2012, the Montezuma County Board of County Commissioners denied the refund petitions, and we appealed to the Colorado Board of Assessment Appeals. A hearing on this matter will be held in the first quarter of 2013.

Other

~~In addition to the matters listed above, audits and administrative inquiries concerning Kinder Morgan CO~~₂’s payments on carbon dioxide produced from the McElmo Dome and Bravo Dome units are currently ongoing. These audits and inquiries involve federal agencies, the states of Colorado and New Mexico, and county taxing authorities in the state of Colorado.

Commercial ~~Litigation~~ Matters

Union Pacific Railroad Company Easements

SFPP and 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 v. 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 September 2011, the judge determined that the annual rent payable as of January 1, 2004 was $15 million, subject to annual consumer price index increases. SFPP intends to appeal the judge’s determination, but if that determination is upheld, SFPP would owe approximately $75 million in back rent. Accordingly, during 2011, we increased our rights-of-way liability to cover this liability amount. In addition, the judge determined that UPRR is entitled to an estimated $20 million for interest on the outstanding back rent liability. We believe the award of interest is without merit and we are pursuing our appellate rights.

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

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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 appealed this decision, and in December 2008, the appellate court affirmed the decision. In addition, UPRR contends that SFPP must comply with the more expensive AREMA standards in determining when relocations are necessary and in completing relocations. Each party is seeking declaratory relief with respect to its positions regarding the application of these standards with respect to relocations. A trial occurred in the fourth quarter of 2011, with a verdict having been reached that SFPP was obligated to comply with AREMA standards in connection with a railroad project in Beaumont Hills, California. SFPP is evaluating its post-trial and appellate options.

Since SFPP does not know UPRR’s plans for projects or other activities that would cause pipeline relocations, it is difficult to quantify the effects of the outcome of these cases on SFPP. 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, our results of operations, our cash flows, and our distributions to our limited partners. These effects would be even greater in the event SFPP is unsuccessful in one or more of these litigations.

Severstal Sparrows Point Crane Collapse

On June 4, 2008, a bridge crane owned by Severstal and located in Sparrows Point, Maryland collapsed while being operated by KMBT. According to our investigation, the collapse was caused by unexpected, sudden and extreme winds. On June 24, 2009, Severstal filed suit against KMBT in the United States District Court for the District of Maryland, Case No. 09CV1668-WMN. Severstal and its successor in interest, RG Steel, allege that KMBT was contractually obligated to replace the collapsed crane and that its employees were negligent in failing to properly secure the crane prior to the collapse. RG Steel seeks to recover in excess of $30 million for the alleged value of the crane and lost profits. KMBT denies each of RG Steel’s allegations. On or about June 1, 2012, RG Steel filed for bankruptcy in Case No. 12-11669 in the United States Bankruptcy Court for the District of Delaware; consequently, the trial date has been postponed indefinitely.

Pipeline Integrity and Releases

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From time to time, despite our best efforts, our pipelines experience leaks and ruptures. These leaks and ruptures may cause explosions, fire, and 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.

~~Perth Amboy, New Jersey Tank Release~~ General

In May 2011, the PHMSA issued an NOPV to KMLT. The notice alleges violations of PHMSA’s regulations related to an October 28, 2009 tank release from our Perth Amboy, New Jersey liquids terminal. No product left the company’s property, and additionally, there were no injuries, no impact to the adjacent community or public, and no fire as a result of the release. The notice proposes a penalty of less than ~~$1 million. KMLT is pursuing an administrative appeal of the NOPV.~~

~~Central Florida Pipeline Release, Tampa, Florida~~

On July 22, 2011, our subsidiary Central Florida Pipeline LLC reported a refined petroleum products release on a section of its 10-inch diameter pipeline near Tampa, Florida. The pipeline carries jet fuel and diesel to Orlando and was carrying jet fuel at the time of the incident. There was no fire and were no injuries associated with the incident. We immediately began clean up operations in coordination with federal, state and local agencies. The cause of the incident is outside force damage. The incident is under investigation by the PHMSA, U.S. EPA and the Florida Department of Environmental Protection.

~~General~~

Although no assurance can be given, we believe that we have meritorious defenses to the actions set forth in this note and, to the extent an assessment of the matter is reasonably possible, if it is probable that a liability has been incurred and the amount of loss can be reasonably estimated, we believe that we have established an adequate reserve to cover potential liability.

Additionally, although it is not possible to predict the ultimate outcomes, we also believe, based on our experiences to date and the reserves we have established, that the ultimate resolution of these matters will not have a material adverse impact on our business, financial position, results of operations or distributions to limited partners. As of ~~September 30, 2012~~March 31, 2013 and December 31, ~~2011~~,2012, we have recorded a total reserve for legal fees, transportation rate cases and other potential litigation liabilities in the amount of $~~309~~431 million and $~~332~~404 million, respectively. The reserve is primarily related to various claims from regulatory proceedings arising from our ~~West Coast~~ products pipeline and natural gas pipeline transportation ~~rates, and the contingent amount is based on both the circumstances of probability and reasonability of dollar estimates.~~rates. We regularly assess the likelihood of potential adverse outcomes ~~resulting from these claims~~in pending matters in order to determine the adequacy of our ~~liability provision.~~reserves.

Environmental Matters

We are subject to environmental cleanup and enforcement actions from time to time. In particular, the Comprehensive Environmental Response, Compensation and Liability Act, also know as CERCLA, generally imposes joint and several liability for cleanup and enforcement costs on current and predecessor owners and operators of a site, among others, without regard to fault or the legality of the original conduct, subject to the right of a liable party to establish a “reasonable basis” for apportionment of costs. 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,

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regulations and enforcement policies under the terms of authority of those laws, 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 alleged violations of environmental and safety regulations. As we receive notices of non-compliance, we attempt to negotiate and settle such matters where appropriate. Specifically, we are involved in matters including incidents at terminal facilities in New Jersey and Texas involving PHMSA and the Texas Commission on Environmental Quality, respectively, which may result in fines and penalties for alleged violations. We do not believe that these alleged violations will have a material adverse effect on our business, financial position, results of operations or distributions to limited partners.

We are also currently involved in several governmental proceedings involving groundwater and soil remediation efforts under administrative orders or related state remediation programs. 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.

Colorado Oil and Gas Conservation Commission Inspections

In Fall 2012, the Colorado Oil and Gas Conservation Commission (COGCC) performed inspections at multiple well sites in Southwestern Colorado owned by Kinder Morgan CO₂Company, L.P. and some of these inspections resulted in alleged violations of COGCC’s rules. Kinder Morgan took immediate steps to correct the alleged deficiencies and has engaged COGCC and other agencies in its efforts to maintain compliance. In April 2013, COGCC proposed a penalty of $300,000 to resolve the matter. We are evaluating the proposed penalty as well as potential responses to the alleged violations.

New Jersey Department of Environmental Protection v. Occidental Chemical Corporation, et al. (Defendants), Maxus Energy Corp. and Tierra Solutions, Inc. (Third Party Plaintiffs) v. 3M Company et al., Superior Court of New Jersey, Law Division –- Essex County, Docket No. L-9868-05

The NJDEP sued Occidental Chemical and others under the New Jersey Spill Act for contamination in the Newark Bay Complex including numerous waterways and rivers. Occidental et al. then brought in approximately 300 third party defendants for contribution. NJDEP claimed damages related to forty years of discharges of TCDD (a form of dioxin), DDT and “other hazardous substances.” GATX Terminals Corporation (n/k/a/ KMLT) was brought in as a third party defendant because of the noted hazardous substances language and because the Carteret, New Jersey facility (a former GATX Terminals facility) is located on the Arthur Kill River, one of the waterways included in the litigation. This case was filed against third party defendants in 2009. The judge issued his trial plan for this case during the first quarter of 2011. According to the trial plan, the judge allowed the State to file summary judgment motions against Occidental, Maxus and Tierra on liability issues immediately. Numerous third party defendants,Recently, KMLT, as part of a joint defense group, ~~of which KMLT is~~entered a ~~member, filed motions~~settlement agreement (Consent Judgment) with the NJDEP whereby the settling parties for a prescribed payment, get a contribution bar against first party defendants Occidental, Maxus and Tierra in addition to ~~dismiss, which were denied, and now have filed interim appeals from those motions. The appeals court panel heard oral arguments on these motions to dismiss~~a release. This third-party Consent Judgment will be published in ~~March 2012 and issued a ruling~~

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~~denying these motions in June 2012. The appellants have filed appeals to~~ the New Jersey ~~Supreme Court regarding~~Register followed by a 60-day comment period after which it will be lodged with the court. Additionally, we have information that the NJDEP has reached an agreement in principle on terms for a settlement with Maxus and Tierra. Occidental is not part of the settlement. As part of this ~~lower court ruling. Maxus/Tierra’s~~settlement, these defendants agree to dismiss all direct claims against third-party defendants and to not oppose the ~~third party defendants are set~~third-party settlement. We expect the first-party settlement to be ~~tried in April 2013 with damages to be tried in September 2013.~~finalized over the next 60 days. All discovery and trial proceedings are stayed during these settlement negotiations.

Portland Harbor Superfund Site, Willamette River, Portland, Oregon

In December 2000, the U.S. ~~EPA~~Environmental Protection Agency (U.S. EPA) sent out General Notice letters to potentially responsible parties including GATX Terminals Corporation (n/k/a KMLT). At that time, GATX owned two liquids terminals along the lower reach of the Willamette River, an industrialized area known as Portland Harbor. Portland Harbor is listed on the National Priorities List and is designated as a Superfund Site under CERCLA. ~~The major~~A group of potentially responsible parties formed what is known as the Lower Willamette Group (LWG), of which KMLT is a ~~non-voting~~non-

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voting member and pays a minimal fee to be part of the group. The LWG agreed to conduct the Remedial Investigation and Feasibility Study leading to the proposed remedy for cleanup of the Portland Harbor site. Once the U.S. EPA determines the cleanup remedy from the remedial investigations and feasibility studies conducted during the last decade at the site, it will issue a Record of Decision. Currently, KMLT and 90 other parties are involved in an allocation process to determine each party’s respective share of the cleanup costs. This is a non-judicial allocation process. We are participating in the allocation process on behalf of both KMLT and KMBT. Each entity has two facilities located in Portland Harbor. We expect the allocation to conclude in 2013 or 2014, depending upon when the U.S. EPA issues its Record of Decision.

Roosevelt Irrigation District v. Kinder Morgan G.P., Inc., Kinder Morgan Energy Partners, L.P. , U.S. District Court, Arizona

This is a CERCLA case brought against a number of defendants by a water purveyor whose wells have allegedly been contaminated due to the presence of a number of contaminants. The Roosevelt Irrigation District is seeking up to $175 million from approximately 70 defendants. The plume of contaminants has traveled under Kinder Morgan’s Phoenix Terminal. The plaintiffs have advanced a novel theory that the releases of petroleum from the Phoenix Terminal (which are exempt under the petroleum exclusion under CERCLA) have facilitated the natural degradation of certain hazardous substances and thereby have resulted in a release of hazardous substances regulated under CERCLA. We are part of a joint defense group consisting of other terminal operators at the Phoenix Terminal including Chevron, BP, Salt River Project, Shell and a number of others, collectively referred to as the terminal defendants. Together, we filed a motion to dismiss all claims based on the petroleum exclusion under CERCLA. This case was assigned to a new judge, who has deemed all previous motions withdrawn and will grant leave to re-file such motions at a later date. We plan to re-file the motion to dismiss as well as numerous summary judgment motions as the judge allows.

~~Casper and Douglas, U.S. EPA Notice of Violation~~

In March 2011, the U.S. EPA conducted inspections of several environmental programs at the Douglas and Casper Gas Plants in Wyoming. In June 2011, we received two letters from the U.S. EPA alleging violations at both gas plants of the Risk Management Program requirements under the Clean Air Act. In September 2012, we entered into Combined Complaint and Consent Agreements and paid a monetary penalty of ~~$158,000~~ ~~for each plant to resolve these issues.~~

The City of Los Angeles v. Kinder Morgan Liquids Terminals, LLC, Shell Oil Company, Equilon Enterprises LLC; California Superior Court, County of Los Angeles, Case No. NC041463

KMLT is a defendant in a lawsuit filed in 2005 alleging claims for environmental cleanup costs at the former Los Angeles Marine Terminal in the Port of Los Angeles. The lawsuit was stayed beginning in 2009 and ~~remains~~remained stayed ~~through~~following the ~~next~~last case management conference in March 2013. During the stay, the parties deemed responsible by the local regulatory agency (including the City of Los Angeles) have worked with that agency concerning the scope of the required ~~cleanup and have now completed a sampling and testing program at the site.~~cleanup. We anticipate that cleanup activities by the Port at the site will begin in the ~~Spring~~summer of 2013. ~~The local regulatory agency issued specific cleanup goals in early 2010,~~On April 9, 2013, KMLT and ~~two of those parties, including KMLT, have appealed those cleanup goals to the state water board. The state water board has not yet taken any action with regard to our appeal petitions.~~

~~Plaintiff’s Third Amended Complaint alleges that future environmental cleanup costs at the former terminal will exceed~~ ~~$10 million, and that the plaintiff’s past damages exceed~~ ~~$2 million. No trial date has yet been set. We have begun settlement negotiations with~~ the Port of Los ~~Angeles.~~Angeles entered into a Settlement and Release Agreement the terms of which provide for the dismissal of the litigation by the Port upon the payment by KMLT of 60% of the Port’s costs to remediate the former terminal site; the amount of payment not to exceed $15 million. The parties also filed a Good Faith Settlement motion in the Superior Court as part of the process of dismissal of the case. Further, according to terms of the Settlement and Release, we received a 5-year lease extension that allows KMLT to continue fuel loading and offloading operations at another KMLT Port of Los Angeles terminal property.

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Exxon Mobil Corporation v. GATX Corporation, Kinder Morgan Liquids Terminals, LLC and ST Services, Inc.

On April 23, 2003, 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 Corp. from 1989 through September 2000, and later owned by Support Terminals and Pacific Atlantic Terminals, LLC. The terminal is now owned by Plains Products, and it too is a party to the lawsuit.

On June 25, 2007, the NJDEP, 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 KMLT, formerly known as GATX Terminals Corporation, alleging natural resource damages related to historic contamination at the Paulsboro terminal. The complaint was filed in Gloucester County, New Jersey. Both ExxonMobil and KMLT filed third party complaints against Support Terminals/Plains ~~seeking to bring~~and successfully brought Support Terminals/Plains into the case. ~~Support Terminals/Plains filed motions to dismiss the third party complaints, which were denied. Support Terminals/Plains is now joined in the case, and it filed an Answer denying all claims.~~ The court ~~has~~ consolidated the two cases. ~~All private parties and the state participated in two mediation conferences in 2010.~~

In mid 2011, KMLT and Plains Products entered into ana settlement agreement ~~in principle~~ with the NJDEP for settlement of the state’s alleged natural resource damages claim. The parties then entered into a Consent Judgment ~~which was subject to public notice and comment and court approval.~~ concerning the claim.

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The natural resource damage settlement includes a monetary award of $1 million and a series of remediation and restoration activities at the terminal site. KMLT and Plains Products have joint responsibility for this settlement. Simultaneously, KMLT and Plains Products entered into a settlement agreement that settled each ~~parties’~~party’s relative share of responsibility (50/50) to the NJDEP under the Consent Judgment noted above. The Consent Judgment is now entered with the Court and the settlement is final. ~~Now~~According to the agreement, Plains will ~~begin conducting~~conduct remediation activities at the site and KMLT will provide oversight and 50% of the costs.

The settlement with the state ~~does~~did not resolve the original complaint brought by ExxonMobil. On or around, April 10, 2013, KMLT, Plains and ExxonMobil settled the original Exxon complaint for past remediation costs for $750,000 to be split 50/50 between KMLT and ~~Plains received a settlement demand from ExxonMobil in~~Plains. All parties have now executed the ~~amount of~~ ~~$1.38 million~~ ~~for past costs related to~~agreement and the ~~remediation at the Paulsboro facility. Plains~~litigation is settled and ~~KMLT are in discussions regarding the ExxonMobil offer. There is no trial date set.~~dismissed.

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 us and several affiliates seeking injunctive relief and unspecified damages allegedly resulting from hydrocarbon and methyl tertiary butyl ether (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, we removed the case to the United States District Court, Southern District of California, case number 07CV1883WCAB. The City disclosed in discovery that it is seeking approximately $170 million in damages for alleged lost value/lost profit from the redevelopment of the City’s property and alleged lost use of the water resources underlying the property. Later, in 2010, the City amended its initial disclosures to add claims for restoration of the site as well as a number of other claims that increased their claim for damages to approximately $365 million.

~~The Court issued a~~In accordance with the Case Management Order, ~~on January 6, 2011, setting dates for completion of discovery and setting a trial date. In April 2011,~~ the parties filed a joint stipulation to extend the discovery schedule by approximately three months. In December 2011, the parties again entered into a joint stipulation to extend the various schedules in the Court’s Case Management Order. According to the schedule, the parties completed fact discovery in March 2012 and expert discovery in May 2012. Both parties filed their respective summary adjudication motions and motions to exclude experts on June 29, 2012. ~~Oral arguments related~~On November 29, 2012, the Court issued a Notice of Tentative Rulings on the parties’ pending motions. The Court tentatively granted our motions to ~~these~~exclude certain of the City’s proposed expert witnesses, tentatively granted our partial motions ~~are set~~ for ~~November 30, 2012. The trial is now set~~summary judgment on the City’s claims for ~~April 9, 2013. We have been~~water and ~~will continue to aggressively defend this action.~~real estate damages and the State’s claims for violations of California Business and Professions Code § 17200, tentatively denied the City’s motion for summary judgment on its claims of liability for nuisance and trespass, and tentatively granted our cross motion for summary judgment on such claims. On January 25, 2013, the Court issued its final order reaffirming in all respects its tentative rulings and rendered judgment in favor of all defendants on all claims asserted by the City. This site has been, and currently is, under the regulatory oversight and order of the California Regional Water Quality Control Board. ~~We continue~~SFPP continues to conduct an extensive remediation effort at the ~~City's~~City’s stadium property site.

~~Kinder Morgan, U.S. EPA Section 114 Information Request~~

~~On January 8, 2010, KMI,~~Uranium Mines in Vicinity of Cameron, Arizona

In the 1950s and 1960s, Rare Metals Inc., an historical subsidiary of EPNG, operated approximately twenty uranium mines in the vicinity of Cameron, Arizona, many of which are located on ~~behalf~~the Navajo Indian Reservation. The mining activities were in response to numerous incentives provided to industry by the United States to locate and produce domestic sources of ~~Natural Gas Pipeline Company of America LLC, Horizon Pipeline Company and Rockies Express,~~uranium to support the Cold War-era nuclear weapons program. In May 2012, EPNG received a ~~Clean Air Act Section 114 information request~~general notice letter from the U.S. EPA ~~Region V. This~~

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~~information request requires~~the EPA's investigation of certain sites and its determination that the ~~three affiliated companies provide the U.S.~~ EPA ~~with air permit and various other information related~~considers EPNG to their natural gas pipeline compressor station operations located in Illinois, Indiana, and Ohio. The affiliated companies have responded to the request and believe the relevant natural gas compressor station operations are in substantial compliance with applicable air quality laws and regulations.

~~Administrative Agreement with the U.S. EPA~~

In April 2011, we received Notices of Proposed Debarment from the U.S. EPA SDD. The Notices proposed the debarment of us (along with four of our subsidiaries), KMI, Kinder Morgan G.P., Inc., and Kinder Morgan Management, LLC, from participation in future federal contracting and assistance activities. The Notices alleged that certain of the respondents’ past environmental violations indicated a lack of present responsibility warranting debarment.

In May 2012, we reached an administrative agreement with the U.S. EPA which resolved this matter without the debarment of any Kinder Morgan entities. The agreement requires independent monitoring of our Environmental Compliance and Ethics Programs, independent auditing of our facilities, enhanced training and notification requirements, and certain enhancements to our operational and compliance policies and procedures. We take environmental compliance very seriously and expect to comply with all aspects of this agreement.

~~TGP, PHMSA Notice of Violation~~

~~On April 25, 2012, the PHMSA issued an NOPV against TGP proposing~~ ~~$118,500~~ ~~in penalties for alleged violations discovered during an inspection prior to Kinder Morgan's ownership of TGP. We responded to the NOPV and paid the penalty to resolve this matter.~~

~~Other Environmental~~

We are subject to environmental cleanup and enforcement actions from time to time. In particular, CERCLA generally imposes joint and several liability for cleanup and enforcement costs on current and predecessor owners and operators of a site, among others, without regard to fault or the legality of the original conduct, subject to the right of a liable party to establish a “reasonable basis” for apportionment of costs. 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 under the terms of authority of those laws, 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 alleged violations of environmental and safety regulations. As we receive notices of non-compliance, we negotiate and settle these matters. We do not believe that these alleged violations will have a material adverse effect on our business, financial position, results of operations or cash flows.

~~In addition, we are involved with and have been identified as~~ a potentially responsible party ~~in several federal~~within the meaning of CERCLA. In February 2013, the EPA delivered a proposed Administrative Order on Consent and ~~state superfund sites. Environmental reserves have been established for those sites where our~~proposed Scope of Work regarding the government's proposed next steps to investigate the mines. We are negotiating the terms and conditions of both the Administrative Order on Consent and the Scope of Work. We are also seeking 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~~the United States toward the cost of ~~accidental leaks or spills~~environmental activities associated with the mines, given its pervasive control over all aspects 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.the nuclear weapons program.

General

Although it is not possible to predict the ultimate outcomes, we believe that the resolution of the environmental

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matters set forth in this note, and other matters to which we are a party, 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~~resolution of ~~these~~such claims will occur, and changing circumstances could cause these matters to have a material

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adverse impact. As of ~~September 30,~~March 31, 2013 and December 31, 2012,, we have accrued ana total reserve for environmental ~~reserve~~liabilities in the amount of $~~110 million~~ ~~(including~~ ~~$1 million~~ ~~of environmental related liabilities belonging to our FTC Natural Gas Pipelines disposal group). In addition, as of~~ ~~September 30, 2012, we have recorded a receivable of~~ ~~$5 million~~ ~~for expected cost recoveries that have been deemed probable. As of~~ ~~December 31, 2011, our environmental reserve totaled~~ ~~$75~~163 million and ~~our estimated receivable for environmental cost recoveries totaled~~ $5166 million., respectively. 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.

~~Other~~10. Regulatory Matters and Accounting for Regulatory Activities

~~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~~Regulatory Assets and ~~taking into account established reserves, 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.~~Liabilities

~~11. Regulatory Matters~~

Regulatory assets and liabilities represent probable future revenues or expenses associated with certain charges and credits that will be recovered from or refunded to customers through the ratemaking process. ~~The amount~~We included the amounts of our regulatory assets and liabilities ~~reflected~~ within “Other current assets,” “Deferred charges and other ~~assets”~~assets,” “Accrued other current liabilities” and “Other long-term liabilities and deferred credits,” respectively, in our accompanying consolidated balance ~~sheets as of~~sheets. The recovery period for these regulatory assets is approximately 20 years.

The following table summarizes our regulatory asset and liability balances (in millions):



	March 31, 2013		December 31, 2012
Current regulatory assets	$	26	$	18
Non-current regulatory assets	203		204
Total Regulatory Assets	$	229	$	222

Current regulatory liabilities	$	4	$	4
Non-current regulatory liabilities	62		65
Total Regulatory Liabilities	$	66	$	69

More information about our regulatory matters can be found in Note 17 ~~September 30, 2012~~“ ~~and~~ ~~December 31, 2011~~ ~~are not material~~Regulatory Matters” to our consolidated balance sheets. For information on our pipeline regulatory proceedings, see Note 10 “Litigation, Environmental and Other Contingencies—Federal Energy Regulatory Commission Proceedings” and “California Public Utilities Commission Proceedings.”

~~TGP's Proposed Sale of Production Area Facilities~~

~~On July 26, 2012, TGP filed an application with the FERC seeking authority to abandon by sale certain offshore and~~

~~onshore supply facilities as well as a related offer of settlement~~financial statements that ~~addresses the proposed rate and accounting treatment~~

associated with the sale. The offer of settlement provides for a rate adjustment to TGP’s maximum tariff rates upon the transfer of the assets and the establishment of a regulatory asset for a portion of the unrecovered net book value of the facilities to be sold. The sale is conditioned on approval by the FERC of both the requested abandonment authorization and offer of settlement. As of ~~September 30, 2012, these assets totaled$32 million~~ ~~and are~~were included ~~within "Assets held for sale"~~ in our ~~accompanying consolidated balance sheet. Additionally, we have recorded an approximately~~ ~~$115 million~~ ~~regulated asset, which is included within "Deferred charges and other assets" in our accompanying consolidated balance sheet as of~~ ~~September 30, 2012, for the portion of the loss that we expect to recover through TGP's jurisdictional transportation rates as outlined in the FERC filing.~~

~~TGP Northeast Supply Diversification Project (Docket No. CP11-30-000)~~

On September 10, 2011, the FERC issued an order authorizing the expansion of TGP's pipeline facilities in northern Pennsylvania and western New York along with an associated lease of transportation capacity from Dominion Transmission, Inc. in order to provide incremental firm transportation service to shippers of ~~250,000~~ ~~dekatherms per day of natural gas produced in the Marcellus Shale supply area to northeast markets. The estimated capital cost of the project is~~ ~~$56 million~~ ~~and the capacity is fully subscribed under long-term contracts. The project is planned to be placed in service on November 1, 2012.~~

~~TGP Northeast Upgrade Project (Docket No. CP11-161-000)~~

~~On May 29,~~ 2012 the FERC issued an order authorizing the expansion of TGP's pipeline facilities in Pennsylvania and New Jersey that will provide needed infrastructure to support continued development of Marcellus shale natural gas production and increase TGP's delivery capacity in the region by ~~636,000~~ ~~dekatherms per day. The estimated capital cost of the project is approximately~~ ~~$376 million~~ ~~and the capacity is fully subscribed under long term contracts. The project is anticipated to be placed in service on November 1, 2013.~~

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~~TGP MPP Project (Docket No. CP12-28-000)~~

On August 9, 2012, the FERC issued an order authorizing the expansion of TGP's pipeline facilities in northwestern Pennsylvania that will provide needed infrastructure to support continued development of Marcellus shale natural gas production and increase TGP's delivery capacity in the region by ~~240,000~~ ~~dekatherms per day. The estimated capital cost of the project is approximately~~ ~~$89 million, and the capacity is fully subscribed under long term contracts. The project is anticipated to be placed in service on November 1, 2013.~~

~~TGP Rose Lake Expansion Project (Docket No. CP13-03-000)~~

On October 10, 2012, TGP filed an application with the FERC requesting authority to expand its pipeline capacity in northern Pennsylvania through the installation and modification of new and existing compression facilities that will result in increased capacity of ~~230,000~~ dekatherms per day and will improve the efficiency and reduce emissions by replacing certain older existing compression facilities. The project will further support continued development of Marcellus shale natural gas production in the region. The estimated capital cost of the project is approximately ~~$92 million~~ ~~and the capacity is fully subscribed under long term contracts. The project is anticipated to be placed in service on November 1, 2014.~~

~~EPNG Regulatory Matters~~

~~Docket No. RP08-426~~

In April 2010, the FERC approved an offer of settlement which increased EPNG's base tariff rates, effective January 1, 2009. The settlement resolved all but four issues in the proceeding. In January 2011, the presiding administrative law judge issued a decision that for the most part found against EPNG on those four issues. In May 2012, the FERC upheld the initial decision of the presiding administrative law judge in Opinion No. 517 on three of the issues and found in favor of EPNG on one of the issues. EPNG, along with other parties, has sought rehearing of those decisions to the FERC and may also seek review of any of the FERC's decisions to the U.S. Court of Appeals. However, in compliance with Opinion No. 517, EPNG filed with the FERC to implement certain aspects of the May 2012 order as they relate to rates under Docket No. RP08-426. Although the final outcome of all issues related to this open docket is not currently determinable, EPNG believes the accruals established for this matter are adequate.

~~Docket No. RP10-1398~~

~~In September 2010, EPNG filed a new rate case with the FERC proposing an increase in base tariff rates which would increase revenues by approximately~~ ~~$100 million~~ annually over previously effective tariff rates. In October 2010, the FERC issued an order accepting and suspending the effective date of the proposed rates to April 1, 2011, subject to refund, the outcome of a hearing and other proceedings. Hearings were conducted during the fourth quarter of 2011 and in June 2012, the presiding administrative law judge issued an initial decision which was overall favorable for EPNG. The initial decision is currently being reviewed by the FERC. Participants may appeal this decision to the FERC and ultimately seek review of the FERC's decision to the U.S. Court of Appeals. Additionally, certain customers have requested that the FERC require EPNG to decrease its currently effective recourse rates based on an order issued in May 2012 for matters in Docket No. RP08-426. The FERC issued an order requiring the implementation of its decisions in Docket No. RP08-426, which included interim reductions to the currently effective rates. Although EPNG requested rehearing on the interim rate decrease, EPNG filed proforma tariff records to comply with the FERC's order and requested adequate surcharge authority in the event the final rates are above the interim rates. That rehearing request and filing currently are pending before the FERC. EPNG is pursuing settlement with its customers of all issues in both open rate cases. It is uncertain whether the expected increase in revenues will be achieved in the context of any such settlement or following the final determination of the FERC or the courts on the rate matters. Although the final outcome is not currently determinable, EPNG believes the accruals established for this matter are adequate.

~~Docket No. CP12-6-000~~

On October 7, 2011, EPNG submitted an application, pursuant to Section 7(c) of the Natural Gas Act (NGA), requesting a certificate of public convenience and necessity authorizing the construction and operation of the Willcox Lateral 2013 Expansion Project located in Cochise County, Arizona. Concurrent with that application, EPNG also filed an application, pursuant to Section 3 of the NGA, for amended presidential permits to increase the export capacity of

~~Table of Contents~~

~~certain border crossings connected to the Willcox Lateral. At a cost of approximately~~ ~~$23 million~~, the project consists of modifications to the existing EPNG Willcox Compressor Station, increasing the maximum allowable operating pressure of the Willcox Lateral, replacing various pipeline road crossings, and upgrading existing meter stations. The new project facilities would create ~~185,000~~ dekatherms per day of incremental capacity on the Willcox Lateral. A FERC order approving this project was issued on October 12, 2012, with construction activities beginning shortly thereafter to permit a project in-service date by the second quarter 2013.Form 10-K.

~~12.~~11. Recent Accounting Pronouncements

Accounting Standards Updates

None of the Accounting Standards Updates (ASU) that we adopted and that became effective January 1, ~~2012~~2013 (including ~~ASU No. 2011-8, “Intangibles—Goodwill and Other (Topic 350): Testing Goodwill for Impairment”) had a material impact on our consolidated financial statements.~~

~~ASU No. 2011-11~~

~~On December 16, 2011, the Financial Accounting Standards Board issued~~(i) ASU No. 2011-11, “Balance Sheet (Topic 210): Disclosures about Offsetting Assets and ~~Liabilities.~~Liabilities;” This ASU requires disclosures to provide information to help reconcile differences in the offsetting requirements under U.S. Generally Accepted Accounting Principles and International Financial Reporting Standards. The disclosure requirements of this ASU mandate that entities disclose both gross and net information about financial instruments and transactions eligible for offset in the statement of financial position as well as instruments and transactions subject to an enforceable master netting arrangement or similar agreement. ASU No. 2011-11 also requires disclosure of collateral received and posted in connection with master netting arrangements or similar arrangements. The scope of this ASU includes derivative contracts, repurchase agreements, and securities borrowing and lending arrangements. Entities are required to apply the amendments of ASU No. 2011-11 for annual reporting periods beginning on or after January 1, 2013, and interim periods within those annual periods. All disclosures provided by those amendments are required to be provided retrospectively for all comparative periods presented. We are currently reviewing the effects of ASU No. 2011-11.

~~ASU No. 2012-02~~

~~On July 27, 2012, the Financial Accounting Standards Board issued~~(ii) ASU No. 2012-02, “Intangibles-Goodwill and Other (Topic 350): Testing Indefinite-Lived Intangible Assets for ~~Impairment.~~Impairment;” This ASU allows an entity the option to first assess qualitative factors to determine whether the existence of events and circumstances indicates that it is more likely than not (that is, a likelihood of more than 50%) that an indefinite-lived intangible asset other than goodwill is impaired. If, after this assessment, an entity concludes that it is not more likely than not that the indefinite-lived intangible asset is impaired, the entity is not required to take further action. However, if an entity concludes otherwise, then it is required to determine the fair value of the indefinite-lived intangible asset and perform the quantitative impairment test prescribed by current accounting principles. Moreover, an entity can bypass the qualitative assessment for any indefinite-lived intangible asset in any period and proceed directly to the quantitative impairment test, and then resume performing the qualitative assessment in any subsequent period.(iii) ASU No. ~~2012-02 is effective for annual~~2013-01, “Clarifying the Scope of Disclosures about Offsetting Assets and ~~interim impairment tests performed for fiscal years beginning after September 15, 2012 (January 1, 2013 for us),~~Liabilities;” and ~~early adoption is permitted. We are currently reviewing the effects of~~(iv) ASU No. ~~2012-02.~~2013-02, “Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income”) had a material impact on our consolidated financial statements. More information about the four ASUs listed above can be found in Note 18 “Recent Accounting Pronouncements” to our consolidated financial statements that were included in our 2012 Form 10-K.

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

General and Basis of Presentation

The following discussion and analysis should be read in conjunction with (i) our accompanying interim consolidated financial statements and related notes (included elsewhere in this report); (ii) our consolidated financial statements and related notes included in our ~~2011~~2012 Form 10-K; and (iii) our management’s discussion and analysis of financial condition and results of operations included in our ~~2011~~2012 Form ~~10-K and in our Current Report on Form 8-K filed May 1, 2012.~~10-K.

Table of Contents

We prepared our consolidated financial statements in accordance with U.S. generally accepted accounting principles. In addition, as discussed in ~~Notes~~Note 1 “General” and Note 2 “Acquisitions and 3Discontinued Operations” to our consolidated financial statements included elsewhere in this report,

~~Table of Contents~~

our financial statements reflect:

the reclassifications necessary to reflect the results of our FTC Natural Gas Pipelines disposal group as discontinued operations. Accordingly, we have excluded the disposal group’s financial results from our Natural Gas Pipelines business segment disclosures for all periods presented in this report; and

our ~~August~~March 1, ~~2012~~2013 acquisition of net assets from KMI as if such acquisition had taken place on ~~May 25, 2012,~~ the effective ~~date that KMI acquired the same net assets from El Paso Corporation.~~dates of common control pursuant to generally accepted accounting principles. We refer to this transfer of net assets from KMI to us as the drop-down transaction, and we refer to the transferred assets as our drop-down asset group. We accounted for the drop-down transaction as a ~~transfer~~combination of ~~net assets between~~ entities under common control, and accordingly, the financial information contained in this ~~Management's~~Management’s Discussion and Analysis of Financial Condition and Results of Operations include the financial results of the drop-down asset group for all periods subsequent to ~~May 25,~~the effective dates of common control; and

the reclassifications necessary to reflect the results of our FTC Natural Gas Pipelines disposal group as discontinued operations. We sold our FTC Natural Gas Pipelines disposal group to Tallgrass Development, LP (now known as Tallgrass Energy Partners, LP) effective November 1, 2012 for approximately $1.8 billion in cash (before selling costs), or $3.3 billion including our share of joint venture debt. In the first quarter of 2013, following final working capital and other liability account reconciliations, we recorded an incremental loss of $2 million related to our sale of the disposal group, and except for this loss amount, we recorded no other financial results from the operations of the disposal group during the first quarter of 2013. Furthermore, we have excluded the disposal group’s financial results from our Natural Gas Pipelines business segment disclosures for the three months ended March 31, 2012.

Critical Accounting Policies and Estimates

Accounting standards require information in financial statements about the risks and uncertainties inherent in significant estimates, and the application of U.S. generally accepted accounting principles involves the exercise of varying degrees of judgment. Certain amounts included in or affecting our consolidated financial statements and related disclosures must be estimated, requiring us to make certain assumptions with respect to values or conditions that cannot be known with certainty at the time our financial statements are prepared. These estimates and assumptions affect the amounts we report for our assets and liabilities, our revenues and expenses during the reporting period, and our disclosure of contingent assets and liabilities at the date of our financial statements. We routinely evaluate these estimates, 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, and 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.

Furthermore, with regard to goodwill impairment testing, we review our goodwill for impairment annually, and we evaluated our goodwill for impairment on May 31, 2012. Our goodwill impairment analysis performed on that date did not result in an impairment charge nor did our analysis reflect any reporting units at risk, and subsequent to that date, no event has occurred indicating that the implied fair value of each of our reporting units (including its inherent goodwill) is less than the carrying value of its net assets.

Further information about us and information regarding our accounting policies and estimates that we consider to be “critical” can be found in Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our ~~2011~~2012 Form ~~10-K and our Current Report on Form 8-K filed May 1, 2012.~~10-K.

Table of Contents

Results of Operations

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.

Consolidated

~~Table of Contents~~

Three Months Ended
September 30,

2012 2011
Earnings
increase/(decrease)
(In millions, except percentages)
Segment earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments(a)
Products Pipelines(b) $ 150
$ 103
$ 47
46 %
Natural Gas Pipelines(c) 405
18
387
2,150 %
CO₂(d)
327
295
32
11 %
Terminals(e) 183
180
3
2 %
Kinder Morgan Canada 56
48
8
17 %
Segment earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments 1,121
644
477
74 %
Depreciation, depletion and amortization expense(f) (292 ) (247 ) (45 ) (18 )%
Amortization of excess cost of equity investments (1 ) (2 ) 1
50 %
General and administrative expense(g) (131 ) (100 ) (31 ) (31 )%
Interest expense, net of unallocable interest income(h) (181 ) (132 ) (49 ) (37 )%
Unallocable income tax expense (2 ) (2 ) —
— %
Income from continuing operations 514
161
353
219 %
Income (Loss) from discontinued operations(i) (131 ) 55
(186 ) (338 )%
Net Income 383
216
167
77 %
Net Income attributable to noncontrolling interests(j) (4 ) (1 ) (3 ) (300 )%
Net Income attributable to Kinder Morgan Energy Partners, L.P. $ 379

$ 215
$ 164
76 %

~~____________~~

~~Table of Contents~~


Results of Operations												Results of Operations

	Nine Months Ended September 30,											Three Months Ended March 31,
	2012			2011			Earnings increase / (decrease)					2013			2012			Earnings increase/(decrease)
	(In millions, except percentages)											(In millions, except percentages)
Segment earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments(a)
Products Pipelines(k)	$	492		$	304		$	188		62	%
Natural Gas Pipelines(l)	877			319			558			175	%
CO₂(m)	988			823			165			20	%
Natural Gas Pipelines												$	557		$	222		$	335		151	%
CO₂												342			334			8			2	%
Products Pipelines												185			176			9			5	%
Terminals~~(n)~~	565			525			40			8	%	186			187			(1		)	(1	)%
Kinder Morgan Canada~~(o)~~	158			150			8			5	%	193			50			143			286	%
Segment earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments	3,080			2,121			959			45	%
Segment earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments (EBDA)(b)												1,463			969			494			51	%
Depreciation, depletion and amortization expense~~(p)~~(c)	(796		)	(685		)	(111		)	(16	)%	(328		)	(239		)	(89		)	(37	)%
Amortization of excess cost of equity investments	(5		)	(5		)	—			—	%	(2		)	(2		)	—			—	%
General and administrative expense~~(q)~~(d)	(379		)	(387		)	8			2	%	(134		)	(107		)	(27		)	(25	)%
Interest expense, net of unallocable interest income~~(r)~~(e)	(474		)	(393		)	(81		)	(21	)%	(202		)	(139		)	(63		)	(45	)%
Unallocable income tax expense	(7		)	(7		)	—			—	%	(3		)	(2		)	(1		)	(50	)%
Income from continuing operations	1,419			644			775			120	%	794			480			314			65	%
Income (Loss) from discontinued operations(s)	(682		)	145			(827		)	(570	)%
Loss from discontinued operations(f)												(2		)	(272		)	270			99	%
Net Income	737			789			(52		)	(7	)%	792			208			584			281	%
Net Income attributable to noncontrolling interests~~(t)~~(g)	(12		)	(6		)	(6		)	(100	)%	(9		)	(2		)	(7		)	(350	)%
Net Income (Loss) attributable to Kinder Morgan Energy Partners, L.P.	$	725		$	783		$	(58	)	(7	)%
Net Income attributable to Kinder Morgan Energy Partners, L.P.												$	783		$	206		$	577		280	%



Delaware		76-0380342
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES TABLE OF CONTENTS

		Page Number
	PART I. FINANCIAL INFORMATION

Item 1.	Financial Statements (Unaudited)	3
	Consolidated Statements of Income - Three ~~and Nine~~ Months Ended ~~September 30, 2012~~March 31, 2013 and ~~2011~~2012	3
	Consolidated Statements of Comprehensive Income - Three ~~and Nine~~ Months Ended ~~September 30, 2012~~March 31, 2013 and ~~2011~~2012	4
	Consolidated Balance Sheets – ~~September 30, 2012~~March 31, 2013 and December 31, ~~2011~~2012	5
	Consolidated Statements of Cash Flows – ~~Nine~~Three Months Ended ~~September 30, 2012~~March 31, 2013 and ~~2011~~2012	6
	Notes to Consolidated Financial Statements	8

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	38
	General and Basis of Presentation	3832
	Critical Accounting Policies and Estimates	3933
	Results of Operations	3934
	Financial Condition	5645
	Recent Accounting Pronouncements	6250
	Information Regarding Forward-Looking Statements	6351

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	6351

Item 4.	Controls and Procedures	6351

	PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	6452

Item 1A.	Risk Factors	6452

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	6452

Item 3.	Defaults Upon Senior Securities	6452

Item 4.	Mine Safety Disclosures	6452

Item 5.	Other Information	6452

Item 6.	Exhibits	6552

	Signature	6754

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (In Millions Except Per Unit Amounts) (Unaudited)	KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (In Millions Except Per Unit Amounts) (Unaudited)												KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (In Millions Except Per Unit Amounts) (Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended March 31,
	2012			2011			2012			2011			2013			2012
Revenues
Natural gas sales	$	675		$	925		$	1,756		$	2,575		$	735		$	584
Services	989			737			2,585			2,190			1,188			761
Product sales and other	669			449			1,791			1,201			738			503
Total Revenues	2,333			2,111			6,132			5,966			2,661			1,848

Operating Costs, Expenses and Other
Gas purchases and other costs of sales	828			914			2,036			2,550
Costs of sales													957			580
Operations and maintenance	429			399			1,094			1,163			384			306
Depreciation, depletion and amortization	292			247			796			685			328			239
General and administrative	131			100			379			387			134			107
Taxes, other than income taxes	63			37			169			133			74			50
Other expense (income)	(8		)	(1		)	(28		)	(15		)
Total Operating Costs, Expenses and Other	1,735			1,696			4,446			4,903			1,877			1,282

Operating Income	598			415			1,686			1,063			784			566

Other Income (Expense)
Earnings from equity investments	100			52			225			155			83			65
Amortization of excess cost of equity investments	(1		)	(2		)	(5		)	(5		)	(2		)	(2		)
Interest expense	(184		)	(134		)	(480		)	(396		)
Interest income	8			6			19			16
Loss on remeasurement of previously held equity interest in KinderHawk to fair value (Note 2)	—			(167		)	—			(167		)
Interest expense, net													(199		)	(135		)
Gain on sale of investments in Express pipeline system													225			—
Other, net	4			3			14			11			4			1
Total Other Income (Expense)	(73		)	(242		)	(227		)	(386		)	111			(71		)

Income from Continuing Operations Before Income Taxes	525			173			1,459			677			895			495

Income Tax (Expense) Benefit	(11		)	(12		)	(40		)	(33		)
Income Tax Expense													(101		)	(15		)

Income from Continuing Operations	514			161			1,419			644			794			480

Discontinued Operations (Note 2)
Discontinued Operations (Notes 1 and 2)
Income from operations of FTC Natural Gas Pipelines disposal group	47			55			145			145			—			50
Loss from costs to sell and the remeasurement of FTC Natural Gas Pipelines disposal group to fair value	(178		)	—			(827		)	—
Income (Loss) from Discontinued Operations	(131		)	55			(682		)	145
Loss on sale and the remeasurement of FTC Natural Gas Pipelines disposal group to fair value													(2		)	(322		)
Loss from Discontinued Operations													(2		)	(272		)

Net Income	383			216			737			789			792			208

Net Income Attributable to Noncontrolling Interests	(4		)	(1		)	(12		)	(6		)	(9		)	(2		)

Net Income Attributable to Kinder Morgan Energy Partners, L.P.	$	379		$	215		$	725		$	783		$	783		$	206

Calculation of Limited Partners’ Interest in Net Loss
Calculation of Limited Partners’ Interest in Net (Loss) Income
Attributable to Kinder Morgan Energy Partners, L.P.:
Income from Continuing Operations	$	509		$	161		$	1,400		$	640		$	785		$	475
Less: Pre-acquisition income from operations of drop-down asset group allocated to General Partner (Note 2)	(36		)	—			(23		)	—
Less: General Partner’s remaining Interest	(367		)	(298		)	(1,024		)	(870		)
Less: Pre-acquisition income from operations of drop-down asset group allocated to General Partner													(19		)	—
Add: Drop-Down asset group severance expense allocated to General Partner													2			—
Less: General Partner’s remaining interest													(402		)	(321		)
Limited Partners’ Interest	106			(137		)	353			(230		)	366			154
Add: Limited Partners’ Interest in Discontinued Operations	(128		)	54			(668		)	142
Limited Partners’ Interest in Net Loss	$	(22	)	$	(83	)	$	(315	)	$	(88	)
Add: Limited Partners’ interest in discontinued operations													(2		)	(266		)
Limited Partners�� Interest in Net Income (Loss)													$	364		$	(112	)

Limited Partners’ Net Income (Loss) per Unit:
Income (Loss) from Continuing Operations	$	0.30		$	(0.41	)	$	1.02		$	(0.71	)
Income (Loss) from Discontinued Operations	(0.36		)	0.16			(1.93		)	0.44
Net Loss	$	(0.06	)	$	(0.25	)	$	(0.91	)	$	(0.27	)
Limited Partners’ Net Income (Loss) per Unit - basic and diluted:
Income from Continuing Operations													$	0.97		$	0.46
Loss from Discontinued Operations													—			(0.79		)
Net Income (Loss) - basic and diluted													$	0.97		$	(0.33	)

Weighted Average Number of Units Used in Computation of Limited Partners’ Net Income (Loss) per Unit	356			331			345			323
Weighted Average Number of Units Used in Computation of Limited Partners’ Net Income per Unit													376			338

Per Unit Cash Distribution Declared	$	1.26		$	1.16		$	3.69		$	3.45		$	1.30		$	1.20

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

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (In Millions)	KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (In Millions)				KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (In Millions)

	September 30, 2012		December 31, 2011		March 31, 2013		December 31, 2012(a)
ASSETS	(Unaudited)				(Unaudited)
Current assets
Cash and cash equivalents	$	532	$	409	$	736	$	529
Restricted deposits	6		—
Accounts, notes and interest receivable, net	956		884
Accounts receivable, net of allowance					1,085		1,114
Inventories	241		110		352		338
Gas in underground storage	56		62
Fair value of derivative contracts	59		72		33		55
Assets held for sale	1,859		—		32		211
Other current assets	59		39		124		130
Total Current assets	3,768		1,576		2,362		2,377

Property, plant and equipment, net	19,326		15,596		22,584		22,330
Investments	3,070		3,346		1,880		1,864
Notes receivable	168		165
Goodwill	4,605		1,436		5,412		5,417
Other intangibles, net	1,115		1,152		1,123		1,142
Fair value of derivative contracts	705		632		552		634
Deferred charges and other assets	836		200		1,239		1,212
Total Assets	$	33,593	$	24,103	$	35,152	$	34,976

LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities
Current portion of debt	$	2,697	$	1,638	$	1,127	$	1,155
Cash book overdrafts	63		21
Accounts payable	849		706		983		1,091
Accrued interest	149		259		184		327
Accrued taxes	140		38
Deferred revenues	97		100
Fair value of derivative contracts	41		121		49		21
Accrued other current liabilities	526		236		851		653
Total Current liabilities	4,562		3,119		3,194		3,247

Long-term liabilities and deferred credits
Long-term debt
Outstanding	15,217		11,183		16,829		15,907
Debt fair value adjustments	1,530		1,055		1,586		1,698
Total Long-term debt	16,747		12,238		18,415		17,605
Deferred income taxes	262		250		254		249
Fair value of derivative contracts	15		39		11		13
Other long-term liabilities and deferred credits	950		853		1,044		1,100
Total Long-term liabilities and deferred credits	17,974		13,380		19,724		18,967

Total Liabilities	22,536		16,499		22,918		22,214
Commitments and contingencies (Notes 4 and 10)
Commitments and contingencies (Notes 3 and 9)
Partners’ Capital
Common units	4,360		4,347		5,137		4,723
Class B units	18		42		13		14
i-units	3,492		2,857		3,676		3,564
General partner	2,856		259		3,008		4,026
Accumulated other comprehensive income	178		3		79		168
Total Kinder Morgan Energy Partners, L.P. Partners’ Capital	10,904		7,508		11,913		12,495
Noncontrolling interests	153		96		321		267
Total Partners’ Capital	11,057		7,604		12,234		12,762
Total Liabilities and Partners’ Capital	$	33,593	$	24,103	$	35,152	$	34,976
The accompanying notes are an integral part of these consolidated financial statements.

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (In Millions) (Unaudited)	KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (In Millions) (Unaudited)						KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (In Millions) (Unaudited)

	Nine Months Ended September 30,						Three Months Ended March 31,
	2012			2011			2013			2012
Cash Flows From Operating Activities
Net Income	$	737		$	789		$	792		$	208
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	803			705			328			246
Amortization of excess cost of equity investments	5			5			2			2
Loss from costs to sell and the remeasurement of FTC Natural Gas Pipelines disposal group to fair value (Note 2)	827			—
Loss on remeasurement of previously held interest in Kinderhawk to fair value (Note 2)	—			167
Noncash compensation expense allocated from parent (Note 9)	—			90
Gain from the sale of investments in Express pipeline system (Note 2)							(225		)	—
Loss from the sale of discontinued operations and the remeasurement of FTC Natural Gas Pipelines disposal group to fair value (Note 2)							2			322
Earnings from equity investments	(289		)	(214		)	(83		)	(87		)
Distributions from equity investments	277			201			82			80
Proceeds from termination of interest rate swap agreements	53			73
Changes in components of working capital:
Accounts receivable	(40		)	28			21			83
Inventories	(98		)	9			(13		)	(77		)
Other current assets	13			(2		)	24			41
Accounts payable	41			(9		)	(161		)	(61		)
Cash book overdrafts	42			9
Accrued interest	(138		)	(143		)	(143		)	(162		)
Accrued taxes	74			47
Accrued liabilities	49			(2		)
Accrued other current liabilities							208			105
Rate reparations, refunds and other litigation reserve adjustments	(42		)	161			15			—
Other, net	—			70			(103		)	(42		)
Net Cash Provided by Operating Activities	2,314			1,984			746			658

Cash Flows From Investing Activities
Payment to KMI for drop-down asset group, net of cash acquired (Note 2)	(3,482		)	—
Payment to KMI for drop-down asset group (Note 2)							(988		)	—
Acquisitions of assets and investments	(72		)	(945		)	(4		)	(30		)
Repayments from related party	42			29
Capital expenditures	(1,273		)	(838		)	(552		)	(353		)
Sale or casualty of property, plant and equipment, and other net assets net of removal costs	36			29
(Investments in) Net proceeds from margin and restricted deposits	(16		)	56
Proceeds from sale of investments in Express pipeline system							403			—
Contributions to equity investments	(155		)	(297		)	(40		)	(49		)
Distributions from equity investments in excess of cumulative earnings	120			165			19			43
Refined products, natural gas liquids and transmix line-fill	14			3
Other, net	—			1			(9		)	16
Net Cash Used in Investing Activities	(4,786		)	(1,797		)	(1,171		)	(373		)

Cash Flows From Financing Activities
Issuance of debt	8,378			6,356			2,699			2,420
Payment of debt	(5,074		)	(5,538		)	(1,809		)	(2,160		)
Debt issue costs	(16		)	(17		)	(7		)	(6		)
Proceeds from issuance of i-units	727			—
Proceeds from issuance of common units	387			813			385			124
Contributions from noncontrolling interests	40			15			65			2
Pre-acquisition contributions and distributions from KMI to drop-down asset group							35			—
Distributions to partners and noncontrolling interests:
Common units	(847		)	(762		)	(326		)	(270		)
Class B units	(19		)	(18		)	(7		)	(6		)
General Partner	(970		)	(859		)	(388		)	(307		)
Noncontrolling interests	(23		)	(20		)	(9		)	(7		)
Other, net	(1		)	—
Net Cash Provided by (Used in) Financing Activities	2,582			(30		)	638			(210		)

Effect of Exchange Rate Changes on Cash and Cash Equivalents	13			(15		)	(6		)	7

Net increase in Cash and Cash Equivalents	123			142			207			82
Cash and Cash Equivalents, beginning of period	409			129			529			409
Cash and Cash Equivalents, end of period	$	532		$	271		$	736		$	491

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


▪	the earnings of the drop-down asset group for the periods beginning on the effective dates of common control and ending March 1, 2013 (and we reported this amount separately as “Pre-acquisition income from operations of drop-


	Pro Forma Nine Months Ended September 30,
	2012			2011			Pro Forma Three Months Ended March 31, 2012
	(Unaudited)						(Unaudited)
Revenues	$	6,549		$	6,640		$	2,116
Income from Continuing Operations	$	1,396		$	844		$	579
Income (Loss) from Discontinued Operations	$	(682	)	$	145
Loss from Discontinued Operations							$	(272	)
Net Income	$	714		$	989		$	307
Net Income Attributable to Noncontrolling Interests	$	(12	)	$	(8	)	$	(2	)
Net Income Attributable to Kinder Morgan Energy Partners, L.P.	$	702		$	981		$	305

Limited Partners’ Net Income (Loss) per Unit:
Income (Loss) from Continuing Operations	$	0.82		$	(0.19	)
Income (Loss) from Discontinued Operations	(1.89		)	0.43
Net Income (Loss)	$	(1.07	)	$	0.24
Income from Continuing Operations							$	0.70
Loss from Discontinued Operations							(0.76		)
Net Loss							$	(0.06	)



	Products Pipelines		Natural Gas Pipelines			CO₂		Terminals		Kinder Morgan Canada			Total
Historical Goodwill	$	263	$	557		$	46	$	326	$	621		$	1,813
Accumulated impairment losses(a)	—		—			—		—		(377		)	(377		)
Balance as of December 31, 2011	263		557			46		326		244			1,436
Acquisitions(b)	—		3,246			—		—		—			3,246
Disposals(c)	—		(85		)	—		—		—			(85		)
Currency translation adjustments	—		—			—		—		8			8
Balance as of September 30, 2012	$	263	$	3,718		$	46	$	326	$	252		$	4,605


~~(b)~~	~~Acquisition amount relates to our August 1, 2012 acquisition of the drop-down asset group from KMI as discussed in Note 2.~~



	September 30, 2012		December 31, 2011
Current portion of debt(a)	$	2,697	$	1,638
Long-term portion of debt	15,217		11,183
Net carrying value of debt(b)	$	17,914	$	12,821



	March 31, 2013		December 31, 2012
Current portion of debt(a)	$	1,127	$	1,155
Long-term portion of debt	16,829		15,907
Carrying value of debt(b)	$	17,956	$	17,062


(a)	As of ~~September 30, 2012~~March 31, 2013 and December 31, ~~2011~~2012, includes commercial paper borrowings of $~~2,664~~595 million and $~~645~~621 million, respectively.



Debt borrowings	Interest rate		Increase / (decrease)			Cash received / (paid)
Issuances and Assumptions
Senior notes due September 1, 2022(a)	3.95	%	$	1,000		$	998
Senior notes due February 15, 2023(b)	3.45	%	625			622
Senior notes due August 15, 2042(b)	5.00	%	625			621
Commercial paper	variable		5,561			5,561
Bridge loan credit facility due February 6, 2013(c)	variable		576			576
Tennessee Gas Pipeline L.L.C. - senior notes due February 1, 2016(d)	8.00	%	250			—
Tennessee Gas Pipeline L.L.C. - senior notes due April 4, 2017(d)	7.50	%	300			—
Tennessee Gas Pipeline L.L.C. - senior notes due March 15, 2027(d)	7.00	%	300			—
Tennessee Gas Pipeline L.L.C. - senior notes due October 15, 2028(d)	7.00	%	400			—
Tennessee Gas Pipeline L.L.C. - senior notes due June 15, 2032(d)	8.375	%	240			—
Tennessee Gas Pipeline L.L.C. - senior notes due April 1, 2037(d)	7.625	%	300			—
Total increases in debt			$	10,177		$	8,378

Repayments and other
Senior notes due March 15, 2012(a)	7.125	%	$	(450	)	$	(450	)
Senior notes due September 15, 2012(e)	5.85	%	(500		)	(500		)
Commercial paper	variable		(3,542		)	(3,542		)
Bridge loan credit facility due February 6, 2013(c)	variable		(576		)	(576		)
Kinder Morgan Texas Pipeline, L.P. - senior notes due January 2, 2014	5.23	%	(5		)	(5		)
Kinder Morgan Arrow Terminals L.P. - note due April 4, 2014	6.0	%	(1		)	(1		)
Kinder Morgan Operating L.P. "A" - BP note due March 31, 2012	5.40	%	(5		)	—
Kinder Morgan Canada Company - BP note due March 31, 2012	5.40	%	(5		)	—
Total decreases in debt			$	(5,084	)	$	(5,074	)


~~(d)~~	~~Our subsidiary, Tennessee Gas Pipeline L.L.C. is the obligor of six separate series of fixed-rate unsecured senior notes having a combined principal amount of~~ ~~$1,790 million~~December 31, 2012. ~~We assumed these debt borrowings as part of the drop-down transaction.~~


~~(e)~~	~~On September 15, 2012, we paid~~ ~~$500 million~~ ~~to retire the principal amount of our~~ ~~5.85%~~ ~~senior notes that matured on that date.~~



	March 31, 2013	December 31, 2012
Common units:
Held by third parties	236,318,422	231,718,422
Held by KMI and affiliates (excluding our general partner)	20,563,455	19,314,003
Held by our general partner	1,724,000	1,724,000
Total Common units	258,605,877	252,756,425
Class B units(a)	5,313,400	5,313,400
i-units(b)	116,922,934	115,118,338
Total limited partner units	380,842,211	373,188,163


(a)	As of both March 31, 2013 and December 31, 2012, all of our Class B units were held by a wholly-owned subsidiary of KMI. The Class B units are similar to our common units except that they are not eligible for trading on the New York Stock Exchange.


	Nine Months Ended September 30,																		Three Months Ended March 31,
	2012									2011									2013									2012
	KMP			Noncontrolling Interests			Total			KMP			Noncontrolling interests			Total			KMP			Noncontrolling Interests			Total			KMP			Noncontrolling interests			Total
Beginning Balance	$	7,508		$	96		$	7,604		$	7,211		$	82		$	7,293		$	12,495		$	267		$	12,762		$	7,508		$	96		$	7,604
Units issued for cash	1,114			—			1,114			813			—			813			385			—			385			124			—			124
Units issued as consideration in the acquisition of assets(a)	686			—			686			24			—			24			108			—			108			7			—			7
Distributions paid in cash	(1,836		)	(23		)	(1,859		)	(1,639		)	(20		)	(1,659		)	(721		)	(9		)	(730		)	(583		)	(7		)	(590		)
Adjustments to capital due to acquisitions from KMI(a)	2,483			25			2,508			—			—			—			(1,051		)	(10		)	(1,061		)	—			—			—
Contribution from KMI for FTC Natural Gas Pipelines disposal group selling expenses(b)	45			—			45			—			—			—
Noncash compensation expense allocated from KMI(c)	—			—			—			89			1			90
Noncash compensation expense allocated from KMI(b)																			1			—			1			—			—			—
Cash contributions	—			40			40			—			15			15			—			65			65			—			2			2
Other adjustments	4			1			5			(3		)	—			(3		)	2			—			2			—			2			2
Comprehensive income	900			14			914			1,142			10			1,152			694			8			702			161			1			162
Ending Balance	$	10,904		$	153		$	11,057		$	7,637		$	88		$	7,725		$	11,913		$	321		$	12,234		$	7,217		$	94		$	7,311


(b)	~~For further information about~~We do not have any obligation, nor did we pay any amounts related to this ~~contribution, see Note 9.~~


~~(c)~~	expense. For further information about this expense, see Note ~~9. We do not have any obligation, nor do we expect to pay any amounts related to this expense.~~1 “General—Basis of Presentation—March 2013 KMI Asset Drop-Down.”


(a)	Distributions for the fourth quarter of each year are declared and paid during the first quarter of the following year.


(b)	Consisting of our common and Class B unitholders, our general partner and noncontrolling interests.


(e)	Incentive distribution does not include the general partner’s initial 2% distribution of available cash.



	Net open position long/(short)
Derivatives designated as hedging contracts
Crude oil fixed price	~~(20.5)~~ (21.4)	million barrels
Natural gas fixed price	~~(27.6)~~ (33.9)	billion cubic feet
Natural gas basis	~~(27.6)~~ (34.4)	billion cubic feet
Derivatives not designated as hedging contracts
Crude oil fixed price	(0.1)	million barrels
Crude oil basis	(3.6)	million barrels
Natural gas fixed price	~~(0.6)~~ (2.0)	billion cubic feet
Natural gas basis	12.2	billion cubic feet

Fair Value of Derivative Contracts
		Asset derivatives				Liability derivatives							Asset derivatives				Liability derivatives
		September 30, 2012		December 31, 2011		September 30, 2012			December 31, 2011				March 31, 2013		December 31, 2012		March 31, 2013			December 31, 2012
	Balance sheet location	Fair value		Fair value		Fair value			Fair value			Balance sheet location	Fair value		Fair value		Fair value			Fair value
Derivatives designated as hedging contracts
Energy commodity derivative contracts	Current-Fair value of derivative contracts	$	58	$	66	$	(39	)	$	(116	)	Current-Fair value of derivative contracts	$	19	$	42	$	(45	)	$	(18	)
	Current-Assets held for Sale / Accrued other current liabilities	1		—		—			—
	Non-current-Fair value of derivative contracts	52		39		(15		)	(39		)	Non-current-Fair value of derivative contracts	37		40		(8		)	(11		)
Subtotal		111		105		(54		)	(155		)		56		82		(53		)	(29		)
Interest rate swap agreements	Current-Fair value of derivative contracts	—		3		—			—			Current-Fair value of derivative contracts	7		9		—			—
	Non-current-Fair value of derivative contracts	652		593		—			—			Non-current-Fair value of derivative contracts	515		594		(3		)	(1		)
Subtotal		652		596		—			—				522		603		(3		)	(1		)
Total		763		701		(54		)	(155		)		578		685		(56		)	(30		)

Derivatives not designated as hedging contracts
Energy commodity derivative contracts	Current-Fair value of derivative contracts	1		3		(2		)	(5		)	Current-Fair value of derivative contracts	7		4		(4		)	(3		)
	Non-current-Fair value of derivative contracts	1		—		—			—			Non-current-Fair value of derivative contracts	—		—		—			(1		)
Total		2		3		(2		)	(5		)		7		4		(4		)	(4		)
Total derivatives		$	765	$	704	$	(56	)	$	(160	)
Total derivatives(a)													$	585	$	689	$	(60	)	$	(34	)


Derivatives in fair value hedging relationships	Location of gain/(loss) recognized in income on derivatives	Amount of gain/(loss) recognized in income on derivatives and related hedged item(a)												Location of gain/(loss) recognized in income on derivatives	Amount of gain/(loss) recognized in income on derivatives and related hedged item(a)
		Three Months Ended September 30,						Nine Months Ended September 30,							Three Months Ended March 31,
		2012			2011			2012			2011				2013			2012
Interest rate swap agreements	Interest expense	$	28		$	437		$	109		$	501		Interest expense	$	(83	)	$	(113	)
Total		$	28		$	437		$	109		$	501			$	(83	)	$	(113	)

Fixed rate debt	Interest expense	$	(28	)	$	(437	)	$	(109	)	$	(501	)	Interest expense	$	83		$	113
Total		$	(28	)	$	(437	)	$	(109	)	$	(501	)		$	83		$	113


(a)	Amounts reflect the change in the fair value of interest rate swap agreements and the change in the fair value of the associated fixed rate debt, which exactly offset each other as a result of no hedge ineffectiveness.


Derivatives in cash flow hedging relationships	Amount of gain/(loss) recognized in OCI on derivative (effective portion)(a)					Location of gain/(loss) reclassified from Accumulated OCI into income (effective portion)	Amount of gain/(loss) reclassified from Accumulated OCI into income (effective portion)(b)						Location of gain/(loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)	Amount of gain/(loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)					Amount of gain/(loss) recognized in OCI on derivative (effective portion)(a)						Location of gain/(loss) reclassified from Accumulated OCI into income (effective portion)	Amount of gain/(loss) reclassified from Accumulated OCI into income (effective portion)(b)					Location of gain/(loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)	Amount of gain/(loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)
	Three Months Ended September 30,						Three Months Ended September 30,							Three Months Ended September 30,					Three Months Ended March 31,							Three Months Ended March 31,						Three Months Ended March 31,
	2012			2011			2012			2011				2012			2011		2013			2012				2013		2012				2013			2012
Energy commodity derivative contracts	$	(90	)	$	387	Revenues-Natural gas sales	$	2		$	—		Revenues-Natural gas sales	$	—		$	—	$	(41	)	$	(114	)	Revenues-Natural gas sales	$	—	$	—		Revenues-Natural gas sales	$	—		$	—
						Revenues-Product sales and other	—			(51		)	Revenues-Product sales and other	(5		)	8								Revenues-Product sales and other	7		(29		)	Revenues-Product sales and other	(3		)	(3		)
						Gas purchases and other costs of sales	8			2			Gas purchases and other costs of sales	—			—								Gas purchases and other costs of sales	—		(2		)	Gas purchases and other costs of sales	—			—
Total	$	(90	)	$	387	Total	$	10		$	(49	)	Total	$	(5	)	$	8	$	(41	)	$	(114	)	Total	$	7	$	(31	)	Total	$	(3	)	$	(3	)

	Nine Months Ended September 30,						Nine Months Ended September 30,							Nine Months Ended September 30,
	2012			2011			2012			2011				2012			2011
Energy commodity derivative contracts	$	99		$	289	Revenues-Natural gas sales	$	4		$	1		Revenues-Natural gas sales	$	—		$	—
						Revenues-Product sales and other	(31		)	(203		)	Revenues-Product sales and other	(8		)	10
						Gas purchases and other costs of sales	17			13			Gas purchases and other costs of sales	—			—
Total	$	99		$	289	Total	$	(10	)	$	(189	)	Total	$	(8	)	$	10



Derivatives not designated as hedging contracts	Location of gain/(loss) recognized in income on derivative	Amount of gain/(loss) recognized in income on derivatives
		Three Months Ended March 31,
		2013		2012
Natural gas derivative contracts	Revenues-Natural gas sales	$	—	$	—
Crude oil derivative contracts	Revenues-Product sales and other	4		—
Total		$	4	$	—


	Asset position			Asset position
Interest rate swap agreements	$	652		$	522
Energy commodity derivative contracts	113			63
Gross exposure	765			585
Netting agreement impact	(39		)	(18		)
Cash collateral held	—			—
Net exposure	$	726		$	567



	Net unrealized gains/(losses) on cash flow hedge derivatives			Foreign currency translation adjustments			Pension and other postretirement liability adjs.			Total Accumulated other comprehensive income/(loss)
Balance as of December 31, 2012	$	66		$	132		$	(30	)	$	168
Other comprehensive income before reclassifications	(40		)	(43		)	1			(82		)
Amounts reclassified from accumulated other comprehensive income	(7		)	—			—			(7		)
Net current-period other comprehensive income	(47		)	(43		)	1			(89		)
Balance as of March 31, 2013	$	19		$	89		$	(29	)	$	79


▪	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).


	Asset fair value measurements using								Asset fair value measurements using
	Total		Quoted prices in active markets for identical assets (Level 1)		Significant other observable inputs (Level 2)		Significant unobservable inputs (Level 3)		Total		Quoted prices in active markets for identical assets (Level 1)		Significant other observable inputs (Level 2)		Significant unobservable inputs (Level 3)
As of September 30, 2012
As of March 31, 2013
Energy commodity derivative contracts(a)	$	113	$	16	$	88	$	9	$	63	$	2	$	57	$	4
Interest rate swap agreements	$	652	$	—	$	652	$	—	$	522	$	—	$	522	$	—

As of December 31, 2011
As of December 31, 2012
Energy commodity derivative contracts(a)	$	108	$	34	$	47	$	27	$	86	$	3	$	76	$	7
Interest rate swap agreements	$	596	$	—	$	596	$	—	$	603	$	—	$	603	$	—


	Liability fair value measurements using												Liability fair value measurements using
	Total			Quoted prices in active markets for identical assets (Level 1)			Significant other observable inputs (Level 2)			Significant unobservable inputs (Level 3)			Total			Quoted prices in active markets for identical liabilities (Level 1)			Significant other observable inputs (Level 2)			Significant unobservable inputs (Level 3)
As of September 30, 2012
As of March 31, 2013
Energy commodity derivative contracts(a)	$	(56	)	$	(14	)	$	(39	)	$	(3	)	$	(57	)	$	(17	)	$	(39	)	$	(1	)
Interest rate swap agreements	$	—		$	—		$	—		$	—		$	(3	)	$	—		$	(3	)	$	—

As of December 31, 2011
As of December 31, 2012
Energy commodity derivative contracts(a)	$	(160	)	$	(15	)	$	(125	)	$	(20	)	$	(33	)	$	(3	)	$	(26	)	$	(4	)
Interest rate swap agreements	$	—		$	—		$	—		$	—		$	(1	)	$	—		$	(1	)	$	—