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KINDER MORGAN ENERGY PARTNERS L P - 10-Q - Management's Discussion and Analysis of Financial Condition and Results of Operations.(Edgar Glimpses Via Acquire Media NewsEdge) 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 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. 38-------------------------------------------------------------------------------- Table of Contents 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, 2014. 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, 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 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 39-------------------------------------------------------------------------------- Table of Contents 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 and six months ended June 30, 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 June 30, Six Months Ended June 30, 2014 2013 2014 2013 Net Income $ 669 $ 1,010 $ 1,423 $ 1,802 Add/(Less): Certain items - combined expense/(income)(a) 29 (383 ) 63 (520 ) Net Income before certain items 698 627 1,486 1,282 Less: Net Income before certain items attributable to noncontrolling interests(b) (9 ) (7 ) (17 ) (14 ) Net Income before certain items attributable to KMEP 689 620 1,469 1,268 Less: General Partner's interest in Net Income before certain items(c) (466 ) (418 ) (919 ) (819 ) Limited Partners' interest in Net Income before certain items 223 202 550 449 Depreciation, depletion and amortization(d)(f) 431 379 857 717 Book (cash) taxes paid, net (1 ) - 16 12 Incremental contributions from equity investments in the Express Pipeline and Endeavor Gathering LLC 7 (6 ) 2 (5 ) Sustaining capital expenditures(e)(f) (99 ) (70 ) (171 ) (118 ) Distributable cash flow before certain items $ 561 $ 505 $ 1,254 $ 1,055 ______________(a) Consists of certain items summarized in footnotes (b) through (d) and (f) through (j) 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) Equal to "Net income attributable to noncontrolling interests;" in addition, (i) three and six month 2014 amounts exclude a $1 million decrease in income attributable to our noncontrolling interests related to the combined effect from all of the three and six month 2014 certain items disclosed in the footnotes to the "-Results of Operations" table included below; and (ii) three and six month 2013 amounts exclude increases in income of $3 million and $5 million, respectively, in income attributable to our noncontrolling interests related to the combined effect from all of the three and six month 2013 certain items disclosed in footnotes (e) and (k) to the "-Results of Operations" tables included below. (c) Amounts are net of waived incentive distributions of $33 million and $25 million for the three months ended June 30, 2014 and 2013, respectively, and $66 million and $29 million for the six months ended June 30, 2014 and 2013, respectively, related to certain acquisitions. (d) Three and six month 2014 amounts include expense amounts of $20 million and $42 million, respectively, and three and six month 2013 amounts include expense amounts of $20 million and $47 million, respectively, for our proportionate share of the DD&A expenses of certain unconsolidated joint ventures. Six month 2013 amount also excludes a $19 million expense amount attributable to our March 2013 drop-down asset group for periods prior to our acquisition. (e) Three and six month 2014 amounts include expenditures of $2 million and $3 million, respectively, and three and six month 2013 amounts each include expenditures of $1 million, for our proportionate share of the sustaining capital expenditures of certain unconsolidated joint ventures. (f) 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 (d)). 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 considered in 40-------------------------------------------------------------------------------- Table of Contents 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 June 30, Earnings 2014 2013 increase/(decrease) (In millions, except percentages) Segment EBDA(a) Natural Gas Pipelines $ 639 $ 1,123 $ (484 ) (43 )% CO2 332 358 (26 ) (7 )% Products Pipelines 203 12 191 1,592 % Terminals 233 207 26 13 % Kinder Morgan Canada 40 50 (10 ) (20 )% Segment EBDA(b) 1,447 1,750 (303 ) (17 )% DD&A expense (406 ) (357 ) (49 ) (14 )% Amortization of excess cost of equity investments (5 ) (2 ) (3 ) (150 )% General and administrative expense(c) (132 ) (163 ) 31 19 % Interest expense, net of unallocable interest income(d) (231 ) (215 ) (16 ) (7 )% Unallocable income tax expense (4 ) (3 ) (1 ) (33 )% Income from continuing operations 669 1,010 (341 ) (34 )% Net Income 669 1,010 (341 ) (34 )% Net Income attributable to noncontrolling interests(e) (8 ) (10 ) 2 20 % Net Income attributable to KMEP $ 661 $ 1,000 $ (339 ) (34 )% ______________ Results of Operations Six Months Ended June 30, Earnings 2014 2013 increase/(decrease) (In millions, except percentages) Segment EBDA(a) Natural Gas Pipelines $ 1,358 $ 1,680 $ (322 ) (19 )% CO2 695 700 (5 ) (1 )% Products Pipelines 411 197 214 109 % Terminals 447 393 54 14 % Kinder Morgan Canada 88 243 (155 ) (64 )% Segment EBDA(f) 2,999 3,213 (214 ) (7 )% DD&A expense(g) (807 ) (685 ) (122 ) (18 )% Amortization of excess cost of equity investments (8 ) (4 ) (4 ) (100 )% General and administrative expense(h) (285 ) (297 ) 12 4 % Interest expense, net of unallocable interest income(i) (470 ) (417 ) (53 ) (13 )% Unallocable income tax expense (6 ) (6 ) - - % Income from continuing operations 1,423 1,804 (381 ) (21 )% Loss from discontinued operations(j) - (2 ) 2 100 % Net Income 1,423 1,802 (379 ) (21 )% Net Income attributable to noncontrolling interests(k) (16 ) (19 ) 3 16 %Net Income attributable to KMEP $ 1,407 $ 1,783 $ (376 ) (21 )% ______________ (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. 41-------------------------------------------------------------------------------- Table of Contents Certain item footnotes (b) 2014 and 2013 amounts include a decrease in earnings of $31 million and an increase in earnings of $413 million, respectively, related to the combined effect from all of the three month 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 $32 million increase in expense related to the combined effect from all of the three month 2013 certain items related to general and administrative expenses disclosed below in "-Other." (d) 2014 and 2013 amounts include a certain item that decreases interest expense by $2 million, and is associated with debt fair value adjustments recorded in purchase accounting for our Copano acquisition. (e) 2014 and 2013 amounts include a $1 million decrease and a $3 million increase, respectively, in net income attributable to our noncontrolling interests, related to the combined effect from all of the three month 2014 and 2013 certain items disclosed below in both our management's discussion and analysis of segment results and "-Other." (f) 2014 and 2013 amounts include a decrease in earnings of $48 million and an increase in earnings of $600 million, respectively, related to the combined effect from all of the six month 2014 and 2013 certain items impacting continuing operations and disclosed below in our management discussion and analysis of segment results. (g) 2013 amount includes a certain item resulting in 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. (h) 2014 and 2013 amounts include increases in expense of $6 million and $46 million, respectively, related to the combined effect from all of the six month 2014 and 2013 certain items related to general and administrative expenses disclosed below in "-Other." (i) 2014 and 2013 amounts includes certain items that decrease interest expense by $4 million and $2 million, respectively, associated with debt fair value adjustments recorded in purchase accounting for our Copano acquisition. 2014 amount also includes a certain item $13 million increase in interest expense associated with a certain Pacific operations litigation matter. 2013 amount also includes a certain item $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. (j) 2013 amount represents an incremental loss related to the certain item sale of our FTC Natural Gas Pipelines disposal group effective November 1, 2012. (k) 2014 and 2013 amounts include a $1 million decrease and a $5 million increase, respectively, in net income attributable to our noncontrolling interests, related to the combined effect from all of the six month 2014 and 2013 certain items disclosed below in both our management's discussion and analysis of segment results and "-Other." For the comparable second quarter periods, the certain items described in footnote (b) to the tables above accounted for a $444 million decrease in EBDA in the second quarter of 2014, when compared to the second quarter of 2013 (combining to decrease total segment EBDA by $31 million in the second quarter of 2014 and increase total segment EBDA by $413 million in the second quarter of 2013). After taking into effect these certain items, the remaining $141 million (11%) quarter-to-quarter increase in EBDA was largely driven by better performance in the second quarter of 2014 from our Natural Gas Pipelines, Terminals, Products Pipelines and CO2 business segments. For the comparable six month periods, the certain items described in footnote (f) to the tables above accounted for a $648 million decrease in EBDA in the first half of 2014, when compared to the first half of 2013 (combining to decrease total segment EBDA by $48 million in the first half of 2014 and increase total segment EBDA by $600 million in the first half of 2013). After taking into effect these certain items, the remaining $434 million (17%) period-to-period increase in EBDA was largely driven by better performance in the first six months of 2014 from our Natural Gas Pipelines, Terminals, CO2 and Products Pipelines business segments. 42-------------------------------------------------------------------------------- Table of Contents Natural Gas Pipelines Three Months Ended June 30, Six Months Ended June 30, 2014 2013 2014 2013 (In millions, except operating statistics) Revenues(a) $ 2,112 $ 1,696 $ 4,288 $ 3,065 Operating expenses(b) (1,509 ) (1,179 ) (3,010 ) (2,039 ) Other income (expense) (1 ) - 3 - Earnings from equity investments(c) 34 45 77 93 Interest income and Other, net(d) 6 564 6 565 Income tax expense (3 ) (3 ) (6 ) (4 ) EBDA from continuing operations 639 1,123 1,358 1,680 Discontinued operations(e) - - - (2 ) Certain items, net(a)(b)(c)(d)(e) 3 (557 ) 7 (615 ) EBDA before certain items $ 642 $ 566 $ 1,365 $ 1,063 Change from prior period Increase/(Decrease) Revenues before certain items(a) $ 418 25 % $ 1,340 45 % EBDA before certain items $ 76 13 % $ 302 28 % Natural gas transport volumes (BBtu/d)(f) 16,948 15,555 17,441 16,310 Natural gas sales volumes (BBtu/d)(g) 2,208 2,417 2,231 2,387 Natural gas gathering volumes (BBtu/d)(h) 3,090 3,060 2,981 2,975 ______________ Certain item footnotes (a) Three and six month 2014 amounts include decreases in revenues of $3 million and $7 million, respectively, and three and six month 2013 amounts each include a decrease in revenues of $1 million from other certain items. Six month 2013 amount also 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) Six month 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 a $1 million increase in expense from other certain items. (c) Six month 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 $1 million decrease in earnings from other certain items. (d) Three and six month 2013 amounts include a $558 million gain from the remeasurement of our previously held 50% equity interest in Eagle Ford to fair value. (e) Six month 2013 amount represents an incremental loss from the sale of our FTC Natural Gas Pipelines disposal group's net assets. Other footnotes (f) Includes 100% of pipeline volumes for our wholly-owned assets as well as our joint venture assets as if they were wholly-owned for all periods presented. Volumes for acquired pipelines are included for all periods. (g) Represents volumes for the Texas intrastate natural gas pipeline group. (h) Includes 100% of gas gathering volumes for our wholly-owned assets. Joint venture throughput is reported at our ownership share. Volumes for acquired pipelines are included for all periods. 43-------------------------------------------------------------------------------- Table of Contents Following is information related to the increases and decreases in both EBDA and revenues before certain items, in the comparable three and six month periods of 2014 and 2013: Three months ended June 30, 2014 versus Three months ended June 30, 2013 EBDA Revenues increase/(decrease) increase/(decrease) (In millions, except percentages) TGP $ 41 22 % $ 44 18 % Copano operations (excluding Eagle Ford) 31 n/a 279 n/a Eagle Ford(a) 6 n/a 91 n/a EP midstream asset operations 5 28 % 13 32 % EPNG 2 2 % 10 7 % Kinder Morgan treating operations (5 ) (29 )% (10 ) (35 )% Texas Intrastate Natural Gas Pipeline Group (1 ) (3 )% 29 3 % All others (including eliminations) (3 ) (3 )% (38 ) (610 )% Total Natural Gas Pipelines $ 76 13 % $ 418 25 % ______________ Six months ended June 30, 2014 versus Six months ended June 30, 2013 EBDA Revenues increase/(decrease) increase/(decrease) (In millions, except percentages) Copano operations (excluding Eagle Ford) $ 111 n/a $ 742 n/a TGP 76 19 % 83 16 % EPNG 58 42 % 107 62 % Eagle Ford(a) 30 n/a 236 n/a Texas Intrastate Natural Gas Pipeline Group 18 11 % 302 17 % EP midstream asset operations 17 56 % 50 93 % Kinder Morgan treating operations (7 ) (25 )% (24 ) (40 )% All others (including eliminations) (1 ) - % (156 ) (215 )% Total Natural Gas Pipelines $ 302 28 % $ 1,340 45 % ______________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 comparable three and six month periods of 2014 and 2013 included the following: ? increases of $41 million (22%) and $76 million (19%), respectively, from TGP primarily due to higher revenues from (i) firm transportation and storage, due largely to new projects placed in service in the latter part of 2013 and new southbound capacity contracts; (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 half of 2013; ? incremental earnings of $31 million and $111 million, respectively, 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 $6 million and $30 million, respectively, 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; ? increases of $5 million (28%) and $17 million (56%), respectively, from our EP midstream assets, due largely to higher gathering revenues from increased drilling from both the Altamont gathering system in Utah and the Camino Real gathering system in South Texas, and for the comparable six month periods, by our acquisition from KMI effective March 1, 2013 of the remaining 50% interest we did not already own; 44-------------------------------------------------------------------------------- Table of Contents ? increases of $2 million (2%) and $58 million (42%), respectively, from EPNG, due largely to higher transport revenues, and for the comparable six month periods, to our acquisition of the remaining 50% interest we did not already own from KMI effective March 1, 2013; ? decreases of $5 million (29%) and $7 million (25%), respectively, from our Kinder Morgan treating operations, due largely to reduced activity at SouthTex Treaters (our manufacturing facility); and ? a decrease of $1 million (3%) and an increase of $18 million (11%), respectively, from our Texas intrastate natural gas pipeline group, due largely to higher maintenance costs in the second quarter of 2014, and for the comparable six month periods, to higher natural gas sales, transportation and storage margins, all driven in part by colder weather in the first quarter of 2014. CO2 Three Months Ended June 30, Six Months Ended June 30, 2014 2013 2014 2013 (In millions, except operating statistics) Revenues(a) $ 454 $ 460 $ 937 $ 889 Operating expenses (127 ) (107 ) (252 ) (199 ) Earnings from equity investments 7 7 14 13 Income tax expense (2 ) (2 ) (4 ) (3 ) EBDA 332 358 695 700 Certain items(a) 28 (7 ) 31 (9 ) EBDA before certain items $ 360 $ 351 $ 726 $ 691 Change from prior period Increase/(Decrease) Revenues before certain items(a) $ 29 6 % $ 88 10 % EBDA before certain items $ 9 3 % $ 35 5 % Southwest Colorado CO2 production (gross) (Bcf/d)(b) 1.3 1.2 1.3 1.2 Southwest Colorado CO2 production (net) (Bcf/d)(b) 0.5 0.5 0.5 0.5 SACROC oil production (gross)(MBbl/d)(c) 32.2 30.0 32.0 30.4 SACROC oil production (net)(MBbl/d)(d) 26.8 25.0 26.6 25.3 Yates oil production (gross)(MBbl/d)(c) 19.6 20.7 19.6 20.6 Yates oil production (net)(MBbl/d)(d) 8.5 9.2 8.6 9.1 Katz oil production (gross)(MBbl/d)(c) 3.8 2.5 3.7 2.3 Katz oil production (net)(MBbl/d)(d) 3.2 2.1 3.0 1.9 Goldsmith oil production (gross)(MBbl/d)(c) 1.3 0.4 1.2 0.2 Goldsmith oil production (net)(MBbl/d)(d) 1.1 0.4 1.1 0.2 NGL sales volumes (net)(MBbl/d)(d) 9.9 9.6 9.9 9.9 Realized weighted average oil price per Bbl(e) $ 88.83 $ 94.20 $ 90.35 $ 90.55 Realized weighted average NGL price per Bbl(f) $ 45.71 $ 44.17 $ 47.56 $ 45.36 ______________ n/a - not applicable Certain item footnote (a) Three and six month 2014 amounts include unrealized losses of $28 million and $31 million, respectively, and three and six month 2013 amounts include unrealized gains of $7 million and $9 million, respectively, all relating to derivative contracts used to hedge forecasted crude oil sales. Other footnotes (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. 45-------------------------------------------------------------------------------- Table of Contents Our CO2 segment's primary businesses involve the production, marketing and transportation of both CO2 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 Source and Transportation Activities, and for each of these two primary businesses, following is information related to the increases and decreases in both EBDA and revenues before certain items, in the comparable three and six month periods of 2014 and 2013: Three months ended June 30, 2014 versus Three months ended June 30, 2013 EBDA Revenues increase/(decrease) increase/(decrease) (In millions, except percentages) Source and Transportation Activities $ 21 23 % $ 23 22 % Oil and Gas Producing Activities (12 ) (4 )% 11 3 % Intrasegment eliminations - - % (5 ) (30 )% Total CO2 $ 9 3 % $ 29 6 % ______________ Six months ended June 30, 2014 versus Six months ended June 30, 2013 EBDA Revenues increase/(decrease) increase/(decrease) (In millions, except percentages) Source and Transportation Activities $ 41 22 % $ 49 24 % Oil and Gas Producing Activities (6 ) (1 )% 49 7 % Intrasegment eliminations - - % (10 ) (30 )% Total CO2 $ 35 5 % $ 88 10 % The primary increases and decreases in our CO2 segment's source and transportation activities in the comparable three and six month periods of 2014 and 2013 included the following: ? EBDA increases of $21 million (23%) and $41 million (22%), respectively, driven primarily by higher revenues (described following), somewhat offset by higher labor costs, power costs and property taxes. ? revenue increases of $23 million (22%) and $49 million (24%), respectively, driven primarily by increases of 14% and 16%, respectively, in average CO2 sales prices. The increases in sales prices were due primarily to two factors: (i) a change in the mix of contracts resulting in more CO2 being delivered under higher price contracts; and (ii) heavier weighting of new CO2 contract prices to the price of crude oil. CO2 sales volumes were also higher by 13% and 14%, respectively, when compared to the same two periods in 2013, primarily due to expansion projects at our Doe Canyon field which went in service in the fourth quarter of 2013. The primary increases and decreases in our CO2 segment's 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, in the comparable three and six month periods of 2014 and 2013 included the following: ? EBDA decreases of $12 million (4%) and $6 million (1%), respectively, driven by higher operating expenses as a result of incremental well work over costs at our recently acquired Goldsmith Landreth unit. Power costs increased primarily due to increased production at SACROC and higher power prices along with the incremental power required at the Goldsmith Landreth unit. In addition, operating expenses increased due to higher property taxes and severance taxes related to the increases in revenue (described following). ? revenue increases of $11 million (3%) and $49 million (7%), respectively, driven primarily by an increase of 8% and 8%, respectively, in crude oil volumes. The increases in sales volumes were 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 increases in revenues from productions were offset somewhat in the second quarter by a decrease in weighted average prices of 5%. 46-------------------------------------------------------------------------------- Table of Contents Products Pipelines Three Months Ended June 30, Six Months Ended June 30, 2014 2013 2014 2013 (In millions, except operating statistics) Revenues $ 524 $ 443 $ 1,058 $ 897 Operating expenses(a) (333 ) (439 ) (672 ) (720 ) Other income (expense)(b) (1 ) (5 ) 2 (5 ) Earnings from equity investments 18 17 35 35 Interest income and Other, net - 2 (1 ) 2 Income tax expense (5 ) (6 ) (11 ) (12 ) EBDA 203 12 411 197 Certain items, net(a)(b) 6 167 2 182 EBDA before certain items $ 209 $ 179 $ 413 $ 379 Change from prior period Increase/(Decrease) Revenues $ 81 18 % $ 161 18 % EBDA before certain items $ 30 17 % $ 34 9 % Gasoline (MMBbl)(c) 112.8 105.6 215.7 203.4 Diesel fuel (MMBbl) 38.8 36.8 74.6 69.6 Jet fuel (MMBbl) 29.4 27.7 56.8 54.9 Total refined product volumes (MMBbl)(d) 181.0 170.1 347.1 327.9 NGL (MMBbl)(e) 6.2 8.0 14.9 17.8 Condensate (MMBbl)(f) 7.8 2.6 12.4 4.6 Total delivery volumes (MMBbl) 195.0 180.7 374.4 350.3 Ethanol (MMBbl)(g) 10.4 9.7 20.1 18.4 ______________ Certain item footnotes (a) Three and six month 2014 amounts include increases in expense of $5 million and $4 million, respectively, associated with a certain Pacific operations litigation matter. Three and six month 2013 amounts include a $162 million increase in operations and maintenance expense associated with certain rate case liability adjustments. Six month 2013 amount also includes a $15 million increase in expense associated with a rate case liability adjustment related to a certain West Coast terminal environmental matter. (b) Three and six month 2014 amounts include a loss of $1 million and a gain of $2 million, respectively, from the sale of propane pipeline line-fill. Three and six month 2013 amounts represent the loss from the write-off of assets at our Los Angeles Harbor West Coast terminal. Other footnotes (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. 47-------------------------------------------------------------------------------- Table of Contents Following is information related to the increases and decreases in both EBDA and revenues before certain items, in the comparable three and six month periods of 2014 and 2013: Three months ended June 30, 2014 versus Three months ended June 30, 2013 EBDA Revenues increase/(decrease) increase/(decrease) (In millions, except percentages) Crude & Condensate Pipeline $ 14 699 % $ 19 417 % Pacific operations 13 20 % 12 12 % Transmix operations 9 176 % 56 26 % Southeast terminal operations 3 16 % 1 5 % Cochin Pipeline (9 ) (52 )% (8 ) (38 )% All others (including eliminations) - - % 1 2 % Total Products Pipelines $ 30 17 % $ 81 18 % ______________ Six months ended June 30, 2014 versus Six months ended June 30, 2013 EBDA Revenues increase/(decrease) increase/(decrease) (In millions, except percentages) Crude & Condensate Pipeline $ 19 289 % $ 42 435 % Transmix operations 12 64 % 107 24 % Pacific operations 10 8 % 14 7 % Southeast terminal operations 5 14 % 6 11 % Cochin Pipeline (14 ) (30 )% (14 ) (26 )% All others (including eliminations) 2 1 % 6 5 % Total Products Pipelines $ 34 9 % $ 161 18 % The primary increases and decreases in our Products Pipelines business segment's EBDA in the comparable three and six month periods of 2014 and 2013 included the following: ? increases of $14 million (699%) and $19 million (289%), respectively, from our Kinder Morgan Crude Oil & Condensate Pipeline, due mainly to increases of 199% and 128%, respectively, in higher pipeline throughput volumes as the facility comes closer to capacity; ? increases of $13 million (20%) and $10 million (8%), respectively, from our Pacific operations, due primarily to higher volumes and margins and higher physical gains; ? increases of $9 million (176%) and $12 million (64%), respectively, from our transmix processing operations, due to higher volumes and margins at various transmix sales plants; ? increases of $3 million (16%) and $5 million (14%), respectively, from our Southeast terminal operations, driven by higher butane blending revenues; and ? decreases of $9 million (52%) and $14 million (30%), respectively, from our Cochin Pipeline, primarily due to lower terminal, storage and petrochemical volumes and associated revenues, as a result of the Cochin Reversal project, which converted the line to northbound condensate service to serve oilsands producers' needs in western Canada. 48-------------------------------------------------------------------------------- Table of Contents Terminals Three Months Ended June 30, Six Months Ended June 30, 2014 2013 2014 2013 (In millions, except operating statistics) Revenues(a) $ 421 $ 344 $ 812 $ 681 Operating expenses(b) (190 ) (169 ) (373 ) (326 ) Other income (expense)(c) (1 ) 29 (2 ) 29 Earnings from equity investments 6 5 11 12 Interest income and Other, net(d) 4 1 5 2 Income tax expense(e) (7 ) (3 ) (6 ) (5 ) EBDA 233 207 447 393 Certain items, net(a)(b)(c)(d)(e) (6 ) (16 ) 8 (15 ) EBDA before certain items $ 227 $ 191 $ 455 $ 378 Change from prior period Increase/(Decrease) Revenues before certain items(a) $ 69 20 % $ 123 18 % EBDA before certain items $ 36 19 % $ 77 20 % Bulk transload tonnage (MMtons)(f) 22.4 22.0 44.0 44.4 Ethanol (MMBbl) 18.6 15.6 35.1 30.8 Liquids leaseable capacity (MMBbl) 72.1 62.1 72.1 62.1 Liquids utilization %(g) 94.8 % 94.5 % 94.8 % 94.5 % ______________ Certain item footnotes (a) Three and six month 2014 amounts include an $8 million increase in revenues from amortization of deferred credits from our APT acquisition. The amortization is related to the valuation of certain customer contracts at fair value in purchase accounting. We are amortizing these deferred credits as noncash adjustments (increases) to revenue over the remaining contract period. (b) Three and six month 2014 amounts include increases in expense of $1 million and $8 million, respectively, and three and six month 2013 amounts include increases in expense of $13 million and $14 million, respectively, all related to hurricane clean-up and repair activities at our New York Harbor and Mid-Atlantic terminals. Three and six month 2014 amounts also include increases in expense of $2 million and $12 million, respectively, primarily associated with a legal liability adjustment related to a certain litigation matter. (c) Six month 2014 amount includes a $1 million casualty indemnification loss, and three and six month 2013 amounts include a $28 million casualty indemnification gain, all related to 2012 hurricane activity at our New York Harbor and Mid-Atlantic terminals. (d) Three and six month 2013 amounts include a $1 million casualty indemnification gain related to 2012 hurricane activity at our New York Harbor and Mid-Atlantic terminals. (e) Three and six month 2014 amounts include decreases in expense (representing tax savings) of $1 million and $5 million, respectively, related to the pre-tax expense amount associated with the litigation matter described in footnote (b). Other footnotes (f) Volumes for acquired terminals are included for all periods and include our proportionate share of joint venture tonnage. (g) The ratio of our actual leased capacity (excluding the capacity of tanks out of service) to our estimated potential capacity. 49-------------------------------------------------------------------------------- Table of Contents Our Terminals business segment includes the transportation, transloading and storing of refined petroleum products, crude oil, condensate (other than those included in our Products Pipelines segment), and bulk products, including coal, petroleum coke, cement, alumina, salt and other bulk chemicals. Following is information related to the increases and decreases in both EBDA and revenues before certain items, in the comparable three and six month periods of 2014 and 2013: Three months ended June 30, 2014 versus Three months ended June 30, 2013 EBDA Revenues increase/(decrease) increase/(decrease) (In millions, except percentages) Acquired assets and businesses $ 16 n/a $ 28 n/a Gulf Central 7 210 % 12 997 % West 6 42 % 10 33 % Gulf Liquids 3 4 % 3 4 % Gulf Bulk 1 4 % 3 9 % All others (including intrasegment eliminations and unallocated income tax expenses) 3 3 % 13 6 % Total Terminals $ 36 19 % $ 69 20 % ______________ Six months ended June 30, 2014 versus Six months ended June 30, 2013 EBDA Revenues increase/(decrease) increase/(decrease) (In millions, except percentages) Acquired assets and businesses $ 29 n/a $ 50 n/a West 13 39 % 20 32 % Gulf Liquids 12 12 % 11 8 % Gulf Central 11 162 % 21 994 % Gulf Bulk 6 18 % 10 15 % All others (including intrasegment eliminations and unallocated income tax expenses) 6 3 % 11 3 % Total Terminals $ 77 20 % $ 123 18 % The primary increases and decreases in our Terminals business segment's EBDA in the comparable three and six month periods of 2014 and 2013 included the following: ? increases $16 million and $29 million, respectively, from acquired assets and businesses, primarily the marine operations we acquired effective January 17, 2014 (our APT acquisition); ? increases of $7 million (210%) and $11 million (162%), respectively, from our Gulf Central terminals, driven by higher earnings from our approximately 55%-owned BOSTCO oil terminal joint venture, which is located on the Houston Ship Channel and began operations in October 2013; ? increases of $6 million (42%) and $13 million (39%), respectively, from our West region terminals, driven by the completion of expansion projects since the end of the second quarter of 2013; ? increases of $3 million (4%) and $12 million (12%), respectively, from our Gulf Liquids terminals, 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 completed expansion projects since the end of the second quarter of 2013; and ? increases of $1 million (4%) and $6 million (18%), respectively, from our Gulf Bulk terminals, driven by higher volumes in 2014, due in large part to refinery and coker shutdowns in 2013 as a result of turnarounds taken. 50-------------------------------------------------------------------------------- Table of Contents Kinder Morgan Canada Three Months Ended June 30, Six Months Ended June 30, 2014 2013 2014 2013 (In millions, except operating statistics) Revenues $ 68 $ 75 $ 137 $ 147 Operating expenses (24 ) (27 ) (48 ) (52 ) Earnings from equity investments - - - 4 Interest income and Other, net(a) (1 ) 11 6 241 Income tax expense(b) (3 ) (9 ) (7 ) (97 ) EBDA 40 50 88 243 Certain items, net(a)(b) - - - (141 ) EBDA before certain items $ 40 $ 50 $ 88 $ 102 Change from prior period Increase/(Decrease) Revenues $ (7 ) (9 )% $ (10 ) (7 )% EBDA before certain items $ (10 ) (20 )% $ (14 ) (14 )% Transport volumes (MMBbl)(c) 27.0 26.8 51.9 53.6 ______________Certain item footnotes (a) Six month 2013 amount includes a gain of $225 million from the sale of our equity and debt investments in the Express pipeline system. (b) Six month 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). Other footnote (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 pipeline system. Following is information related to the increases and decreases in both EBDA and revenues before certain items, in the comparable three and six month periods of 2014 and 2013: Three months ended June 30, 2014 versus Three months ended June 30, 2013 EBDA Revenues increase/(decrease) increase/(decrease) (In millions, except percentages) Express Pipeline(a) $ (11 ) (194 )% n/a n/a Trans Mountain Pipeline 1 1 % $ (7 ) (9 )% Total Kinder Morgan Canada $ (10 ) (20 )% $ (7 ) (9 )% ______________ Six months ended June 30, 2014 versus Six months ended June 30, 2013 EBDA Revenues increase/(decrease) increase/(decrease) (In millions, except percentages) Express Pipeline(a) $ (11 ) (103 )% n/a n/a Trans Mountain Pipeline (3 ) (4 )% $ (10 ) (7 )% Total Kinder Morgan Canada $ (14 ) (14 )% $ (10 ) (7 )% ______________(a) Amount consists of foreign currency losses, net of tax, on outstanding, short-term intercompany borrowings. The increase of $1 million (1%) for the comparable quarterly periods from Trans Mountain's earnings was due to minor changes in volumes. The decrease of $3 million (4%) for the comparable six month periods from Trans Mountain's earnings was driven by an unfavorable impact from foreign currency translation. Due to the weakening of the Canadian 51-------------------------------------------------------------------------------- Table of Contents dollar since the end of the second quarter of 2013, we translated Canadian denominated income and expense amounts into fewer U.S. dollars in 2014. Other Three Months Ended June 30, Six Months Ended June 30, 2014 2013 2014 2013 (In millions) General and administrative expenses(a) $ 132 $ 163 $ 285 $ 297 Interest expense, net of unallocable interest income(b) $ 231 $ 215 $ 470 $ 417 Unallocable income tax expense $ 4 $ 3 $ 6 $ 6 Net income attributable to noncontrolling interests(c) $ 8 $ 10 $ 16 $ 19 ______________Certain item footnotes (a) The three month amount for 2013 includes certain items of $32 million. The six month amounts for 2014 and 2013 include certain items of $6 million and $46 million, respectively. These increases in expense from certain items are primarily related to 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), and for 2013, to both business acquisition expenses and increases in expense attributable to our drop-down asset groups for periods prior to our acquisition dates. (b) The three month amounts for 2014 and 2013 each are decreased by certain items of $2 million, associated with debt fair value adjustments recorded in purchase accounting for our Copano acquisition. The six month amounts for 2014 and 2013 include certain items of $9 million and $13 million, respectively. The six month 2014 certain item amount primarily related to incremental interest expense associated with a certain Pacific operations litigation matter, and the six month 2013 certain item amount was largely related to incremental interest expense attributable to our March 2013 drop-down asset group for periods prior to our March 1, 2013 acquisition date. (c) Three and six month 2014 amounts include a $1 million decrease, and three and six month 2013 amounts include increases of $3 million and $5 million, respectively, in net income attributable to our noncontrolling interests, related to the combined effect from all of the three and six month 2014 and 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. For the three and six months ended June 30, 2014, the certain items described in footnote (a) to the table above accounted for decreases of $32 million and $40 million, respectively, in our general and administrative expenses, when compared to the same two periods a year ago. The remaining $1 million (1%) and $28 million (11%) period-to-period increases in expense were 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 expenses. 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 net interest expense increased $16 million (7%) and $57 million (14%), respectively, in the second quarter and first six months of 2014, when compared to the same year-earlier periods. The increases were driven by higher average debt levels. 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 June 30, 2014 and December 31, 2013, approximately 28% and 29%, 52-------------------------------------------------------------------------------- Table of Contents 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 June 30, 2014, we had $263 million of "Cash and cash equivalents" on our consolidated balance sheet, a decrease of $141 million (35%) from December 31, 2013. We also had, as of June 30, 2014, approximately $1.8 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 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 CO2 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 June 30, 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 June 30, 2014 and December 31, 2013, we had no outstanding credit facility borrowings. Our outstanding short-term debt as of June 30, 2014 was $1,337 million, primarily consisting of (i) $513 million of outstanding commercial paper borrowings; (ii) $500 million in principal amount of 5.125% senior notes that mature 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. As of December 31, 2013, our short-term debt totaled $1,504 million. We had a working capital deficit of $2,018 million as of June 30, 2014, and a working capital deficit of $1,909 million as of December 31, 2013. The overall $109 million (6%) unfavorable change from year-end 2013 was primarily due to both lower cash balances (described above) and higher "Other current liabilities," and partly offset by lower outstanding short-term debt (described above, and driven by lower commercial paper borrowings). The period-to-period increase in current liabilities was due largely to higher fair values on short-term commodity hedging derivative contract liabilities and 53-------------------------------------------------------------------------------- Table of Contents to higher short-term legal and litigation 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 half 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 June 30, 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 June 30, 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 half of 2014 and our consolidated debt obligations as of both June 30, 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 from that which existed immediately prior to the addition or improvement, and are not deducted in calculating cash from operations. With respect to our oil and gas producing activities, we classify a capital expenditure as an expansion capital expenditure if it is expected to increase capacity or throughput (i.e. production capacity) from the capacity or throughput immediately prior to the making or acquisition of such additions or improvements. 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, irrespective of the amount by which the throughput or capacity is increased. 54-------------------------------------------------------------------------------- Table of Contents Budgeting of maintenance capital expenditures is done annually on a bottom up basis. For each of our assets, we budget for and make those maintenance capital expenditures that are necessary to maintain safe and efficient operations, meet customer needs and comply with our operating policies and applicable law. We may budget for and make additional maintenance capital expenditures that we expect to produce economic benefits such as increasing efficiency and/or lowering future expenses. Budgeting and approval of capital additions and improvements are generally made periodically throughout the year on a project by project basis in response to specific investment opportunities identified by our business segments from which we generally expect to receive sufficient returns to justify the expenditures. 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 six months ended June 30, 2014, and the amount we expect to spend for the remainder of 2014 to grow and sustain our businesses are as follows: Six Months Ended 2014 June 30, 2014 Remaining Total (In millions) Sustaining(a) $ 171 $ 271 $ 442 Discretionary(b)(c) 1,484 2,471 3,955 Total $ 1,655 $ 2,742 $ 4,397 ______________(a) Six month 2014 amount, 2014 remaining amount, and total 2014 amount include $3 million, $3 million and $6 million, respectively, for our proportionate share of sustaining capital expenditures of our unconsolidated joint ventures. (b) Six month 2014 amount (i) includes $117 million of discretionary capital expenditures of our unconsolidated joint ventures and acquisitions; and (ii) excludes a combined $123 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 to 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 six months ended June 30, 2014 and 2013, these amounts totaled $1,658 million and $1,268 million, respectively. The overall $390 million (31%) period-to-period increase in our consolidated capital expenditures in the first half of 2014 versus the first half of 2013 was primarily due to higher investment undertaken to expand and improve our Products Pipelines business segment. However, all five of our business segments reported higher capital expenditures in the first six months of 2014, when compared to the same period in 2013. 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 seeking authorization to build and operate the necessary facilities for the proposed expansion project. The NEB issued a hearing order for the proposed project in July 2014, and we expect an NEB decision in January 2016. If approvals are received as planned, we expect to begin construction in 2016 and begin operations in 2018. Failure to secure NEB approval on reasonable terms could require us to either delay or cancel this project. Our current estimate of total construction costs on the project is approximately $5.4 billion. In March 2014, we announced that we will build and operate a new, 213-mile, 16-inch diameter pipeline in Torrance County, New Mexico to transport carbon dioxide from our St. Johns source field (located in Apache County, Arizona) to 55-------------------------------------------------------------------------------- Table of Contents our 50%-owned Cortez Pipeline (which we operate). 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, 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 Except as set forth below, 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. As described in Note 8 "Related Party Transactions-Other Commitments," one of our wholly owned subsidiaries is committed to contribute $175 million to one of our unconsolidated subsidiaries during 2014. Cash Flows Operating Activities Net cash provided by operating activities was $2,249 million for the first half of 2014, versus $1,742 million in the first half of 2013. The period-to-period increase of $507 million (29%) in cash flow from operations consisted of the following: ? a $389 million increase in cash from overall higher partnership income-after adjusting our period-to-period $379 million decrease in net income (discussed above in "-Results of Operations") for the following four non-cash items: (i) a $558 million increase from the 2013 gain on the remeasurement of our previous 50% equity investment in Eagle Ford Gathering to its fair value; (ii) a $225 million increase from the 2013 gain on the sale of our investments in Express (see the discussion of these investments in Note 2 "Acquisitions and Divestitures" to our consolidated financial statements); (iii) a $126 million increase due to higher DD&A expenses (including amortization of excess cost of equity investments); and (iv) a $141 million decrease from expenses associated with adjustments to accrued legal liabilities, primarily related to incremental adjustments recorded in the first half of 2013 related to both our West Coast Products Pipelines' interstate and California intrastate transportation rate case liabilities and our West Coast terminals' legal liabilities; ? a $160 million increase in cash due to favorable changes in the collection and payment of trade and related party receivables and payables, due primarily to the timing of invoices received from customers and paid to vendors and suppliers; ? a $96 million decrease in cash from interest rate swap termination payments. In the first half of 2013, in separate transactions, we terminated three existing fixed-to-variable interest rate swap agreements prior to their contractual maturity dates; and ? a $54 million increase in cash from the combined net activity of our equity method investees and the net changes in all other operating assets and liabilities. The increase was driven by, among other things, higher period-to-period cash inflows from both favorable changes in previously deferred reimbursable costs and expenses, and higher non-cash losses related to commodity hedging activities. The overall increase in cash from operating net assets was 56-------------------------------------------------------------------------------- Table of Contents partly offset by lower cash flows from both natural gas storage and pipeline transportation system balancing, and accrued tax liabilities. Investing Activities Net cash used in investing activities was $2,675 million for the six month period ended June 30, 2014, compared to $2,174 million in the comparable 2013 period. The $501 million (23%) decrease in cash due to higher cash expended for investing activities was primarily attributable to the following: ? a $707 million decrease in cash due to higher expenditures for the acquisition of assets and investments from unrelated parties. The overall increase was primarily related to the $961 million we paid in the first half of 2014 for our APT acquisition, versus the $280 million we paid in the first half of 2013 to acquire the Goldsmith Landreth San Andres oil field unit. For more information about our asset acquisitions during the first six months of 2014 and 2013, see Note 2 "Acquisitions and Divestitures-Acquisitions" to our consolidated financial statements; ? a $403 million decrease in cash due to the net proceeds we received in the first half of 2013 from the sale of our investments in the Express pipeline system; ? a $390 million decrease in cash due to higher capital expenditures in the first half of 2014, as described above in "-Capital Expenditures;" and ? a $994 million increase in cash due to the payments we made to KMI in the first half of 2013 to acquire our March 2013 drop-down asset group. Financing Activities Net cash provided by financing activities amounted to $289 million for the first half of 2014, and $579 million for the first half of 2013. The $290 million (50%) overall decrease in cash from all of our financing activities in the first half of 2014 versus the first half of 2013 was primarily attributable to the following: ? a $326 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 $1,813 million in the first half of 2014, compared to $1,487 million in the first half 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;" ? a $42 million decrease in cash due to lower net contributions from noncontrolling interests, chiefly due to the $73 million we received from our BOSTCO partners in the first half of 2013 for their proportionate share of the joint venture's oil terminal construction costs; and ? a $128 million increase in cash due to higher partnership equity issuances. This increase reflects the combined $1,035 million we received, after commissions and underwriting expenses, from issuing additional common and i-units during the first half of 2014 (discussed in Note 4 "Partners' Capital-Equity Issuances" to our consolidated financial statements), versus the $907 million we received from the sales of additional common units and i-units in the first half of 2013. The proceeds we received from equity issuances in the first six months of 2013 primarily consisted of $449 million from the issuance of common units pursuant to our equity distribution agreement with UBS, and $385 million from the public offering of 4,600,000 common units completed on February 26, 2013. 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 declared and paid in the three and six months ended June 30, of 2014 and 2013, see Note 4 "Partners' Capital-Partnership Distributions" to our consolidated financial statements. On July 16, 2014, we declared a cash distribution of $1.39 per unit for the second quarter of 2014 compared to the $1.32 per unit distribution we declared for the second 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 57-------------------------------------------------------------------------------- Table of Contents distribution in conjunction with both our May 2013 Copano acquisition and our January 2014 APT acquisition, our declared distribution for the second quarter of 2014 of $1.39 per unit will result in an incentive distribution to our general partner of $463 million. Comparatively, our distribution of $1.32 per unit paid on August 14, 2013 for the second quarter of 2013 resulted in an incentive distribution payment to our general partner in the amount of $416 million (and included the effect of a waived incentive distribution amount of $25 million related to our May 2013 Copano acquisition). The increased incentive distribution to our general partner for the second quarter of 2014 over the incentive distribution for the second quarter of 2013 reflects the increase in the distribution per unit as well as the issuance of additional units. For additional information about our second 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. Although the majority of the cash generated by our assets is fee based and is not sensitive to commodity prices, our CO2 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 $102.71 per barrel in 2014. For 2014, we expect that every $1 change in the average WTI crude oil price per barrel will impact our CO2 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. |