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 1.321.33 billion barrels of oil since discovery.  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 and ultimate oil recovery 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 beenb een produced.  The field, discovered in 1926, is comprised of approximately 26,000 acres located about 90 miles south of Midland, Texas.

In 2009,2010, the average purchased carbon dioxide injection rate at SACROC was 253220 million cubic feet per day, down from an average of 259253 million cubic feet per day in 2008.2009.  The average oil production rate for 20092010 was approximately 29,200 barrels of oil per day, down from an average of approximately 30,100 barrels of oil per day up from an average of approximately 28,000 barrels of oil per day during 2008.  The average natural gas liquids production rate (net of the processing plant share) for 2009 was approximately 6,500 barrels per day, an increase from an average of approximately 5,500 barrels per day during 2008.2009.

Our plan over the last several years has been to maintain overall production levels and 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.  We are implementing our plan and during 2009,2010, the Yates unit produced approximately 26,50024,000 barrels of oil per day, down from an average of approximately 27,60026,500 barrels of oil per day during 2008.2009.  Unlike our operations at SACROC, where we use carbon dioxide and water to drive oil to the producing wells, we use carbon dioxide 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 neededne eded to develop and produce the reserves at Yates than is required at SACROC.

We also operate and own 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 the unit produced 203 barrels of oil per day during 2010, down from an average of 218 barrels of oil per day during 2009, down from an average of 235 barrels of oil per day during 2008.2009.  We are presently evaluating operating and subsurface technical data from the Claytonville unit to further assess redevelopment opportunities including carbon dioxide flood operations.

The expansion will involve the installation of a 91-mile, 10-inch carbon dioxide distribution pipeline,following table sets forth productive wells, service wells and the development of a new carbon dioxide flooddrilling wells in the Katz field.  It is anticipatedoil and gas fields in which we own interests as of December 31, 2010.  The oil and gas producing fields in which we own interests are located in the Permian Basin area of West Texas.  When used with respect to acres or wells, “gross” refers to the total acres or wells in which we have a working interest, and “net” refers to gross acres or wells multiplied, in each case, by the percentage working interest owned by us:

The following table reflects our net productive and dry wells that were completed in each of the carbon dioxide pipeline will be placed in service in early 2011years ended December 31, 2010, 2009 and initial carbon dioxide injections into the Katz field will commence shortly thereafter.2008:

See Note 20 to our consolidated financial statements included elsewhere in this report for additional information with respect to operating statistics and supplemental information on our oil and gas producing activities.

We operate and own an approximate 22% working interest plus an additional 28% net profits interest in the Snyder gasoline plant.  We also operate and own 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 natural 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 natural gas.  Production of natural gas liquids at the Snyder gasoline plant during December 20092010 was approximately 14,50016,100 barrels per day, compared to 13,900 barrels14,500 barrel s per day in December 2008.2009.

We own approximately 45% of, and operate, the McElmo Dome unit in Colorado, which contains more than tenseven trillion cubic feet of recoverable carbon dioxide.  Deliverability and compression capacity exceeds 1,300 million cubic feet per day.  The McElmo Dome unit produces approximately 1,200 million cubic feet per day.

We also own approximately 11% of the Bravo Dome unit in New Mexico whichand approximately 87% of the Doe Canyon Deep unit in Colorado.  The Bravo Dome unit contains more than one trillion900 billion cubic feet of recoverable carbon dioxide and produces approximately 300 million cubic feet of carbon dioxide per day, and an approximately 87% ownership interest inday; the Doe Canyon Deep unit in Colorado, which contains more than 1.5 trillion900 billion  cubic feet of carbon dioxide and produces approximately 110 million cubic feet per day.

As a result of our 50% ownership interest in Cortez Pipeline Company, we own a 50% equity interest in and operate the approximate 500-mile Cortez pipeline.  The pipeline carries carbon dioxide from the McElmo Dome and Doe Canyon source fields near Cortez, Colorado to the Denver City, Texas hub.  The Cortez pipeline currently transports over 1,200 million cubic feet of carbon dioxide per day, including approximately 99% of the carbon dioxide transported downstream on our Central Basin pipeline and our Centerline pipeline (discussed following).  The tariffs charged by Cortez Pipeline are not regulated.regulated, but are based on a consent decree.

Our Centerline carbon dioxide 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.

We own 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, we own 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 270 million cubic feet per day and makes deliveries to the SACROC, Sharon Ridge, Cogdell and Reinecke units.  The Pecos pipeline is a 25-mile carbon dioxide 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.

Our 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, our approximately 25 liquids terminals facilities possess liquids storage capacity of approximately 56.458.2 million barrels, and in 20092010 and 2008,2009, these terminals handledexperienced throughput of approximately 604620 million barrels and 597604 million barrels, respectively, of petroleum, chemicals and vegetable oil products.

Our major liquids terminal assets include the following:

Our bulk terminal operations primarily involve dry-bulk material handling services; however, we also provide conveyor manufacturing and installation, engineering and design services, and in-plant services covering material handling, conveying, maintenance and repair, truck-railcar-marine transloading, railcar switching and miscellaneous marine services.  Combined,We own or operate approximately 99 dry-bulk terminals in the United States, Canada and the Netherlands, and combined, our dry-bulk and material transloading facilities handled approximately 7892.4 million tons and 10578.0 million tons of coal, petroleum coke, fertilizers, steel, ores and other dry-bulk materials in 2010 and 2009, and 2008, respectively.  We own or operate approximately 95 dry-bulk terminals in the United States, Canada and the Netherlands.

Our major bulk terminal assets include the following:

Our materials services operations include rail or truck transloading operations conducted at 33 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.  We also design and build transloading facilities, perform inventory management services, and provide value-added services such as blending, heating and sparging.
60; In 2010 and 2009, our terminals segment, including all bulk, liquids and 2008, our materials services operations, handled approximately 227,000229,000 and 348,000227,000 railcars, respectively.

Our Kinder Morgan Canada business segment includes our Trans Mountain pipeline system, our ownership of a one-third interest in the Express pipeline system, and our 25-mile Jet Fuel pipeline system.  The weighted average remaining life of the shipping contracts on these pipelines was approximately four years as of December 31, 2010.

Our Trans Mountain common carrier pipeline system originates at Edmonton, Alberta and transports crude oil and refined petroleum products to destinations in the interior and on the west coast of British Columbia.  AWe own a connecting pipeline owned by usthat delivers petroleumcrude oil to refineries in the state of Washington.

Overall, Alberta crude oil supply has been increasing steadily overIn the past few years as a resultfourth quarter of significant oil sands development,2010, Trans Mountain completed negotiations 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.  While recently expanded pipeline capacity to the United States results in excess capacity currently, the long term increase in supply will require additional export capacity from Western Canada to both U.S. and offshore markets later this decade.  This long term supply growth and increasing global demand supports our view that the demand for transportation services provided by Trans Mountain’s pipeline will remain stronga new negotiated toll settlement effective for the foreseeable future.period beginning January 1, 2011 and ending December 31, 2015.  Trans Mountain filed the settlement with the National Energy Board of Canada in November 2010 and anticipates approval in the first half of 2011.

We own a one-third ownership interest in the Express pipeline system, and we own a long-term investment in a debt securitysubordinated debenture issued by Express US Holdings LP, (the obligor), the partnership that maintains ownership of the U.S. portion of the Express pipeline system.  We operate the Express pipeline system and we account for our 33 1/3%one-third investment 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, 24-inch diameter pipeline that begins at the crude oil 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 200,000 barrels per day in 2010, as compared to 208,246 barrels per day in 2009, as compared to 196,160 barrels per day in 2008.2009.

The Platte Pipeline is a 926-mile, 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.area.  The Platte Pipeline has a current capacity of approximately 150,000 barrels per day downstream of Casper, Wyoming and approximately 140,000 barrels per day downstream of Guernsey, Wyoming.  Platte deliveries averaged 142,400 barrels per day during 2010, as compared to 137,810 barrels per day during 2009, as compared to 133,637 barrels per day during 2008.2009.

We also own and operate the approximate 25-mile aviation turbine fuel pipeline that serves the Vancouver International Airport, located in Vancouver, British Columbia, Canada.  The turbine fuel pipeline is referred to in this report as our Jet Fuel pipeline system.  In addition to its receiving and storage facilities located at the Westridge Marine terminal, located in the Port ofMetro Vancouver, our Jet Fuel pipeline system’s operations include a terminal at the Vancouver airport that consists of five jet fuel storage tanks with an overall volumecapacity of 15,000 barrels.

Some of our U.S. refined petroleum products and crude oil 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.rat es.  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 also 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 we charged for transportation service on our 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 our Pacific operations’ pipeline system were subject to protest during the 365-day period established by the Energy Policy Act.  Accordingly, certain of the Pacific pipelines’ rates have been, and continue to be, subject tothe su bject of complaints with the FERC, as is more fully described in Note 16 to our consolidated financial statements included elsewhere in this report.

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-serviceCost-of-service ratemaking, market-based rates and settlement rates asare alternatives to the indexing approach and may be used in certain specified circumstances.circumstances to change rates.

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.

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 or Midcontinent Express pipelines, 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.

The FERC regulates the rates, terms and conditions of service, construction and abandonment of facilities by companies performing interstate natural gas transportation andservices, including storage services, under the Natural Gas Act.Act of 1938.  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:

On November 25, 2003, the FERC issued Order No. 2004, adopting revised standards of conduct that apply uniformly to interstate natural gas pipelines and public utilities.  In light of the changing structure of the energy industry, these standards of conduct governgoverned relationships between regulated interstate natural gas pipelines and all of their energy affiliates.  These standards were designed to (i) eliminate the loophole in the previous regulations that did not cover an interstate natural gas pipeline’s relationship with energy affiliates that are not marketers; (ii) prevent interstate natural gas pipelines from giving an undue preference to any of their energy affiliates; and (iii) ensure that transmission is provided on a nondiscriminatory basis.  In addition, unlike the prior regulations, these requirements applied even if the energy affiliate was not a customer of its affiliated interstate pipeline.  However, on November 17, 2006, the United States Court of Appeals for the District of Columbia Circuit vacated FERC Order No. 2004 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 No. 717.717, which revised 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.  According to the provisions of Order No. 717, a natural gas 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 Standardsstandards of Conductconduct to all transmission function employees, marketing function employees, officers, directors, supervisory employees, and any other employees likely to become privy to transmission function information.  This rule became effective November 26, 2008.

On October 15, 2009, the FERC issued Order No. 717-A, an order on rehearing and clarification regarding FERC’s Affiliate Rule—Standards of Conduct, and on November 16, 2009, the FERC issued Order No. 717-B, an order clarifying what employees should be considered marketing function employees.  In both orders, the FERC clarified a lengthy list of issues relating to: the applicability, the definition of transmission function and transmission function employees, the definition of marketing function and marketing function employees, the definition of transmission function information, independent functioning, transparency, training, and North American Energy Standards Board business practice standards.  The FERC generally reaffirmed its determinations in Order No. 717, but granted rehearing on and clarified certain provisions.pro visions.  Order Nos. 717-A and 717-B aim to make the Standardsstandards of Conductconduct clearer and aim to refocus the rules on the areas where there is the greatest potential for abuse.  The rehearing and clarification granted in Order No. 717-A are not anticipated to have a material impact on the operation of our interstate pipelines.

The intrastate common carrier operations of our Pacific operations’ pipelines 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 our Pacific operations’ 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 issuesissue s similar to those which have arisen with respect to our FERC regulated rates also could also arise with respect to our intrastate rates.  Certain of our Pacific operations’ pipeline rates have been, and continue to be, subject to complaints with the CPUC, as is more fully described in Note 16 to our consolidated financial statements included elsewhere in this report.

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.

Our interstate pipelines are subject to regulation by the United States Department of Transportation, referred to in this report as the 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, and we are also subjectrailcars.

On September 15, 2010, the secretary of the U.S. DOT sent to the requirementsU.S. Congress proposed legislation to provide stronger oversight of the Federal Occupationalnation's pipelines and to increase the penalties for violations of pipeline safety rules.  The proposed legislation entitled “Strengthening Pipeline Safety and HealthEnforcement Act of 2010,” would, among other things, increase the maximum fine for the most serious violations from $1 million to $2.5 million, provide additional resources for the enforcement program, require a review of whether safety requirements for “high consequence areas” should be applied instead to entire pipelines, eliminate exemptions and other comparable federalensure standards are in place for bio-fuel and state statutes that address employee health and safety.carbon dioxide pipelines.

The Pipeline Safety Improvement Act of 2002 provides guidelines in the areas of testing, education, training and communication.  The Pipeline Safety Improvement 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“high consequence areas.”  Testing consists of 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 exists for refined petroleum products pipelines.

In general, we expect to increase expenditures in the future to comply with higher industry and regulatory safety standards.  However, we cannot accurately estimate suchSuch increases in our expenditures, and the extent to which they might be offset, cannot be accurately estimated at this time.

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 human health 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.  Furthermore, new projects may require approvals and environmental analysis u nder federal and state laws, including the National Environmental Policy Act and the Endangered Species Act.  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.

In accordance with generally accepted accounting principles, 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 in this report as the U.S. EPA, or similar state or Canadian 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, weWe believe that the ultimateultimat e resolution of these environmental matters will not have a material adverse effect on our business, financial position or results of operations.  However, it is possible that our ultimate liability with respect to these environmental matters could exceed the amounts accrued in an amount that could be material to our business, financial position, results of operations or distributions to limited partners in any particular reporting period.  We have accrued an environmental reserve in the amount of $81.1$74.7 million as of December 31, 2009.2010.  Our reserve estimates range in value from approximately $81.1$74.7 million to approximately $138.5$122.7 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 16 to our consolidated financial statements included elsewhere in this report.

We generate both hazardous and non-hazardous wastes that are subject to the requirements of the Federal Resource Conservation and Recovery Act and comparable state and Canadian statutes.  From time to time, state regulators and the U.S. EPA and state and Canadian regulators 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“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 operatingoperati ng expenses for us.

The Comprehensive Environmental Response, Compensation and Liability Act, referred to as CERCLA in this report and commonlyalso known as “CERCLA” or the Superfund“Superfund” law, and analogous state and Canadian laws, impose joint and several liability, without regard to fault or the legality of the original conduct, on certain classes of potentially“potentially responsible personspersons” for releases of hazardous substances“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.

Our operations are subject to the Clean Air Act, its implementing regulations, and analogous state and Canadian statutes and regulations.  We believe that the operations of our pipelines, storage facilities and terminals are in substantial compliance with such statutes.  The U.S. EPA has recently adopted new regulations under the Clean Air Act that are to take effect in early 2011 and that establish requirements for the monitoring, reporting, and control of greenhouse gas emissions from stationary sources.  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 and processing facilities, storage facilities, and terminals.terminals an d wells.  Depending on the nature of those requirements and any additional requirements that may be imposed by state, local and localCanadian 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.  At this time, we are unable to fully estimate the effect on earnings or operations or the amount and timing of such required capital expenditures; however, we do not believe that we will be materially adversely affected by any such requirements.

Our operations can result in the discharge of pollutants.  The Federal Water Pollution Control Act of 1972, as amended, also known as the Clean Water Act, and analogous state and Canadian laws 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, state or stateCanadian authorities.  The Oil Pollution Act was enacted in 1990 and amends provisions of the Clean Water Act pertaining to prevention and response to oil spills.  Spill prevention control and countermeasure requirements of the Clean Water Act and some state and Canadian laws require containment and similar structures to help prevent contaminationcontam ination of navigable waters in the event of an overflow or release.

Studies have suggested that emissions of certain gases, commonly referred to as greenhouse“greenhouse gases,” may be contributing to warming of the Earth’sEarth'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.  On June 26, 2009, the U.S. House of Representatives passed the “AmericanAmerican Clean Energy and Security Act of 2009,” or “ACESA,” referred to in this report as ACESA, which would establish an economy-wide cap-and-trade program to reduce U.S. emissions of “greenhouse gases”greenhouse gases, including carbon dioxide and methane.  The U.S. Senate ishas been working on its own legislation for restricting domestic greenhouse gas emissions, and President Obama has indicated his support of legislation to reduce greenhouse gas emissions through an emission allowance system.  It is not possible at this time to predict when the Senate may act on climate change legislation or how any bill passed by the Senate would be reconciled with ACESA.

The U.S. EPA separately announced on December 7, 2009, its findingsfinding that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to human health and the environment.  These findingsThis finding by the U.S. EPA may allowallowed the agency to proceed with the adoption and implementation ofadopt regulations that would restrictbegan restricting emissions of greenhouse gases underfrom certain stationary sources using existing provisions of the federal Clean Air Act. In addition,Act on September 22, 2009,January 2, 2011.  Additionally, the U.S. EPA has issued a final rule requiring the reporting of greenhouse gas emissions in the United States beginning in 2011 for emissions occurringthat occurred in 2010 from specified large greenhouse gas emission sources, fractionated natural gas liquids, and the production of naturally occurring carbon dioxide, like our McElmo Dome carbon dioxide field, even when such production is not emitted to the atmosphere.

Because our operations, including our compressor stations and gas processing plants in our Natural Gas Pipelines segment, emit various types of greenhouse gases, primarily methane and carbon dioxide, such legislation or regulation could increase our costs related to operating and maintaining our facilities and require us to install new emission controls on our facilities, acquire allowances for our greenhouse gas emissions, pay taxes related to our greenhouse gas emissions and administer and manage a greenhouse gas emissions program.  We are not able at this time to estimate such increased costs; however, they could be significant.  While we may be able to include some or all of such increased costs in the rates charged by our natural gas pipelines, such recovery of costs is uncertain in all cases and may depend on eventsev ents beyond our control including the outcome of future rate proceedings before the FERC and the provisions of any final legislation or other regulations.  Any of the foregoing could have adverse effects on our business, financial position, results of operations and prospects.

Some climatic models indicate that global warming is likely to result in rising sea level rise,levels, increased intensity of hurricanes and tropical storms, and increased frequency of extreme precipitation and flooding.  We may experience increased insurance premiums and deductibles, or a decrease in available coverage, for our assets in areas subject to severe weather.  To the extent these phenomena occur, they could damage our physical assets, especially operations located in low-lying areas near coasts and river banks, and facilities situated in hurricane-prone regions.  However, the timing and location of these climate change impacts is not known with any certainty and, in any event, these impacts are expected to manifest themselves over a long time horizon.  Thus, we are not in a position to say whether the physical impacts of climate change pose a material risk to our business, financial position, results of operations or prospects.

In Section 550 of the Homeland Security Appropriations Act of 2007, the U.S. Congress gave the Department of Homeland Security, referred to in this report as the DHS, regulatory authority over security at certain high-risk chemical facilities.  Pursuant to its congressional mandate, on April 9, 2007, the DHS promulgated the Chemical Facility Anti-Terrorism Standards and required all high-risk chemical and industrial facilities, including oil and gas facilities, to comply with the regulatory requirements of these standards.

KMGP Services Company, Inc., KMI and Kinder Morgan Canada Inc. employ all persons necessary for the operation of our business.  Generally, we reimburse these entities for the services of their employees.  As of December 31, 2009,2010, KMGP Services Company, Inc., KMI and Kinder Morgan Canada Inc. had, in the aggregate, 7,9318,142 full-time employees.  Approximately 890925 full-time hourly personnel at certain terminals and pipelines are represented by labor unions under collective bargaining agreements that expire between 20102011 and 2014.2015.  KMGP Services Company, Inc., KMI and Kinder Morgan Canada Inc. each consider relations with their employees to be good.  For more information on our related party transactions, see Note 11 to our consolidated financial statements included elsewhere in this report.

We believe that we have generally satisfactory title to the properties we own and use in our businesses, subject to liens for current taxes, liens incident to minor encumbrances, and easements and restrictions, which do not materially detract from the value of such property, the interests in those properties or the use of such properties in our businesses.  Our terminals, storage facilities, treating and processing plants, regulator and compressor stations, oil and gas wells, 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.

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’speople'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.

For geographic information concerning our assets and operations, see Note 15 to our consolidated financial statements included elsewhere in this report.