UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
F O R M 10‑Q
[X]
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended
March 31, 2014
or
[ ]
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from
_____to_____
Commission file number:
1‑11234
KINDER MORGAN ENERGY PARTNERS, L.P.
(Exact name of registrant as specified in its charter)
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Delaware
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76-0380342
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(State or other jurisdiction of
incorporation or organization)
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(I.R.S. Employer
Identification No.)
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1001 Louisiana Street, Suite 1000, Houston, Texas 77002
(Address of principal executive offices)(zip code)
Registrant’s telephone number, including area code: 713‑369‑9000
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes [X] No [ ]
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. Large accelerated filer [X] Accelerated filer [ ] Non-accelerated filer [ ] (Do not check if a smaller reporting company) Smaller reporting company [ ]
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes [ ] No [X]
The Registrant had
320,924,671
common units outstanding as of
April 28, 2014
.
1
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KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
TABLE OF CONTENTS
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2
3
Information Regarding Forward-Looking Statements
This report includes forward-looking statements. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. They use words such as “anticipate,” “believe,” “intend,” “plan,” “projection,” “forecast,” “strategy,” “position,” “continue,” “estimate,” “expect,” “may,” or the negative of those terms or other variations of them or comparable terminology. In particular, expressed or implied statements concerning future actions, conditions or events, future operating results or the ability to generate sales, income or cash flow or to make distributions are forward-looking statements. Forward-looking statements are not guarantees of performance. They involve risks, uncertainties and assumptions. Future actions, conditions or events and future results of operations may differ materially from those expressed in these forward-looking statements. Many of the factors that will determine these results are beyond our ability to control or predict.
See
“
Information Regarding Forward-Looking Statements” and Part I, Item 1A “Risk Factors” in our Annual Report on Form 10-K for the year ended
December 31, 2013
(
2013
Form 10-K) for a more detailed description of factors that may affect the forward-looking statements. When considering forward-looking statements, one should keep in mind the risk factors described in our
2013
Form 10-K. The risk factors could cause our actual results to differ materially from those contained in any forward-looking statement. Because of these risks and uncertainties, you should not place undue reliance on any forward-looking statement. We plan to provide updates to projections included in this report when we believe previously disclosed projections no longer have a reasonable basis.
4
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements.
5
6
7
8
9
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
1. General
Organization
KMEP is a Delaware limited partnership formed in August 1992. We are a leading pipeline transportation and energy storage company in North America, managing a diversified portfolio of energy transportation and storage assets. We own an interest in or operate approximately
52,000
miles of pipelines and
180
terminals, and we conduct our business through
five
reportable business segments (described further in Note 7). Our common units trade on the NYSE under the symbol “KMP.”
Our pipelines transport natural gas, refined petroleum products, crude oil, condensate, CO
2
and other products, and our terminals store petroleum products, ethanol and chemicals, and handle such products as coal, petroleum coke and steel. We are also the leading producer and transporter of CO
2
, for enhanced oil recovery projects in North America.
KMI and Kinder Morgan G.P., Inc.
KMI, a Delaware corporation, indirectly owns all the common stock of our general partner, Kinder Morgan G.P., Inc., a Delaware corporation. In July 2007, our general partner issued and sold to a third party
100,000
shares of Series A fixed-to-floating rate term cumulative preferred stock due
2057
. The consent of holders of a majority of these preferred shares is required with respect to a commencement of or a filing of a voluntary bankruptcy proceeding with respect to us or
two
of our subsidiaries, SFPP and Calnev. KMI’s common stock trades on the NYSE under the symbol “KMI.”
As of
March 31, 2014
, KMI and its consolidated subsidiaries owned, through KMI’s general and limited partner interests in us and its ownership of shares issued by its subsidiary KMR (discussed below), an approximate
11.5%
interest in us. In addition, as of
March 31, 2014
, KMI owns a
40%
limited partner interest and the
2%
general partner interest in EPB.
KMR
KMR is a Delaware LLC. Our general partner owns all of KMR’s voting securities and, pursuant to a delegation of control agreement, has delegated to KMR, to the fullest extent permitted under Delaware law and our partnership agreement, all of its power and authority to manage and control our business and affairs, except that KMR cannot take certain specified actions without the approval of our general partner. Generally, KMR makes all decisions relating to the management and control of our business, and in general, KMR has a duty to manage us in a manner beneficial to our unitholders. KMR’s shares representing LLC interests trade on the NYSE under the symbol “KMR.” As of
March 31, 2014
, KMR, through its sole ownership of our i-units, owned approximately
28.1%
of all of our outstanding limited partner units (which are in the form of i-units that are issued only to KMR).
More information about the entities referred to above and the delegation of control agreement is contained in our
2013
Form 10-K. For a more complete discussion of our related party transactions with the entities referred to above, 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
2013
Form 10-K.
Basis of Presentation
General
Our reporting currency is in U.S. dollars, and all references to dollars are U.S. dollars, except where stated otherwise. Canadian dollars are designated as C$.
Our accompanying consolidated financial statements include our accounts, and the accounts of Copano and our operating limited partnerships and Copano’s majority-owned and controlled subsidiaries, and we have prepared our accompanying unaudited consolidated financial statements under the rules and regulations of the SEC. These rules and
10
regulations conform to the accounting principles contained in the FASB’s Accounting Standards Codification, the single source of GAAP. Under such rules and regulations, all significant intercompany items have been eliminated in consolidation. Additionally, we have condensed or omitted certain information and notes normally included in financial statements prepared in conformity with the Codification. We believe, however, that our disclosures are adequate to make the information presented not misleading.
Our accompanying unaudited consolidated financial statements reflect normal adjustments, and also recurring adjustments that are, in the opinion of our management, necessary for a fair statement of our financial results for the interim periods. In addition, certain amounts from prior periods have been reclassified to conform to the current presentation (including reclassifications between “Services” and “Product sales and other” within the “Revenues” section of our accompanying consolidated statements of income). Interim results are not necessarily indicative of results for a full year; accordingly, you should read these consolidated financial statements in conjunction with our consolidated financial statements and related notes included in our
2013
Form 10-K.
Our financial statements are consolidated into the consolidated financial statements of KMI; however, except for the related party transactions described in Note 8 “Related Party Transactions,” KMI is not liable for, and its assets are not available to satisfy, our obligations and/or our subsidiaries’ obligations, and vice versa. Responsibility for payments of obligations reflected in our or KMI’s financial statements is a legal determination based on the entity that incurs the liability. Furthermore, the determination of responsibility for payment among entities in our consolidated group of subsidiaries is not impacted by the consolidation of our financial statements into the consolidated financial statements of KMI.
March 2013 KMI Asset Drop-Down
Effective
March 1, 2013
, we acquired from KMI the remaining
50%
ownership interest we did not already own in both EPNG and the EP midstream assets for an aggregate consideration of approximately
$1.7 billion
(including our proportional share of assumed debt borrowings as of
March 1, 2013
). In this report, we refer to this acquisition of assets from KMI as the March 2013 drop-down transaction; the combined group of assets acquired from KMI effective March 1, 2013 as the March 2013 drop-down asset group; and the EP midstream assets of Kinder Morgan Altamont LLC (formerly, El Paso Midstream Investment Company, L.L.C.) as the EP midstream assets. We acquired our initial
50%
ownership interest in the EP midstream assets from an investment vehicle affiliated with Kohlberg Kravis Roberts & Co. L.P., referred to as KKR, effective June 1, 2012. Prior to the March 2013 drop-down transaction, we accounted for our initial
50%
ownership interests in both EPNG and the EP midstream assets under the equity method of accounting.
KMI acquired all of the assets included in the March 2013 drop-down asset group as part of its May 25, 2012 acquisition of EP, and KMI accounted for its EP acquisition under the acquisition method of accounting. We, however, accounted for the March 2013 drop-down transaction as combinations of entities under common control. Accordingly, we prepared our consolidated financial statements to reflect the transfer of the March 2013 drop-down asset group from KMI to us as if such transfer had taken place on the date when the March 2013 drop-down asset group met the accounting requirements for entities under common control—May 25, 2012 for EPNG, and June 1, 2012 for the EP midstream assets. Specifically, we (i) consolidated our now
100%
investment in the March 2013 drop-down asset group as of the effective dates of common control, recognizing the acquired assets and assumed liabilities at KMI’s carrying value (including all of KMI’s purchase accounting adjustments); (ii) recognized any difference between our purchase price and the carrying value of the net assets we acquired as an adjustment to our Partners’ Capital (specifically, as an adjustment to our general partner’s and our noncontrolling interests’ capital interests); and (iii) retrospectively adjusted our consolidated financial statements, for any date after the effective dates of common control.
Additionally, because KMI both controls us and consolidates our financial statements into its consolidated financial statements as a result of its ownership of our general partner, we fully allocated to our general partner:
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▪
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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
(we refer to these earnings as “pre-acquisition” earnings and we reported these earnings separately as “Pre-acquisition income from operations of March 2013 drop-down asset group allocated to General Partner” within the “Calculation of Limited Partners’ Interest in Net Income Attributable to KMEP” section of our accompanying consolidated statements of income for the
three
months ended
March 31, 2013
); and
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▪
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incremental severance expense related to KMI’s acquisition of EP and allocated to us from KMI. This severance expense allocated to us was associated with both the March 2013 drop-down asset group and assets we acquired
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11
(pursuant to the drop-down) from KMI effective August 1, 2012; however, we do not have any obligation, nor did we pay any amounts related to this expense. Furthermore, we reported this expense separately as “Drop-down asset group’s severance expense allocated to General Partner” within the “Calculation of Limited Partners’ Interest in Net Income Attributable to KMEP” section of our accompanying consolidated statements of income for each of the
three
months ended
March 31, 2014
and
2013
.
For all periods beginning after our acquisition date of
March 1, 2013
, we allocated our earnings (including the earnings from the March 2013 drop-down asset group) to all of our partners according to our partnership agreement.
Goodwill
We evaluate goodwill for impairment on
May 31
of each year. There were no impairment charges resulting from our May 31, 2013 impairment testing, and no event indicating an impairment has occurred subsequent to that date.
Limited Partners’ Net Income per Unit
We compute Limited Partners’ Net Income per Unit by dividing our limited partners’ interest in net income by the weighted average number of units outstanding during the period.
2. Acquisitions and Divestitures
Acquisitions
American Petroleum Tankers and State Class Tankers
Effective
January 17, 2014
, we acquired American Petroleum Tankers (APT) and State Class Tankers (SCT) for aggregate consideration of
$960 million
in cash, subject to purchase price adjustments (the APT acquisition). Our general partner has agreed to waive incentive distribution amounts of
$13 million
for 2014,
$19 million
for 2015 and
$6 million
for 2016 to facilitate the transaction.
APT is engaged in the marine transportation of crude oil, condensate and refined products in the U.S. domestic trade, commonly referred to as the Jones Act trade. APT’s primary assets consist of a fleet of
five
medium range Jones Act qualified product tankers, each with
330
MBbl of cargo capacity, and each operating pursuant to long-term time charters with high quality counterparties, including major integrated oil companies, major refiners and the U.S. Navy. The vessels’ time charters have an average remaining term of approximately four years, with renewal options to extend the initial terms by an average of two years. APT’s vessels are operated by Crowley Maritime Corporation.
SCT has commissioned the construction of
four
medium range Jones Act qualified product tankers, each with
330
MBbl of cargo capacity. The SCT vessels are scheduled to be delivered in 2015 and 2016 and are being constructed by General Dynamics’ NASSCO shipyard. We expect to invest approximately
$214 million
to complete the construction of the vessels. Upon delivery, the SCT vessels will be operated pursuant to long-term time charters with a major integrated oil company. Each of the time charters has an initial term of five years, with renewal options to extend the initial term by up to three years. Our APT acquisition complements and extends our existing crude oil and refined products transportation business, and all of the acquired assets are included in our Terminals business segment.
As of
March 31, 2014
, our preliminary purchase price allocation related to our APT acquisition, as adjusted to date, is as follows (in millions). Our evaluation of the assigned fair values is ongoing and subject to adjustment.
12
The “Goodwill” intangible asset amount represents the future economic benefits expected to be derived from this acquisition that are not assignable to other individually identifiable, separately recognizable assets acquired. We believe the primary items that generated the goodwill are the value of the synergies created by expanding our non-pipeline liquids handling operations, and we expect the entire amount to be deductible for tax purposes.
Other
Effective
May 1, 2013
, we acquired
all
of Copano’s outstanding units for a total purchase price of approximately
$5.2 billion
(including assumed debt and all other assumed liabilities). The transaction was a
100%
unit for unit transaction with an exchange ratio of
0.4563
of our common units for each Copano common unit. We issued
43,371,210
of our common units valued at
$3,733 million
as consideration for the Copano acquisition (based on the
$86.08
closing market price of a common unit on the NYSE on the
May 1, 2013
issuance date).
Effective
June 1, 2013
, we acquired certain oil and gas properties, rights, and related assets located in the Goldsmith Landreth San Andres oil field unit in the Permian Basin of West Texas from Legado Resources LLC for an aggregate consideration of
$298 million
, consisting of
$280 million
in cash and assumed liabilities of
$18 million
(including
$12 million
of long-term asset retirement obligations).
For additional information about our Copano and Goldsmith Landreth acquisitions (including our preliminary purchase price allocations as of
December 31, 2013
), see Note 3 “Acquisitions and Divestitures—Business Combinations and Acquisitions of Investments” to our consolidated financial statements included in our
2013
Form 10-K.
Pro Forma Information
The following summarized unaudited pro forma consolidated income statement information for the
three
months ended
March 31, 2013
assumes that our acquisitions of (i) APT, (ii) Copano and (iii) the Goldsmith Landreth oil field unit had occurred as of
January 1, 2013
. We prepared the following summarized unaudited pro forma financial results for comparative purposes only. The summarized unaudited pro forma financial results may not be indicative of the results that would have occurred if we had completed these acquisitions as of
January 1, 2013
, or the results that will be attained in the future. Amounts presented below are in millions, except for the per unit amounts:
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Pro Forma
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Three Months Ended
March 31, 2013 |
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(Unaudited)
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Revenues
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$
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3,211
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Income from Continuing Operations
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766
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Loss from Discontinued Operations
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(2
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)
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Net Income
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764
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Net Income Attributable to Noncontrolling Interests
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(9
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)
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Net Income Attributable to KMEP
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755
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Limited Partners’ Net Income per Unit:
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Income from Continuing Operations
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$
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0.79
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Net Income
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$
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0.79
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Divestitures
Express Pipeline System
Effective
March 14, 2013
, we sold both our one-third equity ownership interest in the Express pipeline system and our subordinated debenture investment in Express to Spectra Energy Corp. We received net cash proceeds of
$402 million
(after paying
$1 million
in the second quarter of 2013 for both a final working capital settlement and certain transaction related selling expenses), and we reported the
$403 million
in proceeds received in the first quarter of 2013 separately as “Proceeds from sale of investments in Express pipeline system” within the investing section of our
13
accompanying consolidated statements of cash flows. Additionally, we recognized a combined
$225 million
pre-tax gain with respect to this sale in the first quarter of 2013, and we reported this gain amount separately as “Gain on sale of investments in Express pipeline system” on our accompanying consolidated statements of income. We also recorded an income tax expense of
$84 million
related to this gain on sale for the three month period, and we included this expense within
“
Income Tax Expense.” As of the date of sale, our equity investment in Express totaled
$67 million
and our note receivable due from Express totaled
$110 million
.
FTC Natural Gas Pipelines Disposal Group – Discontinued Operations
As discussed in our 2013 Form 10-K, we sold our FTC Natural Gas Pipelines disposal group to Tallgrass Energy Partners, LP (now known as Tallgrass Development, LP) (Tallgrass) effective November 1, 2012. We and Tallgrass trued up the final consideration for the sale of our FTC Natural Gas Pipelines disposal group in the first quarter of 2013, and based on this true up, we recognized an additional
$2 million
loss.
3. Debt
We classify our debt based on the contractual maturity dates of the underlying debt instruments. We defer costs associated with debt issuance over the applicable term. These costs are then amortized as interest expense in our accompanying consolidated statements of income using the effective interest rate method. The following table provides detail on the principal amount of our outstanding debt as of
March 31, 2014
and
December 31, 2013
. The table amounts exclude all debt fair value adjustments, including debt discounts and premiums (in millions).
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March 31,
2014 |
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December 31,
2013 |
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KMEP borrowings:
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Senior notes, 2.65% through 9.00%, due 2014 through 2044(a)
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$
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17,100
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$
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15,600
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Commercial paper borrowings(b)
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419
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979
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Credit facility due May 1, 2018(c)
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—
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—
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Subsidiary borrowings (as obligor):
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TGP - Senior Notes, 7.00% through 8.375%, due 2016 through 2037
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1,790
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1,790
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EPNG - Senior Notes, 5.95% through 8.625%, due 2017 through 2032
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1,115
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1,115
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Copano - Senior Notes, 7.125%, due April 1, 2021
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332
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332
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Other miscellaneous subsidiary debt
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97
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98
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Total debt
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20,853
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19,914
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Less: Current portion of debt(d)
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(1,243
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)
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(1,504
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)
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Total long-term debt(e)
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$
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19,610
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$
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18,410
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__________
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(a)
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All of our fixed rate senior notes provide that we may redeem the notes at any time at a price equal to
100%
of the principal amount of the notes plus accrued interest to the redemption date plus a make-whole premium.
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(b)
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As of
March 31, 2014
and
December 31, 2013
, the average interest rates on our outstanding commercial paper borrowings were
0.26%
and
0.28%
, respectively. The borrowings under our commercial paper program were used principally to finance the acquisitions and capital expansions we made during the first three months of
2014
, and in the near term, we expect that our short-term liquidity and financing needs will be met primarily through borrowings made under our commercial paper program.
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(c)
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See “—Credit Facilities” below.
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(d)
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Amounts include outstanding commercial paper borrowings, discussed above in footnote (b).
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(e)
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Excludes debt fair value adjustments. As of
March 31, 2014
and
December 31, 2013
, our “Debt fair value adjustments
”
increased our debt balances by
$1,235 million
and
$1,214 million
, respectively. In addition to all unamortized debt discount/premium amounts and purchase accounting on our debt balances, our debt fair value adjustments also include (i) amounts associated with the offsetting entry for hedged debt; and (ii) any unamortized portion of proceeds received from the early termination of interest rate swap agreements. For further information about our debt fair value adjustments, see Note 5 “Risk Management—Debt Fair Value Adjustments.”
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Credit Facilities
As of both
March 31, 2014
and
December 31, 2013
, we had
no
borrowings under our
$2.7 billion
five
-year senior unsecured revolving credit facility maturing
May 1, 2018
. Borrowings under our revolving credit facility can be used for
14
general partnership purposes and as a backup for our commercial paper program. Similarly, borrowings under our commercial paper program reduce the borrowings allowed under our credit facility.
We had, as of
March 31, 2014
,
$2,079 million
of borrowing capacity available under our credit facility. The amount available for borrowing under our credit facility was reduced by
a combined amount of
$621 million
, consisting of
$419 million
of commercial paper borrowings and
$202 million
of letters of credit, consisting of (i) a
$100 million
letter of credit that supports certain proceedings with the CPUC involving refined products tariff charges on the intrastate common carrier operations of our Pacific operations’ pipelines in the state of California; (ii) a combined
$84 million
in
three
letters of credit that support tax-exempt bonds; and (iii) a combined
$18 million
in other letters of credit supporting other obligations of us and our subsidiaries.
Changes in Debt
On January 15, 2014, in anticipation of our APT acquisition, we entered into a short-term unsecured liquidity facility with us as borrower, and UBS as administrative agent. This liquidity facility provided for borrowings of up to
$1.0 billion
from a syndicate of financial institutions and was scheduled to mature on July 15, 2014. Additionally, in conjunction with the establishment of this liquidity facility, we increased our commercial paper program to provide for the issuance of up to
$3.7 billion
(up from
$2.7 billion
). We made
no
borrowings under this liquidity facility, and after receiving the cash proceeds from both our February 2014 public offering of senior notes (described following) and our February 2014 public offering of common units (described in Note 4 “Partners’ Capital—Equity Issuances”), we terminated the liquidity facility and decreased our commercial paper program to again provide for the issuance of up to
$2.7 billion
.
On February 24, 2014, we completed a public offering of a total
$1.5 billion
in principal amount of senior notes in two separate series. We received net proceeds of
$743 million
from the offering of
$750 million
in principal amount of
3.50%
senior notes due March 1, 2021, and
$739 million
from the offering of
$750 million
in principal amount of
5.50%
senior notes due March 1, 2044. We used the proceeds from our February 2014 debt offering to reduce the borrowings under our commercial paper program (by reducing the incremental commercial paper borrowings we made in January 2014 to fund our APT acquisition).
4. Partners’ Capital
Limited Partner Units
As of
March 31, 2014
and
December 31, 2013
, our Partners’ Capital included the following limited partner units:
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March 31,
2014 |
|
December 31,
2013 |
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Common units:
|
|
|
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Held by third parties
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298,637,216
|
|
|
290,504,106
|
|
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Held by KMI and affiliates (excluding our general partner)
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20,563,455
|
|
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20,563,455
|
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Held by our general partner
|
1,724,000
|
|
|
1,724,000
|
|
|
Total Common units
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320,924,671
|
|
|
312,791,561
|
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Class B units(a)
|
5,313,400
|
|
|
5,313,400
|
|
|
i-units(b)
|
127,637,092
|
|
|
125,323,734
|
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Total limited partner units
|
453,875,163
|
|
|
443,428,695
|
|
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(a)
|
As of both
March 31, 2014
and
December 31, 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 NYSE.
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(b)
|
As of both
March 31, 2014
and
December 31, 2013
, all of our i-units were held by KMR. Our i-units are a separate class of limited partner interests in us and are not publicly traded. In accordance with KMR’s LLC agreement, KMR’s activities are restricted to being a limited partner in us, and to controlling and managing our business and affairs and the business and affairs of our operating limited partnerships and their subsidiaries. Through the combined effect of the provisions in our partnership agreement and the provisions of KMR’s LLC agreement, the number of outstanding KMR shares and the number of our i-units will at all times be equal. The number of i-units we distribute to KMR is based upon the amount of cash we distribute to the owners of our common units. When cash is paid to the holders of our common units, we issue additional i-units to KMR. The fraction of an i-unit paid per i-unit owned by KMR will have a value based on the cash payment on the common units.
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15
The total limited partner units represent our limited partners’ interest and an effective
98%
interest in us, exclusive of our general partner’s right to receive incentive distributions. Our general partner has an effective
2%
interest in us, excluding its right to receive incentive distributions.
Equity Issuances
For the
three month period ended March 31, 2014
, our equity issuances consisted of the following:
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•
|
on
February 24, 2014
, we issued, in a public offering,
7,935,000
of our common units at a price of
$78.32
per unit, less commissions and underwriting expenses. We received net proceeds of
$603 million
for the issuance of these
7,935,000
common units, and used the proceeds to reduce the borrowings under our commercial paper program (by reducing the incremental borrowings we made under our commercial paper program in January 2014 to fund our APT acquisition);
|
|
•
|
in
January 2014
, we issued
198,110
of our common units pursuant to our equity distribution agreements with UBS (to settle sales made on or before
December 31, 2013
). We received net proceeds from the issuance of these common units of
$16 million
, and we used the proceeds to reduce the borrowings under our commercial paper program; and
|
|
•
|
in
January 2014
, we issued
76,100
i-units to KMR (to settle sales made on or before
December 31, 2013
). We received net proceeds of
$6 million
for the issuance of these i-units, and we used the proceeds to reduce the borrowings under our commercial paper program.
|
Income Allocations
For the purposes of maintaining partner capital accounts, our partnership agreement specifies that items of income and loss shall be allocated among the partners, other than owners of i-units, in accordance with their percentage interests. Normal allocations according to percentage interests are made, however, only after giving effect to any priority income allocations in an amount equal to the incentive distributions that are allocated
100%
to our general partner. Incentive distributions are generally defined as all cash distributions paid to our general partner that are in excess of
2%
of the aggregate value of cash and i-units being distributed, and we determine the allocation of incentive distributions to our general partner by the amount quarterly distributions to unitholders exceed certain specified target levels, according to the provisions of our partnership agreement.
Partnership Distributions
The following table provides information about our distributions for each of the
three
month periods ended
March 31, 2014
and
2013
(in millions except per unit and i-unit distributions amounts):
|
|
Three Months Ended
March 31, |
||||||
|
|
2014
|
|
2013
|
||||
|
Per unit cash distribution declared for the period
|
$
|
1.38
|
|
|
$
|
1.30
|
|
|
Per unit cash distribution paid in the period
|
$
|
1.36
|
|
|
$
|
1.29
|
|
|
Cash distributions paid in the period to all partners(a)(b)
|
$
|
895
|
|
|
$
|
730
|
|
|
i-unit distributions made in the period to KMR(c)
|
2,237,258
|
|
|
1,804,596
|
|
||
|
General Partner’s incentive distribution(d):
|
|
|
|
||||
|
Declared for the period(e)
|
$
|
449
|
|
|
$
|
398
|
|
|
Paid in the period(b)(c)(f)
|
$
|
445
|
|
|
$
|
384
|
|
_________
|
(a)
|
Consisting of our common and Class B unitholders, our general partner and noncontrolling interests.
|
|
(b)
|
The period-to-period increases in distributions paid primarily reflect the increases in amounts distributed per unit as well as the issuance of additional units.
|
|
(c)
|
Under the terms of our partnership agreement, we agreed that we will not, except in liquidation, make a distribution on an i-unit other than in additional i-units or a security that has in all material respects the same rights and privileges as our i-units. The number of i-units we distribute to KMR is based upon the amount of cash we distribute to the owners of our common units. When cash is paid to the holders of our common units, we will issue additional i-units to KMR. The fraction of an i-unit paid per i-unit owned by KMR will have a value based on the cash payment on the common units. If additional units are distributed to the holders of our common units, we will issue an equivalent amount of i-units to KMR based on the number of i-units it owns. Based on the preceding, the i-units we distributed were based on the
$1.36
and
$1.29
per unit paid to our common unitholders during the
first
quarters of
2014
and
2013
, respectively.
|
|
(d)
|
Incentive distribution does not include the general partner’s initial
2%
distribution of available cash.
|
16
|
(e)
|
2014 amount includes a decrease of
$30 million
for waived general partner incentive amounts related to common units issued to finance our May 2013 Copano acquisition, and a decrease of
$3 million
for waived general partner incentive amounts related to common units issued to finance a portion of our January 2014 APT acquisition. 2013 amount includes a decrease of
$4 million
for waived general partner incentive amounts related to common units issued to finance a portion of our July 2011 KinderHawk acquisition.
|
|
(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.
|
For additional information about our partnership distributions, see Note 11 “Related Party Transactions—Partnership Interests and Distributions” to our consolidated financial statements included in our
2013
Form 10-K.
Subsequent Events
On April 16, 2014, we declared a cash distribution of
$1.38
per unit for the quarterly period ended
March 31, 2014
. The distribution will be paid on May 15, 2014 to unitholders of record as of April 30, 2014. Our common unitholders and our Class B unitholder will receive cash. KMR will receive a distribution of
2,386,814
additional i-units based on the
$1.38
distribution per common unit. For each outstanding i-unit that KMR holds, a fraction of an i-unit (
0.018700
) will be issued. This fraction was determined by dividing:
|
•
|
$1.38
, the cash amount distributed per common unit
|
by
|
•
|
$73.796
, the average of KMR’s shares’ closing market prices from April 11-25, 2014, the ten consecutive trading days preceding the date on which the shares began to trade ex-dividend under the rules of the NYSE.
|
5. Risk Management
Certain of our business activities expose us to risks associated with unfavorable changes in the market price of natural gas, NGL and crude oil. We also have exposure to interest rate risk as a result of the issuance of our debt obligations. Pursuant to our management’s approved risk management policy, we use derivative contracts to hedge or reduce our exposure to certain of these risks.
Energy Commodity Price Risk Management
As of
March 31, 2014
, we had the following outstanding commodity forward contracts to hedge our forecasted energy commodity purchases and sales:
|
|
Net open position
long/(short)
|
|
|
Derivatives designated as hedging contracts
|
|
|
|
Crude oil fixed price
|
(24.0)
|
MMBbl
|
|
Natural gas fixed price
|
(23.0)
|
Bcf
|
|
Natural gas basis
|
(23.0)
|
Bcf
|
|
Derivatives not designated as hedging contracts
|
|
|
|
Crude oil fixed price
|
(0.7)
|
MMBbl
|
|
Crude oil basis
|
(0.7)
|
MMBbl
|
|
Natural gas fixed price
|
(13.1)
|
Bcf
|
|
Natural gas basis
|
(9.1)
|
Bcf
|
|
NGL fixed price
|
(1.0)
|
MMBbl
|
As of
March 31, 2014
, the maximum length of time over which we have hedged our exposure to the variability in future cash flows associated with energy commodity price risk is through
December 2018
.
Interest Rate Risk Management
As of
March 31, 2014
, we had a combined notional principal amount of
$5,175 million
of fixed-to-variable interest rate swap agreements, effectively converting the interest expense associated with certain series of our senior notes from fixed rates to variable rates based on an interest rate of LIBOR plus a spread. All of our swap agreements have termination dates that correspond to the maturity dates of the related series of senior notes and, as of
March 31, 2014
, the
17
maximum length of time over which we have hedged a portion of our exposure to the variability in the value of this debt due to interest rate risk is through
March 15, 2035
.
As of
December 31, 2013
, we had a combined notional principal amount of
$4,675 million
of fixed-to-variable interest rate swap agreements. In
February 2014
, we entered into
four
separate fixed-to-variable interest rate swap agreements having a combined notional principal amount of
$500 million
. These agreements effectively convert a portion of the interest expense associated with our
3.50%
senior notes due March 1, 2021, from a fixed rate to a variable rate based on an interest rate of LIBOR plus a spread.
Fair Value of Derivative Contracts
The following table summarizes the fair values of our derivative contracts included on our accompanying consolidated balance sheets as of
March 31, 2014
and
December 31, 2013
(in millions):
|
Fair Value of Derivative Contracts
|
|||||||||||||||||
|
|
|
|
Asset derivatives
|
|
Liability derivatives
|
||||||||||||
|
|
|
|
March 31,
2014 |
|
December 31,
2013 |
|
March 31,
2014 |
|
December 31,
2013 |
||||||||
|
|
Balance sheet location
|
|
Fair value
|
|
Fair value
|
|
Fair value
|
|
Fair value
|
||||||||
|
Derivatives designated as hedging contracts
|
|
|
|
|
|
|
|
|
|
||||||||
|
Energy commodity derivative contracts
|
Other current assets/(Other current liabilities)
|
|
$
|
13
|
|
|
$
|
18
|
|
|
$
|
(51
|
)
|
|
$
|
(33
|
)
|
|
|
Deferred charges and other assets/(Other long-term liabilities and deferred credits)
|
|
22
|
|
|
58
|
|
|
(13
|
)
|
|
(30
|
)
|
||||
|
Subtotal
|
|
|
35
|
|
|
76
|
|
|
(64
|
)
|
|
(63
|
)
|
||||
|
Interest rate swap agreements
|
Other current assets/(Other current liabilities)
|
|
105
|
|
|
76
|
|
|
—
|
|
|
—
|
|
||||
|
|
Deferred charges and other assets/(Other long-term liabilities and deferred credits)
|
|
151
|
|
|
141
|
|
|
(94
|
)
|
|
(116
|
)
|
||||
|
Subtotal
|
|
|
256
|
|
|
217
|
|
|
(94
|
)
|
|
(116
|
)
|
||||
|
Total
|
|
|
291
|
|
|
293
|
|
|
(158
|
)
|
|
(179
|
)
|
||||
|
|
|
|
|
|
|
|
|
|
|
||||||||
|
Derivatives not designated as hedging contracts
|
|
|
|
|
|
|
|
|
|
||||||||
|
Energy commodity derivative contracts
|
Other current assets/(Other current liabilities)
|
|
6
|
|
|
4
|
|
|
(9
|
)
|
|
(5
|
)
|
||||
|
Total
|
|
|
6
|
|
|
4
|
|
|
(9
|
)
|
|
(5
|
)
|
||||
|
Total derivatives
|
|
|
$
|
297
|
|
|
$
|
297
|
|
|
$
|
(167
|
)
|
|
$
|
(184
|
)
|
Debt Fair Value Adjustments
The offsetting entry to adjust the carrying value of the debt securities whose fair value was being hedged is included within “Debt fair value adjustments” on our accompanying consolidated balance sheets. Our “Debt fair value adjustments” also include all unamortized debt discount/premium amounts, purchase accounting on our debt balances, and any unamortized portion of proceeds received from the early termination of interest rate swap agreements. As of
March 31, 2014
and
December 31, 2013
, these fair value adjustments to our debt balances included (i)
$629 million
and
$645 million
, respectively, associated with fair value adjustments to our debt previously recorded in purchase accounting; (ii)
$162 million
and
$101 million
, respectively, associated with the offsetting entry for hedged debt; (iii)
$501 million
and
$517 million
, respectively, associated with unamortized premium from the termination of interest rate swap agreements; and offset by (iv)
$57 million
and
$49 million
, respectively, associated with unamortized debt discount amounts. As of
March 31, 2014
, the weighted-average amortization period of the unamortized premium from the termination of the interest rate swaps was approximately
16
years.
18
Effect of Derivative Contracts on the Income Statement
The following three tables summarize the impact of our derivative contracts on our accompanying consolidated statements of income for each of the
three
months ended
March 31, 2014
and
2013
(in millions):
|
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)
|
||||||
|
|
|
|
Three Months Ended
March 31, |
||||||
|
|
|
|
2014
|
|
2013
|
||||
|
Interest rate swap agreements
|
|
Interest expense
|
$
|
61
|
|
|
$
|
(83
|
)
|
|
Total
|
|
|
$
|
61
|
|
|
$
|
(83
|
)
|
|
Fixed rate debt
|
|
Interest expense
|
$
|
(61
|
)
|
|
$
|
83
|
|
|
Total
|
|
|
$
|
(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)
|
||||||||||||||||||
|
|
|
Three Months Ended
March 31, |
|
|
|
Three Months Ended
March 31, |
|
|
|
Three Months Ended
March 31, |
||||||||||||||||||
|
|
|
2014
|
|
2013
|
|
|
|
2014
|
|
2013
|
|
|
|
2014
|
|
2013
|
||||||||||||
|
Energy commodity derivative contracts
|
|
$
|
(56
|
)
|
|
$
|
(41
|
)
|
|
Revenues-Natural gas sales
|
|
$
|
(10
|
)
|
|
$
|
—
|
|
|
Revenues-Natural gas sales
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
Revenues-Product sales and other
|
|
(9
|
)
|
|
7
|
|
|
Revenues-Product sales and other
|
|
(5
|
)
|
|
(3
|
)
|
||||||||
|
|
|
|
|
|
|
Costs of sales
|
|
1
|
|
|
—
|
|
|
Costs of sales
|
|
—
|
|
|
—
|
|
||||||||
|
Total
|
|
$
|
(56
|
)
|
|
$
|
(41
|
)
|
|
Total
|
|
$
|
(18
|
)
|
|
$
|
7
|
|
|
Total
|
|
$
|
(5
|
)
|
|
$
|
(3
|
)
|
____________
|
(a)
|
We expect to reclassify an approximate
$30 million
loss
associated with energy commodity price risk management activities and included in our Partners’ Capital as of
March 31, 2014
into earnings during the next twelve months (when the associated forecasted sales and purchases are also expected to occur); however, actual amounts reclassified into earnings could vary materially as a result of changes in market prices.
|
|
(b)
|
Amounts reclassified were the result of the hedged forecasted transactions actually affecting earnings (i.e., when the forecasted sales and purchases actually occurred).
|
|
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
|
|
Credit Risks
We have counterparty credit risk as a result of our use of financial derivative contracts. Our counterparties consist primarily of financial institutions, major energy companies and local distribution companies. This concentration of
19
counterparties may impact our overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions.
We maintain credit policies with regard to our counterparties that we believe minimize our overall credit risk. These policies include (i) an evaluation of potential counterparties’ financial condition; (ii) collateral requirements under certain circumstances; and (iii) the use of standardized agreements which allow for netting of positive and negative exposure associated with a single counterparty. Based on our policies, exposure, credit and other reserves, our management does not anticipate a material adverse effect on our financial position, results of operations, or cash flows as a result of counterparty performance.
Our OTC swaps and options are entered into with counterparties outside central trading organizations such as futures, options or stock exchanges. These contracts are with a number of parties,
all
of which have investment grade credit ratings. While we enter into derivative transactions with investment grade counterparties and actively monitor their ratings, it is nevertheless possible that from time to time losses will result from counterparty credit risk in the future.
In conjunction with the purchase of exchange-traded derivative contracts or when the market value of our derivative contracts with specific counterparties exceeds established limits, we are required to provide collateral to our counterparties, which may include posting letters of credit or placing cash in margin accounts. As of
both
March 31, 2014
and
December 31, 2013
, we had no outstanding letters of credit supporting our hedging of energy commodity price risks associated with the sale of natural gas, NGL and crude oil.
We also have agreements with certain counterparties to our derivative contracts that contain provisions requiring us to post additional collateral upon a decrease in our credit rating. As of
March 31, 2014
, we estimate that if our credit rating was downgraded
one
notch,
we would be required to post
no
additional collateral to our counterparties. If we were downgraded
two
notches (that is, below investment grade), we would be required to post
$25 million
of additional collateral.
Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income
Cumulative revenues, expenses, gains and losses that under GAAP are included within our comprehensive income but excluded from our earnings are reported as “Accumulated other comprehensive (loss) income” within “Partners’ Capital” in our consolidated balance sheets. Changes in the components of our
“
Accumulated other comprehensive (loss) income” for each of the
three
months ended
March 31, 2014
and
2013
are summarized as follows (in millions):
|
|
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
|
)
|
______________
20
|
|
Net unrealized
gains/(losses)
on cash flow
hedge derivatives
|
|
Foreign
currency
translation
adjustments
|
|
Pension and
other
postretirement
liability adjs.
|
|
Total
Accumulated other
comprehensive
income/(loss)
|
||||||||
|
Balance as of December 31, 2012
|
$
|
66
|
|
|
$
|
132
|
|
|
$
|
(30
|
)
|
|
$
|
168
|
|
|
Other comprehensive (loss) income before reclassifications
|
(40
|
)
|
|
(43
|
)
|
|
1
|
|
|
(82
|
)
|
||||
|
Amounts reclassified from accumulated other comprehensive income
|
(7
|
)
|
|
—
|
|
|
—
|
|
|
(7
|
)
|
||||
|
Net current-period other comprehensive (loss) income
|
(47
|
)
|
|
(43
|
)
|
|
1
|
|
|
(89
|
)
|
||||
|
Balance as of March 31, 2013
|
$
|
19
|
|
|
$
|
89
|
|
|
$
|
(29
|
)
|
|
$
|
79
|
|
6. Fair Value
The fair values of our financial instruments are separated into three broad levels (Levels 1, 2 and 3) based on our assessment of the availability of observable market data and the significance of non-observable data used to determine fair value. Each fair value measurement must be assigned to a level corresponding to the lowest level input that is significant to the fair value measurement in its entirety.
The three broad levels of inputs defined by the fair value hierarchy are as follows:
|
▪
|
Level 1 Inputs—quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date;
|
|
▪
|
Level 2 Inputs—inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. If the asset or liability has a specified (contractual) term, a Level 2 input must be observable for substantially the full term of the asset or liability; and
|
|
▪
|
Level 3 Inputs—unobservable inputs for the asset or liability. These unobservable inputs reflect the entity’s own assumptions about the assumptions that market participants would use in pricing the asset or liability, and are developed based on the best information available in the circumstances (which might include the reporting entity’s own data).
|
Fair Value of Derivative Contracts
The following two tables summarize the fair value measurements of our (i) energy commodity derivative contracts; and (ii) interest rate swap agreements as of
March 31, 2014
and
December 31, 2013
, based on the three levels established by the Codification. Also, certain of our derivative contracts are subject to master netting agreements. The following tables present our derivative contracts subject to such netting agreements as of
March 31, 2014
and
December 31, 2013
(in millions):
|
|
Balance Sheet asset
fair value measurements using
|
|
Amounts not offset in the Balance Sheet
|
|
Net Amount
|
||||||||||||||||||||||
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Gross Amount
|
|
Financial Instruments
|
|
Cash Collateral Held(b)
|
||||||||||||||||
|
As of March 31, 2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
|
Energy commodity derivative contracts(a)
|
$
|
6
|
|
|
$
|
29
|
|
|
$
|
6
|
|
|
$
|
41
|
|
|
$
|
(30
|
)
|
|
$
|
—
|
|
|
$
|
11
|
|
|
Interest rate swap agreements
|
$
|
—
|
|
|
$
|
256
|
|
|
$
|
—
|
|
|
$
|
256
|
|
|
$
|
(44
|
)
|
|
$
|
—
|
|
|
$
|
212
|
|
|
As of December 31, 2013
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
|
Energy commodity derivative contracts(a)
|
$
|
4
|
|
|
$
|
46
|
|
|
$
|
30
|
|
|
$
|
80
|
|
|
$
|
(44
|
)
|
|
$
|
—
|
|
|
$
|
36
|
|
|
Interest rate swap agreements
|
$
|
—
|
|
|
$
|
217
|
|
|
$
|
—
|
|
|
$
|
217
|
|
|
$
|
(28
|
)
|
|
$
|
—
|
|
|
$
|
189
|
|
21
|
|
Balance Sheet liability
fair value measurements using
|
|
Amounts not offset in the Balance Sheet
|
|
Net Amount
|
||||||||||||||||||||||
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Gross Amount
|
|
Financial Instruments
|
|
Cash Collateral Held(c)
|
||||||||||||||||
|
As of March 31, 2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
|
Energy commodity derivative contracts(a)
|
$
|
(14
|
)
|
|
$
|
(50
|
)
|
|
$
|
(9
|
)
|
|
$
|
(73
|
)
|
|
$
|
30
|
|
|
$
|
22
|
|
|
$
|
(21
|
)
|
|
Interest rate swap agreements
|
$
|
—
|
|
|
$
|
(94
|
)
|
|
$
|
—
|
|
|
$
|
(94
|
)
|
|
$
|
44
|
|
|
$
|
—
|
|
|
$
|
(50
|
)
|
|
As of December 31, 2013
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
|
Energy commodity derivative contracts(a)
|
$
|
(6
|
)
|
|
$
|
(31
|
)
|
|
$
|
(31
|
)
|
|
$
|
(68
|
)
|
|
$
|
44
|
|
|
$
|
17
|
|
|
$
|
(7
|
)
|
|
Interest rate swap agreements
|
$
|
—
|
|
|
$
|
(116
|
)
|
|
$
|
—
|
|
|
$
|
(116
|
)
|
|
$
|
28
|
|
|
$
|
—
|
|
|
$
|
(88
|
)
|
____________
|
(a)
|
Level 1 consists primarily of NYMEX natural gas futures. Level 2 consists primarily of OTC WTI swaps. Level 3 consists primarily of WTI options, WTI basis swaps, NGL options and NGL swaps.
|
|
(b)
|
Cash margin deposits held by us associated with our energy commodity contract positions and OTC swap agreements and reported within “Other current liabilities” on our accompanying consolidated balance sheets.
|
|
(c)
|
Cash margin deposits posted by us associated with our energy commodity contract positions and OTC swap agreements and reported within “Other current assets” on our accompanying consolidated balance sheets.
|
The table below provides a summary of changes in the fair value of our Level 3 energy commodity derivative contracts for each of the
three
months ended
March 31, 2014
and
2013
(in millions):
|
Significant unobservable inputs (Level 3)
|
|||||||
|
|
Three Months Ended
March 31, |
||||||
|
|
2014
|
|
2013
|
||||
|
Derivatives-net asset (liability)
|
|
|
|
||||
|
Beginning of Period
|
$
|
(1
|
)
|
|
$
|
3
|
|
|
Total gains or (losses):
|
|
|
|
||||
|
Included in earnings
|
1
|
|
|
6
|
|
||
|
Included in other comprehensive income
|
(1
|
)
|
|
(1
|
)
|
||
|
Settlements
|
(2
|
)
|
|
(5
|
)
|
||
|
End of Period
|
$
|
(3
|
)
|
|
$
|
3
|
|
|
The amount of total gains or (losses) for the period included in earnings attributable to the change in unrealized gains or (losses) relating to assets held at the reporting date
|
$
|
3
|
|
|
$
|
—
|
|
As of
March 31, 2014
, our Level 3 derivative assets and liabilities consisted primarily of WTI options, WTI basis swaps, NGL options and NGL swaps, where a significant portion of fair value is calculated from underlying market data that is not readily observable. The derived values use industry standard methodologies that may consider the historical relationships among various commodities, modeled market prices, time value, volatility factors and other relevant economic measures. The use of these inputs results in our management’s best estimate of fair value.
Fair Value of Financial Instruments
The estimated fair value of our outstanding debt balance as of
March 31, 2014
and
December 31, 2013
(both short-term and long-term and including debt fair value adjustments), is disclosed below (in millions):
|
|
March 31, 2014
|
|
December 31, 2013
|
||||||||||||
|
|
Carrying
Value
|
|
Estimated
Fair value
|
|
Carrying
Value
|
|
Estimated
Fair value
|
||||||||
|
Total debt
|
$
|
22,088
|
|
|
$
|
22,935
|
|
|
$
|
21,128
|
|
|
$
|
21,550
|
|
We used Level 2 input values to measure the estimated fair value of our outstanding debt balance as of both
March 31, 2014
and
December 31, 2013
.
22
7. Reportable Segments
We operate in
five
reportable business segments. These segments and their principal sources of revenues are as follows:
|
▪
|
Natural Gas Pipelines—the sale, transport, processing, treating, fractionation, storage and gathering of natural gas and NGL;
|
|
▪
|
CO
2
—the production, sale and transportation of crude oil from fields in the Permian Basin of West Texas and the production, transportation and marketing of CO
2
used as a flooding medium for recovering crude oil from mature oil fields;
|
|
▪
|
Products Pipelines—the transportation and terminaling of refined petroleum products (including gasoline, diesel fuel and jet fuel), NGL, crude oil and condensate, and bio-fuels;
|
|
▪
|
Terminals—the transportation, transloading and storing of refined petroleum products, crude oil, and dry and liquid bulk products, including coal, petroleum coke, cement, alumina, salt and other bulk chemicals; and
|
|
▪
|
Kinder Morgan Canada—the transportation of crude oil and refined products from Alberta, Canada to marketing terminals and refineries in British Columbia and the State of Washington. As further described in Note 3, Kinder Morgan Canada divested its interest in the Express pipeline system effective March 14, 2013.
|
We evaluate performance principally based on each segment’s EBDA (including amortization of excess cost of equity investments), which excludes general and administrative expenses, third party debt costs and interest expense, unallocable interest income, and unallocable income tax expense. Our reportable segments are strategic business units that offer different products and services, and they are structured based on how our chief operating decision makers organize their operations for optimal performance and resource allocation. Each segment is managed separately because each segment involves different products and marketing strategies. Financial information by segment follows (in millions):
|
|
Three Months Ended
March 31, |
||||||
|
|
2014
|
|
2013
|
||||
|
Revenues
|
|
|
|
||||
|
Natural Gas Pipelines
|
|
|
|
||||
|
Revenues from external customers
|
$
|
2,175
|
|
|
$
|
1,369
|
|
|
Intersegment revenues
|
1
|
|
|
—
|
|
||
|
CO
2
|
483
|
|
|
429
|
|
||
|
Products Pipelines
|
534
|
|
|
454
|
|
||
|
Terminals
|
391
|
|
|
337
|
|
||
|
Kinder Morgan Canada
|
69
|
|
|
72
|
|
||
|
Total segment revenues
|
3,653
|
|
|
2,661
|
|
||
|
Less: Total intersegment revenues
|
(1
|
)
|
|
—
|
|
||
|
Total consolidated revenues
|
$
|
3,652
|
|
|
$
|
2,661
|
|
23
|
|
Three Months Ended
March 31, |
||||||
|
|
2014
|
|
2013
|
||||
|
Segment earnings before depreciation, depletion, amortization and amortization of excess cost of equity investments(a)
|
|
|
|
||||
|
Natural Gas Pipelines
|
$
|
719
|
|
|
$
|
557
|
|
|
CO
2
|
363
|
|
|
342
|
|
||
|
Products Pipelines
|
208
|
|
|
185
|
|
||
|
Terminals
|
214
|
|
|
186
|
|
||
|
Kinder Morgan Canada(b)
|
48
|
|
|
193
|
|
||
|
Segment EBDA
|
1,552
|
|
|
1,463
|
|
||
|
Total segment DD&A expense
|
(401
|
)
|
|
(328
|
)
|
||
|
Total segment amortization of excess cost of investments
|
(3
|
)
|
|
(2
|
)
|
||
|
General and administrative expense
|
(153
|
)
|
|
(134
|
)
|
||
|
Interest expense, net of unallocable interest income
|
(239
|
)
|
|
(202
|
)
|
||
|
Unallocable income tax expense
|
(2
|
)
|
|
(3
|
)
|
||
|
Loss from discontinued operations
|
—
|
|
|
(2
|
)
|
||
|
Total consolidated net income
|
$
|
754
|
|
|
$
|
792
|
|
|
|
March 31,
2014 |
|
December 31,
2013 |
||||
|
Assets
|
|
|
|
||||
|
Natural Gas Pipelines
|
$
|
25,517
|
|
|
$
|
25,721
|
|
|
CO
2
|
2,996
|
|
|
2,954
|
|
||
|
Products Pipelines
|
5,650
|
|
|
5,488
|
|
||
|
Terminals
|
7,183
|
|
|
6,124
|
|
||
|
Kinder Morgan Canada
|
1,622
|
|
|
1,678
|
|
||
|
Total segment assets
|
42,968
|
|
|
41,965
|
|
||
|
Corporate assets(c)
|
990
|
|
|
799
|
|
||
|
Total consolidated assets
|
$
|
43,958
|
|
|
$
|
42,764
|
|
____________
|
(a)
|
Includes revenues, earnings from equity investments, allocable interest income, and other, net, less operating expenses, allocable income taxes, and other income, net. Operating expenses include natural gas purchases and other costs of sales, operations and maintenance expenses, and taxes, other than income taxes.
|
|
(b)
|
2013 amount includes a
$141 million
increase in earnings from the after-tax
gain on the sale of our investments in the Express pipeline system.
|
|
(c)
|
Includes cash and cash equivalents; margin and restricted deposits; unallocable interest receivable, prepaid assets and deferred charges; and risk management assets related to debt fair value adjustments.
|
8. Related Party Transactions
From time to time in the ordinary course of business, we buy and sell assets and related services from KMI and its subsidiaries. Such transactions are conducted in accordance with all applicable laws and regulations and on an arms’ length basis consistent with our policies governing such transactions. In conjunction with our acquisition of (i) certain Natural Gas Pipelines assets and partnership interests from KMI in December 1999 and December 2000; (ii) TransColorado Gas Transmission Company LLC from KMI in November 2004; (iii) TGP and
50%
of EPNG from KMI in August 2012; and (iv) the remaining
50%
ownership interest in EPNG and the EP midstream assets from KMI in March 2013, KMI has agreed to indemnify us and our general partner with respect to approximately
$5.9 billion
of our debt as of
March 31, 2014
. KMI would be obligated to perform under this indemnity only if we are unable, and/or our assets were insufficient, to satisfy our obligations.
24
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
The tariffs and rates charged by SFPP and 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 million
in annual rate reductions and approximately
$100 million
in refunds. However, applying the principles of several recent FERC decisions in SFPP cases, as applicable, to 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) in May 2012. EPNG implemented certain aspects of that decision and believes it has an appropriate reserve related to the findings in Opinion 517. EPNG has sought rehearing on Opinion 517. With respect to the 2010 rate case, the FERC issued 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 Opinion 528. EPNG has filed for rehearing on certain issues in Opinion 528. We have evaluated all recent decisions and believe our reserve is 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
25
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 denied SFPP’s petition, and on 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 pending before the CPUC, with a decision expected in the 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
$400 million
in reparation payments and approximately
$30 million
in annual rate reductions. The actual amount of reparations will be determined through settlement negotiations or further proceedings at the CPUC. As of
March 31, 2014
, we believe our legal reserve is adequate such that the resolution of pending CPUC matters will not have a material adverse impact on our business, financial position or results of operations. Furthermore, we do not expect any reparations that we would pay in this matter to impact the per unit cash distributions we expect to pay to our limited partners for 2014.
Other Commercial Matters
Union Pacific Railroad Company Easements
SFPP and 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
$14 million
, subject to annual consumer price index increases. Judgment was entered by the Court on May 29, 2012 and SFPP appealed the judgment. If the judgment is upheld on appeal, SFPP would owe approximately
$93 million
in back rent. Accordingly, we have increased our rights-of-way liability to cover this potential liability for back rent. In addition, the judge determined that UPRR is entitled to 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 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.
26
SFPP and UPRR are also engaged in multiple disputes over the circumstances under which SFPP must pay for a relocation of its pipeline within the UPRR right-of-way and the safety standards that govern relocations. In July 2006, a trial before a judge regarding the circumstances under which SFPP must pay for relocations concluded, and the judge determined that SFPP must pay for any relocations resulting from any legitimate business purpose of the UPRR. SFPP 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 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 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 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 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 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 March 6, 2014, the Court issued findings of fact and conclusions of law and entered judgment against KMBT in the 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 sale by TGP of the 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 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.
27
General
As of
March 31, 2014
and
December 31, 2013
, our total reserve for legal matters was
$655 million
and
$611 million
, respectively. The reserve primarily relates to various claims from regulatory proceedings arising from our products pipeline and natural gas pipeline transportation rates.
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 Court of Chancery in 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 dismiss is decided in the suit filed by Jon Slotoroff described above.
Environmental Matters
We are subject to environmental cleanup and enforcement actions from time to time. In particular, CERCLA generally imposes joint and several liability for cleanup and enforcement costs on current and predecessor owners and operators of a site, among others, without regard to fault or the legality of the original conduct, subject to the right of a liable party to establish a “reasonable basis” for apportionment of costs. Our operations are also subject to federal, state and local laws and regulations relating to protection of the environment. Although we believe our operations are in substantial compliance with applicable environmental law and regulations, risks of additional costs and liabilities are
28
inherent in pipeline, terminal and CO
2
field and oil field operations, and there can be no assurance that we will not incur significant costs and liabilities. Moreover, it is possible that other developments, such as increasingly stringent environmental laws, regulations and enforcement policies under the terms of authority of those laws, and claims for damages to property or persons resulting from our operations, could result in substantial costs and liabilities to us.
We are currently involved in several governmental proceedings involving alleged violations of environmental and safety regulations. As we receive notices of non-compliance, we attempt to negotiate and settle such matters where appropriate. 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, NGL, natural gas and CO
2
.
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 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. asserted claims for contribution against approximately
300
third party defendants. NJDEP claimed damages related to
40 years
of discharges of TCDD (a form of dioxin), DDT and “other hazardous substances.” GATX Terminals Corporation (n/k/a Kinder Morgan Liquids Terminals LLC) (KMLT) was 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. KMLT, as part of a joint defense group, entered a settlement agreement (the Consent Judgment) with the NJDEP whereby the settling parties for a prescribed payment obtained a contribution bar against first party defendants Occidental, Maxus Energy Corp. (Maxus) and Tierra Solutions, Inc. (Tierra) in addition to a release of claims. The Consent Judgment was published in the New Jersey Register for a 60-day comment period and no significant comments were received. Additionally, the NJDEP reached a settlement agreement with Maxus and Tierra. Occidental is not part of the settlement. On December 12, 2013, the Court approved the settlements. Pursuant to the Consent Judgment, KMLT submitted its settlement payment by the January 27, 2014 deadline and received the Court’s order dismissing KMLT from the litigation.
Portland Harbor Superfund Site, Willamette River, Portland, Oregon
In December 2000, the 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-voting member and pays a minimal fee to be part of the group. The LWG agreed to conduct the remedial investigation and feasibility study (RI/FS) leading to the proposed remedy for cleanup of the Portland Harbor site. Once the 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 2015. We also expect the LWG to complete the RI/FS process in 2015, after which the EPA 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.
29
Roosevelt Irrigation District v. Kinder Morgan G.P., Inc., Kinder Morgan Energy Partners, L.P. , U.S. District Court, Arizona
The Roosevelt Irrigation District sued 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 monetary damages in unspecified amounts and reducing the number of defendants to
26
including KMEP and SFPP. The claims now presented against KMEP and SFPP are related to alleged releases from a specific parcel within the SFPP Phoenix Terminal and the alleged impact of such releases on water wells owned by the plaintiffs and located in the vicinity of the Terminal. On October 24, 2013, we moved to dismiss 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 was 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. On April 9, 2013, KMLT and the Port of Los Angeles entered into a settlement agreement, the terms of which provide for the dismissal of the litigation by the Port and KMLT’s agreement to pay
60%
of the Port’s costs to remediate the former terminal site up to a
$15 million
cap. Further, according to terms of the settlement agreement, we received a
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.
The City of Los Angeles, KMLT, Chevron and Phillips 66 remain named on a 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 first quarter of 2014.
Paulsboro, New Jersey 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, 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 terminal is now owned by Plains Products, which was also joined as a party to the lawsuit.
In mid-2011, KMLT and Plains Products entered into a settlement agreement and subsequent Consent Judgment with the NJDEP which resolved the state’s alleged natural resource damages claim. The natural resource damage settlement includes a monetary award of
$1 million
and a series of remediation and restoration activities at the terminal site. KMLT and Plains Products have joint responsibility for this settlement. Simultaneously, KMLT and Plains Products entered into 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.
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 U.S. District Court, Southern District of California, case number 07CV1883WCAB. The City disclosed in discovery that it is seeking approximately
$170 million
in damages for alleged lost value/lost profit from the redevelopment of the City’s property and alleged lost use of the water resources underlying the property. Later,
30
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
.
On November 29, 2012, the Court issued a Notice of Tentative Rulings on the parties’ summary adjudication motions. The Court 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 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 (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
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 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 EPA notifying EPNG of the 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 August 2013, EPNG and the EPA entered into an Administrative Order on Consent and Scope of Work, pursuant to which EPNG will conduct a radiological assessment of the surface of the mines. We are also seeking contribution from the applicable federal government agencies toward the cost of environmental activities associated with the mines, given 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.
31
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. As of
March 31, 2014
and
December 31, 2013
, our total reserve for environmental liabilities was
$164 million
and
$168 million
, respectively.
10. Recent Accounting Pronouncements
Accounting Standards Updates
None of the Accounting Standards Updates (ASU) that we adopted and that became effective January 1, 2014 (including ASU No. 2013-05, “Parent’s Accounting for the Cumulative Translation Adjustment upon Derecognition of Certain Subsidiaries or Groups of Assets within a Foreign Entity or of an Investment in a Foreign Entity (a consensus of the FASB Emerging Issues Task Force)) had a material impact on our consolidated financial statements. More information about this ASU can be found in Note 17
“
Recent Accounting Pronouncements” to our consolidated financial statements that were included in our
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.
32
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
|
|
33
|
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
|
|
34
|
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
|
|
35
|
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
|
|
36
|
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
|
|
37
|
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
2013
Form 10-K; and (iii) our management’s discussion and analysis of financial condition and results of operations included in our
2013
Form 10-K.
We prepared our consolidated financial statements in accordance with GAAP. In addition, as discussed in Note 1
“
General” and Note 2
“
Acquisitions and Divestitures” to our consolidated financial statements, our financial statements reflect our March 2013 drop-down transaction as if such acquisition had taken place on the effective dates of common 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
38
and Results of Operations includes the financial results of the March 2013 drop-down asset group for all periods subsequent to the effective dates of common control.
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 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, 2013. Our goodwill impairment analysis performed as 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 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” in our
2013
Form 10-K.
Results of Operations
Non-GAAP Measures
The non-GAAP financial measures of (i) DCF before certain items, both in the aggregate and per unit, and (ii) segment earnings before DD&A; amortization of excess cost of equity investments; and certain items, are presented below
under “—Distributable Cash Flow” and “—Consolidated Earnings Results,” respectively. Certain items are items that are required by GAAP to 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 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 defined differently by different companies in our industry, our DCF before certain items may not be comparable to 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 its analysis and its decision making processes.
Distributable Cash Flow
As more fully described in our
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
39
generally consists of all our cash receipts, less cash disbursements and changes in reserves). For more information about our available cash and partnership distributions, see Note 11 “Related Party Transactions—Partnership Interests and Distributions” to 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 months ended March 31, 2014 and 2013 (calculated before the combined effect from all of the 2014 and 2013 certain items disclosed in the footnotes to the tables below):
|
Distributable Cash Flow
|
|||||||
|
|
Three Months Ended
March 31, |
||||||
|
|
2014
|
|
2013
|
||||
|
|
|
||||||
|
Net Income
|
$
|
754
|
|
|
$
|
792
|
|
|
Add/(Less): Certain items - combined expense/(income)(a)
|
34
|
|
|
(137
|
)
|
||
|
Net Income before certain items
|
788
|
|
|
655
|
|
||
|
Less: Net Income before certain items attributable to noncontrolling interests
|
(8
|
)
|
|
(7
|
)
|
||
|
Net Income before certain items attributable to KMEP
|
780
|
|
|
648
|
|
||
|
Less: General Partner’s interest in Net Income before certain items(b)
|
(453
|
)
|
|
(401
|
)
|
||
|
Limited Partners’ interest in Net Income before certain items
|
327
|
|
|
247
|
|
||
|
Depreciation, depletion and amortization(c)(e)
|
426
|
|
|
338
|
|
||
|
Book (cash) taxes paid, net
|
17
|
|
|
12
|
|
||
|
Incremental contributions from equity investments in the Express Pipeline and Endeavor Gathering LLC
|
(5
|
)
|
|
1
|
|
||
|
Sustaining capital expenditures(d)(e)
|
(72
|
)
|
|
(48
|
)
|
||
|
Distributable cash flow before certain items
|
$
|
693
|
|
|
$
|
550
|
|
____________
|
(a)
|
Equal to the combined income (expense) effect from all of the
2014
and
2013
certain items disclosed in the footnotes to the “—Results of Operations” table included below (and described in more detail below in both our management’s discussion and analysis of segment results and “—Other”).
|
|
(b)
|
2014
amount includes both a
$30 million
reduction for waived general partner incentive amounts related to common units issued to finance our May 2013 Copano acquisition, and a
$3 million
reduction for waived general partner incentive amounts related to common units issued to finance a portion of our January 2014 APT acquisition. 2013 amount includes a
$4 million
reduction for waived general partner incentive amounts related to common units issued to finance a portion of our July 2011 KinderHawk acquisition.
|
|
(c)
|
2014
and 2013 amounts include expense amounts of
$22 million
and
$27 million
, respectively, for our proportionate share of the DD&A expenses of our unconsolidated joint ventures. 2013 amount also excludes a
$19 million
expense amount attributable to our March 2013 drop-down asset group for periods prior to our acquisition.
|
|
(d)
|
2014 amount includes expenditures of
$1 million
for our proportionate share of the sustaining capital expenditures of certain unconsolidated joint ventures.
|
|
(e)
|
In order to more closely track the cash distributions we receive from our unconsolidated joint ventures, our calculation of DCF (i) adds back our proportionate share of the DD&A expenses of certain joint ventures; and (ii) subtracts our proportionate share of the sustaining expenditures of the corresponding joint ventures (i.e. the same equity investees for which we add back DD&A as discussed in footnote (c)).
|
Consolidated Earnings Results
With regard to our reportable business segments, we consider segment earnings before all DD&A expenses, and amortization of excess cost of equity investments, to be an important measure of our success in maximizing returns to our partners. This measure, sometimes referred to in this report as segment EBDA, is more fully defined in footnote (a) to the
“
—Results of Operations” table below. We also use segment EBDA internally as a measure of profit and loss used for evaluating segment performance and for deciding how to allocate resources to our five reportable business segments. EBDA may not be comparable to measures used by other companies. Additionally, EBDA should be
40
considered in conjunction with net income and other performance measures such as operating income, income from continuing operations or operating cash flows.
|
Results of Operations
|
||||||||||||||
|
|
Three Months Ended
March 31, |
|
Earnings
increase/(decrease)
|
|||||||||||
|
|
2014
|
|
2013
|
|
||||||||||
|
|
(In millions, except percentages)
|
|||||||||||||
|
Segment EBDA(a)
|
|
|
|
|
|
|
|
|||||||
|
Natural Gas Pipelines
|
$
|
719
|
|
|
$
|
557
|
|
|
$
|
162
|
|
|
29
|
%
|
|
CO
2
|
363
|
|
|
342
|
|
|
21
|
|
|
6
|
%
|
|||
|
Products Pipelines
|
208
|
|
|
185
|
|
|
23
|
|
|
12
|
%
|
|||
|
Terminals
|
214
|
|
|
186
|
|
|
28
|
|
|
15
|
%
|
|||
|
Kinder Morgan Canada
|
48
|
|
|
193
|
|
|
(145
|
)
|
|
(75
|
)%
|
|||
|
Segment EBDA(b)
|
1,552
|
|
|
1,463
|
|
|
89
|
|
|
6
|
%
|
|||
|
DD&A expense(c)
|
(401
|
)
|
|
(328
|
)
|
|
(73
|
)
|
|
(22
|
)%
|
|||
|
Amortization of excess cost of equity investments
|
(3
|
)
|
|
(2
|
)
|
|
(1
|
)
|
|
(50
|
)%
|
|||
|
General and administrative expense(d)
|
(153
|
)
|
|
(134
|
)
|
|
(19
|
)
|
|
(14
|
)%
|
|||
|
Interest expense, net of unallocable interest income(e)
|
(239
|
)
|
|
(202
|
)
|
|
(37
|
)
|
|
(18
|
)%
|
|||
|
Unallocable income tax expense
|
(2
|
)
|
|
(3
|
)
|
|
1
|
|
|
33
|
%
|
|||
|
Income from continuing operations
|
754
|
|
|
794
|
|
|
(40
|
)
|
|
(5
|
)%
|
|||
|
Loss from discontinued operations
|
—
|
|
|
(2
|
)
|
|
2
|
|
|
100
|
%
|
|||
|
Net Income
|
754
|
|
|
792
|
|
|
(38
|
)
|
|
(5
|
)%
|
|||
|
Net Income attributable to noncontrolling interests(f)
|
(8
|
)
|
|
(9
|
)
|
|
1
|
|
|
11
|
%
|
|||
|
Net Income attributable to KMEP
|
$
|
746
|
|
|
$
|
783
|
|
|
$
|
(37
|
)
|
|
(5
|
)%
|
____________
|
(a)
|
Includes revenues, earnings from equity investments, allocable interest income and other, net, less operating expenses, allocable income taxes, and other income, net. Operating expenses include natural gas purchases and other costs of sales, operations and maintenance expenses, and taxes, other than income taxes.
|
|
(b)
|
2014
and
2013
amounts include a decrease in earnings of $17 million and an increase in earnings of $187 million, respectively, related to the combined effect from all of the
2014
and
2013
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 March 2013 drop-down asset group for periods prior to our March 1, 2013 acquisition date.
|
|
(d)
|
2014
and
2013
amounts include increases in expense of
$6 million and $14 million, respectively, related to the combined effect from all of the
2014
and
2013
certain items related to general and administrative expenses disclosed below in “—Other.”
|
|
(e)
|
2014
amount includes an $11 million increase in expense related to the combined effect from all of the
2014
certain items related to interest expense, net of unallocable interest income disclosed below in “—Other.”
2013
amount includes a $15 million increase in expense attributable to our March 2013 drop-down asset group for periods prior to our March 1, 2013 acquisition date.
|
|
(f)
|
2014 amount includes a $2 million increase in net income attributable to our noncontrolling interests, related to the combined effect from all of the 2014 certain items disclosed below in both our management’s discussion and analysis of segment results and “—Other.”
|
The certain items described in footnote (b) to the table above accounted for a
$204 million decrease in EBDA in the first quarter of
2014
, when compared to the same prior year period. After taking into effect these certain items, the remaining $293 million (23%) quarter-to-quarter increase in EBDA was largely driven by better performance in the first quarter of
2014
from our Natural Gas Pipelines, Terminals and CO
2
business segments.
41
Natural Gas Pipelines
|
|
Three Months Ended
March 31, |
||||||
|
|
2014
|
|
2013
|
||||
|
|
(In millions, except operating statistics)
|
||||||
|
Revenues(a)
|
$
|
2,176
|
|
|
$
|
1,369
|
|
|
Operating expenses(b)
|
(1,501
|
)
|
|
(860
|
)
|
||
|
Other income
|
4
|
|
|
—
|
|
||
|
Earnings from equity investments(c)
|
43
|
|
|
48
|
|
||
|
Interest income and Other, net
|
—
|
|
|
1
|
|
||
|
Income tax expense
|
(3
|
)
|
|
(1
|
)
|
||
|
EBDA from continuing operations
|
719
|
|
|
557
|
|
||
|
Discontinued operations
|
—
|
|
|
(2
|
)
|
||
|
Certain items, net(a)(b)(c)
|
4
|
|
|
(58
|
)
|
||
|
EBDA before certain items
|
$
|
723
|
|
|
$
|
497
|
|
|
|
|
|
|
||||
|
Change from prior period
|
Increase/(Decrease)
|
||||||
|
Revenues before certain items(a)
|
$
|
922
|
|
|
67
|
%
|
|
|
EBDA before certain items
|
$
|
226
|
|
|
45
|
%
|
|
|
|
|
|
|
||||
|
Natural gas transport volumes (BBtu/d)(d)
|
17,938.2
|
|
|
17,073.4
|
|
||
|
Natural gas sales volumes (BBtu/d)(e)
|
2,254.0
|
|
|
2,357.0
|
|
||
|
Natural gas gathering volumes (BBtu/d)(f)
|
2,871.3
|
|
|
2,889.3
|
|
||
____________
|
(a)
|
2014
amount includes a decrease in revenues of $4 million related to derivative contracts used to hedge forecasted natural gas, NGL and crude oil sales.
2013
amount includes an increase in revenues of $111 million attributable to our March 2013 drop-down asset group for periods prior to our March 1, 2013 acquisition date.
|
|
(b)
|
2013
amount includes an increase in expense of $30 million attributable to our March 2013 drop-down asset group for periods prior to our March 1, 2013 acquisition date, and an increase in expense of $1 million related to hurricane clean-up and repair activities.
|
|
(c)
|
2013
amount includes a decrease in earnings of $19 million attributable to our March 2013 drop-down asset group for periods prior to our March 1, 2013 acquisition date, and a decrease of $1 million from incremental severance expenses.
|
|
(d)
|
Includes pipeline volumes for TransColorado Gas Transmission Company LLC, Midcontinent Express Pipeline LLC, Kinder Morgan Louisiana Pipeline LLC, Fayetteville Express Pipeline LLC, TGP, EPNG, Copano South Texas and the Texas intrastate natural gas pipeline group. Volumes for acquired pipelines are included for all periods.
|
|
(e)
|
Represents volumes for the Texas intrastate natural gas pipeline group.
|
|
(f)
|
Includes Copano operations, EP midstream assets operations, KinderHawk, Endeavor, Eagle Ford, and Red Cedar Gathering Company throughput volumes. Joint venture throughput is reported at our ownership share. Volumes for acquired pipelines are included for all periods.
|
42
Following is information related to the increases and decreases, in the comparable three month periods of
2014
and
2013
:
____________
n/a – not applicable
|
(a)
|
Equity investment until May 1, 2013. On that date, as part of our Copano acquisition, we acquired the remaining 50% ownership interest that we did not already own. Prior to that date, we recorded earnings under the equity method of accounting, but we received distributions in amounts essentially equal to equity earnings plus our share of depreciation and amortization expenses less our share of sustaining capital expenditures.
|
The primary increases and decreases in our Natural Gas Pipelines business segment’s EBDA in the first quarter of 2014 compared to the first quarter of 2013 were attributable to the following:
|
▪
|
incremental earnings of $80 million from our Copano operations, which we acquired effective May 1, 2013 (but excluding Copano’s 50% ownership interest in Eagle Ford, which is included below with the 50% ownership interest we previously owned);
|
|
▪
|
incremental earnings of $56 million from EPNG, due largely to our acquisition of the remaining 50% interest we did not already own from KMI effective March 1, 2013;
|
|
▪
|
a $35 million (16%) increase from TGP, primarily due to higher revenues from (i) firm transportation and storage due largely to new projects placed in service since the end of the first quarter of 2013; (ii) usage and interruptible transportation services, due to both weather-related increases and higher short-haul volumes; and (iii) natural gas park and loan customer services, due also primarily to colder winter weather relative to the first quarter of 2013;
|
|
▪
|
incremental earnings of $24 million from our total (100%) Eagle Ford natural gas gathering operations, due mainly to the incremental 50% ownership interest we acquired as part of our acquisition of Copano effective May 1, 2013, and to higher natural gas gathering volumes from the Eagle Ford shale formation;
|
|
▪
|
a $19 million (21%) increase from our Texas intrastate natural gas pipeline group, due largely to higher natural gas sales, transportation, and storage margins, all driven in part by colder weather in the first quarter of 2014; and
|
|
▪
|
incremental earnings of $12 million from our EP midstream assets, due largely to our acquisition from KMI effective March 1, 2013 of the remaining 50% interest we did not already own.
|
43
CO
2
|
|
Three Months Ended
March 31, |
||||||
|
|
2014
|
|
2013
|
||||
|
|
(In millions, except operating statistics)
|
||||||
|
Revenues(a)
|
$
|
483
|
|
|
$
|
429
|
|
|
Operating expenses
|
(125
|
)
|
|
(92
|
)
|
||
|
Earnings from equity investments
|
7
|
|
|
6
|
|
||
|
Income tax expense
|
(2
|
)
|
|
(1
|
)
|
||
|
EBDA
|
363
|
|
|
342
|
|
||
|
Certain items(a)
|
3
|
|
|
(2
|
)
|
||
|
EBDA before certain items
|
$
|
366
|
|
|
$
|
340
|
|
|
|
|
|
|
||||
|
Change from prior period
|
Increase/(Decrease)
|
||||||
|
Revenues before certain items(a)
|
$
|
59
|
|
|
14
|
%
|
|
|
EBDA before certain items
|
$
|
26
|
|
|
8
|
%
|
|
|
|
|
|
|
||||
|
Southwest Colorado CO
2
production (gross) (Bcf/d)(b)
|
1.3
|
|
|
1.2
|
|
||
|
Southwest Colorado CO
2
production (net) (Bcf/d)(b)
|
0.6
|
|
|
0.5
|
|
||
|
SACROC oil production (gross)(MBbl/d)(c)
|
31.8
|
|
|
30.7
|
|
||
|
SACROC oil production (net)(MBbl/d)(d)
|
26.4
|
|
|
25.6
|
|
||
|
Yates oil production (gross)(MBbl/d)(c)
|
19.6
|
|
|
20.5
|
|
||
|
Yates oil production (net)(MBbl/d)(d)
|
8.7
|
|
|
9.1
|
|
||
|
Katz oil production (gross)(MBbl/d)(c)
|
3.5
|
|
|
2.1
|
|
||
|
Katz oil production (net)(MBbl/d)(d)
|
2.9
|
|
|
1.7
|
|
||
|
Goldsmith oil production (gross)(MBbl/d)(c)
|
1.2
|
|
|
n/a
|
|
||
|
Goldsmith oil production (net)(MBbl/d)(d)
|
1.0
|
|
|
n/a
|
|
||
|
NGL sales volumes (net)(MBbl/d)(d)
|
9.9
|
|
|
10.3
|
|
||
|
Realized weighted average oil price per Bbl(e)
|
$
|
91.89
|
|
|
$
|
86.85
|
|
|
Realized weighted average NGL price per Bbl(f)
|
$
|
49.44
|
|
|
$
|
46.48
|
|
____________
n/a – not applicable
|
(a)
|
2014
and
2013
amounts include unrealized losses of $3 million and unrealized gains of $2 million, respectively, all relating to derivative contracts used to hedge forecasted crude oil sales.
|
|
(b)
|
Includes McElmo Dome and Doe Canyon sales volumes.
|
|
(c)
|
Represents 100% of the production from the field. We own an approximately 97% working interest in the SACROC unit, an approximately 50% working interest in the Yates unit, an approximately 99% working interest in the Katz Strawn unit and a 100% working interest in the Goldsmith Landreth unit.
|
|
(d)
|
Net to us, after royalties and outside working interests.
|
|
(e)
|
Includes all of our crude oil production properties.
|
|
(f)
|
Includes production attributable to leasehold ownership and production attributable to our ownership in processing plants and third party processing agreements.
|
Our CO
2
segment’s primary businesses involve the production, marketing and transportation of both CO
2
and crude oil, and the production and marketing of natural gas and NGL.
We refer to the segment’s two primary businesses as its Oil and Gas Producing Activities and its Sales and Transportation Activities.
44
For each of the segment’s two primary businesses, following is information related to the increases and decreases, in the comparable three month periods of
2014
and
2013
:
The quarter-to-quarter increase in EBDA from the segment’s sales and transportation activities was primarily revenue related, largely attributable to the following:
|
▪
|
a $24 million (34%) increase in CO
2
sales revenues driven by
an 18% increase in average sales prices. The increase in sales prices was due primarily to two factors: (i) a change in the mix of contracts resulting in more CO
2
being delivered under higher price contracts; and (ii) heavier weighting of new CO
2
contract prices to the price of crude oil. CO
2
sales volumes were also higher by 14% in the first quarter of 2014 versus the first quarter of 2013.
|
The quarter-to-quarter increase in EBDA from oil and gas producing activities, which include the operations associated with the segment’s ownership interests in oil-producing fields and natural gas processing plants, was largely due to the following:
|
▪
|
a $37 million (13%) increase from higher crude oil sales revenues, due primarily to 6% increase in our realized weighted average price per barrel of crude oil, and partly due to higher oil sales volumes. Overall crude oil sales volumes increased 7% in the first quarter of 2014, when compared to the first quarter last year. The increase in sales volumes was due primarily to higher production at the Katz field unit, incremental production from the Goldsmith Landreth unit (acquired effective June 1, 2013), and higher production at the SACROC unit (volumes presented in the results of operations table above). The increase in revenue was partially offset by an increase in power costs that was due to higher gas and water volumes and market pricing. In addition, operating costs increased due to higher property taxes and severance taxes related to the increase in revenue. Incremental well work-over costs at our recently acquired Goldsmith property also contributed to an increase in operating expenses.
|
45
Products Pipelines
|
|
Three Months Ended
March 31, |
||||||
|
|
2014
|
|
2013
|
||||
|
|
(In millions, except operating statistics)
|
||||||
|
Revenues
|
$
|
534
|
|
|
$
|
454
|
|
|
Operating expenses(a)
|
(339
|
)
|
|
(281
|
)
|
||
|
Other income(b)
|
3
|
|
|
—
|
|
||
|
Earnings from equity investments
|
17
|
|
|
18
|
|
||
|
Interest income and Other, net
|
(1
|
)
|
|
—
|
|
||
|
Income tax expense
|
(6
|
)
|
|
(6
|
)
|
||
|
EBDA
|
208
|
|
|
185
|
|
||
|
Certain items, net(a)(b)
|
(4
|
)
|
|
15
|
|
||
|
EBDA before certain items
|
$
|
204
|
|
|
$
|
200
|
|
|
|
|
|
|
||||
|
Change from prior period
|
Increase/(Decrease)
|
||||||
|
Revenues
|
$
|
80
|
|
|
18
|
%
|
|
|
EBDA before certain items
|
$
|
4
|
|
|
2
|
%
|
|
|
|
|
|
|
||||
|
Gasoline (MMBbl)(c)
|
103.0
|
|
|
97.8
|
|
||
|
Diesel fuel (MMBbl)
|
35.6
|
|
|
32.8
|
|
||
|
Jet fuel (MMBbl)
|
27.4
|
|
|
27.2
|
|
||
|
Total refined product volumes (MMBbl)(d)
|
166.0
|
|
|
157.8
|
|
||
|
NGL (MMBbl)(e)
|
8.8
|
|
|
9.8
|
|
||
|
Condensate (MMBbl)(f)
|
4.6
|
|
|
2.0
|
|
||
|
Total delivery volumes (MMBbl)
|
179.4
|
|
|
169.6
|
|
||
|
Ethanol (MMBbl)(g)
|
9.7
|
|
|
8.7
|
|
||
___________
|
(a)
|
2014 amount includes a $1 million decrease in expense associated with capitalized overhead costs associated with a certain Pacific operations litigation matter. 2013 amount includes a $15 million increase in expense associated with a rate case liability adjustment related to a certain West Coast terminal environmental matter.
|
|
(b)
|
2014 amount represents a gain from the sale of propane pipeline line-fill.
|
|
(c)
|
Volumes include ethanol pipeline volumes.
|
|
(d)
|
Includes Pacific, Plantation Pipe Line Company, Calnev, Central Florida and Parkway pipeline volumes.
|
|
(e)
|
Includes Cochin and Cypress pipeline volumes.
|
|
(f)
|
Includes Kinder Morgan Crude & Condensate and Double Eagle pipeline volumes.
|
|
(g)
|
Represents total ethanol volumes, including ethanol pipeline volumes included in gasoline volumes above.
|
46
Following is information related to the increases and decreases, in the comparable three month periods of 2014 and 2013:
The primary increases and decreases in our Products Pipelines business segment’s EBDA in the comparable three month periods of
2014
and
2013
included the following:
|
▪
|
a $5 million (111%) increase from our Kinder Morgan Crude Oil & Condensate Pipeline, due mainly to a 63% increase in pipeline throughput volumes;
|
|
▪
|
a $3 million (23%) increase from our transmix processing operations due to higher volumes and margins at various transmix sales plants;
|
|
▪
|
a $2 million (11%) increase from our Southeast terminal operations, driven by higher volumes and revenues and higher physical inventory gains;
|
|
▪
|
incremental earnings of $2 million from our 50%-owned Parkway Pipeline, which was placed into service in September 2013;
|
|
▪
|
a $5 million (18%) decrease from our Cochin Pipeline, primarily due to lower terminal, storage and petrochemical volumes and associated revenues;
|
|
▪
|
a $3 million (5%) decrease from our Pacific operations, due primarily to an unfavorable settlement of a certain litigation matter in the first quarter of 2014; and
|
|
▪
|
a $2 million (9%) decrease from our West Coast terminal operations, due primarily from lower volumes.
|
47
Terminals
|
|
Three Months Ended
March 31, |
||||||
|
|
2014
|
|
2013
|
||||
|
|
(In millions, except operating statistics)
|
||||||
|
Revenues
|
$
|
391
|
|
|
$
|
337
|
|
|
Operating expenses(a)
|
(183
|
)
|
|
(157
|
)
|
||
|
Other expense(b)
|
(1
|
)
|
|
—
|
|
||
|
Earnings from equity investments
|
5
|
|
|
7
|
|
||
|
Interest income and Other, net
|
1
|
|
|
1
|
|
||
|
Income tax benefit (expense)(c)
|
1
|
|
|
(2
|
)
|
||
|
EBDA
|
214
|
|
|
186
|
|
||
|
Certain items, net(a)(b)(c)
|
14
|
|
|
1
|
|
||
|
EBDA before certain items
|
$
|
228
|
|
|
$
|
187
|
|
|
|
|
|
|
||||
|
Change from prior period
|
Increase/(Decrease)
|
||||||
|
Revenues
|
$
|
54
|
|
|
16
|
%
|
|
|
EBDA before certain items
|
$
|
41
|
|
|
22
|
%
|
|
|
|
|
|
|
||||
|
Bulk transload tonnage (MMtons)(d)
|
21.6
|
|
|
22.4
|
|
||
|
Ethanol (MMBbl)
|
16.5
|
|
|
15.2
|
|
||
|
Liquids leaseable capacity (MMBbl)
|
71.6
|
|
|
60.5
|
|
||
|
Liquids utilization %(e)
|
94.4
|
%
|
|
95.1
|
%
|
||
__________
|
(a)
|
2014 and 2013 amounts include increases in expense of $7 million and $1 million, respectively, related to hurricane clean-up and repair activities at our New York Harbor and Mid-Atlantic terminals. 2014 amount also includes a $10 million increase in expense primarily associated with a legal liability adjustment related to a certain litigation matter.
|
|
(b)
|
2014 amount represents a casualty indemnification loss, related to 2012 hurricane activity at our New York Harbor and Mid-Atlantic terminals.
|
|
(c)
|
2014 amount includes a $4 million decrease in expense (representing tax savings) related to the pre-tax expense amount associated with the litigation matter mentioned in footnote (a).
|
|
(d)
|
Volumes for acquired terminals are included for all periods and include our proportionate share of joint venture tonnage.
|
|
(e)
|
The ratio of our actual leased capacity (excluding the capacity of tanks out of service) to our estimated potential capacity.
|
Our Terminals business segment includes the operations of our petroleum, chemical and other liquids terminal facilities (other than those included in our Products Pipelines segment), and all of our coal, petroleum coke, fertilizer, steel, ores and other dry-bulk material services facilities. Following is information related to the increases and decreases, in the comparable three month periods of
2014
and
2013
:
48
The primary increases and decreases in our Terminals business segment’s EBDA in the comparable three month periods of
2014
and
2013
included the following:
|
▪
|
The $13 million increase from acquired assets and businesses relates primarily to the incremental earnings for the marine operations we acquired effective January 17, 2014 (our APT acquisition).
|
|
▪
|
The higher earnings from our Gulf Liquids terminals were mainly due to higher liquids warehousing revenues from our Pasadena and Galena Park liquids facilities located along the Houston Ship Channel. The facilities benefited from high gasoline export demand, increased rail services, and new and incremental customer agreements at higher rates, including new tankage from our expansion projects.
|
|
▪
|
We also realized higher quarter-to-quarter earnings in 2014 from our West region terminals (driven by the completion of expansion projects since the end of the first quarter of 2013), our Gulf Bulk terminals (driven by higher volumes in the first quarter of 2014, due in large part to refinery and coker shutdowns in the first quarter of 2013 as a result of turnarounds taken), and our Gulf Central terminals (driven by higher earnings from BOSTCO, our oil terminal joint venture, of which we own approximately 55%, located on the Houston Ship Channel that began operations in October 2013).
|
Kinder Morgan Canada
|
|
Three Months Ended
March 31, |
||||||
|
|
2014
|
|
2013
|
||||
|
|
(In millions, except operating statistics)
|
||||||
|
Revenues
|
$
|
69
|
|
|
$
|
72
|
|
|
Operating expenses
|
(24
|
)
|
|
(25
|
)
|
||
|
Earnings from equity investments
|
—
|
|
|
4
|
|
||
|
Interest income and Other, net(a)
|
7
|
|
|
230
|
|
||
|
Income tax expense(b)
|
(4
|
)
|
|
(88
|
)
|
||
|
EBDA
|
48
|
|
|
193
|
|
||
|
Certain items, net(a)(b)
|
—
|
|
|
(141
|
)
|
||
|
EBDA before certain items
|
$
|
48
|
|
|
$
|
52
|
|
|
|
|
|
|
||||
|
Change from prior period
|
Increase/(Decrease)
|
||||||
|
Revenues
|
$
|
(3
|
)
|
|
(4
|
)%
|
|
|
EBDA before certain items
|
$
|
(4
|
)
|
|
(8
|
)%
|
|
|
|
|
|
|
||||
|
Transport volumes (MMBbl)(c)
|
25.0
|
|
|
26.7
|
|
||
__________
|
(a)
|
2013 amount includes a gain of $225 million from the sale of our equity and debt investments in the Express pipeline system.
|
|
(b)
|
2013 amount includes an
increase of $84 million related to the pre-tax gain amount associated with the sale of our equity and debt investments in the Express pipeline system described in footnote (a).
|
|
(c)
|
Represents Trans Mountain pipeline system volumes.
|
Our Kinder Morgan Canada business segment includes the operations of our Trans Mountain and Jet Fuel pipeline systems, and until March 14, 2013, the effective date of sale, our one-third ownership interest in the Express crude oil pipeline system. Following is information related to the increases and decreases, in the comparable three month periods of 2014 and 2013:
__________
49
|
(a)
|
Equity investment; accordingly, we recorded earnings under the equity method of accounting. However, we sold our debt and equity investments in Express effective March 14, 2013.
|
The decrease in Trans Mountain’s earnings was driven by a $5 million unfavorable impact from foreign currency translation. Due to the weakening of the Canadian dollar since the end of the first quarter of 2013, we translated Canadian denominated income and expense amounts into fewer U.S. dollars in 2014.
Other
|
|
Three Months Ended
March 31, |
||||||
|
|
2014
|
|
2013
|
||||
|
|
(In millions)
|
||||||
|
General and administrative expenses(a)
|
$
|
153
|
|
|
$
|
134
|
|
|
|
|
|
|
||||
|
Interest expense, net of unallocable interest income(b)
|
$
|
239
|
|
|
$
|
202
|
|
|
|
|
|
|
||||
|
Unallocable income tax expense
|
$
|
2
|
|
|
$
|
3
|
|
|
|
|
|
|
||||
|
Net income attributable to noncontrolling interests(c)
|
$
|
8
|
|
|
$
|
9
|
|
__________
|
(a)
|
2014
amount includes (i) a $6 million increase in severance expense allocated to us from KMI (associated with both our March 2013 asset drop-down group and assets we acquired from KMI in August 2012; however, we do not have any obligation, nor did we pay any amounts related to this expense); (ii) a $1 million increase in expense associated with unallocated business acquisition costs; and (iii) a $1 million decrease in expense associated with capitalized overhead costs related to a certain Pacific operations litigation matter. 2013 amount also includes (i) a $9 million increase in expense attributable to our March 2013 drop-down asset group for periods prior to our March 1, 2013 acquisition date; (ii) a $4 million increase in expense associated with unallocated legal expenses and certain asset and business acquisition costs; and (iii) a $1 million increase in severance expense allocated to us from KMI (associated with both our March 2013 asset drop-down group and assets we acquired from KMI in August 2012; however, we do not have any obligation, nor did we pay any amounts related to this expense).
|
|
(b)
|
2014
amount includes
a $13 million increase in interest expense associated with a certain Pacific operations litigation matter, and a $2 million decrease in interest expense associated with debt fair value adjustments recorded in purchase accounting for our Copano acquisition.
2013
amount includes a $15 million increase in interest expense attributable to our March 2013 drop-down asset group for periods prior to our March 1, 2013 acquisition date.
|
|
(c)
|
2013
amount includes
a $2 million increase in net income attributable to our noncontrolling interests, related to the combined effect from all of the
2013
certain items previously disclosed in the footnotes to the tables included above in “—Results of Operations.”
|
Items not attributable to any segment include general and administrative expenses, unallocable interest income and income tax expense, interest expense, and net income attributable to noncontrolling interests. Our general and administrative expenses include such items as unallocated salaries and employee-related expenses, employee benefits, payroll taxes, insurance, office supplies and rentals, unallocated litigation and environmental expenses, and shared corporate services—including accounting, information technology, human resources and legal services.
These expenses are generally not controllable by our business segment operating managers and therefore are not included when we measure business segment operating performance. For this reason, we do not specifically allocate our general and administrative expenses to our business segments. As discussed previously, we use segment EBDA internally as a measure of profit and loss to evaluate segment performance, and each of our segment’s EBDA includes all costs directly incurred by that segment.
The certain items described in footnote (a) to the table above accounted for an
$8 million decrease in our general and administrative expenses in the first quarter of 2014, when compared to the same prior year period. The remaining $27 million (23%) quarter-to-quarter increase in expense was largely driven by the acquisition of additional businesses, associated primarily with our acquisition of both Copano (effective May 1, 2013) and the March 2013 drop-down asset group from KMI (effective March 1, 2013). Additional drivers were increased benefits costs and higher segment labor.
In the table above, we report our interest expense as “net,” meaning that we have subtracted unallocated interest income and capitalized interest from our interest expense to arrive at one interest amount, and after taking into effect the certain items described in footnote (b) to the table above, our unallocable interest expense increased
$41 million (22%) in the first quarter of
2014
, when compared to the first quarter of 2013. The increase was driven by higher average debt
50
levels (average borrowings for the three month period ended March 31, 2014 increased 16%, when compared to the same period a year ago), largely due to the capital expenditures, joint venture contributions and business acquisitions we have made since the end of the first quarter of
2013
. T
he weighted average interest rate on all of our borrowings—including both short-term and long-term borrowing amounts—was essentially flat across both three month periods (from 4.57% for the first quarter of 2013
to
4.60% for the first quarter of
2014
).
We swap a portion of our long-term fixed rate debt securities (senior notes) into variable rate debt in order to achieve our desired mix of fixed and variable rate debt. As of
March 31, 2014
and
December 31, 2013
, approximately
27% and 29%, respectively, of our consolidated debt balances (excluding debt fair value adjustments) were subject to variable interest rates—either as short-term or long-term variable rate debt obligations or as fixed-rate debt converted to variable rates through the use of interest rate swap agreements. For more information about our interest rate swaps, see Note 5 “Risk Management—Interest Rate Risk Management” to our consolidated financial statements.
Financial Condition
General
As of
March 31, 2014
, we had $347 million of “Cash and cash equivalents” on our consolidated balance sheet, a decrease of
$57 million (14%) from
December 31, 2013
. We also had, as of
March 31, 2014
, approximately
$2.1 billion of borrowing capacity available under our
$2.7 billion
senior unsecured revolving credit facility (discussed below in “—Short-term Liquidity”). We believe our cash position and our remaining borrowing capacity is adequate to allow us to manage our day-to-day cash requirements and anticipated obligations.
Our primary cash requirements, in addition to normal operating expenses, are for debt service, sustaining capital expenditures, expansion capital expenditures and quarterly distributions to our common unitholders, Class B unitholder and general partner.
In general, we expect to fund:
|
▪
|
cash distributions and sustaining capital expenditures with existing cash and cash flows from operating activities;
|
|
▪
|
expansion capital expenditures and working capital deficits with retained cash (which may result from including i-units in the determination of cash distributions per unit but paying quarterly distributions on i-units in additional i-units rather than cash), proceeds from divestitures, additional borrowings (including commercial paper issuances), and the issuance of additional common units or the proceeds from purchases of additional i-units by KMR;
|
|
▪
|
interest payments with cash flows from operating activities; and
|
|
▪
|
debt principal payments, as such debt principal payments become due, with proceeds from divestitures, additional borrowings or by the issuance of additional common units or the proceeds from purchases of additional i-units by KMR.
|
In addition to our results of operations, our debt and capital balances are affected by our financing activities, as discussed below in “—Financing Activities.” Cash provided from our operations is fairly stable across periods since a majority of our cash generated is fee based from a diversified portfolio of assets and is not sensitive to commodity prices. However, in our CO
2
business segment, while we hedge the majority of our oil production, we do have exposure to unhedged volumes, a significant portion of which are NGL.
Short-term Liquidity
As of
March 31, 2014
, our principal sources of short-term liquidity were (i) our
$2.7 billion
senior unsecured revolving credit facility with a diverse syndicate of banks that matures May 1, 2018; (ii) our
$2.7 billion
short-term commercial paper program (which is supported by our credit facility, with the amount available for borrowing under our credit facility being reduced by our outstanding commercial paper borrowings and letters of credit); and (iii) cash from operations (discussed below in “—Operating Activities”). The loan commitments under our revolving credit facility can be used to fund borrowings for general partnership purposes and as a backup for our commercial paper program. As of both
March 31, 2014
and
December 31, 2013
, we had no outstanding credit facility borrowings.
Our outstanding short-term debt as of
March 31, 2014
was
$1,243 million
, primarily consisting of (i)
$419 million
of outstanding commercial paper borrowings; (ii) $500 million in principal amount of 5.125% senior notes that mature
51
November 15, 2014; and (iii) $300 million in principal amount of 5.625% senior notes that mature February 15, 2015. We intend to refinance our current short-term debt through a combination of long-term debt, equity, and/or the issuance of additional commercial paper or credit facility borrowings to replace maturing commercial paper and current maturities of long-term debt. As of
December 31, 2013
, our short-term debt totaled
$1,504 million
.
We had a working capital deficit of
$1,516 million as of
March 31, 2014
, and a working capital deficit of $1,909 million as of December 31, 2013. The overall
$393 million (21%) favorable change from year-end 2013 was primarily due to the lower short-term debt balance (discussed above), and to lower accrued interest liabilities. Generally, our working capital balance varies due to factors such as the timing of scheduled debt payments, timing differences in the collection and payment of receivables and payables, the change in fair value of our derivative contracts, and changes in cash and cash equivalent balances as a result of debt or equity issuances (discussed below in “—Long-term Financing”).
Long-term Financing
In addition to our principal sources of short-term liquidity listed above, we could meet our cash requirements (other than distributions of cash from operations to our common unitholders, Class B unitholder and general partner) through issuing long-term debt securities or additional common units, or by utilizing the proceeds from purchases of additional i-units by KMR with the proceeds from issuances of KMR shares. Our equity offerings consist of the issuance of additional common units or the issuance of additional i-units to KMR (which KMR purchases with the proceeds from the sale of additional KMR shares). For more information about our equity issuances in the first quarter of 2014, see Note 4 “Partners’ Capital—Equity Issuances” to our consolidated financial statements.
From time to time we issue long-term debt securities, often referred to as our senior notes. Our senior notes issued to date, generally have very similar terms, except for interest rates, maturity dates and prepayment premiums. All of our outstanding senior notes are unsecured obligations that rank equally with all of our other senior debt obligations. Our fixed rate senior notes provide that we may redeem the notes at any time at a price equal to 100% of the principal amount of the notes plus accrued interest to the redemption date plus a make-whole premium. As of
March 31, 2014
and December 31, 2013, the aggregate principal amount of the various series of our senior notes was
$17,100 million and $15,600 million, respectively.
In addition, from time to time our subsidiaries have issued long-term debt securities, often referred to as their senior notes. Most of the debt of our operating partnerships and subsidiaries is unsecured; however a modest amount of secured debt has been incurred by some of our operating partnerships and subsidiaries. As of
March 31, 2014
and December 31, 2013, the total liability balance due on the various borrowings of our operating partnerships and subsidiaries (including senior notes) was
$3,334 million and
$3,335 million, respectively.
To date, our debt balances have not adversely affected our operations, our ability to grow or our ability to repay or refinance our indebtedness. For additional information about our debt-related transactions in the first quarter of 2014 and our consolidated debt obligations as of both
March 31, 2014
and
December 31, 2013
, see Note 3 “Debt” to our consolidated financial statements. For additional information regarding our debt securities, see Note 8 “Debt” to our consolidated financial statements included in our
2013
Form 10-K.
Based on our historical record, we believe that our capital structure will continue to allow us to achieve our business objectives. We are subject, however, to conditions in the equity and debt markets for our limited partner units and long-term senior notes, and there can be no assurance we will be able or willing to access the public or private markets for our limited partner units and/or long-term senior notes in the future. If we were unable or unwilling to issue additional limited partner units, we would be required to either restrict expansion capital expenditures and/or potential future acquisitions or pursue debt financing alternatives, some of which could involve higher costs or negatively affect our credit ratings. Furthermore, our ability to access the public and private debt markets is affected by our credit ratings.
Capital Expenditures
We account for our capital expenditures in accordance with GAAP. Capital expenditures under our partnership agreement include those that are maintenance/sustaining capital expenditures and those that are capital additions and improvements (which we refer to as expansion or discretionary capital expenditures). These distinctions are used when determining cash from operations pursuant to our partnership agreement (which is distinct from GAAP cash flows from operating activities). Capital additions and improvements are those expenditures which increase throughput or capacity
52
from that which existed immediately prior to the addition or improvement, and are not deducted in calculating cash from operations. Maintenance capital expenditures are those which maintain throughput or capacity. Thus under our partnership agreement, the distinction between maintenance capital expenditures and capital additions and improvements is a physical determination rather than an economic one.
Generally, the determination of whether a capital expenditure is classified as maintenance or as capital additions and improvements is made on a project level. The classification of capital expenditures as capital additions and improvements or as maintenance capital expenditures under our partnership agreement is left to the good faith determination of the general partner, which is deemed conclusive.
Our capital expenditures for the
three
months ended
March 31, 2014
, and the amount we expect to spend for the remainder of 2014 to grow and sustain our businesses are as follows (in millions):
|
|
Three Months Ended
March 31, 2014 |
|
2014
Remaining
|
|
Total
|
||||||
|
Sustaining(a)
|
$
|
72
|
|
|
$
|
374
|
|
|
$
|
446
|
|
|
Discretionary(b)(c)
|
710
|
|
|
3,211
|
|
|
3,921
|
|
|||
|
Total
|
$
|
782
|
|
|
$
|
3,585
|
|
|
$
|
4,367
|
|
—————————
|
(a)
|
Three month 2014 amount, 2014 remaining amount, and total 2014 amount include $1 million, $5 million and $6 million, respectively, for our proportionate share of sustaining capital expenditures of our unconsolidated joint ventures.
|
|
(b)
|
Three month 2014 amount (i) includes $66 million of discretionary capital expenditures of our unconsolidated joint ventures and acquisitions; and (ii) excludes a combined $94 million net change from accrued capital expenditures, contractor retainage and amounts primarily related to contributions from our noncontrolling interests to fund a portion of certain capital projects.
|
|
(c)
|
2014 remaining amount includes our contributions to certain unconsolidated joint ventures and small acquisitions, net of contributions estimated from unaffiliated joint venture partners for consolidated investments.
|
We generally fund our sustaining capital expenditures with existing cash or from cash flows from operations.
Generally, we initially fund our discretionary capital expenditures through borrowings under our commercial paper program or our revolving credit facility until the amount borrowed is of a sufficient size to cost effectively replace the initial funding with long-term debt, equity (including retained cash related i-unit distributions), or both.
We report our total consolidated capital expenditures separately as
“
Capital expenditures
”
within the
“
Cash Flows from Investing Activities
”
section on our accompanying cash flow statements, and
for each of the
three
months ended
March 31, 2014
and
2013
, these amounts totaled
$809 million
and
$552 million
, respectively. The
overall
$257 million (47%) quarter-to-quarter increase in our consolidated capital expenditures in 2014 versus 2013 was primarily due to higher investment undertaken to expand and improve our
Products Pipelines, Natural Gas Pipelines and Kinder Morgan Canada
business segments.
Additional Capital Requirements
In April 2012, we announced that we were proceeding with our proposal to expand our existing Trans Mountain pipeline system. When completed, the proposed expansion will increase capacity on Trans Mountain from its current 300 MBbl/d of crude oil and refined petroleum products to approximately 890 MBbl/d. In December 2013, we filed a Facilities Application with the NEB to receive authorization to build and operate the necessary facilities for the proposed expansion project. The NEB recently issued a hearing order for the proposed project, and we expect public hearings to begin this summer and an NEB decision by July 2015. Failure to secure NEB approval of this project on reasonable terms could require us to either delay or cancel this project; however, if approvals are received as planned, we expect to begin construction in 2015 or 2016, and begin operations in late 2017. Our current estimate of total construction costs on the project is approximately
$
5.4 billion.
On March 26, 2014, we announced that we will build and operate a new, 213-mile, 16-inch diameter pipeline to transport carbon dioxide from our St. Johns source field located in Apache County, Arizona, to Cortez Pipeline, which we operate and of which we own 50%, in Torrance County, New Mexico. The new Lobos Pipeline will have an initial capacity of 300 million standard cubic feet per day and will support current and future enhanced oil recovery projects owned by us and other operators in the Permian Basin of West Texas and eastern New Mexico. We plan to invest approximately $300 million in the pipeline and an additional $700 million to drill wells and build field gathering,
53
treatment and compression facilities at the St. Johns field. We expect to place the project into service by the third quarter of 2016, pending receipt of environmental and regulatory approvals.
In addition, we regularly consider and enter into discussions regarding potential acquisitions, including those from KMI or its affiliates, and are currently contemplating potential acquisitions. Such transactions can be effected quickly, may occur at any time and may be significant in size relative to our existing assets or operations.
Our ability to expand our assets is impacted by our ability to maintain adequate liquidity and to raise the necessary capital needed to fund such expansions. As an MLP, we distribute all of our available cash (except to the extent that we retain cash from the payment of distributions on i-units in additional i-units), and we access capital markets to fund acquisitions and asset expansions. Historically, we have succeeded in raising necessary capital in order to fund our acquisitions and expansions, and although we cannot predict future changes in the overall equity and debt capital markets (in terms of tightening or loosening of credit), we believe that our stable cash flows, our investment grade credit rating, and our historical record of successfully accessing both equity and debt funding sources should allow us to continue to execute our current investment, distribution and acquisition strategies, as well as refinance maturing debt when required.
Off Balance Sheet Arrangements
There have been no material changes in our obligations with respect to other entities that are not consolidated in our financial statements that would affect the disclosures presented as of
December 31, 2013
in our
2013
Form 10-K.
Cash Flows
The following table summarizes our net cash flows from operating, investing and financing activities for each of the three months ended March 31, 2014 and 2013:
|
|
Three Months Ended
March 31,
|
|
|
||||||||
|
|
2014
|
|
2013
|
|
Cash
increase/(decrease)
|
||||||
|
|
(In millions)
|
||||||||||
|
Net Cash Provided by (Used in):
|
|
|
|
|
|
||||||
|
Operating activities
|
$
|
1,074
|
|
|
$
|
746
|
|
|
$
|
328
|
|
|
Investing activities
|
(1,801
|
)
|
|
(1,171
|
)
|
|
(630
|
)
|
|||
|
Financing activities
|
680
|
|
|
638
|
|
|
42
|
|
|||
|
Effect of exchange rate changes on cash and cash equivalents
|
(10
|
)
|
|
(6
|
)
|
|
(4
|
)
|
|||
|
Net (Decrease) Increase in Cash and Cash Equivalents
|
$
|
(57
|
)
|
|
$
|
207
|
|
|
$
|
(264
|
)
|
Operating Activities
The overall
$328 million
(44%) increase in cash flows provided from our operating activities in the first quarter of 2014 versus the first quarter of 2013 consisted of the following:
|
▪
|
a $261 million increase in cash from overall higher partnership income—after adjusting our quarter-to-quarter $38 million decrease in net income for the following two non-cash items: (i) a $225 million increase from the first quarter 2013 gain on the sale of our investments in Express (we deducted the gain amount from our net income within the operating activities section of our statement of cash flows for the first quarter of 2013 and reported the proceeds received from this sale within the investing activities section); and (ii) a $74 million increase due to higher DD&A expenses (including amortization of excess cost of equity investments). The period-to-period change in partnership income in the first quarter of 2014 versus the first quarter of 2013 is discussed above in “—Results of Operations” (including all of the certain items disclosed in the associated table footnotes); and
|
|
▪
|
a $67 million increase in cash from the combined net activity of our equity method investees and the net cash changes in operating assets and liabilities. The overall increase in cash was driven by higher cash inflows from favorable changes in trade and related party accounts payables, and largely offset by, among other things, lower cash inflows from unfavorable changes in accrued tax liabilities.
|
54
Investing Activities
The overall
$630 million
(54%) quarter-to-quarter
increase in cash used in our investing activities in the first quarter of 2014 versus the first quarter of 2013 was primarily due to the following:
|
▪
|
$403 million of net proceeds we received in the first quarter of 2013 from the sale of our investments in the Express pipeline system; and
|
|
▪
|
a
$257 million increase in cash used due to higher capital expenditures in the first quarter of 2014, as described above in “—Capital Expenditures.”
|
For more information about our asset acquisitions during the first three months of 2014 and 2013, including our APT acquisition, see Note 2 “Acquisitions and Divestitures—Acquisitions” to our consolidated financial statements.
Financing Activities
The overall
$42 million
(7%) quarter-to-quarter increase in cash from all of our financing activities in the first quarter of 2014 versus the first quarter of 2013 was primarily attributable to the following:
|
▪
|
a $240 million increase in cash due to higher partnership equity issuances. This increase reflects the
combined $625 million we received, after commissions and underwriting expenses, from issuing additional common and i-units during the first quarter of 2014 (discussed in Note 4 “Partners’ Capital—Equity Issuances” to our consolidated financial statements), versus the
$385 million we received from the sales of additional common units in the first quarter of 2013 (on February 26, 2013, we issued, in a public offering, 4,600,000 of our common units at a price of $86.35 per unit, less commissions and underwriting expenses); and
|
|
▪
|
a
$165 million decrease in cash due to higher partnership distributions. Distributions to all partners, consisting of our common and Class B unitholders, our general partner and our noncontrolling interests, totaled
$895 million in the first quarter of 2014, compared to $730 million in the first quarter of 2013. The increase in distributions was due to increases in the per unit cash distribution paid, the number of outstanding units, and the resulting increase in our general partner incentive distributions. Further information regarding our distributions is discussed following in “—Partnership Distributions.”
|
Partnership Distributions
Our partnership agreement requires that we distribute 100% of “Available Cash,” as defined in our partnership agreement, to our partners within 45 days following the end of each calendar quarter. Our
2013
Form 10-K contains additional information concerning our partnership distributions, including the definition of “Available Cash,” the manner in which our total distributions are divided between our general partner and our limited partners, and the form of distributions to all of our partners, including our noncontrolling interests. For further information about the partnership distributions we paid in the first quarters of 2014 and 2013 (for the fourth quarterly periods of 2013 and 2012, respectively), see Note 4 “Partners’ Capital—Partnership Distributions” to our consolidated financial statements.
On April 16, 2014, we declared a cash distribution of
$1.38
per unit for the first quarter of 2014 compared to the $1.30 per unit distribution we made for the first quarter of 2013. Based on (i) our declared distribution; (ii) the number of units outstanding; and (iii) our general partner’s agreement to forgo a combined
$33 million of its incentive cash distribution in conjunction with both our May 2013 Copano acquisition and our January 2014 APT acquisition, our declared distribution for the first quarter of 2014 of
$1.38
per unit will result in an incentive distribution to our general partner of
$449 million
.
Comparatively, our distribution of $1.30 per unit paid on May 15, 2013 for the first quarter of 2013 resulted in an incentive distribution payment to our general partner in the amount of $398 million (and included the effect of a waived incentive distribution amount of
$4 million related to our July 2011 KinderHawk acquisition). The increased incentive distribution to our general partner for the first quarter of 2014 over the incentive distribution for the first quarter of 2013 reflects the increase in the distribution per unit as well as the issuance of additional units. For additional information about our first quarter 2014 cash distribution, see Note 4 “Partners’ Capital—Subsequent Event” to our consolidated financial statements. For additional information about our 2013 partnership distributions, see Note 10 “Partners’ Capital—Income Allocation and Declared Distributions” and Note 11 “Related Party Transactions—Partnership Interests and Distributions” to our consolidated financial statements included in our
2013
Form 10-K.
55
Although the majority of the cash generated by our assets is fee based and is not sensitive to commodity prices, our CO
2
business segment is exposed to commodity price risk related to the price volatility of crude oil and NGL, and while we hedge the majority of our crude oil production, we do have exposure on our unhedged volumes, the majority of which are NGL volumes. Our 2014 budget assumes an average WTI crude oil price of approximately $96.15 per barrel (with some minor adjustments for timing, quality and location differences) in 2014, and based on the actual prices we have received through the date of this report and the forward price curve for WTI (adjusted for the same factors used in our 2014 budget), we currently expect the average price of WTI crude oil will be approximately
$96.62 per barrel in 2014. For 2014, we expect that every $1 change in the average WTI crude oil price per barrel will impact our CO
2
segment’s cash flows by approximately $7 million on a full year basis (or approximately 0.125% of our combined business segments’ anticipated EBDA expenses). This sensitivity to the average WTI price is very similar to what we experienced in 2013.
Item 3. Quantitative and Qualitative Disclosures About Market Risk.
There have been no material changes in market risk exposures that would affect the quantitative and qualitative disclosures presented as of
December 31, 2013
, in Item 7A in our
2013
Form 10-K. For more information on our risk management activities, see Note 5 “Risk Management” to our consolidated financial statements included elsewhere in this report.
Item 4. Controls and Procedures.
As of
March 31, 2014
, our management, including our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. Based upon and as of the date of the evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the design and operation of our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed in the reports we file and submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported as and when required, and is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. There has been no change in our internal control over financial reporting during the quarter ended
March 31, 2014
that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
56
PART II. OTHER INFORMATION
Item 1. Legal Proceedings.
See Part I, Item 1, Note 9 to our consolidated financial statements entitled “Litigation, Environmental and Other Contingencies,” which is incorporated in this item by reference.
Item 1A. Risk Factors.
There have been no material changes in or additions to the risk factors disclosed in Part I, Item 1A “Risk Factors” in our
2013
Form 10-K.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.
None.
Item 3. Defaults Upon Senior Securities.
None.
Item 4. Mine Safety Disclosures
The information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17 CFR 229.104) is included in exhibit 95 to this quarterly report.
Item 5. Other Information.
None.
57
Item 6. Exhibits.
|
4.1
|
|
—Certificate of the Vice President, Finance and Investor Relations and the Vice President and Secretary of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 3.50% Senior Notes due 2021 and the 5.50% Senior Notes due 2044.
|
|
4.2
|
|
—Certain instruments with respect to long-term debt of Kinder Morgan Energy Partners, L.P. and its consolidated subsidiaries which relate to debt that does not exceed 10% of the total assets of Kinder Morgan Energy Partners, L.P. and its consolidated subsidiaries are omitted pursuant to Item 601(b)(4)(iii)(A) of Regulation S-K (17 CFR 229.601). Kinder Morgan Energy Partners, L.P. hereby agrees to furnish supplementally to the Securities and Exchange Commission a copy of each such instrument upon request.
|
|
12
|
|
—Statement re: computation of ratio of earnings to fixed charges.
|
|
31.1
|
|
—Certification by CEO pursuant to Rule 13a-14 or 15d-14 of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
|
|
31.2
|
|
—Certification by CFO pursuant to Rule 13a-14 or 15d-14 of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
|
|
32.1
|
|
—Certification by CEO pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
|
|
32.2
|
|
—Certification by CFO pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
|
|
95
|
|
—Mine Safety Disclosures.
|
|
101
|
|
—Interactive data files pursuant to Rule 405 of Regulation S-T: (i) our Consolidated Statements of Income for the three months ended March 31, 2014 and 2013; (ii) our Consolidated Statements of Comprehensive Income for the three months ended March 31, 2014 and 2013; (iii) our Consolidated Balance Sheets as of March 31, 2014 and December 31, 2013; (iv) our Consolidated Statements of Cash Flows for the three months ended March 31, 2014 and 2013; (v) our Consolidated Statements of Partners’ Capital for the three months ended March 31, 2014 and 2013; and (vi) the notes to our Consolidated Financial Statements.
|
58
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
|
|
KINDER MORGAN ENERGY PARTNERS, L.P.
|
|
|
Registrant (a Delaware Limited Partnership)
|
|
|
|
|
|
By:
KINDER MORGAN G.P., INC.,
|
|
|
Its sole General Partner
|
|
|
|
|
|
By:
KINDER MORGAN MANAGEMENT, LLC,
the Delegate of Kinder Morgan G.P., Inc.
|
|
|
|
|
|
By: /s/ KIMBERLY A. DANG
|
|
|
Kimberly A. Dang,
Vice President and Chief Financial Officer
(principal financial and accounting officer)
|
Date:
April 29, 2014
59