~~Generally, KMR makes all decisions relating to the management and control~~

Table of our business, and in general, KMR has a duty to manage us in a manner beneficial to our unitholders. Our general partner owns all of KMR’s voting securities and elects all of KMR’s directors. KMI indirectly owns all the common stock of our general partner, and the officers of KMI have fiduciary duties to manage KMI, including selection and management of its investments in its subsidiaries and affiliates, in a manner beneficial to the owners of KMI. Accordingly, certain conflicts of interest could arise as a result of the relationships among KMR, our general partner, KMI and us.Contents

The partnership agreements for us and our operating partnerships contain provisions that allow KMR to take into account the interests of parties in addition to us in resolving conflicts of interest, thereby limiting its duty to our unitholders, as well as provisions that may restrict the remedies available to our unitholders for actions taken that might, without such limitations, constitute breaches of duty. The partnership agreements also provide that in the absence of bad faith by KMR, the resolution of a conflict by KMR will not be a breach of any duties. The duty of the officers of KMI may, therefore, come into conflict with the duties of KMR and its directors and officers to our unitholders. The audit committee of KMR’s board of directors will, at the request of KMR, review (and is one of the means for resolving) conflicts of interest that may arise between KMI or its subsidiaries, on the one hand, and us, on the other hand.

For a more complete discussion of our related party transactions, including (i) the accounting for our general and administrative expenses; (ii) KMI’s operation and maintenance of the assets comprising our Natural Gas Pipelines business segment; and (iii) our partnership interests and distributions, see Note 11 “~~Related Party Transactions” to our consolidated financial statements included in our 2012 Form 10-K.~~

9. Litigation, Environmental and Other Contingencies

We are party to various legal, regulatory and other matters arising from the day-to-day operations of our businesses that may result in claims against the Partnership. Although no assurance can be given, we believe, based on our experiences to date 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 distributions to limited partners. We believe we have meritorious defenses to the matters to which we are a party and intend to vigorously defend the Partnership. When we determine a loss is probable of occurring and is reasonably estimable, we accrue an undiscounted liability for such contingencies based on our best estimate using information available at that time. If the estimated loss is a range of potential outcomes and there is no better estimate within the range, we accrue the amount at the low end of the range. We disclose contingencies where an adverse outcome may be material, or in the judgment of management, we conclude the matter should otherwise be disclosed.

Federal Energy Regulatory Commission Proceedings

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The tariffs and rates charged by SFPP ~~L.P. (SFPP)~~ and ~~El Paso Natural Gas Company, LLC (EPNG)~~EPNG are subject to a number of ongoing proceedings at the FERC. A substantial portion of our legal reserves relate to these FERC cases and the CPUC cases described below them.

SFPP

The tariffs and rates charged by SFPP are subject to a number of ongoing proceedings at the FERC, including the complaints and protests of various shippers. In general, these complaints and protests allege the rates and tariffs charged by SFPP are not just and reasonable under the Interstate Commerce Act (ICA). If the shippers are successful in proving their claims, they are entitled to seek reparations (which may reach back up to two years prior to the filing of their complaints) or refunds of any excess rates paid, and SFPP may be required to reduce its rates going forward. These proceedings tend to be protracted, with decisions of the FERC often appealed to the federal courts. The issues involved in these proceedings include, among others, whether indexed rate increases are justified, and the appropriate level of return and income tax allowance we may include in our rates. With respect to all of the SFPP proceedings at the FERC, we estimate that the shippers are seeking approximately ~~$20~~$20 million in annual rate reductions and approximately ~~$100~~$100 million in refunds. However, applying the principles of several recent FERC decisions in SFPP cases, as applicable, to ~~other~~ pending cases would result in substantially lower rate reductions and refunds than those sought by the shippers. We do not expect refunds in these cases to have an impact on our distributions to our limited partners.

EPNG

The tariffs and rates charged by EPNG are subject to two ongoing FERC proceedings (the “2008 rate case” and the “2010 rate case”). With respect to the 2008 rate case, the FERC issued its decision ~~(“Opinion 517”)~~(Opinion 517) in May ~~2012 and~~2012. EPNG implemented certain aspects of that ~~decision.~~ ~~The FERC subsequently issued~~decision and believes it has an ~~order requiring EPNG to decrease its rates~~appropriate reserve related to the ~~2010 rate case~~findings in ~~accordance with~~ Opinion 517. EPNG has sought rehearing on ~~that order as well as~~ Opinion 517. With respect to the 2010 rate case, the ~~presiding administrative law judge~~FERC issued ~~an initial~~its decision (Opinion 528) on October 17, 2013. The FERC ordered EPNG to file within 60 days of issuance of Opinion 528 revised pro forma recalculated rates consistent with the terms of Opinion 528. The FERC has ordered additional proceedings concerning one of the issues in ~~June 2012. This initial decision~~Opinion 528. EPNG has filed for rehearing on certain issues in Opinion 528. We have evaluated all recent decisions and believe our reserve is ~~currently being reviewed by the FERC. EPNG is pursuing settlement with its shippers in both open rate cases and believes the accruals established for these matters are adequate.~~appropriate.

California Public Utilities Commission Proceedings

We have previously reported ratemaking and complaint proceedings against SFPP pending with the CPUC. The ratemaking and complaint cases generally involve challenges to rates charged by SFPP for intrastate transportation of refined petroleum products through its pipeline system in the state of California and request prospective rate adjustments and refunds with respect to tariffed and previously untariffed charges for certain pipeline transportation and related services. These matters have generally been consolidated and assigned to two administrative law judges.

On May 26, 2011, the CPUC issued a decision in several intrastate rate cases involving SFPP and a number of its shippers (the “Long” cases). The decision includes determinations on issues, such as SFPP’s entitlement to an income tax allowance, allocation of environmental expenses, and refund liability which we believe are contrary both to CPUC policy and precedent and to established federal regulatory policies for pipelines. On March 8, 2012, the CPUC issued another

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decision related to the Long cases. This decision largely reflected the determinations made on May 26, 2011, including the denial of an income tax allowance for SFPP. The CPUC’s order denied SFPP’s request for rehearing of the CPUC’s income tax allowance treatment, while granting requested rehearing of various, other issues relating to SFPP’s refund liability and staying the payment of refunds until resolution of the outstanding issues on rehearing. On March 23, 2012, SFPP filed a petition for writ of review in the California Court of Appeals, seeking a court order vacating the CPUC’s determination that SFPP is not entitled to recover an income tax allowance in its intrastate rates. The Court ~~has granted review with respect to~~denied SFPP’s petition, and ~~oral arguments were held~~ on ~~April 25, 2013.~~October 16, 2013, the California Supreme Court declined SFPP’s request for further review. SFPP is currently assessing the precise impact of the now final state rulings denying SFPP an income tax allowance and is awaiting CPUC decisions that will determine the impact related to the denial of an income tax allowance.

On April 6, 2011, in proceedings unrelated to the above-referenced CPUC dockets, a CPUC administrative law judge issued a proposed decision (Bemesderfer case) substantially reducing SFPP’s authorized cost of service and ordering SFPP to pay refunds from May 24, 2007 to the present of revenues collected in excess of the authorized cost of service. The proposed decision was subsequently withdrawn, and the presiding administrative law judge is expected to reissue a proposed decision at some indeterminate time in the future.

On January 30, 2012, SFPP filed an application reducing its intrastate rates by approximately 7%. This matter remains

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pending before the ~~CPUC. The matter is scheduled for hearing in April, 2013,~~CPUC, with a decision expected in the ~~third or~~ fourth quarter of 2014.

On July 19, 2013, Calnev filed an application with the CPUC requesting a 36% increase in its intrastate rates. A decision from the CPUC approving the requested rate increase was issued on November 14, 2013.

On November 27, 2013, the CPUC issued its Order to Show Cause directing SFPP to demonstrate whether or not the CPUC should require immediate refund payments associated with various pending SFPP rate matters. Subsequently, the CPUC issued an order directing SFPP and its shippers to engage in mandatory settlement discussions. On April 3, 2014, the CPUC issued its ruling suspending proceedings in all pending SFPP matters until October 1, 2014 or the date upon which SFPP and its shippers inform the CPUC that SFPP and its shippers have reached settlement of all pending matters or have failed to do so. If the matter is not settled, a decision addressing, if not resolving, all pending SFPP rate matters at the CPUC is anticipated in the first quarter of 2015.

Based on our review of these CPUC proceedings and the shipper comments thereon, we estimate that the shippers are requesting approximately ~~$375~~$400 million in reparation payments and approximately ~~$30~~$30 million in annual rate reductions. The actual amount of reparations will be determined through settlement negotiations or further proceedings at the ~~CPUC and, potentially, the California Court~~CPUC. As of ~~Appeals. We~~March 31, 2014, we believe our legal reserve is adequate such that the ~~appropriate application~~resolution of ~~the income tax allowance and corrections~~pending CPUC matters will not have a material adverse impact on our business, financial position or results of ~~errors in law and fact should result in a considerably lower amount. We~~operations. Furthermore, we do not expect any reparations that we would pay in ~~these matters~~this matter to ~~have a material~~ impact ~~on our~~the per unit cash distributions we expect to pay to our limited ~~partners.~~

~~Copano Shareholders’ Litigation~~

~~Three~~ putative class action lawsuits are currently pending in connection with our proposed merger with Copano: (i) Schultes v. Copano Energy, L.L.C., et al. (Case No. 06966), in the District Court of Harris County, Texas, which is referred to as the Texas State Action; (ii) Bruen v. Copano Energy, L.L.C., et al. (Case No. 4:13-CV-00540) in the United States District Courtpartners for the Southern District of Texas, which is referred to as the Texas Federal Action; and (iii) In re Copano Energy, L.L.C. Shareholder Litigation, Case No. 8284-VCN in the Court of Chancery of the State of Delaware, which is referred to as the Delaware Action, which reflects the consolidation of three actions originally filed in the Court of Chancery. The Texas State Action, the Texas Federal Action and the Delaware Action are collectively referred to as the “Actions.”

The Actions name Copano, R. Bruce Northcutt, William L. Thacker, James G. Crump, Ernie L. Danner, T. William Porter, Scott A. Griffiths, Michael L. Johnson, Michael G. MacDougall, Kinder Morgan GP, Kinder Morgan Energy Partners and Merger Sub as defendants. The Actions are purportedly brought on behalf of a putative class seeking to enjoin the merger and allege, among other things, that the members of Copano’s board of directors breached their fiduciary duties by agreeing to sell Copano for inadequate and unfair consideration and pursuant to an inadequate and unfair process, and that Copano, Kinder Morgan Energy Partners, Kinder Morgan GP and Merger Sub aided and abetted such alleged breaches. In addition, the plaintiffs in each of the Texas State Action and the Delaware Action allege that

the Copano directors breached their duty of candor to unitholders by failing to provide the unitholders with all material information regarding the merger and/or made misstatements in the preliminary proxy statement. The plaintiffs in the Texas Federal Action also assert a claim under the federal securities laws alleging that the preliminary proxy statement omits and/or misrepresents material information in connection with the merger.

On April 21, 2013, the parties in all the Actions executed a Memorandum of Understanding by which, in exchange for the full settlement and dismissal with prejudice of each of the Actions, Copano agreed to make certain additional disclosures concerning the merger in a Form 8-K filed by Copano on April 22, 2013. The parties are in the process of preparing and filing a Stipulation of Settlement and such other additional documents as may be required to in the Delaware Chancery Court for approval of the settlement.2014.

Other Commercial Matters

Union Pacific Railroad Company Easements

SFPP and ~~UPRR~~Union Pacific Railroad Company (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~~$14 million,, subject to annual consumer price index increases. Judgment was entered by the Court on May 29, 2012 and SFPP ~~intends to appeal~~appealed the ~~judge’s determination, but if that determination~~judgment. If the judgment is upheld on appeal, SFPP would owe approximately ~~$75~~$93 million in back rent. Accordingly, ~~during 2011,~~ we have increased our rights-of-way liability to cover this potential liability ~~amount.~~for back rent. In addition, the judge determined that UPRR is entitled to ~~an estimated~~ ~~$20~~approximately $20 million for interest through the date of the judgment on the outstanding back rent liability. We believe the award of interest is without merit and we are pursuing our appellate rights. By notice dated October 25, 2013, UPRR demanded the payment of $22.25 million in rent for the first year of the next ten-year period beginning January 1, 2014. SFPP rejected the demand and the parties are pursuing the dispute resolution procedure in their contract to determine the rental adjustment, if any, for such period.

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SFPP and UPRR are also engaged in multiple disputes over the circumstances under which SFPP must pay for a relocation of its pipeline within the UPRR right-of-way and the safety standards that govern relocations. In July 2006, a

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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~~American Railway Engineering and Maintenance-of-Way Association (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. On March 10, 2014, the trial court issued a tentative statement of decision addressing all of the causes of action and defenses and resolved those matters against SFPP, consistent with the jury’s verdict. If the tentative statement of decision and jury verdict become final and are affirmed on appeal, SFPP will be required to pay a judgment of at least $22.6 million.UPRR has also requested the trial court award prejudgment interest and costs to UPRR. SFPP is ~~evaluating~~continuing to evaluate 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.~~our subsidiary Kinder Morgan Bulk Terminals, Inc. (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~~U.S. 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~~$30 million for the alleged value of the crane and lost profits. KMBT denies each of RG Steel’s allegations. A bench trial occurred in November 2013. On ~~or about June 1, 2012, RG Steel filed for bankruptcy in Case No. 12-11669~~March 6, 2014, the Court issued findings of fact and conclusions of law and entered judgment against KMBT in the ~~United States Bankruptcy~~amount of $13.79 million. KMBT has filed a notice of appeal of the judgment.

Plains Gas Solutions, LLC v. Tennessee Gas Pipeline Company, L.L.C. et al

On October 16, 2013, Plains Gas Solutions, LLC (Plains) filed a petition in the 151^st Judicial District Court for Harris County, Texas (Case No. 62528) against TGP, Kinetica Partners, LLC and two other Kinetica entities. The suit arises from the ~~District~~sale by TGP of ~~Delaware; consequently,~~ the ~~trial date~~Cameron System in Louisiana to Kinetica Partners, LLC on September 1, 2013. Plains alleges that defendants breached a straddle agreement requiring that gas on the Cameron System be committed to Plains’ Grand Chenier gas-processing facility, that requisite daily volume reports were not provided, that TGP improperly assigned its obligations under the straddle agreement to Kinetica, and that defendants interfered with Plains’ contracts with producers. The petition alleges damages of at least $100 million. Under the Amended and Restated Purchase and Sale Agreement with Kinetica, Kinetica has ~~been postponed indefinitely.~~agreed to indemnify TGP in connection with the gas commitment and reporting claims. The suit was removed to federal court and Plains has filed a motion to remand. We intend to vigorously defend the suit.

Pipeline Integrity and Releases

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.

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General

As of March 31, ~~2013~~2014 and December 31, ~~2012, we have recorded a~~2013, our total reserve for legal ~~fees, transportation rate cases~~matters was $655 million and ~~other potential litigation liabilities in the amount of~~ ~~$431~~$611 million, ~~and~~ ~~$404 million~~, respectively. The reserve is primarily ~~related~~relates to various claims from regulatory proceedings arising from our products pipeline and natural gas pipeline transportation rates. ~~We regularly assess~~

Other

Slotoroff v. Kinder Morgan, Inc., Kinder Morgan G.P., Inc., et al

On February 5, 2014, a putative class action and derivative complaint was filed in the ~~likelihood~~Court of ~~potential adverse outcomes~~Chancery in ~~pending matters~~the State of Delaware (Case No. 9318) against defendants KMI, KMGP and nominal defendant KMEP. The suit was filed by Jon Slotoroff, a purported unitholder of KMEP, and seeks to assert claims both individually and on behalf of a putative class consisting of all public holders of KMEP units during the period of February 5, 2011 through the date of the filing of the suit. The suit alleges direct and derivative causes of action for breach of the partnership agreement, breach of the duty of good faith and fair dealing, aiding and abetting, and tortious interference. Among other things, the suit alleges that defendants made a bad faith allocation of capital expenditures to expansion capital expenditures rather than maintenance capital expenditures for the alleged purpose of “artificially” inflating KMEP’s distributions and growth rate. The suit seeks disgorgement of any distributions to KMGP, KMI and any related entities, beyond amounts that would have been distributed in accordance with a “good faith” allocation of maintenance capital expenses, together with other unspecified monetary damages including punitive damages and attorney fees. On March 3, 2014, nominal defendant KMEP and defendants KMI and KMGP moved to dismiss this suit. Defendants believe that this suit is without merit and intend to defend it vigorously.

Burns et al v. Kinder Morgan, Inc. Kinder Morgan G.P., Inc. et al

On March 27, 2014, a putative class action and derivative complaint was filed in the Court of Chancery in the State of Delaware (Case No. 9479) against defendants KMI, KMGP and nominal defendant KMEP. The suit was filed by Darrell Burns and Terrence Zehrer, purported unitholders of KMEP, and seeks to assert claims both individually and on behalf of a putative class consisting of all public holders of KMEP units during the period of February 5, 2011 through the date of the filing of the suit. The suit asserts claims and allegations substantially similar to the suit filed by Jon Slotoroff described above. On April 8, 2014, the Court ordered that this suit be consolidated for all purposes with the suit filed by Jon Slotoroff described above and that the caption of the consolidated action shall be In Re Kinder Morgan Energy Partners, L.P. Derivative Litigation, Consolidated Case No. 9318.

Walker v. Kinder Morgan, Inc., Kinder Morgan G.P., Inc. et al

On March 6, 2014, a putative class action and derivative complaint was filed in the District Court of Harris County, Texas (Case No. 2014-11872 in the 215th Judicial District) against KMI, KMGP, KMR, Richard D. Kinder, Steven J. Kean, Ted A. Gardner, Gary L. Hultquist and Perry M. Waughtal. The suit was filed by Kenneth Walker, a purported unit holder of KMP, and alleges direct and derivative causes of action for alleged violation of duties owed under the partnership agreement, breach of the implied covenant of good faith and fair dealing, “abuse of control” and “gross mismanagement” in connection with the calculation of distributions and allocation of capital expenditures to expansion capital expenditures and maintenance capital expenditures. The suit seeks unspecified money damages, interest, punitive damages, attorney and expert fees, costs and expenses, unspecified equitable relief, and demands a trial by jury. Defendants believe that this suit is without merit and intend to defend it vigorously. On April 9, 2014, the Court entered an order staying the case until the defendants’ motion to ~~determine~~dismiss is decided in the ~~adequacy of our reserves.~~suit filed by Jon Slotoroff described above.

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

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inherent in pipeline, terminal and ~~carbon dioxide~~CO₂ 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,~~NGL, 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~~New Jersey Department of Environmental Protection (NJDEP) sued Occidental Chemical Corporation (Occidental) and others under the New Jersey Spill Act for contamination in the Newark Bay Complex including numerous waterways and rivers. In 2009, Occidental et al. ~~then brought in~~asserted claims for contribution against approximately 300 third party ~~defendants for contribution.~~defendants. NJDEP claimed damages related to ~~forty~~40 years of discharges of TCDD (a form of dioxin), DDT and “other hazardous substances.” GATX Terminals Corporation (n/k/~~a/ KMLT)~~a Kinder Morgan Liquids Terminals LLC) (KMLT) was ~~brought in~~named as a third party defendant because of the noted hazardous substances language and because the Carteret, New Jersey facility (a former GATX Terminals Corporation 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. Recently,~~ KMLT, as part of a joint defense group, entered a settlement agreement ~~(Consent~~(the Consent Judgment) with the NJDEP whereby the settling parties for a prescribed payment ~~get~~obtained a contribution bar against first party defendants Occidental, Maxus Energy Corp. (Maxus) and Tierra Solutions, Inc. (Tierra) in addition to a ~~release. This third-party~~release of claims. The Consent Judgment ~~will be~~was published in the New Jersey Register ~~followed by~~for a 60-day comment period ~~after which it will be lodged with the court.~~and no significant comments were received. Additionally, ~~we have information that~~ the NJDEP ~~has~~ reached ~~an agreement in principle on terms for~~ a settlement agreement with Maxus and Tierra. Occidental is not part of the settlement. ~~As part of this~~On December 12, 2013, the Court approved the settlements. Pursuant to the Consent Judgment, KMLT submitted its settlement ~~these defendants agree to dismiss all direct claims against third-party defendants~~payment by the January 27, 2014 deadline and ~~to not oppose~~received the ~~third-party settlement. We expect~~Court’s order dismissing KMLT from the ~~first-party settlement to be finalized over the next 60 days. All discovery and trial proceedings are stayed during these settlement negotiations.~~litigation.

Portland Harbor Superfund Site, Willamette River, Portland, Oregon

In December 2000, the ~~U.S. Environmental Protection Agency (U.S. EPA) sent out~~EPA issued 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. A group of potentially responsible parties formed what is known as the Lower Willamette Group (LWG), of which KMLT is a ~~non-~~

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~~voting~~non-voting member and pays a minimal fee to be part of the group. The LWG agreed to conduct the ~~Remedial Investigation~~remedial investigation and ~~Feasibility Study~~feasibility study (RI/FS) 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 process to conclude in ~~2013 or 2014, depending upon when~~2015. We also expect the ~~U.S.~~LWG to complete the RI/FS process in 2015, after which the EPA ~~issues its~~is expected to develop a proposed plan leading to a Record of Decision targeted for 2017. It is anticipated that the cleanup activities will begin within one year of the issuance of the Record of Decision.

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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 issued KMGP, KMEP and others under CERCLA for contamination of the water purveyor’s wells. The First Amended Complaint sought $175 million in damages against approximately 70 defendants. On August 6, 2013, plaintiffs filed its Second Amended Complaint seeking upmonetary damages in unspecified amounts and reducing the number of defendants to ~~$175 million~~26 including KMEP and SFPP. The claims now presented against KMEP and SFPP are related to alleged releases from ~~approximately~~ 70 ~~defendants. The plume of contaminants has traveled under Kinder Morgan’s Phoenix Terminal. The plaintiffs have advanced~~ a ~~novel theory that~~specific parcel within the ~~releases of petroleum from the~~SFPP Phoenix Terminal ~~(which are exempt under~~and the ~~petroleum exclusion under CERCLA) have facilitated~~alleged impact of such releases on water wells owned by the ~~natural degradation~~plaintiffs and located in the vicinity 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,~~Terminal. On October 24, 2013, we ~~filed a motion~~moved 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.this suit.

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 iswas 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 remained stayed following the 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. We anticipate that cleanup activities by the Port at the site will begin in the summer of 2013. On April 9, 2013, KMLT and the Port of Los Angeles entered into a ~~Settlement and Release Agreement~~settlement agreement, the terms of which provide for the dismissal of the litigation by the Port ~~upon the payment by KMLT of~~ and KMLT’s agreement to pay 60% of the Port’s costs to remediate the former terminal ~~site; the amount of payment not~~site up to ~~exceed~~ ~~$15~~a $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.~~ cap. Further, according to terms of the ~~Settlement and Release,~~settlement agreement, we received a ~~5-year~~five-year lease extension that allows KMLT to continue fuel loading and offloading operations at another KMLT Port of Los Angeles terminal property. The Court approved the parties’ Good Faith Settlement motion and dismissed the case.

~~Exxon Mobil Corporation v. GATX Corporation, Kinder Morgan Liquids Terminals, LLC~~

The City of Los Angeles, KMLT, Chevron and ~~ST Services, Inc.~~

~~On April 23, 2003, ExxonMobil filed~~Phillips 66 remain named on a ~~complaint~~Cleanup and Abatement Order from the California Regional Water Quality Control Board as parties responsible for the cleanup of the former Los Angeles Marine Terminal. The private parties have all settled with the City of Los Angeles and agreed to pay a percentage of the City’s costs to perform the required cleanup at the site. Cleanup activities by the Port began in the ~~Superior Court~~first quarter of ~~New Jersey, Gloucester County. The lawsuit relates to environmental remediation obligations at a~~ 2014.

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.Liquids Terminal Consent Judgment

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 in Gloucester County, New Jersey against ExxonMobil and KMLT, formerly known as GATX Terminals Corporation, alleging natural resource damages related to historic contamination at the Paulsboro, ~~terminal.~~New Jersey liquids terminal owned by ExxonMobil from the mid-1950s through November 1989, by GATX Terminals Corporation from 1989 through September 2000, and later owned by Support Terminals and Pacific Atlantic Terminals, LLC. The ~~complaint~~terminal is now owned by Plains Products, which was ~~filed in Gloucester County, New Jersey. Both ExxonMobil and KMLT filed third~~also joined as a party ~~complaints against Support Terminals/Plains and successfully brought Support Terminals/Plains into~~to the ~~case. The court consolidated the two cases.~~lawsuit.

In ~~mid 2011,~~mid-2011, KMLT and Plains Products entered into a settlement agreement and subsequent Consent Judgment with the NJDEP ~~for settlement of~~which resolved the state’s alleged natural resource damages claim. ~~The parties then entered into a Consent Judgment concerning the claim.~~

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The natural resource damage settlement includes a monetary award of $1$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~~an agreement that settled each 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. According to the agreement, Plains will conduct remediation activities at the site and KMLT will provide oversight and 50% of the costs. We are awaiting approval from the NJDEP in order to begin remediation activities.

The settlement with the state 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. All parties have now executed the agreement and the litigation is settled and 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~~U.S. District Court, Southern District of California, case number 07CV1883WCAB. The City disclosed in discovery that it is seeking approximately ~~$170~~$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,

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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~~.$365 million.

~~In accordance with the Case Management Order, the parties filed their respective summary adjudication motions and motions to exclude experts on June 29, 2012.~~

On November 29, 2012, the Court issued a Notice of Tentative Rulings on the parties’ ~~pending~~summary adjudication motions. The Court ~~tentatively granted our motions to exclude certain of the City’s proposed expert witnesses,~~ tentatively granted our partial motions for summary judgment on the City’s claims for water and 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.

On February 20, 2013, the City of San Diego filed a notice of appeal of this case to the U.S. Court of Appeals for the Ninth Circuit. The appeal is currently pending.

This site has been, and currently is, under the regulatory oversight and order of the California Regional Water Quality Control ~~Board.~~Board (RWQCB). SFPP continues to conduct an extensive remediation effort at the City’s stadium property site.

On May 7, 2013, the City of San Diego filed a writ of mandamus to the California Superior Court seeking an order from the Court setting aside the RWQCB’s approval of our permit request to increase the discharge of water from our groundwater treatment system to the City of San Diego’s municipal storm sewer system. KMEP is coordinating with the RWQCB to oppose the City’s writ.

Uranium Mines in Vicinity of Cameron, Arizona

In the 1950s and 1960s, Rare Metals Inc., an historical subsidiary of EPNG, operated approximately ~~twenty~~20 uranium mines in the vicinity of Cameron, Arizona, many of which are located on the Navajo Indian Reservation. The mining activities were in response to numerous incentives provided to industry by the ~~United States~~U.S. to locate and produce domestic sources of uranium to support the Cold War-era nuclear weapons program. In May 2012, EPNG received a general notice letter from the ~~U.S.~~ EPA notifying EPNG of the ~~EPA's~~EPA’s investigation of certain sites and its determination that the EPA considers EPNG to be a potentially responsible party within the meaning of CERCLA. In ~~February~~August 2013, EPNG and the EPA ~~delivered a proposed~~entered into an Administrative Order on Consent and ~~proposed~~ Scope of Work, ~~regarding~~pursuant to which EPNG will conduct a radiological assessment of the ~~government's proposed next steps to investigate~~surface of 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 from the ~~United States~~applicable federal government agencies toward the cost of environmental activities associated with the mines, given ~~its~~their pervasive control over all aspects of the nuclear weapons program.

PHMSA Inspection of Carteret Terminal, Carteret, New Jersey

On April 4, 2013, the PHMSA, Office of Pipeline Safety issued a Notice of Probable Violation, Proposed Civil Penalty and Proposed Compliance Order (NOPV) arising from an inspection at the KMLT, Carteret, New Jersey location on March 15, 2011, following a release and fire that occurred during maintenance activity on March 14, 2011. On July 17, 2013, KMLT entered into a Consent Agreement and Order with the PHMSA, pursuant to which KMLT paid a penalty of $63,100 and is required to complete ongoing pipeline integrity testing and other corrective measures by May 2015.

Southeast Louisiana Flood Protection Litigation

On July 24, 2013, the Board of Commissioners of the Southeast Louisiana Flood Protection Authority - East (Flood Protection Authority) filed a petition for damages and injunctive relief in state district court for Orleans Parish, Louisiana (Case No. 13-6911) against TGP and approximately 100 energy companies, alleging that defendants’ drilling, dredging, pipeline and industrial operations since the 1930’s have caused direct land loss and increased erosion and submergence resulting in alleged increased storm surge risk, increased flood protection costs and unspecified damages to the plaintiff. The Flood Protection Authority asserts claims for negligence, strict liability, public nuisance, private nuisance, and breach of contract. Among other relief, the petition seeks unspecified monetary damages, attorney fees, interest, and injunctive relief in the form of abatement and restoration of the alleged coastal land loss including but not limited to backfilling and re-vegetation of canals, wetlands and reef creation, land bridge construction, hydrologic restoration, shoreline protection, structural protection, and bank stabilization. On August 13, 2013, the suit was removed to the U.S. District Court for the Eastern District of Louisiana. On September 10, 2013, the Flood Protection Authority filed a motion to remand the case to the state district court for Orleans Parish. On December 18, 2013, a hearing was conducted on the remand motion and it remains under consideration by the court.

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Plaquemines Parish Louisiana Coastal Zone Litigation

On November 8, 2013, the Parish of Plaquemines, Louisiana filed a petition for damages in the state district court for Plaquemines Parish, Louisiana (Docket No. 60-999) against TGP and 17 other energy companies, alleging that defendants’ oil and gas exploration, production and transportation operations in the Bastian Bay, Buras, Empire and Fort Jackson oil and gas fields of Plaquemines Parish caused substantial damage to the coastal waters and nearby lands (Coastal Zone) within the Parish, including the erosion of marshes and the discharge of oil waste and other pollutants which detrimentally affected the quality of state waters and plant and animal life, in violation of the State and Local Coastal Resources Management Act of 1978 (Coastal Zone Management Act). As a result of such alleged violations of the Coastal Zone Management Act, Plaquemines Parish seeks, among other relief, unspecified monetary relief, attorney fees, interest, and payment of costs necessary to restore the allegedly affected Coastal Zone to its original condition, including costs to clear, vegetate and detoxify the Coastal Zone. On December 18, 2013, defendants removed the case to the U.S. District Court for the Eastern District of Louisiana. On January 14, 2014, the plaintiff filed a motion to remand the case to state court and such motion remains pending.

Pennsylvania Department of Environmental Protection Notice of Alleged Violations

The Pennsylvania Department of Environmental Protection (PADEP) has notified TGP of alleged violations of certain conditions to the construction permits issued to TGP for the construction of TGP’s 300 Line Project in 2011. The alleged violations arise from field inspections performed during construction by county conservation districts, as delegates of the PADEP, and generally involve the alleged failure by TGP to implement and maintain best practices to achieve sufficient erosion and sediment controls, stabilization of the right of way, and prevention of potential discharge of sediment into the waters of the commonwealth during construction and before placing the line into service. To resolve such alleged violations, the PADEP initially proposed a collective penalty of approximately $1.5 million. TGP and the PADEP are seeking to reach a mutually agreeable resolution of the alleged notices of violations, including an agreed penalty amount.

General

Although it is not possible to predict the ultimate outcomes, we believe that the resolution of the environmental matters set forth in this note, 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 resolution of such claims will occur, and changing circumstances could cause these matters to have a material~~

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~~adverse impact.~~ As of March 31, ~~2013~~2014 and December 31, ~~2012, we have accrued a~~2013, our total reserve for environmental liabilities ~~in the amount of~~ ~~$163~~was $164 million and ~~$166~~$168 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.

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

~~Regulatory Assets and Liabilities~~

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. We included the amounts of our regulatory assets and liabilities within “Other current assets,” “Deferred charges and other assets,” “Accrued other current liabilities” and “Other long-term liabilities and deferred credits,” respectively, in our accompanying consolidated balance 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~~ “~~Regulatory Matters” to our consolidated financial statements that were included in our 2012 Form 10-K.~~

~~11.~~ Recent Accounting Pronouncements

Accounting Standards Updates

None of the Accounting Standards Updates (ASU) that we adopted and that became effective January 1, ~~2013~~2014 (including ~~(i)~~ ASU No. ~~2011-11, “Balance Sheet (Topic 210): Disclosures about Offsetting~~2013-05, “Parent’s Accounting for the Cumulative Translation Adjustment upon Derecognition of Certain Subsidiaries or Groups of Assets ~~and Liabilities;” (ii) ASU No. 2012-02, “Intangibles-Goodwill and Other (Topic 350): Testing Indefinite-Lived Intangible Assets for Impairment;” (iii) ASU No. 2013-01, “Clarifying~~within a Foreign Entity or of an Investment in a Foreign Entity (a consensus of the ~~Scope of Disclosures about Offsetting Assets and Liabilities;” and (iv) ASU No. 2013-02, “Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income”~~FASB Emerging Issues Task Force)) had a material impact on our consolidated financial statements. More information about ~~the four ASUs listed above~~this ASU can be found in Note 1817 “Recent Accounting Pronouncements” to our consolidated financial statements that were included in our ~~2012~~2013 Form 10-K.

11. Guarantee of Securities of Subsidiaries

KMEP has guaranteed the payment of Copano’s outstanding 7.125% senior notes due April 1, 2021 (referred to in this report as the “Guaranteed Notes”). Copano Energy Finance Corporation (Copano Finance Corp.), a direct subsidiary of Copano, is the co-issuer of the Guaranteed Notes. Excluding fair value adjustments, as of March 31, 2014, Copano had $332 million of Guaranteed Notes outstanding. Copano Finance Corp’s obligations as a co-issuer and primary obligor are the same as and joint and several with the obligations of Copano as issuer, however, it has no subsidiaries and no independent assets or operations. Subject to the limitations set forth in the applicable supplemental indentures, KMEP’s guarantee is full and unconditional and guarantees the Guaranteed Notes through their maturity date.

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A significant amount of KMEP’s income and cash flow is generated by its respective subsidiaries. As a result, the funds necessary to meet its debt service and/or guarantee obligations are provided in large part by distributions or advances it receives from its respective subsidiaries. For purposes of the condensed consolidating financial information, distributions from our wholly owned subsidiaries have been presented as operating cash flows whether or not distributions exceeded cumulative earnings. In addition, we utilize a centralized cash pooling program among our majority-owned and consolidated subsidiaries, including the subsidiary issuers and non-guarantor subsidiaries. The following Condensed Consolidating Statements of Cash Flows present the intercompany loan and distribution activity, as well as cash collection and payments made on behalf of our subsidiaries, as cash activities.

Included among the non-guarantor subsidiaries are KMEP’s five operating limited partnerships and their majority-owned and controlled subsidiaries, along with Copano’s remaining majority-owned and controlled subsidiaries. In the following unaudited condensed consolidating financial information, KMEP is “Parent Guarantor,” and Copano and Copano Finance Corp. are the “Subsidiary Issuers.” The Subsidiary Issuers are 100% owned by KMEP.

Condensed Consolidating Statement of Income for the Three Months ended March 31, 2014 (In Millions) (Unaudited)

	Parent Guarantor			Subsidiary Issuers			Non-guarantor Subsidiaries			Eliminations			Consolidated KMP
Revenues	$	—		$	—		$	3,652		$	—		$	3,652
Operating Costs, Expenses and Other
Costs of sales	—			—			1,638			—			1,638
Depreciation, depletion and amortization	—			—			401			—			401
Other operating expenses	—			7			673			—			680
Total Operating Costs, Expenses and Other	—			7			2,712			—			2,719
Operating (Loss) Income	—			(7		)	940			—			933
Other Income (Expense), Net	749			33			(163		)	(782		)	(163		)
Income from Continuing Operations Before Income Taxes	749			26			777			(782		)	770
Income Tax Expense	(3		)	—			(13		)	—			(16		)
Net Income	746			26			764			(782		)	754
Net Income Attributable to Noncontrolling Interests	—			—			(8		)	—			(8		)
Net Income Attributable to KMEP	$	746		$	26		$	756		$	(782	)	$	746

Condensed Consolidating Statement of Income for the Three Months ended March 31, 2013 (In Millions) (Unaudited)

	Parent Guarantor			Subsidiary Issuers		Non-guarantor Subsidiaries			Eliminations			Consolidated KMP
Revenues	$	—		$	—	$	2,661		$	—		$	2,661
Operating Costs, Expenses and Other
Costs of sales	—			—		957			—			957
Depreciation, depletion and amortization	—			—		328			—			328
Other operating expenses	—			—		592			—			592
Total Operating Costs, Expenses and Other	—			—		1,877			—			1,877
Operating Income	—			—		784			—			784
Other Income, Net	786			—		101			(776		)	111
Income from Continuing Operations Before Income Taxes	786			—		885			(776		)	895
Income Tax Expense	(3		)	—		(98		)	—			(101		)
Income from Continuing Operations	783			—		787			(776		)	794
Loss from Discontinued Operations	—			—		(2		)	—			(2		)
Net Income	783			—		785			(776		)	792
Net Income Attributable to Noncontrolling Interests	—			—		(9		)	—			(9		)
Net Income Attributable to KMEP	$	783		$	—	$	776		$	(776	)	$	783

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Condensed Consolidating Statement of Comprehensive Income for the Three Months ended March 31, 2014 (In Millions) (Unaudited)

	Parent Guarantor			Subsidiary Issuers		Non-guarantor Subsidiaries			Eliminations			Consolidated KMP
Net Income	$	746		$	26	$	764		$	(782	)	$	754
Other Comprehensive Income (Loss):
Change in fair value of derivatives utilized for hedging purposes	(56		)	—		(56		)	56			(56		)
Reclassification of change in fair value of derivatives to net income	18			—		18			(18		)	18
Foreign currency translation adjustments	(78		)	—		(79		)	78			(79		)
Adjustments to pension and other postretirement benefit plan liabilities	(2		)	—		(2		)	2			(2		)
Total Other Comprehensive Loss	(118		)	—		(119		)	118			(119		)
Comprehensive Income	628			26		645			(664		)	635
Comprehensive Income Attributable to Noncontrolling Interests	—			—		(7		)	—			(7		)
Comprehensive Income Attributable to KMEP	$	628		$	26	$	638		$	(664	)	$	628

Condensed Consolidating Statement of Comprehensive Income for the Three Months ended March 31, 2013 (In Millions) (Unaudited)

	Parent Guarantor			Subsidiary Issuers		Non-guarantor Subsidiaries			Eliminations			Consolidated KMP
Net Income	$	783		$	—	$	785		$	(776	)	$	792
Other Comprehensive Income (Loss):
Change in fair value of derivatives utilized for hedging purposes	(40		)	—		(41		)	40			(41		)
Reclassification of change in fair value of derivatives to net income	(7		)	—		(7		)	7			(7		)
Foreign currency translation adjustments	(43		)	—		(43		)	43			(43		)
Adjustments to pension and other postretirement benefit plan liabilities	1			—		1			(1		)	1
Total Other Comprehensive Loss	(89		)	—		(90		)	89			(90		)
Comprehensive Income	694			—		695			(687		)	702
Comprehensive Income Attributable to Noncontrolling Interests	—			—		(8		)	—			(8		)
Comprehensive Income Attributable to KMEP	$	694		$	—	$	687		$	(687	)	$	694

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Condensed Consolidating Balance Sheet as of March 31, 2014 (In Millions) (Unaudited)

	Parent Guarantor		Subsidiary Issuers		Non-guarantor Subsidiaries		Eliminations			Consolidated KMP
ASSETS
Cash and cash equivalents	$	22	$	—	$	325	$	—		$	347
All other current assets	3,224		5		2,168		(3,061		)	2,336
Property, plant and equipment, net	—		191		28,367		—			28,558
Investments	—		—		2,263		—			2,263
Investments in subsidiaries	13,930		4,348		—		(18,278		)	—
Goodwill	—		813		5,793		—			6,606
Notes receivable from affiliates	18,199		—		—		(18,199		)	—
Other non-current assets	251		—		3,597		—			3,848
Total Assets	$	35,626	$	5,357	$	42,513	$	(39,538	)	$	43,958

LIABILITIES AND PARTNERS’ CAPITAL
Liabilities
Current portion of debt	$	1,243	$	—	$	—	$	—		$	1,243
All other current liabilities	173		88		5,756		(3,061		)	2,956
Total long-term debt	16,882		391		3,572		—			20,845
Notes payable to affiliates	—		832		17,367		(18,199		)	—
Deferred income taxes	—		2		275		—			277
Other long-term liabilities and deferred credits	152		—		862		—			1,014
Total Liabilities	18,450		1,313		27,832		(21,260		)	26,335

Partners’ Capital
Total KMEP Partners’ Capital	17,176		4,044		14,234		(18,278		)	17,176
Noncontrolling interests	—		—		447		—			447
Total Partners’ Capital	17,176		4,044		14,681		(18,278		)	17,623
Total Liabilities and Partners’ Capital	$	35,626	$	5,357	$	42,513	$	(39,538	)	$	43,958

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Condensed Consolidating Balance Sheet as of December 31, 2013 (In Millions)

	Parent Guarantor		Subsidiary Issuers		Non-guarantor Subsidiaries		Eliminations			Consolidated KMP
ASSETS
Cash and cash equivalents	$	10	$	1	$	393	$	—		$	404
All other current assets	3,071		13		2,151		(2,971		)	2,264
Property, plant and equipment, net	—		170		27,235		—			27,405
Investments	—		—		2,233		—			2,233
Investments in subsidiaries	13,931		4,430		—		(18,361		)	—
Goodwill	—		813		5,734		—			6,547
Notes receivable from affiliates	17,284		—		—		(17,284		)	—
Other non-current assets	233		—		3,678		—			3,911
Total Assets	$	34,529	$	5,427	$	41,424	$	(38,616	)	$	42,764

LIABILITIES AND PARTNERS’ CAPITAL
Liabilities
Current portion of debt	$	1,504	$	—	$	—	$	—		$	1,504
All other current liabilities	407		107		5,530		(2,971		)	3,073
Total long-term debt	15,644		393		3,587		—			19,624
Notes payable to affiliates	—		907		16,377		(17,284		)	—
Deferred income taxes	—		2		283		—			285
Other long-term liabilities and deferred credits	173		—		884		—			1,057
Total Liabilities	17,728		1,409		26,661		(20,255		)	25,543

Partners’ Capital
Total KMEP Partners’ Capital	16,801		4,018		14,343		(18,361		)	16,801
Noncontrolling interests	—		—		420		—			420
Total Partners’ Capital	16,801		4,018		14,763		(18,361		)	17,221
Total Liabilities and Partners’ Capital	$	34,529	$	5,427	$	41,424	$	(38,616	)	$	42,764

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Condensed Consolidating Statement of Cash Flow for the Three Months ended March 31, 2014 (In Millions) (Unaudited)

	Parent Guarantor			Subsidiary Issuers			Non-guarantor Subsidiaries			Eliminations			Consolidated KMP
Net Cash Provided by (Used in) Operating Activities	$	687		$	(3	)	$	1,444		$	(1,054	)	$	1,074

Cash Flows From Investing Activities
Business acquisitions (Note 2)	—			—			(960		)	—			(960		)
Acquisitions of assets-other	—			—			(25		)	—			(25		)
Loans to related party	(17		)	—			—			—			(17		)
Capital expenditures	—			(27		)	(782		)	—			(809		)
Contributions to investments	—			—			(35		)	—			(35		)
Distributions from equity investments in excess of cumulative earnings	—			—			15			—			15
Funding (to) from affiliates	(545		)	97			740			(292		)	—
Natural gas storage and natural gas and liquids line-fill	—			—			21			—			21
Sale or casualty of property, plant and equipment, investments and other net assets, net of removal costs	—			—			19			—			19
Other, net	(5		)	—			(5		)	—			(10		)
Net Cash (Used in) Provided by Investing Activities	(567		)	70			(1,012		)	(292		)	(1,801		)

Cash Flows From Financing Activities
Issuance of debt	4,498			—			—			—			4,498
Payment of debt	(3,568		)	—			(1		)	—			(3,569		)
Debt issue costs	(10		)	—			—			—			(10		)
Funding (to) from affiliates	(769		)	(68		)	545			292			—
Proceeds from issuance of common units	619			—			—			—			619
Proceeds from issuance of i-units	6			—			—			—			6
Contributions from noncontrolling interests	—			—			32			—			32
Distributions to partners and noncontrolling interests	(883		)	—			(1,066		)	1,054			(895		)
Other, net	(1		)	—			—			—			(1		)
Net Cash Used in Financing Activities	(108		)	(68		)	(490		)	1,346			680

Effect of Exchange Rate Changes on Cash and Cash Equivalents	—			—			(10		)	—			(10		)

Net increase (decrease) in Cash and Cash Equivalents	12			(1		)	(68		)	—			(57		)
Cash and Cash Equivalents, beginning of period	10			1			393			—			404
Cash and Cash Equivalents, end of period	$	22		$	—		$	325		$	—		$	347

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Condensed Consolidating Statement of Cash Flow for the Three Months ended March 31, 2013 (In Millions) (Unaudited)

	Parent Guarantor			Subsidiary Issuers		Non-guarantor Subsidiaries			Eliminations			Consolidated KMP
Net Cash Provided by Operating Activities	$	542		$	—	$	1,074		$	(870	)	$	746

Cash Flows From Investing Activities
Payment to KMI for March 2013 drop-down asset group (Note 1)	—			—		(988		)	—			(988		)
Acquisitions of assets-other	—			—		(4		)	—			(4		)
Capital expenditures	—			—		(552		)	—			(552		)
Proceeds from sale of investments in Express pipeline system	—			—		403			—			403
Contributions to investments	—			—		(40		)	—			(40		)
Distributions from equity investments in excess of cumulative earnings	—			—		19			—			19
Funding to affiliates	(1,614		)	—		(411		)	2,025			—
Natural gas storage and natural gas and liquids line-fill	—			—		10			—			10
Sale or casualty of property, plant and equipment, investments and other net assets, net of removal costs	—			—		(3		)	—			(3		)
Other, net	(17		)	—		1			—			(16		)
Net Cash Used in Investing Activities	(1,631		)	—		(1,565		)	2,025			(1,171		)

Cash Flows From Financing Activities
Issuance of debt	2,685			—		14			—			2,699
Payment of debt	(1,715		)	—		(94		)	—			(1,809		)
Debt issue costs	(7		)	—		—			—			(7		)
Funding from affiliates	411			—		1,614			(2,025		)	—
Proceeds from issuance of common units	385			—		—			—			385
Contributions from noncontrolling interests	—			—		65			—			65
Pre-acquisition contributions from KMI to March 2013 drop-down asset group	—			—		35			—			35
Distributions to partners and noncontrolling interests	(721		)	—		(879		)	870			(730		)
Net Cash Provided by Financing Activities	1,038			—		755			(1,155		)	638

Effect of Exchange Rate Changes on Cash and Cash Equivalents	—			—		(6		)	—			(6		)

Net (decrease) increase in Cash and Cash Equivalents	(51		)	—		258			—			207
Cash and Cash Equivalents, beginning of period	95			—		434			—			529
Cash and Cash Equivalents, end of period	$	44		$	—	$	692		$	—		$	736

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 ~~2012~~2013 Form 10-K; and (iii) our management’s discussion and analysis of financial condition and results of operations included in our ~~2012~~2013 Form 10-K.

~~Table of Contents~~

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

reflect our March 1, 2013 ~~acquisition of net assets from KMI~~drop-down transaction as if such acquisition had taken place on the effective 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.control. We accounted for the March 2013 drop-down transaction as a combination of entities under common control, and accordingly, the financial information contained in this Management’s Discussion and Analysis of Financial Condition

Table of Contents

and Results of Operations ~~include~~includes the financial results of the March 2013 drop-down asset group for all periods subsequent to the effective dates of common ~~control; and~~control.

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~~GAAP 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.~~2013. Our goodwill impairment analysis performed onas of 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” ofin our ~~2012~~2013 Form 10-K.

~~Table of Contents~~

Results of Operations

~~In our discussions~~Non-GAAP Measures

The non-GAAP financial measures of (i) DCF before certain items, both in the ~~operating results~~aggregate and per unit, and (ii) segment earnings before DD&A; amortization of ~~individual businesses that follow, we generally identify the important fluctuations between periods~~excess cost of equity investments; and certain items, are presented belowunder “—Distributable Cash Flow” and “—Consolidated Earnings Results,” respectively. Certain items are items that are ~~attributable~~required by GAAP to ~~acquisitions~~be reflected in net income, but typically either do not have a cash impact, or by their nature are separately identifiable from our normal business operations and ~~dispositions separately from those~~in our view are likely to occur only sporadically.

Our non-GAAP measures described below should not be considered as an alternative to GAAP net income, operating income or any other GAAP measure. DCF before certain items, and segment earnings before DD&A, amortization of excess cost of equity investments, and certain items, are not financial measures in accordance with GAAP and have important limitations as analytical tools. You should not consider any of these non-GAAP measures in isolation or as a substitute for an analysis of our results as reported under GAAP. Because DCF before certain items excludes some but not all items that affect net income, and because DCF measures are ~~attributable~~defined differently by different companies in our industry, our DCF before certain items may not be comparable to ~~businesses owned~~DCF measures of other companies. Segment earnings before DD&A, amortization of excess cost of equity investments, and certain items, has similar limitations. Our management compensates for the limitations of these non-GAAP measures by reviewing our comparable GAAP measures, understanding the differences between the measures and taking this information into account in ~~both periods.~~its analysis and its decision making processes.

~~Consolidated~~

Results of Operations
Three Months Ended
March 31,
2013
2012
Earnings
increase/(decrease)
(In millions, except percentages)
Segment earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments(a)
Natural Gas Pipelines $ 557
$ 222
$ 335
151 %
CO₂
342
334
8
2 %
Products Pipelines 185
176
9
5 %
Terminals 186
187
(1 ) (1 )%
Kinder Morgan Canada 193
50
143
286 %
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(c) (328 ) (239 ) (89 ) (37 )%
Amortization of excess cost of equity investments (2 ) (2 ) —
— %
General and administrative expense(d) (134 ) (107 ) (27 ) (25 )%
Interest expense, net of unallocable interest income(e) (202 ) (139 ) (63 ) (45 )%
Unallocable income tax expense (3 ) (2 ) (1 ) (50 )%
Income from continuing operations 794
480
314
65 %
Loss from discontinued operations(f) (2 ) (272 ) 270
99 %
Net Income 792
208
584
281 %
Net Income attributable to noncontrolling interests(g) (9 ) (2 ) (7 ) (350 )%
Net Income attributable to Kinder Morgan Energy Partners, L.P. $ 783

$ 206
$ 577
280 %

~~____________~~


~~(a)~~	Includes revenues, earnings from equity investments, allocable interest income and other, net, less operating expenses, allocable income taxes, and other expense (income). Operating expenses include natural gas purchases and other costs of sales, operations and maintenance expenses, and taxes, other than income taxes.


~~(b)~~	~~2013~~ ~~and~~ ~~2012~~ ~~amounts include an increase in earnings of $187 million and a decrease in earnings of $3 million, respectively, related to the combined effect from all of the~~ ~~2013~~ ~~and~~ ~~2012~~ ~~certain items impacting continuing operations and disclosed below in our management, discussion and analysis of segment results.~~


~~(c)~~	~~2013~~ ~~amount includes a $19 million increase in expense attributable to our drop-down asset group for periods prior to our acquisition date of March 1, 2013.~~


~~(d)~~	~~2013~~ ~~and~~ ~~2012~~ amounts include increases in expense of $14 million and $1 million, respectively, related to the combined effect from the 2013 and 2012 certain items related to general and administrative expenses disclosed below in “—Other.”


~~(e)~~	~~2013~~ ~~amount includes a $15 million increase in expense attributable to our drop-down asset group for periods prior to our acquisition date of March 1, 2013.~~

~~(f)~~

~~Represents amounts attributable to our FTC Natural Gas Pipelines disposal group.2013~~ ~~amount represents an incremental loss related to the sale of our disposal group effective November 1, 2012.~~ ~~2012~~ amount includes a $322 million loss from a remeasurement of net assets to fair value, and $7 million of depreciation and amortization expense. The remaining 2012 amount ($57 million) represents our FTC Natural Gas Pipelines disposal group’s earnings before depreciation, depletion and amortization expenses.

~~Table of Contents~~


~~(g)~~	~~2013~~ ~~and~~ ~~2012~~ ~~amounts includean increase of $2 million and a decrease of $4 million, respectively, in net income attributable to our noncontrolling interests, related to the combined effect from all of the~~ ~~2013~~ ~~and~~ ~~2012~~ ~~certain items disclosed below in both our management discussion and analysis of segment results and “—Other.~~”

Distributable Cash Flow

As more fully described in our ~~2012~~2013 Form 10-K, we own and manage a diversified portfolio of energy transportation, production and storage assets, and primarily, our business model is designed to generate stable, fee-based income that provides overall long-term value to our unitholders. Our partnership agreement requires us to distribute 100% of our available cash to our partners on a quarterly basis (available cash as defined in our partnership agreement

Table of Contents

generally consists of all our cash receipts, less cash disbursements and changes in reserves). ~~Distributable~~For more information about our available cash ~~flow, sometimes referred~~and partnership distributions, see Note 11 “Related Party Transactions—Partnership Interests and Distributions” to as our consolidated financial statements included in our 2013 Form 10-K.

DCF is an overall performance metric we use to estimate the ability of our assets to generate cash flows on an ongoing basis and as a measure of available cash. We believe the primary measure of company performance used by us, investors and industry analysts covering MLPs is cash generation performance. Therefore, we believe DCF is an important measure to evaluate the operating and financial performance of the partnership and to compare it with the performance of other publicly traded MLPs within the industry. The following table discloses the calculation of our DCF for each of the three ~~month periods~~months ended March 31, ~~2013~~2014 and ~~2012 is as follows~~2013 (calculated before the combined effect from all of the 2014 and 2013 certain items disclosed in the footnotes to the tables ~~above)~~below):

Distributable Cash Flow
	Three Months Ended March 31,						Three Months Ended March 31,
	2013			2012			2014			2013

Net Income	$	792		$	208		$	754		$	792
Add-back/(Less): Certain items - combined income (expense)(a)	(137		)	326
Add/(Less): Certain items - combined expense/(income)(a)							34			(137		)
Net Income before certain items	655			534			788			655
Less: Net Income before certain items attributable to noncontrolling interests	(7		)	(6		)	(8		)	(7		)
Net Income before certain items attributable to Kinder Morgan Energy Partners, L.P.	648			528
Net Income before certain items attributable to KMEP							780			648
Less: General Partner’s interest in Net Income before certain items(b)	(401		)	(321		)	(453		)	(401		)
Limited Partners’ interest in Net Income before certain items	247			207			327			247
Depreciation, depletion and amortization(c)(e)	338			290			426			338
Book (cash) taxes paid, net	12			9			17			12
Incremental contributions from equity investments in the Express Pipeline and Endeavor Gathering LLC	1			—			(5		)	1
Sustaining capital expenditures(d)(e)	(48		)	(44		)	(72		)	(48		)
Distributable cash flow (DCF) before certain items	$	550		$	462
Distributable cash flow before certain items							$	693		$	550



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~~Glossary	3
	Information Regarding Forward-Looking Statements	4

	PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements (Unaudited)
	Consolidated Statements of Income - Three Months Ended March 31, ~~2013~~2014 and ~~201~~20132	35
	Consolidated Statements of Comprehensive Income - Three Months Ended March 31, ~~2013~~2014 and ~~201~~20132	46
	Consolidated Balance Sheets – March 31, ~~2013~~2014 and December 31, ~~201~~20132	57
	Consolidated Statements of Cash Flows – Three Months Ended March 31, ~~2013~~2014 and ~~201~~20132	68
	Consolidated Statements of Partners’ Capital – Three Months Ended March 31, 2014 and 2013	9
	Notes to Consolidated Financial Statements	810

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
	General and Basis of Presentation	3238
	Critical Accounting Policies and Estimates	3339
	Results of Operations	3439
	Financial Condition	45
	~~Recent Accounting Pronouncements~~	50
	~~Information Regarding Forward-Looking Statements~~	51

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	5156

Item 4.	Controls and Procedures	5156

	PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	5257

Item 1A.	Risk Factors	5257

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	5257

Item 3.	Defaults Upon Senior Securities	5257

Item 4.	Mine Safety Disclosures	5257

Item 5.	Other Information	5257

Item 6.	Exhibits	5258

	Signature	5459



KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES GLOSSARY

Company Abbreviations
BOSTCO	=	Battleground Oil Specialty Terminal	KinderHawk	=	KinderHawk Field Services LLC
		Company LLC	KMBT	=	Kinder Morgan Bulk Terminals, Inc.
Calnev	=	Calnev Pipe Line LLC	KMCO₂	=	Kinder Morgan CO₂ Company, L.P.
Copano	=	Copano Energy, L.L.C.	KMEP	=	Kinder Morgan Energy Partners, L.P.
Eagle Ford	=	Eagle Ford Gathering LLC	KMGP	=	Kinder Morgan G.P., Inc.
EP	=	El Paso Corporation and its majority-owned	KMI	=	Kinder Morgan, Inc.
		and controlled subsidiaries	KMLT	=	Kinder Morgan Liquids Terminals LLC
EPB	=	El Paso Pipeline Partners, L.P. and its	KMR	=	Kinder Morgan Management, LLC
		majority-owned and controlled subsidiaries	SFPP	=	SFPP, L.P.
EPNG	=	El Paso Natural Gas Company, L.L.C.	TGP	=	Tennessee Gas Pipeline Company, L.L.C.
Unless the context otherwise requires, references to “we,” “us,” “our,” “KMP” or the “Partnership” are intended to mean Kinder Morgan Energy Partners, L.P., our majority-owned and controlled subsidiaries, and our operating limited partnerships and their majority-owned and controlled subsidiaries.

Common Industry and Other Terms
Bcf/d	=	billion cubic feet per day	LLC	=	limited liability company
BBtu/d	=	billion British Thermal Units per day	MBbl/d	=	thousands of barrels per day
CERCLA	=	Comprehensive Environmental Response,	MLP	=	master limited partnership
		Compensation and Liability Act	NEB	=	National Energy Board
CO₂	=	carbon dioxide	NGL	=	natural gas liquids
CPUC	=	California Public Utilities Commission	NYMEX	=	New York Mercantile Exchange
EBDA	=	earnings before depreciation, depletion and	NYSE	=	New York Stock Exchange
		amortization	OTC	=	over-the-counter
DD&A	=	depreciation, depletion and amortization	PHMSA	=	Pipeline and Hazardous Materials Safety
DCF	=	distributable cash flow			Administration
EPA	=	United States Environmental Protection	SEC	=	United States Securities and Exchange
		Agency			Commission
FERC	=	Federal Energy Regulatory Commission	Sustaining	=	capital expenditures which do not increase
FASB	=	Financial Accounting Standards Board			capacity or throughput
GAAP	=	United States Generally Accepted Accounting	TBtu	=	trillion British Thermal Units
		Principles	WTI	=	West Texas Intermediate
LIBOR	=	London Interbank Offered Rate
When we refer to cubic feet measurements, all measurements are at a pressure of 14.73 pounds per square inch.

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

	March 31, 2013		December 31, 2012(a)
ASSETS	(Unaudited)
Current assets
Cash and cash equivalents	$	736	$	529
Accounts receivable, net of allowance	1,085		1,114
Inventories	352		338
Fair value of derivative contracts	33		55
Assets held for sale	32		211
Other current assets	124		130
Total Current assets	2,362		2,377

Property, plant and equipment, net	22,584		22,330
Investments	1,880		1,864
Goodwill	5,412		5,417
Other intangibles, net	1,123		1,142
Fair value of derivative contracts	552		634
Deferred charges and other assets	1,239		1,212
Total Assets	$	35,152	$	34,976

LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities
Current portion of debt	$	1,127	$	1,155
Accounts payable	983		1,091
Accrued interest	184		327
Fair value of derivative contracts	49		21
Accrued other current liabilities	851		653
Total Current liabilities	3,194		3,247

Long-term liabilities and deferred credits
Long-term debt
Outstanding	16,829		15,907
Debt fair value adjustments	1,586		1,698
Total Long-term debt	18,415		17,605
Deferred income taxes	254		249
Fair value of derivative contracts	11		13
Other long-term liabilities and deferred credits	1,044		1,100
Total Long-term liabilities and deferred credits	19,724		18,967

Total Liabilities	22,918		22,214
Commitments and contingencies (Notes 3 and 9)
Partners’ Capital
Common units	5,137		4,723
Class B units	13		14
i-units	3,676		3,564
General partner	3,008		4,026
Accumulated other comprehensive income	79		168
Total Kinder Morgan Energy Partners, L.P. Partners’ Capital	11,913		12,495
Noncontrolling interests	321		267
Total Partners’ Capital	12,234		12,762
Total Liabilities and Partners’ Capital	$	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 PARTNERS' CAPITAL (In Millions, Except Units) (Unaudited)

	Three Months Ended March 31,
	2014				2013
	Units	Amount			Units	Amount
Common units:
Beginning Balance	312,791,561	$	9,459		252,756,425	$	4,723
Net income		211				246
Units issued as consideration in the acquisition of assets	—	—			1,249,452	108
Units issued for cash	8,133,110	619			4,600,000	385
Distributions		(426		)		(326		)
Other adjustments		—				1
Ending Balance	320,924,671	9,863			258,605,877	5,137

Class B units:
Beginning Balance	5,313,400	6			5,313,400	14
Net income		4				6
Distributions		(7		)		(7		)
Ending Balance	5,313,400	3			5,313,400	13

i-Units:
Beginning Balance	125,323,734	4,222			115,118,338	3,564
Net income		84				112
Units issued for cash	76,100	6			—	—
Distributions	2,237,258	—			1,804,596	—
Ending Balance	127,637,092	4,312			116,922,934	3,676

General partner:
Beginning Balance		3,081				4,026
Net income		447				419
Distributions		(450		)		(388		)
Drop-Down acquisition (Note 1)		—				(1,051		)
Reimbursed severance expense allocated from KMI		5				1
Other adjustments		—				1
Ending Balance		3,083				3,008

Accumulated other comprehensive income (loss):
Beginning Balance		33				168
Other comprehensive loss		(118		)		(89		)
Ending Balance		(85		)		79

Total KMEP Partners’ Capital	453,875,163	17,176			380,842,211	11,913

Noncontrolling interests:
Beginning Balance		420				267
Net income		8				9
Contributions		32				65
Distributions		(12		)		(9		)
Drop-Down acquisition (Note 1)		—				(10		)
Other comprehensive loss		(1		)		(1		)
Ending Balance		447				321

Total Partners’ Capital	453,875,163	$	17,623		380,842,211	$	12,234

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)

	March 31, 2014			December 31, 2013
	(Unaudited)
ASSETS
Current assets
Cash and cash equivalents	$	347		$	404
Accounts receivable, net	1,455			1,511
Inventories	381			393
Natural gas imbalance receivables	172			68
Other current assets	328			292
Total current assets	2,683			2,668

Property, plant and equipment, net	28,558			27,405
Investments	2,263			2,233
Goodwill	6,606			6,547
Other intangibles, net	2,380			2,414
Deferred charges and other assets	1,468			1,497
Total Assets	$	43,958		$	42,764


LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities
Current portion of debt	$	1,243		$	1,504
Accounts payable	1,444			1,537
Accrued interest	205			371
Accrued contingencies	581			529
Other current liabilities	726			636
Total current liabilities	4,199			4,577

Long-term liabilities and deferred credits
Long-term debt
Outstanding	19,610			18,410
Debt fair value adjustments	1,235			1,214
Total long-term debt	20,845			19,624
Deferred income taxes	277			285
Other long-term liabilities and deferred credits	1,014			1,057
Total long-term liabilities and deferred credits	22,136			20,966

Total Liabilities	26,335			25,543
Commitments and contingencies (Notes 3 and 9)
Partners’ Capital
Common units	9,863			9,459
Class B units	3			6
i-units	4,312			4,222
General partner	3,083			3,081
Accumulated other comprehensive (loss) income	(85		)	33
Total KMEP Partners’ Capital	17,176			16,801
Noncontrolling interests	447			420
Total Partners’ Capital	17,623			17,221
Total Liabilities and Partners’ Capital	$	43,958		$	42,764

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


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



Preliminary Purchase Price Allocation:
Current assets	$	2
Property, plant and equipment	887
Goodwill	68
Other assets	3
Total assets acquired	960
Cash consideration	$	960



	Pro Forma Three Months Ended March 31, 2012
	(Unaudited)
Revenues	$	2,116
Income from Continuing Operations	$	579
Loss from Discontinued Operations	$	(272	)
Net Income	$	307
Net Income Attributable to Noncontrolling Interests	$	(2	)
Net Income Attributable to Kinder Morgan Energy Partners, L.P.	$	305

Limited Partners’ Net Income (Loss) per Unit:
Income from Continuing Operations	$	0.70
Loss from Discontinued Operations	(0.76		)
Net Loss	$	(0.06	)



	Pro Forma
	Three Months Ended March 31, 2013
	(Unaudited)
Revenues	$	3,211
Income from Continuing Operations	766
Loss from Discontinued Operations	(2		)
Net Income	764
Net Income Attributable to Noncontrolling Interests	(9		)
Net Income Attributable to KMEP	755

Limited Partners’ Net Income per Unit:
Income from Continuing Operations	$	0.79
Net Income	$	0.79



	Three Months Ended March 31, 2012
Operating revenues	$	71
Operating expenses	(37		)
Depreciation and amortization	(7		)
Earnings from equity investments	22
Interest income and Other, net	1
Income from operations of FTC Natural Gas Pipelines disposal group	$	50



	March 31, 2014			December 31, 2013
KMEP borrowings:
Senior notes, 2.65% through 9.00%, due 2014 through 2044(a)	$	17,100		$	15,600
Commercial paper borrowings(b)	419			979
Credit facility due May 1, 2018(c)	—			—
Subsidiary borrowings (as obligor):
TGP - Senior Notes, 7.00% through 8.375%, due 2016 through 2037	1,790			1,790
EPNG - Senior Notes, 5.95% through 8.625%, due 2017 through 2032	1,115			1,115
Copano - Senior Notes, 7.125%, due April 1, 2021	332			332
Other miscellaneous subsidiary debt	97			98
Total debt	20,853			19,914
Less: Current portion of debt(d)	(1,243		)	(1,504		)
Total long-term debt(e)	$	19,610		$	18,410



	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)	AsAll of our fixed rate senior notes provide that we may redeem the notes at any time at a price equal to ~~March 31, 2013~~100% ~~and~~ ~~December 31, 2012, includes commercial paper borrowings~~ of ~~$595 million~~ ~~and~~ ~~$621 million, respectively.~~the principal amount of the notes plus accrued interest to the redemption date plus a make-whole premium.


(d)	Amounts include outstanding commercial paper borrowings, discussed above in footnote (b).


(c)	See “—Credit Facilities” below.



	Three Months Ended March 31,
	2013		2012
Per unit cash distribution declared	$	1.30	$	1.20
Per unit cash distribution paid(a)	$	1.29	$	1.16
Cash distributions paid to all partners(b)(c)	$	730	$	590
i-Unit distributions made to KMR(d)	1,804,596		1,464,145
General Partner’s incentive distribution(e):
Declared	$	398	$	319
Paid(a)(c)	$	384	$	302



Debt borrowings	Interest rate		Increase / (decrease)			Cash received / (paid)
Issuances and assumptions
Senior notes due September 1, 2023(a)	3.50	%	$	600		$	598
Senior notes due March 1, 2043(a)	5.00	%	400			398
Commercial paper	variable		1,689			1,689
Kinder Morgan Altamont LLC credit facility due August 2, 2014(b)	variable		14			14
Total increases in debt			$	2,703		$	2,699

Repayments and other
Commercial paper	variable		(1,715		)	(1,715		)
Kinder Morgan Altamont LLC credit facility due August 2, 2014(b)	variable		(92		)	(92		)
Kinder Morgan Texas Pipeline, L.P. - senior notes due January 2, 2014	5.23	%	(2		)	(2		)
Total decreases in debt			$	(1,809	)	$	(1,809	)


(a)	As of both March 31, ~~2013~~2014 and December 31, ~~2012~~2013, 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.~~NYSE.


~~(b)~~	We do not have any obligation, nor did we pay any amounts related to this expense. For further information about this expense, see Note 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)~~(d)	Incentive distribution does not include the general partner’s initial 2% distribution of available cash.


(f)	2014 amount includes a decrease of $25 million for waived general partner incentive amounts related to common units issued to finance our May 2013 Copano acquisition. 2013 amount includes a decrease of $7 million for waived general partner incentive amounts related to common units issued to finance a portion of our July 2011 KinderHawk acquisition.



	Net open position long/(short)
Derivatives designated as hedging contracts
Crude oil fixed price	~~(21.4)~~(24.0)	~~million barrels~~MMBbl
Natural gas fixed price	~~(33.9)~~(23.0)	~~billion cubic feet~~Bcf
Natural gas basis	~~(34.4)~~(23.0)	~~billion cubic feet~~Bcf
Derivatives not designated as hedging contracts
Crude oil fixed price	~~(0.1)~~(0.7)	~~million barrels~~MMBbl
Crude oil basis	~~(3.6)~~(0.7)	~~million barrels~~MMBbl
Natural gas fixed price	~~(2.0)~~(13.1)	~~billion cubic feet~~Bcf
Natural gas basis	~~12.2~~(9.1)	~~billion cubic feet~~Bcf
NGL fixed price	(1.0)	MMBbl

Fair Value of Derivative Contracts
		Asset derivatives				Liability derivatives							Asset derivatives				Liability derivatives
		March 31, 2013		December 31, 2012		March 31, 2013			December 31, 2012				March 31, 2014		December 31, 2013		March 31, 2014			December 31, 2013
	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	$	19	$	42	$	(45	)	$	(18	)	Other current assets/(Other current liabilities)	$	13	$	18	$	(51	)	$	(33	)
	Non-current-Fair value of derivative contracts	37		40		(8		)	(11		)	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	22		58		(13		)	(30		)
Subtotal		56		82		(53		)	(29		)		35		76		(64		)	(63		)
Interest rate swap agreements	Current-Fair value of derivative contracts	7		9		—			—			Other current assets/(Other current liabilities)	105		76		—			—
	Non-current-Fair value of derivative contracts	515		594		(3		)	(1		)	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	151		141		(94		)	(116		)
Subtotal		522		603		(3		)	(1		)		256		217		(94		)	(116		)
Total		578		685		(56		)	(30		)		291		293		(158		)	(179		)

Derivatives not designated as hedging contracts
Energy commodity derivative contracts	Current-Fair value of derivative contracts	7		4		(4		)	(3		)	Other current assets/(Other current liabilities)	6		4		(9		)	(5		)
	Non-current-Fair value of derivative contracts	—		—		—			(1		)
Total		7		4		(4		)	(4		)		6		4		(9		)	(5		)
Total derivatives(a)		$	585	$	689	$	(60	)	$	(34	)
Total derivatives													$	297	$	297	$	(167	)	$	(184	)


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 March 31,							Three Months Ended March 31,
		2013			2012				2014			2013
Interest rate swap agreements	Interest expense	$	(83	)	$	(113	)	Interest expense	$	61		$	(83	)
Total		$	(83	)	$	(113	)		$	61		$	(83	)

Fixed rate debt	Interest expense	$	83		$	113		Interest expense	$	(61	)	$	83
Total		$	83		$	113			$	(61	)	$	83


(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 March 31,							Three Months Ended March 31,						Three Months Ended March 31,						Three Months Ended March 31,							Three Months Ended March 31,						Three Months Ended March 31,
	2013			2012				2013		2012				2013			2012			2014			2013				2014			2013			2014			2013
Energy commodity derivative contracts	$	(41	)	$	(114	)	Revenues-Natural gas sales	$	—	$	—		Revenues-Natural gas sales	$	—		$	—		$	(56	)	$	(41	)	Revenues-Natural gas sales	$	(10	)	$	—	Revenues-Natural gas sales	$	—		$	—
							Revenues-Product sales and other	7		(29		)	Revenues-Product sales and other	(3		)	(3		)							Revenues-Product sales and other	(9		)	7		Revenues-Product sales and other	(5		)	(3		)
							Gas purchases and other costs of sales	—		(2		)	Gas purchases and other costs of sales	—			—									Costs of sales	1			—		Costs of sales	—			—
Total	$	(41	)	$	(114	)	Total	$	7	$	(31	)	Total	$	(3	)	$	(3	)	$	(56	)	$	(41	)	Total	$	(18	)	$	7	Total	$	(5	)	$	(3	)



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	$	—



Derivatives not designated as accounting hedges	Location of gain/(loss) recognized in income on derivatives	Amount of gain/(loss) recognized in income on derivatives
		Three Months Ended March 31,
		2014			2013
Energy commodity derivative contracts	Revenues-Natural gas sales	$	(7	)	$	—
	Revenues-Product sales and other	(7		)	4
	Costs of sales	10			—
	Other expense (income)	(2		)	—
Total		$	(6	)	$	4



	Asset position
Interest rate swap agreements	$	522
Energy commodity derivative contracts	63
Gross exposure	585
Netting agreement impact	(18		)
Cash collateral held	—
Net exposure	$	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, 2013	$	24		$	(4	)	$	13		$	33
Other comprehensive (loss) income before reclassifications	(56		)	(78		)	(2		)	(136		)
Amounts reclassified from accumulated other comprehensive income	18			—			—			18
Net current-period other comprehensive (loss) income	(38		)	(78		)	(2		)	(118		)
Balance as of March 31, 2014	$	(14	)	$	(82	)	$	11		$	(85	)


▪	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								Balance Sheet asset fair value measurements using								Amounts not offset in the Balance Sheet					Net Amount
	Total		Quoted prices in active markets for identical assets (Level 1)		Significant other observable inputs (Level 2)		Significant unobservable inputs (Level 3)		Level 1		Level 2		Level 3		Gross Amount		Financial Instruments			Cash Collateral Held(b)		Net Amount
As of March 31, 2013
As of March 31, 2014
Energy commodity derivative contracts(a)	$	63	$	2	$	57	$	4	$	6	$	29	$	6	$	41	$	(30	)	$	—	$	11
Interest rate swap agreements	$	522	$	—	$	522	$	—	$	—	$	256	$	—	$	256	$	(44	)	$	—	$	212

As of December 31, 2012
As of December 31, 2013
Energy commodity derivative contracts(a)	$	86	$	3	$	76	$	7	$	4	$	46	$	30	$	80	$	(44	)	$	—	$	36
Interest rate swap agreements	$	603	$	—	$	603	$	—	$	—	$	217	$	—	$	217	$	(28	)	$	—	$	189