities
                                
Loss (Income) from Discontinued Operations, Net of Tax
  
0.9
      
1.5
        
(287.9
)
    
542.8
  
Loss from Impairment of Assets
  
4,033.3
      
-
        
377.1
      
1.2
  
Loss on Early Extinguishment of Debt
  
23.6
      
-
        
4.4
      
-
  
Depreciation, Depletion and Amortization
  
918.4
      
476.2
        
264.9
      
540.3
  
Deferred Income Taxes
  
(496.4
)
    
(89.8
)
      
138.7
      
10.8
  
Income from the Allowance for Equity Funds Used During Construction
  
(10.9
)
    
-
        
-
      
-
  
Equity in Earnings of Equity Investees
  
(195.4
)
    
(54.3
)
      
(39.1
)
    
(100.6
)
Distributions from Equity Investees
  
241.6
      
86.5
        
48.2
      
74.8
  
Minority Interests in Income of Consolidated Subsidiaries
  
396.1
      
48.0
        
90.7
      
374.2
  
Gains from Property Casualty Indemnifications
  
-
      
-
        
(1.8
)
    
(15.2
)
Net Losses (Gains) on Sales of Assets
  
9.2
      
(6.3
)
      
(2.6
)
    
(22.0
)
Mark-to-Market Interest Rate Swap (Gain) Loss
  
(19.8
)
    
-
        
-
      
22.3
  
Foreign Currency Loss
  
0.2
      
-
        
15.5
      
-
  
Changes in Gas in Underground Storage
  
(28.0
)
    
51.3
        
(84.2
)
    
(35.3
)
Changes in Working Capital Items (Note 6)
  
(44.9
)
    
104.0
        
(202.9
)
    
80.0
  
Proceeds from (Payment for) Termination of Interest Rate Swaps
  
192.0
      
(2.2
)
      
51.9
      
-
  
Kinder Morgan Energy Partners’ Rate Reparations, Refunds and Reserve Adjustments
  
(13.7
)
    
140.0
        
-
      
(19.1
)
Other, Net
  
(9.3
)
    
45.8
        
54.4
      
(31.4
)
Net Cash Flows Provided by Continuing Operations
  
1,397.6
      
1,047.7
        
493.2
      
1,494.7
  
Net Cash Flows (Used in) Provided by Discontinued Operations
  
(0.8
)
    
(3.2
)
      
109.8
      
212.6
  
Net Cash Flows Provided by Operating Activities
  
1,396.8
      
1,044.5
        
603.0
      
1,707.3
  
  
                                
Cash Flows from Investing Activities
                                
Purchase of Predecessor Stock
  
-
      
(11,534.3
)
      
-
      
-
  
Capital Expenditures
  
(2,545.3
)
    
(1,287.0
)
      
(652.8
)
    
(1,375.6
)
Proceeds from Sale of 80% Interest in NGPL PipeCo LLC, Net of $1.1 Cash Sold
  
2,899.3
      
-
        
-
      
-
  
Terasen Acquisition
  
-
      
-
        
-
      
(10.6
)
Other Acquisitions
  
(47.6
)
    
(122.0
)
      
(42.1
)
    
(396.5
)
Loans to Customers
  
(109.6
)
    
-
        
-
      
-
  
Proceeds from (Investments in) NGPL PipeCo LLC Restricted Cash
  
3,106.4
      
(3,030.0
)
      
-
      
-
  
Net Proceeds from (Investment in) Margin Deposits
  
71.0
      
(39.3
)
      
(54.8
)
    
38.6
  
Distributions from Equity Investees
  
98.1
      
-
        
-
      
-
  
Contributions to Investments
  
(366.2
)
    
(246.4
)
      
(29.7
)
    
(6.1
)
Change in Natural Gas Storage and Natural Gas Liquids Line Fill Inventory
  
(7.2
)
    
10.0
        
8.4
      
(12.9
)
Property Casualty Indemnifications
  
-
      
-
        
8.0
      
13.1
  
Net Proceeds (Costs of Removal) from Sales of Assets
  
111.1
      
301.3
        
(1.5
)
    
92.2
  
Net Cash Flows Provided by (Used in) Continuing Investing Activities
  
3,210.0
      
(15,947.7
)
      
(764.5
)
    
(1,657.8
)
Net Cash Flows Provided by (Used in) Discontinued Investing Activities
  
-
      
196.6
        
1,488.2
      
(138.1
)
Net Cash Flows Provided by (Used in) Investing Activities
$
3,210.0
    
$
(15,751.1
)
    
$
723.7
    
$
(1,795.9
)


 
96
 
Item 8:   Financial Statements and Supplementary Data.  (continued)
Knight Form 10-K


KNIGHT INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (continued)
(In millions)
 
 
Successor Company
    
Predecessor Company
 
Year Ended
December 31,
2008
  
Seven Months
Ended
December 31,
2007
    
Five Months
Ended
May 31,
2007
  
Year Ended
December 31,
2006
Cash Flows from Financing Activities
                                
Short-term Debt, Net
$
(879.3
)
  
$
(52.6
)
    
$
(247.5
)
  
$
1,009.5
  
Long-term Debt Issued
  
2,113.2
      
8,805.0
        
1,000.0
      
-
  
Long-term Debt Retired
  
(5,874.6
)
    
(829.2
)
      
(302.4
)
    
(140.7
)
Issuance of Kinder Morgan, G.P., Inc. Preferred Stock
  
-
      
100.0
        
-
      
-
  
Discount (Premium) on Early Extinguishment of Debt
  
69.2
      
-
        
(4.2
)
    
-
  
Cash Book Overdraft
  
14.5
      
(14.0
)
      
(14.9
)
    
17.9
  
Issuance of Shares by Kinder Morgan Management, LLC
  
-
      
-
        
297.9
      
-
  
Other Common Stock Issued
  
-
      
-
        
9.9
      
38.7
  
Excess Tax Benefits from Share-based Payments
  
-
      
-
        
56.7
      
18.6
  
Cash Paid to Share-based Award Holders Due to Going Private Transaction
  
-
      
(181.1
)
      
-
      
-
  
Contributions from Successor Investors
  
-
      
5,112.0
        
-
      
-
  
Short-term Advances from (to) Unconsolidated Affiliates
  
2.7
      
10.9
        
2.3
      
(4.9
)
Treasury Stock Acquired
  
-
      
-
        
-
      
(34.3
)
Cash Dividends, Common Stock
  
-
      
-
        
(234.9
)
    
(468.5
)
Distributions to Minority Interests
  
(630.3
)
    
(259.6
)
      
(248.9
)
    
(575.0
)
Contributions from Minority Interests
  
561.5
      
342.9
        
-
      
353.8
  
Debt Issuance Costs
  
(15.9
)
    
(81.5
)
      
(13.1
)
    
(4.8
)
Other, Net
  
10.9
      
4.0
        
(0.1
)
    
(3.5
)
Net Cash Flows (Used In) Provided by Continuing Financing Activities
  
(4,628.1
)
    
12,956.8
        
300.8
      
206.8
  
Net Cash Flows Provided by (Used in) Discontinued Financing Activities
  
-
      
-
        
140.1
      
(118.1
)
Net Cash Flows (Used In) Provided by Financing Activities
  
(4,628.1
)
    
12,956.8
        
440.9
      
88.7
  
                                 
Effect of Exchange Rate Changes on Cash
  
(8.7
)
    
(2.8
)
      
7.6
      
6.6
  
  
                                
Effect of Accounting Change on Cash
  
-
      
-
        
-
      
12.1
  
  
                                
Cash Balance Included in Assets Held for Sale
  
-
      
(1.1
)
      
(2.7
)
    
(5.6
)
  
                                
Net (Decrease) Increase in Cash and Cash Equivalents
  
(30.0
)
    
(1,753.7
)
      
1,772.5
      
13.2
  
Cash and Cash Equivalents at Beginning of Period
  
148.6
      
1,902.3
        
129.8
      
116.6
  
Cash and Cash Equivalents at End of Period
$
118.6
    
$
148.6
      
$
1,902.3
    
$
129.8
  

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

 
97
 
Item 8:   Financial Statements and Supplementary Data.  (continued)
Knight Form 10-K


 
1.  Nature of Operations and Summary of Significant Accounting Policies
 
Nature of Operations
 
We are a large energy transportation and storage company, operating or owning an interest in approximately 36,000 miles of pipelines and approximately 170 terminals. We have both regulated and nonregulated operations. We also own the general partner interest and a significant limited partner interest in Kinder Morgan Energy Partners, L.P., a publicly traded pipeline limited partnership. Our executive offices are located at 500 Dallas Street, Suite 1000, Houston, Texas 77002 and our telephone number is (713) 369-9000. Unless the context requires otherwise, references to “we,” “us,” “our,” or the “Company” are intended to mean Knight Inc. (formerly Kinder Morgan, Inc.) and its consolidated subsidiaries both before and after the Going Private transaction discussed below. Unless the context requires otherwise, references to “Kinder Morgan Energy Partners” and “KMP” are intended to mean Kinder Morgan Energy Partners, L.P. and its consolidated subsidiaries.
 
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., of which we indirectly own all of the outstanding common equity, 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.
 
Basis of Presentation
 
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (“GAAP”) requires management to make estimates and assumptions. These estimates and assumptions affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities, and the reported amounts of revenues and expenses. Actual results could differ from these estimates.
 
Our consolidated financial statements include the accounts of Knight Inc. and our majority-owned subsidiaries, as well as those of (i) Kinder Morgan Energy Partners, (ii) Kinder Morgan Management and (iii) Triton Power Company LLC, in which we have a preferred investment. Except for Kinder Morgan Energy Partners, Kinder Morgan Management and Triton Power Company LLC, investments in 50% or less owned operations are accounted for under the equity method. All material intercompany transactions and balances have been eliminated. Certain prior period amounts have been reclassified to conform to the current presentation. Notwithstanding the consolidation of Kinder Morgan Energy Partners and its subsidiaries into our financial statements, we are not liable for, and our assets are not available to satisfy, the obligations of Kinder Morgan Energy Partners and/or its subsidiaries and vice versa. Responsibility for payments of obligations reflected in our or Kinder Morgan Energy Partners’ financial statements is a legal determination based on the entity that incurs the liability.
 
On May 30, 2007, Kinder Morgan, Inc. merged with a wholly owned subsidiary of Knight Holdco LLC, with Kinder Morgan, Inc. continuing as the surviving legal entity and subsequently renamed Knight Inc. Knight Holdco LLC is a private company owned by Richard D. Kinder, our Chairman and Chief Executive Officer; our co-founder William V. Morgan; former Kinder Morgan, Inc. board members Fayez Sarofim and Michael C. Morgan; other members of our senior management, most of whom are also senior officers of Kinder Morgan G.P., Inc. and Kinder Morgan Management; and affiliates of (i) Goldman Sachs Capital Partners, (ii) Highstar Capital, (iii) The Carlyle Group and (iv) Riverstone Holdings LLC. This transaction is referred to in this report as the Going Private transaction. As a result of this transaction, we are now privately owned, our stock is no longer traded on the New York Stock Exchange, and we have adopted a new basis of accounting for our assets and liabilities. This transaction was a “business combination” for accounting purposes, requiring that these investors, pursuant to SFAS No. 141, Business Combinations, record the assets acquired and liabilities assumed at their fair market values as of the acquisition date, resulting in a new basis of accounting.
 
As a result of the application of the SEC rules and guidance regarding “push down” accounting, the investors’ new accounting basis in our assets and liabilities is reflected in our financial statements effective with the closing of the Going Private transaction. Therefore, in the accompanying Consolidated Financial Statements, transactions and balances prior to the closing of the Going Private transaction (the amounts labeled “Predecessor Company”) reflect the historical accounting basis in our assets and liabilities, while the amounts subsequent to the closing (labeled “Successor Company”) reflect the push down of the investors’ new accounting basis to our financial statements. Hence, there is a blackline division on the financial statements and relevant notes, which is intended to signify that the amounts shown for periods prior to and subsequent to the Going Private transaction are not comparable.
 

 
98
 
Item 8:   Financial Statements and Supplementary Data.  (continued)
Knight Form 10-K


As required by SFAS No. 141 (applied by the investors and pushed down to our financial statements), effective with the closing of the Going Private transaction, all of our assets and liabilities have been recorded at their estimated fair market values based on an allocation of the aggregate purchase price paid in the Going Private transaction. To the extent that we consolidate less than wholly owned subsidiaries (such as Kinder Morgan Energy Partners, Kinder Morgan Management and Triton Power Company LLC), the reported assets and liabilities for these entities have been given a new accounting basis only to the extent of our economic ownership interest in those entities. Therefore, the assets and liabilities of these entities are included in our financial statements, in part, at a new accounting basis reflecting the investors’ purchase of our economic interest in these entities (approximately 50% in the case of Kinder Morgan Energy Partners and 14% in the case of Kinder Morgan Management). The remaining percentage of these assets and liabilities, reflecting the continuing minority ownership interest, is included at its historical accounting basis. The purchase price paid in the Going Private transaction and the allocation of that purchase price is as follows:
 
 
(In millions)
The Total Purchase Price Consisted of the Following
      
Cash Paid
$
5,112.0
  
Kinder Morgan, Inc. Shares Contributed
  
2,719.2
  
Equity Contributed
  
7,831.2
  
Cash from Issuances of Long-term Debt
  
4,696.2
  
Total Purchase Price
$
12,527.4
  
  
      
The Allocation of the Purchase Price is as Follows
      
Current Assets
$
1,551.2
  
Investments
  
897.8
  
Goodwill
  
13,786.1
  
Property, Plant and Equipment, Net
  
15,281.6
  
Deferred Charges and Other Assets
  
1,639.8
  
Current Liabilities
  
(3,279.5
)
Deferred Income Taxes, Non-current
  
(2,392.8
)
Other Long-term Liabilities and Deferred Credits
  
(1,786.3
)
Long-term Debt
  
(9,855.9
)
Minority Interests in Equity of Subsidiaries
  
(3,314.6
)
 
$
12,527.4
  


The following is a reconciliation of shares purchased and contributed and the Going Private transaction purchase price (in millions except per share information):
 
 
Number of
Shares
  
Price per
Share
  
Total Value
Shares Purchased with Cash
  
107.6
    
$
107.50
    
$
11,561.3
  
                       
Shares Contributed
                      
Richard D. Kinder
  
24.0
    
$
101.00
      
2,424.0
  
Other Kinder Morgan, Inc. Management and Board Members
  
2.7
    
$
107.50
      
295.2
  
Total Shares Contributed
  
26.7
              
2,719.2
  
                       
Total Shares Outstanding as of May 31, 2007
  
134.3
              
14,280.5
  
                       
Less: Portion of Shares Acquired using Knight Inc. Cash on Hand
                  
(1,756.8
)
Add: Cash Contributions by Management At or After May 30, 2007
                  
3.7
  
Purchase Price
                
$
12,527.4
  

The shares contributed by members of management and the board members other than Richard D. Kinder who were investors in the Going Private transaction were valued at $107.50 per share, the same as the amount per share paid to the public shareholders in the Going Private transaction. Richard D. Kinder agreed to value the shares he contributed at $101.00 per share because Mr. Kinder agreed to participate in the transaction at less than the merger price in order to help increase the merger price for the other public shareholders.
 
Revenue Recognition Policies
 
We recognize revenues as services are rendered or goods are delivered and, if applicable, title has passed. We generally sell natural gas under long-term agreements, with periodic price adjustments. In some cases, we sell natural gas under short-term agreements at prevailing market prices. In all cases, we recognize natural gas sales revenues when the natural gas is sold at a
 

 
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Item 8:   Financial Statements and Supplementary Data.  (continued)
Knight Form 10-K


fixed or determinable price, delivery has occurred and title has transferred, and collectibility of the revenue is reasonably assured. The natural gas we market is primarily purchased gas produced by third parties, and we market this gas to power generators, local distribution companies, industrial end-users and national marketing companies. We recognize gas gathering and marketing revenues in the month of delivery based on customer nominations and, in general our natural gas marketing revenues are recorded at gross, rather than net of cost of gas sold.
 
We provide various types of natural gas storage and transportation services to customers. When we provide these services, the natural gas remains the property of these customers at all times. In many cases (generally described as “firm service”), the customer pays a two-part rate that includes (i) a fixed fee reserving the right to transport or store natural gas in our facilities and (ii) a per-unit rate for volumes actually transported or injected into/withdrawn from storage. The fixed-fee component of the overall rate is recognized as revenue in the period the service is provided. The per-unit charge is recognized as revenue when the volumes are delivered to the customers’ agreed upon delivery point, or when the volumes are injected into/withdrawn from our storage facilities. In other cases (generally described as “interruptible service”), there is no fixed fee associated with the services because the customer accepts the possibility that service may be interrupted at our discretion in order to serve customers who have purchased firm service. In the case of interruptible service, revenue is recognized in the same manner utilized for the per-unit rate for volumes actually transported under firm service agreements. In addition to our “firm” and “interruptible” transportation services, we also provide natural gas park and loan service to assist customers in managing short-term gas surpluses or deficits. Revenues are recognized based on the terms negotiated under these contracts.
 
We provide crude oil transportation services and refined petroleum products transportation and storage services to customers. Revenues are recorded when products are delivered and services have been provided and adjusted according to terms prescribed by the toll settlements with shippers and approved by regulatory authorities.
 
We recognize bulk terminal transfer service revenues based on volumes loaded and unloaded. We recognize liquids terminal tank rental revenue ratably over the contract period. We recognize liquids terminal throughput revenue based on volumes received and volumes delivered. Liquids terminal minimum take-or-pay revenue is recognized at the end of the contract year or contract term depending on the terms of the contract. We recognize transmix processing revenues based on volumes processed or sold and if applicable, when title has passed. We recognize energy-related product sales revenues based on delivered quantities of product.
 
Revenues from the sale of oil, natural gas liquids and natural gas production are recorded using the entitlement method. Under the entitlement method, revenue is recorded when title passes based on our net interest. We record our entitled share of revenues based on entitled volumes and contracted sales prices. Since there is a ready market for oil and natural gas production, we sell the majority of our products soon after production at various locations, at which time title and risk of loss pass to the buyer. As a result, we maintain a minimum amount of product inventory in storage.
 
Restricted Deposits
 
Except as discussed following, Restricted Deposits consist of restricted funds on deposit with brokers in support of our risk management activities (see Note 15). The $3 billion of proceeds from NGPL PipeCo LLC’s sale of debt in a private placement (see Note 10) were held in escrow and are included in the caption “Current Assets: Assets Held for Sale” in the accompanying Consolidated Balance Sheet at December 31, 2007.
 
Accounts Receivable
 
The caption “Accounts, Notes and Interest Receivable, Net” in the accompanying Consolidated Balance Sheets is presented net of allowances for doubtful accounts. Our policy for determining an appropriate allowance for doubtful accounts varies according to the type of business being conducted and the customers being served. Generally, we make periodic reviews and evaluations of the appropriateness of the allowance for doubtful accounts based on a historical analysis of uncollected amounts, and we record adjustments as necessary for changed circumstances and customer-specific information. When specific receivables are determined to be uncollectible, the reserve and receivable are relieved.
 
Inventory
 
Our inventories of products consist of natural gas liquids, refined petroleum products, natural gas, carbon dioxide and coal. We report these assets at the lower of weighted-average cost or market. We report materials and supplies at the lower of cost or market.
 
Gas Imbalances and Gas Purchase Contracts
 
We value gas imbalances due to or due from interconnecting pipelines at the lower of cost or market. Gas imbalances represent the difference between customer nominations and actual gas receipts from and gas deliveries to our interconnecting pipelines and shippers under various operational balancing and shipper imbalance agreements. Natural gas imbalances are settled in cash or made up in-kind subject to the terms of the various pipelines’ tariffs or other contractual provisions.
 

 
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Item 8:   Financial Statements and Supplementary Data.  (continued)
Knight Form 10-K


Assets and Liabilities Held for Sale
 
On December 10, 2007, we entered into a definitive agreement to sell an 80% ownership interest in our NGPL business segment (primarily MidCon Corp, which was the parent of Natural Gas Pipeline Company of America) to Myria Acquisition Inc. (“Myria”), a Delaware corporation, for approximately $5.9 billion, subject to certain adjustments. The closing of the sale occurred on February 15, 2008. We continue to operate NGPL assets pursuant to a 15-year operating agreement. See Note 10 for further information regarding this transaction.
 
In accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, as of December 31, 2007, 100% of the assets and liabilities in our NGPL business segment were reclassified to assets and liabilities held for sale in connection with our February 2008 sale of an 80% interest in that segment. The non-current assets and long-term debt held for sale balances were reduced by the 20% ownership interest, which we retained in the NGPL business segment and recorded as an investment. Therefore, the accompanying Consolidated Balance Sheet at December 31, 2007 includes the following:
 
 
December 31,
2007
Current Assets: Assets Held for Sale
      
Restricted Deposits
$
3,030.0
  
Other
  
323.3
  
 
$
3,353.3
  
       
Assets Held for Sale, Non-current
      
Goodwill
$
5,216.4
  
Plant, Property and Equipment, Net
  
1,699.3
  
Deferred Charges and Other Assets
  
38.9
  
Less: Investment in Net Assets of NGPL
  
(1,320.0
)
 
$
5,634.6
  
       
Current Liabilities: Liabilities Held for Sale
$
168.2
  
       
Liabilities Held for Sale, Non-current
      
Long-term Debt: Outstanding Notes and Debentures
$
3,000.0
  
Other Liabilities and Minority Interests
  
24.1
  
Less: Investment in Long-term Debt of NGPL
  
(600.0
)
 
$
2,424.1
  

The 20% ownership interest that we retained in the NGPL business segment is included in our Consolidated Balance Sheet as of December 31, 2007 as follows:
 
Investments
      
20% Investment of NGPL’s Net Assets
$
1,320.0
  
20% Investment of NGPL’s Long-term Debt
  
(600.0
)
 
$
720.0
  

Pensions and Other Postretirement Benefits
 
We account for pension and other postretirement benefit plans according to the provisions of SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statement Nos. 87, 88, 106 and 132(R). This Statement requires us to fully recognize the overfunded or underfunded status of our consolidating subsidiaries’ pension and postretirement benefit plans as either assets or liabilities on our balance sheet.  For more information on our pension and postretirement benefit disclosures, see Note 16.
 
Accounting for Risk Management Activities
 
We utilize energy commodity derivative contracts for the purpose of mitigating our risk resulting from fluctuations in the market price of natural gas, natural gas liquids and crude oil. We also utilize interest rate swap agreements to mitigate our risk from fluctuations in interest rates and cross-currency interest rate swap agreements to mitigate foreign currency risk from our investments in businesses owned and operated outside the United States. Pursuant to current accounting provisions, we record our derivative contracts at their estimated fair values as of each reporting date. For more information on our risk management activities; see Note 15.
 

 
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Item 8:   Financial Statements and Supplementary Data.  (continued)
Knight Form 10-K


Property, Plant and Equipment
 
We report property, plant and equipment at its acquisition cost. We expense costs for maintenance and repairs in the period incurred. The cost of property, plant and equipment sold or retired and the related depreciation are removed from our balance sheet in the period of sale or disposition. For our pipeline system assets, we generally charge the original cost of property sold or retired to accumulated depreciation and amortization, net of salvage and cost of removal. We do not include retirement gain or loss in income except in the case of significant retirements or sales. Gains and losses on minor system sales, excluding land, are recorded to the appropriate accumulated depreciation reserve. Gains and losses for operating systems sales and land sales are booked to income or expense accounts in accordance with regulatory accounting guidelines.
 
We maintain natural gas in underground storage as part of our inventory. This component of our inventory represents the portion of gas stored in an underground storage facility generally known as “working gas,” and represents an estimate of the portion of gas in these facilities available for routine injection and withdrawal to meet demand. In addition to this working gas, underground gas storage reservoirs contain injected gas which is not routinely cycled but, instead, serves the function of maintaining the necessary pressure to allow efficient operation of the facility. This gas, generally known as “cushion gas,” is divided into the categories of “recoverable cushion gas” and “unrecoverable cushion gas,” based on an engineering analysis of whether the gas can be economically removed from the storage facility at any point during its life. The portion of the cushion gas that is determined to be unrecoverable is considered to be a permanent part of the facility itself (thus, part of our “Property, Plant & Equipment, Net” balance in the accompanying Consolidated Balance Sheets) and is depreciated over the facility’s estimated useful life. The portion of the cushion gas that is determined to be recoverable is also considered a component of the facility but is not depreciated because it is expected to ultimately be recovered and sold.
 
Depreciation on our long-lived assets is computed principally based on the straight-line method over their estimated useful lives. Generally, we apply composite depreciation rates to functional groups of property having similar economic characteristics. These rates range from 1.6% to 12.5%, excluding certain short-lived assets such as vehicles. Depreciation estimates are based on various factors, including age (in the case of acquired assets), manufacturing specifications, technological advances and historical data concerning useful lives of similar assets. Uncertainties that impact these estimates include changes in laws and regulations relating to restoration and abandonment requirements, economic conditions, and supply and demand in the area. When assets are put into service, we make estimates with respect to useful lives (and salvage values where appropriate) that we believe are reasonable. However, subsequent events could cause us to change our estimates, thus impacting the future calculation of depreciation and amortization expense. Historically, adjustments to useful lives have not had a material impact on our aggregate depreciation levels from year to year.
 
Our oil and gas producing activities are accounted for under the successful efforts method of accounting. Under this method costs that are incurred to acquire leasehold and subsequent development costs are capitalized. Costs that are associated with the drilling of successful exploration wells are capitalized if proved reserves are found. Costs associated with the drilling of exploratory wells that do not find proved reserves, geological and geophysical costs, and costs of certain non-producing leasehold costs are expensed as incurred. The capitalized costs of our producing oil and gas properties are depreciated and depleted by the units-of-production method. Other miscellaneous property, plant and equipment are depreciated over the estimated useful lives of the assets.
 
A gain on the sale of property, plant and equipment used in our oil and gas producing activities or in our bulk and liquids terminal activitities is calculated as the difference between the cost of the asset disposed of, net of depreciation, and the sales proceeds received. A gain on an asset disposal is recognized in income in the period that the sale is closed. A loss on the sale of property, plant and equipment is calculated as the difference between the cost of the asset disposed of, net of depreciation, and the sales proceeds received or the market value if the asset is being held for sale. A loss is recognized when the asset is sold or when the net cost of an asset held for sale is greater than the market value of the asset.
 
In addition, we engage in enhanced recovery techniques in which carbon dioxide is injected into certain producing oil reservoirs. In some cases, the acquisition cost of the carbon dioxide associated with enhanced recovery is capitalized as part of our development costs when it is injected. The acquisition cost associated with pressure maintenance operations for reservoir management is expensed when it is injected. When carbon dioxide is recovered in conjunction with oil production, it is extracted and re-injected, and all of the associated costs are expensed as incurred. Proved developed reserves are used in computing units of production rates for drilling and development costs, and total proved reserves are used for depletion of leasehold costs. The units-of-production rate is determined by field.
 
We evaluate the impairment of our long-lived assets in accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. SFAS No. 144 requires that long-lived assets that are to be disposed of by sale be measured at the lower of book value or fair value less the cost to sell. We review for the impairment of long-lived assets whenever events or changes in circumstances indicate that our carrying amount of an asset may not be recoverable. We would recognize an impairment loss when estimated future cash flows expected to result from our use of the asset and its eventual disposition are less than its carrying amount.
 

 
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Item 8:   Financial Statements and Supplementary Data.  (continued)
Knight Form 10-K


We evaluate our oil and gas producing properties for impairment of value on a field-by-field basis or, in certain instances, by logical grouping of assets if there is significant shared infrastructure, using undiscounted future cash flows based on total proved and risk-adjusted probable and possible reserves. Oil and gas producing properties deemed to be impaired are written down to their fair value, as determined by discounted future cash flows based on total proved and risk-adjusted probable and possible reserves or, if available, comparable market values. Unproved oil and gas properties that are individually significant are periodically assessed for impairment of value, and a loss is recognized at the time of impairment. Due to the decline in crude oil and natural gas prices during the course of 2008, on December 31, 2008, we conducted an impairment test on our oil and gas producing properties in Kinder Morgan Energy Partners’ CO2 business segment and determined that no impairment was necessary. For the purpose of impairment testing, we use the forward curve prices as observed at the test date. The forward curve cash flows may differ from the amounts presented in Supplemental Information on Oil and Gas Producing Activities (Unaudited) contained elsewhere herein, due to differences between the forward curve and spot prices.
 
Goodwill
 
Goodwill represents the excess of cost over fair value of the net assets of businesses acquired. The Company tests for impairment of goodwill on an annual basis and at any other time if events occur or circumstances indicate that the carrying amount of goodwill may not be recoverable. See Note 3 for more information about Goodwill and our annual impairment test.
 
Equity Method of Accounting
 
We account for investments greater than 20% in affiliates, which we do not control, by the equity method of accounting. Under this method, an investment is carried at our acquisition cost, plus our equity in undistributed earnings or losses since the acquisition, minus distributions received.
 
Income Taxes
 
Income tax expense is recorded based on an estimate of the effective tax rate in effect or to be in effect during the relevant periods. Deferred income tax assets and liabilities are recognized for temporary differences between the basis of assets and liabilities for financial reporting and tax purposes. Changes in tax legislation are included in the relevant computations in the period in which such changes are effective. Deferred tax assets are reduced by a valuation allowance for the amount of any tax benefit we do not expect to be realized. Note 13 contains information about our income taxes, including the components of our income tax provision and the composition of our deferred income tax assets and liabilities.
 
In determining the deferred income tax asset and liability balances attributable to our investments, we have applied an accounting policy that looks through our investments including our Kinder Morgan Energy Partners investment. The application of this policy resulted in no deferred income taxes being provided on the difference between the book and tax basis on the non-tax-deductible goodwill portion of our investment in Kinder Morgan Energy Partners. See Note 3 regarding the Going Private transaction goodwill assigned to our Kinder Morgan Energy Partners investment.
 
Environmental Matters
 
We expense or capitalize, as appropriate, environmental expenditures that relate to current operations. We expense expenditures that relate to an existing condition caused by past operations, which do not contribute to current or future revenue generation. We do not discount environmental liabilities to a net present value, and we record environmental liabilities when environmental assessments and/or remedial efforts are probable and we can reasonably estimate the costs. Generally, our recording of these accruals coincides with our completion of a feasibility study or our commitment to a formal plan of action. We recognize receivables for anticipated associated insurance recoveries when such recoveries are deemed to be probable.
 
We routinely conduct reviews of potential environmental issues and claims that could impact our assets or operations. These reviews assist us in identifying environmental issues and estimating the costs and timing of remediation efforts. We also routinely adjust our environmental liabilities to reflect changes in previous estimates. In making environmental liability estimations, we consider the material effect of environmental compliance, pending legal actions against us, and potential third-party liability claims. Often, as the remediation evaluation and effort progresses, additional information is obtained, requiring revisions to estimated costs. These revisions are reflected in our income in the period in which they are reasonably determinable. For more information on our environmental matters, see Note 21.
 
Legal
 
We are subject to litigation and regulatory proceedings as the result of our business operations and transactions. We utilize both internal and external counsel in evaluating our potential exposure to adverse outcomes from orders, judgments or settlements. In general, we expense legal costs as incurred and all recorded legal liabilities are revised as better information becomes available. When we identify specific litigation that is expected to continue for a significant period of time and require substantial expenditures, we identify a range of possible costs expected to be required to litigate the matter to a
 

 
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Item 8:   Financial Statements and Supplementary Data.  (continued)
Knight Form 10-K


conclusion or reach an acceptable settlement, and we accrue for such amounts. To the extent that actual outcomes differ from our estimates, or additional facts and circumstances cause us to revise our estimates, our earnings will be affected. For more information on our legal disclosures, see Note 21.
 
Foreign Currency Translation
 
We translate the financial statements of our foreign consolidated subsidiaries into United States dollars using the current rate method of foreign currency translation. Under this method, assets and liabilities are translated at the rate of exchange in effect at the balance sheet date, revenue and expense items are translated at average rates of exchange for the period, stockholder’s equity accounts at historical exchange rates and the exchange gains and losses arising on the translation of the financial statements are reflected as a separate component of the “Accumulated Other Comprehensive Income” caption in the accompanying Consolidated Balance Sheets.
 
Foreign currency transaction gains or losses, other than hedges of net investments in foreign companies, are included in results of operations. In 2006, we recorded net pre-tax losses of $22.5 million from foreign currency transactions and swaps. See Note 15 for information regarding our hedges of net investments in foreign companies.
 
Canadian dollars are designated as C$ in these Notes to Consolidated Financial Statements. To convert December 31, 2008 balances denominated in Canadian dollars to U.S. dollars, we used the December 31, 2008 Bank of Canada closing exchange rate of 0.8210 U.S. dollars per Canadian dollar.
 
Transfer of Net Assets Between Entities Under Common Control
 
We account for the transfer of net assets between entities under common control by carrying forward the net assets recognized in the balance sheets of each combining entity to the balance sheet of the combined entity, and no other assets or liabilities are recognized as a result of the combination. Transfers of net assets between entities under common control do not affect the income statement of the combined entity.
 
2.   Investment in Kinder Morgan Energy Partners, L.P.
 
At December 31, 2008, we owned, directly, and indirectly in the form of i-units corresponding to the number of shares of Kinder Morgan Management we owned, approximately 32.8 million limited partner units of Kinder Morgan Energy Partners. These units, which consist of 16.4 million common units, 5.3 million Class B units and 11.1 million i-units, represent approximately 12.3% of the total limited partner interests of Kinder Morgan Energy Partners. See Note 9 for additional information regarding Kinder Morgan Management and Kinder Morgan Energy Partners’ i-units. In addition, we are the sole common stockholder of the general partner of Kinder Morgan Energy Partners, which holds an effective 2% combined interest in Kinder Morgan Energy Partners and its operating partnerships. Together, our limited partner and general partner interests represented approximately 14.1% of Kinder Morgan Energy Partners’ total equity interests at December 31, 2008. As of the close of the Going Private transaction, our limited partner interests and our general partner interest represented an approximate 50% economic interest in Kinder Morgan Energy Partners. This difference results from the existence of incentive distribution rights held by the general partner shareholder.
 
In conjunction with Kinder Morgan Energy Partners’ acquisition of certain natural gas pipelines from us, we agreed to indemnify Kinder Morgan Energy Partners with respect to approximately $733.5 million of its debt. We would be obligated to perform under this indemnity only if Kinder Morgan Energy Partners’ assets were unable to satisfy its obligations.
 
Additional information regarding Kinder Morgan Energy Partners’ results of operations and financial position are contained in its Annual Report on Form 10-K for the year ended December 31, 2008.
 

 
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Item 8:   Financial Statements and Supplementary Data.  (continued)
Knight Form 10-K


3.  Goodwill and Other Intangibles
 
Goodwill
 
Changes in the carrying amount of our goodwill for the year ended December 31, 2008 are summarized as follows:
 
 
December 31,
2007
  
Acquisitions
and
Purchase Price
Adjustments1
  
Impairment
of Assets
  
Other2
  
December 31,
2008
 
(In millions)
Products Pipelines–KMP
$
2,179.4
      
$
(54.8
)
    
$
(1,266.5
)
  
$
(8.1
)
  
$
850.0
  
Natural Gas Pipelines–KMP
  
3,201.0
        
251.2
        
(2,090.2
)
    
(12.8
)
    
1,349.2
  
CO2–KMP
  
1,077.6
        
450.9
        
-
      
(6.8
)
    
1,521.7
  
Terminals–KMP
  
1,465.9
        
(9.5
)
      
(676.6
)
    
(5.6
)
    
774.2
  
Kinder Morgan Canada–KMP
  
250.1
        
-
        
-
      
(46.5
)
    
203.6
  
Consolidated Total
$
8,174.0
      
$
637.8
      
$
(4,033.3
)
  
$
(79.8
)
  
$
4,698.7
  
_______________
1
Adjustments relate primarily to a reallocation between goodwill and property, plant, and equipment in our final purchase price allocation.
2
Adjustments include (i) the translation of goodwill denominated in foreign currencies and (ii) reductions in goodwill due to reductions in our ownership percentage of Kinder Morgan Energy Partners.
 
We evaluate goodwill for impairment in accordance with the provisions of SFAS No. 142, Goodwill and Other Intangible Assets. For this purpose, we have six reporting units as follows: (i) Products Pipelines–KMP (excluding associated terminals), (ii) Products Pipelines Terminals–KMP (evaluated separately from Products Pipelines for goodwill purposes), (iii) Natural Gas Pipelines–KMP, (iv) CO–KMP, (v) Terminals–KMP and (vi) Kinder Morgan Canada–KMP. For investments we account for under the equity method of accounting, the premium or excess cost over underlying fair value of net assets is referred to as equity method goodwill and is not subject to amortization but rather to impairment testing in accordance with APB No. 18, The Equity Method of Accounting for Investments in Common Stock. As of both December 31, 2008 and December 31, 2007, we have reported $138.2 million of equity method goodwill within the caption “Investments” in the accompanying Consolidated Balance Sheets.
 
In the second quarter of 2008, we finalized the purchase price allocation associated with our May 2007 Going Private transaction, establishing the fair values of our individual assets and liabilities including assigning the associated goodwill to our six reporting units, in each case as of the May 31, 2007 acquisition date. A significant portion of the goodwill that arose in conjunction with this acquisition was determined to be associated with the general partner and significant limited partner interests in Kinder Morgan Energy Partners (a publicly traded master limited partnership, or “MLP”), attributable, in part, to the difference between the market multiples that might be paid to acquire the general partner and limited interests in an MLP and the market multiples that might be paid to acquire the individual assets that comprise that MLP. This market premium is partially attributable to the incentive distribution right that is embedded in the Kinder Morgan Energy Partners general partner interest for which a separate intangible asset was not recognized in purchase accounting because this right cannot be detached or transferred apart from the entire general partner interest.
 
In conjunction with our first annual impairment test of the carrying value of this goodwill, performed as of May 31, 2008, we determined that the fair value of certain reporting units that are part of our investment in Kinder Morgan Energy Partners were less than the carrying values. The fair value of each reporting unit was determined from the present value of the expected future cash flows from the applicable reporting unit (inclusive of a terminal value calculated using market multiples between six and nine times cash flows) discounted at a rate of 9.00%. In accordance with paragraph 23 of SFAS No. 142, the value of each reporting unit was determined on a stand-alone basis from the perspective of a market participant and represents the price that would be received to sell the unit as a whole in an orderly transaction between market participants at the measurement date. Thus, any value generated from the inclusion of these assets in an MLP structure was not captured in the valuation of these reporting units. This resulted in several of the reporting units having fair values less than their carrying values as the incremental value created by the inclusion of these assets in an MLP structure was taken into account in the Going Private transaction and thus was used in allocating the purchase price under SFAS No. 141. To capture this value at the reporting unit level, we believe it would be necessary to recreate the MLP structure at the reporting unit level. We believe this is not feasible for Knight Inc. or for any market participant, as further discussed below.
 
Recreating such structure would involve separating each of our reporting units into separate entities so that each reporting unit could be valued on a stand alone basis assuming each such unit was sold as an MLP. Creating separate MLPs would involve significant structural difficulties including potentially numerous adverse state and federal tax consequences to Kinder Morgan Energy Partners and its unitholders. In addition, it would involve a significant amount of tax, legal and commercial analysis, and based on that analysis may also require customer and/or joint venture consents, lender consents, and regulatory approvals and/or unitholder approval. As a result of these factors, we believe that it is not feasible to apply the MLP structure related
 

 
105
 
Item 8:   Financial Statements and Supplementary Data.  (continued)
Knight Form 10-K


value to the individual reporting unit level.
 
For the reporting units where the fair value was determined to be less than the carrying value, we determined the implied fair value of goodwill. The implied fair value of goodwill within each reporting unit was then compared to the carrying value of goodwill of each such unit, resulting in the following goodwill impairment charges by reporting units: Products Pipelines–KMP (excluding associated terminals) – $1.20 billion, Products Pipelines Terminals–KMP (separate from Products Pipelines–KMP for goodwill impairment purposes) - $70 million, Natural Gas Pipelines–KMP – $2.09 billion, and Terminals–KMP – $677 million, for a total impairment of $4.03 billion. The goodwill impairment charges are non-cash charges and do not have any impact on our cash flows.
 
The decline in the market price of crude oil since May 31, 2008 has required us to update our goodwill impairment analysis of the CO2–KMP segment as of December 31, 2008. The fair value of the CO2–KMP segment was determined from the present value of the expected future cash flows based on forward prices of crude oil as of December 31, 2008. The assumed price of oil for each year in our analysis was $54.32, $63.83, $68.79, $71.07 and $72.67 for the fiscal years 2009-2013. A terminal value calculated using a market multiple for similar assets was applied to 2013 cash flows. This calculated fair value of the CO2–KMP reporting unit was greater than the book value of this reporting unit and thus at December 31, 2008 goodwill impairment was not necessary.
 
On April 30, 2007, Kinder Morgan Energy Partners acquired the Trans Mountain pipeline system from us. This transaction caused us to evaluate the fair value of the Trans Mountain pipeline system in determining whether goodwill related to these assets was impaired. Accordingly, based on our consideration of supporting information obtained regarding the fair values of the Trans Mountain pipeline system assets, a goodwill impairment charge of $377.1 million was recorded in 2007.
 
In February 2007, we entered into a definitive agreement, which closed on May 17, 2007 (see Note 11) to sell Terasen Inc. to Fortis, Inc., a Canada-based company with investments in regulated distribution utilities. Execution of this sale agreement constituted an event of the type that, under GAAP, required us to consider the market value indicated by the definitive sales agreement in our 2006 goodwill impairment evaluation. Accordingly, based on the fair values of these reporting unit(s) derived principally from this definitive sales agreement, an estimated goodwill impairment charge of approximately $650.5 million was recorded in the 2006 period and is reported in the accompanying Consolidated Statement of Operations for the year ended December 31, 2006 within the caption, “Income (Loss) from Discontinued Operations, Net of Tax.”
 
Other Intangibles, Net
 
Our intangible assets other than goodwill include customer relationships, contracts and agreements, technology-based assets, lease values and other long-term assets. These intangible assets are being amortized on a straight-line basis over their estimated useful lives and are reported separately as “Other Intangibles, Net” in the accompanying Consolidated Balance Sheets. Following is information related to our intangible assets:
 
 
December 31,
 
2008
  
2007
 
(In millions)
Customer Relationships, Contracts and Agreements
              
Gross Carrying Amount
$
270.9
    
$
321.3
  
Accumulated Amortization
  
(30.3
)
    
(11.6
)
Net Carrying Amount
  
240.6
      
309.7
  
               
Technology-based Assets, Lease Value and Other
              
Gross Carrying Amount
  
11.7
      
11.7
  
Accumulated Amortization
  
(0.8
)
    
(0.3
)
Net Carrying Amount
  
10.9
      
11.4
  
               
Total Other Intangibles, Net
$
251.5
    
$
321.1
  

Amortization expense on our intangibles consisted of the following:
 
 
Successor Company
    
Predecessor Company
 
Year Ended
December 31,
2008
  
Seven Months
Ended
December 31,
2007
    
Five Months
Ended
May 31,
2007
  
Year Ended
December 31,
2006
 
(In millions)
    
(In millions)
Customer Relationships, Contracts and Agreements
$
18.7
    
$
11.6
      
$
6.1
    
$
15.0
  
Technology-based Assets, Lease Value and Other
  
0.5
      
0.3
        
0.2
      
0.2
  
Total Amortizations
$
19.2
    
$
11.9
      
$
6.3
    
$
15.2
  


 
106
 
Item 8:   Financial Statements and Supplementary Data.  (continued)
Knight Form 10-K


As of December 31, 2008, the weighted-average amortization period for our intangible assets was approximately 16.6 years. Our estimated amortization expense for these assets for each of the next five fiscal years is approximately $17.2 million, $17.0 million, $16.8 million, $16.5 million and $16.5 million, respectively.
4.  Other Investments
 
Our long-term investments as of December 31, 2008 consisted of equity investments totaling $1,814.2 million and bond investments totaling $13.2 million.
 
Our significant equity investments as of December 31, 2008 (and our percentage of ownership interests) consisted of:
 
 
·
NGPL PipeCo LLC (20%);
 
·
West2East Pipeline LLC (51%);
 
·
Plantation Pipe Line Company (51%);
 
·
Red Cedar Gathering Company (49%);
 
·
Express Pipeline System (33⅓%);
 
·
Cortez Pipeline Company (50%);
 
·
Fayetteville Express Pipeline LLC (50%); and
 
·
Midcontinent Express Pipeline LLC (50%);
 
On February 15, 2008, we sold an 80% ownership interest in NGPL PipeCo LLC (formerly MidCon Corp.), which owns Natural Gas Pipeline of America and certain affiliates, collectively referred to as “NGPL,” to Myria Acquisition Inc. (“Myria”). Pursuant to the purchase agreement, Myria acquired all 800 Class B shares and we retained all 200 Class A shares of NGPL PipeCo LLC. We will continue to operate NGPL’s assets pursuant to a 15-year operating agreement. Myria is owned by a syndicate of investors led by Babcock & Brown, an international investment and specialized fund and asset management group. See Note 10 for further discussion regarding this transaction.
 
Kinder Morgan Energy Partners operates and owns a 51% ownership interest in West2East Pipeline LLC, a limited liability company that is the sole owner of Rockies Express Pipeline LLC. ConocoPhillips owns a 24% ownership interest in West2East Pipeline LLC and Sempra Energy holds the remaining 25% interest. When construction of the entire Rockies Express Pipeline project is completed, Kinder Morgan Energy Partners’ ownership interest will be reduced to 50%, at which time the capital accounts of West2East Pipeline LLC will be trued up to reflect Kinder Morgan Energy Partners’ 50% economic interest in the project. According to the provisions of current accounting standards, because Kinder Morgan Energy Partners will receive 50% of the economics of the Rockies Express Pipeline project on an ongoing basis, Kinder Morgan Energy Partners is not considered the primary beneficiary of West2East Pipeline LLC and thus, accounts for its investment under the equity method of accounting.
 
Similarly, Kinder Morgan Energy Partners operates and owns an approximate 51% ownership interest in Plantation Pipe Line Company, and an affiliate of ExxonMobil owns the remaining approximate 49% interest. Each investor has an equal number of directors on Plantation’s board of directors, and board approval is required for certain corporate actions that are considered participating rights. Therefore, Kinder Morgan Energy Partners does not control Plantation Pipe Line Company and accounts for its investment under the equity method of accounting.
 
Kinder Morgan Energy Partners acquired its ownership interest in the Red Cedar Gathering Company from us on December 31, 1999, and acquired its ownership interest in the Express pipeline system from us effective August 28, 2008. Kinder Morgan Energy Partners acquired a 50% ownership interest in Cortez Pipeline Company from affiliates of Shell in April 2000. Kinder Morgan Energy Partners formed Midcontinent Express Pipeline LLC in May 2006.
 
On October 1, 2008, Kinder Morgan Energy Partners announced that it had entered into a 50/50 joint venture with Energy Transfer Partners, L.P. to build and develop the Fayetteville Express Pipeline, a new natural gas pipeline that will provide shippers in the Arkansas Fayetteville Shale area with takeaway natural gas capacity, added flexibility, and further access to growing markets. Fayetteville Express Pipeline LLC will construct the 187-mile, 42-inch diameter pipeline, which will originate in Conway County, Arkansas, continue eastward through White County, Arkansas, and terminate at an interconnect with Trunkline Gas Company’s pipeline in Quitman County, Mississippi. Pending necessary regulatory approvals, the approximately $1.2 billion pipeline project is expected to be in service by late 2010 or early 2011.
 
In 2007, Kinder Morgan Energy Partners began making cash contributions to Midcontinent Express Pipeline LLC, the sole owner of the  Midcontinent Express Pipeline, for its share of the Midcontinent Express Pipeline construction costs; however, as of December 31, 2008, Kinder Morgan Energy Partners had no net investment in Midcontinent Express Pipeline LLC because in 2008, Midcontinent Express Pipeline LLC established and made borrowings under its own revolving bank credit facility in order to fund its pipeline construction costs and to make distributions to its member owners to fully reimburse them for prior contributions.
 

 
107
 
Item 8:   Financial Statements and Supplementary Data.  (continued)
Knight Form 10-K


In January 2008, Midcontinent Express Pipeline LLC and MarkWest Pioneer, L.L.C. (a subsidiary of MarkWest Energy Partners, L.P.) entered into an option agreement, which provides MarkWest Pioneer, L.L.C. a one-time right to purchase a 10% ownership interest in Midcontinent Express Pipeline LLC after the pipeline is fully constructed and fully placed into service—currently estimated to be August 1, 2009. If the option is exercised, Kinder Morgan Energy Partners and Energy Transfer Partners, L.P. will each own 45% of Midcontinent Express Pipeline LLC, while MarkWest Pioneer, L.L.C. will own the remaining 10%.
 
In addition to the investments listed above, significant equity investments as of December 31, 2007 included a 25% equity interest in Thunder Creek Gas Services, LLC and a 49.5% interest in Thermo Cogeneration Partnerships, L.P. and Greenhouse Holdings, LLC (“Thermo Companies”). Kinder Morgan Energy Partners sold its ownership interest in Thunder Creek Gas Services, LLC to PVR Midstream LLC on April 1, 2008 and we sold our interests in the Thermo Companies to Bear Stearns on January 25, 2008. Both Kinder Morgan Energy Partners’ divestiture of its investment in Thunder Creek Gas Services, LLC and our sale of our investment in the Thermo Companies are discussed in Note 10.
 
The amount of our recorded long-term investments is as follows:
 
 
December 31,
 
2008
  
2007
 
(In millions)
Equity Method Investments:
          
NGPL PipeCo LLC
$
717.3
  
$
720.0
Express Pipeline System
  
64.9
    
402.1
Plantation Pipe Line Company
  
343.6
    
351.4
Thermo Companies
  
-
    
53.5
West2East Pipeline LLC
  
501.1
    
191.9
Red Cedar Gathering Company
  
138.9
    
135.6
Midcontinent Express Pipeline LLC
  
-
    
63.0
Thunder Creek Gas Services, LLC
  
-
    
37.0
Cortez Pipeline Company
  
13.6
    
14.2
Fayetteville Express Pipeline LLC
  
9.0
    
-
Horizon Pipeline Company1
  
-
    
-
Subsidiary Trusts Holding Solely Debentures of Kinder Morgan
  
8.6
    
8.6
All Others
  
17.2
    
18.9
Total Equity Investments
  
1,814.2
    
1,996.2
Gulf Opportunity Zone Bonds
  
13.2
    
-
Total Long-term Investments
$
1,827.4
  
$
1,996.2
____________
1
Balance at December 31, 2007 is included in the caption “Assets Held for Sale, Non-current” in the accompanying Consolidated Balance Sheet.

 
108
 
Item 8:   Financial Statements and Supplementary Data.  (continued)
Knight Form 10-K


Our earnings (losses) from equity investments and our amortization of excess costs over underlying fair value of net assets of these investments were as follows:
 
 
Successor Company
    
Predecessor Company
 
Year Ended
December 31,
2008
  
Seven Months
Ended
December 31,
2007
    
Five Months
Ended
May 31,
2007
  
Year Ended
December 31,
2006
 
(In millions)
    
(In millions)
NGPL PipeCo LLC
$
40.1
    
$
n/a
      
$
n/a
    
$
n/a
  
Cortez Pipeline Company
  
20.8
      
10.5
        
8.7
      
19.2
  
Express Pipeline System
  
8.2
      
14.9
        
5.0
      
17.1
  
Plantation Pipe Line Company
  
13.6
      
10.8
        
11.9
      
12.8
  
Thermo Companies
  
-
      
8.0
        
5.1
      
11.3
  
Red Cedar Gathering Company
  
26.7
      
16.1
        
11.9
      
36.3
  
Customer Works LP1
  
n/a
      
n/a
        
-
      
-
  
Thunder Creek Gas Services, LLC
  
1.3
      
1.2
        
1.0
      
2.5
  
Midcontinent Express Pipeline LLC
  
0.5
      
1.2
        
0.2
      
-
  
West2East Pipeline LLC
  
84.9
      
(8.2
)
      
(4.2
)
    
-
  
Horizon Pipeline Company
  
0.2
      
1.0
        
0.6
      
1.8
  
Heartland Pipeline Company2
  
n/a
      
-
        
-
      
-
  
All Others
  
4.8
      
1.3
        
0.5
      
3.2
  
Total
$
201.1
    
$
56.8
      
$
40.7
    
$
104.2
  
Amortization of Excess Costs
$
(5.7
)
  
$
(3.4
)
    
$
(2.4
)
  
$
(5.6
)
 
____________
1
This investment was part of the Terasen Inc. sale, therefore our earnings from it are included in “(Loss) Income from Discontinued Operations, Net of Tax” in the accompanying Consolidated Statements of Operations; see Note 11.
2
This investment was part of the North System sale, therefore our earnings from it are included in “(Loss) Income from Discontinued Operations, Net of Tax” in the accompanying Consolidated Statements of Operations; see Note 11.
 
Summarized combined unaudited financial information for our significant equity investments (listed above) is reported below (amounts represent 100% of investee financial information):
 
 
Year Ended December 31,
 
2008
  
2007
  
2006
 
(In millions)
Revenues
$
2,170.4
    
$
738.4
    
$
692.1
  
Costs and Expenses
  
1,649.6
      
534.4
      
483.2
  
Net Income
$
520.8
    
$
204.0
    
$
208.9
  
  
 
December 31,
 
2008
  
20071
 
(In millions)
Current Assets
$
501.7
  
$
3,566.2
Non-current Assets
  
13,582.1
    
11,469.5
Current Liabilities
  
3,876.4
    
572.3
Non-current Liabilities
  
5,306.0
    
6,078.4
Minority Interest in Equity of Subsidiaries
  
0.6
    
1.7
Partners’/Owners’ Equity
  
4,900.8
    
8,383.2
____________
1
Includes amounts associated with our NGPL business segment. In December 2007, we entered into a definitive agreement to sell an 80% ownership interest in our NGPL business segment. The closing of the sale occurred on February 15, 2008 (see Note 10).
 
5.  Asset Retirement Obligations
 
We have included $2.5 million of our total asset retirement obligations as of December 31, 2008 in the caption “Other” within “Current Liabilities” and the remaining $74.0 million in the caption “Other Long-term Liabilities and Deferred Credits:” in the accompanying Consolidated Balance Sheet. A reconciliation of the changes in our accumulated asset retirement obligations for the year ended December 31, 2008, seven months ended December 31, 2007 and five months ended May 31, 2007 is as follows:
 

 
109
 
Item 8:   Financial Statements and Supplementary Data.  (continued)
Knight Form 10-K



 
Successor Company
    
Predecessor
Company
 
Year Ended
December 31,
2008
  
Seven Months
Ended
December 31,
2007
    
Five Months
Ended
May 31, 2007
 
(In millions)
    
(In millions)
Balance at Beginning of Period
$
55.0
    
$
53.1
      
$
52.5
  
Additions
  
26.2
      
1.2
        
0.2
  
Liabilities Settled
  
(8.2
)1
    
(0.8
)
      
(0.7
)
Accretion Expense
  
3.5
      
1.5
        
1.1
  
Balance at End of Period
$
76.5
    
$
55.0
      
$
53.1
  
____________
1
Amount includes $2.8 million settled through our 80% sale of NGPL in 2008.
 
In the CO2–KMP business segment, we are required to plug and abandon oil and gas wells that have been removed from service and to remove our surface wellhead equipment and compressors. As of December 31, 2008 and December 31, 2007, we have recognized asset retirement obligations in the aggregate amount of $74.1 million and $49.2 million, respectively, relating to these requirements at existing sites within the CO2–KMP business segment. The $24.9 million increase since December 31, 2007 was primarily related to higher estimated service, material and equipment costs related to the CO2–KMP business segment’s legal obligations associated with the retirement of tangible long-lived assets.
 
In the Natural Gas Pipelines–KMP business segment, the operating systems are composed of underground piping, compressor stations and associated facilities, natural gas storage facilities and certain other facilities and equipment. Currently, we have no plans to abandon any of these facilities, the majority of which have been providing utility services for many years. However, if we were to cease providing utility services in total or in any particular area, we would be required to remove certain surface facilities and equipment from land belonging to our customers and others (we would generally have no obligations for removal or remediation with respect to equipment and facilities, such as compressor stations, located on land we own). We believe we can reasonably estimate both the time and costs associated with the retirement of these facilities and as of December 31, 2008 and December 31, 2007, we have recognized asset retirement obligations in the aggregate amount of $2.4 million and $3.0 million, respectively, relating to the businesses within the Natural Gas Pipelines–KMP business segment.
 
We have various other obligations throughout our businesses to remove facilities and equipment on rights-of- way and other leased facilities. We currently cannot reasonably estimate the fair value of these obligations because the associated assets have indeterminate lives. These assets include pipelines, certain processing plants and distribution facilities, and certain bulk and liquids terminal facilities. An asset retirement obligation, if any, will be recognized once sufficient information is available to reasonably estimate the fair value of the obligation.
 
6.  Cash Flow Information
 
We consider all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. “Other, Net,” presented as a component of “Cash Flows From Operating Activities” in the accompanying Consolidated Statements of Cash Flows includes, among other things, non-cash charges and credits to income including amortization of deferred revenue and amortization of gains and losses realized on the termination of interest rate swap agreements; see Note 15.
 

 
110
 
Item 8:   Financial Statements and Supplementary Data.  (continued)
Knight Form 10-K


ADDITIONAL CASH FLOW INFORMATION
 
Changes in Working Capital Items
(Net of Effects of Acquisitions and Sales)
Increase (Decrease) in Cash and Cash Equivalents
 
 
Successor Company
    
Predecessor Company
 
Year Ended
December 31,
2008
  
Seven Months
Ended
December 31,
2007
    
Five Months
Ended
May 31,
2007
  
Year Ended
December 31,
2006
 
(In millions)
    
(In millions)
Accounts Receivable
$
60.6
    
$
(64.3
)
    
$
(31.9
)
  
$
192.5
  
Materials and Supplies Inventory
  
(7.9
)
    
(8.1
)
      
(1.7
)
    
(0.5
)
Other Current Assets
  
11.1
      
(65.2
)
      
0.5
      
103.2
  
Accounts Payable
  
(99.3
)
    
68.7
        
26.3
      
(243.4
)
Accrued Interest
  
0.7
      
65.9
        
(22.5
)
    
56.7
  
Accrued Taxes
  
109.0
      
142.5
        
(114.0
)
    
(4.3
)
Other Current Liabilities
  
(119.1
)
    
(35.5
)
      
(59.6
)
    
(24.2
)
 
$
(44.9
)
  
$
104.0
      
$
(202.9
)
  
$
80.0
  
  
Supplemental Disclosures of Cash Flow Information
 
 
Successor Company
    
Predecessor Company
 
Year Ended
December 31,
2008
  
Seven Months
Ended
December 31,
2007
    
Five Months
Ended
May 31,
2007
  
Year Ended
December 31,
2006
 
(In millions)
    
(In millions)
Cash Paid for
                                
Interest (Net of Amount Capitalized)
$
649.9
    
$
586.5
      
$
381.8
    
$
731.6
  
Income Taxes Paid (Net of Refunds)1
$
657.3
    
$
146.4
      
$
133.3
    
$
314.9
  
__________
1
Income taxes paid during 2008 includes taxes paid related to prior periods.
 
During the year ended December 31, 2008, seven months ended December 31, 2007, five months ended May 31, 2007 and year ended December 31, 2006, we acquired $4.8 million, $1.2 million, $18.5 million and $6.1 million, respectively, of assets by the assumption of liabilities.
 
Non-cash investing activities during the year ended December 31, 2008, seven months ended December 31, 2007, five months ended May 31, 2007 and year ended December 31, 2006 include increases in the accrual for construction costs of $17.7 million, $83.0 million, $4.9 million and $70.5 million, respectively.
 
Pursuant to the purchase and sale agreement with Trans-Global Solutions, Inc., Kinder Morgan Energy Partners issued 266,813 common units in May 2007 to TGS to settle a purchase price liability related to its acquisition of bulk terminal operations from TGS in April 2005. As agreed between TGS and Kinder Morgan Energy Partners, the units were issued equal to a value of $15.0 million. Additionally, in December 2006, Kinder Morgan Energy Partners contributed 34,627 common units, representing approximately $1.7 million of value, as partial consideration for the acquisition of Devco USA L.L.C.
 
In March 2006, Kinder Morgan Energy Partners made a $17.0 million contribution of net assets to its investment in Coyote Gulch.
 
We adopted Emerging Issues Task Force No. 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, effective January 1, 2006 which resulted in the inclusion of the accounts, balances and results of operations of Kinder Morgan Energy Partners in our consolidated financial statements. Prior to January 1, 2006, we applied the equity method of accounting to our investment in Kinder Morgan Energy Partners. Therefore, we have included Kinder Morgan Energy Partners’ cash and cash equivalents at December 31, 2005 of $12.1 million as an “Effect of Accounting Change on Cash” in the accompanying Consolidated Statement of Cash Flows for the year ended December 31, 2006.
 
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 2.
 

 
111
 
Item 8:   Financial Statements and Supplementary Data.  (continued)
Knight Form 10-K


As discussed in Note 17 following, during the year ended December 31, 2006, we made non-cash grants of restricted shares of common stock.
 
7.  Transactions with Related Parties
 
Related-party operating revenues included in the accompanying Consolidated Statements of Operations for the year ended December 31, 2008, seven months ended December 31, 2007, five months ended May 31, 2007 and year ended December 31, 2006 were $11.5 million, $6.7 million, $4.5 million and $6.1 million, respectively:
 
During 2008, 2007 and 2006, related-party operating revenues were primarily attributable to Horizon Pipeline Company and Plantation Pipeline Company.
 
The caption “Gas Purchases and Other Costs of Sales” in the accompanying Consolidated Statements of Operations includes related-party costs totaling  $5.4 million, $0.8 million, $0.3 million and $1.5 million for the year ended December 31, 2008, seven months ended December 31, 2007, five months ended May 31, 2007 and year ended December 31, 2006, respectively. During 2008, related party “Gas Purchases and Other Costs of Sales” is primarily related to purchases from NGPL PipeCo LLC.
 
The caption “Interest Expense, Net” in the accompanying Consolidated Statements of Operations includes related-party costs totaling $5.5 million, $2.6 million, $1.8 million and $4.5 million for the year ended December 31, 2008, seven months ended December 31, 2007, five months ended May 31, 2007 and year ended December 31, 2006, respectively. Related party “Interest Expenses, Net” is primarily related to interest income from Plantation Pipe Line Company and Express US Holdings LP.
 
Significant Investors
 
As discussed in Note 1, as a result of the Going Private transaction, a number of individuals and entities became significant investors in us because of their investment in Knight Holdco LLC. By virtue of the size of their ownership interest, two of those investors became “related parties” to us as that term is defined in the authoritative accounting literature: (i) American International Group, Inc. and certain of its affiliates, including Highstar Capital (“AIG”) and (ii) Goldman Sachs Capital Partners and certain of its affiliates (“Goldman Sachs”). We enter into transactions with certain AIG affiliates in the ordinary course of their conducting insurance and insurance-related activities, although no individual transaction is, and all such transactions collectively are not, material to our consolidated financial statements. In addition, Goldman Sachs has provided, and may in the future provide, us and our affiliates investment banking services. Such activity is not material to our consolidated financial statements. We also conduct commodity risk management activities in the ordinary course of implementing our risk management strategies in which the counterparty to certain of our derivative transactions is an affiliate of Goldman Sachs. In conjunction with these activities, we are a party (through one of our subsidiaries engaged in the production of crude oil) to a hedging facility with J. Aron & Company/Goldman Sachs, which requires us to provide certain periodic information but does not require the posting of margin. As a result of changes in the market value of our derivative positions, we have recorded both amounts receivable from and payable to Goldman Sachs affiliates. At December 31, 2008 and December 31, 2007, the fair values of these derivative contracts are included in the accompanying Consolidated Balance Sheets within the captions indicated in the following table:
 
 
December 31,
2008
  
December 31,
2007
 
(In millions)
Derivative Assets (Liabilities)
              
Current Assets: Fair Value of Derivative Instruments
$
60.4
    
$
-
  
Assets: Fair Value of Derivative Instruments, Non-current
$
20.1
    
$
-
  
Current Liabilities: Fair Value of Derivative Instruments
$
(13.2
)
  
$
(239.8
)
Liabilities and Stockholder’s Equity: Fair Value of Derivative Instruments, Non-current
$
(24.1
)
  
$
(386.5
)

Knight Holdco LLC
 
In accordance with SFAS No. 123R (revised 2007), Share-Based Payment, our parent, Knight Holdco LLC, is required to recognize compensation expense in connection with its Class A-1 and Class B units over the expected life of such units. As a subsidiary of Knight Holdco LLC, we and certain of our subsidiaries are allocated this compensation expense, which totaled $7.6 million for the year ended December 31, 2008, although none of us or any of our subsidiaries have any obligation, nor do we expect to pay any amounts in respect of such units.
 

 
112
 
Item 8:   Financial Statements and Supplementary Data.  (continued)
Knight Form 10-K


Plantation Pipe Line Company
 
Kinder Morgan Energy Partners has a seven-year note receivable bearing interest at the rate of 4.72% per annum from Plantation Pipe Line Company, its 51.17%-owned equity investee. The outstanding note receivable balance was $88.5 million and $89.7 million as of December 31, 2008 and December 31, 2007, respectively. Of these amounts, $3.7 million and $2.4 million are included within “Accounts, Notes and Interest Receivable, Net” on the accompanying Consolidated Balance Sheets as of December 31, 2008 and December 31, 2007, respectively, and the remainder is included within “Accounts, Notes and Interest Receivable, Net ” at each reporting date.
 
Express US Holdings LP Note Receivable
 
On June 30, 2008, we exchanged our C$113.6 million preferred equity interest in Express US Holdings LP for two subordinated notes from Express US Holdings LP with a combined face value of $111.4 million (C$113.6 million).
 
On August 28, 2008, we sold our one-third interest in the net assets of the Express pipeline system (“Express”), as well as our full ownership of the net assets of the Jet Fuel pipeline system (“Jet Fuel”), to Kinder Morgan Energy Partners. This transaction included the sale of our subordinated notes described above. We accounted for this transaction as a transfer of net assets between entities under common control. Therefore, following our sale of Express and Jet Fuel to Kinder Morgan Energy Partners, Kinder Morgan Energy Partners recognized the assets and liabilities acquired at our carrying amounts (historical cost) at the date of transfer; see Note 14 for additional information relating to this sale.
 
As of December 31, 2008, the outstanding note receivable balance, representing the translated amount included in our consolidated financial statements in U.S. dollars, was $93.3 million, and we included this amount in the accompanying Consolidated Balance Sheet within the caption “Accounts, Notes and Interest Receivable, Net.”
 
Coyote Gas Treating, LLC
 
Coyote Gas Treating, LLC is a joint venture that was organized in December 1996. It is referred to as Coyote Gulch in this report. The sole asset owned by Coyote Gulch is a 250 million cubic feet per day natural gas treating facility located in La Plata County, Colorado. Prior to the contribution of Kinder Morgan Energy Partners’ ownership interest in Coyote Gulch to Red Cedar Gathering on September 1, 2006, discussed below, Kinder Morgan Energy Partners was the managing partner and owned a 50% equity interest in Coyote Gulch, with the Southern Ute Tribe owning the remaining 50%.
 
On September 1, 2006, Kinder Morgan Energy Partners and the Southern Ute Tribe contributed the value of their respective 50% ownership interests in Coyote Gulch to Red Cedar, and as a result, Coyote Gulch became a wholly owned subsidiary of Red Cedar. The value of Kinder Morgan Energy Partners’ 50% equity contribution from Coyote Gulch to Red Cedar on September 1, 2006 was $16.7 million, and this amount remains included within “Investments: Other” in the accompanying Consolidated Balance Sheets.
 
NGPL PipeCo LLC
 
On February 15, 2008, Knight Inc. entered in to an Operations and Reimbursement Agreement (“Agreement”) with Natural Gas Pipeline Company of America LLC, a wholly owned subsidiary of NGPL PipeCo LLC. The Agreement provides for Knight Inc. to be reimbursed, at cost, for pre-approved operations and maintenance costs, plus a $43.2 million annual general and administration fixed fee charge (“Fixed Fee”), for services provided under the Agreement. This Fixed Fee escalates at 3% each year through 2010 and is billed monthly. For the year ended December 31, 2008, these Fixed Fees totaled $38.9 million.
 
In addition, Kinder Morgan Energy Partners purchases transportation and storage services from NGPL PipeCo LLC. For the year ended December 31, 2008, these purchases totaled $8.1 million.
 
8.  Accounting for Minority Interests
 
The caption “Minority Interests in Equity of Subsidiaries” in the accompanying Consolidated Balance Sheets is comprised of the following balances:
 
 
December 31,
 
2008
  
2007
 
(In millions)
Kinder Morgan Energy Partners
$
2,198.2
    
$
1,616.0
  
Kinder Morgan Management
  
1,826.5
      
1,657.7
  
Triton Power Company LLC
  
39.0
      
29.2
  
Other
  
8.9
      
11.1
  
 
$
4,072.6
    
$
3,314.0
  


 
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During the year ended December 31, 2008, Kinder Morgan Energy Partners paid distributions of $3.89 per common unit, of which $626.6 million was paid to the public holders (represented in minority interests) of Kinder Morgan Energy Partners’ common units. On January 21, 2009, Kinder Morgan Energy Partners declared a quarterly distribution of $1.05 per common unit for the quarterly period ended December 31, 2008. The distribution was paid on February 13, 2009, to unitholders of record as of January 30, 2009.
 
9.  Kinder Morgan Management, LLC
 
On November 14, 2008, Kinder Morgan Management made a distribution of 0.021570 of its shares per outstanding share (1,646,891 total shares) to shareholders of record as of October 31, 2008, based on the $1.02 per common unit distribution declared by Kinder Morgan Energy Partners. On February 13, 2009, Kinder Morgan Management made a distribution of 0.024580 of its shares per outstanding share (1,917,189 total shares) to shareholders of record as of January 30, 2009, based on the $1.05 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 share determined for a ten-trading day period ending on the trading day immediately prior to the ex-dividend date for the shares. Kinder Morgan Management has paid share distributions totaling 5,565,424, 2,402,439, 2,028,367 and 4,383,303 shares in the years ended December 31, 2008, seven months ended December 31, 2007, five months ended May 31, 2007 and year ended December 31, 2006, respectively.
 
On May 15, 2007, Kinder Morgan Management issued 5.7 million listed shares in a public offering at a price of $52.26 per share. Kinder Morgan Management used the net proceeds of $297.9 million from the sale to purchase 5.7 million i-units from Kinder Morgan Energy Partners.
 
At December 31, 2008, we owned 11.1 million Kinder Morgan Management shares representing 14.3% of Kinder Morgan Management’s outstanding shares.
 
10. Business Combinations, Investments and Sales
 
The following acquisitions were accounted for as business combinations and the assets acquired and liabilities assumed were recorded at their estimated fair market values as of the acquisition date. The preliminary allocation of purchase price to assets acquired (and any liabilities assumed) may be adjusted to reflect the final determined amounts during a period of time following the acquisition. Although the time that is required to identify and measure the fair value of the assets acquired and the liabilities assumed in a business combination will vary with circumstances, generally our allocation period ends when we no longer are waiting for information that is known to be available or obtainable. Additionally, goodwill associated with transactions occurring prior to the Going Private transaction has been reallocated based on the purchase price paid in the Going Private transaction (See Note 1). The results of operations from these acquisitions are included in our consolidated financial statements from the acquisition date.
 
Entrega Gas Pipeline LLC
 
Effective February 23, 2006, Rockies Express Pipeline LLC acquired Entrega Gas Pipeline LLC from EnCana Corporation for $244.6 million in cash. West2East Pipeline LLC is a limited liability company and is the sole owner of Rockies Express Pipeline LLC. Kinder Morgan Energy Partners contributed 66 2/3% of the consideration for this purchase, which corresponded to its percentage ownership of West2East Pipeline LLC at that time. At the time of acquisition, Sempra Energy held the remaining 33 1/3% ownership interest and contributed this same proportional amount of the total consideration.
 
With regard to Rockies Express Pipeline LLC’s acquisition of Entrega Gas Pipeline LLC, the allocation of the purchase price to assets acquired and liabilities assumed was as follows (in millions):
 
Purchase Price
    
Cash Paid, Including Transaction Costs
$
244.6
Total Purchase Price
$
244.6
     
Allocation of Purchase Price
    
Property, Plant and Equipment
$
244.6
 
$
244.6

On the acquisition date, Entrega Gas Pipeline LLC owned the Entrega Pipeline, an interstate natural gas pipeline that when fully constructed, will be over 300 miles in length. The acquired assets are included in the Natural Gas Pipelines–KMP business segment.
 
In April 2006, Rockies Express Pipeline LLC merged with and into Entrega Gas Pipeline LLC, and the surviving entity was renamed Rockies Express Pipeline LLC. Going forward, the entire pipeline system (including the lines currently being developed by Rockies Express Pipeline LLC) will be known as the Rockies Express Pipeline. The combined 1,679-mile
 

 
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pipeline system will be one of the largest natural gas pipelines ever constructed in North America. The project, with an expected cost of $6.3 billion (including expansion) will have the capability to transport 1.8 billion cubic feet per day of natural gas, and binding firm commitments have been secured for virtually all of the pipeline capacity.
 
On June 30, 2006, ConocoPhillips exercised its option to acquire a 25% ownership interest in West2East Pipeline LLC. On that date, a 24% ownership interest was transferred to ConocoPhillips, and an additional 1% interest will be transferred once construction of the entire project is completed. Through Kinder Morgan Energy Partners’ subsidiary Kinder Morgan W2E Pipeline LLC, Kinder Morgan Energy Partners will continue to operate the project but its ownership interest decreased to 51% of the equity in the project (down from 66 2/3%). Sempra’s ownership interest in West2East Pipeline LLC decreased to 25% (down from 33 1/3%). When construction of the entire project is completed, Kinder Morgan Energy Partners’ ownership interest will be reduced to 50% at which time the capital accounts of West2East Pipeline LLC will be trued up to reflect our 50% economics in the project. We do not anticipate any additional changes in the ownership structure of the Rockies Express Pipeline project.
 
West2East Pipeline LLC qualifies as a variable interest entity as defined by Financial Accounting Standards Board Interpretation No. 46 (Revised December 2003), Consolidation of Variable Interest Entities-An Interpretation of ARB No. 51 (“FIN 46R”), because the total equity at risk is not sufficient to permit the entity to finance its activities without additional subordinated financial support provided by any parties, including equity holders. Furthermore, following ConocoPhillips’ acquisition of its ownership interest in West2East Pipeline LLC on June 30, 2006, Kinder Morgan Energy Partners receives 50% of the economics of the Rockies Express project on an ongoing basis and thus, effective June 30, 2006, Kinder Morgan Energy Partners was no longer considered the primary beneficiary of this entity as defined by FIN 46R. Accordingly, on that date, we made the change in accounting for the investment in West2East Pipeline LLC from full consolidation to the equity method following the decrease in Kinder Morgan Energy Partners’ ownership percentage.
 
Under the equity method, the costs of the investment in West2East Pipeline LLC are recorded within the “Investments” caption on the accompanying Consolidated Balance Sheets and as changes in the net assets of West2East Pipeline LLC occur (for example, earnings and dividends), we recognize our proportional share of that change in the investment account. We also record our proportional share of any accumulated other comprehensive income or loss within the “Accumulated Other Comprehensive Loss” caption in the accompanying Consolidated Balance Sheets.
 
In addition, Kinder Morgan Energy Partners has guaranteed its proportionate share of West2East Pipeline LLC’s debt borrowings under a $2 billion credit facility, a $2 billion commercial program and $600 million of senior notes entered into by Rockies Express Pipeline LLC. See Note 18 for additional information regarding Rockies Express Pipeline LLC’s debt.
 
Oil and Gas Properties
 
On April 5, 2006, Kinder Morgan Production Company L.P. purchased various oil and gas properties from Journey Acquisition – I, L.P. and Journey 2000, L.P. for an aggregate consideration of approximately $63.6 million, consisting of $60.0 million in cash and $3.6 million in assumed liabilities. The acquisition was effective March 1, 2006. However, Kinder Morgan Energy Partners divested certain acquired properties that were not considered candidates for carbon dioxide enhanced oil recovery, thus reducing the total investment. Kinder Morgan Energy Partners received proceeds of approximately $27.1 million from the sale of these properties.
 
The properties are primarily located in the Permian Basin area of West Texas, produce approximately 400 barrels of oil equivalent per day and include some fields with potential for enhanced oil recovery development near Kinder Morgan Energy Partners’ current carbon dioxide operations. The acquired operations are included as part of the CO2–KMP business segment.
 
The allocation of the purchase price to assets acquired and liabilities assumed was as follows (in millions):
 
Purchase Price
    
Cash Paid, Including Transaction Costs
$
60.0
Liabilities Assumed
  
3.6
Total Purchase Price
$
63.6
     
Allocation of Purchase Price
    
Current Assets
$
0.1
Property, Plant and Equipment
  
63.5
 
$
63.6


 
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Terminal Assets
 
In April 2006, Kinder Morgan Energy Partners acquired terminal assets and operations from A&L Trucking, L.P. and U.S. Development Group in three separate transactions for an aggregate consideration of approximately $61.9 million, consisting of $61.6 million in cash and $0.3 million in assumed liabilities.
 
The first transaction included the acquisition of equipment and infrastructure on the Houston Ship Channel that loads and stores steel products. The acquired assets complement Kinder Morgan Energy Partners’ nearby bulk terminal facility purchased from General Stevedores, L.P. in July 2005. The second acquisition included the purchase of a rail terminal at the Port of Houston that handles both bulk and liquids products. The rail terminal complements Kinder Morgan Energy Partners’ existing Texas petroleum coke terminal operations and maximizes the value of its existing deepwater terminal by providing customers with both rail and vessel transportation options for bulk products. Thirdly, Kinder Morgan Energy Partners acquired the entire membership interest of Lomita Rail Terminal LLC, a limited liability company that owns a high-volume rail ethanol terminal in Carson, California. The terminal serves approximately 80% of the Southern California demand for reformulated fuel blend ethanol with expandable offloading/distribution capacity, and the acquisition expanded Kinder Morgan Energy Partners’ existing rail transloading operations. All of the acquired assets are included in the Terminals–KMP business segment.
 
The allocation of the purchase price to assets acquired and liabilities assumed was as follows (in millions):
 
Purchase Price
    
Cash Paid, Including Transaction Costs
$
61.6
Liabilities Assumed
  
0.3
Total Purchase Price
$
61.9
     
Allocation of Purchase Price
    
Current Assets
$
0.5
Property, Plant and Equipment
  
43.6
Goodwill
  
17.8
 
$
61.9

A total of $17.8 million of goodwill was assigned to the Terminals–KMP business segment and the entire amount is expected to be deductible for tax purposes. Kinder Morgan Energy Partners believes the purchase price for the assets, including intangible assets, exceeded the fair value of acquired net assets and liabilities; in the aggregate, these factors represented goodwill.
 
Transload Services, LLC
 
Effective November 20, 2006, Kinder Morgan Energy Partners acquired all of the membership interests of Transload Services, LLC from Lanigan Holdings, LLC for an aggregate consideration of approximately $16.6 million, consisting of $15.8 million in cash and $0.8 million of assumed liabilities. Transload Services, LLC is a leading provider of innovative, high quality material handling and steel processing services, operating 14 steel-related terminal facilities located in the Chicago metropolitan area and various cities in the United States. Its operations include transloading services, steel fabricating and processing, warehousing and distribution, and project staging. Specializing in steel processing and handling, Transload Services can inventory product, schedule shipments and provide customers cost-effective modes of transportation. The combined operations include over 92 acres of outside storage and 445,000 square feet of covered storage that offers customers environmentally controlled warehouses with indoor rail and truck loading facilities for handling temperature and humidity sensitive products. The acquired assets are included in the Terminals–KMP business segment, and the acquisition further expanded and diversified Kinder Morgan Energy Partners’ existing terminals’ materials services (rail transloading) operations.
 
The allocation of the purchase price to assets acquired and liabilities assumed was as follows (in millions):
 
Purchase Price
    
Cash Paid, Including Transaction Costs
$
15.8
Liabilities Assumed
  
0.8
Total Purchase Price
$
16.6
     
Allocation of Purchase Price
    
Current Assets
$
1.6
Property, Plant and Equipment
  
6.6
Goodwill
  
8.4
 
$
16.6


 
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Knight Form 10-K


A total of $8.4 million of goodwill was assigned to the Terminals–KMP business segment, and the entire amount is expected to be deductible for tax purposes. Kinder Morgan Energy Partners believes this acquisition resulted in the recognition of goodwill primarily because it establishes a business presence in several key markets, taking advantage of the non-residential and highway construction demand for steel that contributed to our acquisition price exceeding the fair value of acquired identifiable net assets and liabilities - in the aggregate, these factors represented goodwill.
 
Devco USA L.L.C.
 
Effective December 1, 2006, Kinder Morgan Energy Partners acquired all of the membership interests in Devco USA L.L.C., an Oklahoma limited liability company, for an aggregate consideration of approximately $7.3 million, consisting of $4.8 million in cash, $1.6 million in common units and $0.9 million of assumed liabilities. The primary asset acquired was a technology-based identifiable intangible asset, a proprietary process that transforms molten sulfur into premium solid formed pellets that are environmentally friendly, easy to handle and store, and safe to transport. The process was developed internally by Devco’s engineers and employees. Devco, a Tulsa, Oklahoma-based company, has more than 20 years of sulfur handling expertise and Kinder Morgan Energy Partners believes the acquisition and subsequent application of this acquired technology complements its existing dry-bulk terminal operations. Kinder Morgan Energy Partners allocated $6.5 million of the total purchase price to the value of this intangible asset, which is included as part of the Terminals–KMP business segment.
 
The allocation of the purchase price to assets acquired and liabilities assumed was as follows (in millions):
 
Purchase Price
    
Cash Paid, Including Transaction Costs
$
4.8
Issuance of Common Units
  
1.6
Liabilities Assumed
  
0.9
Total Purchase Price
$
7.3
     
Allocation of Purchase Price
    
Current Assets
$
0.8
Deferred Charges and Other Assets
  
6.5
 
$
7.3

Roanoke, Virginia Products Terminal
 
Effective December 15, 2006, Kinder Morgan Energy Partners acquired a refined petroleum products terminal located in Roanoke, Virginia from Motiva Enterprises, LLC for approximately $6.4 million in cash. The terminal has storage capacity of approximately 180,000 barrels per day for refined petroleum products like gasoline and diesel fuel. The terminal is served exclusively by the Plantation Pipeline and Motiva has entered into a long-term contract to use the terminal. The acquisition complemented the other refined products terminals Kinder Morgan Energy Partners owns in the southeastern region of the United States, and the acquired terminal is included as part of the Products Pipelines–KMP business segment.
 
The allocation of the purchase price to assets acquired and liabilities assumed was as follows (in millions):
 
Purchase Price
    
Cash Paid, Including Transaction Costs
$
6.4
Total Purchase Price
$
6.4
     
Allocation of Purchase Price
    
Property, Plant and Equipment
$
6.4
 
$
6.4

Interest in Cochin Pipeline
 
Effective January 1, 2007, Kinder Morgan Energy Partners acquired the remaining approximate 50.2% interest in the Cochin pipeline system that it did not already own for an aggregate consideration of approximately $47.8 million, consisting of $5.5 million in cash and a note payable having a fair value of $42.3 million. As part of the transaction, the seller also agreed to reimburse Kinder Morgan Energy Partners for certain pipeline integrity management costs over a five-year period in an aggregate amount not to exceed $50 million. Upon closing, Kinder Morgan Energy Partners became the operator of the pipeline.
 
The Cochin Pipeline is a multi-product liquids pipeline consisting of approximately 1,900 miles of pipe operating between Fort Saskatchewan, Alberta, and Windsor, Ontario, Canada. Its operations are included as part of the Products Pipeline–KMP business segment.
 

 
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Knight Form 10-K


The allocation of the purchase price to assets acquired and liabilities assumed was as follows (in millions):
 
Purchase Price
    
Cash Paid, Including Transaction Costs
$
5.5
Notes Payable (Fair Value)
  
42.3
Total Purchase Price
$
47.8
     
Allocation of Purchase Price
    
Property, Plant and Equipment
$
47.8
 
$
47.8

Vancouver Wharves Terminal
 
On May 30, 2007, Kinder Morgan Energy Partners purchased the Vancouver Wharves bulk marine terminal from British Columbia Railway Company, a crown corporation owned by the Province of British Columbia, for aggregate consideration of $59.5 million, consisting of $38.8 million in cash and $20.7 million in assumed liabilities. The acquisition both expanded and complemented Kinder Morgan Energy Partners’ existing terminal operations and all of the acquired assets are included in the Terminals–KMP business segment.
 
In the first half of 2008, Kinder Morgan Energy Partners made its final purchase price adjustments to reflect final fair value of acquired assets and final expected value of assumed liabilities. Kinder Morgan Energy Partners’ adjustments increased “Property, Plant and Equipment, Net” by $2.7 million, reduced working capital balances by $1.6 million, and increased long-term liabilities by $1.1 million. Based on Kinder Morgan Energy Partners’ estimate of fair market values, we allocated $53.4 million of our combined purchase price to “Property, Plant and Equipment, Net,” and $6.1 million to items included within “Current Assets.”
 
The allocation of the purchase price to assets acquired and liabilities assumed was as follows (in millions):
 
Purchase Price
    
Cash Paid, Including Transaction Costs
$
38.8
Assumed Liabilities
  
20.7
Total Purchase Price
$
59.5
  
    
Allocation of Purchase Price
    
Current Assets
$
6.1
Property, Plant and Equipment
  
53.4
 
$
59.5

Marine Terminals, Inc.
 
Effective September 1, 2007, Kinder Morgan Energy Partners acquired certain bulk terminals assets from Marine Terminals, Inc. for an aggregate consideration of approximately $102.1 million, consisting of $100.8 million in cash and assumed liabilities of $1.3 million. The acquired assets and operations are primarily involved in the handling and storage of steel and alloys. The acquisition both expanded and complemented Kinder Morgan Energy Partners existing ferro alloy terminal operations and will provide customers further access to Kinder Morgan Energy Partners’ growing national network of marine and rail terminals. All of the acquired assets are included in the Terminals-KMP business segment.
 
During 2008, Kinder Morgan Energy Partners paid an additional $0.5 million for purchase price settlements, and made purchase price adjustments to reflect final fair value of acquired assets and final expected value of assumed liabilities. Kinder Morgan Energy Partners’ 2008 adjustments primarily reflected changes in the allocation of the purchase cost to intangible assets acquired. Based on Kinder Morgan Energy Partners’ estimate of fair market values, we allocated $60.8 million of the combined purchase price to “Property, Plant and Equipment, Net,” $21.7 million to “Other Intangibles, Net,” $18.6 million to “Goodwill,” and $1.0 million to “Current Assets: Other” and “Deferred Charges and Other Assets.”
 
The allocation to “Other Intangibles, Net” included a $20.1 million amount representing the fair value of a service contract entered into with Nucor Corporation, a large domestic steel company with significant operations in the Southeast region of the United States. For valuation purposes, the service contract was determined to have a useful life of 20 years, and pursuant to the contract’s provisions, the acquired terminal facilities will continue to provide Nucor with handling, processing, harboring and warehousing services.
 
The allocation to “Goodwill,” which is expected to be deductible for tax purposes, was based on the fact that this acquisition both expanded and complemented Kinder Morgan Energy Partners’ existing ferro alloy terminal operations and will provide Nucor and other customers further access to Kinder Morgan Energy Partners’ growing national network of marine and rail
 

 
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terminals. Kinder Morgan Energy Partners believes the acquired value of the assets, including all contributing intangible assets, exceeded the fair value of acquired identifiable net assets and liabilities—in the aggregate, these factors represented goodwill.
 
The allocation of the purchase price to assets acquired and liabilities assumed was as follows (in millions):
 
Purchase Price
    
Cash Paid, Including Transaction Costs
$
100.8
Assumed Liabilities
  
1.3
Total Purchase Price
$
102.1
     
Allocation of Purchase Price
    
Current Assets
$
0.2
Property, Plant and Equipment
  
60.8
Deferred Charges and Other
  
22.5
Goodwill
  
18.6
 
$
102.1

Wilmington, North Carolina Liquids Terminal
 
On August 15, 2008, Kinder Morgan Energy Partners purchased certain terminal assets from Chemserve, Inc. for an aggregate consideration of $12.7 million, consisting of $11.8 million in cash and $0.9 million in assumed liabilities. The liquids terminal facility is located in Wilmington, North Carolina and stores petroleum products and chemicals. The acquisition both expanded and complemented Kinder Morgan Energy Partners’ existing Mid-Atlantic region terminal operations and all of the acquired assets are included in the Terminals–KMP business segment. In the fourth quarter of 2008, the purchase price was allocated to reflect the final fair value of acquired assets and final expected value of assumed liabilities. A total of $6.8 million of goodwill was assigned to the Terminals–KMP business segment and the entire amount is expected to be deductible for tax purposes. Kinder Morgan Energy Partners believes this acquisition resulted in the recognition of goodwill primarily because of certain advantageous factors (including the synergies provided by increasing the liquids storage capacity in the Southeast region of the U.S.) that contributed to the acquisition price exceeding the fair value of acquired identifiable net assets and liabilities—in the aggregate, these factors represented goodwill.
 
Purchase Price
    
Cash Paid, Including Transaction Costs
$
11.8
Assumed Liabilities
  
0.9
Total Purchase Price
$
12.7
     
Allocation of Purchase Price
    
Property, Plant and Equipment
$
5.9
Goodwill
  
6.8
 
$
12.7

Phoenix, Arizona Products Terminal
 
Effective December 10, 2008, Kinder Morgan Energy Partners’ West Coast Products Pipelines acquired a refined petroleum products terminal located in Phoenix, Arizona from ConocoPhillips for approximately $27.5 million in cash. The terminal has storage capacity of approximately 200,000 barrels for gasoline, diesel fuel and ethanol. The acquisition complemented Kinder Morgan Energy Partners’ existing Phoenix liquids assets, and the acquired incremental storage will increase Kinder Morgan Energy Partners’ combined storage capacity in the Phoenix market by approximately 13%. The acquired terminal is included as part the Products Pipelines-KMP business segment.
 
Purchase Price
    
Cash Paid, Including Transaction Costs
$
27.5
Total Purchase Price
$
27.5
     
Allocation of Purchase Price
    
Property, Plant and Equipment
$
27.5
 
$
27.5


 
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Investment in Rockies Express Pipeline
 
In 2008, Kinder Morgan Energy Partners made capital contributions of $306.0 million to West2East Pipeline LLC (the sole owner of Rockies Express Pipeline LLC) to partially fund its Rockies Express Pipeline construction costs. This cash contribution was recorded as an increase to “Investments” in the accompanying Consolidated Balance Sheet as of December 31, 2008, and it was included within “Cash Flows from Investing Activities: Contributions to Investments” in the accompanying Consolidated Statement of Cash Flows for the year ended December 31, 2008. Kinder Morgan Energy Partners owns a 51% equity interest in West2East Pipeline LLC.
 
Midcontinent Express Pipeline LLC
 
During 2008, Kinder Morgan Energy Partners made capital contributions of $27.5 million to Midcontinent Express Pipeline LLC (“Midcontinent Express Pipeline”) to partially fund its Midcontinent Express Pipeline construction costs. This cash contribution has been recorded as an increase to “Investments” in the accompanying Consolidated Balance Sheet as of December 31, 2008 and has been included within “Cash Flows from Investing Activities: Contributions to Investments” in the accompanying Consolidated Statement of Cash Flows for the year ended December 31, 2008. Kinder Morgan Energy Partners owns a 50% equity interest in Midcontinent Express Pipeline LLC.
 
Kinder Morgan Energy Partners received, in 2008, an $89.1 million return of capital from Midcontinent Express Pipeline LLC. In February 2008, Midcontinent Express Pipeline LLC entered into and then made borrowings under a new $1.4 billion three-year, unsecured revolving credit facility due February 28, 2011. Midcontinent Express Pipeline LLC then made distributions (in excess of cumulative earnings) to its two member owners to reimburse them for prior contributions made to fund its pipeline construction costs, and this cash receipt has been included in “Cash Flows from Investing Activities: Distributions from Equity Investees” in the accompanying Consolidated Statement of Cash Flows for the year ended December 31, 2008.
 
Fayetteville Express Pipeline LLC
 
On October 1, 2008, Kinder Morgan Energy Partners announced that it has entered into a 50/50 joint venture with Energy Transfer Partners, L.P. to build and develop the Fayetteville Express Pipeline, a new natural gas pipeline that will provide shippers in the Arkansas Fayetteville Shale area with takeaway natural gas capacity, added flexibility and further access to growing markets.
 
The new pipeline will also interconnect with Natural Gas Pipeline Company of America LLC’s pipeline in White County, Arkansas; Texas Gas Transmission LLC’s pipeline in Coahoma County, Mississippi; and ANR Pipeline Company’s pipeline in Quitman County, Mississippi. Natural Gas Pipeline Company of America LLC’s pipeline is operated and 20% owned by us. The Fayetteville Express Pipeline will have an initial capacity of two billion cubic feet of natural gas per day. Pending necessary regulatory approvals, the approximately $1.2 billion pipeline project is expected to be in service by late 2010 or early 2011. Fayetteville Express Pipeline LLC has secured binding 10-year commitments totaling approximately 1.85 billion cubic feet per day.
 
In the fourth quarter of 2008, Kinder Morgan Energy Partners made capital contributions of $9.0 million to Fayetteville Express Pipeline LLC to fund its proportionate share of certain pre-construction pipeline costs. We included this cash contribution as an increase to “Investments” in the accompanying Consolidated Balance Sheet as of December 31, 2008, and we included it within “Cash Flows from Investing Activities: Contributions to Investments” in the accompanying Consolidated Statement of Cash Flows for the year ended December 31, 2008.
 
Pro Forma Information
 
Pro forma information regarding consolidated income statement information that assumes all of the acquisitions we have made and joint ventures we have entered into since January 1, 2007, including the ones listed above, had occurred as of January 1, 2007, is not materially different from the information presented in the accompanying Consolidated Statements of Operations.
 
Sales
 
In connection with the August 28, 2008 sale to Kinder Morgan Energy Partners of our 33 1/3% ownership interest in the Express pipeline system and our full ownership of the Jet Fuel pipeline system, Kinder Morgan Energy Partners issued 2,014,693 of common units to us. The units were issued August 28, 2008, and as agreed between Kinder Morgan Energy Partners and us, were valued at $116.0 million. We accounted for this transaction as a transfer of net assets between entities under common control. Kinder Morgan Energy Partners recognized these assets and liabilities acquired at our carrying amounts (historical cost) at the date of transfer. For more information on this transaction; see Note 7.
 

 
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Knight Form 10-K


Effective April 1, 2008, Kinder Morgan Energy Partners sold its 25% ownership interest in Thunder Creek Gas Services, LLC to PVR Midstream LLC, a subsidiary of Penn Virginia Corporation. Prior to the sale, we accounted for the investment in Thunder Creek Gas Services, LLC, referred to in this report as Thunder Creek, under the equity method of accounting and included its financial results within the Natural Gas Pipelines–KMP business segment. In the second quarter of 2008, Kinder Morgan Energy Partners received cash proceeds, net of closing costs and settlements, of approximately $50.7 million for the investment and used the proceeds from this sale to reduce the commercial paper borrowings. Due to the fair market valuation resulting from the Going Private transaction (see Note 1), the consideration Kinder Morgan Energy Partners received from the sale of its North System was equal to its carrying value; therefore no gain or loss was recorded on this disposal transaction.
 
On February 15, 2008, we sold an 80% ownership interest in NGPL PipeCo LLC (formerly MidCon Corp.), which owns Natural Gas Pipeline Company of America LLC and certain affiliates, collectively referred to as “NGPL,” to Myria Acquisition Inc. (“Myria”) for approximately $2.9 billion. We also received approximately $3.0 billion of cash previously held in escrow related to a notes offering by NGPL PipeCo LLC in December 2007, the net proceeds of which were distributed to us principally as repayment of intercompany indebtedness and partially as a dividend, immediately prior to the closing of the sale to Myria. Pursuant to the purchase agreement, Myria acquired all 800 Class B shares and we retained all 200 Class A shares of NGPL PipeCo LLC. We continue to operate NGPL’s assets pursuant to a 15-year operating agreement. Myria is owned by a syndicate of investors led by Babcock & Brown, an international investment and specialized fund and asset management group. The total proceeds from this sale of $5.9 billion were used to pay off the entire outstanding balances of our senior secured credit facility’s Tranche A and Tranche B term loans, to repurchase $1.67 billion of our outstanding debt securities and to reduce balances outstanding under our $1.0 billion revolving credit facility (see Note 14).
 
In January 2008, we completed the sale of our interests in three natural gas-fired power plants in Colorado to Bear Stearns. We received proceeds of $63.1 million.
 
During 2007, we completed the sales of (i) our U.S.-based retail natural gas distribution and related operations, (ii) Terasen Inc., our Canada-based retail natural gas distribution operations, which we previously referred to as the Terasen Gas business segment and (iii) Terasen Pipelines (Corridor) Inc. Additionally, in 2007 Kinder Morgan Energy Partners completed the sale of its North System and its 50% ownership interest in the Heartland Pipeline Company. Note 11 contains additional information regarding these discontinued operations.
 
In December 2007, we sold the remainder of our surplus power equipment for $3.0 million (net of marketing fees.) We did not recognize any gain or loss associated with this sale.
 
On April 30, 2007, Kinder Morgan Energy Partners acquired the Trans Mountain pipeline system from us. We accounted for this transaction as a transfer of net assets between entities under common control. Kinder Morgan Energy Partners recognized the Trans Mountain assets and liabilities acquired at our carrying amounts (historical cost) at the date of transfer. As discussed in Note 3, based on an evaluation of the fair value of the Trans Mountain pipeline system, a goodwill impairment charge of approximately $377.1 million was recorded in 2007.
 
In December 2006, we sold power generation equipment for $13.3 million (net of marketing fees). We recognized a pre-tax gain of $1.2 million associated with this sale. During the first quarter of 2006, we sold power generation equipment for $7.5 million (net of marketing fees). We recognized a pre-tax gain of $1.5 million associated with this sale. This equipment was a portion of the equipment that became surplus as a result of our decision to exit the power development business.
 
Effective April 1, 2006, Kinder Morgan Energy Partners sold its Douglas natural gas gathering system and its Painter Unit fractionation facility to Momentum Energy Group, LLC for approximately $42.5 million in cash. Kinder Morgan Energy Partners’ investment in the net assets sold in this transaction, including all transaction related accruals, was approximately $24.5 million, most of which represented property, plant and equipment, and Kinder Morgan Energy Partners recognized approximately $18.0 million of gain on the sale of these net assets. Kinder Morgan Energy Partners used the proceeds from these asset sales to reduce the outstanding balance on its commercial paper borrowings.
 
Additionally, upon the sale of Kinder Morgan Energy Partners’ Douglas gathering system, Kinder Morgan Energy Partners reclassified a net loss of $2.9 million from “Accumulated Other Comprehensive Loss” into net income on those derivative contracts that effectively hedged uncertain future cash flows associated with forecasted Douglas gathering transactions. We included the net amount of the gain, $15.1 million, within the caption “Operating Costs and Expenses: Other Expenses (Income)” in the accompanying Consolidated Statement of Operations for the year ended December 31, 2006.
 
Investments
 
Kinder Morgan Energy Partners spent approximately $333.5 million in 2008 for its proportionate share of discretionary capital expenditures for both the Rockies Express and Midcontinent Express natural gas pipeline projects, and it expects to spend a combined $1.5 billion for its share of discretionary capital expenditures for both projects in 2009.
 

 
121
 
Item 8:   Financial Statements and Supplementary Data.  (continued)
Knight Form 10-K


During 2007, Kinder Morgan Energy Partners made incremental investments of $202.7 million for its share of construction costs of the Rockies Express Pipeline. Kinder Morgan Energy Partners owns a 51% equity interest through West2East Pipeline LLC, a limited liability company that is the sole owner of Rockies Express Pipeline LLC. (See note 4 for further information regarding this equity investment.)
 
During 2007, Kinder Morgan Energy Partners made incremental investments of $61.6 million for its share of construction costs of the Midcontinent Express Pipeline. Kinder Morgan Energy Partners owns a 50% equity interest in the approximate $2.2 billion, 500-mile interstate natural gas pipeline that will extend between Bennington, Oklahoma and Butler, Alabama.
 
In December 2006, Kinder Morgan Energy Partners issued 34,627 common units as partial consideration for the acquisition of Devco USA L.L.C. This transaction had the associated effects of increasing our minority interests associated with Kinder Morgan Energy Partners by $1.57 million and reducing our (i) goodwill by $110,000, (ii) associated accumulated deferred income taxes by $11,411 and (iii) paid-in capital by $18,589.
 
11. Discontinued Operations
 
North System Natural Gas Liquids Pipeline System - In October 2007, Kinder Morgan Energy Partners completed the sale of its North System and its 50% ownership interest in the Heartland Pipeline Company to ONEOK Partners, L.P. for approximately $298.6 million in cash. For the year ended December 31, 2008, Kinder Morgan Energy Partners paid $2.4 million to ONEOK Partners, L.P. to fully settle both the sale of working capital items and the allocation of pre-acquisition investee distributions, and to partially settle the sale of liquids inventory balances. Due to the fair market valuation resulting from the Going Private transaction (see Note 1), the consideration Kinder Morgan Energy Partners received from the sale of its North System was equal to its carrying value; therefore no gain or loss was recorded on this disposal transaction. The North System consists of an approximately 1,600-mile interstate common carrier pipeline system that delivers natural gas liquids and refined petroleum products from south central Kansas to the Chicago area. Also included in the sale were eight propane truck-loading terminals located at various points in three states along the pipeline system, and one multi-product terminal complex located in Morris, Illinois. All of these assets were included in our Products Pipelines–KMP business segment.
 
Terasen Pipelines (Corridor) Inc. - In June 2007, we completed the sale of Terasen Pipelines (Corridor) Inc. (“Corridor”) to Inter Pipeline Fund, a Canada-based company. Corridor transports diluted bitumen from the Athabasca Oil Sands Project near Fort McMurray, Alberta, to the Scotford Upgrader near Fort Saskatchewan, Alberta. The sale did not include any other assets of Kinder Morgan Canada (formerly Terasen Pipelines). The sale price was approximately $711 million (C$760 million) plus the buyer’s assumption of all of the debt related to Corridor, including the debt associated with the expansion taking place on Corridor at the time of the sale. The consideration was equal to Corridor’s carrying value, therefore no gain or loss was recorded on this disposal transaction.
 
Terasen Inc. - We closed the sale of Terasen Inc. to Fortis Inc. on May 17, 2007, for sales proceeds of approximately $3.4 billion (C$3.7 billion) including cash plus the buyers’ assumption of debt. The sale did not include the assets of Kinder Morgan Canada (formerly Terasen Pipelines) discussed in the preceding paragraph. We recorded a book gain on this disposition of $55.7 million in the second quarter of 2007. The sale resulted in a capital loss of $998.6 million for tax purposes. Approximately $223.3 million of this loss was utilized to reduce capital gains principally associated with the sale of our U.S.-based retail gas operations (see below) resulting in a tax benefit of approximately $82.2 million. The remaining capital loss carryforward of $775.3 million was utilized to reduce the capital gain associated with our sale of an 80% ownership interest in NGPL PipeCo LLC (see Note 10).
 
Natural Gas Distribution and Retail Operations - In March 2007, we completed the sale of our U.S.-based retail natural gas distribution and related operations to GE Energy Financial Services, a subsidiary of General Electric Company and Alinda Investments LLC for $710 million and an adjustment for working capital. In conjunction with this sale, we recorded a pre-tax gain of $251.8 million (net of $3.9 million of transaction costs) in the first quarter of 2007. Our Natural Gas Pipelines–KMP business segment (i) provides natural gas transportation and storage services and sells natural gas to and (ii) receives natural gas transportation and storage services, natural gas and natural gas liquids and other gas supply services from the discontinued U.S.-based retail natural gas distribution business. These transactions are continuing after the sale of this business and will likely continue to a similar extent into the future. For the five months ended May 31, 2007, revenues and expenses of our continuing operations totaling $3.1 million and $1.2 million, respectively for products and services sold to and purchased from our discontinued U.S.-based retail natural gas distribution operations prior to its sale in March 2007, have been eliminated in the accompanying Consolidated Statements of Operations. We are currently receiving fees from SourceGas, a subsidiary of General Electric Company, to provide certain administrative functions for a limited period of time and for the lease of office space. We do not have any significant continuing involvement in or retain any ownership interest in these operations and, therefore, the continuing cash flows discussed above are not considered direct cash flows of the disposed assets.
 

 
122
 
Item 8:   Financial Statements and Supplementary Data.  (continued)
Knight Form 10-K


Earnings of Discontinued Operations - The financial results of discontinued operations have been reclassified for all periods presented and reported in the caption, “Income (Loss) from Discontinued Operations, Net of Tax” in the accompanying Consolidated Statements of Operations. Summarized financial results of these operations are as follows:
 
 
Successor Company
    
Predecessor Company
 
Year Ended
December 31,
2008
  
Seven Months
Ended
December 31,
2007
    
Five Months
Ended
May 31, 2007
  
Year Ended
December 31,
2006
 
(In millions)
    
(In millions)
Operating Revenues
$
-
    
$
24.1
      
$
921.8
    
$
1,999.3
  
                                 
Earnings (Loss) from Discontinued Operations Before Income Taxes
$
(0.9
)
  
$
(10.2
)
    
$
393.2
    
$
(530.6
)
Income Taxes
  
-
      
8.7
        
(94.6
)
    
2.1
  
Earnings (Loss) from Discontinued Operations
$
(0.9
)
  
$
(1.5
)
    
$
298.6
    
$
(528.5
)

The cash flows attributable to discontinued operations are included in the accompanying Consolidated Statements of Cash Flows for the year ended December 31, 2008, seven months ended December 31, 2007, five months ended May 31, 2007 and year ended December 31, 2006 in the captions “Net Cash Flows (Used in) Provided by Discontinued Operations,” “Net Cash Flows Provided by (Used in) Discontinued Investing Activities” and “Net Cash Flows Provided by (Used in) Discontinued Financing Activities.”
 
12. Property, Plant and Equipment
 
Classes and Depreciation
 
As of December 31, 2008 and 2007, investments in property, plant and equipment are as follows:
 
 
December 31,
 
2008
  
2007
Knight Inc.
              
Natural Gas and Liquids Pipelines
$
-
    
$
16.1
  
Electric Generation
  
-
      
10.3
  
General and Other
  
44.4
      
43.9
  
Kinder Morgan Energy Partners1
              
Natural Gas, Liquids and Carbon Dioxide Pipelines
  
5,641.5
      
6,572.6
  
Pipeline and Terminals Station Equipment
  
7,577.0
      
5,596.0
  
General and Other
  
2,084.5
      
1,095.9
  
  
              
Accumulated Amortization, Depreciation and Depletion
  
(979.0
)
    
(277.0
)
   
14,368.4
      
13,057.8
  
Land
  
201.7
      
297.3
  
Natural Gas, Liquids (including Line Fill) and Transmix Processing
  
210.3
      
168.2
  
Construction Work in Process
  
1,329.4
      
1,280.6
  
Property, Plant and Equipment, Net
$
16,109.8
    
$
14,803.9
  
 
____________
1
Includes the allocation of purchase accounting adjustments associated with the Going Private transaction (see Note 1).
 
Property Casualties
 
2005 Hurricanes
 
In 2006, Kinder Morgan Energy Partners reached settlements with its insurance carriers on all property damage claims related to the 2005 hurricanes and recognized a casualty gain of $15.2 million, excluding repair and clean-up expenses. After proceeds from insurance carrier claim reimbursements of $8.0 million and $13.1 million in 2007 and 2006 respectively, which are included in the caption “Property Casualty Indemnifications” within investing activities in the accompanying Consolidated Statements of Cash Flows, Kinder Morgan Energy Partners’ total increase in net income, net of repair and clean-up expenses, was $8.6 million in 2006 from the 2005 hurricanes.
 

 
123
 
Item 8:   Financial Statements and Supplementary Data.  (continued)
Knight Form 10-K


2008 Hurricanes and Fires
 
Kinder Morgan Energy Partners realized a combined $11.1 million of incremental expenses for clean-up and asset damage from hurricanes Hanna, Gustav and Ike, excluding estimates for lost business and lost revenues. Additionally, fire damage at three separate terminal locations resulted in $7.2 million of incremental expenses, excluding estimates for lost business and lost revenues. Of these incremental expenses for the hurricanes and terminal fires, $10.5 million and $5.3 million were included within the captions “Operations and Maintenance” and “Other Expenses (Income),” respectively, in the accompanying Consolidated Statement of Operations for the year ended December 31, 2008.
 
13. Income Taxes
 
The components of income (loss) before income taxes from continuing operations are as follows:
 
 
Successor Company
    
Predecessor Company
 
Year Ended
December 31,
2008
  
Seven Months
Ended
December 31,
2007
    
Five Months
Ended
May 31,
2007
  
Year Ended
December 31,
2006
 
(In millions)
    
(In millions)
United States
$
(3,374.8
)
  
$
474.2
      
$
279.2
    
$
903.6
  
Foreign
  
80.7
      
1.7
        
(376.4
)
    
(17.3
)
Total
$
(3,294.1
)
  
$
475.9
      
$
(97.2
)
  
$
886.3
  

Components of the income tax provision applicable to continuing operations for federal and state income taxes are as follows:
 
 
Successor Company
    
Predecessor Company
 
Year Ended
December 31,
2008
  
Seven Months
Ended
December 31,
2007
    
Five Months
Ended
May 31,
2007
  
Year Ended
December 31,
2006
 
(In millions)
    
(In millions)
Current Tax Provision
                                
U.S.
                                
Federal
$
786.6
    
$
268.6
      
$
(7.0
)
  
$
246.6
  
State
  
18.6
      
25.1
        
3.2
      
10.2
  
Foreign
  
(4.5
)
    
23.5
        
0.6
      
18.3
  
   
800.7
      
317.2
        
(3.2
)
    
275.1
  
  
                                
Deferred Tax Provision
                                
U.S.
                                
Federal
  
(439.5
)
    
(95.2
)
      
134.0
      
46.9
  
State
  
11.5
      
0.5
        
6.4
      
(36.3
)
Foreign
  
(68.4
)
    
4.9
        
(1.7
)
    
0.2
  
   
(496.4
)
    
(89.8
)
      
138.7
      
10.8
  
Total Tax Provision
$
304.3
    
$
227.4
      
$
135.5
    
$
285.9
  
                                 
Effective Tax Rate
  
9.2
%
    
47.8
%
      
139.3
%
    
32.3
%


 
124
 
Item 8:   Financial Statements and Supplementary Data.  (continued)
Knight Form 10-K


The difference between the statutory federal income tax rate and our effective income tax rate is summarized as follows:
 
 
Successor Company
    
Predecessor Company
 
Year Ended
December 31,
2008
  
Seven Months
Ended
December 31,
2007
    
Five Months
Ended
May 31,
2007
  
Year Ended
December 31,
2006
 
(In millions)
    
(In millions)
Federal Income Tax Rate
  
(35.0
%)
    
35.0
%
      
(35.0
%)
    
35.0
%
Increase (Decrease) as a Result of:
                                
Nondeductible Goodwill Impairment
  
42.9
%
    
-
        
135.8
%
    
-
  
Terasen Acquisition Financing Structure
  
-
      
-
        
(17.1
%)
    
(5.1
%)
Nondeductible Going Private Costs
  
-
      
-
        
31.6
%
    
-
  
Deferred Tax Rate Change
  
0.5
%
    
-
        
-
      
(4.3
%)
Kinder Morgan Management Minority Interest
  
0.9
%
    
2.7
%
      
6.4
%
    
2.7
%
Foreign Earnings Subject to Different Tax Rates
  
(2.1
%)
    
5.8
%
      
8.6
%
    
2.6
%
Net Effects of Consolidating Kinder Morgan Energy Partners’ United States Income Tax Provision
  
0.9
%
    
2.5
%
      
4.1
%
    
1.4
%
State Income Tax, Net of Federal Benefit
  
0.5
%
    
2.3
%
      
6.9
%
    
1.7
%
Other
  
0.6
%
    
(0.5
%)
      
(2.0
%)
    
(1.7
%)
Effective Tax Rate
  
9.2
%
    
47.8
%
      
139.3
%
    
32.3
%

Income taxes included in the financial statements were composed of the following:
 
 
Successor Company
    
Predecessor Company
 
Year Ended
December 31,
2008
  
Seven Months
Ended
December 31,
2007
    
Five Months
Ended
May 31,
2007
  
Year Ended
December 31,
2006
 
(In millions)
    
(In millions)
Continuing Operations
$
304.3
    
$
227.4
      
$
135.5
    
$
285.9
  
Discontinued Operations
  
(0.4
)
    
(8.7
)
      
94.6
      
(2.1
)
Equity Items
  
122.2
      
(219.4
)
      
(51.7
)
    
(22.2
)
Total
$
426.1
    
$
(0.7
)
    
$
178.4
    
$
261.6
  


 
125
 
Item 8:   Financial Statements and Supplementary Data.  (continued)
Knight Form 10-K


Deferred tax assets and liabilities result from the following:
 
 
December 31,
2008
    
December 31,
2007
 
(In millions)
    
(In millions)
Deferred Tax Assets
                
Postretirement Benefits
$
79.8
      
$
12.1
  
Book Accruals
  
14.3
        
-
  
Derivatives
  
-
        
270.9
  
Capital Loss Carryforwards
  
-
        
279.5
  
Interest Rate Swaps
  
7.0
        
-
  
Other
  
7.9
        
-
  
Total Deferred Tax Assets
  
109.0
        
562.5
  
Deferred Tax Liabilities
                
Property, Plant and Equipment
  
160.0
        
125.2
  
Investments
  
1,937.2
        
1,909.0
  
Book Accruals
  
-
        
62.1
  
Derivative Instruments
  
5.7
        
-
  
Rate Matters
  
-
        
0.4
  
Prepaid Pension Costs
  
16.6
        
17.9
  
Assets/Liabilities Held for Sale
  
-
        
897.5
  
Debt Adjustment
  
23.0
        
-
  
Other
  
47.8
        
66.2
  
Total Deferred Tax Liabilities
  
2,190.3
        
3,078.3
  
Net Deferred Tax Liabilities
$
2,081.3
      
$
2,515.8
  
  
                
Current Deferred Tax Asset
$
-
      
$
-
  
Current Deferred Tax Liability
  
-
        
666.4
  
Non-current Deferred Tax Liability
  
2,081.3
        
1,849.4
  
Net Deferred Tax Liabilities
$
2,081.3
      
$
2,515.8
  

During 2007, our sale of Terasen Inc. resulted in a capital loss of $998.6 million of which approximately $223.3 million was utilized to reduce capital gain principally associated with the sale of our U.S.-based retail natural gas operations. The remaining capital loss was carried forward and utilized to reduce the capital gain on the sale of our 80% ownership interest in the NGPL business segment.
 
In July 2006, the FASB issued Interpretation No. 48, Accounting for Uncertainty in Income Taxes—an Interpretation of FASB Statement No. 109, (“FIN No. 48”) which became effective January 1, 2007. FIN No. 48 addressed the determination of how tax benefits claimed or expected to be claimed on a tax return should be recorded in the financial statements. Under FIN No. 48, we must recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based not only on the technical merits of the tax position based on tax law, but also the past administrative practices and precedents of the taxing authority. The tax benefits recognized in the financial statements from such a position are measured based on the largest benefit that has a greater than 50% likelihood of being realized upon ultimate resolution.
 
We adopted the provisions of FIN No. 48 on January 1, 2007. The total amount of unrecognized tax benefits as of the date of adoption was $63.1 million. We recorded a $4.8 million decrease to the opening balance of retained earnings as a result of the implementation of FIN No. 48.
 
A reconciliation of our gross unrecognized tax benefit excluding interest and penalties for the years ended December 31, 2008 and 2007 is as follows (in millions):
 
 
2008
    
2007
Balance at beginning of period
$
41.5
      
$
63.1
  
Additions based on current year tax positions
  
2.1
        
9.8
  
Additions based on prior year tax positions
  
15.9
        
0.5
  
Reductions based on settlements with taxing authority
  
(10.2
)
      
(21.4
)
Reductions due to lapse in statue of limitations
  
(3.7
)
      
(2.7
)
Reductions for tax positions related to prior year
  
(19.4
)
      
(7.8
)
Balance at end of period
$
26.2
      
$
41.5
  


 
126
 
Item 8:   Financial Statements and Supplementary Data.  (continued)
Knight Form 10-K


Our continuing practice is to recognize interest and/or penalties related to income tax matters in income tax expense, and as of December 31, 2007, we had $8.1 million of accrued interest and no accrued penalties. As of December 31, 2008, we had $2.9 million of accrued interest and $0.8 million of accrued penalties. In addition, we believe it is reasonably possible that our liability for unrecognized tax benefits will increase by $4.8 million during the next twelve months, and that approximately $34.1 million included in the total $26.2 million of unrecognized tax benefits on the accompanying Consolidated Balance Sheet as of December 31, 2008 would affect our effective tax rate in future periods in the event those unrecognized tax benefits were recognized. Such amounts exclude interest, while the latter amount of $26.6 million includes both temporary and permanent differences.
 
We are subject to taxation, and have tax years open to examination for the periods 2003-2008 in the United States and Mexico, 2004-2008 in Canada, and 1999-2008 in various states.
 
14. Financing
 
Notes Payable
 
We and our consolidated subsidiaries had the following unsecured credit facilities outstanding at December 31, 2008.
 
Credit Facilities
 
Knight Inc.—$1.0 billion, six-year secured revolver, due May 2013
Kinder Morgan Energy Partners—$1.85 billion, five-year unsecured revolver, due August 2010

The following are short-term borrowings, issued by the below-listed borrowers, where the commercial paper is supported by each borrower’s respective credit facilities. The short-term borrowings shown in the tables below, totaling $8.8 million and $888.1 million, respectively, are reported in the caption “Notes Payable” in the accompanying Balance Sheets at December 31, 2008 and 2007, respectively.
 
 
December 31, 2008
 
Short-term
Borrowings
Outstanding
Under
Revolving
Credit Facility
  
Commercial Paper
Outstanding
  
Weighted-average
Interest Rate of
Short-term Debt
Outstanding
 
(In millions)
Knight Inc.
                        
$1.0 billion
$
8.8
      
-
      
3.38
%
  
Kinder Morgan Energy Partners
                        
$1.85 billion
$
-
      
-
      
-
%
  
 
 
December 31, 2007
 
Short-term
Borrowings
Outstanding
Under
Revolving
Credit Facility
  
Commercial Paper
Outstanding
  
Weighted-average
Interest Rate of
Short-term Debt
Outstanding
 
(In millions)
Knight Inc.
                        
$1.0 billion
$
299.0
    
$
-
      
6.42
%
  
Kinder Morgan Energy Partners
                        
$1.85 billion
$
-
    
$
589.1
      
5.58
%
  
  
The weighted average interest rates on our outstanding borrowings under the $1.0 billion credit facility for the year ended December 31, 2008 and seven months ended December 31, 2007 were approximately 4.43% and 6.61%, respectively. The weighted average interest rate on Terasen Pipelines (Corridor) Inc.’s short term debt was 4.33% for the seven months ended December 31, 2007. For the five months ended May 31, 2007, the weighted average interest rates on outstanding borrowings under Knight Inc.’s $800 million credit facility, which was terminated on May 30, 2007, was 5.81% and the outstanding borrowings under the Terasen Inc., Terasen Gas Inc. and Terasen Pipelines (Corridor) Inc.’s respective credit facilities were 4.34%, 4.23% and 4.24% . Terasen Inc, including Terasen Gas Inc., and Terasen Pipelines (Corridor) Inc. were sold on May
 

 
127
 
Item 8:   Financial Statements and Supplementary Data.  (continued)
Knight Form 10-K


17, 2007 and June 15, 2007 respectively. Accordingly, the average short-term debt associated with these facilities for the seven months ended December 31, 2007 and five months ended May 31, 2007 are only through the respective dates of sale.
 
The weighted average interest rates under Kinder Morgan Energy Partners’ credit facility for the year ended December 31, 2008 was 3.47%. Weighted average interest rates under Kinder Morgan Energy Partners’ commercial paper program for the year ended December 31, 2008, seven months ended December 31, 2007 and five months ended May 31, 2007 were 3.47%, 5.46% and 5.40%, respectively. Kinder Morgan Energy Partners currently does not have access to the commercial paper market.
 
The Knight Inc. $1.0 billion six-year senior secured revolving credit facility matures on May 30, 2013 and includes a sublimit of $300 million for the issuance of letters of credit and a sublimit of $50 million for swingline loans. Knight Inc. does not have a commercial paper program. This revolving credit facility, as part of a $5.755 billion credit agreement used to finance the Going Private transaction, replaced an $800 million five-year credit facility dated August 5, 2005. The $5.755 billion credit agreement dated May 30, 2007, is with a syndicate of financial institutions and Citibank, N.A., as administrative agent and included three tranches of term loan facilities, which were subsequently retired.
 
The credit agreement permits one or more incremental increases under the revolving credit facility or an addition of new term facilities in an aggregate amount of up to $1.5 billion, provided certain conditions are met. Such additional capacity is uncommitted. Additionally, the revolving credit facility allows for one or more swingline loans from Citibank, N.A., in its individual capacity, up to an aggregate amount of $50.0 million provided certain conditions are met.
 
Our obligations under the credit agreement and certain existing notes issued by us and Kinder Morgan Finance Company, LLC, the sale of which were registered under the Securities Act of 1933, as amended, are secured, subject to specified exceptions, by a first-priority lien on all the capital stock of each of our wholly owned subsidiaries (limited, in the case of foreign subsidiaries, to 65% of the capital stock of such subsidiaries) and by perfected security interests in, and mortgages on, substantially all of our and our subsidiaries’ tangible and intangible assets (including, without limitation, accounts (other than deposit accounts or other bank or securities accounts), inventory, equipment, investment property, intellectual property, other general intangibles, material fee-owned real property (other than pipeline assets and any leasehold property) and proceeds of the foregoing). None of the assets of Kinder Morgan G.P., Inc., Kinder Morgan Management, Kinder Morgan Energy Partners or their respective subsidiaries are pledged as security as part of this financing.
 
Loans under the revolving credit facility will bear interest, at Knight Inc.’s option, at:
 
 
·
a rate equal to LIBOR (London Interbank Offered Rate) plus an applicable margin, or
 
·
a rate equal to the higher of (a) U.S. prime rate and (b) the federal funds effective rate plus 0.50%, in each case, plus an applicable margin.
 
The swingline loans will bear interest at:
 
 
·
a rate equal to the higher of (a) U.S. prime rate and (b) the federal funds effective rate plus 0.50%, in each case, plus an applicable margin.
 
The applicable margin for the revolving credit facility is subject to decrease pursuant to a leverage-based pricing grid. In addition, the credit agreement provides for customary commitment fees and letter of credit fees under the revolving credit facility. Based on our ratio, as defined in the credit agreement, of consolidated total debt to earnings before interest, income taxes and depreciation and amortization at December 31, 2008, our facility fee was 25 basis points. The credit agreement contains customary terms and conditions and is unconditionally guaranteed by each of our wholly owned material domestic restricted subsidiaries, to the extent permitted by applicable law and contract. Voluntary prepayments can be made at any time on revolving credit loans and swingline loans, in each case without premium or penalty, and on LIBOR Loans (as defined in the credit agreement) on the interest payment date without premium or penalty.
 
Our $5.755 billion credit agreement includes the following restrictive covenants:
 
 
·
total debt divided by earnings before interest, income taxes, depreciation and amortization for (i) the test period ending December 31, 2007 may not exceed 8.75:1.00, (ii) January 1, 2008 to December 31, 2008 may not exceed 8.00:1.00, (iii) January 1, 2009 to December 31, 2009 may not exceed 7.00:1.00 and (iv) thereafter may not exceed 6.00:1.00;
 
·
certain limitations on indebtedness, including payments and amendments;
 
·
certain limitations on entering into mergers, consolidations, sales of assets and investments;
 
·
limitations on granting liens; and
 
·
prohibitions on making any dividend to shareholders if an event of default exists or would exist upon making such dividend.
 

 
128
 
Item 8:   Financial Statements and Supplementary Data.  (continued)
Knight Form 10-K


The Kinder Morgan Energy Partners $1.85 billion five-year unsecured bank credit facility matures August 18, 2010 and can be amended to allow for borrowings up to $2.1 billion. Borrowings under the credit facility can be used for partnership purposes and as a backup for Kinder Morgan Energy Partners’ commercial paper program. As of December 31, 2008 and 2007, respectively, there were no borrowings under the credit facility.
 
Kinder Morgan Energy Partners’ five-year credit facility is with a syndicate of financial institutions. Wachovia Bank, National Association is the administrative agent. The credit facility permits Kinder Morgan Energy Partners to obtain bids for fixed rate loans from members of the lending syndicate. Interest on the credit facility accrues at Kinder Morgan Energy Partners’ option at a floating rate equal to either (i) the administrative agent’s base rate (but not less than the Federal Funds Rate, plus 0.5%); or (ii) London Interbank Offered Rate (“LIBOR”), plus a margin, which varies depending upon the credit rating of Kinder Morgan Energy Partners’ long-term senior unsecured debt.
 
Kinder Morgan Energy Partners’ credit facility included the following restrictive covenants as of December 31, 2008:
 
 
·
total debt divided by earnings before interest, income taxes, depreciation and amortization for the preceding four quarters may not exceed:
 
·
5.5, in the case of any such period ended on the last day of (i) a fiscal quarter in which Kinder Morgan Energy Partners makes any Specified Acquisition, or (ii) the first or second fiscal quarter next succeeding such a fiscal quarter; or
 
·
5.0, in the case of any such period ended on the last day of any other fiscal quarter;
 
·
certain limitations on entering into mergers, consolidations and sales of assets;
 
·
limitations on granting liens; and
 
·
prohibitions on making any distribution to holders of units if an event of default exists or would exist upon making such distribution.
 
In addition to normal repayment covenants, under the terms of Kinder Morgan Energy Partners’ credit facility, the occurrence at any time of any of the following would constitute an event of default: (i) Kinder Morgan Energy Partners’ failure to make required payments of any item of indebtedness or any payment in respect of any hedging agreement, provided that the aggregate outstanding principal amount for all such indebtedness or payment obligations in respect of all hedging agreements is equal to or exceeds $75 million, (ii) Kinder Morgan G.P., Inc.’s failure to make required payments of any item of indebtedness, provided that the aggregate outstanding principal amount for all such indebtedness is equal to or exceeds $75 million, (iii) adverse judgments rendered against Kinder Morgan Energy Partners for the payment of money in an aggregate amount in excess of $75 million, if this same amount remains undischarged for a period of thirty consecutive days during which execution shall not be effectively stayed and (iv) voluntary or involuntary commencements of any proceedings or petitions seeking Kinder Morgan Energy Partners’ liquidation, reorganization or any other similar relief under any federal, state or foreign bankruptcy, insolvency, receivership or similar law.
 
Excluding the relatively non-restrictive specified negative covenants and events of defaults, Kinder Morgan Energy Partners’ credit facility does not contain any provisions designed to protect against a situation where a party to an agreement is unable to find a basis to terminate that agreement while its counterparty’s impending financial collapse is revealed and perhaps hastened through the default structure of some other agreement. The credit facility also does not contain a material adverse change clause coupled with a lockbox provision; however, the facility does provide that the margin Kinder Morgan Energy Partners will pay with respect to borrowings and the facility fee that Kinder Morgan Energy Partners will pay on the total commitment will vary based on Kinder Morgan Energy Partners’ senior debt investment rating. None of Kinder Morgan Energy Partners’ debt is subject to payment acceleration as a result of any change to its credit ratings.
 
On September 15, 2008, Lehman Brothers Holdings Inc. filed for bankruptcy protection under the provisions of Chapter 11 of the U.S. Bankruptcy Code. One Lehman entity was a lending institution that provided a portion of Kinder Morgan Energy Partners’, Rockies Express’ and Mid Continent Express’ respective credit facilities. Since Lehman Brothers declared bankruptcy, its affiliate, which is a party to the credit facilities, has not met its obligations to lend under those agreements. As such, the commitments have been effectively reduced by $63 million, $41 million and $100 million, respectively, to $1.8 billion, $2.0 billion and $1.3 billion. The commitments of the other banks remain unchanged and the facilities are not defaulted.
 
Long-term Debt
 
Since we are accounting for the Going Private transaction (see Note 1) as a purchase business combination that is required to be “pushed-down” to us, we have adjusted the carrying value of our long-term debt securities to reflect their fair values, to the extent of Knight Inc.’s economic ownership interest, at the time of the Going Private transaction and the adjustments are being amortized over the remaining lives of the debt securities. The unamortized fair value adjustment balances reflected within the caption “Long-term Debt” in the accompanying Consolidated Balance Sheet at December 31, 2008 were $46.0 million and $6.7 million, representing a decrease to the carrying value of our long-term debt and an increase in the value of our interest
 

 
129
 
Item 8:   Financial Statements and Supplementary Data.  (continued)
Knight Form 10-K


rate swaps, respectively. Our long-term debt balances at December 31, 2008 and 2007 of $12,126.8 million and $15,297.4 million, respectively, consisted of the balances shown in the table below.
 
 
December 31,
 
2008
  
2007
  
(In millions)
Knight Inc.
              
Debentures
              
6.50% Series, Due 2013
$
6.1
    
$
30.1
  
6.67% Series, Due 2027
  
7.0
      
148.3
  
7.25% Series, Due 2028
  
32.0
      
494.3
  
7.45% Series, Due 2098
  
25.9
      
146.3
  
Senior Notes
              
6.50% Series, Due 2012
  
846.2
      
1,010.5
  
5.15% Series, Due 2015
  
233.3
      
231.2
  
Senior Secured Credit Term Loan Facilities
              
Tranche A Term Loan, Due 2013
  
-
      
997.5
  
Tranche B Term Loan, Due 2014
  
-
      
3,191.7
  
Deferrable Interest Debentures Issued to Subsidiary Trusts
              
8.56% Junior Subordinated Deferrable Interest Debentures Due 2027
  
15.8
      
106.9
  
7.63% Junior Subordinated Deferrable Interest Debentures Due 2028
  
19.9
      
176.2
  
Unamortized Gain on Termination of Interest Rate Swap
  
6.4
      
11.5
  
  
              
Kinder Morgan Finance Company, LLC
              
5.35% Series, Due 2011
  
742.0
      
738.5
  
5.70% Series, Due 2016
  
806.6
      
801.9
  
6.40% Series, Due 2036
  
33.8
      
503.8
  
Carrying Value Adjustment for Interest Rate Swap1
  
-
      
23.2
  
Unamortized Gain on Termination of Interest Rate Swap
  
12.8
      
11.6
  
  
              
Kinder Morgan G.P., Inc.
              
$1,000 Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock
  
100.0
      
100.0
  
  
              
Kinder Morgan Energy Partners
              
Senior Notes
              
6.30% Series, Due 2009
  
250.1
      
250.9
  
7.50% Series, Due 2010
  
253.8
      
255.7
  
6.75% Series, Due 2011
  
707.6
      
710.6
  
7.125% Series, Due 2012
  
458.7
      
461.1
  
5.85% Series, Due 2012
  
500.0
      
500.0
  
5.00% Series, Due 2013
  
491.3
      
489.8
  
5.125% Series, Due 2014
  
490.2
      
488.9
  
6.00% Series, Due 2017
  
597.8
      
597.5
  
5.95% Series Due 2018
  
975.0
      
-
  
9.00% Series Due 2019
  
500.0
      
-
  
7.40% Series, Due 2031
  
310.3
      
310.5
  
7.75% Series, Due 2032
  
316.4
      
316.7
  
7.30% Series, Due 2033
  
513.9
      
514.1
  
5.80% Series, Due 2035
  
477.4
      
477.1
  
6.50% Series, Due 2037
  
395.8
      
395.7
  
6.95% Series, Due 2038
  
1,175.0
      
550.0
  
Other
  
1.1
      
1.1
  
Carrying Value Adjustment for Interest Rate Swaps1
  
754.2
      
146.2
  
Unamortized Gain on Termination of Interest Rate Swap
  
197.6
      
7.2
  
               
Central Florida Pipe Line LLC
              
7.84% Series, Due 2008
  
-
      
5.0
  
  
              
Arrow Terminals L.P.
              
Illinois Development Finance Authority Adjustable Rate Industrial Development Revenue Bonds, Due 2010, weighted-average interest rate of 2.52% for the year ended December 31, 2008 (3.77% for the seven months ended December 31, 2007 and 3.87% for the five months ended May 31, 2007)
  
5.3
      
5.3
  


 
130
 
Item 8:   Financial Statements and Supplementary Data.  (continued)
Knight Form 10-K



  
              
Kinder Morgan Operating, L.P. “A” and Kinder Morgan Canada
              
5.40% Note, Due 2012
  
36.6
      
44.6
  
  
              
Kinder Morgan Texas Pipeline, L.P. 
              
8.85% Series, Due 2014
  
37.0
      
43.2
  
  
              
Kinder Morgan Liquids Terminals LLC
              
New Jersey Economic Development Revenue Refunding Bonds, Due 2018, weighted-average interest rate of 1.63% for the year ended December 31, 2008(3.48 % for the seven months ended December 31, 2007 and 3.63% for the five months ended May 31, 2007)
  
25.0
      
25.0
  
  
              
Kinder Morgan Operating, L.P. “B”
              
Jackson-Union Counties, Illinois Regional Port District Tax-exempt Floating Rate Bonds, Due 2024, weighted-average interest rate of 2.96% for the year ended December 31, 2008 (3.68% for the seven months ended December 31, 2007 and 3.59% for the five months ended May 31, 2007)
  
23.7
      
23.7
  
Other
  
0.2
      
0.2
  
  
              
International Marine Terminals
              
Plaquemines Port, Harbor and Terminal District (Louisiana) Adjustable Rate Annual Tender Port Facilities Revenue Refunding Bonds, Due 2025, weighted-average interest rate of 2.50% for the year ended December 31, 2008 (3.65% for the seven months ended December 31, 2007 and 3.59% for the five months ended May 31, 2007)
  
40.0
      
40.0
  
    
              
Gulf Opportunity Zone Bonds
              
Kinder Morgan Louisiana Pipeline LLC
              
6.00% Louisiana Community Development Authority Revenue Bonds Due 2011
  
5.0
      
-
  
               
Kinder Morgan Columbus LLC
              
5.50% Mississippi Business Finance Corporation Revenue Bonds Due 2022
  
8.2
      
-
  
  
              
Unamortized Debt Discount on Long-term Debt
  
(14.5
)
    
(6.4
)
Current Maturities of Long-term Debt
  
(293.7
)
    
(79.8
)
Total Long-term Debt
$
12,126.8
    
$
15,297.4
  
__________
1   Adjustment of carrying value of long-term securities subject to outstanding interest rate swaps; see Note 15.
 
In February 2008, approximately $4.6 billion of the proceeds from the completed sale of an 80% ownership interest in NGPL PipeCo LLC were used to pay off and retire our senior secured credit facility’s Tranche A and Tranche B term loans and to pay down amounts outstanding at that time under our $1.0 billion revolving credit facility as follows:
 
 
Debt Paid Down
and/or Retired
 
(In millions)
Knight Inc.
          
Senior Secured Credit Term Loan Facilities
          
Tranche A Term Loan, Due 2013
  
$
995.0
    
Tranche B Term Loan, Due 2014
    
3,183.5
    
Credit Facility
          
$1.0 billion Secured Revolver, Due May 2013
    
375.0
    
Total Paid Down and/or Retired
  
$
4,553.5
    


 
131
 
Item 8:   Financial Statements and Supplementary Data.  (continued)
Knight Form 10-K


In March 2008, using primarily proceeds from the completed sale of an 80% ownership interest in NGPL PipeCo LLC, along with cash on hand and borrowings under our $1.0 billion revolving credit facility, we repurchased approximately $1.67 billion par value of our outstanding debt securities for $1.6 billion in cash as follows:
 
 
Par Value of
Debt Repurchased
 
(In millions)
Knight Inc.
          
Debentures
          
6.50% Series, Due 2013
  
$
18.9
    
6.67% Series, Due 2027
    
143.0
    
7.25% Series, Due 2028
    
461.0
    
7.45% Series, Due 2098
    
124.1
    
Senior Notes
          
6.50% Series, Due 2012
    
160.7
    
Kinder Morgan Finance Company, LLC
          
6.40% Series, Due 2036
    
513.6
    
Deferrable Interest Debentures Issued to Subsidiary Trusts
          
8.56% Junior Subordinated Deferrable Interest Debentures Due 2027
    
87.3
    
7.63% Junior Subordinated Deferrable Interest Debentures Due 2028
    
160.6
    
Repurchase of Outstanding Debt Securities
  
$
1,669.2
    

As of December 31, 2008, maturities of long-term debt (in millions) for the five years ending December 31, 2013 and thereafter were $293.7, $271.9, $1,471.2, $2,305.7, $506.5 and $6,647.0, respectively.
 
Knight Inc.
 
The 2013 Debentures are not redeemable prior to maturity. The 2028 and 2098 Debentures and the 2012 senior notes are redeemable in whole or in part, at our option at any time, at redemption prices defined in the associated prospectus supplements. The 2015 senior notes are redeemable in whole or in part at our option, but at redemption prices that generally do not make early redemption an economically favorable alternative. The 2027 Debentures are redeemable in whole or in part, at our option after November 1, 2004 at redemption prices defined in the associated prospectus supplements.
 
On September 5, 2008 and September 3, 2007, we made a $5.0 million payment on each date on our 6.50% Series Debentures, Due 2013.
 
On May 7, 2007, we retired our $300 million 6.80% senior notes due March 1, 2008 at 101.39% of the face amount. We paid a premium of $4.2 million in connection with this early extinguishment of debt.
 
Kinder Morgan Finance Company, LLC
 
The 2011, 2016 and 2036 senior notes issued by Kinder Morgan Finance Company, LLC are redeemable in whole or in part, at our option at any time, at redemption prices defined in the associated prospectus supplements. Each series of these notes is fully and unconditionally guaranteed by Knight Inc. on a senior unsecured basis as to principal, interest and any additional amounts required to be paid as a result of any withholding or deduction for Canadian taxes. Additionally, the 6.40% senior notes due 2016 had an associated fixed-to-floating interest rate swap agreement with a notional principal amount of $275 million, which was terminated in 2008. See Note 15 for additional information on this swap agreement.
 
Kinder Morgan Energy Partners
 
Kinder Morgan Energy Partners’ fixed rate notes provide for redemption at any time at a price equal to 100% of the principal amount of the notes plus accrued interest to the redemption date plus a make-whole premium. Approximately $2.3 billion of Kinder Morgan Energy Partners’ senior notes have associated fixed-to-floating interest rate swap agreements that effectively convert the related interest expense from fixed rates to floating rates. See Note 15 for additional information on these swap agreements.
 
On December 19, 2008, Kinder Morgan Energy Partners completed a public offering of senior notes, issuing a total of $500 million in principal amount of 9.00% senior notes due February 1, 2019. Kinder Morgan Energy Partners used the $498.4 million net proceeds, after underwriting discounts and commissions, to reduce the borrowings under its revolving credit facility.
 

 
132
 
Item 8:   Financial Statements and Supplementary Data.  (continued)
Knight Form 10-K


On June 6, 2008, Kinder Morgan Energy Partners completed a public offering of senior notes, issuing $700 million in principal amount of senior notes, consisting of $375 million of 5.95% notes due February 15, 2018 (these notes constitute a further issuance of the $600 million aggregate principal amount of 5.95% notes Kinder Morgan Energy Partners issued on February 12, 2008 and form a single series with those notes) and $325 million of 6.95% notes due January 15, 2038 (these notes constitute a further issuance of the combined $850 million aggregate principal amount of 6.95% notes Kinder Morgan Energy Partners issued on June 21, 2007 and February 12, 2008, and form a single series with those notes). Kinder Morgan Energy Partners used the $687.7 million net proceeds, after underwriting discounts and commissions, to reduce the borrowings under its commercial paper program.
 
On February 12, 2008, Kinder Morgan Energy Partners completed a public offering of senior notes, issuing a total of $900 million in principal amount of senior notes, consisting of $600 million of 5.95% notes due February 15, 2018, and $300 million of 6.95% notes due January 15, 2038 (the 6.95% notes constitute a further issuance of the $550 million aggregate principal amount of 6.95% notes Kinder Morgan Energy Partners issued on June 21, 2007 and form a single series with those notes). Kinder Morgan Energy Partners used the $894.1 million net proceeds to reduce borrowings under its commercial paper program.
 
On August 28, 2007, Kinder Morgan Energy Partners issued $500 million of its 5.85% senior notes due September 15, 2012. Kinder Morgan Energy Partners used the $497.8 million net proceeds received after underwriting discounts and commissions to reduce the borrowings under its commercial paper program.
 
On August 15, 2007, Kinder Morgan Energy Partners repaid $250 million of its 5.35% senior notes that matured on that date.
 
On June 21, 2007, Kinder Morgan Energy Partners issued $550 million of its 6.95% senior notes due January 15, 2038. Kinder Morgan Energy Partners used the $543.9 million net proceeds received after underwriting discounts and commissions to reduce the borrowings under its commercial paper program.
 
On January 30, 2007, Kinder Morgan Energy Partners completed a public offering of senior notes, issuing a total of $1.0 billion in principal amount of senior notes, consisting of $600 million of 6.00% notes due February 1, 2017 and $400 million of 6.50% notes due February 1, 2037. Kinder Morgan Energy Partners received proceeds from the issuance of the notes, after underwriting discounts and commissions, of approximately $992.8 million, and used the proceeds to reduce the borrowings under its commercial paper program.
 
Central Florida Pipeline LLC Debt
 
Central Florida Pipeline LLC was an obligor on an aggregate principal amount of $40 million of senior notes originally issued to a syndicate of eight insurance companies. The senior notes had a fixed annual interest rate of 7.84% with repayments in annual installments of $5.0 million beginning July 23, 2001. Central Florida Pipeline LLC paid the final $5.0 million outstanding principal amount on July 23, 2008.
 
Arrow Terminals L.P. Debt
 
Arrow Terminals L.P. is an obligor on Adjustable Rate Industrial Development Revenue Bonds issued by the Illinois Development Finance Authority. The bonds have a maturity date of January 1, 2010, and interest on these bonds is paid and computed quarterly at the Bond Market Association Municipal Swap Index. The bonds are collateralized by a first mortgage on assets of Arrow’s Chicago operations and a third mortgage on assets of Arrow’s Pennsylvania operations. As of December 31, 2008, the interest rate was 1.328%. A $5.4 million letter of credit issued by JP Morgan Chase backs-up the $5.3 million principal amount of the bonds and $0.1 million of interest on the bonds for up to 45 days computed at 12% per annum on the principal amount thereof.
 
Kinder Morgan Operating L.P. “A” and Kinder Morgan Canada Company Debt
 
Effective January 1, 2007, Kinder Morgan Energy Partners acquired the remaining approximate 50.2% interest in the Cochin pipeline system that it did not already own (see Note 10). As part of Kinder Morgan Energy Partners’ purchase price, two of its subsidiaries issued a long-term note payable to the seller having a fair value of $42.3 million. Kinder Morgan Energy Partners valued the debt equal to the present value of amounts to be paid, determined using an annual interest rate of 5.40%. The principal amount of the note, along with interest, is due in five annual installments of $10.0 million beginning March 31, 2008. Kinder Morgan Energy Partners paid the first installment on March 31, 2008 and the final payment is due March 31, 2012. Kinder Morgan Energy Partners’ subsidiaries, Kinder Morgan Operating L.P. “A” and Kinder Morgan Canada Company, are the obligors on the note.
 

 
133
 
Item 8:   Financial Statements and Supplementary Data.  (continued)
Knight Form 10-K


Kinder Morgan Texas Pipeline, L.P. Debt
 
Kinder Morgan Texas Pipeline, L.P. is the obligor on a series of unsecured senior notes with a fixed annual stated interest rate of 8.85%. The assumed principal amount, along with interest, is due in monthly installments of approximately $0.7 million. The final payment is due January 2, 2014.
 
Additionally, the unsecured senior notes may be prepaid at any time in amounts of at least $1.0 million at a price equal to the higher of par value or the present value of the remaining scheduled payments of principal and interest on the portion being prepaid.
 
Kinder Morgan Liquids Terminals LLC Debt
 
Kinder Morgan Liquids Terminals LLC is the obligor on $25.0 million of Economic Development Revenue Refunding Bonds issued by the New Jersey Economic Development Authority. These bonds have a maturity date of January 15, 2018. These bonds have a maturity date of January 15, 2018. Interest on these bonds is computed on the basis of a year of 365 or 366 days, as applicable, for the actual number of days elapsed during Commercial Paper, Daily or Weekly Rate Periods and on the basis of a 360-day year consisting of twelve 30-day months during a Term Rate Period. As of December 31, 2008, the annual interest rate was 0.52%. Kinder Morgan Energy Partners has an outstanding letter of credit issued by Citibank in the amount of $25.4 million that backs-up the $25.0 million principal amount of the bonds and $0.4 million of interest on the bonds for up to 46 days computed at 12% on a per annum basis on the principal thereof.
 
Kinder Morgan Operating L.P. “B” Debt
 
As of December 31, 2008, Kinder Morgan Energy Partners’ subsidiary Kinder Morgan Operating L.P. “B” was the obligor of tax-exempt bonds due April 1, 2024. The bonds were issued by the Jackson-Union Counties Regional Port District, a political subdivision embracing the territories of Jackson County and Union County in the state of Illinois. These variable rate demand bonds bear interest at a weekly floating market rate and are backed-up by a letter of credit issued by Wachovia.
 
The bond indenture also contains certain standby purchase agreement provisions, which allow investors to put (sell) back their bonds at par plus accrued interest. In the fourth quarter of 2008, certain investors elected to sell back their bonds and Kinder Morgan Energy Partners paid a total principal and interest amount of $5.2 million according to the letter of credit reimbursement provisions. However, the bonds were subsequently resold and as of December 31, 2008, Kinder Morgan Energy Partners was fully reimbursed for the prior payments. As of December 31, 2008, the annual interest rate on these bonds was 3.04%. Kinder Morgan Energy Partners has an outstanding letter of credit issued by Wachovia in the amount of $18.0 million that backs-up the principal amount of $17.7 million the bonds and $0.3 million of interest on the bonds for up to 55 days computed at 12% per annum on the principal amount thereof.
 
International Marine Terminals Debt
 
Kinder Morgan Energy Partners owns a 66 2/3% interest in International Marine Terminals partnership (“IMT”). The principal assets owned by IMT are dock and wharf facilities financed by the Plaquemines Port, Harbor and Terminal District (Louisiana) $40.0 million Adjustable Rate Annual Tender Port Facilities Revenue Refunding Bonds (International Marine Terminals Project) Series 1984A and 1984B. As of December 31, 2008, the annual interest rate on these bonds was 2.20%.
 
On March 15, 2005, these bonds were refunded and the maturity date was extended from March 15, 2006 to March 15, 2025. No other changes were made under the bond provisions. The bonds are backed by two letters of credit issued by KBC Bank N.V. On March 19, 2002, an Amended and Restated Letter of Credit Reimbursement Agreement relating to the letters of credit in the amount of $45.5 million was entered into by IMT and KBC Bank. In connection with that agreement, Kinder Morgan Energy Partners agreed to guarantee the obligations of IMT in proportion to its ownership interest. Kinder Morgan Energy Partners’ obligation is approximately $30.3 million for principal, plus interest and other fees.
 
Gulf Opportunity Zone Bonds
 
To help fund business growth in the states of Mississippi and Louisiana, Kinder Morgan Energy Partners completed the purchase of a combined $13.2 million in principal amount of tax exempt revenue bonds in two separate transactions in December 2008. The bond offerings were issued under the Gulf Opportunity Zone Act of 2005 and consisted of the following: (i) $8.2 million in principal amount of 5.5% Development Revenue Bonds issued by the Mississippi Business Finance Corporation, a public, non-profit corporation that coordinates a variety of resources used to assist business and industry in the state of Mississippi and (ii) $5.0 million in principal amount of 6.0% Development Revenue Bonds issued by the Louisiana Community Development Authority, a political subdivision of the state of Louisiana.
 
The Mississippi revenue bonds mature on September 1, 2022, and both principal and interest are due in full at maturity. Kinder Morgan Energy Partners holds an option to redeem the bonds in full (and settle the note payable to the Mississippi Business Finance Corporation) without penalty after one year. The Louisiana revenue bonds have a maturity date of January
 

 
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Item 8:   Financial Statements and Supplementary Data.  (continued)
Knight Form 10-K


1, 2011 and provide for semi-annual interest payments each July 1 and January 1.
 
Capital Trust Securities
 
Our business trusts, K N Capital Trust I and K N Capital Trust III, are obligated for $15.8 million of 8.56% Capital Trust Securities maturing on April 15, 2027 and $19.9 million of 7.63% Capital Trust Securities maturing on April 15, 2028, respectively, which are guaranteed by us. The 2028 Securities are redeemable in whole or in part, at our option at any time, at redemption prices as defined in the associated prospectus. The 2027 Securities are redeemable in whole or in part at our option and at any time in certain limited circumstances upon the occurrence of certain events and at prices, all defined in the associated prospectus supplements. Upon redemption by us or at maturity of the Junior Subordinated Deferrable Interest Debentures, we must use the proceeds to make redemptions of the Capital Trust Securities on a pro rata basis.
 
Common Stock – Financing of the Going Private Transaction
 
On May 30, 2007, investors led by Richard D. Kinder, our Chairman and Chief Executive Officer, completed the Going Private transaction. As of the closing date of the Going Private transaction, Kinder Morgan, Inc. had 149,316,603 common shares outstanding, before deducting 15,030,135 shares held in treasury. The Going Private transaction, including associated fees and expenses, was financed through (i) $5.0 billion in new equity financing from private equity funds and other entities providing equity financing, (ii) approximately $2.9 billion from rollover investors, who were certain current or former directors, officers or other members of management of Kinder Morgan, Inc. (or entities controlled by such persons) that directly or indirectly reinvested all or a portion of their equity interests in Kinder Morgan, Inc. and/or cash in exchange for equity interests in Knight Holdco LLC, the parent of the surviving entity of the Going Private transaction, (iii) approximately $4.8 billion of new debt financing, (iv) approximately $4.5 billion of our existing indebtedness (excluding debt of Terasen Pipelines (Corridor) Inc., which was divested on June 15, 2007) and (v) $1.7 billion of cash on hand resulting principally from the sale of our U.S.-based and Canada-based retail natural gas distribution operations (see Note 1).
 
Kinder Morgan Energy Partners’ Common Units
 
On December 22, 2008, Kinder Morgan Energy Partners issued, in a public offering, 3,900,000 of Kinder Morgan Energy Partners’ common units at a price of $46.75 per unit, less commissions and underwriting expenses. After commissions and underwriting expenses, Kinder Morgan Energy Partners received net proceeds of $176.6 million for the issuance of these common units, and used the proceeds to reduce the borrowings under its bank credit facility. This transaction had the associated effects of increasing our (i) minority interests associated with Kinder Morgan Energy Partners by $170.6 million and (ii) associated accumulated deferred income taxes by $2.2 million and reducing our (i) goodwill by $7.6 million and (ii) paid-in capital by $3.8 million.
 
On December 16, 2008, Kinder Morgan Energy Partners furnished to the Securities and Exchange Commission two Current Reports on Form 8-K and one Current Report on Form 8-K/A (in each case, containing disclosures under item 7.01 of Form 8-K) containing certain information with respect to this public offering of Kinder Morgan Energy Partners’ common units. Kinder Morgan Energy Partners also filed a prospectus supplement with respect to this common unit offering on December 17, 2008. These Current Reports may have constituted prospectuses not meeting the requirements of the Securities Act due to the legends used in the Current Reports. Accordingly, under certain circumstances, purchasers of the common units from the offering might have the right to require Kinder Morgan Energy Partners to repurchase the common units they purchased, or if they have sold those common units, to pay damages. Consequently, Kinder Morgan Energy Partners could have a potential liability arising out of these possible violations of the Securities Act. The magnitude of any potential liability is presently impossible to quantify, and would depend upon whether it is demonstrated Kinder Morgan Energy Partners violated the Securities Act, the number of common units that purchasers in the offering sought to require us to repurchase and the treading price of our common units.
 
In connection with the August 28, 2008 sale of our one-third ownership interest in the Express pipeline system and the full interest in the net assets of the Jet Fuel pipeline system, Kinder Morgan Energy Partners issued 2,014,693 of its common units to us. These units, as agreed by Kinder Morgan Energy Partners and us, were valued at $116.0 million. For more information on this acquisition, see Note 10.
 
On March 3, 2008, Kinder Morgan Energy Partners issued, in a public offering, 5,000,000 of its common units at a price of $57.70 per unit, less commissions and underwriting expenses. At the time of the offering, Kinder Morgan Energy Partners granted the underwriters a 30-day option to purchase up to an additional 750,000 of its common units on the same terms and conditions, and pursuant to this option, Kinder Morgan Energy Partners issued an additional 750,000 common units on March 10, 2008 upon exercise of this option. After commissions and underwriting expenses, Kinder Morgan Energy Partners received net proceeds of $324.2 million for the issuance of these 5,750,000 common units, and used the proceeds to reduce the borrowings under its commercial paper program. This transaction had the associated effects of increasing our (i) minority interests associated with Kinder Morgan Energy Partners by $311.2 million and (ii) associated accumulated deferred income taxes by $4.7 million and reducing our (i) goodwill by $21.6 million and (ii) paid-in capital by $13.3 million.
 

 
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Item 8:   Financial Statements and Supplementary Data.  (continued)
Knight Form 10-K


On February 12, 2008, Kinder Morgan Energy Partners completed an offering of 1,080,000 of its common units at a price of $55.65 per unit in a privately negotiated transaction. Kinder Morgan Energy Partners received net proceeds of $60.1 million for the issuance of these 1,080,000 common units, and used the proceeds to reduce the borrowings under its commercial paper program. This transaction had the associated effects of increasing our (i) minority interests associated with Kinder Morgan Energy Partners by $57.6 million and (ii) associated accumulated deferred income taxes by $0.9 million and reducing our (i) goodwill by $4.2 million and (ii) paid-in capital by $2.6 million.
 
On December 5, 2007, Kinder Morgan Energy Partners issued, in a public offering, 7,130,000 of its common units, including common units sold pursuant to the underwriters’ over-allotment option, at a price of $48.09 per common unit, less underwriting expenses, receiving total net proceeds of $342.9 million. This transaction had the associated effects of increasing our minority interests associated with Kinder Morgan Energy Partners by $330.1 million and reducing our (i) goodwill by $33.8 million, (ii) associated accumulated deferred income taxes by $7.6 million and (iii) paid-in capital by $13.4 million.
 
In December 2006, Kinder Morgan Energy Partners issued 34,627 common units as partial consideration for the acquisition of Devco USA L.L.C. This transaction had the associated effects of increasing our minority interests associated with Kinder Morgan Energy Partners by $1.57 million and reducing our (i) goodwill by $110,000, (ii) associated accumulated deferred income taxes by $11,411 and (iii) paid-in capital by $18,589.
 
In August 2006, Kinder Morgan Energy Partners issued, in a public offering, 5,750,000 common units, including common units sold pursuant to an underwriters’ over-allotment option, at a price of $44.80 per unit, less commissions and underwriting expenses. Kinder Morgan Energy Partners received net proceeds of approximately $248.0 million for the issuance of these 5,750,000 common units, and used the proceeds to reduce the borrowings under its commercial paper program. This transaction had the associated effects of increasing our minority interests associated with Kinder Morgan Energy Partners by $236.8 million and reducing our (i) goodwill by $18.8 million, (ii) associated accumulated deferred income taxes by $2.8 million and (iii) paid-in capital by $4.7 million.
 
Kinder Morgan G.P., Inc. Preferred Shares
 
On July 27, 2007, Kinder Morgan G.P., Inc. sold 100,000 shares of its $1,000 Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock due 2057 to a single purchaser. We used the net proceeds of approximately $98.6 million after the initial purchaser’s discounts and commissions to reduce debt. Until August 18, 2012, dividends will accumulate, commencing on the issue date, at a fixed rate of 8.33% per annum and will be payable quarterly in arrears, when and if declared by Kinder Morgan G.P., Inc.’s board of directors, on February 18, May 18, August 18 and November 18 of each year, beginning November 18, 2007. After August 18, 2012, dividends on the preferred stock will accumulate at a floating rate of the 3-month LIBOR plus 3.8975% and will be payable quarterly in arrears, when and if declared by Kinder Morgan G.P., Inc.’s board of directors, on February 18, May 18, August 18 and November 18 of each year, beginning November 18, 2012. The preferred stock has approval rights over a commencement of or filing of voluntary bankruptcy by Kinder Morgan Energy Partners or its SFPP, L.P. or Calnev Pipe Line LLC subsidiaries.
 
During 2008, $8.3 million in cash dividends, or $83.3 per share, was paid on our Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock. On January 21, 2009, Kinder Morgan G.P., Inc.’s board of directors declared a quarterly cash dividend on its Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock of $20.825 per share payable on February 18, 2009 to shareholders of record as of January 30, 2009.
 
Kinder Morgan Management
 
On May 15, 2007, Kinder Morgan Management sold 5.7 million listed shares in a registered offering at a price of $52.26 per share. None of the shares in the offering were purchased by us. Kinder Morgan Management used the net proceeds from the sale to purchase 5.7 million i-units from Kinder Morgan Energy Partners. Kinder Morgan Energy Partners used the net proceeds of approximately $297.9 million to reduce its outstanding commercial paper debt. This transaction had the associated effects of increasing our (i) minority interests associated with Kinder Morgan Energy Partners by $22.7 million, (ii) associated accumulated deferred income taxes by $1.9 million and (iii) paid-in capital by $3.4 million, and reducing our goodwill by $17.4 million. Additional information concerning the business of, and our obligations to, Kinder Morgan Management is contained in Kinder Morgan Management’s Annual Report on Form 10-K for the year ended December 31, 2008.
 
Credit Ratings
 
 
Standard
& Poor’s
  
Moody’s
  
Fitch
Knight Inc.
          
$1.0 billion, six-year secured revolver, due May 2013
BB
  
Ba1
  
BB+
Kinder Morgan Energy Partners
          
$1.85 billion, five-year unsecured revolver, due August 2010
BBB
  
Baa2
  
BBB


 
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Item 8:   Financial Statements and Supplementary Data.  (continued)
Knight Form 10-K


A securities rating is not a recommendation to buy, sell or hold a security, may be subject to revision or withdrawal at any time by the issuing ratings agency in its sole discretion and should be evaluated independently of any other rating.
 
In conjunction with the Going Private transaction, Knight Inc. incurred approximately $4.8 billion in additional debt. Standard & Poor’s Rating Services (“Standard & Poor’s”) and Moody’s Investors Service (“Moody’s”) downgraded the ratings assigned to Knight Inc.’s senior unsecured debt to BB- and Ba2, respectively. Upon the February 2008 80% ownership interest sale of our NGPL business segment, which resulted in Knight Inc.’s repayment of a substantial amount of debt, Standard & Poor’s and Fitch’s upgraded Knight Inc.’s senior unsecured debt to BB and BB+, respectively. However, these ratings are still below investment grade. Since the Going Private transaction, Knight Inc. has not had access to the commercial paper market and is currently utilizing its $1.0 billion revolving credit facility for its short-term borrowing needs.
 
On October 13, 2008, Standard & Poor’s revised its outlook on Kinder Morgan Energy Partners’ long-term credit rating to negative from stable (but affirmed Kinder Morgan Energy Partners’ long-term credit rating at BBB), due to Kinder Morgan Energy Partners’ previously announced expected delay and cost increases associated with the completion of the Rockies Express Pipeline project. At the same time, Standard & Poor’s lowered Kinder Morgan Energy Partners’ short-term credit rating to A-3 from A-2. As a result of this revision and current commercial paper market conditions, Kinder Morgan Energy Partners is unable to access commercial paper borrowings. However, Kinder Morgan Energy Partners expects that short-term financing and liquidity needs will continue to be met through borrowings made under its bank credit facility.
 
Fair Value of Financial Instruments
 
Fair value as used in SFAS No. 107, “Disclosures About Fair Value of Financial Instruments,” represents the amount at which an instrument could be exchanged in a current transaction between willing parties. The estimated fair value of our long-term debt, including its current portion, is based upon prevailing interest rates available to us as of December 31, 2008 and December 31, 2007 and is disclosed below (in millions).
 
 
December 31, 2008
  
December 31, 2007
 
Carrying
Value
  
Estimated
Fair Value
  
Carrying
Value
  
Estimated
Fair Value
Total Debt
$
12,420.5
    
$
10,776.1
    
$
15,377.2
    
$
15,093.7
  

We adjusted the fair value measurement of our long-term debt as of December 31, 2008 in accordance with SFAS No. 157, and the estimated fair value of our debt as of December 31, 2008 (presented in the table above) includes a decrease related to discounting the fair value measurement for the effect of credit risk.
 
Interest Expense, Net
 
Total “Interest Expense, Net” as presented in the accompanying Consolidated Statements of Operations is comprised of the following.
 
 
Successor Company
    
Predecessor Company
 
Year Ended
December 31,
2008
  
Seven Months
Ended
December 31,
2007
    
Five Months
Ended
May 31,
2007
  
Year Ended
December 31,
2006
 
(In millions)
    
(In millions)
Interest Expense, Net
$
674.3
    
$
603.4
      
$
253.3
    
$
576.1
  
Capitalized Interest1
  
(49.3
)
    
(25.5
)
      
(12.2
)
    
(23.3
)
Interest Expense – Preferred Interest in General Partner of KMP
  
8.4
      
3.6
        
-
      
-
  
Total Interest Expense, Net
$
633.4
    
$
581.5
      
$
241.1
    
$
552.8
  
__________
1
Includes the debt component of the allowance for funds used during construction for our regulated utility operations, which are accounted for in accordance with the provisions of SFAS No. 71, Accounting for the Effects of Certain Types of Regulation.
 
“Interest Expense–Net” as presented in the accompanying Consolidated Statement of Operations includes gains and losses from (i) the reacquisition of debt, (ii) the termination of interest rate swaps designated as fair value hedges for which the hedged liability has been extinguished and (iii) the termination of interest rate swaps designated as cash flow hedges for which the forecasted interest payments will no longer occur. During the year ended December 31, 2008, we recorded a $34.4 million loss from the early extinguishment of debt in the caption “Interest Expense, Net,” consisting of an $18.1 million gain on the debt repurchased in the tender more than offset by a $41.7 million loss from the write-off of debt issuance costs associated
 

 
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Item 8:   Financial Statements and Supplementary Data.  (continued)
Knight Form 10-K


with the $5.755 billion secured credit facility. We also recorded $19.8 million of gains from the termination of interest rate swaps designated as fair value hedges, for which the hedged liability was extinguished, in the caption “Interest Expense, Net” in the accompanying Consolidated Statements of Operations.
 
“Interest Expense-Net” for the seven months ended December 31, 2007 includes approximately $179.6 million of interest expense related to the increased debt incurred in the Going Private transaction (See Note 1) and $236.4 million related to Kinder Morgan Energy Partners. “Interest Expense – Net” for the five months ended May 31, 2007 includes $155.0 million related to Kinder Morgan Energy Partners. Included in “Interest Expense-Net” in 2006 is $332.0 million of interest expense relating to Kinder Morgan Energy Partners and $61.3 million of interest expense related to Terasen.
 
15. Risk Management
 
We are exposed to risks associated with changes in the market price of natural gas, natural gas liquids and crude oil as a result of our expected future purchase or sale of these products. We have exposure to interest rate risk as a result of the issuance of variable and fixed rate debt and to foreign currency risk from our investments in businesses owned and operated outside the United States. Pursuant to our risk management policy, 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 (“SFAS No. 133”).
 
Commodity Price Risk Management
 
Our principal use of energy commodity derivative contracts is to mitigate the risk associated with market fluctuations in the price of energy commodities. In accordance with the provisions of SFAS No. 133, we designate these instruments as hedges of various exposures as discussed following, and we test the effectiveness of changes in the value of these hedging instruments with the risk being hedged. Hedge ineffectiveness is recognized in income in the period in which it occurs. Our over-the-counter swaps and options are entered into with counterparties outside central trading facilities such as a futures, options or stock exchange. These contracts are with a number of parties all of which have investment grade credit ratings. While we enter into derivative transactions principally with investment grade counterparties and actively monitor their ratings, it is nevertheless possible that from time to time losses will result from counterparty credit risk.
 
Our normal business activities expose us to risks associated with changes in the market price of natural gas, natural gas liquids and crude oil. Reflecting the portion of changes in the value of derivative contracts that were not effective in offsetting changes in expected cash flows (the ineffective portion of hedges) and to the extent of our economic ownership, we recognized a pre-tax loss of $1.5 million during the year ended December 31, 2008. We recognized a pre-tax gain of approximately $0.5 million and a pre-tax loss of approximately $0.7 million in the seven months ended December 31, 2007 and five months ended May 31, 2007, respectively, and a pre-tax gain of approximately $5.9 million for the year ended December 31, 2006. The gains and losses for each respective period were a result of ineffectiveness of these hedges, which amounts are reported within the captions “Natural Gas Sales,” “Product Sales and Other,” “Gas Purchases and Other Costs of Sales,” “Earnings of Equity Investees” and “Minority Interests” in the accompanying Consolidated Statements of Operations, and for each of the respective periods, we did not exclude any component of the derivative contracts’ gain or loss from the assessment of hedge effectiveness.
 
As the hedged sales and purchases take place and we record them into earnings, we also reclassify the associated gains and losses included in accumulated other comprehensive income into earnings. During the year ended December 31, 2008, we reclassified $117.1 million of accumulated other comprehensive loss into earnings, as a result of hedged forecasted transactions occurring during the period. During the seven months ended December 31, 2007, we did not reclassify any accumulated other comprehensive income or losses into earnings as a result of hedged forecasted transactions occurring during the period. During the five months ended May 31, 2007, we reclassified $11.4 million of accumulated other comprehensive loss into earnings, and during the year ended December 31, 2006, we reclassified, $21.7 million of accumulated other comprehensive loss into earnings, as a result of hedged forecasted transactions occurring during these periods. Furthermore, during the five months ended May 31, 2007 and year ended December 31, 2006, we reclassified $1.1 million of net gains and $2.9 million of net losses, respectively, 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. During the year ended December 31, 2008 and the seven months ended December 31, 2007, we did not reclassify any of our accumulated other comprehensive loss into earnings as a result of the discontinuance of cash flow hedges due to a determination that forecasted transactions would no longer occur by the end of the originally specified time period. During the next twelve months, we expect to reclassify approximately $59.0 million of accumulated other comprehensive income into earnings.
 
Effective at the beginning of the second quarter of 2008, Kinder Morgan Energy Partners determined that the derivative contracts of its Casper and Douglas natural gas processing operations that previously had been designated as cash flow hedges for accounting purposes no longer met the hedge effectiveness assessment as required by SFAS No. 133. Consequently, we discontinued hedge accounting treatment for these relationships (primarily crude oil hedges of heavy natural gas liquids sales) effective as of March 31, 2008. Since the forecasted sales of natural gas liquids volumes (the hedged item) are still expected to
 

 
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Item 8:   Financial Statements and Supplementary Data.  (continued)
Knight Form 10-K


occur, all of the accumulated losses through March 31, 2008 on the related derivative contracts remained in accumulated other comprehensive income, and will not be reclassified into earnings until the physical transactions occurs. Any changes in the value of the these derivative contracts subsequent to March 31, 2008 will no longer be deferred in other comprehensive income, but rather will impact current period income. As a result, we recognized an increase in income of $5.6 million in 2008 related to the increase in value of derivative contracts outstanding as of December 31, 2008 for which hedge accounting had been discontinued.
 
Derivative instruments that are entered into for the purpose of mitigating commodity price risk include swaps, futures and options. Additionally, basis swaps may also be used in connection with another derivative contract to reduce hedge ineffectiveness by reducing basis difference between hedged exposure and a derivative contract. The fair values of these derivative contracts reflect the amounts that we would receive or pay to terminate the contracts at the reporting date and are included in the accompanying Consolidated Balance Sheets as of December 31, 2008 and 2007 within the captions indicated in the following table:
 
 
December 31,
2008
  
December 31,
2007
 
(In millions)
Derivatives Asset (Liability)
              
Current Assets: Fair Value of Derivative Instruments
$
115.3
    
$
37.1
  
Current Assets: Assets Held for Sale
$
-
    
$
8.4
  
Assets: Fair Value of Derivative Instruments, Non-current
$
48.9
    
$
4.4
  
Current Liabilities: Fair Value of Derivative Instruments
$
(129.5
)
  
$
(594.7
)
Current Liabilities: Liabilities Held for Sale
$
-
    
$
(0.4
)
Liabilities and Stockholder’s Equity: Fair Value of Derivative Instruments, Non-current
$
(92.2
)
  
$
(836.8
)

Interest Rate Risk Management
 
In order to maintain a cost effective capital structure, it is our policy to borrow funds using a mix of fixed rate debt and variable rate debt. We use interest rate swap agreements to manage the interest rate risk associated with the fair value of our fixed rate borrowings and to effectively convert a portion of the underlying cash flows related to our long-term fixed rate debt securities into variable rate cash flows in order to achieve our desired mix of fixed and variable rate debt.
 
Prior to the Going Private transaction, all of our interest rate swaps qualified for, and since the Going Private transaction, the new interest rate swaps that Kinder Morgan Energy Partners entered into in February 2008, discussed below, qualify for the “short-cut” method prescribed in SFAS No. 133 for qualifying fair value hedges. Under this method, 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. Interest expense is equal to the floating rate payments, which is accrued monthly and paid semi-annually.
 
In connection with the Going Private transaction, all of our debt, including debt of our subsidiary, Kinder Morgan Energy Partners, was remeasured and recorded on our balance sheet at fair value to the extent of our economic ownership interest. Except for Corridor’s outstanding interest rate swap agreements classified as held for sale, all of our interest rate swaps and swaps of our subsidiary, Kinder Morgan Energy Partners, were re-designated as fair value hedges effective June 1, 2007. Because these swaps did not have a fair value of zero as of June 1, 2007, they did not meet the requirements for the “short-cut” method of assessing their effectiveness. Accordingly, the carrying value of the swap is adjusted to its fair value as of the end of each subsequent reporting period, and an offsetting entry is made to adjust the carrying value of the debt securities whose fair value is being hedged. Any hedge ineffectiveness resulting from the difference between the change in fair value of the interest rate swap and the change in fair value of the hedged debt instrument is recorded as interest expense in the current period. During the year ended December 31, 2008, no hedge ineffectiveness related to these hedges was recognized. Interest expense equal to the floating rate payments is accrued monthly and paid semi-annually.
 
As of December 31, 2007, we, and our subsidiary Kinder Morgan Energy Partners, were parties to interest rate swap agreements with notional principal amounts of $275 million and $2.3 billion, respectively, for a consolidated total of $2.575 billion. On March 7, 2008, we paid $2.5 million to terminate our remaining interest rate swap agreement having a notional value of $275 million associated with Kinder Morgan Finance Company, LLC’s 6.40% senior notes due 2036. In February 2008, Kinder Morgan Energy Partners entered into two additional fixed-to-floating interest rate swap agreements having a combined notional principal amount of $500 million related to its $600 million 5.95% senior notes issued on February 12, 2008. Additionally, on June 6, 2008, following Kinder Morgan Energy Partner’s issuance of $700 million in principal amount of senior notes in two separate series, Kinder Morgan Energy Partners entered into two additional fixed-to-floating interest rate swap agreements having a combined notional principal amount of $700 million. In December 2008, Kinder Morgan Energy Partners took advantage of the general decrease in variable interest rates since the start of 2008 by terminating two of its existing agreements in separate transactions having (i) a notional principal amount of $375 million and a maturity date of
 

 
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Item 8:   Financial Statements and Supplementary Data.  (continued)
Knight Form 10-K


February 15, 2018; and (ii) a notional principal amount of $325 million and a maturity date of January 15, 2038, in which it received combined proceeds of $194.3 million from the early termination of these swap agreements. Therefore, as of December 31, 2008, we were not party to any interest rate swap agreements and Kinder Morgan Energy Partners was a party to fixed-to-floating interest rate swap agreements with a combined notional principal amount of $2.8 billion; effectively converting the interest expense associated with certain series of its senior notes from fixed rates to variable rates based on an interest rate of LIBOR plus a spread.
 
The fair value of interest rate swaps at December 31, 2008 and 2007 of $747.1 million and $139.1 million, respectively, are included in the accompanying Consolidated Balance Sheets within the captions “Assets: Fair Value of Derivative Instruments, Non-current.” The total unamortized net gain on the termination of interest rate swaps of $216.8 million is included within the caption “Long-term Debt: Value of Interest Rate Swaps” in the accompanying Consolidated Balance Sheet at December 31, 2008. All of Kinder Morgan Energy Partners’ swap agreements have termination dates that correspond to the maturity dates of the related series of senior notes and, as of December 31, 2008, the maximum length of time over which Kinder Morgan Energy Partners has hedged a portion of its exposure to the variability in the value of this debt due to interest rate risk is through January 15, 2038.
 
Net Investment Hedges
 
We are exposed to foreign currency risk from our investments in businesses owned and operated outside the United States. To hedge the value of our investment in Canadian operations, we have entered into various cross-currency interest rate swap transactions that have been designated as net investment hedges in accordance with SFAS No. 133. We have recognized no ineffectiveness through the income statement as a result of these hedging relationships during the year ended December 31, 2008, seven months ended December 31, 2007, five months ended May 31, 2007, or year ended December 31, 2006. The effective portion of the changes in fair value of these swap transactions is reported as a cumulative translation adjustment under the caption “Accumulated Other Comprehensive Loss” in the accompanying Consolidated Balance Sheets at December 31, 2008 and 2007.
 
The notional value of our remaining cross-currency interest rate swaps at December 31, 2008 and 2007 was approximately C$154.7 and C$281.6 million, respectively. The fair value of the swaps as of December 31, 2008 was an asset of $32.0 million and at December 31, 2007 was a liability of $51.2 million, which amounts are included in the caption “Assets: Fair Value of Derivative Instruments, Non-current” and “Liabilities and Stockholder’s Equity: Fair Value of Derivative Instruments, Non-current” in the accompanying Consolidated Balance Sheets, respectively. In October 2008, we received $150,000 for the termination of cross-currency interest rate swaps with a combined notional amount of C$126.9 million.
 
SFAS No. 157
 
On September 15, 2006, the FASB issued SFAS No. 157, Fair Value Measurements. In general, fair value measurements and disclosures are made in accordance with the provisions of this Statement and, while not requiring material new fair value measurements, SFAS No. 157 established a single definition of fair value in GAAP and expanded disclosures about fair value measurements. The provisions of this Statement apply to other accounting pronouncements that require or permit fair value measurements; the FASB having previously concluded in those accounting pronouncements that fair value is the relevant measurement attribute.
 
On February 12, 2008, the FASB issued FASB Staff Position FAS 157-2, Effective Date of FASB Statement No. 157 (“FAS 157-2”). FAS 157-2 delayed the effective date of SFAS No. 157 for all nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). Accordingly, we adopted SFAS No. 157 for financial assets and financial liabilities effective January 1, 2008. The adoption did not have a material impact on our balance sheet, statement of operations, or statement of cash flows since we already apply its basic concepts in measuring fair values.
 
We adopted SFAS No. 157 for non-financial assets and non-financial liabilities effective January 1, 2009. This includes applying the provisions of SFAS No. 157 to (i) nonfinancial assets and liabilities initially measured at fair value in business combinations; (ii) reporting units or nonfinancial assets and liabilities measured at fair value in conjunction with goodwill impairment testing; (iii) other nonfinancial assets measured at fair value in conjunction with impairment assessments; and (iv) asset retirement obligations initially measured at fair value. The adoption did not have a material impact on our balance sheet, statement of operations, or statement of cash flows since we already apply its basic concepts in measuring fair values.
 
On October 10, 2008, the FASB issued FASB Staff Position FAS 157-3, Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active, (“FAS 157-3). FAS 157-3 provides clarification regarding the application of SFAS No. 157 in inactive markets. The provisions of FAS 157-3 are effective immediately. This Staff Position did not have any material effect on our consolidated financial statements.
 

 
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Item 8:   Financial Statements and Supplementary Data.  (continued)
Knight Form 10-K


The degree of judgment utilized in measuring the fair value of financial instruments generally correlates to the level of pricing observability. Pricing observability is affected by a number of factors, including the type of financial instrument, whether the financial instrument is new to the market, and the characteristics specific to the transaction. Financial instruments with readily available active quoted prices or for which fair value can be measured from actively quoted prices generally will have a higher degree of pricing observability and a lesser degree of judgment utilized in measuring fair value. Conversely, financial instruments rarely traded or not quoted will generally have less (or no) pricing observability and a higher degree of judgment utilized in measuring fair value.
 
SFAS No. 157 established a hierarchal disclosure framework associated with the level of pricing observability utilized in measuring fair value. This framework defined three levels of inputs to the fair value measurement process, and requires that each fair value measurement be assigned to a level corresponding to the lowest level input that is significant to the fair value measurement in its entirety. The three broad levels of inputs defined by the SFAS No. 157 hierarchy are as follows:
 
 
·
Level 1 Inputs—quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date;
 
·
Level 2 Inputs—inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. If the asset or liability has a specified (contractual) term, a Level 2 input must be observable for substantially the full term of the asset or liability; and
 
·
Level 3 Inputs—unobservable inputs for the asset or liability. These unobservable inputs reflect the entity’s own assumptions about the assumptions that market participants would use in pricing the asset or liability, and are developed based on the best information available in the circumstances (which might include the reporting entity’s own data).
 
Derivative contracts can be exchange-traded or over-the-counter, referred to in this report as OTC. Exchange-traded derivative contracts typically fall within Level 1 of the fair value hierarchy if they are traded in an active market. We and Kinder Morgan Energy Partners value exchange-traded derivative contracts using quoted market prices for identical securities.
 
OTC derivative contracts are valued using models utilizing a variety of inputs including contractual terms, commodity, interest rate and foreign currency curves, and measures of volatility. The selection of a particular model and particular inputs to value an OTC derivative contract depends upon the contractual terms of the instrument as well as the availability of pricing information in the market. We and Kinder Morgan Energy Partners use similar models to value similar instruments. For OTC derivative contracts that trade in liquid markets, such as generic forwards and swaps, model inputs can generally be verified and model selection does not involve significant management judgment. Such contracts are typically classified within Level 2 of the fair value hierarchy.
 
Certain OTC derivative contracts trade in less liquid markets with limited pricing information, and the determination of fair value for these derivative contracts is inherently more difficult. Such contracts are classified within Level 3 of the fair value hierarchy. The valuations of these less liquid OTC derivative contracts are typically impacted by Level 1 and/or Level 2 inputs that can be observed in the market, as well as unobservable Level 3 inputs. Use of a different valuation model or different valuation input values could produce a significantly different estimate of fair value. However, derivative contracts valued using inputs unobservable in active markets are generally not material to our financial statements.
 
When appropriate, valuations are adjusted for various factors including credit considerations. Such adjustments are generally based on available market evidence. In the absence of such evidence, management’s best estimate is used. Our fair value measurements of derivative contracts are adjusted for credit risk in accordance with SFAS No. 157, and as of December 31, 2008, the net asset balance associated with these contracts recorded in the accompanying Consolidated Balance Sheet includes a reduction of $2.2 million related to discounting the value of our energy commodity derivative liabilities for the effect of credit risk. We also adjusted the fair value measurements of our interest rate swap agreements for credit risk in accordance with SFAS No. 157, and as of December 31, 2008, the value of interest rate swaps included a decrease (loss) of $10.6 million related to discounting the fair value measurement of our interest rate swap agreements’ asset value for the effect of credit risk.
 

 
141
 
Item 8:   Financial Statements and Supplementary Data.  (continued)
Knight Form 10-K


The following tables summarize the fair value measurements of our (i) energy commodity derivative contracts, (ii) interest rate swap agreements and (iii) cross-currency interest rate swaps as of December 31, 2008, based on the three levels established by SFAS No. 157, and does not include cash margin deposits, which are reported in the caption “Current Assets: Restricted Deposits” in the accompanying Consolidated Balance Sheet.
 
 
Asset Fair Value Measurements as of December 31, 2008 Using
 
Total
  
Quoted Prices in Active Markets
for Identical
Assets (Level 1)
  
Significant Other
Observable
Inputs (Level 2)
  
Significant
Unobservable
Inputs (Level 3)
 
(In millions)
Energy Commodity Derivative Contracts1
$
164.2
    
$
0.1
    
$
108.9
    
$
55.2
    
                                 
Interest Rate Swap Agreements
$
747.1
    
$
-
    
$
747.1
    
$
-
    
                                 
Cross-currency Interest Rate Swaps
$
32.0
    
$
-
    
$
32.0
    
$
-
    
 
 
Liability Fair Value Measurements as of December 31, 2008 Using
 
Total
  
Quoted Prices in Active Markets
for Identical
Assets (Level 1)
  
Significant Other
Observable
Inputs (Level 2)
  
Significant
Unobservable
Inputs (Level 3)
 
(In millions)
Energy Commodity Derivative Contracts2
$
(221.7
)
  
$
-
    
$
(210.6
)
  
$
(11.1
)
  
                                 
Interest Rate Swap Agreements
$
-
    
$
-
    
$
-
    
$
-
    
____________
1
Level 2 consists primarily of OTC West Texas Intermediate hedges and OTC natural gas hedges that are settled on the New York Mercantile Exchange (“NYMEX”). Level 3 consists primarily of West Texas Intermediate options and West Texas Sour hedges.
2
Level 2 consists primarily of OTC West Texas Intermediate hedges. Level 3 consists primarily of natural gas basis swaps, natural gas options and West Texas Intermediate options.
 
The table below provides a summary of changes in the fair value of our Level 3 energy commodity derivative contracts for the year ended December 31, 2008:
 
Significant Unobservable Inputs (Level 3)
 
 
Year Ended
December 31,
2008
 
(In millions)
Net Asset (Liability)
      
Beginning Balance
$
(100.3
)
Realized and Unrealized Net Losses
  
69.6
  
Purchases and Settlements
  
74.8
  
Balance as of December 31, 2008
$
44.1
  
Change in Unrealized Net Losses Relating to Contracts Still Held as of December 31, 2008
$
88.8
  

Credit Risks
 
We and Kinder Morgan Energy Partners have counterparty credit risk as a result of our use of energy commodity derivative contracts. Our counterparties consist primarily of financial institutions, major energy companies and local distribution companies. This concentration of counterparties may impact our overall exposure to credit risk, either positively or negatively in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions.
 
We maintain credit policies with regard to our counterparties that we believe minimize our overall credit risk. These policies include (i) an evaluation of potential counterparties’ financial condition (including credit ratings), (ii) collateral requirements under certain circumstances and (iii) the use of standardized agreements which allow for netting of positive and negative exposure associated with a single counterparty. Based on our policies, exposure, credit and other reserves, our management
 

 
142
 
Item 8:   Financial Statements and Supplementary Data.  (continued)
Knight Form 10-K


does not anticipate a material adverse effect on our financial position, results of operations, or cash flows as a result of counterparty performance.
 
Our over-the-counter swaps and options are entered into with counterparties outside central trading organizations such as a futures, options or stock exchange. These contracts are with a number of parties, all of which have investment grade credit ratings. While we enter into derivative transactions principally with investment grade counterparties and actively monitor their ratings, it is nevertheless possible that from time to time losses will result from counterparty credit risk in the future.
 
In addition, in conjunction with the purchase of exchange-traded derivative contracts or when the market value of our derivative contracts with specific counterparties exceeds established limits, we are required to provide collateral to our counterparties, which may include posting letters of credit or placing cash in margin accounts. As of December 31, 2008 and December 31, 2007, Kinder Morgan Energy Partners had outstanding letters of credit totaling $40.0 million and $298.0 million, respectively, in support of its hedging of commodity price risks associated with the sale of natural gas, natural gas liquids and crude oil. Additionally, as of December 31, 2008, Kinder Morgan Energy Partners’ counterparties associated with its energy commodity contract positions and over-the-counter swap agreements had margin deposits with Kinder Morgan Energy Partners totaling $3.1 million, and we reported this amount in the caption “Other” within “Current Liabilities” in the accompanying Consolidated Balance Sheet. As of December 31, 2007, we had cash margin deposits associated with Kinder Morgan Energy Partners’ commodity contract positions and over-the-counter swap partners totaling $67.9 million, and we reported this amount in the caption “Current Assets: Restricted Deposits” in the accompanying Consolidated Balance Sheet.
 
We and Kinder Morgan Energy Partners are also exposed to credit related losses in the event of nonperformance by counterparties to our interest rate swap agreements, and while we and Kinder Morgan Energy Partners enter into these agreements primarily with investment grade counterparties and actively monitor their credit ratings; it is nevertheless possible that from time to time losses will result from counterparty credit risk in the future. As of December 31, 2008, all of our and Kinder Morgan Energy Partners’ interest rate swap agreements were with counterparties with investment grade credit ratings, and the $747.1 million total fair value of our and Kinder Morgan Energy Partners’ interest rate swap derivative assets at December 31, 2008 (disclosed above) included amounts of $301.8 million and $249.0 million related to open positions with Citigroup and Merrill Lynch, respectively.
 
16. Employee Benefits
 
Knight Inc.
 
Retirement Plans
 
We have defined benefit pension plans covering eligible full-time employees. These plans provide pension benefits that are based on the employees’ compensation during the period of employment, age and years of service. These plans are tax-qualified subject to the minimum funding requirements of the Employee Retirement Income Security Act of 1974, as amended. Our funding policy is to contribute annually the recommended contribution using the actuarial cost method and assumptions used for determining annual funding requirements. Plan assets consist primarily of pooled fixed income, equity, bond and money market funds. The Plan did not have any material investments in our company or affiliates as of December 31, 2008 and 2007.
 
Total amounts recognized in net periodic pension cost include the following components:
 
 
Successor Company
    
Predecessor Company
 
Year Ended
December 31,
2008
  
Seven Months
Ended
December 31,
2007
    
Five Months
Ended
May 31,
2007
  
Year Ended December 31,
2006
 
(In millions)
    
(In millions)
Net Periodic Pension Benefit Cost
                                
Service Cost
$
10.8
    
$
5.6
      
$
4.5
    
$
10.6
  
Interest Cost
  
14.5
      
8.1
        
5.6
      
12.7
  
Expected Return on Assets
  
(23.2
)
    
(14.0
)
      
(9.6
)
    
(21.3
)
Amortization of Prior Service Cost
  
0.1
      
-
        
0.1
      
0.2
  
Amortization of Loss
  
0.3
      
-
        
0.2
      
0.9
  
Net Periodic Pension Benefit Cost
$
2.5
    
$
(0.3
)
    
$
0.8
    
$
3.1
  


 
143
 
Item 8:   Financial Statements and Supplementary Data.  (continued)
Knight Form 10-K


The following table sets forth the reconciliation of the beginning and ending balances of the pension benefit obligation:
 
 
Successor Company
    
Predecessor
Company
 
Year Ended
December 31,
2008
  
Seven Months
Ended
December 31,
2007
    
Five Months
Ended
May 31, 2007
 
(In millions)
    
(In millions)
Benefit Obligation at Beginning of Period
$
258.0
    
$
236.5
      
$
232.0
  
Service Cost
  
10.8
      
5.6
        
4.5
  
Interest Cost
  
14.5
      
8.1
        
5.6
  
Actuarial Loss (Gain)
  
(14.2
)
    
18.5
        
(2.5
)
Plan Amendments
  
0.8
      
-
        
2.7
  
Benefits Paid
  
(14.9
)
    
(10.7
)
      
(5.8
)
Benefit Obligation at End of Period
$
255.0
    
$
258.0
      
$
236.5
  

The accumulated benefit obligation at December 31, 2008 and 2007 was $248.6 million and $248.1 million, respectively.
 
The following table sets forth the reconciliation of the beginning and ending balances of the fair value of the plans’ assets and the plans’ funded status:
 
 
Successor Company
    
Predecessor
Company
 
Year Ended
December 31,
2008
  
Seven Months
Ended
December 31,
2007
    
Five Months
Ended
May 31, 2007
 
(In millions)
    
(In millions)
Fair Value of Plan Assets at Beginning of Period
$
264.7
    
$
273.4
      
$
261.6
  
Actual Return on Plan Assets During the Period
  
(70.1
)
    
1.9
        
17.6
  
Benefits Paid During the Period
  
(14.9
)
    
(10.7
)
      
(5.8
)
Fair Value of Plan Assets at End of Period
  
179.7
      
264.6
        
273.4
  
Benefit Obligation at End of Period
  
(255.0
)
    
(258.0
)
      
(236.5
)
Funded Status at End of Period
$
(75.3
)
  
$
6.6
      
$
36.9
  

The accompanying Consolidated Balance Sheets at December 31, 2008 include a balance of $75.3 million under the caption “Other Long-term Liabilities and Deferred Credits” related to our pension plans. At December 31, 2007, the accompanying Consolidated Balance Sheets include a balance of $7.0 million under the caption “Deferred Charges and Other Assets,” and a balance of $0.4 million under the caption “Other Long-term Liabilities and Deferred Credits” related to our pension plans.
 
Amounts recognized in “Accumulated Other Comprehensive Loss” consist of:
 
 
Successor Company
    
Predecessor
Company
 
Year Ended
December 31,
2008
  
Seven Months
Ended
December 31,
2007
    
Five Months
Ended
May 31, 2007
 
(In millions)
    
(In millions)
Beginning Balance
$
30.6
    
$
-
      
$
19.3
  
Net (Gain)/Loss Arising During Period
  
79.1
      
30.6
        
(10.5
)
Prior Service Cost Arising During Period
  
0.7
      
-
        
2.7
  
Amortization of (Gain)/Loss
  
(0.4
)
    
-
        
(0.2
)
Amortization of Prior Service Cost
  
(0.1
)
    
-
        
(0.1
)
Ending Balance
$
109.9
    
$
30.6
      
$
11.2
  

Our actuarial estimates allocate costs based on projected employee costs. As experience develops under our plan, actuarial gains (losses) result from experience more favorable (unfavorable) than assumed.
 

 
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Item 8:   Financial Statements and Supplementary Data.  (continued)
Knight Form 10-K


The estimated net loss for the defined benefit pension plans that will be amortized from accumulated other comprehensive income into net periodic pension benefit cost over the next fiscal year is $7.4 million.
 
We expect to contribute approximately $20 million to the Plan during 2009.
 
The following net benefit payments, which reflect expected future service, as appropriate, are expected to be paid:
 
Fiscal Year
  
Expected Net Benefit Payments
   
(In millions)
2009
  
$
14.4
  
2010
  
$
15.3
  
2011
  
$
16.3
  
2012
  
$
17.1
  
2013
  
$
17.6
  
2014-2017
  
$
108.5
  

Effective January 1, 2001, we added a cash balance plan to our retirement plan. Certain collectively bargained employees and “grandfathered” employees continue to accrue benefits through the defined pension benefit plan described above. All other employees accrue benefits through a personal retirement account in the cash balance plan. All employees converting to the cash balance plan were credited with the current fair value of any benefits they had previously accrued through the defined benefit plan. We make contributions on behalf of these employees equal to 3% of eligible compensation every pay period. Interest is credited to the personal retirement accounts at the 30-year U.S. Treasury bond rate, or an approved substitute, in effect each year. Employees become fully vested in the plan after three years (five years prior to January 1, 2008) and they may take a lump sum distribution upon termination of employment or retirement.
 
In addition to our retirement plan described above, we have the Knight Inc. Savings Plan (the “Plan”), a defined contribution 401(k) plan. The plan permits all full-time employees to contribute between 1% and 50% of base compensation, on a pre-tax basis, into participant accounts. In addition to a Company contribution equal to 4% of base compensation per year for most plan participants, we may make discretionary contributions. Certain employees’ contributions are based on collective bargaining agreements. The contributions are made each pay period on behalf of each eligible employee. Participants may direct the investment of their contributions and all employer contributions, including discretionary contributions, into a variety of investments. Plan assets are held and distributed pursuant to a trust agreement. The total amount contributed for the year ended December 31, 2008, seven months ended December 31, 2007, five months ended May 31, 2007 and year ended December 31, 2006 was $20.8 million, $11.0 million, $8.1 million and $18.3 million, respectively.
 
Employer contributions for employees vest on the second anniversary of the date of hire. Effective October 1, 2005, a tiered employer contribution schedule was implemented for new employees of the Terminals–KMP segment. This tiered schedule provides for employer contributions of 1% for service less than one year, 2% for service between one and two years, 3% for services between two and five years, and 4% for service of five years or more. All employer contributions for Terminals–KMP employees hired after October 1, 2005 vest on the fifth anniversary of the date of hire. Effective January 1, 2008, this five year anniversary date for Terminals –KMP employees was changed to three years to comply with changes in federal regulations. Vesting and contributions for bargaining employees will follow the collective bargaining agreements.
 
At its July 2008 meeting, the compensation committee of our board of directors approved a special contribution of an additional 1% of base pay into the Plan for each eligible employee. Each eligible employee will receive an additional 1% Company contribution based on eligible base pay each pay period beginning with the first pay period of August 2008 and continuing through the last pay period of July 2009. The additional 1% contribution does not change or otherwise impact, the annual 4% contribution that eligible employees currently receive and the vesting schedule mirrors the Company’s 4% contribution. Since this additional 1% Company contribution is discretionary, compensation committee approval will be required annually for each additional contribution. During the first quarter of 2009, excluding the 1% additional contribution described above, we will not make any additional discretionary contributions to individual accounts for 2008.
 
Additionally, participants have an option to make after-tax “Roth” contributions (Roth 401(k) option) to a separate participant account. Unlike traditional 401(k) plans, where participant contributions are made with pre-tax dollars, earnings grow tax-deferred, and the withdrawals are treated as taxable income, Roth 401(k) contributions are made with after-tax dollars, earnings are tax-free, and the withdrawals are tax-free if they occur after both (i) the fifth year of participation in the Roth 401(k) option and (ii) attainment of age 59 ½, death or disability. The employer contribution will still be considered taxable income at the time of withdrawal.
 

 
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Item 8:   Financial Statements and Supplementary Data.  (continued)
Knight Form 10-K


In 2006, we elected not to make any restricted stock awards as a result of the Going Private transaction. To ensure that certain key employees who had previously received restricted stock and restricted stock unit awards continued under a long-term retention and incentive program, the Company implemented the Long-term Incentive Retention Award plan. The plan provides cash awards approved by the compensation committees of the Company which are granted in July of each year to recommended key employees. Senior management is not eligible for these awards. These grants require the employee to sign a grant agreement. The grants vest 100% after the third year anniversary of the grant provided the employee remains with the Company. Grants were made in July of 2006, 2007 and 2008. During the year ended December 31, 2008, seven months ended December 31, 2007, five months ended May 31, 2007 and year ended December 31, 2006, we amortized $6.9 million, $5.3 million, $1.3 million and $1.9 million, respectively, related to these grants.
 
Other Postretirement Employee Benefits
 
We have a postretirement plan providing medical and life insurance benefits upon retirement. For certain eligible employees and their eligible dependents that are “grandfathered,” we also provide a subsidized premium. All others who are eligible pay the full cost. We fund a portion of the future expected postretirement benefit cost under the plan by making payments to Voluntary Employee Benefit Association trusts. Plan assets are invested in a mix of equity funds and fixed income instruments similar to the investments in our pension plans.
 
Total amounts recognized in net periodic postretirement benefit cost include the following components:
 
 
Successor Company
    
Predecessor Company
 
Year Ended
December 31,
2008
  
Seven Months
Ended
December 31,
2007
    
Five Months
Ended
May 31,
2007
  
Year Ended December 31,
2006
 
(In millions)
    
(In millions)
Net Periodic Postretirement Benefit Cost
                                
Service Cost
$
0.3
    
$
0.2
      
$
0.2
    
$
0.4
  
Interest Cost
  
4.6
      
2.7
        
1.9
      
4.9
  
Expected Return on Assets
  
(6.5
)
    
(3.9
)
      
(2.7
)
    
(5.8
)
Amortization of Prior Service Credit
  
-
      
-
        
(0.7
)
    
(1.6
)
Amortization of Loss
  
0.5
      
-
        
2.0
      
5.2
  
Net Periodic Postretirement Benefit Cost
$
(1.1
)
  
$
(1.0
)
    
$
0.7
    
$
3.1
  

The following table sets forth the reconciliation of the beginning and ending balances of the accumulated postretirement benefit obligation:
 
 
Successor Company
    
Predecessor
Company
 
Year Ended December 31, 2008
  
Seven Months
Ended
December 31, 2007
    
Five Months
Ended
May 31, 2007
 
(In millions)
    
(In millions)
Benefit Obligation at Beginning of Period
$
82.0
    
$
78.7
      
$
84.0
  
Service Cost
  
0.3
      
0.2
        
0.2
  
Interest Cost
  
4.6
      
2.7
        
1.9
  
Actuarial Loss (Gain)
  
2.0
      
7.5
        
(3.5
)
Benefits Paid
  
(13.8
)
    
(8.5
)
      
(5.3
)
Retiree Contributions
  
2.9
      
1.4
        
1.4
  
Benefit Obligation at End of Period
$
78.0
    
$
82.0
      
$
78.7
  


 
146
 
Item 8:   Financial Statements and Supplementary Data.  (continued)
Knight Form 10-K


The following table sets forth the reconciliation of the beginning and ending balances of the fair value of plan assets and the plan’s funded status:
 
 
Successor Company
    
Predecessor
Company
 
Year Ended
December 31,
2008
  
Seven Months
Ended
December 31,
2007
    
Five Months
Ended
May 31, 2007
 
(In millions)
    
(In millions)
Fair Value of Plan Assets at Beginning of Period
$
69.2
    
$
76.9
      
$
67.5
  
Actual Return on Plan Assets
  
(17.5
)
    
0.1
        
4.5
  
Contributions
  
8.7
      
-
        
8.7
  
Retiree Contributions
  
2.9
      
1.6
        
1.2
  
Transfers In
  
-
      
0.1
        
-
  
Benefits Paid
  
(14.2
)
    
(9.5
)
      
(5.0
)
Fair Value of Plan Assets at End of Period
  
49.1
      
69.2
        
76.9
  
Benefit Obligation at End of Period
  
(78.0
)
    
(82.0
)
      
(78.7
)
Funded Status at End of Period
$
(28.9
)
  
$
(12.8
)
    
$
(1.8
)

The accompanying Consolidated Balance Sheets at December 31, 2008 and 2007 include balances of $28.9 million and $12.8 million, respectively, under the caption “Other Long-term Liabilities and Deferred Credits,” related to our other postretirement benefit plans.
 
Amounts recognized in “Accumulated Other Comprehensive Loss” consist of:
 
 
Successor Company
    
Predecessor
Company
 
Year Ended
December 31,
2008
  
Seven Months
Ended
December 31,
2007
    
Five Months
Ended
May 31, 2007
 
(In millions)
    
(In millions)
Beginning Balance
$
12.0
    
$
-
      
$
44.0
  
Net (Gain)/Loss Arising During Period
  
26.4
      
12.0
        
(5.4
)
Amortization of (Gain)/Loss
  
(0.5
)
    
-
        
(2.0
)
Amortization of Prior Service Cost
  
-
      
-
        
0.7
  
Ending Balance
$
37.9
    
$
12.0
      
$
37.3
  

The estimated net loss for the postretirement benefit plans that will be amortized from accumulated other comprehensive income into net periodic postretirement benefit cost over the next fiscal year is $3.0 million. NGPL PipeCo LLC expects to make contributions of approximately $8.7 million to the plan in 2009.
 
A one-percentage-point increase (decrease) in the assumed health care cost trend rate for each future year would have increased (decreased) the aggregate of the service and interest cost components of the 2008 net periodic postretirement benefit cost by approximately $5 $(4) thousand and would have increased (decreased) the accumulated postretirement benefit obligation as of December 31, 2008 by approximately $77 $(72) thousand.
 
The following net benefit payments, which reflect expected future service, as appropriate, are expected to be paid:
 
Fiscal Year
  
Expected Net Benefit Payments
   
(In millions)
2009
  
$
7.6
  
2010
  
$
7.3
  
2011
  
$
7.2
  
2012
  
$
6.9
  
2013
  
$
6.8
  
2014-2017
  
$
31.2
  


 
147
 
Item 8:   Financial Statements and Supplementary Data.  (continued)
Knight Form 10-K


Actuarial Assumptions
 
The assumptions used to determine benefit obligations for the pension and postretirement benefit plans were:
 
 
Successor Company
    
Predecessor Company
 
Year Ended December 31,
2008
  
Seven Months
Ended
December 31,
2007
    
Five Months
Ended
May 31,
2007
  
Year Ended
December 31,
2006
Discount Rate
    
6.25
%
        
5.75
%
          
6.00
%
        
6.00
%
  
Expected Long-term Return on Assets
    
8.75
%
        
9.00
%
          
9.00
%
        
9.00
%
  
Rate of Compensation Increase (Pension Plan Only)
    
3.50
%
        
3.50
%
          
3.50
%
        
3.50
%
  

The assumptions used to determine net periodic benefit cost for the pension and postretirement benefits were:
 
 
Successor Company
    
Predecessor Company
 
Year Ended December 31,
2008
  
Seven Months
Ended
December 31,
2007
    
Five Months
Ended
May 31,
2007
  
Year Ended
December 31,
2006
Discount Rate
    
5.75
%
        
6.00
%
          
6.00
%
        
5.75
%
  
Expected Long-term Return on Assets
    
9.00
%
        
9.00
%
          
9.00
%
        
9.00
%
  
Rate of Compensation Increase (Pension Plan Only)
    
3.50
%
        
3.50
%
          
3.50
%
        
3.50
%
  

The assumed healthcare cost trend rates for the postretirement plan were:
 
 
Successor Company
    
Predecessor Company
 
Year Ended December 31,
2008
  
Seven Months
Ended
December 31,
2007
    
Five Months
Ended
May 31,
2007
  
Year Ended
December 31,
2006
Healthcare Cost Trend Rate Assumed for Next Year
    
3.0%
          
3.0%
            
3.0%
          
3.0%
    
Rate to which the Cost Trend Rate is Assumed to Decline (Ultimate Trend Rate)
    
3.0%
          
3.0%
            
3.0%
          
3.0%
    
Year the Rate Reaches the Ultimate Trend Rate
    
2008
          
2007
            
2007
          
2006
    

Plan Investment Policies
 
The investment policies and strategies for the assets of our pension and retiree medical and retiree life insurance plans are established by the Fiduciary Committee (the “Committee”), which is responsible for investment decisions and management oversight of each plan. The stated philosophy of the Committee is to manage these assets in a manner consistent with the purpose for which the plans were established and the time frame over which the plans’ obligations need to be met. The objectives of the investment management program are to (1) meet or exceed plan actuarial earnings assumptions over the long term and (2) provide a reasonable return on assets within established risk tolerance guidelines and liquidity needs of the plans with the goal of paying benefit and expense obligations when due. In seeking to meet these objectives, the Committee recognizes that prudent investing requires taking reasonable risks in order to raise the likelihood of achieving the targeted investment returns. In order to reduce portfolio risk and volatility, the Committee has adopted a strategy of using multiple asset classes.
 
As of December 31, 2008, the following target asset allocation ranges were in effect for our pension plans (Minimum/Target/Maximum): Cash – 0%/0%/5%; Fixed Income –20%/30%/40%; Equity – 55%/65%/75% and Alternative Investments – 0%/5%/10%. As of December 31, 2008, the following target asset allocation ranges were in effect for our retiree medical and retiree life insurance plans (Minimum/Target/Maximum): Cash – 0%/0%/5%; Fixed Income –20%/30%/40% and Equity – 60%/70%/80%. In order to achieve enhanced diversification, the equity category is further subdivided into sub-categories with respect to small cap vs. large cap, value vs. growth and international vs. domestic, each with its own target asset allocation.
 
In implementing its investment policies and strategies, the Committee has engaged a professional investment advisor to assist with its decision making process and has engaged professional money managers to manage plan assets. The Committee believes that such active investment management will achieve superior returns with comparable risk in comparison to passive management. Consistent with its goal of reasonable diversification, no manager of an equity portfolio for the plan is allowed to have more than 10% of the market value of the portfolio in a single security or weight a single economic sector more than twice the weighting of that sector in the appropriate market index. Finally, investment managers are not permitted to invest or engage in the following equity transactions unless specific permission is given in writing (which permission has not been requested or granted by the Committee to-date): derivative instruments, except for the purpose of asset value protection (such
 

 
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as the purchase of protective puts), direct ownership of letter stock, restricted stock, limited partnership units (unless the security is registered and listed on a domestic exchange), venture capital, short sales, margin purchases or borrowing money, stock loans and commodities. In addition, fixed income holdings in the following investments are prohibited without written permission: private placements, except medium-term notes and securities issued under SEC Rule 144a; foreign bonds (non-dollar denominated); municipal or other tax exempt securities, except taxable municipals; margin purchases or borrowing money to effect leverage in the portfolio; inverse floaters, interest only and principle only mortgage structures; and derivative investments (futures or option contracts) used for speculative purposes. Certain other types of investments such as hedge funds and land purchases are not prohibited as a matter of policy but have not, as yet, been adopted as an asset class or received any allocation of fund assets.
 
Return on Plan Assets
 
For the year ending December 31, 2008, our defined benefit pension plan yielded a weighted-average rate of return of (27.87%), below the expected rate of return on assets of 9.00%. Investment performance for a balanced fund comprised of a similar mix of assets yielded a weighted-average return of (25.45%), so our plans underperformed the benchmark balanced fund index. For the year ending December 31, 2008, our retiree medical and retiree life insurance plans yielded a weighted-average rate of return of (26.04%), below the expected rate of return on assets of 9.00%. Investment performance for a balanced fund comprised of a similar mix of assets yielded a weighted-average return of (22.55%), so our plans underperformed the benchmark balanced fund index.
 
At December 31, 2008, our pension plan assets consisted of 60.6% equity, 34.4% fixed income and 5.0% cash and cash equivalents, and our retiree medical and retiree life insurance plan assets consisted of 54.1% equity, 38.8% fixed income and 7.1% cash and cash equivalents. Historically over long periods of time, widely traded large cap equity securities have provided a return of 10%, while fixed income securities have provided a return of 6%, indicating that a long term expected return predicated on the asset allocation as of December 31, 2008 would be approximately 8.75% to 9.31% if investments were made in the broad indexes for our defined benefit pension plan, and 8.36% to 8.88% for our retiree medical and retiree life insurance plan. As reported in our 2007 Annual Report on Form 10-K, these expected returns as of December 31, 2007 were 9.6% to 9.8%. We arrived at an overall expected return of 9.0% for our periodic benefit cost calculations for 2008 and an overall expected return of 8.75% for our benefit obligation calculations as of December 31, 2008.
 
Kinder Morgan Energy Partners
 
Kinder Morgan Canada Inc. and Trans Mountain Pipeline Inc. (as general partners of Trans Mountain Pipeline, L.P.) are sponsors of pension plans for eligible Trans Mountain employees. The plans include registered defined benefit pension plans, supplemental unfunded arrangements, which provide pension benefits in excess of statutory limits, and defined contributory plans. Kinder Morgan Energy Partners also provides postretirement benefits other than pensions for retired employees. Kinder Morgan Energy Partners’ combined net periodic benefit costs for these Trans Mountain pension and postretirement benefit plans for the year ended December 31, 2008, seven months ended December 31, 2007 and five months ended May 31, 2007 were approximately $3.5 million, $1.9 million and $1.3 million, respectively. As of December 31, 2008, Kinder Morgan Energy Partners estimates its overall net periodic pension and postretirement benefit costs for these plans for the year 2009 will be approximately $3.1 million, although this estimate could change if there is a significant event, such as a plan amendment or a plan curtailment, which would require a remeasurement of liabilities. Kinder Morgan Energy Partners expects to contribute approximately $7.7 million to these benefit plans in 2009. Prior to the sale of Trans Mountain to Kinder Morgan Energy Partners on April 30, 2007 (refer to Note 10) the pension plans of Trans Mountain were part of the Terasen pension plans. Refer to the following discussion on the Terasen pension plans for 2006.
 
In connection with Kinder Morgan Energy Partners’ acquisition of SFPP, L.P., (“SFPP”) and Kinder Morgan Bulk Terminals, Inc. in 1998, Kinder Morgan Energy Partners acquired certain liabilities for pension and postretirement benefits. Kinder Morgan Energy Partners provides medical and life insurance benefits to current employees, their covered dependents and beneficiaries of SFPP and Kinder Morgan Bulk Terminals. Kinder Morgan Energy Partners also provides the same benefits to former salaried employees of SFPP. Additionally, Kinder Morgan Energy Partners will continue to fund these costs for those employees currently in the plan during their retirement years. SFPP’s postretirement benefit plan is frozen, and no additional participants may join the plan. The noncontributory defined benefit pension plan covering the former employees of Kinder Morgan Bulk Terminals is the Knight Inc. Retirement Plan. The benefits under this plan are based primarily upon years of service and final average pensionable earnings; however, benefit accruals were frozen as of December 31, 1998.
 
The net periodic benefit cost for the SFPP postretirement benefit plan was less than $0.1 million for the year ended December 31, 2008, and credits of $0.1 million, $0.1 million and $0.3 million for the seven months ended December 31, 2007, five months ended May 31, 2007 and year ended December 31, 2006, respectively. The credits in 2006 and 2007 resulted in increases to income, largely due to amortizations of an actuarial gain and a negative prior service cost. As of December 31, 2008, Kinder Morgan Energy Partners estimates its overall net periodic postretirement benefit cost for the SFPP postretirement benefit plan for the year 2009 will be a credit of approximately $0.1 million, however, this estimate could

 
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change if a future significant event would require a remeasurement of liabilities. In addition, Kinder Morgan Energy Partners expects to contribute approximately $0.3 million to this postretirement benefit plan in 2009.
 
As of December 31, 2008 and 2007, the recorded value of Kinder Morgan Energy Partners’ pension and postretirement benefit obligations for these plans was a combined $33.4 million and $37.5 million, respectively.
 
Multiemployer Plans
 
As a result of acquiring several terminal operations, primarily the acquisition of Kinder Morgan Bulk Terminals, Inc. effective July 1, 1998, Kinder Morgan Energy Partners participates in several multi-employer pension plans for the benefit of employees who are union members. Kinder Morgan Energy Partners does not administer these plans and contributes to them in accordance with the provisions of negotiated labor contracts. Other benefits include a self-insured health and welfare insurance plan and an employee health plan where employees may contribute for their dependents’ health care costs. Amounts charged to expense for these plans totaled $7.8 million, $2.5 million, $4.2 million and $6.3 million for the year ended December 31, 2008, seven months ended December 31, 2007, five months ended May 31, 2007 and year ended December 31, 2006, respectively.
 
Terasen
 
Prior to the sale of Terasen Inc. and Terasen Pipelines (Corridor) Inc. on May 17, 2007 and June 15, 2007, respectively, (see Note 19) we were a sponsor of pension plans for eligible employees. Our expense for the Terasen Inc. and Corridor pension and other postretirement benefits plans for the period from January 1 to May 15, 2007 was $3.7 million and $11.1 million for the year ended December 31, 2006. After the sale of Terasen and Corridor we no longer had expenses or obligations related to these pension and other postretirement plans. The Terasen and Corridor plans included registered defined benefit pension plans, supplemental unfunded arrangements, which provide pension benefits in excess of statutory limits, and defined contributory plans. We also provided postretirement benefits other than pensions for retired employees.
 
17. Share-based Compensation
 
Knight Inc.
 
In March 2007, all stock options and restricted stock held by employees of our discontinued U.S. Retail operations became fully vested. In May 2007, all restricted stock units held by employees of our discontinued Terasen gas operations became fully vested and any contingent stock unit grants were fully expensed. Finally, on May 30, 2007, all remaining stock options and restricted stock became fully vested and were exercised upon the closing of the Going Private transaction. We recorded expense of $25.7 million during the five months ended May 31, 2007 related to the accelerated vesting of these awards.
 
Restricted stock and restricted stock unit grants issued in the periods presented below were under the following plans: The 1992 Non-Qualified Stock Option Plan for Non-Employee Directors (which plan has expired), the 1994 Kinder Morgan, Inc. Long-term Incentive Plan (which plan has expired), the Kinder Morgan, Inc. Amended and Restated 1999 Stock Plan and the Non-Employee Directors Stock Awards Plan. The 1994 plan, and the 1999 plan and the Non-Employee Directors Stock Awards Plan provided for the issuance of restricted stock. There were also two employee stock purchase plans, one for U.S. employees and one for Canada-based employees.
 
Over the years, the 1999 Stock Plan had been amended to increase shares available to grant, to allow for granting of restricted shares and effective January 18, 2006, had been amended to allow for the granting of restricted stock units to employees residing outside the United States. We stopped granting stock options after July 2004 and replaced option grants with grants of restricted stock and restricted stock units to fewer people and in smaller amounts. Our restricted stock and restricted stock unit grants generally had either a three-year or five-year cliff vesting.
 
For the five months ended May 31, 2007 and year ended December 31, 2006, we recognized stock option expense of $0.8 million and $5.0 million, respectively.
 
During 2006, we made restricted common stock grants to employees of 10,000 shares. These grants were valued at $1.0 million, based on the closing market price of our common stock on either the date of grant or the measurement date, if different. Restricted stock grants made to employees vest over three or five year periods. During 2006, we made restricted common stock grants to our non-employee directors of 17,600 shares. These grants were valued at $1.7 million. All of the restricted stock grants made to non-employee directors vested during a six-month period. Expense related to restricted stock grants was recognized on a straight-line basis over the respective vesting periods. During the five months ended May 31, 2007 and year ended December 31, 2006, we amortized $5.0 million and $14.9 million, respectively, related to restricted stock grants.
 
During 2006, we made restricted stock unit grants of 61,800 units. These grants were valued at $6.0 million, based on the closing market price of our common stock on either the date of grant or the measurement date, if different. During the five

 
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Item 8:   Financial Statements and Supplementary Data.  (continued)
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months ended May 31, 2007 and year ended December 31, 2006, we amortized $1.6 million and $3.4 million, respectively, related to restricted stock unit grants.
 
A summary of the status of our restricted stock and restricted stock unit plans at May 31, 2007 and December 31, 2006, and changes during the periods then ended is presented in the table below:
 
 
Predecessor Company
 
Five Months Ended
May 31, 20071
  
Year Ended
December 31, 2006
 
Shares
  
Weighted
Average
Grant Date
Fair Value
  
Shares
  
Weighted
Average
Grant Date
Fair Value
 
(Dollars in millions)
Outstanding at Beginning of Period
812,240
    
$
55.6
    
880,310
    
$
56.6
  
Granted
-
      
-
    
89,400
      
8.7
  
Reinstated
-
      
-
    
50,000
      
2.7
  
Vested
(59,117
)
    
(4.8
)
  
(193,620
)
    
(11.3
)
Forfeited
(12,016
)
    
(1.0
)
  
(13,850
)
    
(1.1
)
Outstanding at End of Period
741,107
    
$
49.8
    
812,240
    
$
55.6
  
                           
Intrinsic Value of Restricted Stock Vested During the Period
      
$
3.6
          
$
19.2
  
_____________
1
As discussed above, all remaining restricted stock at the end of the period became fully vested and was exercised upon the closing of the Going Private transaction.
 
Contingent grants totaling an additional 178,000 shares of restricted common stock and 65,650 restricted stock units were granted in July 2006. Upon the closing of the Going Private transaction, these grants were replaced with the Long-term Incentive Retention Award plan (see Note 16).
 
A summary of the status of our stock option plans at May 31, 2007 and December 31, 2006, and changes during the periods then ended is presented as follows:
 
 
Predecessor Company
 
Five Months Ended
May 31, 20071
  
Year Ended
December 31, 2006
 
Shares
  
Weighted
Average
Exercise Price
  
Shares
  
Weighted
Average
Exercise Price
Outstanding at Beginning of Period
2,604,217
    
$
46.02
    
3,421,849
    
$
45.21
  
Granted
-
    
$
-
    
-
    
$
-
  
Exercised
(160,838
)
  
$
44.67
    
(618,746
)
  
$
44.82
  
Forfeited
(35,975
)
  
$
50.10
    
(198,886
)
  
$
41.95
  
Outstanding at End of Period
2,407,404
    
$
46.06
    
2,604,217
    
$
46.02
  
                           
Exercisable at End of Period
2,183,379
    
$
44.55
    
2,310,392
    
$
44.49
  
Weighted-Average Fair Value of Options Granted
      
$
-
          
$
-
  
Aggregate Intrinsic Value of Options Exercisable at End of Period (in millions)
      
$
142.0
          
$
147.9
  
Intrinsic Value of Options Exercised During the Period (In millions)
      
$
9.9
          
$
34.1
  
Cash Received from Exercise of Options During the Period (In millions)
      
$
7.2
          
$
27.7
  
____________
1
As discussed above, all remaining stock options became fully vested and were exercised upon the closing of the Going Private transaction on May 31, 2007.
 
Beginning March 31, 2005, employees could purchase our common stock at a 5% discount, thus making the employee stock purchase plan a non-compensatory plan. Employees purchased 7,605 shares and 36,772 shares for the five months ended May 31, 2007 and year ended December 31, 2006, respectively. We also had a Foreign Subsidiary Employees Stock Purchase Plan for our employees working in Canada. This plan mirrored the Employee Stock Purchase Plan for our United States employees. Employees were eligible to participate in the program beginning April 1, 2006. Employees purchased 545 shares and 2,098 shares during the five months ended May 31, 2007 and year ended December 31, 2006.
 

 
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Kinder Morgan Energy Partners
 
Kinder Morgan Energy Partners has three common unit-based compensation plans: A common unit option plan, the Directors’ Unit Appreciation Rights Plan and the Kinder Morgan Energy Partners, L.P. Common Unit Compensation Plan.
 
The common unit option plan was established in 1998. The plan was authorized to grant up to 500,000 options to key personnel and terminated in March 2008. The options granted generally have a term of seven years, vest 40% on the first anniversary of the date of grant and 20% on each of the next three anniversaries, and have exercise prices equal to the market price of the common units at the grant date. No grants have been made under this plan since May 2000. During 2006, 4,200 options to purchase common units were cancelled or forfeited and 21,100 options to purchase common units were exercised at an average price of $19.67 per unit. The common units underlying these options had an average fair market value of $46.43 per unit. As of December 31, 2006, 2007 and 2008, there were no outstanding options under this plan.
 
The Directors’ Unit Appreciation Rights Plan was established on April 1, 2003. Pursuant to this plan, each of Kinder Morgan Management’s three non-employee directors was eligible to receive common unit appreciation rights. Upon the exercise of unit appreciation rights, Kinder Morgan Energy Partners will pay, within thirty days of the exercise date, the participant an amount of cash equal to the excess, if any, of the aggregate fair market value of the unit appreciation rights exercised as of the exercise date over the aggregate award price of the rights exercised. The fair market value of one unit appreciation right as of the exercise date will be equal to the closing price of one common unit on the New York Stock Exchange on that date. The award price of one unit appreciation right will be equal to the closing price of one common unit on the New York Stock Exchange on the date of grant. All unit appreciation rights granted vest on the six-month anniversary of the date of grant and have a ten-year term. During 2008, 10,000 unit appreciation rights were exercised by one director at an aggregate fair value of $60.32 per unit. During 2007, 7,500 unit appreciation rights were exercised by one director at an aggregate fair value of $53.00 per unit. No unit appreciation rights were exercised during 2006. As of December 31, 2008, 35,000 unit appreciation rights had been granted, vested and remained outstanding. In 2005, this plan was replaced with the Kinder Morgan Energy Partners, L.P. Common Unit Compensation Plan for Non-Employee Directors, discussed following.
 
The Kinder Morgan Energy Partners, L.P. Common Unit Compensation Plan recognizes that the compensation to be paid to each non-employee director is fixed by the Kinder Morgan Management board, generally annually, and that the compensation is expected to include an annual retainer payable in cash. Pursuant to the plan, in lieu of receiving cash compensation, each non-employee director may elect to receive common units. A non-employee director may make a new election each calendar year. The total number of common units authorized under this compensation plan is 100,000. All common units issued under this plan are subject to forfeiture restrictions that expire six months from the date of issuance. A total of 16,868 common units were issued to non-employee directors in 2006, 2007 and 2008 as a result of their elections to receive common units in lieu of cash compensation.
 
18. Commitments and Contingent Liabilities
 
Operating Leases and Purchase Obligations
 
Expenses incurred under operating leases were $84.2 million for the year ended December 31, 2008, $43.8 million for the seven months ended December 31, 2007, $32.2 million for the five months ended May 31, 2007 and $53.5 million in 2006, of which $0.1 million in the seven months ended December 31, 2007, $1.2 million in the five months ended May 31, 2007 and $3.1 million in 2006 were associated with our discontinued operations. Future minimum commitments under major operating leases as of December 31, 2008 are as follows:
 
Year
  
Operating Leases
 
(In millions)
2009
$
57.5
  
2010
  
54.5
  
2011
  
48.9
  
2012
  
44.8
  
2013
  
40.6
  
Thereafter
  
418.4
  
Total
$
664.7
  

We have not reduced our total minimum payments for future minimum sublease rentals, aggregating approximately $5.2 million. The remaining terms on our operating leases range from one to 61 years.
 
Guarantee
 
As a result of our December 1999 sale of assets to ONEOK, Inc., ONEOK, Inc. became primarily obligated for the lease of the Bushton gas processing facility. We remain secondarily liable for the lease, which had a remaining minimum obligation of
 

 
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approximately $78.8 million at December 31, 2008, with remaining payments that average approximately $26.3 million per year through 2011.
 
Capital Expenditures Budget
 
Approximately $581.0 million of our consolidated capital expenditure budget for 2009 had been committed for the purchase of plant and equipment at December 31, 2008.
 
Commitments for Incremental Investment
 
We could be obligated (i) based on operational performance of the equipment at the Jackson, Michigan power generation facility to invest up to an additional $3 to $8 million per year for the next 10 years and (ii) based on cash flows generated by the facility, to invest up to an additional $25 million beginning in 2018, in each case in the form of an incremental preferred interest.
 
Contingent Debt
 
Cortez Pipeline Company Debt. Pursuant to a certain Throughput and Deficiency Agreement, the partners of Cortez Pipeline Company (Kinder Morgan CO2 Company, L.P. – 50% partner; a subsidiary of Exxon Mobil Corporation – 37% partner; and Cortez Vickers Pipeline Company – 13% partner) are required, on a several, proportional percentage ownership basis, to contribute capital to Cortez Pipeline Company in the event of a cash deficiency. Furthermore, due to Kinder Morgan Energy Partners’ indirect ownership of Cortez Pipeline Company through Kinder Morgan CO2 Company, L.P., Kinder Morgan Energy Partners severally guarantees 50% of the debt of Cortez Capital Corporation, a wholly owned subsidiary of Cortez Pipeline Company.
 
As of December 31, 2008, the debt facilities of Cortez Capital Corporation consisted of (i) $53.6 million of Series D notes due May 15, 2013; (ii) a $125 million short-term commercial paper program; and (iii) a $125 million five-year committed revolving credit facility due December 22, 2009 (to support the above-mentioned $125 million commercial paper program). As of December 31, 2008, Cortez Capital Corporation had outstanding borrowings of $116.0 million under its five-year credit facility. The average interest rate on the Series D notes was 7.14% in 2008.
 
In October 2008, Standard & Poor’s Rating Services lowered Cortez Capital Corporation’s short-term credit rating to A-3 from A-2. As a result of this revision and current commercial paper market conditions, Cortez Capital Corporation is unable to access commercial paper borrowings; however, Kinder Morgan Energy Partners expects that its financing and liquidity needs will continue to be met through borrowings made under its long-term bank credit facility.
 
With respect to Cortez Capital Corporation’s Series D notes, Shell Oil Company shares Kinder Morgan Energy Partners’ several guaranty obligations jointly and severally; however, Kinder Morgan Energy Partners is obligated to indemnify Shell for liabilities it incurs in connection with such guaranty. Kinder Morgan Energy Partners has an outstanding letter of credit issued by JP Morgan Chase in the amount of $26.8 million to secure Kinder Morgan Energy Partners’ indemnification obligations to Shell for 50% of the $53.6 million in principal amount of Series D notes outstanding as of December 31, 2008.
 
Nassau County, Florida Ocean Highway and Port Authority Debt – Kinder Morgan Energy Partners has posted a letter of credit as security for borrowings under Adjustable Demand Revenue Bonds issued by the Nassau County, Florida Ocean Highway and Port Authority. The bonds were issued for the purpose of constructing certain port improvements located in Fernandino Beach, Nassau County, Florida, where Kinder Morgan Energy Partners’ subsidiary, Nassau Terminals LLC, is the operator of the marine port facilities. The bond indenture is for 30 years and allows the bonds to remain outstanding until December 1, 2020. Principal payments on the bonds are made on the first of December each year and corresponding reductions are made to the letter of credit.
 
In October 2008, pursuant to the standby purchase agreement provisions contained in the bond indenture—which require the sellers of those guarantees to buy the debt back—certain investors elected to put (sell) back their bonds at par plus accrued interest. A total principal and interest amount of $11.8 million was tendered and drawn against Kinder Morgan Energy Partners’ letter of credit and accordingly, Kinder Morgan Energy Partners paid this amount pursuant to the letter of credit reimbursement provisions. This payment reduced the face amount of Kinder Morgan Energy Partners’ letter of credit from $22.5 million to $10.7 million. However, the bonds were subsequently resold and as of December 31, 2008, Kinder Morgan Energy Partners was fully reimbursed for the prior letter of credit payments. As of December 31, 2008, this letter of credit had a face amount of $10.2 million.
 
Rockies Express Pipeline LLC Debt – Pursuant to certain guaranty agreements, all three member owners of West2East Pipeline LLC (which owns all of the member interests in Rockies Express Pipeline LLC) have agreed to guarantee, severally in the same proportion as their percentage ownership of the member interests in West2East Pipeline LLC, borrowings under Rockies Express Pipeline LLC’s (i) $2.0 billion five-year, unsecured revolving credit facility due April 28, 2011; (ii) $2.0 billion commercial paper program; and (iii) $600 million in principal amount of floating rate senior notes due August 20,
 

 
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2009. The three member owners and their respective ownership interests consist of the following: Kinder Morgan Energy Partners’ subsidiary Kinder Morgan W2E Pipeline LLC – 51%, a subsidiary of Sempra Energy – 25%, and a subsidiary of ConocoPhillips – 24%.
 
Borrowings under the Rockies Express Pipeline LLC commercial paper program and/or its credit facility are primarily used to finance the construction of the Rockies Express interstate natural gas pipeline and to pay related expenses. The credit facility, which can be amended to allow for borrowings up to $2.5 billion, supports borrowings under the commercial paper program, and borrowings under the commercial paper program reduce the borrowings allowed under the credit facility. The $600 million in principal amount of senior notes were issued on September 20, 2007. The notes are unsecured and are not redeemable prior to maturity. Interest on the notes is paid and computed quarterly at an interest rate of three-month LIBOR (with a floor of 4.25%) plus a spread of 0.85%.
 
Upon issuance of the notes, Rockies Express Pipeline LLC entered into two floating-to-fixed interest rate swap agreements having a combined notional principal amount of $600 million and maturity dates of August 20, 2009. On September 24, 2008, Rockies Express Pipeline LLC terminated one of the aforementioned interest rate swaps that had Lehman Brothers as the counterparty. The notional principal amount of the terminated swap agreement was $300 million. The remaining interest rate swap agreement effectively converts the interest expense associated with $300 million of these senior notes from its stated variable rate to a fixed rate of 5.47%.
 
In October 2008, Standard & Poor’s lowered Rockies Express Pipeline LLC’s short-term credit rating to A-3 from A-2. As a result of this revision and current commercial paper market conditions, Rockies Express Pipeline LLC is unable to access commercial paper borrowings, and as of December 31, 2008, there were no borrowings under its commercial paper program. However, Rockies Express Pipeline LLC expects that its financing and liquidity needs will continue to be met through borrowings made under its long-term bank credit facility and contributions by its equity investors.
 
As of December 31, 2008, in addition to the $600 million in floating rate senior notes, Rockies Express Pipeline LLC had outstanding borrowings of $1,561.0 million under its five-year credit facility. Accordingly, as of December 31, 2008, Kinder Morgan Energy Partners’ contingent share of Rockies Express Pipeline LLC’s debt was $1,102.1 million (51% of total guaranteed borrowings). In addition, there is a letter of credit outstanding to support the construction of the Rockies Express pipeline. As of December 31, 2008, this letter of credit, issued by JPMorgan Chase, had a face amount of $31.4 million. Kinder Morgan Energy Partners’ contingent responsibility with regard to this outstanding letter of credit was $16.0 million (51% of the total face amount).
 
One of the Lehman entities was a lending bank with an approximate $41 million commitment to the Rockies Express Pipeline LLC $2.0 billion credit facility. The credit facility has been reduced by this amount. The commitments of the other banks remain unchanged and the facility is not defaulted.
 
Midcontinent Express Pipeline LLC Debt – Pursuant to certain guaranty agreements, each of the two member owners of Midcontinent Express Pipeline LLC have agreed to guarantee, severally in the same proportion as their percentage ownership of the member interests in Midcontinent Express Pipeline LLC, borrowings under Midcontinent Express Pipeline LLC’s $1.4 billion three-year, unsecured revolving credit facility, entered into on February 29, 2008 and due February 28, 2011. The facility is with a syndicate of financial institutions with The Royal Bank of Scotland plc as the administrative agent. Borrowings under the credit agreement will be used to finance the construction of the Midcontinent Express Pipeline and to pay related expenses. One of the Lehman entities was a lending bank with an approximately $100 million commitment to the Midcontinent Express $1.4 billion credit facility. Since declaring bankruptcy, Lehman has not met its obligations to lend under the credit facility and our credit facility has effectively been reduced by its commitment. The commitments of the other banks remain unchanged and the facility is not defaulted.
 
Midcontinent Express Pipeline LLC is an equity method investee of Kinder Morgan Energy Partners, and the two member owners and their respective ownership interests consist of the following: Kinder Morgan Energy Partners’ subsidiary Kinder Morgan Operating L.P. “A” – 50%, and Energy Transfer Partners, L.P. – 50%. As of December 31, 2008, Midcontinent Express Pipeline LLC had $837.5 million borrowed under its three-year credit facility. Accordingly, as of December 31, 2008, Kinder Morgan Energy Partners’ contingent share of Midcontinent Express Pipeline LLC’s debt was $418.8 million (50% of total borrowings). Furthermore, the revolving credit facility can be used for the issuance of letters of credit to support the construction of the Midcontinent Express Pipeline LLC, and as of December 31, 2008, a letter of credit having a face amount of $33.3 million was issued under the credit facility. Accordingly, as of December 31, 2008, Kinder Morgan Energy Partners’ contingent responsibility with regard to this outstanding letter of credit was $16.7 million (50% of total face amount).
 
Standby Letters of Credit
 
Letters of credit totaling $405.8 outstanding as of December 31, 2008 consisted of the following: (i) a $100.0 million letter of credit that supports certain proceedings with the California Public Utilities Commission involving refined products tariff charges on the intrastate common carrier operations of Kinder Morgan Energy Partners’ West Coast Products Pipelines in the state of California; (ii) a $55.9 million letter of credit supporting Kinder Morgan Energy Partners’ pipeline and terminal
 

 
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Item 8:   Financial Statements and Supplementary Data.  (continued)
Knight Form 10-K


operations in Canada; (iii) a combined $40.0 million in two letters of credit supporting Kinder Morgan Energy Partners’ hedging of energy commodity price risks; (iv) Kinder Morgan Energy Partners’ $30.3 million guarantee under letters of credit totaling $45.5 million supporting our International Marine Terminals Partnership Plaquemines, Louisiana Port, Harbor, and Terminal Revenue Bonds; (v) a $26.8 million letter of credit supporting Kinder Morgan Energy Partners’ indemnification obligations on the Series D note borrowings of Cortez Capital Corporation; (vi) four letters of credit totaling $25.8 million, required under provisions of our property and casualty, worker’s compensation and general liability insurance policies; (vii) a $25.4 million letter of credit supporting Kinder Morgan Energy Partners’ Kinder Morgan Liquids Terminals LLC New Jersey Economic Development Revenue Bonds; (viii) two letters of credit totaling $20.3 million supporting the subordination of operating fees payable to us for operation of the Jackson, Michigan power generation facility to payments due under the operating lease of the facilities; (ix) a $18.0 million letter of credit supporting Kinder Morgan Energy Partners’ Kinder Morgan Operating L.P. “B” tax-exempt bonds; (x) a combined $17.2 million in eight letters of credit supporting environmental and other obligations of Kinder Morgan Energy Partners and its subsidiaries; (xi) a $15.3 million letter of credit to fund the Debt Service Reserve Account required under Kinder Morgan Energy Partners’ Express pipeline system’s trust indenture; (xii) a $10.2 million letter of credit supporting Nassau County, Florida Ocean Highway and Port Authority tax-exempt bonds; and (xiii), a $5.4 million letter of credit supporting Kinder Morgan Energy Partners’ Arrow Terminals, L.P. Illinois Development Revenue Bonds.
 
19. Business Segment Information
 
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:
 
 
·
Natural Gas Pipeline Company of America—after February 15, 2008, this segment consists of our 20% interest in NGPL PipeCo LLC, the owner of Natural Gas Pipeline Company of America and certain affiliates, collectively referred to as Natural Gas Pipeline Company of America or NGPL, a major interstate natural gas pipeline and storage system which we operate;
 
·
Power—which consists of two natural gas-fired electric generation facilities;
 
·
Products Pipelines–KMP—which consists of approximately 8,300 miles of refined petroleum products pipelines that deliver gasoline, diesel fuel, jet fuel and natural gas liquids to various markets; plus approximately 60 associated product terminals and petroleum pipeline transmix processing facilities serving customers across the United States;
 
·
Natural Gas Pipelines–KMP—which consists of over 14,300 miles of natural gas transmission pipelines and gathering lines, plus natural gas storage, treating and processing facilities, through which natural gas is gathered, transported, stored, treated, processed and sold;
 
·
CO2–KMP—which produces, markets and transports, through approximately 1,300 miles of pipelines, carbon dioxide to oil fields that use carbon dioxide to increase production of oil; owns interests in and/or operates ten oil fields in West Texas; and owns and operates a 450-mile crude oil pipeline system in West Texas;
 
·
Terminals–KMP—which consists of approximately 110 owned or operated liquids and bulk terminal facilities and more than 45 rail transloading and materials handling facilities located throughout the United States and portions of Canada, which together transload, store and deliver a wide variety of bulk, petroleum, petrochemical and other liquids products for customers across the United States and Canada; and
 
·
Kinder Morgan Canada–KMP—which consists of over 700 miles of common carrier pipelines, originating at Edmonton, Alberta, for the transportation of crude oil and refined petroleum to the interior of British Columbia and to marketing terminals and refineries located in the greater Vancouver, British Columbia area and Puget Sound in Washington State; plus five associated product terminals. This segment also includes a one-third interest in an approximately 1,700-mile integrated crude oil pipeline and a 25-mile aviation turbine fuel pipeline serving the Vancouver International Airport.
 
On August 28, 2008, we sold our one-third interest in the net assets of the Express pipeline system (“Express”), as well as our full ownership of the net assets of the Jet Fuel pipeline system (“Jet Fuel”), to Kinder Morgan Energy Partners. We accounted for this transaction as a transfer of net assets between entities under common control. Therefore, following our sale of Express and Jet Fuel to Kinder Morgan Energy Partners, Kinder Morgan Energy Partners recognized the assets and liabilities acquired at our carrying amounts (historical cost) at the date of transfer. The results of Express and Jet Fuel are now reported in the segment referred to as Kinder Morgan Canada–KMP. Previously, we reported the results of the equity investment in Express pipeline system in the Express segment and the results of Jet Fuel in the “Other” caption in the following tables.
 
On February 15, 2008, we sold an 80% ownership interest in our NGPL business segment to Myria (see Note 10). We continue to operate NGPL’s assets pursuant to a 15-year operating agreement. Effective February 15, 2008, we began to account for the results of operations of the NGPL segment as an equity investment.
 
In November 2007, we signed a definitive agreement to sell our interests in three natural gas-fired power plants in Colorado to Bear Stearns. The sale was effective January 1, 2008.
 

 
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Item 8:   Financial Statements and Supplementary Data.  (continued)
Knight Form 10-K


On October 5, 2007, Kinder Morgan Energy Partners announced that it had completed the sale of the North System and also its 50% ownership interest in the Heartland Pipeline Company to ONEOK Partners, L.P. for approximately $295.7 million in cash. Prior to its sale, the North System and the equity investment in the Heartland Pipeline were reported in the Products Pipelines–KMP business segment.
 
On April 30, 2007, we sold the Trans Mountain pipeline system to Kinder Morgan Energy Partners for approximately $550 million. The transaction was approved by the independent members of our board of directors and those of Kinder Morgan Management following the receipt, by each board, of separate fairness opinions from different investment banks. Due to the inclusion of Kinder Morgan Energy Partners and its subsidiaries in our consolidated financial statements, we accounted for this transaction as a transfer of net assets between entities under common control, Kinder Morgan Energy Partners recognized the Trans Mountain assets and liabilities acquired at our carrying amounts (historical cost) at the date of transfer. As discussed in Note 3, based on an evaluation of the fair value of the Trans Mountain pipeline system, a goodwill impairment charge of approximately $377.1 million was recorded in 2007. The results of Trans Mountain are now reported in the segment referred to as Kinder Morgan Canada–KMP. In prior filings, the Trans Mountain pipeline system was reported in the Trans Mountain–KMP business segment.
 
In March 2007, we completed the sale of our U.S. retail natural gas distribution and related operations to GE Energy Financial Services, a subsidiary of General Electric Company, and Alinda Investments LLC. Prior to its sale, we referred to these operations as the Kinder Morgan Retail business segment.
 
On March 5, 2007, we entered into a definitive agreement to sell Terasen Pipelines (Corridor) Inc. to Inter Pipeline Fund, a Canada-based company. This transaction closed on June 15, 2007 (see Note 11).
 
In February 2007, we entered into a definitive agreement, which closed on May 17, 2007 (see Note 11) to sell Terasen Inc. to Fortis, Inc., a Canada-based company with investments in regulated distribution utilities. Execution of this sale agreement constituted a subsequent event of the type that, under GAAP, required us to consider the market value indicated by the definitive sales agreement in our 2006 goodwill impairment evaluation. Accordingly, based on the fair values of these reporting unit(s) derived principally from this definitive sales agreement, an estimated goodwill impairment charge of approximately $650.5 million was recorded in 2006.
 
The financial results of Terasen Gas, Corridor, Kinder Morgan Retail, the North System and the equity investment in the Heartland Pipeline Company have been reclassified to discontinued operations for all periods presented. See Note 11 for additional information regarding discontinued operations.
 
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, 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, (ii) equity in earnings of equity method investees are included in segment earnings (these equity method earnings are included in “Other Income and (Expenses)” in the accompanying Consolidated Statements of Operations), (iii) certain items included in operating income (such as general and administrative expenses and depreciation, depletion and amortization (“DD&A”)) are not considered by management in its evaluation of business segment performance and, thus, are not included in reported performance measures, (iv) gains and losses from incidental sales of assets are included in segment earnings and (v) our business segments that are also segments of Kinder Morgan Energy Partners include certain other income and expenses and income taxes in their segment earnings. With adjustment for these items, we currently evaluate business segment performance primarily based on segment earnings before DD&A (sometimes referred to in this report as EBDA) in relation to the level of capital employed. Beginning in 2007, the segment earnings measure was changed from segment earnings to segment earnings before DD&A for segments not also segments of Kinder Morgan Energy Partners. This change was made to conform our disclosure to the internal reporting we use as a result of the Going Private transaction.
 
This segment measure change has been reflected in the prior periods shown in this document in order to achieve comparability. Because Kinder Morgan Energy Partners’ partnership agreement requires it to distribute 100% of its available cash to its partners on a quarterly basis (Kinder Morgan Energy Partners’ available cash consists primarily of all of its cash receipts, less cash disbursements and changes in reserves), we consider each period’s earnings before all non-cash depreciation, depletion and amortization expenses to be an important measure of business segment performance for our segments that are also segments of Kinder Morgan Energy Partners. We account for intersegment sales at market prices, while we account for asset transfers at either market value or, in some instances, book value.
 
During 2008, 2007 and 2006, we did not have revenues from any single customer that exceeded 10% of our consolidated operating revenues.
 

 
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Item 8:   Financial Statements and Supplementary Data.  (continued)
Knight Form 10-K


Financial information by segment follows (in millions):
 
 
Successor Company
    
Predecessor Company
 
Year Ended
December 31,
2008
  
Seven Months Ended
December 31,
2007
    
Five Months Ended
May 31,
2007
  
Year Ended
December 31,
2006
Segment Earnings (Loss) before Depreciation, Depletion, Amortization and Amortization of Excess Cost of Equity Investments
                                
NGPL1
$
129.8
    
$
422.8
      
$
267.4
    
$
603.5
  
Power
  
5.7
      
13.4
        
8.9
      
23.2
  
Products Pipelines–KMP2,3
  
(722.0
)
    
162.5
        
224.4
      
467.9
  
Natural Gas Pipelines–KMP2,3
  
(1,344.3
)
    
373.3
        
228.5
      
574.8
  
CO2–KMP2
  
896.1
      
433.0
        
210.0
      
488.2
  
Terminals–KMP2,3
  
(156.5
)
    
243.7
        
172.3
      
408.1
  
Kinder Morgan Canada–KMP2,4
  
152.0
      
58.8
        
(332.0
)
    
95.1
  
Total Segment Earnings (Loss) Before DD&A
  
(1,039.2
)
    
1,707.5
        
779.5
      
2,660.8
  
Depreciation, Depletion and Amortization
  
(918.4
)
    
(472.3
)
      
(261.0
)
    
(531.4
)
Amortization of Excess Cost of Equity Investments
  
(5.7
)
    
(3.4
)
      
(2.4
)
    
(5.6
)
Other Operating Income (Loss)
  
39.0
      
(0.3
)
      
2.9
      
6.8
  
General and Administrative Expenses
  
(352.5
)
    
(175.6
)
      
(283.6
)
    
(305.1
)
Interest and Other, Net5,6
  
(1,019.7
)
    
(624.0
)
      
(348.2
)
    
(968.2
)
Add Back Income Tax Expense Included in Segments Above2
  
2.4
      
44.0
        
15.6
      
29.0
  
Income (Loss) from Continuing Operations Before Income Taxes
$
(3,294.1
)
  
$
475.9
      
$
(97.2
)
  
$
886.3
  

  
 
Successor Company
    
Predecessor Company
 
Year Ended
December 31,
2008
  
Seven Months
Ended
December 31,
2007
    
Five Months
Ended
May 31,
2007
  
Year Ended
December 31,
2006
Revenues from External Customers
                                
NGPL1
$
132.1
    
$
752.4
      
$
424.5
    
$
1,114.4
  
Power
  
44.0
      
40.2
        
19.9
      
60.0
  
Products Pipelines–KMP
  
815.9
      
471.5
        
331.8
      
732.5
  
Natural Gas Pipelines–KMP
  
8,422.0
      
3,825.9
        
2,637.6
      
6,558.4
  
CO2–KMP
  
1,269.2
      
605.9
        
324.2
      
736.5
  
Terminals–KMP
  
1,172.7
      
598.8
        
364.2
      
864.1
  
Kinder Morgan Canada–KMP
  
198.9
      
100.0
        
62.9
      
140.8
  
Other
  
40.0
      
-
        
-
      
1.9
  
Total Revenues
$
12,094.8
    
$
6,394.7
      
$
4,165.1
    
$
10,208.6
  
  
 
Successor Company
    
Predecessor Company
 
Year Ended
December 31,
2008
  
Seven Months
Ended
December 31,
2007
    
Five Months
Ended
May 31,
2007
  
Year Ended
December 31,
2006
Intersegment Revenues
                                
NGPL1
$
0.9
    
$
4.8
      
$
2.0
    
$
3.6
  
Natural Gas Pipelines–KMP
  
-
      
-
        
3.0
      
19.3
  
Terminals–KMP
  
0.9
      
0.4
        
0.3
      
0.7
  
Other
  
(0.9
)
    
-
        
-
      
-
  
Total Intersegment Revenues
$
0.9
    
$
5.2
      
$
5.3
    
$
23.6
  
 

 
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Item 8:   Financial Statements and Supplementary Data.  (continued)
Knight Form 10-K



 
Successor Company
    
Predecessor Company
 
Year Ended
December 31,
2008
  
Seven Months
Ended
December 31,
2007
    
Five Months
Ended
May 31,
2007
  
Year Ended
December 31,
2006
Depreciation, Depletion and Amortization
                                
NGPL1
$
9.3
    
$
42.3
      
$
45.3
    
$
104.5
  
Power
  
-
      
0.2
        
(4.2
)
    
2.1
  
Products Pipelines–KMP
  
116.9
      
58.1
        
33.6
      
74.0
  
Natural Gas Pipelines–KMP
  
99.9
      
52.3
        
26.8
      
65.4
  
CO2–KMP
  
498.1
      
243.5
        
116.3
      
190.9
  
Terminals–KMP
  
157.4
      
62.1
        
34.4
      
74.6
  
Kinder Morgan Canada–KMP
  
36.7
      
13.5
        
8.2
      
19.4
  
Other
  
0.1
      
0.3
        
0.6
      
0.5
  
Total Consolidated Depreciation, Depletion and Amortization
$
918.4
    
$
472.3
      
$
261.0
    
$
531.4
  
  
 
Successor Company
    
Predecessor Company
 
Year Ended
December 31,
2008
  
Seven Months
Ended
December 31,
2007
    
Five Months
Ended
May 31,
2007
  
Year Ended
December 31,
2006
Capital Expenditures
                                
NGPL1
$
10.3
    
$
152.0
      
$
77.3
    
$
193.4
  
Power
  
-
      
-
        
-
      
-
  
Products Pipelines–KMP
  
221.7
      
179.9
        
79.5
      
196.0
  
Natural Gas Pipelines–KMP
  
946.5
      
197.4
        
66.6
      
271.6
  
CO2–KMP
  
542.6
      
249.2
        
133.3
      
283.0
  
Terminals–KMP
  
454.1
      
310.1
        
169.9
      
307.7
  
Kinder Morgan Canada–KMP
  
368.1
      
196.7
        
109.0
      
123.8
  
Other
  
2.0
      
1.7
        
17.2
      
0.1
  
Total Consolidated Capital Expenditures
$
2,545.3
    
$
1,287.0
      
$
652.8
    
$
1,375.6
  
  
 
Successor Company
    
Predecessor
Company
 
2008
  
2007
    
2006
Assets at December 31
                        
NGPL1
$
717.3
    
$
720.0
      
$
5,728.9
  
Power
  
58.9
      
120.6
        
387.4
  
Products Pipelines–KMP
  
5,526.4
      
6,941.4
        
4,812.9
  
Natural Gas Pipelines–KMP
  
7,748.1
      
8,439.8
        
3,796.6
  
CO2–KMP
  
4,478.7
      
3,919.2
        
1,875.6
  
Terminals–KMP
  
4,327.8
      
4,643.3
        
2,564.1
  
Kinder Morgan Canada–KMP
  
1,583.9
      
1,888.3
        
2,555.1
  
Total segment assets
  
24,441.1
      
26,672.6
        
21,720.6
  
Assets Held for Sale
  
-
      
8,987.9
        
510.2
  
Other7
  
1,003.8
      
440.5
        
4,564.8
  
Total Consolidated Assets
$
25,444.9
    
$
36,101.0
      
$
26,795.6
  
___________
1
Effective February 15, 2008, we sold an 80% ownership interest in NGPL PipeCo LLC to Myria. As a result of the sale, beginning February 15, 2008, we account for our 20% ownership interest in NGPL PipeCo LLC as an equity method investment and 100% of NGPL revenues, earnings and assets prior to the sale, are included in the above tables.
2
Kinder Morgan Energy Partners’ income taxes expenses for the year ended December 31, 2008, seven months ended December 31, 2007, five months ended May 31, 2007 and year ended December 31, 2006 were $2.4 million, $44.0 million, $15.6 million and $29.0 million, respectively, and are included in segment earnings.
3
2008 includes non-cash goodwill impairment charges (see Note 3).
4
Five months ended May 31, 2007 includes a non-cash goodwill impairment charge (see Note 3).
5
Includes (i) interest expense, (ii) minority interests and (iii) miscellaneous other income and expenses not allocated to business segments.
6
Results for 2006 include a reduction in pre-tax income of $22.3 million ($14.1 million after tax) resulting from non-cash charges to mark to market certain interest rate swaps
7
Includes assets of discontinued operations, cash, restricted deposits, market value of derivative instruments (including interest rate swaps) and miscellaneous corporate assets (such as information technology and telecommunications equipment) not allocated to individual segments.
 

 
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Item 8:   Financial Statements and Supplementary Data.  (continued)
Knight Form 10-K


Geographic Information
 
Prior to 2005, all but an insignificant amount of our assets and operations were located in the continental United States. Upon our acquisition of Terasen on November 30, 2005, we obtained significant assets and operations in Canada. However, that percent has declined in 2007 relative to 2006 with the sale of two significant portions of our Canadian assets during the year. Following is geographic information regarding the revenues and long-lived assets of our business segments (in millions).
 
 
Successor Company
    
Predecessor Company
 
Year Ended
December 31,
2008
  
Seven Months
Ended
December 31,
2007
    
Five Months
Ended
May 31,
2007
  
Year Ended
December 31,
2006
Revenues from External Customers
                                
United States
$
11,804.2
    
$
6,239.7
      
$
4,086.6
    
$
10,045.9
  
Canada
  
269.3
      
143.5
        
70.5
      
143.2
  
Mexico and the Netherlands
  
21.3
      
11.5
        
8.0
      
19.5
  
Total Consolidated Revenues from External Customers
$
12,094.8
    
$
6,394.7
      
$
4,165.1
    
$
10,208.6
  
  
 
Successor Company
    
Predecessor
Company
 
2008
  
2007
    
2006
Long-lived Assets at December 311
                        
United States
$
17,511.1
    
$
16,051.9
      
$
16,779.7
  
Canada
  
1,568.7
      
1,565.8
        
4,605.8
  
Mexico and the Netherlands
  
97.7
      
88.2
        
117.0
  
Total Consolidated Long-lived Assets
$
19,177.5
    
$
17,705.9
      
$
21,502.5
  
____________
1
Long-lived assets exclude goodwill and other intangibles, net.
 
20.  Regulatory Matters
 
The tariffs we charge for transportation on our interstate common carrier pipelines are subject to rate regulation by the FERC, under the Interstate Commerce Act. The Interstate Commerce Act requires, among other things, that interstate petroleum products pipeline rates be just and reasonable and nondiscriminatory. Pursuant to FERC Order No. 561, effective January 1, 1995, interstate petroleum products pipelines are able to change their rates within prescribed ceiling levels that are tied to an inflation index. FERC Order No. 561-A, affirming and clarifying Order No. 561, expanded the circumstances under which interstate petroleum products pipelines may employ cost-of-service ratemaking in lieu of the indexing methodology, effective January 1, 1995. For each of the years ended December 31, 2008, 2007 and 2006, the application of the indexing methodology did not significantly affect tariff rates on our interstate petroleum products pipelines.
 
Below is a brief description of our ongoing regulatory matters, including any material developments that occurred during 2008. This note also contains a description of any material regulatory matters initiated during 2008 in which we are involved.
 
FERC Order No. 2004/717
 
Since November 2003, the FERC issued Orders No. 2004, 2004-A, 2004-B, 2004-C and 2004-D, adopting new Standards of Conduct as applied to natural gas pipelines. The primary change from existing regulation was to make such standards applicable to an interstate natural gas pipeline’s interaction with many more affiliates (referred to as “energy affiliates”). The Standards of Conduct require, among other things, separate staffing of interstate pipelines and their energy affiliates (but 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.
 
However, on November 17, 2006, the United States Court of Appeals for the District of Columbia Circuit, in Docket No. 04-1183, vacated FERC Orders 2004, 2004-A, 2004-B, 2004-C and 2004-D as applied to natural gas pipelines, and remanded these same orders back to the FERC.
 
On October 16, 2008, the FERC issued a Final Rule in Order 717 revising the FERC Standards of Conduct for natural gas and electric transmission providers by eliminating Order No. 2004’s concept of Energy Affiliates and corporate separation in favor of an employee functional approach as used in Order No. 497. A transmission provider is prohibited from disclosing to a marketing function employee non-public information about the transmission system or a transmission customer. The final rule also retains the long-standing no-conduit rule, which prohibits a transmission function provider from disclosing non-public information to marketing function employees by using a third party conduit. Additionally, the final rule requires that a transmission provider provide annual training on the Standards of Conduct to all transmission function employees, marketing function employees, officers, directors, supervisory employees, and any other employees likely to become privy to
 

 
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transmission function information. This rule became effective on November 26, 2008.
 
Notice of Inquiry – Financial Reporting
 
On February 15, 2007, the FERC issued a notice of inquiry seeking comment on the need for changes or revisions to the FERC’s reporting requirements contained in the financial forms for gas and oil pipelines and electric utilities. Initial comments were filed by numerous parties on March 27, 2007, and reply comments were filed on April 27, 2007.
 
On September 20, 2007, the FERC issued for public comment in Docket No. RM07-9 a proposed rule that would revise its financial forms to require that additional information be reported by natural gas companies. The proposed rule would require, among other things, that natural gas companies (i) submit additional revenue information, including revenue from shipper-supplied gas, (ii) identify the costs associated with affiliate transactions and (iii) provide additional information on incremental facilities and on discounted and negotiated rates. The FERC proposed an effective date of January 1, 2008, which means that forms reflecting the new requirements for 2008 would be filed in early 2009. Comments on the proposed rule were filed by numerous parties on November 13, 2007.
 
On March 21, 2008, the FERC issued a Final Rule regarding changes to the Form 2, 2-A and 3Q. The revisions were designed to enhance the forms’ usefulness by updating them to reflect current market and cost information relevant to interstate pipelines and their customers. The rule is effective January 1, 2008 with the filing of the revised Form 3-Q beginning with the first quarter of 2009. The revised Form 2 and 2-A for calendar year 2008 material would be filed by April 18, 2009. On June 20, 2008, the FERC issued an Order Granting in Part and Denying in Part Rehearing and Granting Request for Clarification. No substantive changes were made to the March 21, 2008 Final Rule.
 
Notice of Inquiry – Fuel Retention Practices
 
On September 20, 2007, the FERC issued a Notice of Inquiry seeking comment on whether it should change its current policy and prescribe a uniform method for all interstate gas pipelines to use in recovering fuel gas and gas lost and unaccounted for. The Notice of Inquiry included numerous questions regarding fuel recovery issues and the effects of fixed fuel percentages as compared with tracking provisions. Comments on the Notice of Inquiry were filed by numerous parties on November 30, 2007. On November 20, 2008, the FERC issued an order terminating the inquiry.
 
Notice of Proposed Rulemaking – Promotion of a More Efficient Capacity Release Market-Order 712
 
On November 15, 2007, the FERC issued a notice of proposed rulemaking in Docket No. RM 08-1-000 regarding proposed modifications to its Part 284 regulations concerning the release of firm capacity by shippers on interstate natural gas pipelines. The FERC proposes to remove, on a permanent basis, the rate ceiling on capacity release transactions of one year or less. Additionally, the FERC proposes to exempt capacity releases made as part of an asset management arrangement from the prohibition on tying and from the bidding requirements of Section 284.8. Initial comments were filed by numerous parties on January 25, 2008. On June 19, 2008, the FERC issued a final rule in Order 712 regarding changes to the capacity release program. The FERC permitted market based pricing for short-term capacity releases of a year or less. Long-term capacity releases and a pipeline’s sale of its own capacity remain subject to a price cap. The ruling would facilitate asset management arrangements by relaxing the FERC’s prohibitions on tying and on its bidding requirements for certain capacity releases. The FERC further clarified that its prohibition on tying does not apply to conditions associated with gas inventory held in storage for releases for firm storage capacity. Finally, the FERC waived the prohibition on tying and bidding requirements for capacity releases made as part of state-approved retail open access programs. The final rule became effective on July 30, 2008.
 
On November 20, 2008, the FERC issued an order generally denying requests for rehearing and/or clarification that had been filed. The FERC reaffirmed its final rule, Order 712, and denied requests for rehearing stating the removal of the rate ceiling for short-term capacity release transactions is designed to extend to capacity release transactions, the pricing flexibility already available to pipelines through negotiated rates without compromising the fundamental protection provided by the availability of recourse rate service. Additionally, the FERC clarified several areas of the rule as it relates to asset management arrangements.
 
Notice of Proposed Rulemaking – Natural Gas Price Transparency
 
On April 19, 2007, the FERC issued a notice of proposed rulemaking in Docket Nos. RM07-10-000 and AD06-11-000 regarding price transparency provisions of Section 23 of the Natural Gas Act and the Energy Policy Act. In the notice, the FERC proposed to revise its regulations to (i) require that intrastate pipelines post daily the capacities of, and volumes flowing through, their major receipt and delivery points and mainline segments in order to make available the information to track daily flows of natural gas throughout the United States; and (ii) require that buyers and sellers of more than a de minimis volume of natural gas report annual numbers and volumes of relevant transactions to the FERC in order to make possible an estimate of the size of the physical U.S. natural gas market, assess the importance of the use of index pricing in that market and determine the size of the fixed-price trading market that produces the information. The FERC believes these revisions to
 

 
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its regulations will facilitate price transparency in markets for the sale or transportation of physical natural gas in interstate commerce. Initial comments were filed on July 11, 2007 and reply comments were filed on August 23, 2007. In addition, the FERC conducted an informal workshop in this proceeding on July 24, 2007, to discuss implementation and other technical issues associated with the proposals set forth in the notice of proposed rulemaking.
 
In addition, on December 21, 2007, the FERC issued a new notice of proposed rulemaking in Docket No. RM08-2-000 regarding the daily posting provisions that were contained in Docket Nos. RM07-10-000 and AD06-11-000. The new notice of proposed rulemaking proposes to exempt from the daily posting requirements those non-interstate pipelines that (i) flow less than ten million MMBtus of natural gas per year, (ii) fall entirely upstream of a processing plant and (iii) deliver more than ninety-five percent (95%) of the natural gas volumes they flow directly to end-users. However, the new notice of proposed rulemaking expands the proposal to require that both interstate and non-exempt non-interstate pipelines post daily the capacities of, volumes scheduled at, and actual volumes flowing through, their major receipt and delivery points and mainline segments. Initial comments were filed by numerous parties on March 13, 2008. A Technical Conference was held on April 3, 2008. Numerous reply comments were received on April 14, 2008.
 
On December 26, 2007, the FERC issued Order No. 704 in this docket implementing only the annual reporting provisions of the notice of proposed rulemaking with minimal changes to the original proposal. The order became effective February 4, 2008. The initial report is due May 1, 2009 for calendar year 2008. Subsequent reports are due by May 1 of each year for the previous calendar year. Order 704 will require most, if not all Kinder Morgan natural gas pipelines to report annual volumes of relevant transactions to the FERC. Technical workshops were held on April 22, 2008 and May 19, 2008. The FERC issued Order 704-A on September 18, 2008. This order generally affirmed the rule, while clarifying what information certain natural gas market participants must report in Form 552. The revisions pertain to the reporting of transactions occurring in calendar year 2008. Order 704-A became effective October 27, 2008.
 
On November 20, 2008, the FERC issued Order 720, which is the final rule in the Docket No. RM08-2-000 proceeding. The final rule established new reporting requirements for interstate and major non-interstate pipelines. A major non-interstate pipeline is defined as a pipeline who delivers annually more than 50 million MMBtus of natural gas measured in average deliveries for the previous three calendar years. Interstate pipelines will be required to post no-notice activity at each receipt and delivery point three days after the day of gas flow. Major non-interstate pipelines will be required to post design capacity, scheduled volumes and available capacity at each receipt or delivery point with a design capacity of 15,000 MMbtus of natural gas per day or greater when gas is scheduled at the point. The final rule became effective January 27, 2009 for interstate pipelines. Non-major interstate pipelines must comply with the requirements of Order 720 within 150 days following the issuance of an order addressing the pending request for rehearing.
 
FERC Equity Return Allowance
 
On April 17, 2008, the FERC adopted a new policy under Docket No. PL07-2-000 that allows master limited partnerships to be included in proxy groups for the purpose of determining rates of return for both interstate natural gas and oil pipelines. Additionally, the policy statement concluded that (i) there should be no cap on the level of distributions included in the FERC’s current discounted cash flow methodology, (ii) the Institutional Brokers Estimated System forecasts should remain the basis for the short-term growth forecast used in the discounted cash flow calculation, (iii) there should be an adjustment to the long-term growth rate used to calculate the equity cost of capital for a master limited partnership, specifically the long-term growth rate would be set at 50% of the gross domestic product and (iv) there should be no modification to the current respective two-thirds and one-third weightings of the short-term and long-term growth factors. Additionally, the FERC decided not to explore other methods for determining a pipeline’s equity cost of capital at this time. The policy statement governs all future gas and oil rate proceedings involving the establishment of a return on equity, as well as those cases that are currently pending before either the FERC or an administrative law judge. On May 19, 2008, an application for rehearing was filed by The American Public Gas Association. On June 13, 2008, the FERC dismissed the request for rehearing.
 
Notice of Proposed Rulemaking - Rural Onshore Low Stress Hazardous Liquids Pipelines
 
On September 6, 2006, the U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration, referred to in this report as the PHMSA, published a notice of proposed rulemaking (PHMSA 71 FR 52504) that proposed to extend certain threat-focused pipeline safety regulations to rural onshore low-stress hazardous liquid pipelines within a prescribed buffer of previously defined U.S. states. Low-stress hazardous liquid pipelines, except those in populated areas or that cross commercially navigable waterways, have not been subject to the safety regulations in PHMSA 49 C.F.R. Part 195.1. According to the PHMSA, unusually sensitive areas are areas requiring extra protection because of the presence of sole-source drinking water resources, endangered species, or other ecological resources that could be adversely affected by accidents or leaks occurring on hazardous liquid pipelines.
 
The notice proposed to define a category of “regulated rural onshore low-stress lines” (rural lines operating at or below 20% of specified minimum yield strength, with a diameter of eight and five-eighths inches or greater, located in or within a quarter-mile of a U.S. state) and to require operators of these lines to comply with a threat-focused set of requirements in Part 195 that already apply to other hazardous liquid pipelines. The proposed safety requirements addressed the most common threats—
 

 
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corrosion and third party damage—to the integrity of these rural lines. The proposal is intended to provide additional integrity protection, to avoid significant adverse environmental consequences, and to improve public confidence in the safety of unregulated low-stress lines.
 
Since the new notice is a proposed rulemaking in which the PHMSA will consider initial and reply comments from industry participants, it is not clear what impact the final rule will have on the business of our intrastate and interstate liquids pipeline companies.
 
Kinder Morgan Liquid Terminals – U.S. Department of Transportation Jurisdiction
 
With regard to several of our liquids terminals, we are working with the U.S. Department of Transportation, referred to in this report as the DOT, to supplement our compliance program for certain of our tanks and internal piping. We anticipate the program will call for incremental capital spending over the next several years to improve and/or add to our facilities. These improvements will enhance the tanks and piping previously considered outside the jurisdiction of DOT to conduct DOT jurisdictional transfers of products. Our original estimate called for an incremental $3 million to $5 million of annual capital spending over the next six to ten years for this work; however, we continue to assess the amount of capital that will be required and the amount may exceed our original estimate.
 
Natural Gas Pipeline Expansion Filings
 
TransColorado Pipeline
 
On April 19, 2007, the FERC issued an order approving TransColorado Gas Transmission Company LLC’s application for authorization to construct and operate certain facilities comprising its proposed “Blanco-Meeker Expansion Project.” This project provides for the transportation of up to approximately 250 million cubic feet per day of natural gas from the Blanco Hub area in San Juan County, New Mexico through TransColorado’s existing interstate pipeline for delivery to the Rockies Express Pipeline at an existing point of interconnection located in the Meeker Hub in Rio Blanco County, Colorado. Construction commenced on May 9, 2007, and the project was completed and entered service January 1, 2008.
 
Rockies Express Pipeline-Currently Certificated Facilities
 
Kinder Morgan Energy Partners operates and owns a 51% ownership interest in West2East Pipeline LLC, a limited liability company that is the sole owner of Rockies Express Pipeline LLC, and operates Rockies Express Pipeline. ConocoPhillips owns a 24% ownership interest in West2East Pipeline LLC and Sempra Energy holds the remaining 25% interest. When construction of the entire Rockies Express Pipeline project is completed, Kinder Morgan Energy Partners’ ownership interest will be reduced to 50% at which time the capital accounts of West2East Pipeline LLC will be trued up to reflect Kinder Morgan Energy Partners’ 50% economics in the project. According to the provisions of current accounting standards, because Kinder Morgan Energy Partners will receive 50% of the economic benefits from the Rockies Express project on an ongoing basis, Kinder Morgan Energy Partners is not considered the primary beneficiary of West2East Pipeline LLC and thus, accounts for its investment under the equity method of accounting.
 
On August 9, 2005, the FERC approved the application of Rockies Express Pipeline LLC, formerly known as Entrega Gas Pipeline LLC, to construct 327 miles of pipeline facilities in two phases. For phase I (consisting of two pipeline segments), Rockies Express Pipeline LLC was granted authorization to construct and operate approximately 136 miles of pipeline extending northward from the Meeker Hub, located at the northern end of Kinder Morgan Energy Partners’ TransColorado pipeline system in Rio Blanco County, Colorado, to the Wamsutter Hub in Sweetwater County, Wyoming (segment 1), and then construct approximately 191 miles of pipeline eastward to the Cheyenne Hub in Weld County, Colorado (segment 2). Construction of segments 1 and 2 has been completed, with interim service commencing on segment 1 on February 24, 2006, and full in-service of both segments on February 14, 2007. For phase II, Rockies Express Pipeline LLC was authorized to construct three compressor stations, referred to as the Meeker, Big Hole and Wamsutter compressor stations. The Meeker and Wamsutter stations went into service in January 2008. Construction of the Big Hole compressor station commenced in the second quarter of 2008, and the expected in service date for the compressor station is in the second quarter of 2009.
 
Rockies Express Pipeline-West Project
 
On April 19, 2007, the FERC issued a final order approving the Rockies Express Pipeline LLC application for authorization to construct and operate certain facilities comprising its proposed “Rockies Express-West” project. This project is the first planned segment extension of the Rockies Express’ facilities described above, and it is comprised of approximately 713 miles of 42-inch diameter pipeline extending from the Cheyenne Hub to an interconnection with Panhandle Eastern Pipe Line located in Audrain County, Missouri. The project also includes certain improvements to existing Rockies Express facilities located to the west of the Cheyenne Hub. Construction on Rockies Express-West commenced on May 21, 2007. Rockies Express-West began interim service for up to 1.4 billion cubic feet per day of natural gas on the segment’s first 503 miles of pipe on January 12, 2008. The project commenced deliveries to Panhandle Eastern Pipe Line, at Audrain County, Missouri, on
 

 
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the remaining 210 miles of pipe on May 20, 2008. The Rockies Express-West pipeline segment transports approximately 1.5 million cubic feet per day of natural gas across five states: Wyoming, Colorado, Nebraska, Kansas and Missouri.
 
Rockies Express Meeker to Cheyenne Expansion Project
 
Pursuant to certain rights exercised by Encana Gas Marketing USA as a result of its foundation shipper status on the former Entrega Gas Pipeline LLC facilities, Rockies Express Pipeline LLC is requesting authorization to construct and operate certain facilities that will comprise its Meeker, Colorado to Cheyenne, Wyoming expansion project. The proposed expansion will consist of additional natural gas compression at its Big Hole compressor station located in Moffat County, Colorado and its Arlington compressor station located in Carbon County, Wyoming. Upon completion, the additional compression will permit the transportation of an additional 200 million cubic feet per day of natural gas from (i) the Meeker Hub located in Rio Blanco County, Colorado northward to the Wamsutter Hub located in Sweetwater County, Wyoming; and (ii) from the Wamsutter Hub eastward to the Cheyenne Hub located in Weld County, Colorado. The expansion is fully contracted and is expected to be operational in April 2010. The total estimated cost for the proposed project is approximately $78 million. Rockies Express Pipeline LLC submitted a FERC application seeking approval to construct and operate this expansion on February 3, 2009.
 
Rockies Express Pipeline-East Project
 
On April 30, 2007, Rockies Express Pipeline LLC filed an application with the FERC requesting a certificate of public convenience and necessity that would authorize construction and operation of the Rockies Express-East Project. The Rockies Express-East Project will be comprised of approximately 639 miles of 42-inch diameter pipeline commencing from the terminus of the Rockies Express-West pipeline to a terminus near the town of Clarington in Monroe County, Ohio and will be capable of transporting approximately 1.8 billion cubic feet per day of natural gas.
 
By order issued May 30, 2008, the FERC authorized the certificate to construct the Rockies Express Pipeline-East Project. Construction commenced on the Rockies Express-East pipeline segment on June 26, 2008. Delays in securing permits and regulatory approvals, as well as weather-related delays, have caused Rockies Express Pipeline LLC to set revised project completion dates. Rockies Express-East is currently projected to commence service on April 1, 2009 to interconnects upstream of Lebanon, followed by service to the Lebanon Hub in Warren County, Ohio beginning June 15, 2009, with final completion and deliveries to Clarington, Ohio commencing by November 1, 2009.
 
On October 31, 2008, Rockies Express Pipeline LLC filed an amendment to its certificate application, seeking authorization to revise its tariff-based recourse rates for transportation service on the Rockies Express Pipeline-East Project facilities to reflect updated construction costs for the project. The proposed amendment is pending FERC approval.
 
Current market conditions for consumables, labor and construction equipment along with certain provisions in the final regulatory orders have resulted in increased costs for the project and have impacted certain projected completion dates. Our current estimate of total completed costs on the Rockies Express Pipeline Project is approximately $6.3 billion including expansion (consistent with Kinder Morgan Energy Partners’ January 21, 2009 fourth quarter earnings release).
 
Kinder Morgan Interstate Gas Transmission Pipeline
 
On August 6, 2007, Kinder Morgan Interstate Gas Transmission Pipeline LLC (referred to in this report as KMIGT) filed in FERC Docket CP07-430, for regulatory approval to construct and operate a 41-mile natural gas pipeline from the Cheyenne Hub to markets in and around Greeley, Colorado, referred to in this report as the Colorado Lateral. When completed, the Colorado Lateral will provide firm transportation of up to 55 million cubic feet per day to a local utility under long-term contract. The FERC issued a draft environmental assessment on the project on January 11, 2008, and comments on the project were received February 11, 2008. On February 21, 2008, the FERC granted the certificate application. On July 8, 2008, in response to a rehearing request by Public Service Company of Colorado (referred to in this report as PSCo) the FERC granted rehearing and denied KMIGT recovery in initial transportation rates $6.2 million in costs associated with non-jurisdictional laterals constructed by KMIGT to serve Atmos. The recourse rate adjustment does not have any material effect on the negotiated rate paid by Atmos to KMIGT or the economics of the project. On July 25, 2008, KMIGT filed an amendment to its certification application seeking authorization to revise its initial rates for transportation service on the Colorado Lateral to reflect updated construction costs for jurisdictional mainline facilities. The FERC approved the revised initial recourse rates on August 22, 2008.
 
PSCo, a competitor serving markets off the Colorado Lateral, also filed a complaint before the State of Colorado Public Utilities Commission (“CoPUC”) against Atmos, the anchor shipper on the project. The CoPUC conducted a hearing on April 14, 2008 on the complaint. On June 9, 2008, PSCo also filed before the CoPUC seeking a temporary cease and desist order to halt construction of the lateral facilities being constructed by KMIGT to serve Atmos. Atmos filed a response to that motion on June 24, 2008. By order dated June 27, 2008 an administrative law judge for the CoPUC denied PSCo’s request for a cease and desist order. On September 4, 2008, an administrative law judge for the CoPUC issued an order wherein it denied PSCo’s claim to exclusivity to serve Atmos and the Greeley market area but affirmed PSCo’s claim that Atmos’ acquisition of the
 

 
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delivery laterals is not in the ordinary course of business and requires separate approvals. Accordingly, Atmos may require a certificate of public convenience and necessity (“CPCN”) related to the delivery lateral facilities from KMIGT. While the need for approvals by Atmos before the CoPUC remains pending, service on the subject facilities commenced in November 2008.
 
On December 21, 2007, KMIGT filed, in Docket CP 08-44, for approval to expand its system in Nebraska to serve incremental ethanol and industrial load. No protests to the application were filed and the project was approved by the FERC. Construction commenced on April 9, 2008. These facilities went into service in October 2008.
 
Kinder Morgan Louisiana Pipeline
 
On September 8, 2006, in FERC Docket No. CP06-449-000, Kinder Morgan Louisiana Pipeline LLC filed an application with the FERC requesting approval to construct and operate the Kinder Morgan Louisiana Pipeline. The natural gas pipeline will extend approximately 135 miles from Cheniere’s Sabine Pass liquefied natural gas terminal in Cameron Parish, Louisiana, to various delivery points in Louisiana and will provide interconnects with many other natural gas pipelines, including NGPL. The project is supported by fully subscribed capacity and long-term customer commitments with Chevron and Total. The entire estimated project cost is now expected to be approximately $950 million (consistent with Kinder Morgan Energy Partners’ January 21, 2009 fourth quarter earnings press release), and it is expected to be fully operational during the third quarter of 2009.
 
On March 15, 2007, the FERC issued a preliminary determination that the authorizations requested, subject to some minor modifications, will be in the public interest. This order does not consider or evaluate any of the environmental issues in this proceeding. On April 19, 2007, the FERC issued the final environmental impact statement, or (“EIS”), which addressed the potential environmental effects of the construction and operation of the Kinder Morgan Louisiana Pipeline. The final EIS was prepared to satisfy the requirements of the National Environmental Policy Act. It concluded that approval of the Kinder Morgan Louisiana Pipeline project would have limited adverse environmental impacts. On June 22, 2007, the FERC issued an order granting construction and operation of the project. Kinder Morgan Louisiana Pipeline officially accepted the order on July 10, 2007.
 
On July 11, 2008, Kinder Morgan Louisiana Pipeline filed an amendment to its certificate application, seeking authorization to revise its initial rates for transportation service on the Kinder Morgan Louisiana Pipeline system to reflect updated construction costs for the project. The amendment was accepted by the FERC on August 14, 2008. On December 30, 2008, KMLP filed a second amendment to its certificate application, seeking authorization to revise its initial rates for transportation service on the KMLP system to reflect an additional increase in projected construction costs for the project. The filing is still pending.
 
Midcontinent Express Pipeline LLC
 
On October 9, 2007, in Docket No. CP08-6-000, Midcontinent Express Pipeline LLC (“Midcontinent Express Pipeline”) filed an application with the FERC requesting a certificate of public convenience and necessity that would authorize construction and operation of the approximately 500-mile Midcontinent Express Pipeline natural gas transmission system.
 
The Midcontinent Express Pipeline will create long-haul, firm transportation takeaway capacity either directly or indirectly connected to natural gas producing regions located in Texas, Oklahoma and Arkansas. The pipeline will originate in southeastern Oklahoma and traverse east through Texas, Louisiana, Mississippi, and terminate at an interconnection with the Transco Pipeline near Butler, Alabama. The Midcontinent Express Pipeline is a 50/50 joint venture between Kinder Morgan Energy Partners and Energy Transfer Partners, L.P., and it has a total capital cost of approximately $2.2 billion including the expansion capacity.
 
On July 25, 2008, the FERC approved the application made by Midcontinent Express Pipeline to construct and operate the 500-mile Midcontinent Express Pipeline natural gas transmission system along with the lease of 272 Mcf of capacity on the Oklahoma intrastate system of Enogex Inc. Initial design capacity for the pipeline was 1.5 Bcf of natural gas per day, which was fully subscribed with long-term binding commitments from creditworthy shippers. A successful binding open season was completed in July 2008, which will increase the main segment of the pipeline’s capacity to 1.8 Bcf per day, subject to regulatory approval.
 
Midcontinent Express Pipeline accepted the FERC Certificate on July 30, 2008. Mobilization for construction of the pipeline began in the third quarter of 2008, and subject to the receipt of regulatory approvals, interim service on the first portion of the pipeline is expected to be available by the second quarter of 2009 with full in service in the third quarter of 2009. On January 9, 2009, Midcontinent Express filed an amendment to its original certificate application requesting authorization to revise its initial rates for transportation service on the pipeline system to reflect an increase in projected construction costs for the project. The filing is still pending.
 

 
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On January 30, 2009, Midcontinent Express Pipeline filed a certificate application in Docket No. CP09-56-000 requesting authorization to increase the capacity in Zone 1 from 1.5 Bcf to 1.8 Bcf/d. The Application is still pending.
 
Kinder Morgan Texas Pipeline LLC
 
On May 30, 2008, Kinder Morgan Texas Pipeline LLC filed in Docket No. PR08-25-000 a petition seeking market-based rate authority for firm and interruptible storage services performed under section 311 of the Natural Gas Policy Act of 1978 (NGPA) at the North Dayton Gas Storage Facility in Liberty County, Texas, and at the Markham Gas Storage Facility in Matagorda County, Texas. On October 3, 2008, the FERC approved this petition effective May 30, 2008.
 
21. Litigation, Environmental and Other Contingencies
 
Below is a brief description of our ongoing material legal proceedings, including any material developments that occurred in such proceedings during 2008. This note also contains a description of any material legal proceeding initiated during 2008 in which we are involved.
 
Following is a listing of certain current FERC proceedings pertaining to Kinder Morgan Energy Partners’ operations:
 
Proceedings
Complainants/Protestants
Defendants
FERC Docket No. OR92-8, et al.
Chevron; Navajo; ARCO; BP WCP; Western Refining; ExxonMobil; Tosco; and Texaco (Ultramar is an intervenor)
SFPP
FERC Docket No. OR92-8-025
BP WCP; ExxonMobil ; Chevron; ConocoPhillips; and Ultramar
SFPP
FERC Docket No. OR96-2, et al.
All Shippers except Chevron (which is an intervenor)
SFPP
FERC Docket Nos. OR02-4 and OR03-5
Chevron
SFPP
FERC Docket No. OR04-3
America West Airlines; Southwest Airlines; Northwest Airlines; and Continental Airlines
SFPP
FERC Docket Nos. OR03-5, OR05-4 and OR05-5
BP WCP; ExxonMobil; and ConocoPhillips (other shippers intervened)
SFPP
FERC Docket No. OR03-5-001
BP WCP; ExxonMobil; and ConocoPhillips (other shippers intervened)
SFPP
FERC Docket No. OR07-1
Tesoro
SFPP
FERC Docket No. OR07-2
Tesoro
SFPP
FERC Docket No. OR07-3
BP WCP; Chevron; ExxonMobil; Tesoro; and Valero Marketing
SFPP
FERC Docket No. OR07-4
BP WCP; Chevron; and ExxonMobil
SFPP; Kinder Morgan G.P., Inc.; and Knight Inc.
FERC Docket Nos. OR07-5 and OR07-7 (consolidated)
ExxonMobil and Tesoro
Calnev; Kinder Morgan G.P., Inc.; and Knight Inc.
FERC Docket No. OR07-6
ConocoPhillips
SFPP
FERC Docket Nos. OR07-8 and OR07-11 (consolidated)
BP WCP and ExxonMobil
SFPP
FERC Docket No. OR07-9
BP WCP
SFPP
FERC Docket No. OR07-14
BP WCP and Chevron
SFPP; Calnev; and several affiliates
FERC Docket No. OR07-16
Tesoro
Calnev
FERC Docket No. OR07-18
Airline Complainants; Chevron; and Valero Marketing
Calnev
FERC Docket No. OR07-19
ConocoPhillips
Calnev
FERC Docket No. OR07-20
BP WCP
SFPP
FERC Docket No. OR07-22
BP WCP
Calnev
FERC Docket No. OR08-13
BP WCP and ExxonMobil
SFPP
FERC Docket No. OR08-15
BP WCP and ExxonMobil
SFPP
FERC Docket No. IS05-230 (North Line rate case)
Shippers
SFPP
FERC Docket No. IS05-327
Shippers
SFPP


 
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FERC Docket No. IS06-283 (East Line rate case)
Shippers
SFPP
FERC Docket No. IS06-296
ExxonMobil
Calnev
FERC Docket No. IS06-356
Shippers
SFPP
FERC Docket No. IS07-137 (Ultra Low Sulfur Diesel (ULSD) surcharge)
Shippers
SFPP
FERC Docket No. IS07-229
BP WCP and ExxonMobil
SFPP
FERC Docket No. IS07-234
BP WCP and ExxonMobil
Calnev
FERC Docket No. IS08-28
ConocoPhillips; Chevron; BP WCP; ExxonMobil ; Southwest Airlines; Western; and Valero
SFPP
FERC Docket No. IS08-302
Chevron; BP WCP; ExxonMobil; and Tesoro
SFPP
FERC Docket No. IS08-389
ConocoPhillips; Valero; Southwest Airlines Co.; Navajo; and Western
SFPP
FERC Docket No. IS08-390
BP WCP; ExxonMobil; ConocoPhillips; Valero; Chevron; and the Airlines
SFPP
Motions to compel payment of interim damages (various dockets)
Shippers
SFPP; Kinder Morgan G.P., Inc.; and Knight Inc.
Motion for resolution on the merits (various dockets)
BP WCP and ExxonMobil
SFPP and Calnev.

In this note, we refer to SFPP, L.P. as SFPP; Calnev Pipe Line LLC as Calnev; Chevron Products Company as Chevron; Navajo Refining Company, L.P. as Navajo; ARCO Products Company as ARCO; BP West Coast Products, LLC as BP WCP; Texaco Refining and Marketing Inc. as Texaco; Western Refining Company, L.P. as Western Refining; Mobil Oil Corporation as Mobil; ExxonMobil Oil Corporation as ExxonMobil; Tosco Corporation as Tosco; ConocoPhillips Company as ConocoPhillips; Ultramar Diamond Shamrock Corporation/Ultramar Inc. as Ultramar; Valero Energy Corporation as Valero; Valero Marketing and Supply Company as Valero Marketing; America West Airlines, Inc., Continental Airlines, Inc., Northwest Airlines, Inc., Southwest Airlines Co. and US Airways, Inc., collectively, as the Airline Complainants; and the Federal Energy Regulatory Commission, as FERC.
 
The tariffs and rates charged by SFPP and Calnev (Kinder Morgan Energy Partners subsidiaries) are subject to numerous ongoing proceedings at the FERC, including the above listed shippers’ complaints and protests regarding interstate rates on these pipeline systems. These complaints have been filed over numerous years beginning in 1992 through and including 2008. In general, these complaints allege the rates and tariffs charged by SFPP and Calnev are not just and reasonable. If the shippers are successful in proving their claims, they are entitled to seek reparations (which may reach up to two years prior to the filing of their complaint) or refunds of any excess rates paid, and SFPP and Calnev may be required to reduce their rates going forward. These proceedings tend to be protracted, with decisions of the FERC often appealed to the federal courts. 
 
As to SFPP, the issues involved in these proceedings include, among others: (i) whether certain of SFPP operations’ rates are “grandfathered” under the Energy Policy Act of 1992, and therefore deemed to be just and reasonable; (ii) whether “substantially changed circumstances” have occurred with respect to any grandfathered rates such that those rates could be challenged; (iii) whether indexed rate increases are justified; and (iv) the appropriate level of return and income tax allowance it may include in its rates. The issues involving Calnev are similar.
 
In May 2005, the FERC issued a statement of general policy stating it will permit pipelines to include in cost of service a tax allowance to reflect actual or potential tax liability on their public utility income attributable to all partnership or limited liability company interests, if the ultimate owner of the interest has an actual or potential income tax liability on such income. Whether a pipeline’s owners have such actual or potential income tax liability will be reviewed by the FERC on a case-by-case basis; consequently, the level of income tax allowance to which SFPP will ultimately be entitled is not certain. In May of 2007, the D.C. Court upheld the FERC’s tax allowance policy.
 
In December 2005, SFPP received a FERC order in OR92-8 and OR96-2 that directed it to submit compliance filings and revised tariffs. In accordance with the FERC’s December 2005 order and its February 2006 order on rehearing, SFPP submitted a compliance filing to the FERC in March 2006, and rate reductions were implemented on May 1, 2006. In addition, in December 2005, Kinder Morgan Energy Partners recorded accruals of $105.0 million for expenses attributable to an increase in its reserves related to its rate case liability.
 
In December 2007, as a follow-up to a March 2006 SFPP compliance filing to FERC, SFPP received a FERC order that directed Kinder Morgan Energy Partners to submit revised compliance filings and revised tariffs. In conjunction with FERC’s December 2007 order, Kinder Morgan Energy Partners’ other FERC and CPUC rate cases, and other unrelated litigation matters, it increased its litigation reserves by $140.0 million in the fourth quarter of 2007. And, in accordance with FERC’s
 

 
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December 2007 order and its February 2008 order on rehearing, SFPP submitted a compliance filing to FERC in February 2008, and further rate reductions were implemented on March 1, 2008.
 
During 2008, SFPP and Calnev made combined settlement payments to various shippers totaling approximately $30 million. In October 2008 in connection with OR92-8-025, IS6-283 and OR07-5, SFPP entered into a settlement resolving disputes regarding its East Line rates filed in Docket No. IS08-28 and related dockets. In January 2009, the FERC approved the settlement. Upon the finality of FERC’s approval, reduced settlement rates are expected to go into effect on May 1, 2009, and SFPP will make refunds and settlement payments shortly thereafter estimated to total approximately $16.0 million.
 
Based on our review of these FERC proceedings, we estimate that as of December 31, 2008, shippers are seeking approximately $355 million in reparation and refund payments and approximately $30 to $35 million in additional annual rate reductions. We assume that, with respect to our SFPP litigation reserves, any reparations and accrued interest thereon will be paid no earlier than the second quarter of 2009.
 
California Public Utilities Commission Proceedings
 
On April 7, 1997, ARCO, Mobil and Texaco filed a complaint against SFPP with the California Public Utilities Commission, referred to in this note as the CPUC. The complaint challenges rates charged by SFPP for intrastate transportation of refined petroleum products through its pipeline system in the state of California and requests prospective rate adjustments and refunds with respect to previously untariffed charges for certain pipeline transportation and related services.
 
In October 2002, the CPUC issued a resolution, referred to in this note as the Power Surcharge Resolution, approving a 2001 request by SFPP to raise its California rates to reflect increased power costs. The resolution reserves the right to require refunds from the date of issuance of the resolution to the extent the CPUC’s analysis of cost data to be submitted by SFPP demonstrates that SFPP’s California jurisdictional rates are unreasonable in any fashion.
 
On December 26, 2006, Tesoro filed a complaint challenging the reasonableness of SFPP’s intrastate rates for the three-year period from December 2003 through December 2006 and requesting approximately $8 million in reparations. As a result of previous SFPP rate filings and related protests, the rates that are the subject of the Tesoro complaint are being collected subject to refund.
 
SFPP also has various, pending ratemaking matters before the CPUC that are unrelated to the above-referenced complaints and the Power Surcharge Resolution. Protests to these rate increase applications have been filed by various shippers. As a consequence of the protests, the related rate increases are being collected subject to refund.
 
All of the above matters have been consolidated and assigned to a single administrative law judge. At the time of this report, it is unknown when a decision from the CPUC regarding the CPUC complaints and the Power Surcharge Resolution will be received. No schedule has been established for hearing and resolution of the consolidated proceedings other than the 1997 CPUC complaint and the Power Surcharge Resolution. Based on our review of these CPUC proceedings, we estimate that shippers are seeking approximately $100 million in reparation and refund payments and approximately $35 million in annual rate reductions.
 
On June 6, 2008, as required by CPUC order, SFPP and Calnev Pipe Line Company filed separate general rate case applications, neither of which request a change in existing pipeline rates and both of which assert that existing pipeline rates are reasonable. On September 26, 2008, SFPP filed an amendment to its general rate case application, requesting CPUC approval of a $5 million rate increase for intrastate transportation services that became effective November 1, 2008. Protests to the amended rate increase application have been filed by various shippers and, as a consequence, the related rate increase is being collected subject to refund. The CPUC has issued a ruling suspending further activity with respect to the SFPP and Calnev Pipe Line Company general rate case applications, pending CPUC resolution of the 1997 CPUC complaint and Power Surcharge proceedings. Consequently, no action has been taken by the CPUC with respect to either the SFPP amended general rate case filing or the Calnev general rate case filing.
 
Carbon Dioxide Litigation
 
Gerald O. Bailey et al. v. Shell Oil Co. et al/Southern District of Texas Lawsuit
 
Kinder Morgan CO2 Company, L.P. (referred to in this note as Kinder Morgan CO2), Kinder Morgan Energy Partners, L.P. and Cortez Pipeline Company are among the defendants in a proceeding in the federal courts for the southern district of Texas. Gerald O. Bailey et al. v. Shell Oil Company et al., (Civil Action Nos. 05-1029 and 05-1829 in the U.S. District Court for the Southern District of Texas—consolidated by Order dated July 18, 2005). The plaintiffs are asserting claims for the underpayment of royalties on carbon dioxide produced from the McElmo Dome Unit. The plaintiffs assert claims for fraud/fraudulent inducement, real estate fraud, negligent misrepresentation, breach of fiduciary and agency duties, breach of contract and covenants, violation of the Colorado Unfair Practices Act, civil theft under Colorado law, conspiracy, unjust enrichment, and open account. Plaintiffs Gerald O. Bailey, Harry Ptasynski, and W.L. Gray & Co. have also asserted claims
 

 
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as private relators under the False Claims Act and for violation of federal and Colorado antitrust laws. The plaintiffs seek actual damages, treble damages, punitive damages, a constructive trust and accounting, and declaratory relief. The defendants filed motions for summary judgment on all claims.
 
Effective March 5, 2007, all defendants and plaintiffs Bridwell Oil Company, the Alicia Bowdle Trust, and the Estate of Margaret Bridwell Bowdle executed a final settlement agreement which provides for the dismissal of these plaintiffs’ claims with prejudice to being refiled. On June 10, 2007, the Houston federal district court entered an order of partial dismissal by which the claims by and against the settling plaintiffs were dismissed with prejudice. The claims asserted by Bailey, Ptasynski, and Gray are not included within the settlement or the order of partial dismissal. Effective April 8, 2008, the Shell and Kinder Morgan defendants and plaintiff Gray entered into an indemnification agreement that provides for the dismissal of Gray’s claims with prejudice.
 
On April 22, 2008, the federal district court granted defendants’ motions for summary judgment and ruled that plaintiffs Bailey, Ptasynski, and Gray take nothing on their claims. The court entered final judgment in favor of defendants on April 30, 2008. Defendants have filed a motion seeking sanctions against plaintiff Bailey. The plaintiffs have appealed the final judgment to the United States Fifth Circuit Court of Appeals. In October 2008, plaintiffs filed their brief in the Fifth Circuit Court of Appeals. Defendants filed their brief in the Fifth Circuit in December 2008.
 
CO2 Claims Arbitration
 
Cortez Pipeline Company and Kinder Morgan CO2, successor to Shell CO2 Company, Ltd., were among the named defendants in CO2 Committee, Inc. v. Shell Oil Co., et al., an arbitration initiated on November 28, 2005. The arbitration arose from a dispute over a class action settlement agreement, which became final on July 7, 2003 and disposed of five lawsuits formerly pending in the U.S. District Court, District of Colorado. The plaintiffs in such lawsuits primarily included overriding royalty interest owners, royalty interest owners, and small share working interest owners who alleged underpayment of royalties and other payments on carbon dioxide produced from the McElmo Dome Unit. The settlement imposed certain future obligations on the defendants in the underlying litigation. The plaintiff alleged that, in calculating royalty and other payments, defendants used a transportation expense in excess of what is allowed by the settlement agreement, thereby causing alleged underpayments of approximately $12 million. The plaintiff also alleged that Cortez Pipeline Company should have used certain funds to further reduce its debt, which, in turn, would have allegedly increased the value of royalty and other payments by approximately $0.5 million. On August 7, 2006, the arbitration panel issued its opinion finding that defendants did not breach the settlement agreement. On June 21, 2007, the New Mexico federal district court entered final judgment confirming the August 7, 2006 arbitration decision.
 
On October 2, 2007, the plaintiff initiated a second arbitration (CO2 Committee, Inc. v. Shell CO2 Company, Ltd., aka Kinder Morgan CO2 Company, L.P., et al.) against Cortez Pipeline Company, Kinder Morgan CO2 and an ExxonMobil entity. The second arbitration asserts claims similar to those asserted in the first arbitration. On June 3, 2008, the plaintiff filed a request with the American Arbitration Association seeking administration of the arbitration. In October 2008, the New Mexico federal district court entered an order declaring that the panel in the first arbitration should decide whether the claims in the second arbitration are barred by res judicata. The plaintiff filed a motion for reconsideration of that order, which was denied by the New Mexico federal district court in January 2009. Plaintiff has appealed to the Tenth Circuit Court of Appeals and continues to seek administration of the second arbitration by the American Arbitration Association.
 
MMS Notice of Noncompliance and Civil Penalty
 
On December 20, 2006, Kinder Morgan CO2 received a “Notice of Noncompliance and Civil Penalty: Knowing or Willful Submission of False, Inaccurate, or Misleading Information—Kinder Morgan CO2 Company, L.P., Case No. CP07-001” from the U.S. Department of the Interior, Minerals Management Service, referred to in this note as the MMS. This Notice, and the MMS’s position that Kinder Morgan CO2 has violated certain reporting obligations, relates to a disagreement between the MMS and Kinder Morgan CO2 concerning the approved transportation allowance to be used in valuing McElmo Dome carbon dioxide for purposes of calculating federal royalties. The Notice of Noncompliance and Civil Penalty assesses a civil penalty of approximately $2.2 million as of December 15, 2006 (based on a penalty of $500.00 per day for each of 17 alleged violations) for Kinder Morgan CO2’s alleged submission of false, inaccurate, or misleading information relating to the transportation allowance, and federal royalties for CO2 produced at McElmo Dome, during the period from June 2005 through October 2006. The MMS stated that civil penalties will continue to accrue at the same rate until the alleged violations are corrected.
 
The parties have reached a settlement of the Notice of Noncompliance and Civil Penalty. The settlement agreement is subject to final MMS approval and upon approval will be funded from existing reserves and indemnity payments by Shell CO2 General LLC and Shell CO2 LLC pursuant to a royalty claim indemnification agreement.
 

 
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MMS Order to Report and Pay
 
On March 20, 2007, Kinder Morgan CO2 received an “Order to Report and Pay” from the MMS. The MMS contends that Kinder Morgan CO2 has over-reported transportation allowances and underpaid royalties in the amount of approximately $4.6 million for the period from January 1, 2005 through December 31, 2006 as a result of its use of the Cortez Pipeline tariff as the transportation allowance in calculating federal royalties. The MMS claims that the Cortez Pipeline Company tariff is not the proper transportation allowance and that Kinder Morgan CO2 must use its “reasonable actual costs” calculated in accordance with certain federal product valuation regulations. The MMS set a due date of April 13, 2007 for Kinder Morgan CO2’s payment of the $4.6 million in claimed additional royalties, with possible late payment charges and civil penalties for failure to pay the assessed amount. Kinder Morgan CO2 has not paid the $4.6 million, and on April 19, 2007, it submitted a notice of appeal and statement of reasons in response to the Order to Report and Pay, challenging the Order and appealing it to the Director of the MMS in accordance with 30 C.F.R. Sec. 290.100, et seq.
 
In addition to the March 2007 Order to Report and Pay, in April 2007, Kinder Morgan CO2 received an “Audit Issue Letter” sent by the Colorado Department of Revenue on behalf of the U.S. Department of the Interior. In the letter, the Department of Revenue states that Kinder Morgan CO2 has over-reported transportation allowances and underpaid royalties (due to the use of the Cortez Pipeline Company tariff as the transportation allowance for purposes of federal royalties) in the amount of $8.5 million for the period from April 2000 through December 2004.
 
The MMS and Kinder Morgan CO2 reached a settlement of the March 2007 and August 2007 Orders to Report and Pay. The settlement agreement is subject to final MMS approval. The settlement is subject to final MMS approval and upon approval will be funded from existing reserves and indemnity payments from Shell CO2 General LLC and Shell CO2 LLC pursuant to a royalty claim indemnification agreement.
 
J. Casper Heimann, Pecos Slope Royalty Trust and Rio Petro LTD, individually and on behalf of all other private royalty and overriding royalty owners in the Bravo Dome Carbon Dioxide Unit, New Mexico similarly situated v. Kinder Morgan CO2 Company, L.P., No. 04-26-CL (8th Judicial District Court, Union County New Mexico)
 
This case involves a purported class action against Kinder Morgan CO2 alleging that it has failed to pay the full royalty and overriding royalty (“royalty interests”) on the true and proper settlement value of compressed carbon dioxide produced from the Bravo Dome Unit during the period beginning January 1, 2000. The complaint purports to assert claims for violation of the New Mexico Unfair Practices Act, constructive fraud, breach of contract and of the covenant of good faith and fair dealing, breach of the implied covenant to market, and claims for an accounting, unjust enrichment, and injunctive relief. The purported class is comprised of current and former owners, during the period January 2000 to the present, who have private property royalty interests burdening the oil and gas leases held by the defendant, excluding the Commissioner of Public Lands, the United States of America, and those private royalty interests that are not unitized as part of the Bravo Dome Unit.
 
The case was tried in the trial court in September 2008. The plaintiffs sought $6.8 million in actual damages as well as punitive damages. The jury returned a verdict finding that Kinder Morgan did not breach the settlement agreement and did not breach the claimed duty to market carbon dioxide. The jury also found that Kinder Morgan breached a duty of good faith and fair dealing and found compensatory damages of $0.3 million and punitive damages of $1.2 million. On October 16, 2008, the trial court entered judgment on the verdict.
 
On January 6, 2009, the district court entered orders vacating the judgment and granting a new trial in the case, which is scheduled a new trial to occur beginning on October 19, 2009.
 
In addition to the matters listed above, audits and administrative inquiries concerning Kinder Morgan CO2’s payments on carbon dioxide produced from the McElmo Dome and Bravo Dome Units are currently ongoing. These audits and inquiries involve federal agencies and the States of Colorado and New Mexico.
 
Commercial Litigation Matters
 
Union Pacific Railroad Company Easements
 
SFPP and Union Pacific Railroad Company (the successor to Southern Pacific Transportation Company and referred to in this note as UPRR) are engaged in a proceeding to determine the extent, if any, to which the rent payable by SFPP for the use of pipeline easements on rights-of-way held by UPRR should be adjusted pursuant to existing contractual arrangements for the ten-year period beginning January 1, 2004 (Union Pacific Railroad Company vs. Santa Fe Pacific Pipelines, Inc., SFPP, L.P., Kinder Morgan Operating L.P. “D”, Kinder Morgan G.P., Inc., et al., Superior Court of the State of California for the County of Los Angeles, filed July 28, 2004). In February 2007, a trial began to determine the amount payable for easements on UPRR rights-of-way. The trial is ongoing and is expected to conclude in the second quarter of 2009.
 

 
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SFPP and UPRR are also engaged in multiple disputes over the circumstances under which SFPP must pay for a relocation of its pipeline within the UPRR right-of-way and the safety standards that govern relocations. In July 2006, a trial before a judge regarding the circumstances under which SFPP must pay for relocations concluded, and the judge determined that SFPP must pay for any relocations resulting from any legitimate business purpose of the UPRR. SFPP has appealed this decision and in December 2008, the appellate court affirmed the decision. In addition, UPRR contends that it has complete discretion to cause the pipeline to be relocated at SFPP’s expense at any time and for any reason, and that SFPP must comply with the more expensive American Railway Engineering and Maintenance-of-Way standards. Each party is seeking declaratory relief with respect to its positions regarding relocations.
 
It is difficult to quantify the effects of the outcome of these cases on SFPP because SFPP does not know UPRR’s plans for projects or other activities that would cause pipeline relocations. Even if SFPP is successful in advancing its positions, significant relocations for which SFPP must nonetheless bear the expense (i.e. for railroad purposes, with the standards in the federal Pipeline Safety Act applying) would have an adverse effect on our financial position and results of operations. These effects would be even greater in the event SFPP is unsuccessful in one or more of these litigations.
 
United States of America, ex rel., Jack J. Grynberg v. K N Energy (Civil Action No. 97-D-1233, filed in the U.S. District Court, District of Colorado).
 
This multi-district litigation proceeding involves four lawsuits filed in 1997 against numerous Kinder Morgan companies. These suits were filed pursuant to the federal False Claims Act and allege underpayment of royalties due to mismeasurement of natural gas produced from federal and Indian lands. The complaints are part of a larger series of similar complaints filed by Mr. Grynberg against 77 natural gas pipelines (approximately 330 other defendants) in various courts throughout the country that were consolidated and transferred to the District of Wyoming.
 
In May 2005, a Special Master appointed in this litigation found that because there was a prior public disclosure of the allegations and that Grynberg was not an original source, the Court lacked subject matter jurisdiction. As a result, the Special Master recommended that the Court dismiss all the Kinder Morgan defendants. In October 2006, the United States District Court for the District of Wyoming upheld the dismissal of each case against the Kinder Morgan defendants on jurisdictional grounds. Grynberg has appealed this Order to the Tenth Circuit Court of Appeals. Briefing was completed and oral argument was held on September 25, 2008. No decision has yet been issued.
 
Prior to the dismissal order on jurisdictional grounds, the Kinder Morgan defendants filed Motions to Dismiss and for Sanctions alleging that Grynberg filed his Complaint without evidentiary support and for an improper purpose. On January 8, 2007, after the dismissal order, the Kinder Morgan defendants also filed a Motion for Attorney Fees under the False Claim Act. On April 24, 2007, the Court held a hearing on the Motions to Dismiss and for Sanctions and the Requests for Attorney Fees. A decision is still pending on the Motions to Dismiss and for Sanctions and the Requests for Attorney Fees.
 
Leukemia Cluster Litigation
 
Richard Jernee, et al. v. Kinder Morgan Energy Partners, et al., No. CV03-03482 (Second Judicial District Court, State of Nevada, County of Washoe) (“Jernee”).
 
Floyd Sands, et al. v. Kinder Morgan Energy Partners, et al., No. CV03-05326 (Second Judicial District Court, State of Nevada, County of Washoe) (“Sands”).
 
On May 30, 2003, plaintiffs, individually and on behalf of Adam Jernee, filed a civil action in the Nevada State trial court against Kinder Morgan Energy Partners and several Kinder Morgan related entities and individuals and additional unrelated defendants. Plaintiffs in the Jernee matter claim that defendants negligently and intentionally failed to inspect, repair and replace unidentified segments of their pipeline and facilities, allowing “harmful substances and emissions and gases” to damage “the environment and health of human beings.” Plaintiffs claim that “Adam Jernee’s death was caused by leukemia that, in turn, is believed to be due to exposure to industrial chemicals and toxins.” Plaintiffs purport to assert claims for wrongful death, premises liability, negligence, negligence per se, intentional infliction of emotional distress, negligent infliction of emotional distress, assault and battery, nuisance, fraud, strict liability (ultra hazardous acts), and aiding and abetting, and seek unspecified special, general and punitive damages. On August 28, 2003, a separate group of plaintiffs, represented by the counsel for the plaintiffs in the Jernee matter, individually and on behalf of Stephanie Suzanne Sands, filed a civil action in the Nevada State trial court against the same defendants and alleging the same claims as in the Jernee case with respect to Stephanie Suzanne Sands. The Jernee case has been consolidated for pretrial purposes with the Sands case. In May 2006, the court granted defendants’ motions to dismiss as to the counts purporting to assert claims for fraud, but denied defendants’ motions to dismiss as to the remaining counts, as well as defendants’ motions to strike portions of the complaint. Defendant Kennametal, Inc. has filed a third-party complaint naming the United States and the United States Navy (the “United States”) as additional defendants. In response, the United States removed the case to the United States District Court for the District of Nevada and filed a motion to dismiss the third-party complaint. Plaintiff has also filed a motion to dismiss the United States and/or to remand the case back to state court. By order dated September 25, 2007, the United States District Court granted the motion to dismiss the United States from the case and remanded the Jernee and Sands cases back to the
 

 
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Second Judicial District Court, State of Nevada, County of Washoe. The cases will now proceed in the State Court. Based on the information available to date, our own preliminary investigation, and the positive results of investigations conducted by State and Federal agencies, we believe that the remaining claims against Kinder Morgan Energy Partners in these matters are without merit and intend to defend against them vigorously.
 
Pipeline Integrity and Releases
 
From time to time, our pipelines experience leaks and ruptures. These leaks and ruptures may cause explosions, fire, damage to the environment, damage to property and/or personal injury or death. In connection with these incidents, we may be sued for damages caused by an alleged failure to properly mark the locations of our pipelines and/or to properly maintain our pipelines. Depending upon the facts and circumstances of a particular incident, state and federal regulatory authorities may seek civil and/or criminal fines and penalties.
 
Pasadena Terminal Fire
 
On September 23, 2008, a fire occurred in the pit 3 manifold area of our Pasadena, Texas terminal facility. One of our employees was injured and subsequently died. In addition, the pit 3 manifold was severely damaged. The cause of the incident is currently under investigation by the Railroad Commission of Texas and the United States Occupational Safety and Health Administration. The remainder of the facility returned to normal operations within twenty-four hours of the incident.
 
Walnut Creek, California Pipeline Rupture
 
On November 9, 2004, excavation equipment operated by Mountain Cascade, Inc., a third-party contractor on a water main installation project hired by East Bay Municipal Utility District, struck and ruptured an underground petroleum pipeline owned and operated by SFPP in Walnut Creek, California. An explosion occurred immediately following the rupture that resulted in five fatalities and several injuries to employees or contractors of Mountain Cascade, Inc. Following court ordered mediation, we have settled with plaintiffs in all of the wrongful death cases and the personal injury and property damages cases. On January 12, 2009, the Contra Costa Superior Court granted summary judgment in favor of Kinder Morgan G.P. Services Co., Inc. in the last remaining civil suit – a claim for indemnity brought by co-defendant Camp, Dresser & McKee, Inc. The only remaining pending matter is our appeal of a civil fine of $140,000 issued by the California Division of Occupational Safety and Health.
 
Rockies Express Pipeline LLC Wyoming Construction Incident
 
On November 11, 2006, a bulldozer operated by an employee of Associated Pipeline Contractors, Inc., (a third-party contractor to Rockies Express Pipeline LLC, referred to in this note as REX), struck an existing subsurface natural gas pipeline owned by Wyoming Interstate Company, a subsidiary of El Paso Pipeline Group. The pipeline was ruptured, resulting in an explosion and fire. The incident occurred in a rural area approximately nine miles southwest of Cheyenne, Wyoming. The incident resulted in one fatality (the operator of the bulldozer) and there were no other reported injuries. The cause of the incident was investigated by the U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration, referred to in this report as the PHMSA. In March 2008, the PHMSA issued a Notice of Probable Violation, Proposed Civil Penalty and Proposed Compliance Order (“NOPV”) to El Paso Corporation in which it concluded that El Paso failed to comply with federal law and its internal policies and procedures regarding protection of its pipeline, resulting in this incident. To date, the PHMSA has not issued any NOPV’s to REX, and we do not expect that it will do so. Immediately following the incident, REX and El Paso Pipeline Group reached an agreement on a set of additional enhanced safety protocols designed to prevent the reoccurrence of such an incident.
 
In September 2007, the family of the deceased bulldozer operator filed a wrongful death action against Kinder Morgan Energy Partners, REX and several other parties in the District Court of Harris County, Texas, 189th Judicial District, at case number 2007-57916. The plaintiffs seek unspecified compensatory and exemplary damages plus interest, attorney’s fees and costs of suit. Kinder Morgan Energy Partners has asserted contractual claims for complete indemnification for any and all costs arising from this incident, including any costs related to this lawsuit, against third parties and their insurers. On March 25, 2008, the defendants entered into a settlement agreement with one of the plaintiffs, the decedent’s daughter, resolving any and all of her claims against Kinder Morgan Energy Partners, REX and its contractors. Kinder Morgan Energy Partners was indemnified for the full amount of this settlement by one of REX’s contractors.  On October 17, 2008, the remaining plaintiffs filed a Notice of Nonsuit, which dismissed the remaining claims against all defendants without prejudice to the plaintiffs’ ability to re-file their claims at a later date. The remaining plaintiffs re-filed their Complaint against REX, Kinder Morgan Energy Partners and several other parties on November 7, 2008, Cause No. 2008-66788, currently pending in the District Court of Harris County, Texas, 189th Judicial District. The parties are currently engaged in discovery.
 
Charlotte, North Carolina
 
On November 27, 2006, the Plantation Pipeline experienced a release of approximately 4,000 gallons of gasoline from a Plantation Pipe Line Company block valve on a delivery line into a terminal owned by a third party company. The line was
 

 
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repaired and put back into service within a few days. Remediation efforts are continuing under the direction of the North Carolina Department of Environment and Natural Resources (the “NCDENR”), which issued a Notice of Violation and Recommendation of Enforcement against Plantation on January 8, 2007. Plantation continues to cooperate fully with the NCDENR.
 
Although Plantation does not believe that penalties are warranted, it has engaged in settlement discussions with the EPA regarding a potential civil penalty for the November 2006 release as part of broader settlement negotiations with the EPA regarding this spill and three other historic releases from Plantation, including a February 2003 release near Hull, Georgia. Plantation has entered into a consent decree with the Department of Justice and the EPA for all four releases for approximately $0.7 million, plus some additional work to be performed to prevent future releases. The proposed consent decree was filed in U.S. District Court and is awaiting entry by the court.
 
In addition, in April 2007, during pipeline maintenance activities near Charlotte, North Carolina, Plantation discovered the presence of historical soil contamination near the pipeline, and reported the presence of impacted soils to the NCDENR. Subsequently, Plantation contacted the owner of the property to request access to the property to investigate the potential contamination. The results of that investigation indicate that there is soil and groundwater contamination, which appears to be from an historical turbine fuel release. The groundwater contamination is underneath at least two lots on which there is current construction of single-family homes as part of a new residential development. Further investigation and remediation are being conducted under the oversight of the NCDENR. Plantation reached a settlement with the builder of the residential subdivision. Plantation continues to negotiate with the owner of the property to address any potential claims that it may bring.
 
Barstow, California
 
The United States Department of Navy has alleged that historic releases of methyl tertiary-butyl ether, referred to in this report as MTBE, from Calnev’s Barstow terminal has (i) migrated underneath the Navy’s Marine Corps Logistics Base (the “MCLB”) in Barstow, (ii) impacted the Navy’s existing groundwater treatment system for unrelated groundwater contamination not alleged to have been caused by Calnev, and (iii) affected the MCLB’s water supply system. Although Calnev believes that it has certain meritorious defenses to the Navy’s claims, it is working with the Navy to agree upon an Administrative Settlement Agreement and Order on Consent for CERCLA Removal Action to reimburse the Navy for $0.5 million in past response actions, plus perform other work to ensure protection of the Navy’s existing treatment system and water supply.
 
Oil Spill Near Westridge Terminal, Burnaby, British Columbia
 
On July 24, 2007, a third-party contractor installing a sewer line for the City of Burnaby struck a crude oil pipeline segment included within Kinder Morgan Energy Partners’ Trans Mountain pipeline system near its Westridge terminal in Burnaby, BC, resulting in a release of approximately 1,400 barrels of crude oil. The release impacted the surrounding neighborhood, several homes and nearby Burrard Inlet. No injuries were reported. To address the release, Kinder Morgan Energy Partners initiated a comprehensive emergency response in collaboration with, among others, the City of Burnaby, the BC Ministry of Environment, the National Energy Board, and the National Transportation Safety Board. Cleanup and environmental remediation is near completion. The incident is currently under investigation by Federal and Provincial agencies. We do not expect this matter to have a material adverse impact on our financial position, results of operations or cash flows.
 
On December 20, 2007, Kinder Morgan Energy Partners initiated a lawsuit entitled Trans Mountain Pipeline LP, Trans Mountain Pipeline Inc. and Kinder Morgan Canada Inc. v. The City of Burnaby, et al., Supreme Court of British Columbia, Vancouver Registry No. S078716. The suit alleges that the City of Burnaby and its agents are liable for damages including, but not limited to, all costs and expenses incurred by Kinder Morgan Energy Partners as a result of the rupture of the pipeline and subsequent release of crude oil. Defendants have denied liability and discovery has begun.
 
Litigation Relating to the “Going Private” Transaction
 
Beginning on May 29, 2006, the day after the proposal for the Going Private transaction was announced, and in the days following, eight putative Class Action lawsuits were filed in Harris County (Houston), Texas and seven putative Class Action lawsuits were filed in Shawnee County (Topeka), Kansas against, among others, Kinder Morgan, Inc., its Board of Directors, the Special Committee of the Board of Directors, and several corporate officers.
 
By order of the Harris County District Court dated June 26, 2006, each of the eight Harris County cases were consolidated into the Crescente v. Kinder Morgan, Inc. et al case, Cause No. 2006-33011, in the 164th Judicial District Court, Harris County, Texas, which challenges the proposed transaction as inadequate and unfair to Kinder Morgan, Inc.’s public stockholders. On September 8, 2006, interim class counsel filed their Consolidated Petition for Breach of Fiduciary Duty and Aiding and Abetting in which they alleged that Kinder Morgan, Inc.’s board of directors and certain members of senior management breached their fiduciary duties and the Sponsor Investors aided and abetted the alleged breaches of fiduciary duty in entering into the merger agreement. They sought, among other things, to enjoin the merger, rescission of the merger agreement, disgorgement of any improper profits received by the defendants, and attorneys’ fees. Defendants filed Answers to
 

 
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the Consolidated Petition on October 9, 2006, denying the plaintiffs’ substantive allegations and denying that the plaintiffs are entitled to relief.
 
By order of the District Court of Shawnee County, Kansas dated June 26, 2006, each of the seven Kansas cases were consolidated into the Consol. Case No. 06 C 801; In Re Kinder Morgan, Inc. Shareholder Litigation; in the District Court of Shawnee County, Kansas, Division 12. On August 28, 2006, the plaintiffs filed their Consolidated and Amended Class Action Petition in which they alleged that Kinder Morgan’s board of directors and certain members of senior management breached their fiduciary duties and the Sponsor Investors aided and abetted the alleged breaches of fiduciary duty in entering into the merger agreement. They sought, among other things, to enjoin the stockholder vote on the merger agreement and any action taken to effect the acquisition of Kinder Morgan and its assets by the buyout group, damages, disgorgement of any improper profits received by the defendants, and attorney’s fees.
 
In late 2006, the Kansas and Texas Courts appointed the Honorable Joseph T. Walsh to serve as Special Master in both consolidated cases “to control all of the pretrial proceedings in both the Kansas and Texas Class Actions arising out of the proposed private offer to purchase the stock of the public shareholders of Kinder Morgan, Inc.” On November 21, 2006, the plaintiffs in In Re Kinder Morgan, Inc. Shareholder Litigation filed a Third Amended Class Action Petition with Special Master Walsh. This Petition was later filed under seal with the Kansas District Court on December 27, 2006.
 
Following extensive expedited discovery, the Plaintiffs in both consolidated actions filed an application for a preliminary injunction to prevent the holding of a special meeting of shareholders for the purposes of voting on the proposed merger, which was scheduled for December 19, 2006.
 
On December 18, 2006, Special Master Walsh issued a Report and Recommendation concluding, among other things, that “plaintiffs have failed to demonstrate the probability of ultimate success on the merits of their claims in this joint litigation.” Accordingly, the Special Master concluded that the plaintiffs were “not entitled to injunctive relief to prevent the holding of the special meeting of KMI shareholders scheduled for December 19, 2006.”
 
Plaintiffs moved for class certification in January, 2008. Defendants opposed this motion, which is currently pending.
 
On January 9, 2009, Special Master Walsh issued a Report recommending that the class should be comprised of all holders of Kinder Morgan, Inc. common stock, during the period August 28, 2006 (the date the merger agreement was signed) through May 30, 2007 (the date the merger closed) and their transferees, successors and assigns. Excluded from the Class are defendants and any person, firm, trust, corporation or other entity related to or affiliated with any defendant. Special Master Walsh also recommended that Dr. Geiger and Mr. Wilson, but not Mr. Land, be appointed as Class Representatives. The Special Master’s recommendation is currently pending before the Kansas trial court.
 
In August, September and October, 2008, the Plaintiffs in both consolidated cases voluntarily dismissed without prejudice the claims against those Kinder Morgan, Inc.’s directors who did not participate in the buyout (including the dismissal of the members of the special committee of the board of directors), Kinder Morgan, Inc. and Knight Acquisition, Inc. In addition, on November 19, 2008, by agreement of the parties, the Texas trial court issued an order staying all proceedings in the Texas actions until such time as a final judgment shall be issued in the Kansas actions. The effect of this stay is that the consolidated matters will proceed only in the Kansas trial court.
 
The parties are currently engaged in consolidated discovery in these matters.
 
On August 24, 2006, a civil action entitled City of Inkster Policeman and Fireman Retirement System, Derivatively on Behalf of Kinder Morgan, Inc., Plaintiffs v. Richard D. Kinder, Michael C. Morgan, William v. Morgan, Fayez Sarofim, Edward H. Austin, Jr., William J. Hybl, Ted A. Gardner, Charles W. Battey, H.A. True, III, James M. Stanford, Stewart A. Bliss, Edward Randall, III, Douglas W.G. Whitehead, Goldman Sachs Capital Partners, American International Group, Inc., The Carlyle Group, Riverstone Holdings LLC, C. Park Shaper, Steven J. Kean, Scott E. Parker and R. Tim Bradley, Defendants and Kinder Morgan, Inc., Nominal Defendant; Case 2006-52653, was filed in the 270th Judicial District Court, Harris County, Texas. This putative derivative lawsuit was brought against certain of Kinder Morgan, Inc.’s senior officers and directors, alleging that the proposal constituted a breach of fiduciary duties owed to Kinder Morgan, Inc. Plaintiff also contends that the Sponsor Investors aided and abetted the alleged breaches of fiduciary duty. Plaintiff seeks, among other things, to enjoin the defendants from consummating the proposal, a declaration that the proposal is unlawful and unenforceable, the imposition of a constructive trust upon any benefits improperly received by the defendants, and attorney’s fees. In November 2007, defendants filed a Joint Motion to Dismiss for Lack of Jurisdiction, or in the Alternative, Motion for Final Summary Judgment. Plaintiffs opposed the motion. In February 2008, the court entered a Final Order granting defendants’ motion in full, ordering that plaintiff, the City of Inkster Policeman and Fireman Retirement System, take nothing on any and all of its claims against any and all defendants. In April 2008, Plaintiffs filed an appeal of the judgment in favor of all defendants in the Texas Court of Appeal, First District. The appeal is currently pending.
 
Defendants believe that the claims asserted in the litigations regarding the Going Private transaction are legally and factually without merit and intend to vigorously defend against them.
 

 
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Litigation Reserves
 
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 experiences to date, that the ultimate resolution of such items will not have a material adverse impact on our business, financial position, results of operations or cash flows.
 
Additionally, although it is not possible to predict the ultimate outcomes, we believe, based on our experiences to date, that the ultimate resolution of these matters will not have a material adverse impact on our business, financial position, results of operations or cash flows. As of December 31, 2008 and December 31, 2007, we have recorded a total reserve for legal fees, transportation rate cases and other litigation liabilities in the amount of $234.8 million and $249.4 million, respectively. The reserve is primarily related to various claims from lawsuits related to SFPP and the contingent amount is based on both probability of realization and our ability to reasonably estimate liability dollar amounts. We regularly assess the likelihood of adverse outcomes resulting from these claims in order to determine the adequacy of our liability provision.
 
Environmental Matters
 
ExxonMobil Corporation v. GATX Terminals Corporation, Kinder Morgan Liquids Terminals LLC and Support Terminals Services, Inc.
 
On April 23, 2003, Exxon Mobil Corporation (“ExxonMobil”) filed a complaint in the Superior Court of New Jersey, Gloucester County. The lawsuit relates to environmental remediation obligations at a Paulsboro, New Jersey liquids terminal owned by ExxonMobil from the mid-1950s through November 1989, by GATX Terminals Corporation (“GATX”). from 1989 through September 2000, later owned by Support Terminals Services, Inc. (“Support Terminals”). The terminal is now owned by Pacific Atlantic Terminals, LLC, (PAT) and it too is a party to the lawsuit.
 
The complaint seeks any and all damages related to remediating all environmental contamination at the terminal, and, according to the New Jersey Spill Compensation and Control Act, treble damages may be available for actual dollars incorrectly spent by the successful party in the lawsuit. The parties are currently involved in mandatory mediation and met in June and October 2008. No progress was made at any of the mediations. The mediation judge will now refer the case back to the litigation court room.
 
On June 25, 2007, the New Jersey Department of Environmental Protection, the Commissioner of the New Jersey Department of Environmental Protection and the Administrator of the New Jersey Spill Compensation Fund, referred to collectively as the plaintiffs, filed a complaint against ExxonMobil and Kinder Morgan Liquids Terminals LLC, f/k/a GATX. The complaint was filed in Gloucester County, New Jersey. Both ExxonMobil and Kinder Morgan Liquids Terminals LLC filed third party complaints against Support Terminals seeking to bring Support Terminals into the case. Support Terminals filed motions to dismiss the third party complaints, which were denied. Support Terminals is now joined in the case and it filed an Answer denying all claims.
 
The plaintiffs seek the costs and damages that the plaintiffs allegedly have incurred or will incur as a result of the discharge of pollutants and hazardous substances at the Paulsboro, New Jersey facility. The costs and damages that the plaintiffs seek include cleanup costs and damages to natural resources. In addition, the plaintiffs seek an order compelling the defendants to perform or fund the assessment and restoration of those natural resource damages that are the result of the defendants’ actions. As in the case brought by ExxonMobil against GATX, the issue is whether the plaintiffs’ claims are within the scope of the indemnity obligations between GATX (and therefore, Kinder Morgan Liquids Terminals LLC) and Support Terminals. The court may consolidate the two cases.
 
Mission Valley Terminal Lawsuit
 
In August 2007, the City of San Diego, on its own behalf and purporting to act on behalf of the People of the state of California, filed a lawsuit against Kinder Morgan Energy Partners and several affiliates seeking injunctive relief and unspecified damages allegedly resulting from hydrocarbon and MTBE impacted soils and groundwater beneath the city’s stadium property in San Diego arising from historic operations at the Mission Valley terminal facility. The case was filed in the Superior Court of California, San Diego County, case number 37-2007-00073033-CU-OR-CTL. On September 26, 2007, Kinder Morgan Energy Partners removed the case to the United States District Court, Southern District of California, case number 07CV1883WCAB. On October 3, 2007, Kinder Morgan Energy Partners filed a Motion to Dismiss all counts of the Complaint. The court denied in part and granted in part the Motion to Dismiss and gave the City leave to amend their complaint. The City submitted its Amended Complaint and we filed an Answer. The parties have commenced with discovery. This site has been, and currently is, under the regulatory oversight and order of the California Regional Water Quality Control Board.
 

 
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In June 2008, we received an Administrative Civil Liability Complaint from the California Regional Water Quality Control Board for violations and penalties associated with permitted surface water discharge from the remediation system operating at the Mission Valley terminal facility. In December 2008, we settled the Administrative Civil Liability Complaint with the RWQCB, paying a civil penalty of $0.2 million.
 
State of Texas v. Kinder Morgan Petcoke, L.P.
 
Harris County, Texas Criminal Court No. 11, Cause No. 1571148. On February 24, 2009 a subsidiary of Kinder Morgan Energy Partners, Kinder Morgan Petcoke, L.P., was served with a misdemeanor summons alleging the unintentional discharge of petcoke into the Houston Ship Channel during maintenance activities. The maximum potential fine for the alleged violation is $0.2 million. The allegations in the summons are currently under investigation.
 
Other Environmental
 
We are subject to environmental cleanup and enforcement actions from time to time. In particular, the federal Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) generally imposes joint and several liability for cleanup and enforcement costs on current or predecessor owners and operators of a site, among others, without regard to fault or the legality of the original conduct. Our operations are also subject to federal, state and local laws and regulations relating to protection of the environment. Although we believe our operations are in substantial compliance with applicable environmental law and regulations, risks of additional costs and liabilities are inherent in pipeline, terminal and carbon dioxide field and oil field operations, and there can be no assurance that we will not incur significant costs and liabilities. Moreover, it is possible that other developments, such as increasingly stringent environmental laws, regulations and enforcement policies thereunder, and claims for damages to property or persons resulting from our operations, could result in substantial costs and liabilities to us.
 
We are currently involved in several governmental proceedings involving air, water and waste violations issued by various governmental authorities related to compliance with environmental regulations. As we receive notices of non-compliance, we negotiate and settle these matters. We do not believe that these violations will have a material adverse affect on our business.
 
We are also currently involved in several governmental proceedings involving groundwater and soil remediation efforts under administrative orders or related state remediation programs issued by various regulatory authorities related to compliance with environmental regulations associated with our assets. We have established a reserve to address the costs associated with the cleanup.
 
In addition, we are involved with and have been identified as a potentially responsible party in several federal and state superfund sites. Environmental reserves have been established for those sites where our contribution is probable and reasonably estimable. In addition, we are from time to time involved in civil proceedings relating to damages alleged to have occurred as a result of accidental leaks or spills of refined petroleum products, natural gas liquids, natural gas and carbon dioxide. See “Pipeline Integrity and Releases,” above for additional information with respect to ruptures and leaks from our pipelines.
 
General
 
Although it is not possible to predict the ultimate outcomes, we believe that the resolution of the environmental matters set forth in this note will not have a material adverse effect on our business, financial position, results of operations or cash flows. However, we are not able to reasonably estimate when the eventual settlements of these claims will occur and changing circumstances could cause these matters to have a material adverse impact. As of December 31, 2008 and December 31, 2007, we have accrued an environmental reserve of $85.0 million and $102.6 million, respectively, and we believe the establishment of this environmental reserve is adequate such that the resolution of pending environmental matters will not have a material adverse impact on our business, cash flows, financial position or results of operation. Additionally, many factors may change in the future affecting our reserve estimates, such as (i) regulatory changes, (ii) groundwater and land use near our sites, and (iii) changes in cleanup technology. Associated with the environmental reserve, we have recorded a receivable of $20.9 million as of both December 31, 2008 and December 31, 2007 for expected cost recoveries that have been deemed probable.
 
22. Recent Accounting Pronouncements
 
SFAS No. 157 and associated pronouncements
 
For information on SFAS No. 157 and associated pronouncements, see Note 15 under the heading “SFAS No. 157.”
 
SFAS No. 159
 
On February 15, 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities. This Statement provides companies with an option to report selected financial assets and liabilities at fair value. The
 

 
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Statement’s objective is to reduce both complexity in accounting for financial instruments and the volatility in earnings caused by measuring related assets and liabilities differently. The Statement also establishes presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities.
 
SFAS No. 159 requires companies to provide additional information that will help investors and other users of financial statements to more easily understand the effect of the company’s choice to use fair value on its earnings. It also requires entities to display the fair value of those assets and liabilities for which the company has chosen to use fair value on the face of the balance sheet. The Statement does not eliminate disclosure requirements included in other accounting standards, including requirements for disclosures about fair value measurements included in SFAS No. 157, discussed in Note 15, “SFAS No. 157,” and SFAS No. 107 Disclosures about Fair Value of Financial Instruments.
 
This Statement was adopted by us effective January 1, 2008, at which time no financial assets or liabilities, not previously required to be recorded at fair value by other authoritative literature, were designated to be recorded at fair value. As such, the adoption of this Statement did not have any impact on our consolidated financial statements.
 
SFAS No. 141(R)
 
On December 4, 2007, the FASB issued SFAS No. 141R (revised 2007), Business Combinations. Although this Statement amends and replaces SFAS No. 141, it retains the fundamental requirements in SFAS No. 141 that (i) the purchase method of accounting be used for all business combinations and (ii) an acquirer be identified for each business combination. SFAS No. 141R defines the acquirer as the entity that obtains control of one or more businesses in the business combination and establishes the acquisition date as the date that the acquirer achieves control. This Statement applies to all transactions or other events in which an entity (the acquirer) obtains control of one or more businesses (the acquiree), including combinations achieved without the transfer of consideration; however, this Statement does not apply to a combination between entities or businesses under common control.
 
Significant provisions of SFAS No. 141R concern principles and requirements for how an acquirer (i) recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree, (ii) recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase and (iii) determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination.
 
This Statement applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008 (January 1, 2009 for us). The adoption of this Statement did not have any impact on our consolidated financial statements.
 
SFAS No. 160
 
On December 4, 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements – an amendment of ARB No. 51. This Statement changes the accounting and reporting for noncontrolling interests in consolidated financial statements. A noncontrolling interest, sometimes referred to as a minority interest, is the portion of equity in a subsidiary not attributable, directly or indirectly, to a parent.
 
Specifically, SFAS No. 160 establishes accounting and reporting standards that require (i) the ownership interests in subsidiaries held by parties other than the parent to be clearly identified, labeled, and presented in the consolidated balance sheet within equity, but separate from the parent’s equity, (ii) the equity amount of consolidated net income attributable to the parent and to the noncontrolling interest to be clearly identified and presented on the face of the consolidated income statement (consolidated net income and comprehensive income will be determined without deducting minority interest, however, earnings-per-share information will continue to be calculated on the basis of the net income attributable to the parent’s shareholders); and (iii) changes in a parent’s ownership interest while the parent retains its controlling financial interest in its subsidiary to be accounted for consistently and similarly—as equity transactions.
 
This Statement is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008 (January 1, 2009 for us). SFAS No. 160 is to be applied prospectively as of the beginning of the fiscal year in which it is initially applied, except for its presentation and disclosure requirements, which are to be applied retrospectively for all periods presented. The adoption of this Statement did not have a material impact on our consolidated financial statements, but it did change our consolidated financial statements’ presentation and disclosures of noncontrolling interests.
 
SFAS No. 161
 
On March 19, 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities. This Statement amends SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities and is intended to help investors better understand how derivative instruments and hedging activities affect an entity’s financial position, financial
 

 
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performance and cash flows through enhanced disclosure requirements. The enhanced disclosures include, among other things, (i) a tabular summary of the fair value of derivative instruments and their gains and losses, (ii) disclosure of derivative features that are credit-risk–related to provide more information regarding an entity’s liquidity and (iii) cross-referencing within footnotes to make it easier for financial statement users to locate important information about derivative instruments.
 
This Statement is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008 (January 1, 2009 for us). This Statement expands and enhances disclosure requirements only, and as such, the adoption of this Statement did not have any impact on our consolidated financial statements.
 
FSP No. FAS 142-3
 
On April 25, 2008, the FASB issued FASB Staff Position (“FSP”) No. FAS 142-3, Determination of the Useful Life of Intangible Assets. This FSP amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS No. 142, Goodwill and Other Intangible Assets. This FSP is effective for financial statements issued for fiscal years beginning after December 15, 2008 (January 1, 2009 for us), and interim periods within those fiscal years. The adoption of this FSP did not have a material impact on our consolidated financial statements.
 
SFAS No. 162
 
On May 9, 2008, the FASB issued SFAS No. 162, The Hierarchy of Generally Accepted Accounting Principles. This Statement is intended to improve financial reporting by identifying a consistent framework, or hierarchy, for selecting accounting principles to be used in preparing financial statements that are presented in conformity with GAAP for nongovernmental entities.
 
SFAS No. 162 establishes that the GAAP hierarchy should be directed to entities because it is the entity (not its auditor) that is responsible for selecting accounting principles for financial statements that are presented in conformity with GAAP. SFAS No. 162 is effective 60 days following the U.S. Securities and Exchange Commission’s approval of the Public Company Accounting Oversight Board Auditing amendments to AU Section 411, The Meaning of Present Fairly in Conformity with Generally Accepted Accounting Principles, and is only effective for nongovernmental entities. We expect the adoption of this Statement will have no effect on our consolidated financial statements.
 
EITF 08-6
 
On November 24, 2008, the Financial Accounting Standards Board ratified the consensus reached by the Emerging Issues Task Force (“EITF”) on Issue No. 08-6, or EITF 08-6, Equity Method Investment Accounting Considerations. EITF 08-6 clarifies certain accounting and impairment considerations involving equity method investments. This Issue is effective for fiscal years beginning on or after December 15, 2008 (January 1, 2009 for us), and interim periods within those fiscal years. The guidance in this Issue is to be applied prospectively for all financial statements presented. The adoption of this Issue did not have any impact on our consolidated financial statements.
 
FSP No. FAS 140-4 and FIN 46(R)-8
 
On December 11, 2008, the FASB issued FSP FAS 140-4 and FIN 46(R)-8 Disclosures by Public Entities (Enterprises) about Transfers of Financial Assets and Interests in Variable Interest Entities. These two pronouncements require enhanced disclosure and transparency by public entities about their involvement with variable interest entities and their continuing involvement with transferred financial assets. The disclosure requirements in these two pronouncements are effective for annual and interim periods ending after December 15, 2008 (December 31, 2008 for us). The adoption of these two pronouncements did not have any impact on our consolidated financial statements.
 
FSP No. FAS 132(R)-1
 
On December 30, 2008, the FASB issued FSP No. FAS 132(R)-1, Employer’s Disclosures About Postretirement Benefit Plan Assets, effective for financial statements ending after December 15, 2009 (December 31, 2009 for us). This FSP requires additional disclosure of pension and postretirement plan holdings regarding (i) investment asset classes, (ii) fair value measurement of assets, (iii) investment strategies, (iv) asset risk and (v) rate-of-return assumptions. We do not expect this FSP to have a material impact on our consolidated financial statements.
 
Securities and Exchange Commission’s Final Rule on Oil and Gas Disclosure Requirements
 
On December 31, 2008, the Securities and Exchange Commission (“SEC”) issued its final rule, Modernization of Oil and Gas Reporting, which revises the disclosures required by oil and gas companies. The SEC disclosure requirements for oil and gas companies have been updated to include expanded disclosure for oil and gas activities, and certain definitions have also been changed that will impact the determination of oil and gas reserve quantities. The provisions of this final rule are effective for
 

 
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registration statements filed on or after January 1, 2010, and for annual reports for fiscal years ending on or after December 31, 2009. We are currently reviewing the effects of this SEC final rule.
 
23. Subsequent Event
 
On February 2, 2009, Kinder Morgan Energy Partners paid $250 million to retire the principal amount of its 6.30% senior notes that matured on that date.
 
In February and March 2009, Kinder Morgan Energy Partners sold 5,666,000 of its common units in a public offering at a price of $46.95 per unit. Kinder Morgan Energy Partners received net proceeds, after commissions and underwriting expenses, of approximately $260 million for the issuance of these 5,666,000 common units and used the proceeds to reduce the borrowings under its bank credit facility.
 
On February 25, 2009, Kinder Morgan Energy Partners entered into four additional fixed-to-floating interest rate swap agreements having a combined notional principal amount of $1.0 billion related to (i) $200 million 6.00% senior notes due 2017, (ii) $300 million of 5.125% senior notes due 2014, (iii) $25 million 5.00% senior notes due 2013 and (iv) $475 million of 5.95% senior notes due 2018.
 
 
Quarterly Operating Results for 2008 and 2007
 
 
Successor Company
 
Three Months Ended
 
March 31,
2008
  
June 30,
2008
  
September 30,
2008
  
December 31,
2008
 
(In millions)
 
Operating Revenues
$
2,895.0
  
$
3,560.5
  
$
3,296.6
  
$
2,342.7
  
Gas Purchases and Other Costs of Sales
  
1,760.6
    
2,494.1
    
2,179.2
    
1,310.1
  
Other Operating Expenses
  
658.2
    
4,704.5
    
719.1
    
741.1
  
Operating Income (Loss)
  
476.2
    
(3,638.1
)
  
398.3
    
291.5
  
Other Income and (Expenses)
  
(283.3
)
  
(202.8
)
  
(201.5
)
  
(134.4
)
Income (Loss) from Continuing Operations Before Income Taxes
  
192.9
    
(3,840.9
)
  
196.8
    
157.1
  
Income Taxes
  
87.1
    
19.4
    
87.9
    
109.9
  
Income (Loss) from Continuing Operations
  
105.8
    
(3,860.3
)
  
108.9
    
47.2
  
Income (Loss) from Discontinued Operations, Net of Tax
  
(0.1
)
  
(0.3
)
  
(0.2
)
  
(0.3
)
Net Income (Loss)
$
105.7
  
$
(3,860.6
)
$
108.7
  
$
46.9
  
  
 
Predecessor Company
    
Successor Company
 
Three Months
Ended
  
Two Months
Ended
    
One Month
Ended
  
Three Months Ended
 
March 31,
2007
  
May 31,
2007
    
June 30,
2007
  
September 30,
2007
  
December 31,
2007
 
(In millions)
 
    
(In millions)
 
Operating Revenues
$
2,444.4
  
$
1,720.7
      
$
936.9
  
$
2,609.0
  
$
2,848.8
  
Gas Purchases and Other Costs of Sales
  
1,452.5
    
1,037.9
        
557.2
    
1,482.8
    
1,616.6
  
Other Operating Expenses
  
968.0
    
501.9
        
220.5
    
683.2
    
791.6
  
Operating Income
  
23.9
    
180.9
        
159.2
    
443.0
    
440.6
  
Other Income and (Expenses)
  
(181.8
)
  
(120.2
)
      
(110.0
)
  
(278.3
)
  
(178.6
)
Income (Loss) from Continuing Operations Before Income Taxes
  
(157.9
)
  
60.7
        
49.2
    
164.7
    
262.0
  
Income Taxes
  
87.7
    
47.8
        
21.3
    
74.6
    
131.5
  
Income (Loss) from Continuing Operations
  
(245.6
)
  
12.9
        
27.9
    
90.1
    
130.5
  
Income (Loss) from Discontinued Operations, Net of Tax
  
233.2
    
65.4
        
2.3
    
(4.4
)
  
0.6
  
Net Income (Loss)
$
(12.4
)
$
78.3
      
$
30.2
  
$
85.7
  
$
131.1
  


 
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The Supplementary Information on Oil and Gas Producing Activities is presented as required by SFAS No. 69, Disclosures about Oil and Gas Producing Activities. The supplemental information includes capitalized costs related to oil and gas producing activities; costs incurred for the acquisition of oil and gas producing activities, exploration and development activities; and the results of operations from oil and gas producing activities.
 
Supplemental information is also provided for per unit production costs; oil and gas production and average sales prices; the estimated quantities of proved oil and gas reserves; the standardized measure of discounted future net cash flows associated with proved oil and gas reserves; and a summary of the changes in the standardized measure of discounted future net cash flows associated with proved oil and gas reserves.
 
Our capitalized costs consisted of the following:
 
Capitalized Costs Related to Oil and Gas Producing Activities
 
 
Successor Company
    
Predecessor
Company
 
December 31,
    
December 31,
 
2008
  
2007
    
2006
 
(In millions)
    
(In millions)
Consolidated Companies1
                        
Wells and equipment, facilities and other
$
2,595.4
    
$
2,081.3
      
$
1,369.5
  
Leasehold
  
429.8
      
449.3
        
347.4
  
Total proved oil and gas properties
  
3,025.2
      
2,530.6
        
1,716.9
  
Accumulated depreciation and depletion
  
(1,155.6
)
    
(787.6
)
      
(470.2
)
Net capitalized costs
$
1,869.6
    
$
1,743.0
      
$
1,246.7
  
__________
1
Amounts relate to Kinder Morgan CO2 Company, L.P. and its consolidated subsidiaries.
 
Includes capitalized asset retirement costs and associated accumulated depreciation. There are no capitalized costs associated with unproved oil and gas properties for the periods reported.
 
Our costs incurred for property acquisition, exploration and development were as follows:
 
Costs Incurred in Exploration, Property Acquisitions and Development
 
 
Successor Company
    
Predecessor Company
 
Year Ended
December 31,
2008
  
Seven Months
Ended
December 31,
2007
    
Five Months
Ended
May 31,
2007
  
Year Ended
December 31,
2006
 
(In millions)
    
(In millions)
Consolidated Companies1
                                
Property Acquisition
                                
Proved oil and gas properties
$
-
    
$
-
      
$
-
    
$
36.6
  
Development
  
495.2
      
156.9
        
87.5
      
261.8
  
__________
1
Amounts relate to Kinder Morgan CO2 Company, L.P. and its consolidated subsidaries.
 
There are no capitalized costs associated with unproved oil and gas properties for the periods reported. All capital expenditures were made to develop our proved oil and gas properties and no exploration costs were incurred for the periods reported.
 

 
179
 
Item 8:   Financial Statements and Supplementary Data.  (continued)
Knight Form 10-K


Our results of operations from oil and gas producing activities for the year ended December 31, 2008, seven months ended December 31, 2007, five months ended May 31, 2007 and year ended December 31, 2006 are shown in the following table:
 
 
Successor Company
    
Predecessor Company
 
Year Ended
December 31,
2008
  
Seven Months
Ended
December 31,
2007
    
Five Months
Ended
May 31, 2007
  
Year Ended
December 31,
2006
 
(In millions)
    
(In millions)
Consolidated Companies1
                                
Revenues2
$
785.5
    
$
352.0
      
$
237.7
      
524.7
  
Expenses:
                                
Production costs
  
308.4
      
147.2
        
96.7
      
208.9
  
Other operating expenses3
  
99.0
      
34.9
        
22.0
      
66.4
  
Depreciation, depletion and amortization expenses
  
342.2
      
151.9
        
106.6
      
169.4
  
Total expenses
  
749.6
      
334.0
        
225.3
      
444.7
  
Results of operations for oil and gas producing activities
$
35.9
    
$
18.0
      
$
12.4
    
$
80.0
  
__________
1
Amounts relate to Kinder Morgan CO2 Company, L.P. and its consolidated subsidaries.
2
Revenues include losses attributable to our hedging contracts of $693.3 million, $311.5 million, $122.7 million and $441.7 million for the year ended December 31, 2008, seven months ended December 31, 2007, five months ended May 31, 2007 and year ended December 31, 2006, respectively.
3
Consists primarily of carbon dioxide expense.
 
The table below represents estimates, as of December 31, 2008, of proved crude oil, natural gas liquids and natural gas reserves prepared by Netherland, Sewell and Associates, Inc. (independent oil and gas consultants) of Kinder Morgan CO2 Company, L.P. and its consolidated subsidiaries’ interests in oil and gas properties, all of which are located in the state of Texas. This data has been prepared using constant prices and costs, as discussed in subsequent paragraphs of this document. The estimates of reserves and future revenue in this document conforms to the guidelines of the United States Securities and Exchange Commission.
 
We believe the geologic and engineering data examined provides reasonable assurance that the proved reserves are recoverable in future years from known reservoirs under existing economic and operating conditions. Estimates of proved reserves are subject to change, either positively or negatively, as additional information becomes available and contractual and economic conditions change.
 
Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, that is, prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations or declines based upon future conditions. Proved developed reserves are the quantities of crude oil, natural gas liquids and natural gas expected to be recovered through existing investments in wells and field infrastructure under current operating conditions. Proved undeveloped reserves require additional investments in wells and related infrastructure in order to recover the production.
 
During 2008, we filed estimates of our oil and gas reserves for the year 2007 with the Energy Information Administration of the U. S. Department of Energy on Form EIA-23. The data on Form EIA-23 was presented on a different basis, and included 100% of the oil and gas volumes from our operated properties only, regardless of our net interest. The difference between the oil and gas reserves reported on Form EIA-23 and those reported in this report exceeds 5%.
 

 
180
 
Item 8:   Financial Statements and Supplementary Data.  (continued)
Knight Form 10-K


Reserve Quantity Information
 
 
Consolidated Companies
 
Crude Oil
(MBbls)
  
NGLs
(MBbls)
  
Nat. Gas
(MMcf)1
Proved developed and undeveloped reserves as of
                
December 31, 20052
21,567
    
2,884
    
327
  
December 31, 20063
123,978
    
10,333
    
291
  
Revisions of Previous Estimates3,4
10,361
    
2,784
    
1,077
  
Production3
(12,984
)
  
(2,005
)
  
(290
)
December 31, 20073
121,355
    
11,112
    
1,078
  
Revisions of Previous Estimates3,5
(29,536
)
  
(2,490
)
  
695
  
Production3
(13,240
)
  
(1,762
)
  
(499
)
December 31, 20083
78,579
    
6,860
    
1,274
  
  
                
Proved developed reserves as of
                
December 31, 20052
11,965
    
1,507
    
251
  
December 31, 20063
69,073
    
5,877
    
291
  
December 31, 20073
70,868
    
5,517
    
1,078
  
December 31, 20083
53,346
    
4,308
    
1,274
  
__________
1
Natural gas reserves are computed at 14.65 pounds per square inch absolute and 60 degrees Fahrenheit.
2
For the period presented, we accounted for Kinder Morgan Energy Partners under the equity method, therefore, amounts reflect our proportionate share of Kinder Morgan Energy Partners’ proved reserves.
3
Amounts relate to Kinder Morgan CO2 Company, L.P. and its consolidated subsidaries.
4
Associated with an expansion of the carbon dioxide flood project area of the SACROC unit.
5
Predominately due to lower product prices used to determine reserve volumes.
 
The standardized measure of discounted cash flows and summary of the changes in the standardized measure computation from year-to-year are prepared in accordance with SFAS No. 69. The assumptions that underlie the computation of the standardized measure of discounted cash flows may be summarized as follows:
 
 
·
the standardized measure includes our estimate of proved crude oil, natural gas liquids and natural gas reserves and projected future production volumes based upon year-end economic conditions;
 
·
pricing is applied based upon year-end market prices adjusted for fixed or determinable contracts that are in existence at year-end;
 
·
future development and production costs are determined based upon actual cost at year-end;
 
·
the standardized measure includes projections of future abandonment costs based upon actual costs at year-end; and
 
·
a discount factor of 10% per year is applied annually to the future net cash flows.
 
Our standardized measure of discounted future net cash flows from proved reserves were as follows:
 
Standardized Measure of Discounted Future Net Cash Flows From
Proved Oil and Gas Reserves
 
 
December 31,
    
December 31,
 
2008
  
2007
    
2006
 
(In millions)
    
(In millions)
Consolidated Companies1
                        
Future Cash Inflows from Production
$
3,498.0
    
$
12,099.5
      
$
7,534.7
  
Future Production Costs
  
(1,671.6
)
    
(3,536.2
)
      
(2,617.9
)
Future Development Costs2
  
(910.3
)
    
(1,919.2
)
      
(1,256.8
)
Undiscounted Future Net Cash Flows
  
916.1
      
6,644.1
        
3,660.0
  
10% Annual Discount
  
(257.7
)
    
(2,565.7
)
      
(1,452.2
)
Standardized Measure of Discounted Future Net Cash Flows
$
658.4
    
$
4,078.4
      
$
2,207.8
  
__________
1
Amounts relate to Kinder Morgan CO2 Company, L.P. and its consolidated subsidaries.
2
Includes abandonment costs.
 
The following table represents our estimate of changes in the standardized measure of discounted future net cash flows from proved reserves:
 
181
 
Item 8:   Financial Statements and Supplementary Data.  (continued)
Knight Form 10-K


Changes in the Standardized Measure of Discounted Future Net Cash Flows From
Proved Oil and Gas Reserves
 
 
Year Ended December 31,
 
2008
  
2007
  
2006
 
(In millions)
Consolidated Companies1
                      
Present Value as of January
$
4,078.4
    
$
2,207.8
      
3,075.0
  
Changes During the Year
                      
Revenues Less Production and Other Costs2
  
(1,012.4
)
    
(722.1
)
    
(690.0
)
Net Changes in Prices, Production and Other Costs2
  
(3,076.9
)
    
2,153.2
      
(123.0
)
Development Costs Incurred
  
495.2
      
244.5
      
261.8
  
Net Changes in Future Development Costs
  
231.1
      
(547.8
)
    
(446.0
)
Purchases of Reserves in Place
  
—
      
-
      
3.2
  
Revisions of Previous Quantity Estimates3
  
(417.1
)
    
510.8
      
(179.5
)
Accretion of Discount
  
392.9
      
198.1
      
307.4
  
Timing Differences and Other
  
(32.8
)
    
33.9
      
(1.1
)
Net Change For the Year
  
(3,420.0
)
    
1,870.6
      
(867.2
)
Present Value as of December 31
$
658.4
    
$
4,078.4
    
$
2,207.8
  
__________
1
Amounts relate to Kinder Morgan CO2 Company, L.P. and its consolidated subsidaries.
2
Excludes the effect of losses attributable to our hedging contracts of $639.3 million, $434.2 million and $441.7 million for the years ended December 31, 2008, 2007 and 2006, respectively.
3
2008 revisions are predominantly due to lower product prices used to determine reserve volumes. 2007 revisions are associated with an expansion of the carbon dioxide flood project area for the SACROC unit. 2006 revisions are based on lower than expected recoveries from a section of the SACROC unit carbon dioxide flood project.
 
 
None.
 
 
 
As of December 31, 2008, 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 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.
 
 
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework in Internal Control –Integrated Framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2008. The effectiveness of our internal control over financial reporting as of December 31, 2008, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.
 

 
182
 
Item 9A.   Controls and Procedures. (continued)
Knight Form 10-K


Certain businesses we acquired during 2008 were excluded from the scope of our management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2008. The excluded businesses consisted of the following:
 
 
·
the bulk terminal assets we acquired from Chemserve, Inc., effective August 15, 2008; and
 
·
the refined petroleum products storage terminal we acquired from ConocoPhillips, effective December 10, 2008.
 
These businesses, in the aggregate, constituted 0.01% of our total operating revenues for 2008 and 0.16% of our total assets as of December 31, 2008.
 
 
There has been no change in our internal control over financial reporting during the fourth quarter of 2008 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
 
 
None
 

 
183
 
 
Knight Form 10-K


PART III
 


Directors and Executive Officers
 
Set forth below is certain information concerning our directors and executive officers. Our directors are elected annually by, and may be removed by, Knight Midco Inc., as our sole common shareholder. Knight Midco Inc. is indirectly wholly owned by Knight Holdco LLC. All of our officers serve at the discretion of our board of directors. The ages set forth below are as of December 31, 2008.
 
Name
Age
Position
Richard D. Kinder
64
Director, Chairman and Chief Executive Officer
C. Park Shaper
40
Director and President
Steven J. Kean
47
Executive Vice President and Chief Operating Officer
Kenneth A. Pontarelli
45
Director
Kimberly A. Dang
39
Vice President and Chief Financial Officer
David D. Kinder
34
Vice President, Corporate Development and Treasurer
Joseph Listengart
40
Vice President, General Counsel and Secretary
James E. Street
52
Vice President, Human Resources and Administration

Richard D. Kinder is Director, Chairman and Chief Executive Officer of Kinder Morgan Management, Kinder Morgan G.P., Inc. and Knight Inc. Mr. Kinder has served as Director, Chairman and Chief Executive Officer of Kinder Morgan Management since its formation in February 2001. He was elected Director, Chairman and Chief Executive Officer of Knight Inc. in October 1999. He was elected Director, Chairman and Chief Executive Officer of Kinder Morgan G.P., Inc. in February 1997. Mr. Kinder was elected President of Kinder Morgan Management, Kinder Morgan G.P., Inc. and Knight Inc. in July 2004 and served as President until May 2005. He has also served as Chief Manager, and as a member of the Board of Managers, of Knight Holdco LLC since May 2007. Mr. Kinder is the uncle of David Kinder, Vice President, Corporate Development and Treasurer of Kinder Morgan Management, Kinder Morgan G.P., Inc. and Knight Inc.
 
C. Park Shaper is Director and President of Kinder Morgan Management, Kinder Morgan G.P., Inc. and Knight Inc. Mr. Shaper was elected President of Kinder Morgan Management, Kinder Morgan G.P., Inc. and Knight Inc. in May 2005. He served as Executive Vice President of Kinder Morgan Management, Kinder Morgan G.P., Inc. and Knight Inc. from July 2004 until May 2005. Mr. Shaper was elected Director of Kinder Morgan Management and Kinder Morgan G.P., Inc. in January 2003 and of Knight Inc. in May 2007. He was elected Vice President, Treasurer and Chief Financial Officer of Kinder Morgan Management upon its formation in February 2001, and served as its Treasurer until January 2004, and its Chief Financial Officer until May 2005. He was elected Vice President, Treasurer and Chief Financial Officer of Knight Inc. in January 2000, and served as its Treasurer until January 2004, and its Chief Financial Officer until May 2005. Mr. Shaper was elected Vice President, Treasurer and Chief Financial Officer of Kinder Morgan G.P., Inc. in January 2000, and served as its Treasurer until January 2004 and its Chief Financial Officer until May 2005. He has also served as President, and as a member of the Board of Managers, of Knight Holdco LLC since May 2007. He received a Masters of Business Administration degree from the J.L. Kellogg Graduate School of Management at Northwestern University. Mr. Shaper also has a Bachelor of Science degree in Industrial Engineering and a Bachelor of Arts degree in Quantitative Economics from Stanford University. Mr. Shaper is also a trust manager of Weingarten Realty Investors.
 
Steven J. Kean is Executive Vice President and Chief Operating Officer of Kinder Morgan Management, Kinder Morgan G.P., Inc. and Knight Inc. Mr. Kean was elected Executive Vice President and Chief Operating Officer of Kinder Morgan Management, Kinder Morgan G.P., Inc. and Knight Inc. in January 2006. He served as Executive Vice President, Operations of Kinder Morgan Management, Kinder Morgan G.P., Inc. and Knight Inc. from May 2005 to January 2006. He served as President, Texas Intrastate Pipeline Group from June 2002 until May 2005. He served as Vice President of Strategic Planning for the Kinder Morgan Gas Pipeline Group from January 2002 until June 2002. He has also served as Chief Operating Officer, and as a member of the Board of Managers, of Knight Holdco LLC since May 2007. Mr. Kean received his Juris Doctor from the University of Iowa in May 1985 and received a Bachelor of Arts degree from Iowa State University in May 1982.
 
Kenneth A. Pontarelli is a Director of Knight Inc. Mr. Pontarelli is a Managing Director of Goldman Sachs & Co. See Item 12, “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters” for details regarding Goldman Sachs’ ownership of Knight Holdco LLC units. Mr. Pontarelli was elected Director of Knight Inc. upon the consummation of the Going Private transaction in May 2007. He has also served as member of the Board of Managers of Knight Holdco LLC since May 2007. He joined Goldman Sachs & Co. in 1997 and was appointed Managing Director in 2004. Mr. Pontarelli currently serves on the board of directors of CVR Energy, Inc., CCS Inc., Cobalt International Energy, L.P. and Energy Future Holdings Corp. He received a B.A. from Syracuse University and an M.B.A. from Harvard Business School.
 

 
184
 
Item 10.   Directors, Executive Officers and Corporate Governance.(continued)
Knight Form 10-K


Kimberly A. Dang is Vice President and Chief Financial Officer of Kinder Morgan Management, Kinder Morgan G.P., Inc. and Knight Inc. Mrs. Dang was elected Chief Financial Officer of Kinder Morgan Management, Kinder Morgan G.P., Inc. and Knight Inc. in May 2005. She served as Treasurer of Kinder Morgan Management, Kinder Morgan G.P., Inc. and Knight Inc. from January 2004 to May 2005. She was elected Vice President, Investor Relations of Kinder Morgan Management, Kinder Morgan G.P., Inc. and Knight Inc. in July 2002 and served in that role until January 2009. From November 2001 to July 2002, she served as Director, Investor Relations of Kinder Morgan Management, Kinder Morgan G.P., and Knight Inc. She has also served as Chief Financial Officer of Knight Holdco LLC since May 2007. Mrs. Dang has received a Masters in Business Administration degree from the J.L. Kellogg Graduate School of Management at Northwestern University and a Bachelor of Business Administration degree in accounting from Texas A&M University.
 
David D. Kinder is Vice President, Corporate Development and Treasurer of Kinder Morgan Management, Kinder Morgan G.P., Inc. and Knight Inc. Mr. Kinder was elected Treasurer of Kinder Morgan Management, Kinder Morgan G.P., Inc. and Knight Inc. in May 2005. He was elected Vice President, Corporate Development of Kinder Morgan Management, Kinder Morgan G.P., Inc. and Knight Inc. in October 2002. He served as manager of corporate development for Knight Inc. and Kinder Morgan G.P., Inc. from January 2000 to October 2002. He has also served as Treasurer of Knight Holdco LLC since May 2007. Mr. Kinder graduated cum laude with a Bachelors degree in Finance from Texas Christian University in 1996. Mr. Kinder is the nephew of Richard D. Kinder.
 
Joseph Listengart is Vice President, General Counsel and Secretary of Kinder Morgan Management, Kinder Morgan G.P., Inc. and Knight Inc. Mr. Listengart was elected Vice President, General Counsel and Secretary of Kinder Morgan Management upon its formation in February 2001. He was elected Vice President and General Counsel of Kinder Morgan G.P., Inc. and Vice President, General Counsel and Secretary of Knight Inc. in October 1999. Mr. Listengart was elected Secretary of Kinder Morgan G.P., Inc. in November 1998 and has been an employee of Kinder Morgan G.P., Inc. since March 1998. He has also served as General Counsel and Secretary of Knight Holdco LLC since May 2007. Mr. Listengart received his Masters in Business Administration from Boston University in January 1995, his Juris Doctor, magna cum laude, from Boston University in May 1994, and his Bachelor of Arts degree in Economics from Stanford University in June 1990.
 
James E. Street is Vice President, Human Resources and Administration of Kinder Morgan Management, Kinder Morgan G.P., Inc. and Knight Inc. Mr. Street was elected Vice President, Human Resources and Administration of Kinder Morgan Management upon its formation in February 2001. He was elected Vice President, Human Resources and Administration of Kinder Morgan G.P., Inc. and Knight Inc. in August 1999. Mr. Street received a Masters of Business Administration degree from the University of Nebraska at Omaha and a Bachelor of Science degree from the University of Nebraska at Kearney.
 
Compensation Committee Interlocks and Insider Participation
 
Our board has no separate compensation committee. Mr. Richard D. Kinder as Chief Manager of Knight Holdco makes compensation decisions with respect to our executive officers. None of our executive officers served during 2008 on a board of directors of another entity which has employed any of the members of our board.
 
Corporate Governance
 
Knight Midco Inc. is our sole common shareholder. As a result, Knight Midco Inc. elects all of our directors and our board of directors does not have a nominating and governance committee or a committee that serves a similar purpose.
 
Mr. Shaper and Mr. Pontarelli comprise our audit committee as specified in Section 3(a)(58)(A) of the Securities Exchange Act of 1934. Our board has determined that C. Park Shaper is an “audit committee financial expert.” Mr. Shaper is also our President and is therefore not independent.
 
We make available free of charge within the “Investors” section of our Internet website, at www.kindermorgan.com, our code of business conduct and ethics (which applies to our senior financial and accounting officers and our chief executive officer, among others). Requests for copies may be directed to Investor Relations, Knight Inc., 500 Dallas Street, Suite 1000, Houston, Texas 77002 or telephone (713) 369-9490. We intend to disclose any amendments to our code of business conduct and ethics, and any waiver from a provision of that code granted to our executive officers or directors, that otherwise would be required to be disclosed on a Form 8-K, on our website within four business days following such amendment or waiver. The information contained on or connected to our Internet website is not incorporated by reference into this report and should not be considered part of any report that we file with or furnish to the Securities and Exchange Commission.
 

 

 
185
 
 
Knight Form 10-K


 
Our executive officers also serve in the same capacities as executive officers of Kinder Morgan G.P., Inc., the general partner of Kinder Morgan Energy Partners, and of Kinder Morgan Management, the delegate of Kinder Morgan G.P., Inc. Certain of our executive officers also serve in the same capacities as officers of Knight Holdco LLC, our privately owned parent company. Except as identified otherwise, all information in this Item 11 with respect to compensation of executive officers describes the total compensation received by those persons in all capacities for services rendered to us and our affiliates, including Kinder Morgan Energy Partners, Kinder Morgan G.P., Inc., Kinder Morgan Management and Knight Holdco LLC. In this Item 11, “we,” “our” or “us” refers to Knight Inc. and, where appropriate, Kinder Morgan Energy Partners, Kinder Morgan G.P., Inc. and Kinder Morgan Management.
 
Our board does not have a separately designated compensation committee. Mr. Richard D. Kinder as Chief Manager of Knight Holdco makes compensation decisions with respect to our executive officers; however, increases in the compensation of our officers and other management personnel who own units of Knight Holdco LLC have to be further approved by Knight Holdco’s board of managers.
 
The compensation committee of the board of directors of Kinder Morgan Management, which committee is generally composed of three independent directors, determines the compensation to be paid by Kinder Morgan Energy Partners to KMGP Services Company, Inc.’s employees and Kinder Morgan Management’s and Kinder Morgan G.P., Inc.’s executive officers. For further information regarding KMGP Services Company, Inc., see “Description of Business—Employees” within Items 1 and 2 of this report. As described below, Kinder Morgan Management’s compensation committee is aware of the compensation paid to such officers by entities such as us and Knight Holdco LLC, but makes its compensation determinations at its sole discretion.
 
Compensation Discussion and Analysis
 
Program Objectives
 
We seek to attract and retain executives who will help us achieve our primary business strategy objective of growing the value of our portfolio of businesses. To help accomplish this goal, we have designed an executive compensation program that rewards individuals with competitive compensation that consists of a mix of cash, benefit plans and long-term compensation, with a majority of executive compensation tied to the “at risk” portions of the annual cash bonus.
 
The key objectives of our executive compensation program are to attract, motivate and retain executives who will advance our overall business strategies and objectives of growing the value of our portfolio of businesses. We believe that an effective executive compensation program should link total compensation to financial performance and to the attainment of short- and long-term strategic, operational, and financial objectives. We also believe it should provide competitive total compensation opportunities at a reasonable cost. In designing our executive compensation program, we have recognized that our executives have a much greater portion of their overall compensation at-risk than do our other employees; consequently, we have tried to establish the at-risk portions of our executive total compensation at levels that recognize their much increased level of responsibility and their ability to influence business results.
 
Currently, our executive compensation program is principally composed of two elements: (i) base cash salary; and (ii) possible annual cash bonus (reflected in the Summary Compensation Table below as Non-Equity Incentive Plan Compensation). Until October 2008, we paid our executive officers a base salary not to exceed $200,000, which we believe is below annual base salaries for comparable positions in the marketplace, based upon independent salary surveys in which we participate. The cap for our executive officers’ base salaries was raised to an annual amount not to exceed $300,000. We believe the base salaries paid to our executive officers continue to be below the industry average for similarly positioned executives. While not awarded by us, Mr. Richard D. Kinder was aware of the units awarded by Knight Holdco LLC (as discussed more fully below) and took these awards into account as components of the total compensation received by our executive officers.
 
In addition, we believe that the compensation of our Chief Executive Officer, Chief Financial Officer and the executives named below, collectively referred to in this Item 11 as our named executive officers, should be directly and materially tied to the financial performance of Kinder Morgan Energy Partners and us. Therefore, the majority of our named executive officers’ compensation is allocated to the “at risk” portion of our compensation program—the annual cash bonus. Accordingly, for 2008, our executive compensation was weighted toward the cash bonus, payable on the basis of achieving (i) an earnings before interest, taxes, depreciation, depletion and amortization (referred to as EBITDA) less capital spending target by us; and (ii) a cash distribution per common unit target by Kinder Morgan Energy Partners.
 
We periodically compare our executive compensation components with market information. The purpose of this comparison is to ensure that our total compensation package operates effectively, remains both reasonable and competitive with the energy industry, and is generally comparable to the compensation offered by companies of similar size and scope as us. We
 

 
186
 
Item 11. Executive Compensation  (continued)
Knight Form 10-K


also keep abreast of current trends, developments, and emerging issues in executive compensation, and if appropriate, will obtain advice and assistance from outside legal, compensation or other advisors.
 
We have endeavored to design our executive compensation program and practices with appropriate consideration of all tax, accounting, legal and regulatory requirements. Section 162(m) of the Internal Revenue Code limits the deductibility of certain compensation for our executive officers to $1,000,000 of compensation per year; however, if specified conditions are met, certain compensation may be excluded from consideration of the $1,000,000 limit. Since the bonuses paid to our executive officers are paid under our Annual Incentive Plan as a result of reaching designated financial targets established by Mr. Richard D. Kinder and Kinder Morgan Management’s compensation committee, we expect that all compensation paid to our executives would qualify for deductibility under federal income tax rules. Though we are advised that limited partnerships such as Kinder Morgan Energy Partners, and private companies, such as us, are not subject to section 162(m), we and Kinder Morgan Energy Partners have chosen to generally operate as if this code section does apply to us and Kinder Morgan Energy Partners as a measure of appropriate governance.
 
Prior to 2006, long-term equity awards comprised a third element of our executive compensation program. These awards primarily consisted of grants of restricted Kinder Morgan, Inc., or KMI stock, and grants of non-qualified options to acquire shares of KMI common stock, both pursuant to the provisions of KMI’s Amended and Restated 1999 Stock Plan, referred to as the KMI stock plan. Prior to 2003, we used both KMI stock options and restricted KMI stock as the principal components of long-term executive compensation, and beginning in 2003, we used grants of restricted stock exclusively as the principal component of long-term executive compensation. For each of the years ended December 31, 2007 and 2008, no restricted stock or options to purchase shares of KMI, Kinder Morgan Energy Partners or Kinder Morgan Management were granted to any of our named executive officers.
 
Additionally, in connection with the Going Private transaction, Knight Holdco LLC awarded members of our management Class A-1 and Class B units of Knight Holdco LLC. In accordance with SFAS No. 123R, Knight Holdco LLC is required to recognize compensation expense in connection with the Class A-1 and Class B units over the expected life of such units. As a subsidiary of Knight Holdco LLC, we are, under accounting rules, allocated a portion of this compensation expense, although none of us or any of our subsidiaries have any obligation, nor do we expect to pay any amounts in respect of such units. The Class A-1 and Class B units awarded to members of our management may be viewed as a replacement of restricted stock as a component of long-term executive compensation. For more information concerning the Knight Holdco LLC units, see “Elements of Compensation—Other Compensation—Knight Holdco LLC Units” below.
 
Behaviors Designed to Reward
 
Our executive compensation program is designed to reward individuals for advancing our business strategies and the interests of our stakeholders, and we prohibit engaging in any detrimental activities, such as performing services for a competitor, disclosing confidential information or violating appropriate business conduct standards. Each executive is held accountable to uphold and comply with company guidelines, which require the individual to maintain a discrimination-free workplace, to comply with orders of regulatory bodies, and to maintain high standards of operating safety and environmental protection.
 
Unlike many companies, we have no executive perquisites, supplemental executive retirement, non-qualified supplemental defined benefit/contribution, deferred compensation or split dollar life insurance programs for our executive officers. Additionally, we do not have employment agreements (other than with our Chairman and Chief Executive Officer, Richard D. Kinder), special severance agreements or change of control agreements for our executive officers. Our executives are eligible for the same severance policy as our workforce, which caps severance payments to an amount equal to six months of salary. We have no executive company cars or executive car allowances nor do we pay for financial planning services. Additionally, we do not own any corporate aircraft and we do not pay for executives to fly first class. We believe that we are currently below competitive levels for comparable companies in this area of our overall compensation package; however, we have no current plans to change our policy of not offering such executive benefits, perquisite programs or special executive severance arrangements.
 
At his request, Mr. Richard D. Kinder, our Chairman and Chief Executive Officer, receives $1 of base salary per year. Additionally, Mr. Kinder has requested that he receive no annual bonus, unit grants, or other compensation from us. Mr. Kinder does not have any deferred compensation, supplemental retirement or any other special benefit, compensation or perquisite arrangement with us. Each year Mr. Kinder reimburses us for his portion of health care premiums and parking expenses. Mr. Kinder was awarded Class B units by and in Knight Holdco LLC in connection with the Going Private transaction, and while we are, under accounting rules, allocated compensation expense attributable to such Class B units, we have no obligation, nor do we expect, to pay any amounts in connection with the Class B units.
 
Elements of Compensation
 
As outlined above, our executive compensation program currently is principally composed of two elements: (i) a base cash salary; and (ii) a possible annual cash bonus. Mr. Richard D. Kinder reviews and approves annually the financial goals and
 

 
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Item 11. Executive Compensation  (continued)
Knight Form 10-K


objectives of both us and Kinder Morgan Energy Partners that are relevant to the compensation of our named executive officers, other than himself.
 
Information is solicited from relevant members of senior management regarding the performance of our named executive officers and determinations and recommendations are made at the regularly scheduled first quarter board meeting.
 
If any of our executive officers is also an executive officer of Kinder Morgan G.P., Inc. or Kinder Morgan Management, the compensation determination or recommendation (i) may be with respect to the aggregate compensation to be received by such officer from us, Kinder Morgan Management, and Kinder Morgan G.P., Inc. that is to be allocated among them, or alternatively (ii) may be with respect to the compensation to be received by such executive officers from us, Kinder Morgan Management or Kinder Morgan G.P., Inc., as the case may be, in which case such compensation will not be allocated among us, on the one hand, and Kinder Morgan Management, and Kinder Morgan G.P., on the other.
 
Base Salary
 
Base salary is paid in cash. Until October 2008, all of our named executive officers, with the exception of our Chairman and Chief Executive Officer who receives $1 of base salary per year as described above, were paid a base salary of $200,000 per year. The cap for our executive officers’ base salaries was raised to an annual amount not to exceed $300,000. Generally, we believe that our executive officers’ base salaries are below base salaries for executives in similar positions and with similar responsibilities at companies of comparable size and scope, based upon independent salary surveys in which we participate.
 
Possible Annual Cash Bonus (Non-Equity Cash Incentive)
 
Our possible annual cash bonuses are provided for under our Annual Incentive Plan, which became effective January 18, 2005. The overall purpose of our Annual Incentive Plan is to increase our executive officers’ and our employees’ personal stake in the continued success of Kinder Morgan Energy Partners and us by providing to them additional incentives through the possible payment of annual cash bonuses. Under the plan, annual cash bonuses are budgeted for at the beginning of each year and may be paid to our executive officers and other employees depending on whether we and our subsidiaries (including Kinder Morgan Energy Partners) meet certain performance objectives. Assuming the performance objectives are met, the budgeted pool of bonus dollars is further assessed and potentially decreased or increased based on our and our subsidiaries’ (including Kinder Morgan Energy Partners’) overall performance in a variety of areas, including safety and environmental goals and regulatory compliance.
 
Once the aggregate pool of bonus dollars is determined, further assessment is done at the business segment level. Each business segment’s financial performance as well as its safety and environmental goals and regulatory compliance are assessed and factored, positively or negatively, into the amount of bonus dollars allocated to that business segment. The business unit’s safety and environmental goals and regulatory compliance are assessed against its performance in these areas in previous years and industry benchmarks. These assessments as well as individual performance factor into bonus awards at the business segment level.
 
Our and our subsidiaries’ (including Kinder Morgan Energy Partners) overall performance, including whether we have met the performance objectives as well as how, on an overall basis, we have performed with respect to a variety of areas such as safety and environmental goals and regulatory compliance, negatively or positively, impacts the bonuses of our named executive officers. Also, with respect to our named executive officers, individual performance impacts their bonuses. Our named executive officers have different areas of responsibility that require different skill sets. Consequently, many of the skills and aspects of performance taken into account in determining the bonus awards for the respective named executive officers differ based on their areas of responsibility. However, some skills, such as working within a budget, are applicable for all of the executive officers. While no formula is used in assessing individual performance, the process of assessing the performance of each of the named executive officers is consistent, with each such officer being assessed relative to the officer’s performance of his or her job in preceding years as well as with respect to specific matters assigned to the officer over the course of the year. Individual performance, as described above, as well as safety and environmental goals and regulatory compliance were taken into account with respect to the 2008 awards.
 
All of our employees and the employees of our subsidiaries, including KMGP Services Company, Inc., are eligible to participate in the plan, except employees who are included in a unit of employees covered by a collective bargaining agreement unless such agreement expressly provides for eligibility under the plan. However, only eligible employees who are selected by Mr. Richard D. Kinder and Kinder Morgan Management’s compensation committee will actually participate in the plan and receive bonuses.
 
The plan consists of two components: the executive plan component and the non-executive plan component. Our Chairman and Chief Executive Officer and all employees who report directly to the Chairman are eligible for the executive plan component; however, as stated elsewhere in this “Compensation Discussion and Analysis”, Mr. Richard D. Kinder, our Chairman and Chief Executive Officer, has elected to not participate under the plan. As of December 31, 2008, excluding
 

 
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Item 11. Executive Compensation  (continued)
Knight Form 10-K


Mr. Richard D. Kinder, ten of our current officers were eligible to participate in the executive plan component. All other U.S. eligible employees were eligible for the non-executive plan component.
 
Following recommendations and determinations, Mr. Richard D. Kinder establishes which of our eligible employees will be eligible to participate under the executive plan component of the plan. At or before the start of each calendar year (or later, to the extent allowed under Internal Revenue Code regulations), performance objectives for that year are identified. The performance objectives are based on one or more of the criteria set forth in the plan. A bonus opportunity is established for each executive officer, which is the bonus the executive officer could earn if the performance objectives are fully satisfied. A minimum acceptable level of achievement of each performance objective may be set, below which no bonus is payable with respect to that objective. Additional levels may be set above the minimum (which may also be above the targeted performance objective), with a formula to determine the percentage of the bonus opportunity to be earned at each level of achievement above the minimum. Performance at a level above the targeted performance objective may entitle the executive officer to earn a bonus in excess of 100% of the bonus opportunity. However, the maximum payout to any individual under the plan for any year is $2.0 million, and Mr. Richard D. Kinder has the discretion to reduce the bonus amounts payable by us in any performance period.
 
Performance objectives may be based on one or more of the following criteria:
 
 
·
our EBITDA less capital spending, or the EBITDA less capital spending of one of our subsidiaries or business units;
 
·
our net income or the net income of one of our subsidiaries or business units;
 
·
our revenues or the revenues of one of our subsidiaries or business units;
 
·
our unit revenues minus unit variable costs or the unit revenues minus unit variable costs of one of our subsidiaries or business units;
 
·
our return on capital, return on equity, return on assets, or return on invested capital, or the return on capital, return on equity, return on assets, or return on invested capital of one of our subsidiaries or business units;
 
·
our free cash flow, cash flow return on assets or cash flows from operating activities, or the cash flow return on assets or cash flows from operating activities of one of our subsidiaries or business units;
 
·
our capital expenditures or the capital expenditures of one of our subsidiaries or business units;
 
·
our operations and maintenance expense or general and administrative expense, or the operations and maintenance expense or general and administrative expense of one of our subsidiaries or business units;
 
·
our debt-equity ratios and key profitability ratios, or the debt-equity ratios and key profitability ratios of one of our subsidiaries or business units; or
 
·
Kinder Morgan Energy Partners’ distribution per unit
 
Two financial performance objectives were set for 2008 under both the executive plan component and the non-executive plan component. The 2008 financial performance objectives were $4.02 in cash distributions per common unit by Kinder Morgan Energy Partners, and $1,056 million of EBITDA less capital spending by us. Kinder Morgan Energy Partners’ targets were the same as its previously disclosed 2008 budget expectations. At the end of 2008 the extent to which the financial performance objectives had been attained and the extent to which the bonus opportunity had been earned under the formula previously established by Mr. Richard D. Kinder was determined.
 
The 2008 bonuses for our executive officers were overwhelmingly based on whether the established financial performance objectives were met. Other factors, such as individual over performance or under performance, were considered. With respect to using these other factors in assessing performance, Mr. Richard D. Kinder did not find it practicable to, and did not, use a “score card”, or quantify or assign relative weight to the specific criteria considered. The amount of a downward or upward adjustment, subject to the maximum bonus opportunity that was established at the beginning of the year, was not subject to a formula. Specific aspects of an individual’s performance were not identified in advance. Rather, the adjustment was based on Mr. Richard D. Kinder’s judgment, giving consideration to the totality of the record presented, including the individual’s performance, and the magnitude of any positive or negative factors.
 
The table below sets forth the bonus opportunities that could be payable by us and Kinder Morgan Energy Partners to our executive officers if the performance objectives established for 2008 are 100% achieved. The amount of the portion of the bonus actually paid by us to any executive officer under the plan may be reduced from the amount of any bonus opportunity open to such executive officer. Because payments under the plan for our executive officers are determined by comparing actual performance to the performance objectives established each year for eligible executive officers chosen to participate for that year, it is not possible to accurately predict any amounts that will actually be paid under the executive plan portion of the plan over the life of the plan. Mr. Richard D. Kinder set bonus opportunities under the plan for 2008 for the executive officers at dollar amounts in excess of that which were expected to actually be paid under the plan. The actual payout amounts under the Non-Equity Incentive Plan Awards made in 2008 are set forth in the Summary Compensation Table included in this report in the column entitled “Non-Equity Incentive Plan Compensation.”
 

 
189
 
Item 11. Executive Compensation  (continued)
Knight Form 10-K


Knight Inc. Annual Incentive Plan
Bonus Opportunities for 2008
 
Name and Principal Position
  
Dollar Value
Richard D. Kinder, Chairman and Chief Executive Officer
$
-
1
Kimberly A. Dang, Vice President and Chief Financial Officer
  
1,000,000
2
Steven J. Kean, Executive Vice President and Chief Operating Officer
  
1,500,000
3
Joseph Listengart, Vice President, General Counsel and Secretary
  
1,000,000
2
C. Park Shaper, Director and President
  
1,500,000
3
____________
1
Declined to participate.
2
Under the plan, for 2008, if neither of the targets was met, no bonus opportunities would have been provided; if one of the targets was met, $500,000 in bonus opportunities would have been available; if both of the targets had been exceeded by 10%, $1,500,000 in bonus opportunities would have been available. Mr. Richard D. Kinder may reduce the award payable by us to any participant for any reason.
3
Under the plan, for 2008, if neither of the targets was met, no bonus opportunities would have been provided; if one of the targets was met, $750,000 in bonus opportunities would have been available; if both of the targets had been exceeded by 10%, $2,000,000 in bonus opportunities would have been available. Mr. Richard D. Kinder may reduce the award payable by us to any participant for any reason.
 
We may amend the plan from time to time without shareholder approval except as required to satisfy the Internal Revenue Code or any applicable securities exchange rules. Awards may be granted under the plan for calendar year 2009, unless the plan is terminated earlier by us. However, the plan will remain in effect until payment has been completed with respect to all awards granted under the plan prior to its termination.
 
Other Compensation
 
Knight Inc. Savings Plan. The Knight Inc. Savings Plan is a defined contribution 401(k) plan. The plan permits all full-time employees of Knight and KMGP Services Company, Inc., including the named executive officers, to contribute between 1% and 50% of base compensation, on a pre-tax basis, into participant accounts. In addition to a contribution equal to 4% of base compensation per year for most plan participants, Kinder Morgan G.P., Inc. may make special discretionary contributions. Certain employees’ contributions are based on collective bargaining agreements. The contributions are made each pay period on behalf of each eligible employee. Participants may direct the investment of both their contributions and employer contributions into a variety of investments at the employee’s discretion. Plan assets are held and distributed pursuant to a trust agreement. Employer contributions for employees vest on the second anniversary of the date of hire.
 
In July 2008, Mr. Richard D. Kinder and Kinder Morgan Management’s compensation committee approved a special contribution through July 2009 of an additional 1% of base pay into the Savings Plan for each eligible employee. Each eligible employee will receive an additional 1% company contribution based on eligible base pay each pay period beginning with the first pay period of August 2008 and continuing through the last pay period of July 2009. The additional 1% contribution does not change or otherwise impact, the annual 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 according to the same vesting schedule described in the preceding paragraph. Since this additional 1% company contribution is discretionary, Mr. Kinder’s and the Kinder Morgan Management compensation committee’s approvals will be required annually for each additional contribution. During the first quarter of 2009, excluding our portion of the 1% additional contribution described above, we will not make any additional discretionary contributions to individual accounts for 2008.
 
Additionally, in 2006, an option to make after-tax “Roth” contributions (Roth 401(k) option) to a separate participant account was added to the Savings Plan as an additional benefit to all participants. Unlike traditional 401(k) plans, where participant contributions are made with pre-tax dollars, earnings grow tax-deferred, and the withdrawals are treated as taxable income, Roth 401(k) contributions are made with after-tax dollars, earnings are tax-free, and the withdrawals are tax-free if they occur after both (i) the fifth year of participation in the Roth 401(k) option and (ii) attainment of age 591/2, death or disability. The employer contribution will still be considered taxable income at the time of withdrawal.
 
Knight Inc. Cash Balance Retirement Plan. Employees of ours and KMGP Services Company, Inc., including our named executive officers, are also eligible to participate in a Cash Balance Retirement Plan. Certain employees continue to accrue benefits through a career-pay formula, “grandfathered” according to age and years of service on December 31, 2000, or collective bargaining arrangements. All other employees accrue benefits through a personal retirement account in the Cash Balance Retirement Plan. Under the plan, we credit each participating employee’s personal retirement account an amount equal to 3% of eligible compensation every pay period. Interest is credited to the personal retirement accounts at the 30-year U.S. Treasury bond rate, or an approved substitute, in effect each year. Employees become fully vested in the plan after three years, and they may take a lump sum distribution upon termination of employment or retirement.
 

 
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Item 11. Executive Compensation  (continued)
Knight Form 10-K


The following table sets forth the estimated actuarial present value of each named executive officer’s accumulated pension benefit as of December 31, 2008, under the provisions of the Cash Balance Retirement Plan. With respect to our named executive officers, the benefits were computed using the same assumptions used for financial statement purposes, assuming current remuneration levels without any salary projection, and assuming participation until normal retirement at age sixty-five. These benefits are subject to federal and state income taxes, where applicable, but are not subject to deduction for social security or other offset amounts.
 
Pension Benefits
Name
  
Plan Name
  
Current
Credited Yrs
of Service
  
Present Value of
Accumulated
Benefit1
  
Contributions
During 2008
Richard D. Kinder
  
Cash Balance
  
8
    
$
- 
      
$
- 
  
Kimberly A. Dang
  
Cash Balance
  
7
      
39,693
        
8,285
  
Steven J. Kean
  
Cash Balance
  
7
      
50,479
        
8,755
  
Joseph Listengart
  
Cash Balance
  
8
      
60,267
        
9,188
  
C. Park Shaper
  
Cash Balance
  
8
      
60,267
        
9,188
  
____________
1
The present values in the Pension Benefits table are based on certain assumptions, including a 6.25% discount rate, 5.0% cash balance interest crediting rate, and a lump sum calculated using the IRS 2009 Mortality Tables. We assumed benefits would commence at normal retirement age, which is 65.
 
Knight Holdco LLC Units. In connection with the Going Private transaction, some of our directors and executive officers received Class A-1 and Class B units of Knight Holdco LLC, our parent company. Mr. Pontarelli did not receive Knight Holdco LLC units. Generally, Knight Holdco LLC has three classes of units—Class A units, Class A-1 units and Class B units.
 
The Class B units were awarded by Knight Holdco LLC to members of Knight Inc.’s management in consideration of their services to or for the benefit of Knight Holdco LLC. The Class B units represent interests in the profits of Knight Holdco LLC following the return of capital for the holders of Class A units and the achievement of predetermined performance targets over time. The Class B units will performance vest in increments of 5% of profits distributions up to a maximum of 20% of all profits distributions that would otherwise be payable with respect to the Class A units and Class A-1 units, based on the achievement of predetermined performance targets. The Class B units are subject to time based vesting, and with respect to any holder thereof, will vest 33 1/3% on each of the third, fourth and fifth year anniversary of the issuance of such Class B units to such holder. The amended and restated limited liability company agreement of Knight Holdco LLC also includes provisions with respect to forfeiture of Class B units upon termination for cause, Knight Holdco LLC’s call rights upon termination and other related provisions relating to an employee’s tenure. The allocation of the Class B units among our management was determined prior to closing by Mr. Richard D. Kinder, and approved by other, non-management investors in Knight Holdco LLC.
 
The Class A-1 units were awarded by Knight Holdco LLC to members of our management (other than Mr. Richard D. Kinder) who reinvested their equity interests in Knight Holdco LLC in connection with the Going Private transaction in consideration of their services to or for the benefit of Knight Holdco LLC. Class A-1 units entitle a holder thereof to receive distributions from Knight Holdco LLC in an amount equal to distributions paid on Class A units (other than distributions on the Class A units that represent a return of the capital contributed in respect of such Class A units), but only after the Class A units have received aggregate distributions in an amount equal to the amount of capital contributed in respect of the Class A units.
 
Other Potential Post-Employment Benefits. On October 7, 1999, Mr. Richard D. Kinder entered into an employment agreement with us pursuant to which he agreed to serve as our Chairman and Chief Executive Officer. His employment agreement provides for a term of three years and one year extensions on each anniversary of October 7th. Mr. Kinder, at his initiative, accepted an annual salary of $1 to demonstrate his belief in our and Kinder Morgan Energy Partners’ long term viability. Mr. Kinder continues to accept an annual salary of $1, and he receives no other compensation from us. Mr. Kinder was awarded Class B units by and in Knight Holdco LLC in connection with the Going Private transaction, and while we, as a subsidiary of Knight Holdco LLC, are allocated compensation expense attributable to such Class B units, we have no obligation, nor do we expect, to pay any amounts in connection with the Class B units.
 
We believe that Mr. Kinder’s employment agreement contains provisions that are beneficial to us and our subsidiaries and accordingly, Mr. Kinder’s employment agreement is extended annually at the request of our and Kinder Morgan Management’s board of directors. For example, with limited exceptions, Mr. Kinder is prevented from competing in any manner with us or any of our subsidiaries, while he is employed by us and for 12 months following the termination of his employment with us. The agreement contains provisions that address termination with and without cause, termination as a result of change in duties or disability, and death. At his current compensation level, the maximum amount that would be paid
 

 
191
 
Item 11. Executive Compensation  (continued)
Knight Form 10-K


to Mr. Kinder or his estate in the event of his termination is three times $750,000, or $2.25 million. This payment would be made if Mr. Kinder were terminated by us without cause or if Mr. Kinder terminated his employment with us as a result of a change in duties (as defined in the employment agreement). There are no employment agreements or change-in-control arrangements with any of our other executive officers.
 
Summary Compensation Table
 
The following table shows compensation paid or otherwise awarded to (i) our principal executive officer; (ii) our principal financial officer; and (iii) our three most highly compensated executive officers (other than our principal executive officer and principal financial officer) serving at fiscal year end 2008 (collectively referred to as the “named executive officers”) for services rendered to us, our subsidiaries or our affiliates, including Kinder Morgan Energy Partners and Knight Holdco LLC (collectively referred to as the “Knight affiliated entities”), during fiscal years 2008, 2007 and 2006. The amounts in the columns below, except the column entitled “Unit Awards by Knight Holdco LLC”, represent the total compensation paid or awarded to the named executive officers by all the Knight affiliated entities, and as a result the amounts are in excess of the compensation expense allocated to and recognized by us for services rendered to us. The amounts in the column entitled “Unit Awards by Knight Holdco LLC” consist of compensation expense calculated in accordance with SFAS No. 123R and allocated to Knight Inc. (excluding any corresponding compensation expense allocated to Kinder Morgan Energy Partners and consolidated into Knight Inc.) for the Knight Holdco LLC Class A-1 and Class B units awarded by Knight Holdco LLC to the named executive officers. As a subsidiary of Knight Holdco LLC, we are allocated a portion of the compensation expense recognized by Knight Holdco LLC with respect to such units, although none of us or any of our subsidiaries have any obligation, nor do we expect, to pay any amounts in respect of such units and none of the named executive officers has received any payments in respect of such units.
 
           
(1)
  
(2)
  
(3)
  
(4)
  
(5)
  
(6)
    
Name and
    Principal Position    
  
Year
  Salary  
  Bonus  
  
Stock
Awards
   by KMI   
  
Option
Awards
  by KMI  
  
Non-Equity
Incentive Plan
Compensation
  
Change
in Pension
   Value   
  
All Other
Compensation
  
Unit Awards
by Knight
Holdco LLC
  
     Total     
Richard D. Kinder
  
2008
$
1
$
-
  
$
-
  
$
-
  
$
-
  
$
-
  
$
-
  
$
660,388
  
$
660,389
Director, Chairman and
  
2007
  
1
  
-
    
-
    
-
    
-
    
-
    
-
    
385,200
    
385,201
Chief Executive Officer
  
2006
  
1
  
-
    
-
    
-
    
-
    
-
    
-
    
-
    
1
                                                       
Kimberly A. Dang
  
2008
  
223,077
  
-
    
-
    
-
    
440,000
    
8,285
    
11,863
    
47,963
    
731,188
Vice President and
  
2007
  
200,000
  
-
    
338,095
    
-
    
400,000
    
7,294
    
32,253
    
27,980
    
1,005,622
Chief Financial Officer
  
2006
  
200,000
  
-
    
139,296
    
37,023
    
270,000
    
6,968
    
46,253
    
-
    
699,540
                                                       
Steven J. Kean
  
2008
  
223,077
  
-
    
-
    
-
    
1,150,000
    
8,755
    
13,007
    
191,720
    
1,586,559
Executive Vice President
  
2007
  
200,000
  
-
    
4,397,080
    
-
    
1,100,000
    
7,767
    
147,130
    
111,820
    
5,963,797
And
  
2006
  
200,000
  
-
    
1,591,192
    
147,943
    
-
    
7,422
    
284,919
    
-
    
2,231,476
Chief Operating Officer
                                                      
                                                       
Joseph Listengart
  
2008
  
223,077
  
-
    
-
    
-
    
900,000
    
9,188
    
11,629
    
120,107
    
1,264,001
Vice President, General
  
2007
  
200,000
  
-
    
847,350
    
-
    
1,000,000
    
8,194
    
102,253
    
70,063
    
2,227,860
Counsel and Secretary
  
2006
  
200,000
  
-
    
721,817
    
-
    
-
    
7,835
    
224,753
    
-
    
1,154,405
                                                       
C. Park Shaper
  
2008
  
223,077
  
-
    
-
    
-
    
1,200,000
    
9,188
    
12,769
    
302,906
    
1,747,940
Director and President
  
2007
  
200,000
  
-
    
1,950,300
    
-
    
1,200,000
    
8,194
    
155,953
    
176,660
    
3,691,107
   
2006
  
200,000
  
-
    
1,134,283
    
24,952
    
-
    
7,835
    
348,542
    
-
    
1,715,612
____________
1
Consists of expense calculated in accordance with SFAS No. 123R attributable to restricted KMI stock awarded in 2003, 2004 and 2005 according to the provisions of the KMI Stock Plan. No restricted stock was awarded in 2008, 2007 or 2006. For grants of restricted stock, we take the value of the award at time of grant and accrue the expense over the vesting period according to SFAS No. 123R. For grants made July 16, 2003—KMI closing price was $53.80, twenty-five percent of the shares in each grant vest on the third anniversary after the date of grant and the remaining seventy-five percent of the shares in each grant vest on the fifth anniversary after the date of grant. For grants made July 20, 2004—KMI closing price was $60.79, fifty percent of the shares vest on the third anniversary after the date of grant and the remaining fifty percent of the shares vest on the fifth anniversary after the date of grant. For grants made July 20, 2005—KMI closing price was $89.48, twenty-five percent of the shares in each grant vest on the third anniversary after the date of grant and the remaining seventy-five percent of the shares in each grant vest on the fifth anniversary after the date of grant. As a result of the Going Private transaction, all outstanding restricted shares vested in 2007 and therefore all remaining compensation expense with respect to restricted stock was recognized in 2007 in accordance with SFAS No. 123R. We bore all of the costs associated with this acceleration.
2
Consists of expense calculated in accordance with SFAS No. 123R attributable to options to purchase KMI shares awarded in 2002 and 2003 according to the provisions of the KMI Stock Plan. No options were granted in 2008, 2007 or 2006. For options granted in 2002—volatility of 0.3912 using a 6 year term, 4.01% five year risk free interest rate return, and a 0.71% expected annual dividend rate. For options granted in 2003—volatility of 0.3853 using a 6.25 year term, 3.37% treasury strip quote at time of grant, and a 2.973% expected annual dividend rate. As a result of the Going Private transaction, all outstanding options vested in 2007 and therefore all remaining compensation expense with respect to options was recognized in 2007 in accordance with SFAS No. 123R. As a condition to their being permitted to participate in the Going Private transaction, Messrs. Kean and Shaper agreed to the cancellation of 10,467 and 22,031 options, respectively. These

 
192
 
Item 11. Executive Compensation  (continued)
Knight Form 10-K


 
cancelled options had weighted-average exercise prices of $39.12 and $24.75 per share, respectively. We bore all of the costs associated with this acceleration.
3
Represents amounts paid according to the provisions of our Annual Incentive Plan. Amounts were earned in the fiscal year indicated but were paid in the next fiscal year. Messrs. Kean, Listengart and Shaper refused to accept a bonus for 2006. The committee agreed that this was not a reflection of performance on these individuals.
4
Represents the 2008, 2007 and 2006, as applicable, change in the actuarial present value of accumulated defined pension benefit (including unvested benefits) according to the provisions of our Cash Balance Retirement Plan.
5
Amounts include value of contributions to the Knight Inc. Savings Plan (a 401(k) plan), value of group-term life insurance exceeding $50,000, taxable parking subsidy and, for 2006 and 2007 only, dividends paid on unvested restricted stock awards. Amounts in 2006 and 2007 include $10,000 and in 2008 include $11,154 representing the value of contributions to the Knight Inc. Savings Plan. Amounts representing the value of dividends paid on unvested restricted stock awards are as follows: for 2007—Mrs. Dang $21,875; Mr. Kean $136,500; Mr. Listengart $91,875; and Mr. Shaper $144,375; and for 2006—Mrs. Dang $35,875; Mr. Kean $273,000; Mr. Listengart $214,375; and Mr. Shaper $336,875.
6
Such amounts represent the amount of the non-cash compensation expense calculated in accordance with SFAS No. 123R attributable to the Class A-1 and Class B units of Knight Holdco LLC and allocated to us for financial reporting purposes but does not include any such expense allocated to any of our subsidiaries. None of the named executive officers has received any payments in connection with such units, and none of us or our subsidiaries are obligated, nor do we expect, to pay any amounts in respect of such units. See “Elements of Compensation—Other Compensation—Knight Holdco LLC Units” above for further discussion of these units.
 
Grants of Plan-Based Awards
 
The following supplemental compensation table shows compensation details on the value of all non-guaranteed and non-discretionary incentive awards granted during 2008 to our named executive officers. The table includes awards made during or for 2008. The information in the table under the caption “Estimated Future Payments Under Non-Equity Incentive Plan Awards” represents the threshold, target and maximum amounts payable under the Knight Inc. Annual Incentive Plan for performance in 2008. Amounts actually paid under that plan for 2008 are set forth in the Summary Compensation Table under the caption “Non-Equity Incentive Plan Compensation.” There will not be any additional payouts under the Annual Incentive Plan for 2008.
 
       
Estimated Future Payouts Under
Non-Equity Incentive Plan Awards1
  
All Other Stock
Awards
  
Grant Date Fair Value of
Name
  
Grant Date
  
Threshold
  
Target
  
Maximum
  
Number of Units
  
Stock Awards
Richard D. Kinder
  
—
  
$
-
  
$
-
  
$
-
  
-
  
$
-
Kimberly A. Dang
  
January 16, 2008
    
$500,000
    
$1,000,000
    
$1,500,000
  
-
    
-
Steven J. Kean
  
January 16, 2008
    
750,000
    
1,500,000
    
2,000,000
  
-
    
-
Joseph Listengart
  
January 16, 2008
    
500,000
    
1,000,000
    
1,500,000
  
-
    
-
C. Park Shaper
  
January 16, 2008
    
750,000
    
1,500,000
    
2,000,000
  
-
    
-
____________
1
See “Elements of Compensation—Possible Annual Cash Bonus (Non-Equity Cash Incentive)” above for further discussion of these awards.
 
Outstanding Equity Awards at Fiscal Year-End
 
The only unvested equity awards outstanding at the end of fiscal 2008 were the Class B units of Knight Holdco LLC awarded in 2007 by Knight Holdco LLC to the named executive officers. As a subsidiary of Knight Holdco LLC, we are allocated a portion of the compensation expense recognized by Knight Holdco LLC with respect to such units, although none of us or any of our subsidiaries have any obligation, nor do we expect to pay any amounts in respect of such units.
 

   
Stock Awards
Name
  
Type of Units
  
Number of Units
that Have Not Vested
  
Market Value of
Units of Stock that
Have Not Vested1
Richard D. Kinder
  
Class B units
  
791,405,452
  
N/A
Kimberly A. Dang
  
Class B units
  
49,462,841
  
N/A
Steven J. Kean
  
Class B units
  
158,281,090
  
N/A
Joseph Listengart
  
Class B units
  
79,140,545
  
N/A
C. Park Shaper
  
Class B units
  
217,636,499
  
N/A
____________
1
Because the Class B units are equity interests of Knight Holdco LLC, a private limited liability company, the market value of such interests is not readily determinable. None of the named executive officers has received any payments in connection with such units, and none of us or our subsidiaries are obligated, nor do we expect, to pay any amounts in respect of such
 

 
193
 
Item 11. Executive Compensation  (continued)
Knight Form 10-K


 
units. See “Elements of Compensation—Other Compensation—Knight Holdco LLC Units” above for further discussion of these units.
 
Director Compensation
 
Compensation Committee Interlocks and Insider Participation. Our board has no separate compensation committee. Mr. Richard D. Kinder as Chief Manager of Knight Holdco makes compensation decisions with respect to our executive officers. Mr. Kinder has not served during 2008 on a board of directors of another entity which has employed any of the members of our current board.
 
Directors Fees. None of our directors receive compensation in their capacity as directors. All directors are reimbursed for reasonable travel and other expenses incurred in attending all board and/or committee meetings.
 
Compensation Committee Report
 
Because our board of directors does not have a separate compensation committee or other committee performing equivalent functions, our board of directors has reviewed and discussed the above Compensation Discussion and Analysis for fiscal year 2008 with management. Based on this review and discussion, the board has concluded that this Compensation Discussion and Analysis should be included in this annual report on Form 10-K for the fiscal year 2008.
 
Board of Directors:
Richard D. Kinder
Kenneth A. Pontarelli
C. Park Shaper

 

 
194
 
 
Knight Form 10-K


 
Security Ownership
 
Knight Midco Inc., an indirect wholly owned subsidiary of Knight Holdco LLC, owns 100% of our outstanding common stock. The following tables set forth information as of January 31, 2009, regarding the beneficial ownership of Kinder Morgan Energy Partners’ common units, Kinder Morgan Management’s shares and Knight Holdco LLC's units by all of our directors, each of the named executive officers identified in Item 11 “Executive Compensation” and by all of our directors and executive officers as a group.  Unless otherwise noted, the address of each person below is c/o Knight Inc., 500 Dallas Street, Suite 1000, Houston, Texas 77002.
 
Amount and Nature of Beneficial Ownership1
 
 
Kinder Morgan Energy Partners Common Units
  
Kinder Morgan Management Shares
 
Number
of Units
  
Percent
of Class2
  
Number of Shares
  
Percent
of Class3
Richard D. Kinder4
315,979
  
*
  
111,782
  
*
C. Park Shaper
4,000
  
*
  
25,618
  
*
Kenneth A. Pontarelli
1,000
  
*
  
—
  
—
Steven J. Kean
—
  
—
  
—
  
—
Joseph Listengart
4,198
  
*
  
—
  
—
Kimberly A. Dang
121
  
*
  
473
  
*
Directors and Executive Officers as a group (8 persons)5
337,484
  
*
  
158,878
  
*
____________
*Less than 1%
1
Except as noted otherwise, each individual has sole voting power and sole disposition power over the units and shares listed.
2
As of January 31, 2009, Kinder Morgan Energy Partners had 183,169,827 common units issued and outstanding.
3
As of January 31, 2009, Kinder Morgan Management had 77,997,906 issued and outstanding shares representing limited liability company interests, including two voting shares owned by Kinder Morgan G.P., Inc.
4
Includes 7,879 common units owned by Mr. Kinder’s spouse. Mr. Kinder disclaims any and all beneficial or pecuniary interest in these units.
5
Includes 9,090 common units owned by spouses of our executives and 719 Kinder Morgan Management shares owned by one of our executives for the benefit of his children. The executives disclaim any beneficial ownership in such common units and shares.
 
 
Amount and Nature of Beneficial Ownership1
 

   
Knight Holdco LLC
Class A Units
  
% of Class A Units2
  
Knight Holdco LLC Class A-1 Units
  
% of Class A-1 Units3
  
Knight Holdco LLC Class B Units
  
% of Class B Units4
Current Directors and Executive Officers
                        
Richard D. Kinder5
  
2,424,000,000
  
30.6
  
—
  
—
  
791,405,452
  
40.0
C. Park Shaper6
  
13,598,785
  
*
  
7,799,775
  
28.3
  
217,636,499
  
11.0
Steven J. Kean7
  
6,684,149
  
*
  
3,833,788
  
13.9
  
158,281,090
  
8.0
Kimberly A. Dang8
  
750,032
  
*
  
430,191
  
1.6
  
49,462,841
  
2.5
Joseph Listengart9
  
6,059,449
  
*
  
3,475,483
  
12.6
  
79,140,545
  
4.0
Kenneth A. Pontarelli10
  
1,997,795,088
  
25.2
  
—
  
—
  
—
  
—
Directors and Executive Officers as a group (8 persons)
  
4,453,776,489
  
56.3
  
18,343,384
  
66.5
  
1,400,787,650
  
70.8
__________
*Less than 1%.
1
Except as noted otherwise, each individual has sole voting power and sole disposition power over the units and shares listed.
2
As of January 31, 2009, Knight Holdco LLC had 7,914,367,913 Class A Units issued and outstanding.
3
As of January 31, 2009, Knight Holdco LLC had 27,225,694 Class A-1 Units issued and outstanding and 345,042 phantom Class A-1 Units issued and outstanding. The phantom Class A-1 Units were issued to Canadian management employees.
4
As of January 31, 2009, Knight Holdco LLC had 1,927,566,908 Class B Units issued and outstanding and 50,946,724 phantom Class B Units issued and outstanding. The phantom Class B Units were issued to Canadian management employees.

 
195
 
Item 12.Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
           (continued)
Knight Form 10-K


5
Includes 522,372 Class A units owned by Mr. Kinder’s wife. Mr. Kinder disclaims any and all beneficial or pecuniary interest in the Class A units held by his wife. Also includes 263,801,817 Class B Units that Mr. Kinder transferred to a limited partnership. Mr. Kinder may be deemed to be the beneficial owner of these transferred Class B Units, because Mr. Kinder controls the voting and disposition power of these Class B Units, but he disclaims ninety-nine percent of any beneficial and pecuniary interest in them. Mr. Kinder contributed 23,994,827 shares of KMI common stock and his wife contributed 5,173 shares of KMI common stock to Knight Holdco LLC that were valued for purposes of Knight Holdco LLC’s limited liability agreement at $2,423,477,628 and $522,372, respectively, in exchange for their respective Class A units. The Class B units received by Mr. Kinder had a grant date fair value as calculated in accordance with SFAS No. 123R of $9,200,000.
6
Includes 217,636,499 Class B Units that Mr. Shaper transferred to a limited partnership. Mr. Shaper may be deemed to be the beneficial owner of these transferred Class B Units, because Mr. Shaper controls the voting and disposition power of these Class B Units, but he disclaims approximately twenty-two percent of any beneficial and pecuniary interest in them. Mr. Shaper made a cash investment of $13,598,785 of his after-tax proceeds from the conversion in the Going Private transaction of 82,500 shares of KMI restricted stock and options to acquire 197,969 shares of KMI common stock in exchange for his Class A units. The Class A-1 units and Class B units received by Mr. Shaper had an aggregate grant date fair value as calculated in accordance with SFAS No. 123R of $4,296,125.
7
Mr. Kean made a cash investment of $6,684,149 of his after-tax proceeds from the conversion in the Going Private transaction of 78,000 shares of KMI restricted stock and options to acquire 25,533 shares of KMI common stock in exchange for his Class A units. The Class A-1 units and Class B units received by Mr. Kean had an aggregate grant date fair value as calculated in accordance with SFAS No. 123R of $2,708,095.
8
Includes 49,462,841 Class B Units that Mrs. Dang transferred to a limited partnership. Mrs. Dang may be deemed to be the beneficial owner of these transferred Class B Units, because Mrs. Dang has voting and disposition power of these Class B Units, but she disclaims ten percent of any beneficial and pecuniary interest in them. Mrs. Dang made a cash investment of $750,032 of her after-tax proceeds from the conversion in the Going Private transaction of 8,000 shares of KMI restricted stock and options to acquire 24,750 shares of KMI common stock in exchange for her Class A units. The Class A-1 units and Class B units received by Mrs. Dang had an aggregate grant date fair value as calculated in accordance with SFAS No. 123R of $672,409.
9
Mr. Listengart made a cash investment of $6,059,449 of his after-tax proceeds from the conversion in the Going Private transaction of 52,500 shares of KMI restricted stock and options to acquire 48,459 shares of KMI common stock in exchange for his Class A units. The Class A-1 units and Class B units received by Mr. Listengart had an aggregate grant date fair value as calculated in accordance with SFAS No. 123R of $1,706,963.
10
Consists of 240,454,180 units owned by GS Capital Partners V Fund, L.P.; a Delaware limited partnership; 124,208,587 units owned by GS Capital Partners V Offshore Fund, L.P., a Cayman Islands exempted limited partnership; 82,455,031 units owned by GS Capital Partners V Institutional, L.P., a Delaware limited partnership; 9,533,193 units owned by GS Capital Partners V GmbH & Co. KG, a German limited partnership; 233,596,750 units owned by GS Capital Partners VI Fund, L.P., a Delaware limited partnership; 194,297,556 units owned by GS Capital Partners VI Offshore Fund, L.P., a Cayman Islands exempted limited partnership; 64,235,126 units owned by GS Capital Partners VI Parallel, L.P., a Delaware limited partnership; 8,302,031 units owned by GS Capital Partners VI GmbH & Co. KG, a German limited partnership; 250,215,732 units owned by Goldman Sachs KMI Investors, L.P., a Delaware limited partnership; 344,448,791 units owned by GSCP KMI Investors, L.P., a Delaware limited partnership; 49,873,203 units owned by GSCP KMI Investors Offshore, L.P., a Cayman Islands exempted limited partnership; 100,534,014 units owned by GS Global Infrastructure Partners I, L.P., a Delaware limited partnership; 10,740,192 units owned by GS Institutional Infrastructure Partners I, L.P., a Delaware limited partnership; and 284,900,702 units owned by GS Infrastructure Knight Holdings, L.P., a Delaware limited partnership (collectively the “GS Entities”). The GS Entities, of which affiliates of The Goldman Sachs Group, Inc. (“GSG”) are the general partner, managing general partner or investment manager, share voting and investment power with certain of its respective affiliates. Mr. Pontarelli is a managing director of Goldman, Sachs & Co. (“GS”), which is a direct and indirect wholly owned subsidiary of GSG. Each of GS, GSG and Mr. Pontarelli disclaims beneficial ownership of the equity interests and the units held directly or indirectly by the GS Entities except to the extent of their pecuniary interest therein, if any. GS, a NASD member, is an investment banking firm that regularly performs services such as acting as a financial advisor and serving as principal or agent in the purchase and sale of securities. In the future, GS may be called upon to provide similar or other services for us or our affiliates. Each of Mr. Pontarelli, GS and GSG has a mailing address of c/o Goldman, Sachs & Co., 85 Broad Street, 10th Floor, New York, NY 10004. GSG’s affiliates that are registered broker-dealers (including specialists and market makers) may from time to time engage in brokerage and trading activities with respect to our securities or those of our affiliates.
 
Equity Compensation Plan Information
 
The following table sets forth information regarding our equity compensation plans as of December 31, 2008. Specifically, the table provides information regarding our Common Unit Compensation Plan for Non-Employee Directors, described in Note 17 of the accompanying Notes to the Consolidated Financial Statements.
 

 
196
 
Item 12.Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
           (continued)
Knight Form 10-K



Plan category
  
Number of Securities
Remaining Available for
Future Issuance Under Equity
Compensation Plans
Equity Compensation Plans Approved by Security Holders
    
─
  
         
Equity Compensation Plans Not Approved by Security Holders
    
77,882
  
         
Total                                                                                  
    
77,882
  

 
Policy Regarding Related Transactions
 
Our policy is that (1) employees must obtain authorization from the appropriate business unit president of the relevant company or head of corporate function and (2) directors, business unit presidents, executive officers and heads of corporate functions must obtain authorization from the non-interested members of the audit committee of the applicable board of directors, for any business relationship or proposed business transaction in which they or an immediate family member has a direct or indirect interest, or from which they or an immediate family member may derive a personal benefit (a “related party transaction”). The maximum dollar amount of related party transactions that may be approved as described above in this paragraph in any calendar year is $1.0 million. Any related party transactions that would bring the total value of such transactions to greater than $1.0 million must be referred to the audit committee of the appropriate board of directors for approval or to determine the procedure for approval.
 
For information regarding related transactions, see Note 7 of the accompanying Notes to Consolidated Financial Statements.
 
Director Independence
 
Subsequent to the Going Private transaction, our common stock is no longer registered with the SEC or traded on any national securities exchange. However, based upon the listing standards of the New York Stock Exchange, Mr. Pontarelli would be considered an “independent” director. Mr. Richard Kinder, our Chairman and Chief Executive Officer, in his role as Chief Manager of Knight Holdco LLC, makes compensation decisions with respect to our executive officers. We do not have a nominating committee or a committee that serves a similar purpose.
 
 
The following sets forth fees billed for the audit and other services provided by PricewaterhouseCoopers LLP for the fiscal years ended December 31, 2008 and 2007:
 
 
Year Ended December 31,
 
2008
  
2007
Audit fees1
$
4,875,799
  
$
5,689,710
Tax fees2
  
2,568,523
    
2,974,126
Total
$
7,444,322
  
$
8,663,836
____________
1
Includes fees for integrated audit of annual financial statements and internal control over financial reporting, reviews of the related quarterly financial statements, and reviews of documents filed with the Securities and Exchange Commission.
2
Includes fees for professional services rendered for tax return review services and for federal, state, local and foreign income tax compliance and consulting services. For 2008 and 2007, amounts include fees of 2,113,318 and $2,352,533, respectively, billed to Kinder Morgan Energy Partners for professional services rendered for tax processing and preparation of Forms K-1 for its unitholders.
 
All services rendered by PricewaterhouseCoopers LLP are permissible under applicable laws and regulations, and were pre-approved by our audit committee. Pursuant to the charter of our audit committee, the committee’s primary purposes include the following: (i) to select, appoint, engage, oversee, retain, evaluate and terminate our external auditors; (ii) to pre-approve all audit and non-audit services, including tax services, to be provided, consistent with all applicable laws, to us by our external auditors; and (iii) to establish the fees and other compensation to be paid to our external auditors. The audit committee has reviewed the external auditors’ fees for audit and non audit services for fiscal year 2008. The audit committee has also considered whether such non audit services are compatible with maintaining the external auditors’ independence and has concluded that they are compatible at this time.
 

 
197
 
Item 14. Principal Accounting Fees and Services (continued)
Knight Form 10-K


Furthermore, the audit committee will review the external auditors’ proposed audit scope and approach as well as the performance of the external auditors. It also has direct responsibility for and sole authority to resolve any disagreements between our management and our external auditors regarding financial reporting, will regularly review with the external auditors any problems or difficulties the auditors encountered in the course of their audit work, and will, at least annually, use its reasonable efforts to obtain and review a report from the external auditors addressing the following (among other items): (i) the auditors’ internal quality-control procedures; (ii) any material issues raised by the most recent internal quality-control review, or peer review, of the external auditors; (iii) the independence of the external auditors; and (iv) the aggregate fees billed by our external auditors for each of the previous two fiscal years.
 

 

 
198
 
 
Knight Form 10-K


 
 
(a)
(1)
Financial Statements

Reference is made to the index of financial statements and supplementary data under Item 8 in Part II.

 
(2)
Financial Statement Schedules

Schedule II - Valuation and Qualifying Accounts is omitted because the required information is shown in Note 1 of the accompanying Notes to Consolidated Financial Statements.

The financial statements, including the notes thereto, of Kinder Morgan Energy Partners, an equity method investee of Knight Inc., are incorporated herein by reference to pages 123 through 215 of Kinder Morgan Energy Partners’ Annual Report on Form 10-K for the year ended December 31, 2008.

 
(3)
Exhibits

In reviewing the documents included or incorporated by reference as exhibits to this report, please remember they are included to provide you with information regarding their terms and are not intended to provide any other factual or disclosure information about us or any other parties to the documents. Some of the documents are agreements that contain representations and warranties by one or more of the parties of the applicable agreement. These representations and warranties were made solely for the benefit of the other parties to the applicable agreement and:
 
 
·
should not be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties if those statements prove to be inaccurate;
 
·
may have been qualified by disclosures that were made to the other party in connection with the negotiation of the applicable agreement, which disclosures are not necessarily reflected in the agreement;
 
·
may apply standards of materiality in a way that is different from what may be viewed as material to you or other readers; and
 
·
may apply only as of the date of the applicable agreement or such other date or dates as may be specified in the agreement and are subject to more recent developments.
 
Accordingly, these representations and warranties may not describe the actual state of affairs as of the date they were made or at any other time.
 
Any references made to K N Energy, Inc. or Kinder Morgan, Inc. in the exhibit listing that follows are references to the former names of Knight Inc. and are made because the exhibit being listed and incorporated by reference was originally filed before the respective date of the change in Knight Inc.’s name.
 
Exhibit
Number                                                                     Description
 
 
2.1
—
Agreement and Plan of Merger dated August 28, 2006, among Kinder Morgan, Inc., Knight Holdco LLC and Knight Acquisition Co. (filed as Exhibit 2.1 to Knight Inc.’s Current Report on Form 8-K filed on August 28, 2006 and incorporated herein by reference)
 
3.1
—
Amended and Restated Articles of Incorporation of Knight Inc. and amendments thereto (filed as Exhibit 3.1 to Knight Inc.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2007 and incorporated herein by reference)
 
3.2
—
Bylaws of Kinder Morgan, Inc. (filed as Exhibit 3.2 to Knight Inc.’s Current Report on Form 8-K filed on June 5, 2007 and incorporated herein by reference)
 
4.1
—
Indenture dated as of September 1, 1988, between K N Energy, Inc. and Continental Illinois National Bank and Trust Company of Chicago (filed as Exhibit 4(a) to Knight Inc.’s Annual Report on Form 10-K/A, Amendment No. 1 filed on May 22, 2000 and incorporated herein by reference)
 
4.2
—
First supplemental indenture dated as of January 15, 1992, between K N Energy, Inc. and Continental Illinois National Bank and Trust Company of Chicago (filed as Exhibit 4.2 to the Registration Statement on Form S-3 (File No. 33-45091) of K N Energy, Inc. filed on January 17, 1992 and incorporated herein by reference)
 
4.3
—
Second supplemental indenture dated as of December 15, 1992, between K N Energy, Inc. and Continental Bank, National Association (filed as Exhibit 4(c) to Knight Inc.’s Annual Report on Form 10-K/A, Amendment No. 1 filed on May 22, 2000 and incorporated herein by reference)

 
199
 
Item 15. Exhibits, Financial Statement Schedules. (continued)
Knight Form 10-K


Exhibit
Number                                                                     Description
 
 
4.4
—
Indenture dated as of November 20, 1993, between K N Energy, Inc. and Continental Bank, National Association (filed as Exhibit 4.1 to the Registration Statement on Form S-3 (File No. 33-51115) of K N Energy, Inc. filed on November 19, 1993 and incorporated herein by reference)
 
4.5
—
Registration Rights Agreement among Kinder Morgan Management, LLC, Kinder Morgan Energy Partners, L.P. and Kinder Morgan, Inc. dated May 18, 2001 (filed as Exhibit 4.7 to Knight Inc.’s Annual Report on Form 10-K for the year ended December 31, 2002 and incorporated herein by reference)
 
4.6
—
Form of Indenture dated as of August 27, 2002 between Kinder Morgan, Inc. and Wachovia Bank, National Association, as Trustee (filed as Exhibit 4.1 to Knight Inc.’s Registration Statement on Form S-4 (File No. 333-100338) filed on October 4, 2002 and incorporated herein by reference)
 
4.7
—
Form of First Supplemental Indenture dated as of December 6, 2002 between Kinder Morgan, Inc. and Wachovia Bank, National Association, as Trustee (filed as Exhibit 4.2 to Knight Inc.’s Registration Statement on Form S-4 (File No. 333-102873) filed on January 31, 2003 and incorporated herein by reference)
 
4.8
—
Form of 6.50% Note (included in the Indenture filed as Exhibit 4.6 hereto and incorporated herein by reference)
 
4.9
—
Form of Senior Indenture between Kinder Morgan, Inc. and Wachovia Bank, National Association, as Trustee (filed as Exhibit 4.2 to Knight Inc.’s Registration Statement on Form S-3 (File No. 333-102963) filed on February 4, 2003 and incorporated herein by reference)
 
4.10
—
Form of Senior Note of Kinder Morgan, Inc. (included in the Form of Senior Indenture filed as Exhibit 4.9 hereto and incorporated herein by reference)
 
4.11
—
Form of Subordinated Indenture between Kinder Morgan, Inc. and Wachovia Bank, National Association, as Trustee (filed as Exhibit 4.4 to Knight Inc.’s Registration Statement on Form S-3 (File No. 333-102963) filed on February 4, 2003 and incorporated herein by reference)
 
4.12
—
Form of Subordinated Note of Kinder Morgan, Inc. (included in the Form of Subordinated Indenture filed as Exhibit 4.11 hereto and incorporated herein by reference)
 
4.13
—
Indenture dated as of December 9, 2005, among Kinder Morgan Finance Company, LLC, Kinder Morgan, Inc. and Wachovia Bank, National Association, as Trustee (filed as Exhibit 4.1 to Knight Inc.’s Current Report on Form 8-K filed on December 15, 2005 and incorporated herein by reference)
 
4.14
—
Forms of Kinder Morgan Finance Company, LLC notes (included in the Indenture filed as Exhibit 4.13 hereto and incorporated herein by reference)
 
4.15
—
Certificate of the President and the Vice President and Chief Financial Officer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 6.00% senior notes due 2017 and 6.50% senior notes due 2037 (filed as Exhibit 1.01 to Kinder Morgan Energy Partners, L.P.’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2007 and incorporated herein by reference)
 
4.16
—
Certificate of the Vice President and Treasurer and the Vice President and Chief Financial Officer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 5.85% senior notes due 2012 (filed as Exhibit 4.2 to Kinder Morgan Energy Partners, L.P.’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2007 and incorporated herein by reference)
 
4.17
—
Certificate of the Vice President and Treasurer and the Vice President and Chief Financial Officer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 6.95% Senior Notes due 2038 (filed as Exhibit 4.2 to Kinder Morgan Energy Partners, L.P.'s Quarterly Report on Form 10-Q for the quarter ended June 30, 2007 and incorporated herein by reference)
 
4.18
—
Certificate of the Vice President and Treasurer and the Vice President and Chief Financial Officer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 5.95% Senior Notes due 2018 (filed as Exhibit 4.28 to Kinder Morgan Energy Partners, L.P.'s Annual Report on Form 10-K for 2007 and incorporated herein by reference)
 
4.19
—
Indenture dated as of December 21, 2007, between NGPL PipeCo LLC and U.S. Bank National Association, as Trustee (filed as Exhibit 4.1 to Knight Inc.’s Current Report on Form 8-K filed on December 21, 2007 and incorporated herein by reference)
 
4.20
—
Forms of notes of NGPL PipeCo LLC (included in the Indenture filed as Exhibit 4.19 hereto and incorporated herein by reference)

 
200
 
Item 15. Exhibits, Financial Statement Schedules. (continued)
Knight Form 10-K


Exhibit
Number                                                                     Description
 
 
4.21
—
Certificate of the Vice President and Treasurer and the Vice President and Chief Financial Officer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 9.00% Senior Notes due 2019 (filed as Exhibit 4.29 to Kinder Morgan Energy Partners, L.P.'s Annual Report on Form 10-K for 2008 and incorporated herein by reference)
 
4.22
—
Certain instruments with respect to the long-term debt of Knight Inc. and its consolidated subsidiaries that relate to debt that does not exceed 10% of the total assets of Knight Inc. and its consolidated subsidiaries are omitted pursuant to Item 601(b) (4) (iii) (A) of Regulation S-K, 17 C.F.R. sec.229.601. Knight Inc. hereby agrees to furnish supplementally to the Securities and Exchange Commission a copy of each such instrument upon request.
 
10.1
—
2005 Annual Incentive Plan of Kinder Morgan, Inc. (filed as Appendix D to Kinder Morgan, Inc.’s 2006 Proxy Statement on Schedule 14A and incorporated herein by reference)
 
10.2
—
Employment Agreement dated October 7, 1999, between the Company and Richard D. Kinder (filed as Exhibit 99.D of the Schedule 13D filed by Mr. Kinder on November 16, 1999 and incorporated herein by reference)
 
10.3
—
Form of Purchase Provisions between Kinder Morgan Management, LLC and Knight Inc. (included as Annex B to the Second Amended and Restated Limited Liability Company Agreement of Kinder Morgan Management, LLC filed as Exhibit 3.1 to Kinder Morgan Management, LLC’s Current Report on Form 8-K filed on May 30, 2007 and incorporated herein by reference)
 
10.4
—
Credit Agreement, dated as of May 30, 2007, among Kinder Morgan, Inc. and Knight Acquisition Co., as the borrower, the several lenders from time to time parties thereto, and Citibank, N.A., as administrative agent and collateral agent (filed as Exhibit 4.1 to Kinder Morgan, Inc.’s Current Report on Form 8-K, filed on June 5, 2007 and incorporated herein by reference)
 
10.5
—
Form of Indemnification Agreement between Knight Inc. and each member of the Special Committee of the Board of Directors (filed as Exhibit 10.1 to Knight Inc.’s Current Report on Form 8-K filed on June 16, 2006 and incorporated herein by reference)
 
10.6
—
Acquisition Agreement dated as of February 26, 2007, by and among Kinder Morgan, Inc., 3211953 Nova Scotia Company and Fortis Inc. (filed as Exhibit 1.01 to Kinder Morgan, Inc.’s Current Report on Form 8-K filed on March 1, 2007 and incorporated herein by reference)
 
10.7
—
Retention and Relocation Agreement, dated as of March 5, 2007, between Kinder Morgan, Inc. and Scott E. Parker (filed as Exhibit 10.2 to Kinder Morgan, Inc.’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2007 and incorporated herein by reference)
 
10.8
—
Purchase Agreement, dated as of December 10, 2007, between Knight Inc. and Myria Acquisition Inc. (filed as Exhibit 10.1 to Knight Inc.’s Current Report on Form 8-K filed on December 11, 2007 and incorporated herein by reference)
 
10.9
—
First Amendment to Retention and Relocation Agreement dated as of July 16, 2008, between Knight Inc. and Scott E. Parker (filed as Exhibit 10.1 to Knight Inc.'s Current Report on Form 8-K filed on July 25, 2008 and incorporated herein by reference)
 
21.1*
—
Subsidiaries of the Registrant
 
31.1*
—
Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
 
31.2*
—
Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
 
32.1*
—
Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
 
32.2*
—
Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
 
99.1
—
The financial statements of Kinder Morgan Energy Partners, L.P. and subsidiaries (incorporated by reference to pages 123 through 215 of the Annual Report on Form 10-K of Kinder Morgan Energy Partners, L.P. for the year ended December 31, 2008)
__________
*Filed herewith.
 
 
 
 

 
201
 
Knight Form 10-K


 
Pursuant to the requirements of Section 13 or 15(d) 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.
 
  
KNIGHT INC.
(Registrant)
 
By
/s/ Kimberly A. Dang
  
 
  
Kimberly A. Dang
Vice President and Chief Financial Officer
Date: March 31, 2009
  

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities set forth below and as of the date set forth above.
 
  
    
/s/ Kimberly A. Dang
  
Vice President and Chief Financial Officer (Principal
Kimberly A. Dang
  
Financial Officer and Principal Accounting Officer)
  
    
/s/ Richard D. Kinder
  
Director, Chairman and Chief Executive Officer
Richard D. Kinder
  
(Principal Executive Officer)
  
    
/s/ Kenneth A. Pontarelli
  
Director
Kenneth A. Pontarelli
    
  
    
/s/ C. Park Shaper
  
Director
C. Park Shaper
    
  
    


 
202