The accompanying notes are an integral part of these consolidated financial statements.
KINDER MORGAN, INC. AND SUBSIDIARIES
Our reporting currency is U.S. dollars, and all references to “dollars” are U.S. dollars, unless stated otherwise. Our accompanying unaudited consolidated financial statements have been prepared under the rules and regulations of the U.S. Securities and Exchange Commission (SEC). These rules and regulations conform to the accounting principles contained in the FASB’s Accounting Standards Codification (ASC), the single source of GAAP. UnderIn compliance with such rules and regulations, all significant intercompany items have been eliminated in consolidation.
In our opinion, all adjustments, which are of a normal and recurring nature, considered necessary for a fair statement of our financial position and operating results for the interim periods have been included in the accompanying consolidated financial statements, and certain amounts from prior periods have been reclassified to conform to the current presentation. 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 20182019 Form 10-K.
The accompanying unaudited consolidated financial statements include our accounts and the accounts of our subsidiaries over which we have control or are the primary beneficiary. We evaluate our financial interests in business enterprises to determine if they represent variable interest entities where we are the primary beneficiary. If such criteria are met, we consolidate the financial statements of such businesses with those of our own.
We calculate earnings per share using the two-class method. Earnings were allocated to Class P shares and participating securities based on the amount of dividends paid in the current period plus an allocation of the undistributed earnings or excess distributions over earnings to the extent that each security participates in earnings or excess distributions over earnings. Our unvested restricted stock awards, which may be restricted stock or restricted stock units issued to employees and non-employee directors and which include dividend equivalent payments, do not participate in excess distributions over earnings.
The following table sets forth the allocation of net income available to shareholders of Class P shares and participating securities (in millions):
2. Impairments
During the first quarter of 2020, the decrease in the worldwide demand for crude oil primarily due to COVID-19 and sharp decline in commodity prices related to the combined impact of falling demand and recent increases in production from OPEC members and other international suppliers resulted in decreases in current and expected long-term crude oil and NGL sale prices, along with reductions to the market capitalization of peer companies in the energy industry. We determined that these conditions represented a triggering event that required us to perform impairment testing of certain businesses that are sensitive to commodity prices. As a result, we performed an impairment analysis of long-lived assets within our CO2 business segment and conducted interim tests of the recoverability of goodwill for our CO2 and Natural Gas Pipelines Non-Regulated reporting units as of March 31, 2020.
Long-lived Assets
For our CO2 assets, the long lived asset impairment test involved a Step 1 assessment as to whether each asset’s net book value is expected to be recovered from the estimated undiscounted future cash flows.
To compute estimated future cash flows for our oil and gas producing properties, we used our reserve engineer’s estimates of proved and risk adjusted probable reserves. These estimates of proved and probable reserves are based upon historical performance along with adjustments for expected crude oil and natural gas field development. In calculating future cash flows, management utilized estimates of commodity prices based on a March 31, 2020 NYMEX forward curve adjusted for the impact of our existing sales contracts to determine the applicable net crude oil and NGL pricing for each property. Operating expenses were determined based on estimated fixed and variable field production requirements, and capital expenditures were based on economically viable development projects.
| |
| • | To compute estimated future cash flows for our CO2 source and transportation assets, volume forecasts were developed based on projected demand for our CO2 services based upon management’s projections of the availability of CO2 supply and the future demand for CO2 for use in enhanced oil recovery projects. The CO2 pricing assumption was a function of the March 31, 2020 NYMEX forward curve adjusted for the impact of existing sales contracts to determine the applicable net CO2 pricing. Operating expenses were determined based on estimated fixed and variable field production requirements, and capital expenditures were based on economically viable development projects. |
Certain oil and gas properties failed the first step. For these assets, we used a discounted cash flow analysis to estimate fair value. We applied a 10.5% discount rate, which we believe represents the estimated weighted average cost of capital of a
theoretical market participant. Based on step two of our long lived assets impairment test, we recognized $350 million of impairments on those oil and gas producing properties where the total carrying value exceeded its total estimated fair market value as of March 31, 2020.
Goodwill
The following goodwill impairment test for our CO2 and Natural Gas Pipelines Non-Regulated reporting units reflects our adoption of the Accounting Standards Updates (ASU) No. 2017-04, “Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment” on January 1, 2020. This new accounting method simplifies the goodwill impairment test by removing Step 2 of the goodwill impairment test, which required a hypothetical purchase price allocation.
For our CO2 and Natural Gas Pipelines Non-Regulated reporting units, we applied an income approach to evaluate the fair value of these reporting units based on the present value of cash flows these reporting units are expected to generate in the future. Due to the uncertainty and volatility in market conditions within our peer group as of the test date, we did not incorporate the market approach to estimate fair value as of March 31, 2020.
| |
| • | In determining the fair value for our CO2 reporting unit, we applied a 9.25% discount rate to the undiscounted cash flow amounts computed in the long-lived asset impairment analyses described above. The discount rate we used represents our estimate of the weighted average cost of capital of a theoretical market participant. The result of our goodwill analysis was a partial impairment of goodwill in our CO2 reporting unit of approximately $600 million as of March 31, 2020. |
For our Natural Gas Pipelines Non-Regulated reporting unit, the income approach we used to determine fair value included an analysis of estimated discounted cash flows based on 6 years of projections and application of a year 6 exit multiple based on management’s expectations of a discount rate and exit multiple that would be applied by a theoretical market participant and for market transactions of comparable assets. The discounted cash flows included various assumptions on volumes and prices for each underlying asset within the reporting unit including, as applicable, current commodity prices. The results of our impairment analysis for our Natural Gas Pipelines Non-Regulated reporting unit did not indicate an impairment of goodwill with the reporting unit’s fair value in excess of its carrying value by less than 10% as of March 31, 2020.
We consider the inputs for our long-lived asset and goodwill impairment calculations to be Level 3 inputs in the fair value hierarchy.
We recognized the following non-cash pre-tax losses (gains) on impairments and divestitures on assets (in millions):
|
| | | | | | | |
| | Three Months Ended March 31, |
| | 2020 | | 2019 |
| Products Pipelines | | | |
| Impairments of long-lived and intangible assets(a) | $ | 21 |
| | $ | — |
|
CO2 | | | |
| Impairments of long-lived assets | 350 |
| | — |
|
| Impairment of goodwill | 600 |
| | — |
|
| Kinder Morgan Canada | | | |
| Losses on divestiture of long-lived assets | — |
| | 2 |
|
| Other gains on divestitures of long-lived assets | — |
| | (2 | ) |
| Pre-tax losses on divestitures and impairments, net | $ | 971 |
| | $ | — |
|
_______
| |
| (a) | The holder of each convertible preferred share participated in2020 impairment amount is associated with our earnings by receiving preferred stock dividends through the mandatory conversion date of October 26, 2018, at which time our convertible preferred shares were converted to common shares.Belton terminal. |
Economic disruptions resulting from events such as COVID-19, conditions in the business environment generally, such as sustained low crude oil demand and continued low commodity prices, supply disruptions, or higher development or production costs, could result in a slowing of supply to our pipelines, terminals and other assets, which will have an adverse effect on the demand for services provided by our four business segments. Financial distress experienced by our customers or other counterparties could have an adverse impact on us in the event they are unable to pay us for the products or services we provide or otherwise fulfill their obligations to us. In addition, the revenues, cash flows, profitability and future growth of some of our
businesses depend to a large degree on prevailing crude oil, NGL and natural gas prices. Our CO2 business segment (and the carrying value of our crude oil, NGL and natural gas producing properties) and certain midstream businesses within our Natural Gas Pipelines business segment depend to a large degree, and certain businesses within our Product Pipelines business segment depend to a lesser degree, on prevailing crude oil, NGL and natural gas prices.
As conditions warrant, we routinely evaluate our assets for potential triggering events such as those described above that could impact the fair value of certain assets or our ability to recover the carrying value of long-lived assets. Such assets include accounts receivable, equity investments, goodwill, other intangibles and property plant and equipment, including oil and gas properties and in-process construction. Depending on the nature of the asset, these evaluations require the use of significant judgments including but not limited to judgments related to customer credit worthiness, future volume expectations, current and future commodity prices, discount rates, regulatory environment, as well as general economic conditions and the related demand for products handled or transported by our assets. In the current worldwide economic and commodity price environment and to the extent conditions further deteriorate, we may identify additional triggering events that may require future evaluations of the recoverability of the carrying value of our long-lived assets, investments and goodwill which could result in further impairment charges. In addition, we are required to perform our annual goodwill impairment test on May 31st. Because certain of our assets have been written down to fair value, any deterioration in fair value could result in further impairments. Such non-cash impairments could have a significant effect on our results of operations, which would be recognized in the period in which the carrying value is determined to not be recoverable.
2. Divestiture3. Debt
Sale of Trans Mountain Pipeline System and Its Expansion Project
On August 31, 2018, KML completed the sale of the TMPL, the TMEP, Puget Sound pipeline system and Kinder Morgan Canada Inc., the Canadian employer of our staff that operate the business, which were indirectly acquired by the Government of Canada through Trans Mountain Corporation (a subsidiary of the Canada Development Investment Corporation) for net cash consideration of C$4.43 billion (U.S.$3.4 billion), net of working capital adjustments (TMPL Sale). Additionally, during the three months ended March 31, 2019, KML settled the remaining C$37.0 million (U.S.$28 million) of working capital adjustments, which amount is included in the accompanying consolidated statement of cash flows within “Sales of assets and equity investments, net of working capital settlements” for the three months ended March 31, 2019 and for which we had substantially accrued for as of December 31, 2018.
On January 3, 2019, KML distributed the net proceeds from the TMPL Sale to its shareholders as a return of capital. Public owners of KML’s restricted voting shares, reflected as noncontrolling interests by us, received approximately $0.9 billion (C$1.2 billion), and most of our approximate 70% portion of the net proceeds of $1.9 billion (C$2.5 billion) (after Canadian tax) were used to repay our outstanding commercial paper borrowings of $0.4 billion, and in February 2019, to pay down approximately $1.3 billion of maturing long-term debt.
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.
The following table provides additional information on the principal amount of our outstanding debt balances. The table amounts exclude all debt fair value adjustments, including debt discounts, premiums and issuance costsbalances (in millions):
| | | | March 31, 2019 | | December 31, 2018 | March 31, 2020 | | December 31, 2019 |
| Current portion of debt | | | | | | |
| $500 million, 364-day credit facility due November 15, 2019 | $ | — |
| | $ | — |
| |
| $4 billion credit facility due November 16, 2023 | — |
| | — |
| $ | — |
| | $ | — |
|
| Commercial paper notes(a) | 109 |
| | 433 |
| — |
| | 37 |
|
| KML $500 million credit facility, due August 31, 2022(b)(c) | 38 |
| | — |
| |
| Current portion of senior notes | | | | | | |
| 9.00%, due February 2019 | — |
| | 500 |
| |
| 2.65%, due February 2019 | — |
| | 800 |
| |
| 3.05%, due December 2019 | 1,500 |
| | 1,500 |
| |
| 6.85%, due February 2020 | 700 |
| | — |
| |
| 6.85%, due February 2020(b) | | — |
| | 700 |
|
| 6.50%, due April 2020(c) | | 535 |
| | 535 |
|
| 5.30%, due September 2020 | | 600 |
| | 600 |
|
| 6.50%, due September 2020 | | 349 |
| | 349 |
|
| 5.00%, due February 2021 | | 750 |
| | — |
|
| 3.50%, due March 2021 | | 750 |
| | — |
|
| 5.80%, due March 2021 | | 400 |
| | — |
|
| Trust I preferred securities, 4.75%, due March 2028 | 111 |
| | 111 |
| 111 |
| | 111 |
|
| Current portion - Other debt | 44 |
| | 44 |
| |
| Kinder Morgan G.P. Inc, $1,000 Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock, due August 2057(d) | | — |
| | 100 |
|
| Current portion of other debt | | 45 |
| | 45 |
|
| Total current portion of debt | 2,502 |
| | 3,388 |
| 3,540 |
| | 2,477 |
|
| | | | | | | |
| Long-term debt (excluding current portion) | | | | | | |
| Senior notes | 31,649 |
| | 32,380 |
| 29,242 |
| | 30,164 |
|
| EPC Building, LLC, promissory note, 3.967%, due 2017 through 2035 | 405 |
| | 409 |
| |
| Kinder Morgan G.P. Inc., $1,000 Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock | 100 |
| | 100 |
| |
| EPC Building, LLC, promissory note, 3.967%, due 2020 through 2035 | | 377 |
| | 381 |
|
| Trust I preferred securities, 4.75%, due March 2028 | 110 |
| | 110 |
| 110 |
| | 110 |
|
| Other | 204 |
| | 206 |
| 226 |
| | 228 |
|
| Total long-term debt | 32,468 |
| | 33,205 |
| 29,955 |
| | 30,883 |
|
| Total debt(d) | $ | 34,970 |
| | $ | 36,593 |
| |
| Total debt(e) | | $ | 33,495 |
| | $ | 33,360 |
|
_______
| |
| (a) | Weighted average interest ratesrate on borrowings outstanding as of MarchDecember 31, 2019 and December 31, 2018 were 2.75% and 3.10%, respectively.was 1.90%. |
| |
| (b) | Weighted average interest rate on borrowings outstandingOn January 9, 2020, we sold the approximate 25 million shares of Pembina Pipeline Corporation (Pembina) common equity that we received as consideration for the sale of KML. We received proceeds of approximately $907 million ($764 million after tax) for the sale of the Pembina shares, which were used to repay debt that matured in February 2020. The fair value of the Pembina common equity of$925 million as of MarchDecember 31, 2019 was 3.42%.reported as “Marketable securities at fair value” in the accompanying consolidated balance sheet. |
| |
| (c) | Borrowings under the KML 2018 Credit Facility are denominated in C$ and are converted to U.S. dollars. AtAs of March 31, 2020, funds for the repayment of these maturing notes, and associated accrued interest, were held in escrow and included in the accompanying consolidated balance sheet within “Restricted deposits.”
|
| |
| (d) | In December 2019, we notified the exchange rateholder of our intent to redeem these securities. As our notification was 0.7483 U.S. dollars per C$. See “—Credit Facilities” below.irrevocable, the outstanding balance was classified as current in our accompanying consolidated balance sheet as of December 31, 2019. We redeemed these securities, including accrued dividends, on January 15, 2020. |
| |
(d)(e) | Excludes our “Debt fair value adjustments” which, as of March 31, 20192020 and December 31, 2018,2019, increased our combinedtotal debt balances by $860$1,450 million and $731$1,032 million, respectively. In addition to all unamortized debt discount/premium amounts, debt issuance costs and purchase accounting on our debt balances, our debt fair value adjustments also include amounts associated with the offsetting entry for hedged debt and any unamortized portion of proceeds received from the early termination of interest rate swap agreements. |
We and substantially all of our wholly owned domestic subsidiaries are parties to a cross guarantee agreement whereby each party to the agreement unconditionally guarantees, jointly and severally, the payment of specified indebtedness of each other party to the agreement. Also, see Note 13.
On February 24, 2020, TGP, a wholly owned subsidiary, issued in a private placement $1,000 million aggregate principal amount of its 2.90% senior notes due 2030 and received net proceeds of $994 million. These notes are guaranteed through the cross guarantee agreement discussed above.
Credit FacilitiesFacility
KMI
As of March 31, 2019,2020, we had no0 borrowings outstanding under our $4.0 billion credit facilities, $109 millionfacility, 0 borrowings outstanding under our $4 billion commercial paper program and $84$83 million in letters of credit. Our availability under these facilitiesour credit facility as of March 31, 20192020 was $4,307$3,917 million. As of March 31, 2019,2020, we were in compliance with all required covenants.
KMLFair Value of Financial Instruments
AsThe carrying value and estimated fair value of our outstanding debt balances are disclosed below (in millions):
|
| | | | | | | | | | | | | | | |
| | March 31, 2020 | | December 31, 2019 |
| | Carrying value | | Estimated fair value | | Carrying value | | Estimated fair value |
| Total debt | $ | 34,945 |
| | $ | 34,198 |
| | $ | 34,392 |
| | $ | 38,016 |
|
We used Level 2 input values to measure the estimated fair value of our outstanding debt balance as of both March 31, 2019, KML had C$50 million (U.S.$38 million) borrowings outstanding under its 4-year, C$500 million unsecured revolving credit facility, due August 31, 2022, with C$444 million (U.S.$331 million) available after reducing the C$500 million (U.S.$374 million) capacity for the C$6 million (U.S.$5 million) in letters of credit. Of the total C$6 million of letters of credit issued, approximately C$3 million are related to Trans Mountain for which it has issued a backstop letter of
credit to KML. As of March 31, 2019, KML was in compliance with all required covenants. As of2020 and December 31, 2018, KML had no borrowings outstanding under its credit facility.2019.
4. Stockholders’ Equity
Common Equity
As of March 31, 2019, our common equity consisted of our Class P common stock. For additional information regarding our Class P common stock, see Note 11 to our consolidated financial statements included in our 2018 Form 10-K.Common Stock
On July 19, 2017, our board of directors approved a $2 billion common share buy-back program that began in December 2017. During the three months ended March 31, 2019,2020, we settled repurchases ofrepurchased approximately 0.13.6 million of our Class P shares for approximately $2 million.$50 million at an average price of approximately $13.94 per share. Since December 2017, in total, we have repurchased approximately 2932 million of our Class P shares under the program at an average price of approximately $17.71 per share for approximately $525$575 million.
KMI For additional information regarding our Class P common stock, see Note 11 to our consolidated financial statements included in our 2019 Form 10-K.
Common Stock Dividends
Holders of our common stock participate in common stock dividends declared by our board of directors, subject to the rights of the holders of any outstanding preferred stock. The following table provides information about our per share dividends:
|
| | | | | | | |
| | Three Months Ended March 31, |
| | 2020 | | 2019 |
| Per common share cash dividend declared for the period | $ | 0.2625 |
| | $ | 0.25 |
|
| Per common share cash dividend paid in the period | 0.25 |
| | 0.20 |
|
|
| | | | | | | |
| | Three Months Ended March 31, |
| | 2019 | | 2018 |
| Per common share cash dividend declared for the period | $ | 0.25 |
| | $ | 0.20 |
|
| Per common share cash dividend paid in the period | $ | 0.20 |
| | $ | 0.125 |
|
On April 17, 2019,22, 2020, our board of directors declared a cash dividend of $0.25$0.2625 per common share for the quarterly period ended March 31, 2019,2020, which is payable on May 15, 20192020 to common shareholders of record as of the close of business on April 30, 2019.May 4, 2020.
Noncontrolling Interests
KML Distributions
KML has a dividend policy pursuant to which it may pay a quarterly dividend on its restricted voting shares in an amount based on a portion of its DCF. For additional information regarding our KML distributions, see Note 11 to our consolidated financial statements included in our 2018 Form 10-K.
On January 3, 2019, KML distributed approximately $0.9 billion of the net proceeds from the TMPL Sale to its Restricted Voting Shareholders as a return of capital.
On January 16, 2019, KML’s board of directors suspended KML’s dividend reinvestment plan, which was effective with the payment of the fourth quarter 2018 dividend on February 15, 2019, in light of KML’s reduced need for capital.
During the three months ended March 31, 2019, KML paid dividends to the public on its Restricted Voting Shares and on its Series 1 and Series 3 Preferred Shares of $4 million and $5 million, respectively.
Adoption of Accounting Pronouncements
On January 1, 2018, we adopted ASU No. 2017-05, “Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets.” This ASU clarifies the scope and application of ASC 610-20 on contracts for the sale or transfer of nonfinancial assets and in substance nonfinancial assets to noncustomers, including partial sales. This ASU also clarifies that the derecognition of all businesses is in the scope of ASC 810 and defines an “in substance nonfinancial asset.” We utilized the modified retrospective method to adopt the provisions of this ASU, which required us to apply the new standard to (i) all new contracts entered into after January 1, 2018, and (ii) to contracts that were not completed contracts as of January 1, 2018 through a cumulative adjustment to our “Retained deficit” balance. The cumulative effect of the adoption of this ASU was a $66 million, net of income taxes, adjustment to our “Retained deficit” balance as presented in our consolidated statement of stockholders’ equity for the three months ended March 31, 2018. This ASU also required us to classify EIG
cumulative contribution to ELC as mezzanine equity, which we have included as “Redeemable noncontrolling interest” on our consolidated balance sheets as of March 31, 2019 and December 31, 2018, as EIG has the right to redeem their interests for cash under certain conditions.
On January 1, 2018, we adopted ASU No. 2018-02, “Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income.” Our accounting policy for the releaseLoss
Reporting of stranded tax effects in accumulated otherAmounts Reclassified Out of Accumulated Other Comprehensive Loss
Cumulative revenues, expenses, gains and losses that under GAAP are included within our comprehensive income is on an aggregate portfolio basis. This ASU permits companies to reclassify the income tax effects of the 2017 Tax Reform on items within accumulated other comprehensive income to retained earnings. The FASB refers to these amountsbut excluded from our earnings are reported as “stranded tax effects.” Only the stranded tax effects resulting from the 2017 Tax Reform are eligible for reclassification. The adoption of this ASU resulted in a $109 million reclassification adjustment of stranded income tax effects from “Accumulated other comprehensive loss” to “Retained deficit” onwithin “Stockholders’ Equity” in our consolidated statementbalance sheets. Changes in the components of stockholders’ equity for the three months ended March 31, 2018.our “Accumulated other comprehensive loss” not including non-controlling interests are summarized as follows (in millions):
|
| | | | | | | | | | | | | | | |
| | Net unrealized gains/(losses) on cash flow hedge derivatives | | Foreign currency translation adjustments | | Pension and other postretirement liability adjustments | | Total accumulated other comprehensive loss |
| Balance as of December 31, 2019 | $ | (7 | ) | | $ | — |
| | $ | (326 | ) | | $ | (333 | ) |
| Other comprehensive gain before reclassifications | 222 |
| | 1 |
| | 11 |
| | 234 |
|
| Loss reclassified from accumulated other comprehensive loss | 37 |
| | — |
| | — |
| | 37 |
|
| Net current-period change in accumulated other comprehensive (loss) income | 259 |
| | 1 |
| | 11 |
| | 271 |
|
| Balance as of March 31, 2020 | $ | 252 |
| | $ | 1 |
| | $ | (315 | ) | | $ | (62 | ) |
|
| | | | | | | | | | | | | | | |
| | Net unrealized gains/(losses) on cash flow hedge derivatives | | Foreign currency translation adjustments | | Pension and other postretirement liability adjustments | | Total accumulated other comprehensive loss |
| Balance as of December 31, 2018 | $ | 164 |
| | $ | (91 | ) | | $ | (403 | ) | | $ | (330 | ) |
| Other comprehensive (loss) gain before reclassifications | (215 | ) | | 16 |
| | 8 |
| | (191 | ) |
| Loss reclassified from accumulated other comprehensive loss | 13 |
| | — |
| | — |
| | 13 |
|
| Net current-period change in accumulated other comprehensive income (loss) | (202 | ) | | 16 |
| | 8 |
| | (178 | ) |
| Balance as of March 31, 2019 | $ | (38 | ) | | $ | (75 | ) | | $ | (395 | ) | | $ | (508 | ) |
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 and foreign currency risk as a result of the issuance of our debt obligations and net investments in foreign operations.obligations. Pursuant to our management’s approved risk management policy, we use derivative contracts to hedge or reduce our exposure to some of these risks.
On January 1, 2019,During the three months ended March 31, 2020, we adopted ASU 2017-12, “Derivatives and Hedging (Topic 815): Targeted Improvementsentered into a floating-to-fixed interest rate swap agreement with a notional principal amount of $2,500 million, which was not designated as an accounting hedge. These agreements effectively fixed our LIBOR exposure for a portion of our fixed to Accountingfloating rate interest rate swaps for Hedging Activities.” The ASU better aligns an entity’s risk management activities and financial reporting for hedging relationships2020. As of March 31, 2020, the maximum length of time over which we have hedged a portion of our exposure to the variability in future interest payments is through changes to both the designation and measurement guidance for qualifying hedging relationships and the presentation of hedge results. ASU 2017-12 was applied using a modified retrospective approach for cash flow and fair value hedges existing at the date of adoption and prospectively for the presentation and disclosure guidance. The adoption of ASU 2017-12 did not have a material impact on our consolidated financial statements.December 31, 2020.
Energy Commodity Price Risk Management
As of March 31, 2019,2020, 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 instrumentscontracts | | | |
| Crude oil fixed price | (20.218.9 | ) | | MMBbl |
| Crude oil basis | (12.26.2 | ) | | MMBbl |
| Natural gas fixed price | (55.735.7 | ) | | Bcf |
| Natural gas basis | (35.631.3 | ) | | Bcf |
| NGL fixed price | (0.71.2 | ) | | MMBbl |
Derivatives not designated as hedging instrumentscontracts | |
| | |
| Crude oil fixed price | (0.60.7 | ) | | MMBbl |
| Crude oil basis | (6.12.4 | ) | | MMBbl |
| Natural gas fixed price | (2.117.3 | ) | | Bcf |
| Natural gas basis | (11.023.4 | )
| | Bcf |
| NGL fixed price | (2.61.7 | ) | | MMBbl |
As of March 31, 2019,2020, the maximum length of time over which we have hedged, for accounting purposes, our exposure to the variability in future cash flows associated with energy commodity price risk is through December 2023.
Interest Rate Risk Management
AsWe utilize interest rate derivatives to hedge our exposure to both changes in the fair value of our fixed rate debt instruments and variability in expected future cash flows attributable to variable interest rate payments. The following table summarizes our outstanding interest rate contracts as of March 31, 2019 and December 31, 2018, we had a combined notional principal amount of $10,225 million and $10,575 million, respectively, of fixed-to-variable interest rate swap agreements, all of which were designated as fair value hedges. All of our swap agreements effectively convert the interest expense associated with certain series of senior notes from fixed rates to variable rates based on an interest rate of the London Interbank Offered Rate (LIBOR) plus a spread and have termination dates that correspond to the maturity dates of the related series of senior notes. As of March 31, 2019, the principal amount of hedged senior notes consisted of $2,200 million included in “Current portion of debt” and $8,025 million included in “Long-term debt” on our accompanying consolidated balance sheets. As of March 31, 2019, the maximum length of time over2020 (in millions):
which we have hedged a portion of our exposure to the variability in the value of debt due to interest rate risk is through March 15, 2035. |
| | | | | | | | | | |
| | Notional amount | | Accounting treatment | | Maximum term | |
| Derivatives designated as hedging instruments | | | | | | | | | | |
| Fixed-to-variable interest rate contracts(a) | | $8,025 | | Fair value hedge | | March 2035 | |
| Variable-to-fixed interest rate contracts | | $250 | | Cash flow hedge | | January 2023 | |
| Variable-to-fixed interest rate contracts | | $2,500 | | Mark-to-Market | | December 2020 | |
_______
| |
| (a) | The principal amount of hedged senior notes consisted of $1,300 million included in “Current portion of debt” and $6,725 million included in “Long-term debt” on our accompanying consolidated balance sheet. |
Foreign Currency Risk Management
AsWe utilize foreign currency derivatives to hedge our exposure to variability in foreign exchange rates. The following table summarizes our outstanding foreign currency contracts as of both March 31, 2019 and December 31, 2018, we had a combined notional principal amount of $1,358 million of cross-currency swap agreements to manage the foreign currency risk related to our Euro-denominated senior notes by effectively converting all of the fixed-rate Euro denominated debt, including annual interest payments and the payment of principal at maturity, to U.S. dollar-denominated debt at fixed rates equivalent to approximately 3.79% and 4.67% for the 7-year and 12-year senior notes, respectively.2020 (in millions):
|
| | | | | | | | | | |
| | Notional amount | | Accounting treatment | | Maximum term | |
| Derivatives designated as hedging instruments | | | | | | | | | | |
| EUR-to-USD cross currency swap contracts(a) | | $1,358 | | Cash flow hedge | | March 2027 | |
_______
(a) These cross-currency swaps are accounted for as cash flow hedges. The terms of the cross-currency swap agreements correspond to the related hedged senior notes, and such agreements have the same maturities as the hedged senior notes.
During the year ended December 31, 2018, we entered into foreign currency swap agreements with a combined notional principal amount of C$2,450 million (U.S.$1,888 million). These swaps resulted in our selling fixed C$ and receiving fixed U.S.$, effectively hedgingswaps eliminate the foreign currency risk associated with a substantial portionall of our share of the TMPL Sale proceeds which were held in Canadian dollar denominated accounts until KML’s board and shareholder approved distribution of the proceeds was made on January 3, 2019. At such time, our share of the TMPL Sale proceeds were then transferred into a U.S. dollar denominated account, our exposure to foreign currency risk was eliminated, and our foreign currency swaps were settled. These foreign currency swaps were accounted for as net investment hedges as the foreign currency risk was related to our investment in Canadian dollar denominated foreign operations, and the critical risks of the forward contracts coincided with those of the net investment. As a result, the change in fair value of the foreign currency swaps while outstanding were reflected in the “Cumulative Translation Adjustment” section of Other Comprehensive Income.Euro-denominated debt.
Fair Value of Derivative Contracts
The following table summarizes the fair values of our derivative contracts included in our accompanying consolidated balance sheets (in millions):
|
| | | | | | | | | | | | | | | | | | |
| Fair Value of Derivative Contracts |
| | | | | Derivatives Asset | | Derivatives Liability |
| | | | | March 31,
2020 | | December 31,
2019 | | March 31,
2020 | | December 31,
2019 |
| | | Location | | Fair value | | Fair value |
| Derivatives designated as hedging instruments | | | | | | | | | | |
| Energy commodity derivative contracts | | Fair value of derivative contracts/(Other current liabilities) | | $ | 279 |
| | $ | 31 |
| | $ | (7 | ) | | $ | (43 | ) |
| | | Deferred charges and other assets/(Other long-term liabilities and deferred credits) | | 135 |
| | 17 |
| | — |
| | (8 | ) |
| Subtotal | | | | 414 |
| | 48 |
| | (7 | ) | | (51 | ) |
| Interest rate contracts | | Fair value of derivative contracts/(Other current liabilities) | | 126 |
| | 45 |
| | (2 | ) | | — |
|
| | | Deferred charges and other assets/(Other long-term liabilities and deferred credits) | | 666 |
| | 313 |
| | (9 | ) | | (1 | ) |
| Subtotal | | | | 792 |
| | 358 |
| | (11 | ) | | (1 | ) |
| Foreign currency contracts | | Fair value of derivative contracts/(Other current liabilities) | | — |
| | — |
| | (30 | ) | | (6 | ) |
| | | Deferred charges and other assets/(Other long-term liabilities and deferred credits) | | 11 |
| | 46 |
| | (24 | ) | | — |
|
| Subtotal | | | | 11 |
| | 46 |
| | (54 | ) | | (6 | ) |
| Total | | | | 1,217 |
| | 452 |
| | (72 | ) | | (58 | ) |
| | | | | | | | | | | |
| Derivatives not designated as hedging instruments | | | | |
| | | | |
| | |
| Energy commodity derivative contracts | | Fair value of derivative contracts/(Other current liabilities) | | 43 |
| | 8 |
| | (2 | ) | | (7 | ) |
| | | Deferred charges and other assets/(Other long-term liabilities and deferred credits) | | 4 |
| | — |
| | — |
| | — |
|
| Subtotal | | | | 47 |
| | 8 |
| | (2 | ) | | (7 | ) |
| Interest rate contracts | | Fair value of derivative contracts/(Other current liabilities) | | — |
| | — |
| | (4 | ) | | — |
|
| Subtotal | | | | — |
| | — |
| | (4 | ) | | — |
|
| Total | | | | 47 |
| | 8 |
| | (6 | ) | | (7 | ) |
| Total derivatives | | | | $ | 1,264 |
| | $ | 460 |
| | $ | (78 | ) | | $ | (65 | ) |
|
| | | | | | | | | | | | | | | | | | |
| Fair Value of Derivative Contracts |
| | | | | Derivative Assets | | Derivative Liabilities |
| | | | | March 31,
2019 | | December 31,
2018 | | March 31,
2019 | | December 31,
2018 |
| | | Location | | Fair value | | Fair value |
| Derivatives designated as hedging instruments | | | | | | | | | | |
| Energy commodity derivative contracts | | Fair value of derivative contracts/(Other current liabilities) | | $ | 25 |
| | $ | 135 |
| | $ | (122 | ) | | $ | (45 | ) |
| | | Deferred charges and other assets/(Other long-term liabilities and deferred credits) | | 16 |
| | 64 |
| | (26 | ) | | — |
|
| Subtotal | | | | 41 |
| | 199 |
| | (148 | ) | | (45 | ) |
| Interest rate contracts | | Fair value of derivative contracts/(Other current liabilities) | | 22 |
| | 12 |
| | (26 | ) | | (37 | ) |
| | | Deferred charges and other assets/(Other long-term liabilities and deferred credits) | | 174 |
| | 121 |
| | (24 | ) | | (78 | ) |
| Subtotal | | | | 196 |
| | 133 |
| | (50 | ) | | (115 | ) |
| Foreign currency contracts | | Fair value of derivative contracts/(Other current liabilities) | | — |
| | 91 |
| | (29 | ) | | (6 | ) |
| | | Deferred charges and other assets/(Other long-term liabilities and deferred credits) | | 95 |
| | 106 |
| | — |
| | — |
|
| Subtotal | | | | 95 |
| | 197 |
| | (29 | ) | | (6 | ) |
| Total | | | | 332 |
| | 529 |
| | (227 | ) | | (166 | ) |
| | | | | | | | | | | |
| Derivatives not designated as hedging instruments | | | | |
| | | | |
| | |
| Energy commodity derivative contracts | | Fair value of derivative contracts/(Other current liabilities) | | 10 |
| | 22 |
| | (5 | ) | | (5 | ) |
| | | Deferred charges and other assets/(Other long-term liabilities and deferred credits) | | — |
| | — |
| | (1 | ) | | — |
|
| Total | | | | 10 |
| | 22 |
| | (6 | ) | | (5 | ) |
| Total derivatives | | | | $ | 342 |
| | $ | 551 |
| | $ | (233 | ) | | $ | (171 | ) |
EffectThe following two tables summarize the fair value measurements of Derivative Contractsour derivative contracts based on the Income Statementthree levels established by the ASC (in millions). The tables also identify the impact of derivative contracts which we have elected to present on our accompanying consolidated balance sheets on a gross basis that are eligible for netting under master netting agreements.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Balance sheet asset fair value measurements by level | | | | |
| |
Level 1 | |
Level 2 | |
Level 3 | | Gross amount | | Contracts available for netting | | Cash collateral held(b) | | Net amount |
| As of March 31, 2020 | | | | | | | | | | | | | |
| Energy commodity derivative contracts(a) | $ | 6 |
| | $ | 455 |
| | $ | — |
| | $ | 461 |
| | $ | (9 | ) | | $ | (25 | ) | | $ | 427 |
|
| Interest rate contracts | — |
| | 792 |
| | — |
| | 792 |
| | (2 | ) | | — |
| | 790 |
|
| Foreign currency contracts | — |
| | 11 |
| | — |
| | 11 |
| | (11 | ) | | — |
| | — |
|
| As of December 31, 2019 | |
| | |
| | |
| | | | | | | | |
| Energy commodity derivative contracts(a) | $ | 19 |
| | $ | 37 |
| | $ | — |
| | $ | 56 |
| | $ | (19 | ) | | $ | (21 | ) | | $ | 16 |
|
| Interest rate contracts | — |
| | 358 |
| | — |
| | 358 |
| | — |
| | — |
| | 358 |
|
| Foreign currency contracts | — |
| | 46 |
| | — |
| | 46 |
| | (6 | ) | | — |
| | 40 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Balance sheet liability fair value measurements by level | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Gross amount | | Contracts available for netting | | Cash collateral posted(b) | | Net amount |
| As of March 31, 2020 | | | | | | | | | | | | | |
| Energy commodity derivative contracts(a) | $ | (7 | ) | | $ | (2 | ) | | $ | — |
| | $ | (9 | ) | | $ | 9 |
| | $ | — |
| | $ | — |
|
| Interest rate contracts | — |
| | (15 | ) | | — |
| | (15 | ) | | 2 |
| | — |
| | (13 | ) |
| Foreign currency contracts | — |
| | (54 | ) | | — |
| | (54 | ) | | 11 |
| | — |
| | (43 | ) |
| As of December 31, 2019 | | | | | | | | | | | | | |
| Energy commodity derivative contracts(a) | $ | (3 | ) | | $ | (55 | ) | | $ | — |
| | $ | (58 | ) | | $ | 19 |
| | $ | — |
| | $ | (39 | ) |
| Interest rate contracts | — |
| | (1 | ) | | — |
| | (1 | ) | | — |
| | — |
| | (1 | ) |
| Foreign currency contracts | — |
| | (6 | ) | | — |
| | (6 | ) | | 6 |
| | — |
| | — |
|
_______
| |
| (a) | Level 1 consists primarily of NYMEX natural gas futures. Level 2 consists primarily of OTC WTI swaps, NGL swaps and crude oil basis swaps. |
| |
| (b) | Any cash collateral paid or received is reflected in this table, but only to the extent that it represents variation margins. Any amount associated with derivative prepayments or initial margins that are not influenced by the derivative asset or liability amounts or those that are determined solely on their volumetric notional amounts are excluded from this table. |
The following tables summarize the pre-tax impact of our derivative contracts in our accompanying consolidated statements of incomeoperations and comprehensive (loss) income (in millions):
| | | Derivatives in fair value hedging relationships | | Location | | Gain/(loss) recognized in income
on derivative and related hedged item | | Location | | Gain/(loss) recognized in income
on derivative and related hedged item |
| | | Three Months Ended March 31, | | Three Months Ended March 31, |
| | | 2019 | | 2018 | | 2020 | | 2019 |
| | | | | | | | | |
| Interest rate contracts | | Interest, net | | $ | 128 |
| | $ | (173 | ) | | Interest, net | | $ | 433 |
| | $ | 128 |
|
| | | | | | | | | |
| Hedged fixed rate debt(a) | | Interest, net | | $ | (138 | ) | | $ | 168 |
| | Interest, net | | $ | (440 | ) | | $ | (138 | ) |
_______
| |
| (a) | As of March 31, 2019,2020, the cumulative amount of fair value hedging adjustments to our hedged fixed rate debt was an increase of $144$799 million included in “Debt fair value adjustments” on our accompanying consolidated balance sheets.sheet. |
| | | Derivatives in cash flow hedging relationships | | Gain/(loss) recognized in OCI on derivative(a) | | Location | | Gain/(loss) reclassified from Accumulated OCI into income(b) | | Gain/(loss) recognized in OCI on derivative(a) | | Location | | Gain/(loss) reclassified from Accumulated OCI into income(b) |
| | | Three Months Ended March 31, | | Three Months Ended March 31, | | Three Months Ended March 31, | | Three Months Ended March 31, |
| | | 2019 | | 2018 | | 2019 | | 2018 | | 2020 | | 2019 | | 2020 | | 2019 |
| Energy commodity derivative contracts | | $ | (245 | ) | | $ | (22 | ) | | Revenues—Natural gas sales | | $ | 3 |
| | $ | 1 |
| | $ | 379 |
| | $ | (245 | ) | | Revenues—Commodity sales | | $ | (8 | ) | | $ | 13 |
|
| | | | | | | Revenues—Product sales and other | | 10 |
| | (19 | ) | |
| | | | | | | Costs of sales | | 1 |
| | — |
| |
| Interest rate contracts(c) | | — |
| | 2 |
| | Earnings from equity investments | | — |
| | (1 | ) | |
| Interest rate contracts | | | (8 | ) | | — |
| | Costs of sales | | (17 | ) | | 1 |
|
| Foreign currency contracts | | (34 | ) | | 65 |
| | Other, net | | (31 | ) | | 40 |
| | (82 | ) | | (34 | ) | | Other, net | | (23 | ) | | (31 | ) |
| Total | | $ | (279 | ) | | $ | 45 |
| | Total | | $ | (17 | ) | | $ | 21 |
| | $ | 289 |
| | $ | (279 | ) | | Total | | $ | (48 | ) | | $ | (17 | ) |
_______
| |
| (a) | We expect to reclassify an approximate $45$257 million lossgain associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balance as of March 31, 20192020 into earnings during the next twelve months (when the associated forecasted transactions are also expected to impact earnings); 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). |
| |
(c) | Amounts represent our share of an equity investee’s accumulated other comprehensive income (loss). |
| | | Derivatives in net investment hedging relationships | | Gain/(loss) recognized in OCI on derivative | | Location | | Gain/(loss) reclassified from Accumulated OCI into income | | Gain/(loss) recognized in OCI on derivative |
| | | Three Months Ended March 31, | | Three Months Ended March 31, | | Three Months Ended March 31, |
| | | 2019 | | 2018 | | 2019 | | 2018 | | 2020 | | 2019 |
| Foreign currency contracts | | $ | (8 | ) | | $ | — |
| | Loss on impairments and divestitures, net | | $ | — |
| | $ | — |
| | $ | — |
| | $ | (8 | ) |
| Total | | $ | (8 | ) | | $ | — |
| | Total | | $ | — |
| | $ | — |
| | $ | — |
| | $ | (8 | ) |
|
| | | | | | | | | | |
| Derivatives not designated as hedging instruments | | Location | | Gain/(loss) recognized in income on derivatives |
| | | | | Three Months Ended March 31, |
| | | | | 2020 | | 2019 |
| Energy commodity derivative contracts | | Revenues—Commodity sales | | $ | 117 |
| | $ | 10 |
|
| | | Costs of sales | | 4 |
| | (2 | ) |
| Total(a) | | | | $ | 121 |
| | $ | 8 |
|
|
| | | | | | | | | | |
| Derivatives not designated as hedging instruments | | Location | | Gain/(loss) recognized in income on derivatives |
| | | | | Three Months Ended March 31, |
| | | | | 2019 | | 2018 |
| Energy commodity derivative contracts | | Revenues—Natural gas sales | | $ | 20 |
| | $ | 3 |
|
| | | Revenues—Product sales and other | | (10 | ) | | (1 | ) |
| | | Costs of sales | | (2 | ) | | — |
|
| Total(a) | | | | $ | 8 |
| | $ | 2 |
|
_______
| |
| (a) | The three months ended March 31, 2020 and 2019 and 2018 bothamounts include approximate gains of $74 million and $8 million, for each respective period,respectively, associated with natural gas, crude and NGL derivative contract settlements. |
Credit Risks
In conjunction with certain derivative contracts, we are required to provide collateral to our counterparties, which may include posting letters of credit or placing cash in margin accounts. As of March 31, 20192020 and December 31, 2018,2019, we had no0 outstanding letters of credit supporting our commodity price risk management program. As of March 31, 2020 and December 31, 2019, we had cash margins of $4$19 million posted by us with our counterparties as collateral and reported within “Restricted Deposits” on our accompanying consolidated balance sheet. As of December 31, 2018, we had cash margins of $16$15 million, respectively, posted by our counterparties with us as collateral and reported within “Other Current Liabilities”current liabilities” on our accompanying consolidated balance sheet.sheets. The balance at March 31, 2019 consisted2020 represents the net of our initial margin requirements of $15$6 million, offset by counterparty variation margin requirements of $11$25 million. We also use industry standard commercial agreements that allow for the netting of exposures associated with transactions executed under a single commercial agreement. Additionally, we generally utilize master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty.
We also have agreements with certain counterparties to our derivative contracts that contain provisions requiring the posting of additional collateral upon a decrease in our credit rating. As of March 31, 2019,2020, based on our current mark to marketmark-to-market positions and posted collateral, we estimate that if our credit rating were downgraded one notchor two notches we would not be required to post additional collateral. If we were downgraded two notches, we would be required to post $73 million of additional collateral.
Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Loss
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” within “Stockholders’ Equity” in our consolidated balance sheets. Changes in the components of our “Accumulated other comprehensive loss” not including non-controlling interests are summarized as follows (in millions):
|
| | | | | | | | | | | | | | | |
| | Net unrealized gains/(losses) on cash flow hedge derivatives | | Foreign currency translation adjustments | | Pension and other postretirement liability adjustments | | Total accumulated other comprehensive loss |
| Balance as of December 31, 2018 | $ | 164 |
| | $ | (91 | ) | | $ | (403 | ) | | $ | (330 | ) |
| Other comprehensive (loss) gain before reclassifications | (215 | ) | | 16 |
| | 8 |
| | (191 | ) |
| Losses reclassified from accumulated other comprehensive loss | 13 |
| | — |
| | — |
| | 13 |
|
| Net current-period other comprehensive (loss) income | (202 | ) | | 16 |
| | 8 |
| | (178 | ) |
| Balance as of March 31, 2019 | $ | (38 | ) | | $ | (75 | ) | | $ | (395 | ) | | $ | (508 | ) |
|
| | | | | | | | | | | | | | | |
| | Net unrealized gains/(losses) on cash flow hedge derivatives | | Foreign currency translation adjustments | | Pension and other postretirement liability adjustments | | Total accumulated other comprehensive loss |
| Balance as of December 31, 2017 | $ | (27 | ) | | $ | (189 | ) | | $ | (325 | ) | | $ | (541 | ) |
| Other comprehensive gain (loss) before reclassifications | 34 |
| | (41 | ) | | 6 |
| | (1 | ) |
| Gains reclassified from accumulated other comprehensive loss | (16 | ) | | — |
| | — |
| | (16 | ) |
| Impact of adoption of ASU 2018-02 (Note 4) | (4 | ) | | (36 | ) | | (69 | ) | | (109 | ) |
| Net current-period other comprehensive income (loss) | 14 |
| | (77 | ) | | (63 | ) | | (126 | ) |
| Balance as of March 31, 2018 | $ | (13 | ) | | $ | (266 | ) | | $ | (388 | ) | | $ | (667 | ) |
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; (ii) interest rate swap agreements; and (iii) cross-currency swap agreements, based on the three levels established by the ASC (in millions). The tables also identify the impact of derivative contracts which we have elected to present on our accompanying consolidated balance sheets on a gross basis that are eligible for netting under master netting agreements.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Balance sheet asset fair value measurements by level | | | | Net amount |
| | Level 1 | | Level 2 | | Level 3 | | Gross amount | | Contracts available for netting | | Cash collateral held(b) |
| As of March 31, 2019 | | | | | | | | | | | | | |
| Energy commodity derivative contracts(a) | $ | 6 |
| | $ | 45 |
| | $ | — |
| | $ | 51 |
| | $ | (19 | ) | | $ | (11 | ) | | $ | 21 |
|
| Interest rate contracts | — |
| | 196 |
| | — |
| | 196 |
| | (8 | ) | | — |
| | 188 |
|
| Foreign currency contracts | — |
| | 95 |
| | — |
| | 95 |
| | (29 | ) | | — |
| | 66 |
|
| As of December 31, 2018 | | | | | | | | | | | | | |
| Energy commodity derivative contracts(a) | $ | 28 |
| | $ | 193 |
| | $ | — |
| | $ | 221 |
| | $ | (39 | ) | | $ | (25 | ) | | $ | 157 |
|
| Interest rate contracts | — |
| | 133 |
| | — |
| | 133 |
| | (7 | ) | | — |
| | 126 |
|
| Foreign currency contracts | — |
| | 197 |
| | — |
| | 197 |
| | (6 | ) | | — |
| | 191 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Balance sheet liability fair value measurements by level | | | | Net amount |
| | Level 1 | | Level 2 | | Level 3 | | Gross amount | | Contracts available for netting | | Collateral posted(b) |
| As of March 31, 2019 | | | | | | | | | | | | | |
| Energy commodity derivative contracts(a) | $ | (4 | ) | | $ | (150 | ) | | $ | — |
| | $ | (154 | ) | | $ | 19 |
| | $ | — |
| | $ | (135 | ) |
| Interest rate contracts | — |
| | (50 | ) | | — |
| | (50 | ) | | 8 |
| | — |
| | (42 | ) |
| Foreign currency contracts | — |
| | (29 | ) | | — |
| | (29 | ) | | 29 |
| | — |
| | — |
|
| As of December 31, 2018 | | | | | | | | | | | | | |
| Energy commodity derivative contracts(a) | $ | (11 | ) | | $ | (39 | ) | | $ | — |
| | $ | (50 | ) | | $ | 39 |
| | $ | — |
| | $ | (11 | ) |
| Interest rate contracts | — |
| | (115 | ) | | — |
| | (115 | ) | | 7 |
| | — |
| | (108 | ) |
| Foreign currency contracts | — |
| | (6 | ) | | — |
| | (6 | ) | | 6 |
| | — |
| | — |
|
_______
| |
(a) | Level 1 consists primarily of NYMEX natural gas futures. Level 2 consists primarily of OTC WTI swaps and NGL swaps. |
| |
(b) | Any cash collateral paid or received is reflected in this table, but only to the extent that it represents variation margins. Any amount associated with derivative prepayments or initial margins that are not influenced by the derivative asset or liability amounts, or those that are determined solely on their volumetric notional amounts, are excluded from this table. |
Fair Value of Financial Instruments
The carrying value and estimated fair value of our outstanding debt balances are disclosed below (in millions):
|
| | | | | | | | | | | | | | | |
| | March 31, 2019 | | December 31, 2018 |
| | Carrying value | | Estimated fair value | | Carrying value | | Estimated fair value |
| Total debt | $ | 35,830 |
| | $ | 37,981 |
| | $ | 37,324 |
| | $ | 37,469 |
|
We used Level 2 input values to measure the estimated fair value of our outstanding debt balance as of both March 31, 2019 and December 31, 2018.
7. Revenue Recognition
Disaggregation of Revenues
The following tables present our revenues disaggregated by revenue source and type of revenue for each revenue source (in millions):
| | | | �� | Three Months Ended March 31, 2019 | | Three Months Ended March 31, 2020 |
| | | Natural Gas Pipelines | | Products Pipelines | | Terminals | | CO2 | | Corporate and Eliminations | | Total | | Natural Gas Pipelines | | Products Pipelines | | Terminals | | CO2 | | Corporate and Eliminations | | Total |
Revenues from contracts with customers | | | | | | | | | | | | | | | | | | | | | | | | |
| Services | | | | | | | | | | | | | | | | | | | | | | | | |
Firm services(a)(b) | | $ | 930 |
| | $ | 80 |
| | $ | 250 |
| | $ | — |
| | $ | (1 | ) | | $ | 1,259 |
| | $ | 865 |
| | $ | 79 |
| | $ | 189 |
| | $ | — |
| | $ | — |
| | $ | 1,133 |
|
| Fee-based services | | 192 |
| | 235 |
| | 148 |
| | 16 |
| | (1 | ) | | 590 |
| | 193 |
| | 260 |
| | 121 |
| | 13 |
| | — |
| | 587 |
|
| Total services revenues | | 1,122 |
| | 315 |
| | 398 |
| | 16 |
| | (2 | ) | | 1,849 |
| |
| Sales | | | | | | | | | | | | | |
| Total services | | | 1,058 |
| | 339 |
| | 310 |
| | 13 |
| | — |
| | 1,720 |
|
| Commodity sales | | | | | | | | | | | | | |
| Natural gas sales | | 754 |
| | — |
| | — |
| | 1 |
| | (2 | ) | | 753 |
| | 501 |
| | — |
| | — |
| | — |
| | (2 | ) | | 499 |
|
| Product sales | | 240 |
| | 66 |
| | 2 |
| | 268 |
| | (6 | ) | | 570 |
| | 136 |
| | 109 |
| | 3 |
| | 232 |
| | (13 | ) | | 467 |
|
| Total sales revenues | | 994 |
| | 66 |
| | 2 |
| | 269 |
| | (8 | ) | | 1,323 |
| |
| Total commodity sales | | | 637 |
| | 109 |
| | 3 |
| | 232 |
| | (15 | ) | | 966 |
|
| Total revenues from contracts with customers | | 2,116 |
| | 381 |
| | 400 |
| | 285 |
| | (10 | ) | | 3,172 |
| | 1,695 |
| | 448 |
| | 313 |
| | 245 |
| | (15 | ) | | 2,686 |
|
Other revenues(b)(c) | | 85 |
| | 43 |
| | 109 |
| | 20 |
| | — |
| | 257 |
| | 180 |
| | 47 |
| | 129 |
| | 64 |
| | — |
| | 420 |
|
| Total revenues | | $ | 2,201 |
| | $ | 424 |
| | $ | 509 |
| | $ | 305 |
| | $ | (10 | ) | | $ | 3,429 |
| | $ | 1,875 |
| | $ | 495 |
| | $ | 442 |
| | $ | 309 |
| | $ | (15 | ) | | $ | 3,106 |
|
| | | | | Three Months Ended March 31, 2018 | | Three Months Ended March 31, 2019 |
| | | Natural Gas Pipelines | | Products Pipelines | | Terminals | | CO2 | | Kinder Morgan Canada(c) | | Corporate and Eliminations | | Total | | Natural Gas Pipelines | | Products Pipelines | | Terminals | | CO2 | | Corporate and Eliminations | | Total |
Revenues from contracts with customers | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Services | | | | | | | | | | | | | | | | | | | | | | | | | | |
Firm services(a)(b) | | $ | 845 |
| | $ | 92 |
| | $ | 256 |
| | $ | 1 |
| | $ | — |
| | $ | (1 | ) | | $ | 1,193 |
| | $ | 930 |
| | $ | 80 |
| | $ | 250 |
| | $ | — |
| | $ | (1 | ) | | $ | 1,259 |
|
| Fee-based services | | 164 |
| | 221 |
| | 144 |
| | 17 |
| | 64 |
| | 1 |
| | 611 |
| | 192 |
| | 235 |
| | 148 |
| | 16 |
| | (1 | ) | | 590 |
|
| Total services revenues | | 1,009 |
| | 313 |
| | 400 |
| | 18 |
| | 64 |
| | — |
| | 1,804 |
| |
| Sales | | | | | | | | | | | | | | | |
| Total services | | | 1,122 |
| | 315 |
| | 398 |
| | 16 |
| | (2 | ) | | 1,849 |
|
| Commodity sales | | | | | | | | | | | | | |
| Natural gas sales | | 828 |
| | — |
| | — |
| | — |
| | — |
| | (2 | ) | | 826 |
| | 754 |
| | — |
| | — |
| | 1 |
| | (2 | ) | | 753 |
|
| Product sales | | 219 |
| | 92 |
| | 3 |
| | 317 |
| | — |
| | (7 | ) | | 624 |
| | 240 |
| | 66 |
| | 2 |
| | 268 |
| | (6 | ) | | 570 |
|
| Total sales revenues | | 1,047 |
| | 92 |
| | 3 |
| | 317 |
| | — |
| | (9 | ) | | 1,450 |
| |
| Total commodity sales | | | 994 |
| | 66 |
| | 2 |
| | 269 |
| | (8 | ) | | 1,323 |
|
| Total revenues from contracts with customers | | 2,056 |
| | 405 |
| | 403 |
| | 335 |
| | 64 |
| | (9 | ) | | 3,254 |
| | 2,116 |
| | 381 |
| | 400 |
| | 285 |
| | (10 | ) | | 3,172 |
|
Other revenues(b)(c) | | 70 |
| | 37 |
| | 92 |
| | (31 | ) | | (3 | ) | | (1 | ) | | 164 |
| | 85 |
| | 43 |
| | 109 |
| | 20 |
| | — |
| | 257 |
|
| Total revenues | | $ | 2,126 |
| | $ | 442 |
| | $ | 495 |
| | $ | 304 |
| | $ | 61 |
| | $ | (10 | ) | | $ | 3,418 |
| | $ | 2,201 |
| | $ | 424 |
| | $ | 509 |
| | $ | 305 |
| | $ | (10 | ) | | $ | 3,429 |
|
_______
| |
| (a) | Differences between the revenue classifications presented on the consolidated statements of operations and the categories for the disaggregated revenues by type of revenue above are primarily attributable to revenues reflected in the “Other revenues” category above (see note (c) below). |
| |
| (b) | Includes non-cancellable firm service customer contracts with take-or-pay or minimum volume commitment elements, including those contracts where both the price and quantity amount are fixed. Excludes service contracts with indexed-basedindex-based pricing, which along with revenues from other customer service contracts are reported as Fee-based services. |
| |
(b)(c) | Amounts recognized as revenue under guidance prescribed in Topics of the Accounting Standards CodificationASC other than in Topic 606 and primarily include leases of $294 million and derivatives.$218 million and derivative contracts of $104 million and $23 million for the three months ended March 31, 2020 and 2019, respectively. See Notes Note 5 and 10 for additional information related to our derivative contracts and lessor contracts, respectively. |
| |
(c) | On August 31, 2018, the assets comprising the Kinder Morgan Canada business segment were sold; therefore, this segment does not have results of operations on a prospective basis (see Note 2).contracts. |
Contract Balances
Contract assets and contract liabilities are the result of timing differences between revenue recognition, billings and cash collections. We recognize
As of March 31, 2020 and December 31, 2019, our contract assets in those instances where billing occurs subsequent to revenue recognition,asset balances were $32 million and our right to invoice the customer is conditioned on something other than the passage of time. Our contract assets are substantially related to breakage revenue associated with our firm service contracts with minimum volume commitment payment obligations and contracts where we apply revenue levelization (i.e., contracts with fixed rates per volume that increase over the life of$27 million, respectively. Of the contract for which we record revenue ratably per unit overasset balance at December 31, 2019, $10 million was transferred to accounts receivable during the lifethree months ended March 31, 2020. As of March 31, 2020 and December 31, 2019, our contract liability balances were $257 million and $232 million, respectively. Of the contract based on our performance obligations that are generally unchanged over the life of the contract). Our contract liabilities are substantially related to (i) capital improvements paid for in advance by certain customers generally in our non-regulated businesses, which we subsequently recognizeliability balance at December 31, 2019, $32 million was recognized as revenue on a straight-line basis overduring the initial term of the related customer contracts; (ii) consideration received from customers for temporary deficiency quantities under minimum volume contracts that we expect will be made up in a future period, which we subsequently recognize as revenue when the customer makes up the volumes or the likelihood that the customer will exercise its right for deficiency volumes becomes remote (e.g., there is insufficient capacity to make up the volumes, the deficiency makeup period expires); and (iii) contracts with fixed rates per volume that decrease over the life of the contract where we apply revenue levelization for amounts received for our future performance obligations.three months ended March 31, 2020.
The following table presents the activity in our contract assets and liabilities (in millions):
|
| | | | | | | |
| | Three Months Ended March 31, |
| | 2019 | | 2018 |
| Contract Assets | | | |
| Balance at beginning of period(a) | $ | 24 |
| | $ | 32 |
|
| Additions | 24 |
| | 24 |
|
| Transfer to Accounts receivable | (11 | ) | | (21 | ) |
| Other | (1 | ) | | — |
|
| Balance at end of period(b) | $ | 36 |
| | $ | 35 |
|
| Contract Liabilities | | | |
| Balance at beginning of period(c) | $ | 292 |
| | $ | 206 |
|
| Additions | 92 |
| | 110 |
|
| Transfer to Revenues | (89 | ) | | (78 | ) |
| Other | 1 |
| | — |
|
| Balance at end of period(d) | $ | 296 |
| | $ | 238 |
|
_______
| |
(a) | Includes current and non-current balances of $14 million and $10 million, respectively, in 2019 and $25 million and $7 million, respectively, in 2018. |
| |
(b) | Includes current and non-current balances of $26 million and $10 million, respectively, in 2019 and $28 million and $7 million, respectively, in 2018 . |
| |
(c) | Includes current and non-current balances of $80 million and $212 million, respectively, in 2019 and $79 million and $127 million, respectively, in 2018. |
| |
(d) | Includes current and non-current balances of $77 million and $219 million, respectively, in 2019 and $88 million and $150 million, respectively, in 2018. |
Revenue Allocated to Remaining Performance Obligations
The following table presents our estimated revenue allocated to remaining performance obligations for contracted revenue that has not yet been recognized, representing our “contractually committed” revenue as of March 31, 20192020 that we will invoice or transfer from contract liabilities and recognize in future periods (in millions):
|
| | | | |
| Year | | Estimated Revenue |
| Nine months ended December 31, 2020 | | $ | 3,309 |
|
| 2021 | | 3,845 |
|
| 2022 | | 3,121 |
|
| 2023 | | 2,529 |
|
| 2024 | | 2,206 |
|
| Thereafter | | 13,988 |
|
| Total | | $ | 28,998 |
|
|
| | | | |
| Year | | Estimated Revenue |
| Nine months ended December 31, 2019 | | $ | 3,796 |
|
| 2020 | | 4,495 |
|
| 2021 | | 3,813 |
|
| 2022 | | 3,196 |
|
| 2023 | | 2,673 |
|
| Thereafter | | 15,171 |
|
| Total | | $ | 33,144 |
|
Our contractually committed revenue, for purposes of the tabular presentation above, is generally limited to service or commodity sale customer contracts which have fixed pricing and fixed volume terms and conditions, generally including contracts with take-or-pay or minimum volume commitment payment obligations. Our contractually committed revenue amounts generally exclude, based on the following practical expedients that we elected to apply, remaining performance obligations forfor: (i) contracts with index-based pricing or variable volume attributes in which such variable consideration is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct service that forms part of a series of distinct services;and (ii) contracts with an original expected duration of one year or less; and (iii) contracts for which we recognize revenue at the amount for which we have the right to invoice for services performed.less.
8. 7. Reportable Segments
For segment reporting purposes, effective January 1, 2019, certain assets were transferred among our business segments. As a result, individual segment results for the three months ended March 31, 2018 and balances as of December 31, 2018 have been reclassified to conform to the current presentation in the following tables.
Financial information by segment follows (in millions):
| | | | Three Months Ended March 31, | Three Months Ended March 31, |
| | 2019 | | 2018 | 2020 | | 2019 |
| Revenues | | | | | | |
| Natural Gas Pipelines | | | | | | |
| Revenues from external customers | $ | 2,192 |
| | $ | 2,116 |
| $ | 1,861 |
| | $ | 2,192 |
|
| Intersegment revenues | 9 |
| | 10 |
| 14 |
| | 9 |
|
| Products Pipelines | 424 |
| | 442 |
| 495 |
| | 424 |
|
| Terminals | | | | | | |
| Revenues from external customers | 508 |
| | 495 |
| 441 |
| | 508 |
|
| Intersegment revenues | 1 |
| | — |
| 1 |
| | 1 |
|
CO2 | 305 |
| | 304 |
| 309 |
| | 305 |
|
| Kinder Morgan Canada(a) | — |
| | 61 |
| |
| Corporate and intersegment eliminations | (10 | ) | | (10 | ) | (15 | ) | | (10 | ) |
| Total consolidated revenues(b) | $ | 3,429 |
| | $ | 3,418 |
| |
| Total consolidated revenues | | $ | 3,106 |
| | $ | 3,429 |
|
| | | | Three Months Ended March 31, | Three Months Ended March 31, |
| | 2019 | | 2018 | 2020 | | 2019 |
Segment EBDA(c)(a) | | | | | | |
| Natural Gas Pipelines | $ | 1,203 |
| | $ | 1,128 |
| $ | 1,196 |
| | $ | 1,203 |
|
| Products Pipelines | 276 |
| | 266 |
| 269 |
| | 276 |
|
| Terminals | 299 |
| | 296 |
| 257 |
| | 299 |
|
CO2 | 198 |
| | 199 |
| (755) |
| | 198 |
|
Kinder Morgan Canada(a) | (2 | ) | | 46 |
| — |
| | (2 | ) |
Total Segment EBDA(d) | 1,974 |
| | 1,935 |
| 967 |
| | 1,974 |
|
| DD&A | (593 | ) | | (570 | ) | (565 | ) | | (593 | ) |
| Amortization of excess cost of equity investments | (21 | ) | | (32 | ) | (32 | ) | | (21 | ) |
| General and administrative and corporate charges | (161 | ) | | (160 | ) | (165 | ) | | (161 | ) |
| Interest, net | (460 | ) | | (467 | ) | (436 | ) | | (460 | ) |
| Income tax expense | (172 | ) | | (164 | ) | (60 | ) | | (172 | ) |
| Total consolidated net income | $ | 567 |
| | $ | 542 |
| |
| Total consolidated net (loss) income | | $ | (291 | ) | | $ | 567 |
|
| | | | March 31, 2019 | | December 31, 2018 | March 31, 2020 | | December 31, 2019 |
| Assets | | | | | | |
| Natural Gas Pipelines | $ | 50,360 |
| | $ | 50,261 |
| $ | 49,393 |
| | $ | 50,310 |
|
| Products Pipelines | 9,538 |
| | 9,598 |
| 9,310 |
| | 9,468 |
|
| Terminals | 9,950 |
| | 9,415 |
| 8,840 |
| | 8,890 |
|
CO2 | 3,747 |
| | 3,928 |
| 2,926 |
| | 3,523 |
|
Corporate assets(e)(b) | 2,697 |
| | 5,664 |
| 3,061 |
| | 1,966 |
|
Total consolidated assets(f) | $ | 76,292 |
| | $ | 78,866 |
| $ | 73,530 |
| | $ | 74,157 |
|
_______
| |
| (a) | On August 31, 2018, the assets comprising the Kinder Morgan Canada business segment were sold; therefore, this segment does not have results of operations on a prospective basis (see Note 2). |
| |
(b) | Revenues previously reported for the three months ended March 31, 2018 were $2,166 million, $399 million, $493 million and $(5) million for the Natural Gas Pipelines, Products Pipelines and Terminals business segments, and Corporate and intersegment eliminations, respectively.
|
| |
(c) | Includes revenues, earnings from equity investments, other, net, less operating expenses.expenses, loss on impairments and divestitures, net, and other income, net. |
| |
(d) | Segment EBDA for the three months ended March 31, 2018 were $1,136 million, $259 million and $295 million for the Natural Gas Pipelines, Product Pipelines and Terminals business segments, respectively. |
| |
(e)(b) | Includes cash and cash equivalents, margin and restricted deposits, certain prepaid assets and deferred charges, including income tax related assets, risk management assets related to debt fair value adjustments,derivative contracts, corporate headquarters in Houston, Texas and miscellaneous corporate assets (such as information technology, telecommunications equipment and legacy activity) not allocated to our reportable segments. |
| |
(f) | Assets previously reported as of December 31, 2018 were $51,562 million, $8,429 million and $9,283 million for the Natural Gas Pipelines, Products Pipelines and Terminals business segments, respectively. The reclassification included a transfer of $450 million of goodwill from the Natural Gas Pipelines Non-Regulated reporting unit to the Product Pipelines reporting unit. |
9. 8. Income Taxes
Income tax expensesexpense included in our accompanying consolidated statements of income wereoperations are as follows (in millions, except percentages):
|
| | | | | | | |
| | Three Months Ended March 31, |
| | 2020 | | 2019 |
| Income tax expense | $ | 60 |
| | $ | 172 |
|
| Effective tax rate | (26.0 | )% | | 23.3 | % |
|
| | | | | | | |
| | Three Months Ended March 31, |
| | 2019 | | 2018 |
| Income tax expense | $ | 172 |
| | $ | 164 |
|
| Effective tax rate | 23.3 | % | | 23.2 | % |
Total tax expense for the three months ended March 31, 2020 is approximately $60 million resulting in an effective tax rate of (26.0)%, as compared with $172 million tax expense and an effective tax rate of 23.3%, for the same period of 2019.
The effective tax rate for the three months ended March 31, 2020 is “negative” in relation to the statutory federal rate of 21% primarily due to the $600 million CO2 reporting unit impairment of non tax deductible goodwill contributing to our loss before income taxes but not providing a tax benefit, partially offset by the refund of alternative minimum tax sequestration credits and dividend-received deductions from our investments in Citrus Corporation (Citrus) and Plantation Pipe Line Company (Plantation). While we would normally expect a federal income tax benefit from our loss before income taxes for the three months ended March 31, 2020, because the tax benefit is not allowed on the goodwill impairment, we incurred an income tax expense for the period.
The effective tax rate for the three months ended March 31, 2019 and 2018 is higher than the statutory federal rate of 21% primarily due to state and foreign income taxestaxes. These increases were partially offset by dividend-received deductions from our investments in Florida Gas Pipeline,Citrus, NGPL Holdings LLC and Plantation Pipe Line Company.Plantation.
10. Leases
Effective January 1, 2019, we adopted ASU No. 2016-02, “Leases (Topic 842)” and the series of related Accounting Standards Updates that followed (collectively referred to as “Topic 842”). The most significant changes under the new guidance include clarification of the definition of a lease, and the requirements for lessees to recognize a ROU asset and a lease liability for all qualifying leases with terms longer than twelve months in the consolidated balance sheet. In addition, under Topic 842, additional disclosures are required to meet the objective of enabling users of financial statements to assess the amount, timing and uncertainty of cash flows arising from leases.
We elected the practical expedient available to us under ASU 2018-11 “Leases: Targeted Improvements” which allows us to apply the transition provision for Topic 842 at our adoption date instead of at the earliest comparative period presented in our financial statements. Therefore, we recognized and measured leases existing at January 1, 2019 but without retrospective application. In addition, we elected the optional practical expedient permitted under the transition guidance related to land easements which allows us to carry forward our historical accounting treatment for land easements on existing agreements upon adoption. We also elected all other available practical expedients except the hindsight practical expedient.
The impact of Topic 842 on our consolidated balance sheet beginning January 1, 2019 was through the recognition of ROU assets and lease liabilities for operating leases, while our accounting for finance leases remained substantially unchanged. Our finance leases were immaterial prior to the adoption of Topic 842, and no change was made to the classification for these leases. Amounts recognized at January 1, 2019 for operating leases were as follows (in millions):
|
| | | |
| | January 1, 2019 |
| ROU assets | $ | 696 |
|
| Short-term lease liability | 52 |
|
| Long-term lease liability | 644 |
|
No impact was recorded to the income statement or beginning retained earnings for Topic 842.
Lessee
We lease property including corporate and field offices and facilities, vehicles, heavy work equipment including rail cars and large trucks, tanks, office equipment and land. Our leases have remaining lease terms of one to 34 years, some of which have options to extend or terminate the lease. We determine if an arrangement is a lease at inception. For purposes of calculating operating lease liabilities, lease terms may be deemed to include options to extend or terminate the lease when it is reasonably certain that we will exercise that option.
Beginning January 1, 2019, operating ROU assets and operating lease liabilities are recognized based on the present value of lease payments over the lease term at commencement date. Operating leases in effect prior to January 1, 2019 were recognized at the present value of the remaining payments on the remaining lease term as of January 1, 2019. Leases with variable rate adjustments, such as Consumer Price Index (CPI) adjustments, were reflected based on contractual lease payments as outlined within the lease agreement and not adjusted for any CPI increases or decreases. Because most of our leases do not provide an explicit rate of return, we use our incremental secured borrowing rate based on lease term information available at the commencement date of the lease in determining the present value of lease payments. We have real estate lease agreements with lease and non-lease components, which are accounted for separately, while for the remainder of our agreements we have elected the practical expedient to account for lease and non-lease components as a single lease component. For certain equipment leases, such as copiers and vehicles, we account for the leases under a portfolio method. Leases that were grandfathered under various portions of Topic 842, such as land easements, would be reassessed in the event of any modifications to those agreements.
Following are components of our lease cost (in millions):
|
| | | |
| | Three Months Ended March 31, 2019 |
| Operating leases | $ | 26 |
|
| Short-term and variable leases | 33 |
|
| Total lease cost(a) | $ | 59 |
|
_______
| |
(a) | Includes $14 million of capitalized lease costs. |
Other information related to our operating leases are as follows (in millions, except lease term and discount rate):
|
| | | |
| | Three Months Ended March 31, 2019 |
| Operating cash flows from operating leases | $ | (45 | ) |
| Investing cash flows from operating leases | (14 | ) |
| ROU assets obtained in exchange for operating lease obligations, net of retirements | 19 |
|
| Amortization of ROU assets | 14 |
|
| | |
| Weighted average remaining lease term | 16.84 years |
|
| Weighted average discount rate | 5.93 | % |
Amounts recognized in the accompanying consolidated balance sheet are as follows (in millions):
|
| | | | |
| Lease Activity | Balance sheet location | March 31, 2019 |
| ROU assets | Deferred charges and other assets | $ | 701 |
|
| Short-term lease liability | Other current liabilities | 53 |
|
| Long-term lease liability | Other long-term liabilities and deferred credits | 648 |
|
| Finance lease assets | Property, plant and equipment, net | 3 |
|
| Finance lease liabilities | Long-term debt—Outstanding | 2 |
|
Operating lease liabilities under non-cancellable leases (excluding short-term leases) as of March 31, 2019 are as follows (in millions):
|
| | | |
| Nine months ended December 31, 2019 | $ | 71 |
|
| 2020 | 80 |
|
| 2021 | 73 |
|
| 2022 | 67 |
|
| 2023 | 61 |
|
| Thereafter | 794 |
|
| Total lease payments(a) | 1,146 |
|
| Less: Interest | (445 | ) |
| Present value of lease liabilities | $ | 701 |
|
_______
| |
(a) | Amount excludes future minimum rights-of-way obligations (ROW) as they do not constitute a lease obligation. The amounts in our future minimum ROW obligations as presented in the table below have not materially changed since December 31, 2018. |
Undiscounted future gross minimum operating lease payments and ROW obligations as of December 31, 2018 are as follows (in millions):
|
| | | | | | | | | | | |
| | Leases | | ROW | | Total(a) |
| 2019 | $ | 90 |
| | $ | 25 |
| | $ | 115 |
|
| 2020 | 75 |
| | 25 |
| | 100 |
|
| 2021 | 70 |
| | 25 |
| | 95 |
|
| 2022 | 65 |
| | 26 |
| | 91 |
|
| 2023 | 59 |
| | 25 |
| | 84 |
|
| Thereafter | 771 |
| | 88 |
| | 859 |
|
| Total payments | $ | 1,130 |
| | $ | 214 |
| | $ | 1,344 |
|
_______
| |
(a) | This table has been revised from the previously reported December 31, 2018 future gross minimum rental commitments under our operating leases and ROW obligations table to (i) separately present lease and ROW obligations and (ii) to correct amounts previously reported to include an additional $482 million of undiscounted future lease payments, primarily in the “Thereafter” amount associated with the 2018 extension of the Edmonton South tank lease through December 2038. |
Short-term lease costs are not material to us and are anticipated to be similar to the current year short-term lease expense outlined in this disclosure.
Lessor
The property we lease to others under operating leases consists primarily of specific facilities where one customer obtains substantially all of the economic benefit from the asset and has the right to direct the use of the asset. These primarily consist of specific tanks, treating and gas equipment and pipelines with separate control locations. Our leases have remaining lease terms of one to 32 years, some of which have options to extend the lease for up to 25 years, and some which may include options to terminate the lease within one year. We determine if an arrangement is a lease at inception. None of our leases allow the lessee to purchase the leased asset.
Lease income for the three months ended March 31, 2019 totaled $218 million, including a significant amount of variable lease payments that is excluded from the following disclosure as the amounts cannot be reasonably estimated for future periods.
Future minimum operating lease revenues based on contractual agreements are as follows (in millions):
|
| | | |
| | March 31, 2019 |
| 2019 (nine months ended December 31, 2019) | $ | 297 |
|
| 2020 | 338 |
|
| 2021 | 320 |
|
| 2022 | 308 |
|
| 2023 | 275 |
|
| Thereafter | 3,471 |
|
| Total | $ | 5,009 |
|
Options for a lessee to renew the contract are not included as part of future minimum operating lease revenues. We elected the practical expedient available to us to not separate lease and non-lease components under these agreements. Any modification of a lease will result in a reevaluation of the lease classification.
11. 9. Litigation, Environmental and Other Contingencies
We and our subsidiaries are parties to various legal, regulatory and other matters arising from the day-to-day operations of our businesses or certain predecessor operations that may result in claims against the Company. Although no assurance can be given, we believe, based on our experiences to date and taking into account established reserves and insurance, that the ultimate resolution of such items will not have a material adverse impact on our business, financial position, results of operations or dividends to our shareholders.business. We believe we have meritorious defenses to the matters to which we are a party and intend to vigorously defend the Company. 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.
FERC Proceedings
FERC Rulemaking on Tax Cuts and Jobs Act for Jurisdictional Natural Gas Pipelines
In July 2018, the FERC issued an order requiring an informational filing by interstate natural gas pipelines on a new Form 501-G, evaluating the impact of the 2017 Tax Reform and the Revised Tax Policy on tax allowances for the pipelines. In the fourth quarter of 2018, KMI filed Form 501-G for 19 of its FERC-regulated assets. The FERC granted SNG a waiver from filing the 501-G based on its previously filed negotiated settlement and TGP was granted an extension from filing based on ongoing negotiations with customers. On April 8, 2019, KMI announced that TGP and EPNG agreed to settlements with their shippers to address FERC’s 501-G process. KMI successfully worked with its shippers without the need for litigation or any additional intervention by the FERC. Rate adjustments have been set forth in the agreements with TGP and EPNG shippers. FERC has approved a settlement that Young Gas Storage reached with its customers and has terminated all but three of the remaining 501-G proceedings without taking further action. FERC initiated a rate investigation of Bear Creek Storage Company. Bear Creek Storage Company filed a cost and revenue study in compliance with the FERC investigation on April 1, 2019. Two other KMI 501-G filings remain pending but relate to systems under rate moratoria. KMI expects the vast majority of KMI's 501-G exposure to be resolved upon FERC’s approval of the EPNG and TGP settlements discussed above.
FERC Inquiry Regarding the Commission’s Policy for Determining Return on Equity
On March 21, 2019, the FERC issued a notice of inquiry (NOI) seeking comments regarding whether the FERC should revise its policies for determining the base return on equity (ROE) used in setting cost of service rates charged by jurisdictional public utilities and interstate natural gas and liquids pipelines. The NOI seekssought comment on whether any aspects of the existing methodologies used by the FERC to set an ROE for a regulated entity should be changed, whether the ROE methodology should be the same across all three industries, and whether alternative methodologies should be considered. Initial comments are due in June 2019. ROEComments were filed by industry groups, pipeline companies and shippers for review and evaluation by the FERC and there is an important component of a regulated entity’s cost of service calculation, includingno deadline or requirement for our interstate natural gas and liquids pipeline assets. We expect broad industry, pipeline company, and shipper participation in the comment process.FERC to take action on this matter.
SFPP FERC Proceedings
The tariffs and rates charged by SFPP are subject to a number of ongoing shipper-initiated proceedings at the FERC, including the complaints and protests ofFERC. These include IS08-390, filed in June 2008, in which various shippers are challenging SFPP’s West Line rates (on appeal to the most recent of which wasD.C. Circuit Court); IS09-437, filed in 2019 (docketed at OR19-21)July 2009, in which various shippers are challenging SFPP’s East Line rates (pending before the FERC on rehearing); OR11-13/16/18, filed in June 2011, in which various shippers are seeking to challenge SFPP’s North Line, Oregon Line, and West Line rates (pending before the FERC for an order on the complaint); OR14-35/36, filed in June 2014, in which various shippers are challenging SFPP’s index increases in 2012 and 2013 (dismissed by the FERC, but remanded back to the FERC from the D.C. Circuit for further consideration); OR16-6, filed in December 2015, in which various shippers are challenging SFPP’s East line rates (pending before the FERC for an order on the initial decision); and OR19-21/33/37, filed beginning in April 2019, in which various shippers are challenging SFPP’s index increases in 2018 index rate increases(pending before the FERC for an order on certain of its lines.the complaints). 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). In some of these proceedings shippers have challenged the overall rate being charged by SFPP, and in others the shippers have challenged SFPP’s index-based rate increases. 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 SFPP may include in its rates. If the shippers prevail on their arguments or claims, they arewould be entitled to seek reparations (which may reach back up tofor the two years prior toyear period preceding the filing date of their complaints) complaints (OR cases) and/or prospective refunds in protest cases from the date of any excess rates paid,protest (IS cases), 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. On March 22, 2016,
SFPP paid refunds to shippers in May 2019, in the D.C. Circuit issued a decision in United Airlines, Inc. v. FERC remanding toIS08-390 proceeding as ordered by the FERC for further consideration of two issues: (1) the appropriate data to be used to determine the returnbased on equity for SFPP in the underlying docket, and (2) the just and reasonable return to be provided to a tax pass-through entity that includes an income tax allowance in its underlying cost of service. On March 15, 2018, the FERC announced certain policy changes including a Revised Policy Statement on Treatment of Income Taxes (Revised Policy Statement) and, that same day, the FERC issued orders in a series of pending SFPP proceedings which combined to deny income tax allowance to SFPP, direct SFPP to make compliance filings in its 2008 and 2009 rate filing dockets, and restart the 2011 SFPP complaint proceeding which had been abated. SFPP made its compliance filings and expects to pay in 2019 refunds in the 2008 docket. On March 15, 2019, SFPP filed with the D.C. Circuit a petition for review of the FERC’s decision in the 2008 docket, including the denial of an income tax allowance. SFPP’s request for rehearing in the 2009 docket remains pending at the FERC. SFPP is awaiting a FERC decision in a 2015 complaint against its East Line rates. The FERC has not yet acted on the shippers’ revised complaints in the 2011 SFPP complaint proceeding. On July 18, 2018, the FERC issued an Order on Rehearing in the Revised Policy Statement docket in which it denied the rehearing petitions and clarified that the issue of entitlement to an income tax allowance will continue to be resolved in individual proceedings, including proceedings involving income tax pass-through entities. SFPP along with another pipeline entity appealed the Revised Policy Statement along with the Order on Rehearing to the D.C. Circuit, and the Court has ordered briefing on the merits. With respect to the various SFPP related complaints and protest proceedings at the FERC (including IS08-390), we estimate that the shippers are seeking approximately $30$50 million in annual rate reductions and approximately $330$400 million in refunds. Management believes SFPP has meritorious arguments supporting SFPP’s rates and intends to vigorously defend SFPP against these complaints and protests. However, to the extent the shippers are successful in one or more of the complaints or protest proceedings, SFPP estimates that applying the principles of FERC precedent, as applicable, as well as the compliance filing methodology recently approved by the FERC to pending SFPP cases would result in rate reductions and refunds substantially lower than those sought by the shippers.
EPNG FERC Proceedings
The tariffs and rates charged by EPNG are subject to two2 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-A) in July 2015. The FERC generally upheld its prior determinations, ordered refunds to be paid within 60 days, and stated that it willwould apply its findings in Opinion 517-A to the same issues in the 2010 rate case. All refund obligations related to the 2008 rate case were satisfied in 2015. EPNG sought federal appellate review of Opinion 517-A. On February 21, 2017, the reviewing court delayed the case until the FERC ruled on the rehearing requests pending in the 2010 Rate Case. With respect to the 2010 rate case, the FERC issued its
decision (Opinion 528-A) on February 18, 2016. The FERC generally upheld its prior determinations, affirmed prior findings of an Administrative Law Judge that certain shippers qualify for lower rates, and required EPNG to file revised pro forma recalculated rates consistent with the terms of Opinions 517-A and 528-A. On May 3, 2018, the FERC issued Opinion 528-B upholding its decisions in Opinion 528-A and requiring EPNG to implement the rates required by its rulings and provide refunds within 60 days. On July 2, 2018, EPNG reported to the FERC the refund calculations, and that the refunds had been provided as ordered. Also on July 2, 2018, EPNG initiated appellate review of Opinions 528, 528-A and 528-B. On August 23, 2018, the reviewing court established a briefing schedule and consolidated EPNG’s delayed appeal fromappeals in the 2008 rate case,
EPNG’s appeal from theand 2010 rate case, andcases as well as the intervenors’ delayed appeal in the 2010 case. In accordance with that schedule, all briefing will be completedrate case were consolidated. Oral argument was heard by April 29, 2019.
Other Commercial Mattersthe U.S. Court of Appeals for the D.C. Circuit on March 13, 2020.
Gulf LNG Facility ArbitrationDisputes
On March 1, 2016, Gulf LNG Energy, LLC and Gulf LNG Pipeline, LLC (GLNG) received a Notice of Arbitration from Eni USA Gas Marketing LLC (Eni USA), one of two companies that entered into a terminal use agreement for capacity of the Gulf LNG Facility in Mississippi for an initial term that was not scheduled to expire until the year 2031. Eni USA is an indirect subsidiary of Eni S.p.A., a multi-national integrated energy company headquartered in Milan, Italy. Pursuant to its Notice of Arbitration, Eni USA sought declaratory and monetary relief based upon its assertion that (i) the terminal use agreement should be terminated because changes in the U.S. natural gas market since the execution of the agreement in December 2007 have “frustrated the essential purpose” of the agreement and (ii) activities allegedly undertaken by affiliates of Gulf LNG Holdings Group LLC “in connection with a plan to convert the LNG Facility into a liquefaction/export facility have given rise to a contractual right on the part of Eni USA to terminate” the agreement. A three-member arbitration panel conducted an arbitration hearing in January 2017. On June 29, 2018, the arbitration panel delivered its Award, and the panel's ruling called for the termination of the agreement and Eni USA's payment of compensation to GLNG. The Award resulted in our recording a net loss in the second quarter of 2018 of our equity investment in GLNG due to a non-cash impairment of our investment in GLNG partially offset by our share of earnings recognized by GLNG. On September 25, 2018, GLNG filed a lawsuit against Eni USA in the Delaware Court of Chancery to enforce the Award. On February 1, 2019, the Delaware Court of Chancery issued a Final Order and Judgment confirming the Award, which was paid by Eni USA on February 20, 2019.
On September 28, 2018, GLNG filed a lawsuit against Eni S.p.A. in the Supreme Court of the State of New York in New York County to enforce a Guarantee Agreement entered into by Eni S.p.A. in connection with the terminal use agreement. On December 12, 2018, Eni S.p.A. filed a counterclaim seeking unspecified damages from GLNG.
On June 3, 2019, Eni USA filed a second Notice of Arbitration against GLNG asserting the same breach of contract claims that had been asserted in the first arbitration and alleging that GLNG negligently misrepresented certain facts or contentions in the first arbitration. By its second Notice of Arbitration, Eni USA seeks to recover as damages some or all of the payments made by Eni USA to satisfy the Final Order and Judgment of the Court of Chancery. In response to the second Notice of Arbitration, GLNG filed a complaint with the Court of Chancery together with a motion seeking to permanently enjoin the arbitration. On January 10, 2020, the Court of Chancery entered an Order and Final Judgment granting GLNG’s motion to enjoin arbitration of the negligent misrepresentation claim, but denying the motion to enjoin arbitration of the breach of contract claims. The parties filed cross appeals of the Final Judgment. The Delaware appeals and arbitration proceeding remain pending.
On December 20, 2019, GLNG’s remaining customer, Angola LNG Supply Services LLC (ALSS), filed a Notice of Arbitration seeking a declaration that its terminal use agreement should be deemed terminated as of March 1, 2016 on substantially the same terms and conditions as set forth in the arbitration award pertaining to Eni USA. ALSS also seeks a declaration that activities allegedly undertaken by affiliates of Gulf LNG Holdings Group LLC in connection with the pursuit of an LNG liquefaction export project have given rise to a contractual right on the part of ALSS to terminate the agreement. ALSS also seeks a monetary award directing GLNG to reimburse ALSS for all reservation charges and operating fees paid by ALSS after December 31, 2016 plus interest.
GLNG intends to continue to vigorously prosecute and defend the lawsuit.
Price Reporting Litigation
Beginning in 2003, several lawsuits were filed by purchasers of natural gas against El Paso Corporation, El Paso Marketing L.P. and numerous other energy companies based on a claim under state antitrust law that such defendants conspired to manipulate the price of natural gas by providing false price information to industry trade publications that published gas indices. Allall of the cases have been settled or dismissed, includingforegoing proceedings.
Continental Resources, Inc. v. Hiland Partners Holdings, LLC
On December 8, 2017, Continental Resources, Inc. (CLR) filed an action in Garfield County, Oklahoma state court alleging that Hiland Partners Holdings, LLC (Hiland Partners) breached a Wisconsin class action lawsuit pendingGas Purchase Agreement, dated November 12, 2010, as amended (GPA), by failing to receive and purchase all of CLR’s dedicated gas under the GPA (produced in three North Dakota counties). CLR also alleged fraud, maintaining that Hiland Partners promised the construction of several additional facilities to process the gas without an intention to build the facilities. Hiland Partners denied these allegations, but the parties entered into a U.S. District Courtsettlement agreement in Nevada,June 2018, under which CLR agreed to release all of its claims in exchange for Hiland
Partners’ construction of 10 infrastructure projects by November 1, 2020. CLR has filed an amended petition in which approximately $300 millionit asserts that Hiland Partners’ failure to construct certain facilities by specific dates nullifies the release contained in the settlement agreement. CLR’s amended petition makes additional claims under both the GPA and a May 8, 2008 gas purchase contract covering additional North Dakota counties, including CLR’s contention that Hiland Partners is not allowed to deduct third-party processing fees from the gas purchase price. CLR seeks damages plus interest was allegedin excess of $225 million. Hiland Partners denies these claims and will vigorously defend against all defendants andany action in which a settlement in principal has been reached that will require class notice and final court approval in 2019. The amount to be paid in settlement of this matter is not material to our results of operations, cash flows or dividends to shareholders.they are asserted.
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.
General
As of March 31, 20192020 and December 31, 2018,2019, our total reserve for legal matters was $222$243 million and $207$203 million, respectively. In addition, as of March 31, 2020 and December 31, 2019, we have recorded a receivable of $31 million and $2 million, respectively, for expected cost recoveries that have been deemed probable.
Environmental Matters
We and our subsidiaries 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 laws and regulations, risks of additional costs and liabilities are inherent in pipeline, terminal and CO2 field and oil field operations, and there can be no assurance that we will not incur significant costs and
liabilities. Moreover, it is possible that other developments, such as increasingly stringent environmental laws, 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, including alleged violations of the Risk Management Program, and leak detection and repair requirements of the Clean Air Act. As we receive notices of non-compliance, we attempt to negotiate and settle such matters where appropriate. These alleged violations may result in fines and penalties, but we do not believe any such fines and penalties, individually or in the aggregate, will be material. 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 remediation.
In addition, we are involved with and have been identified as a potentially responsible party (PRP) in several federal and state superfundSuperfund 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 CO2.
Portland Harbor Superfund Site, Willamette River, Portland, Oregon
On January 6, 2017, the EPA issued a Record of Decision (ROD) that established a final remedy and cleanup plan for an industrialized area on the lower reach of the Willamette River commonly referred to as the Portland Harbor Superfund Site.Site (PHSS). The cost for the final remedy is estimated by the EPA to be approximately $1.1 billion and active cleanup is expected to take as long as 13 years to complete. KMLT, KMBT, and 90 other PRPs identified by the EPA are involved in a non-judicial allocation process to determine each party’s respective share of the cleanup costs related to the final remedy set forth by the ROD. We are participating in the allocation process on behalf of KMLT (in connection with its ownership or operation of two2 facilities acquired from GATX Terminals Corporation) and KMBT (in connection with its ownership or operation of 2 facilities). Effective January 31, 2020, KMLT entered into separate Administrative Settlement Agreements and Orders on Consent (ASAOC) to complete remedial design for two facilities).distinct areas within the PHSS associated with KMLT���s facilities. The ASAOC obligates KMLT to pay a share of the remedial design costs for cleanup activities related to these two areas as required
by the ROD. Our share of responsibility for Portland Harbor Superfund Sitethe PHSS costs will not be determined until the ongoing non-judicial allocation process is concluded in several years or a lawsuit is filed that results in a judicial decision allocating responsibility. Until the allocation process is completed, we are unable to reasonably estimate the extent of our liability for the costs related to the design of the proposed remedy and cleanup of the site.PHSS. In addition to CERCLA cleanup costs, we are reviewing and will attempt to settle, if possible, natural resource damage (NRD) claims asserted by state and federal trustees following their natural resource assessment of the site.PHSS. At this time, we are unable to reasonably estimate the extent of our potential NRD liability.
Uranium Mines in Vicinity of Cameron, Arizona
In the 1950s and 1960s, Rare Metals Inc., a historical subsidiary of EPNG, mined approximately twenty20 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 PRP 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 is conducting a radiological assessment of the surfaceenvironmental assessments of the mines and the immediate vicinity. On September 3, 2014, EPNG filed a complaint in the U.S. District Court for the District of Arizona seeking cost recovery and contribution from the applicable federal government agencies toward the cost of environmental activities associated with the mines, given the U.S. is the owner of the Navajo Reservation, the U.S.’s exploration and reclamation activities at the mines, and the pervasive control of such federal agencies over all aspects of the nuclear weapons program. After a trial which concluded in March 2019, the U.S. District Court issued an order on April 16, 2019 that allocated 35% of past and future response costs to the government.U.S. The decision may bewas not appealed by any party to the Court of Appeals for the Ninth Circuit.party. The decision does not provide or establish the scope of a remedial plan with respect to the sites, nor does it establish the total cost for addressing the sites, all of which remain to be determined in subsequent proceedings and adversarial actions, if necessary, with the EPA. Until such issues are determined, we are unable to reasonably estimate the extent of our potential liability. However, becauseBecause costs associated with any remedial plan approved by the EPA are expected to be spread over at least several years, we do not anticipate that this decision will have a material adverse impact to our results of operations, cash flows, or dividends to KMI shareholders.business.
Lower Passaic River Study Area of the Diamond Alkali Superfund Site, New Jersey
EPEC Polymers, Inc. (EPEC Polymers) and EPEC Oil Company Liquidating Trust (EPEC Oil Trust), former El Paso Corporation entities now owned by KMI, are involved in an administrative action under CERCLA known as the Lower Passaic River Study Area (Site) concerning the lower 17-mile stretch of the Passaic River. It has been alleged that EPEC Polymers and EPEC Oil Trust may be PRPs under CERCLA based on prior ownership and/or operation of properties located along the relevant section of the Passaic River. EPEC Polymers and EPEC Oil Trust entered into two Administrative Orders on Consent (AOCs) with the EPA which obligate them to investigate and characterize contamination at the Site. They are also part of a joint defense group of approximately 44 cooperating parties, referred to as the Cooperating Parties Group (CPG), which is directing and funding the AOC work required by the EPA. Under the first AOC, the CPG submitted draft remedial investigation and feasibility studies (RI/FS) of the Site to the EPA in 2015, and EPA approval remains pending. Under the second AOC, the CPG conducted a CERCLA removal action at the Passaic River Mile 10.9, and is obligated to conduct EPA-directed post-remedy monitoring in the removal area. We have established a reserve for the anticipated cost of compliance with these two AOCs.
On March 4, 2016, the EPA issued its Record of Decision (ROD) for the lower eight8 miles of the Site. TheAt that time the final cleanup plan in the ROD iswas estimated by the EPA to cost $1.7 billion. On October 5, 2016, the EPA entered into an AOC with Occidental Chemical Company (OCC), a member of the PRP group requiring OCC to spend an estimated $165 million to perform engineering and design work necessary to begin the cleanup of the lower eight8 miles of the Site. The design work is expected tounderway. Initial expectations were that the design work would take four years to complete and thecomplete. The cleanup is expected to take at least six years to complete.complete once it begins. On June 30, 2018 and July 13, 2018, respectively, OCC filed two2 separate lawsuits in the U.S. District Court for the District of New Jersey seeking cost recovery and contribution under CERCLA from more than 120 defendants, including EPEC Polymers. OCC alleges that each defendant is responsible to reimburse OCC for a proportionate share of the $165 million OCC is required to spend pursuant to its AOC. EPEC Polymers was dismissed without prejudice from the lawsuit on August 8, 2018.
In addition, the EPA and numerous PRPs, including EPEC Polymers, are engaged in an allocation process for the implementation of the remedy for the lower eight8 miles of the Site. There remains significant uncertainty as to the implementation and associated costs of the remedy set forth in the ROD. There is also uncertainty as to the impact of the recent EPA FS directive for the upper nine miles of the Site not subject to the lower eight mile ROD. In a letter dated October 10, 2018, the EPA directed the CPG to prepare a streamlined FS for the Site that evaluates interim remedy alternatives for sediments in
the upper nine miles of the Site. Until this FS is completed and the RI/FS is finalized and allocations are determined, the scope of potential EPA claims for the Site and liability therefor are not reasonably estimable.
Louisiana Governmental Coastal Zone Erosion Litigation
Beginning in 2013, several parishes in Louisiana and the City of New Orleans filed separate lawsuits in state district courts in Louisiana against a number of oil and gas companies, including TGP and SNG. In these cases, the parishes and New Orleans, as Plaintiffs, allege that certain of the defendants’ oil and gas exploration, production and transportation operations were conducted in violation of the State and Local Coastal Resources Management Act of 1978, as amended (SLCRMA). The Plaintiffs allege the defendants’ operations caused substantial damage to the coastal waters of Louisiana and nearby lands, including marsh (Coastal Zone). The alleged damages include erosion of property within the Coastal Zone, and discharge of pollutants that are alleged to have adversely impacted the Coastal Zone, including plants and wildlife. The Plaintiffs seek, among other relief, unspecified money damages, attorneys’ fees, interest, and payment of costs necessary to restore the affected Coastal Zone to its original condition. The Louisiana Department of Natural Resources (LDNR) and the Louisiana Attorney General (LAG) routinely intervene in these cases, and we expect the LDNR and LAG to intervene in any additional cases that may be filed. There are more than 40 of these cases pending in Louisiana against oil and gas companies, one1 of which is against TGP and one1 of which is against SNG, both described further below.
On November 8, 2013, the Parish of Plaquemines, Louisiana filed a petition for damages in the state district court for Plaquemines Parish, Louisiana against TGP and 17 other energy companies, alleging that the defendants’ operations in Plaquemines Parish violated SLCRMA and Louisiana law, and that those operations caused substantial damage to the Coastal Zone. Plaquemines Parish seeks, among other relief, unspecified monetary relief,money damages, attorney fees, interest, and payment of costs necessary to restore the allegedly affected Coastal Zone to its original condition, including costs to remediate, restore, vegetate and detoxify the affected Coastal Zone property. In 2016, the LAG and LDNR intervened in the lawsuit. In May 2018, the case was removed to the U.S. District Court for the Eastern District of Louisiana.Louisiana on several grounds including federal officer liability. Plaquemines Parish, along with the intervenors, moved to remand the case to the state district court. That motion is pending.On May 28, 2019, the case was remanded to the state district court for Plaquemines Parish. At the same time, the U.S. District Court certified the federal officer liability jurisdiction issue for review by the U.S. Fifth Circuit Court of Appeals and on June 11, 2019, the U.S. District Court stayed the remand order pending the outcome of that review. The case is effectively stayed pending resolution of the removalfederal officer liability issue by the Court of Appeals. Until these and remand issues.other issues are determined, we are not able to reasonably estimate the extent of our potential liability, if any. We will continue to vigorously defend this case.
On March 29, 2019, the City of New Orleans and Orleans Parish (Orleans)(collectively, Orleans) filed a petition for damages in the state district court for Orleans Parish, Louisiana against SNG and 10 other energy companies alleging that the defendants’ operations in Orleans Parish violated the SLCRMA and Louisiana law, and caused substantial damage to the Coastal Zone. Orleans seeks, among other relief, unspecified monetary relief,money damages, attorney fees, interest, and payment of costs necessary to restore the allegedly affected Coastal Zone to its original condition, including costs to remediate, restore, vegetate and detoxify the affected Coastal Zone property. On April 5, 2019, the case was removed to the U.S. District Court for the Eastern District of Louisiana. On May 28, 2019, Orleans moved to remand the case to the state district court. On January 30, 2020, the U.S. District Court ordered the case to be stayed and administratively closed pending the resolution of issues in a separate case to which SNG is not a party; Parish of Cameron vs. Auster Oil & Gas, Inc., pending in U.S. District Court for the Western District of Louisiana; after which either party may move to re-open the case. Until these and other issues are determined, we are not able to reasonably estimate the extent of our potential liability, if any. We will continue to vigorously defend this case.
Louisiana Landowner Coastal Erosion Litigation
Beginning in January 2015, several private landowners in Louisiana, as Plaintiffs, filed separate lawsuits in state district courts in Louisiana against a number of oil and gas pipeline companies, including two2 cases against TGP, two2 cases against SNG, and two2 cases against both TGP and SNG. In these cases, the Plaintiffs allege that the defendants failed to properly maintain pipeline canals and canal banks on their property, which caused the canals to erode and widen and resulted in substantial land loss, including significant damage to the ecology and hydrology of the affected property, includingand damage to timber and wildlife. PlaintiffsThe plaintiffs allege that the defendants’ conduct constitutes a breach of the subject right of way agreements, is inconsistent with prudent operating practices, violates Louisiana law, and that defendants’ failure to maintain canals and canal banks constitutes negligence and trespass. PlaintiffsThe plaintiffs seek, among other relief, unspecified money damages, attorneys’ fees, interest, and payment of costs necessary to return the canals and canal banks to their as-built conditions and restore and remediate the affected property. PlaintiffsThe plaintiffs allege that the defendants are obligated to restore and remediate the affected property without regard to the value of the property. PlaintiffsThe plaintiffs also seek a declaration that the defendants are obligated to take steps to maintain canals and canal banks going forward. There are no trial dates established in any of the pending cases. In one case filed by Vintage Assets, Inc. and several landowners against SNG, TGP, and TGPanother defendant that was tried in 2017 to the U.S. District Court for the Eastern District of Louisiana, $80
$80 million was sought in money damages, including recovery of litigation costs, damages for trespass, and money damages associated with an alleged loss of natural resources and projected reconstruction cost of replacing or restoring wetlands. On May 4, 2018, the District Court entered a judgment dismissing the tort and negligence claims against all of the defendants, and dismissing certain of the contract claims against TGP. In ruling in favor of the plaintiffs on the remaining contract claims, the District Court ordered the defendants to pay $1,104 in money damages, and issued a permanent injunction ordering the defendants to restore a total of 9.6 acres of land and maintain certain canals at widths designated by the right of way agreements in effect. The Court stayed the judgment and the injunction pending appeal. The parties each filed a separate appeal to the U.S. Court of Appeals for the Fifth Circuit. On September 13, 2018, athe third-party defendant filed a motion to vacate the judgment and dismiss all of the appeals for lack of subject matter jurisdiction. On October 2, 2018 the Court of Appeals dismissed the appeals and on April 17, 2019 the case was remanded to the State District Court ofstate district court for Plaquemines Parish, Louisiana for further proceedings. The case is set for trial July 27, 2020. We will continue to vigorously defend these cases.
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 and our subsidiaries 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, 20192020 and December 31, 2018,2019, we have accrued a total reserve for environmental liabilities in the amount of $270$256 million and $271$259 million, respectively. In addition, as of both March 31, 20192020 and December 31, 2018,2019, we have recorded a receivable of $13$12 million and $15 million, respectively, for expected cost recoveries that have been deemed probable.
Other Contingencies
We have agreed to fund our proportionate share of $700 million of 2019 maturing debt obligations at certain of our equity investees and we would be obligated for our $350 million share of these obligations if the equity investees are unable to satisfy their obligations.
12. 10. Recent Accounting Pronouncements
ASU No. 2016-13
On June 16, 2016, the FASB issued ASU No. 2016-13, “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments.” This ASU modifies the impairment model for most financial assets and certain other instruments. For trade and other receivables, held-to-maturity debt securities, loans and other instruments, entities will be required to utilize a new forward-looking “expected loss” methodology that generally will result in the earlier recognition of
allowance for losses. ASU No. 2016-13 will be effective for us as of January 1, 2020, and earlier adoption is permitted. We are currently reviewing the effect of this ASU to our financial statements.
ASU No. 2017-04
On January 26, 2017, the FASB issued ASU No. 2017-04, “Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment.” This ASU simplifies the accounting for goodwill impairment by removing Step 2 of the goodwill impairment test, which requires a hypothetical purchase price allocation. Goodwill impairment will now be the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill. ASU No. 2017-04 will be effective for us as of January 1, 2020, and earlier adoption is permitted. We are currently reviewing the effect of this ASU to our financial statements.
ASU No. 2018-13
On August 28, 2018, the FASB issued ASU No. 2018-13, “Fair Value Measurement (Topic 820): Disclosure Framework-Changes to the Disclosure Requirements for Fair Value Measurement.” This ASU amends existing fair value measurement disclosure requirements by adding, changing, or removing certain disclosures. ASU No. 2018-13 will be effective for us as of January 1, 2020, and earlier adoption is permitted. We are currently reviewing the effect of this ASU to our financial statements.
ASU No. 2018-14
On August 28, 2018, the FASB issued ASU No. 2018-14, “Compensation - Retirement Benefits - Defined Benefit Plans - General (Subtopic 715-20): Disclosure Framework - Changes to the Disclosure Requirements for Defined Benefit Plans.” This ASU amends existing annual disclosure requirements applicable to all employers that sponsor defined benefit pension and other postretirement plans by adding, removing, and clarifying certain disclosures. ASU No. 2018-14 will be effective for us for the fiscal year ending December 31, 2020, and earlier adoption is permitted. We are currently reviewing the effect of this ASU to our financial statements.
ASU No. 2020-04
On March 12, 2020, the FASB issued ASU No. 2020-04, “Reference Rate Reform - Facilitation of the Effects of Reference Rate Reform on Financial Reporting.” This ASU provides temporary optional expedients and exceptions to GAAP guidance on contract modifications and hedge accounting to ease the financial reporting burdens of the expected market transition from LIBOR and other interbank offered rates to alternative reference rates, such as the Secured Overnight Financing Rate. Entities can elect not to apply certain modification accounting requirements to contracts affected by this reference rate reform, if certain criteria are met. An entity that makes this election would not have to remeasure the contracts at the modification date or reassess a previous accounting determination. Entities can also elect various optional expedients that would allow them to continue applying hedge accounting for hedging relationships affected by reference rate reform, if certain criteria are met. The guidance is effective upon issuance and generally can be applied through December 31, 2022. We are currently reviewing the effect of this ASU to our financial statements.
13. Guarantee of Securities of Subsidiaries
KMI, along with its direct subsidiary KMP, are issuers of certain public debt securities. KMI, KMP and substantially all of KMI’s wholly owned domestic subsidiaries are parties to a cross guarantee agreement whereby each party to the agreement unconditionally guarantees, jointly and severally, the payment of specified indebtedness of each other party to the agreement. Accordingly, with the exception of certain subsidiaries identified as Subsidiary Non-Guarantors, the Parent Issuer, Subsidiary Issuer and other subsidiaries are all guarantors of each series of public debt.
Excluding fair value adjustments, as of March 31, 2019, Parent Issuer and Guarantor, Subsidiary Issuer and Guarantor-KMP, and Subsidiary Guarantors had $14,836 million, $16,610 million, and $2,535 million, respectively, of Guaranteed Notes outstanding. Included in the Subsidiary Guarantors debt balance as presented in the accompanying March 31, 2019 condensed consolidating balance sheet is approximately $158 million of other financing obligations that are not subject to the cross guarantee agreement.
Condensed Consolidating Statements of Income and Comprehensive Income for the Three Months Ended March 31, 2019 (In Millions) (Unaudited) |
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | Parent
Issuer and
Guarantor | | Subsidiary
Issuer and
Guarantor -
KMP | | Subsidiary
Guarantors | | Subsidiary
Non-Guarantors | | Consolidating Adjustments | | Consolidated KMI |
| Total Revenues | | $ | — |
| | $ | — |
| | $ | 3,150 |
| | $ | 325 |
| | $ | (46 | ) | | $ | 3,429 |
|
| | | | | | | | | | | | | |
| Operating Costs, Expenses and Other | | | | | | | | | | | | |
| Costs of sales | | — |
| | — |
| | 918 |
| | 65 |
| | (35 | ) | | 948 |
|
| Depreciation, depletion and amortization | | 5 |
| | — |
| | 520 |
| | 68 |
| | — |
| | 593 |
|
| Other operating (income) expense | | (1 | ) | | — |
| | 740 |
| | 142 |
| | (11 | ) | | 870 |
|
| Total Operating Costs, Expenses and Other | | 4 |
| | — |
| | 2,178 |
| | 275 |
| | (46 | ) | | 2,411 |
|
| | | | | | | | | | | | | |
| Operating (Loss) Income | | (4 | ) | | — |
| | 972 |
| | 50 |
| | — |
| | 1,018 |
|
| | | | | | | | | | | | | |
| Other Income (Expense) | | | | | | | | | | | | |
| Earnings from consolidated subsidiaries | | 893 |
| | 847 |
| | 49 |
| | 18 |
| | (1,807 | ) | | — |
|
| Earnings from equity investments | | — |
| | — |
| | 192 |
| | — |
| | — |
| | 192 |
|
| Interest, net | | (190 | ) | | (3 | ) | | (258 | ) | | (9 | ) | | — |
| | (460 | ) |
| Amortization of excess cost of equity investments and other, net | | (4 | ) | | — |
| | (7 | ) | | — |
| | — |
| | (11 | ) |
| | | | | | | | | | | | | |
| Income Before Income Taxes | | 695 |
| | 844 |
| | 948 |
| | 59 |
| | (1,807 | ) | | 739 |
|
| | | | | | | | | | | | | |
| Income Tax Expense | | (139 | ) | | (1 | ) | | (21 | ) | | (11 | ) | | — |
| | (172 | ) |
| | | | | | | | | | | | | |
| Net Income | | 556 |
| | 843 |
| | 927 |
| | 48 |
| | (1,807 | ) | | 567 |
|
| Net Income Attributable to Noncontrolling Interests | | — |
| | — |
| | — |
| | — |
| | (11 | ) | | (11 | ) |
| Net Income Attributable to Controlling Interests | | $ | 556 |
| | $ | 843 |
| | $ | 927 |
| | $ | 48 |
| | $ | (1,818 | ) | | $ | 556 |
|
| | | | | | | | | | | | | |
| Net Income | | $ | 556 |
| | $ | 843 |
| | $ | 927 |
| | $ | 48 |
| | $ | (1,807 | ) | | $ | 567 |
|
| Total other comprehensive (loss) income | | (178 | ) | | (227 | ) | | (232 | ) | | 19 |
| | 434 |
| | (184 | ) |
| Comprehensive income | | 378 |
| | 616 |
| | 695 |
| | 67 |
| | (1,373 | ) | | 383 |
|
| Comprehensive income attributable to noncontrolling interests | | — |
| | — |
| | — |
| | — |
| | (5 | ) | | (5 | ) |
| Comprehensive income attributable to controlling interests | | $ | 378 |
| | $ | 616 |
| | $ | 695 |
| | $ | 67 |
| | $ | (1,378 | ) | | $ | 378 |
|
Condensed Consolidating Statements of Income and Comprehensive Income for the Three Months Ended March 31, 2018 (In Millions) (Unaudited) |
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | Parent
Issuer and
Guarantor | | Subsidiary
Issuer and
Guarantor -
KMP | | Subsidiary
Guarantors | | Subsidiary
Non-Guarantors | | Consolidating Adjustments | | Consolidated KMI |
| Total Revenues | | $ | — |
| | $ | — |
| | $ | 3,080 |
| | $ | 386 |
| | $ | (48 | ) | | $ | 3,418 |
|
| | | | | | | | | | | | | |
| Operating Costs, Expenses and Other | | | | | | | | | | | | |
| Costs of sales | | — |
| | — |
| | 979 |
| | 77 |
| | (37 | ) | | 1,019 |
|
| Depreciation, depletion and amortization | | 5 |
| | — |
| | 484 |
| | 81 |
| | — |
| | 570 |
|
| Other operating expenses | | (25 | ) | | 1 |
| | 743 |
| | 172 |
| | (11 | ) | | 880 |
|
| Total Operating Costs, Expenses and Other | | (20 | ) | | 1 |
| | 2,206 |
| | 330 |
| | (48 | ) | | 2,469 |
|
| | | | | | | | | | | | | |
| Operating Income (Loss) | | 20 |
| | (1 | ) | | 874 |
| | 56 |
| | — |
| | 949 |
|
| | | | | | | | | | | | | |
| Other Income (Expense) | | | | | | | | | | | | |
| Earnings from consolidated subsidiaries | | 806 |
| | 745 |
| | 51 |
| | 16 |
| | (1,618 | ) | | — |
|
| Earnings from equity investments | | — |
| | — |
| | 220 |
| | — |
| | — |
| | 220 |
|
| Interest, net | | (184 | ) | | (4 | ) | | (273 | ) | | (6 | ) | | — |
| | (467 | ) |
| Amortization of excess cost of equity investments and other, net | | 6 |
| | — |
| | (10 | ) | | 8 |
| | — |
| | 4 |
|
| | | | | | | | | | | | | |
| Income Before Income Taxes | | 648 |
| | 740 |
| | 862 |
| | 74 |
| | (1,618 | ) | | 706 |
|
| | | | | | | | | | | | | |
| Income Tax Expense | | (124 | ) | | (2 | ) | | (26 | ) | | (12 | ) | | — |
| | (164 | ) |
| | | | | | | | | | | | | |
| Net Income | | 524 |
| | 738 |
| | 836 |
| | 62 |
| | (1,618 | ) | | 542 |
|
| Net Income Attributable to Noncontrolling Interests | | — |
| | — |
| | — |
| | — |
| | (18 | ) | | (18 | ) |
| | | | | | | | | | | | | |
| Net Income Attributable to Controlling Interests | | 524 |
| | 738 |
| | 836 |
| | 62 |
| | (1,636 | ) | | 524 |
|
| | | | | | | | | | | | | |
| Preferred Stock Dividends | | (39 | ) | | — |
| | — |
| | — |
| | — |
| | (39 | ) |
| Net Income Available to Common Stockholders | | $ | 485 |
| | $ | 738 |
| | $ | 836 |
| | $ | 62 |
| | $ | (1,636 | ) | | $ | 485 |
|
| | | | | | | | | | | | | |
| Net Income | | $ | 524 |
| | $ | 738 |
| | $ | 836 |
| | $ | 62 |
| | $ | (1,618 | ) | | $ | 542 |
|
| Total other comprehensive loss | | (17 | ) | | (56 | ) | | (57 | ) | | (78 | ) | | 167 |
| | (41 | ) |
| Comprehensive income (loss) | | 507 |
| | 682 |
| | 779 |
| | (16 | ) | | (1,451 | ) | | 501 |
|
| Comprehensive loss attributable to noncontrolling interests | | — |
| | — |
| | — |
| | — |
| | 6 |
| | 6 |
|
| Comprehensive income (loss) attributable to controlling interests | | $ | 507 |
| | $ | 682 |
| | $ | 779 |
| | $ | (16 | ) | | $ | (1,445 | ) | | $ | 507 |
|
Condensed Consolidating Balance Sheets as of March 31, 2019 (In Millions) (Unaudited) |
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | Parent
Issuer and
Guarantor | | Subsidiary
Issuer and
Guarantor -
KMP | | Subsidiary
Guarantors | | Subsidiary
Non-Guarantors | | Consolidating Adjustments | | Consolidated KMI |
| ASSETS | | | | | | | | | | | | |
| Cash and cash equivalents | | $ | 2 |
| | $ | — |
| | $ | — |
| | $ | 219 |
| | $ | — |
| | $ | 221 |
|
| Other current assets - affiliates | | 5,647 |
| | 3,314 |
| | 27,163 |
| | 1,396 |
| | (37,520 | ) | | — |
|
| All other current assets | | 73 |
| | 22 |
| | 1,765 |
| | 193 |
| | (12 | ) | | 2,041 |
|
| Property, plant and equipment, net | | 246 |
| | — |
| | 30,607 |
| | 6,929 |
| | — |
| | 37,782 |
|
| Investments | | 664 |
| | — |
| | 7,007 |
| | 99 |
| | — |
| | 7,770 |
|
| Investments in subsidiaries | | 42,572 |
| | 40,683 |
| | 4,297 |
| | 4,337 |
| | (91,889 | ) | | — |
|
| Goodwill | | 13,789 |
| | 22 |
| | 5,166 |
| | 2,988 |
| | — |
| | 21,965 |
|
| Notes receivable from affiliates | | 935 |
| | 20,341 |
| | 192 |
| | 1,117 |
| | (22,585 | ) | | — |
|
| Deferred income taxes | | 3,049 |
| | — |
| | — |
| | — |
| | (1,402 | ) | | 1,647 |
|
| Other non-current assets | | 656 |
| | 148 |
| | 3,973 |
| | 462 |
| | (373 | ) | | 4,866 |
|
| Total assets | | $ | 67,633 |
| | $ | 64,530 |
|
| $ | 80,170 |
|
| $ | 17,740 |
|
| $ | (153,781 | ) |
| $ | 76,292 |
|
| | | | | | | | | | | | | |
| LIABILITIES, REDEEMABLE NONCONTROLLING INTEREST AND STOCKHOLDERS’ EQUITY | | | | | | | | | | | | |
| Liabilities | | | | | | | | | | | | |
| Current portion of debt | | $ | 1,609 |
| | $ | 700 |
| | $ | 31 |
| | $ | 162 |
| | $ | — |
| | $ | 2,502 |
|
| Other current liabilities - affiliates | | 16,195 |
| | 14,209 |
| | 5,775 |
| | 1,341 |
| | (37,520 | ) | | — |
|
| All other current liabilities | | 358 |
| | 129 |
| | 1,591 |
| | 443 |
| | (14 | ) | | 2,507 |
|
| Long-term debt | | 13,500 |
| | 16,163 |
| | 3,013 |
| | 652 |
| | — |
| | 33,328 |
|
| Notes payable to affiliates | | 1,246 |
| | 448 |
| | 20,536 |
| | 355 |
| | (22,585 | ) | | — |
|
| Deferred income taxes | | — |
| | — |
| | 522 |
| | 880 |
| | (1,402 | ) | | — |
|
| All other long-term liabilities and deferred credits | | 1,113 |
| | 40 |
| | 1,208 |
| | 804 |
| | (371 | ) | | 2,794 |
|
| Total liabilities | | 34,021 |
| | 31,689 |
|
| 32,676 |
|
| 4,637 |
|
| (61,892 | ) |
| 41,131 |
|
| | | | | | | | | | | | | |
| Redeemable noncontrolling interest | | — |
| | — |
| | 705 |
| | — |
| | — |
| | 705 |
|
| Stockholders’ equity | | | | | | | | | | | | |
| Total KMI equity | | 33,612 |
| | 32,841 |
| | 46,789 |
| | 13,103 |
| | (92,733 | ) | | 33,612 |
|
| Noncontrolling interests | | — |
| | — |
| | — |
| | — |
| | 844 |
| | 844 |
|
| Total stockholders’ equity | | 33,612 |
| | 32,841 |
|
| 46,789 |
|
| 13,103 |
|
| (91,889 | ) |
| 34,456 |
|
| Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity | | $ | 67,633 |
| | $ | 64,530 |
|
| $ | 80,170 |
|
| $ | 17,740 |
|
| $ | (153,781 | ) |
| $ | 76,292 |
|
Condensed Consolidating Balance Sheets as of December 31, 2018 (In Millions) |
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | Parent
Issuer and
Guarantor | | Subsidiary
Issuer and
Guarantor -
KMP | | Subsidiary
Guarantors | | Subsidiary
Non-Guarantors | | Consolidating Adjustments | | Consolidated KMI |
| ASSETS | | | | | | | | | | | | |
| Cash and cash equivalents | | $ | 8 |
| | $ | — |
| | $ | — |
| | $ | 3,277 |
| | $ | (5 | ) | | $ | 3,280 |
|
| Other current assets - affiliates | | 4,465 |
| | 4,788 |
| | 23,851 |
| | 1,031 |
| | (34,135 | ) | | — |
|
| All other current assets | | 171 |
| | 17 |
| | 2,056 |
| | 212 |
| | (14 | ) | | 2,442 |
|
| Property, plant and equipment, net | | 231 |
| | — |
| | 30,750 |
| | 6,916 |
| | — |
| | 37,897 |
|
| Investments | | 664 |
| | — |
| | 6,718 |
| | 99 |
| | — |
| | 7,481 |
|
| Investments in subsidiaries | | 42,096 |
| | 40,049 |
| | 6,077 |
| | 4,324 |
| | (92,546 | ) | | — |
|
| Goodwill | | 13,789 |
| | 22 |
| | 5,166 |
| | 2,988 |
| | — |
| | 21,965 |
|
| Notes receivable from affiliates | | 945 |
| | 20,345 |
| | 247 |
| | 1,043 |
| | (22,580 | ) | | — |
|
| Deferred income taxes | | 3,137 |
| | — |
| | — |
| | — |
| | (1,571 | ) | | 1,566 |
|
| Other non-current assets | | 233 |
| | 105 |
| | 3,823 |
| | 74 |
| | — |
| | 4,235 |
|
| Total assets | | $ | 65,739 |
| | $ | 65,326 |
|
| $ | 78,688 |
|
| $ | 19,964 |
|
| $ | (150,851 | ) |
| $ | 78,866 |
|
| | | | | | | | | | | | | |
| LIABILITIES, REDEEMABLE NONCONTROLLING INTEREST AND STOCKHOLDERS’ EQUITY | | | | | | | | | | | | |
| Liabilities | | | | | | | | | | | | |
| Current portion of debt | | $ | 1,933 |
| | $ | 1,300 |
| | $ | 30 |
| | $ | 125 |
| | $ | — |
| | $ | 3,388 |
|
| Other current liabilities - affiliates | | 14,189 |
| | 14,087 |
| | 4,898 |
| | 961 |
| | (34,135 | ) | | — |
|
| All other current liabilities | | 486 |
| | 354 |
| | 1,838 |
| | 1,510 |
| | (19 | ) | | 4,169 |
|
| Long-term debt | | 13,474 |
| | 16,799 |
| | 3,020 |
| | 643 |
| | — |
| | 33,936 |
|
| Notes payable to affiliates | | 1,234 |
| | 448 |
| | 20,543 |
| | 355 |
| | (22,580 | ) | | — |
|
| Deferred income taxes | | — |
| | — |
| | 503 |
| | 1,068 |
| | (1,571 | ) | | — |
|
| Other long-term liabilities and deferred credits | | 745 |
| | 59 |
| | 944 |
| | 428 |
| | — |
| | 2,176 |
|
| Total liabilities | | 32,061 |
| | 33,047 |
|
| 31,776 |
|
| 5,090 |
|
| (58,305 | ) |
| 43,669 |
|
| | | | | | | | | | | | | |
| Redeemable noncontrolling interest | | — |
| | — |
| | 666 |
| | — |
| | — |
| | 666 |
|
| Stockholders’ equity | | | | | | | | | | | | |
| Total KMI equity | | 33,678 |
| | 32,279 |
| | 46,246 |
| | 14,874 |
| | (93,399 | ) | | 33,678 |
|
| Noncontrolling interests | | — |
| | — |
| | — |
| | — |
| | 853 |
| | 853 |
|
| Total stockholders’ equity | | 33,678 |
|
| 32,279 |
|
| 46,246 |
|
| 14,874 |
|
| (92,546 | ) |
| 34,531 |
|
| Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity | | $ | 65,739 |
| | $ | 65,326 |
|
| $ | 78,688 |
|
| $ | 19,964 |
|
| $ | (150,851 | ) |
| $ | 78,866 |
|
Condensed Consolidating Statements of Cash Flows for the Three Months Ended March 31, 2019 (In Millions) (Unaudited) |
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | Parent
Issuer and
Guarantor | | Subsidiary
Issuer and
Guarantor -
KMP | | Subsidiary
Guarantors | | Subsidiary
Non-Guarantors | | Consolidating Adjustments | | Consolidated KMI |
| Net cash (used in) provided by operating activities | | $ | (663 | ) | | $ | 737 |
| | $ | 4,724 |
| | $ | (98 | ) | | $ | (4,065 | ) | | $ | 635 |
|
| | | | | | | | | | | | | |
| Cash flows from investing activities | | | | | | | | | | | | |
| Capital expenditures | | (21 | ) | | — |
| | (423 | ) | | (110 | ) | | — |
| | (554 | ) |
| Sales of assets and equity investments, net of working capital settlements | | — |
| | — |
| | 12 |
| | (28 | ) | | — |
| | (16 | ) |
| Sales of property, plant and equipment, net of removal costs | | 3 |
| | — |
| | 14 |
| | (3 | ) | | — |
| | 14 |
|
| Contributions to investments | | (28 | ) | | — |
| | (302 | ) | | (1 | ) | | — |
| | (331 | ) |
| Distributions from equity investments in excess of cumulative earnings | | 294 |
| | — |
| | 81 |
| | — |
| | (294 | ) | | 81 |
|
| Funding to affiliates | | (2,660 | ) | | (7 | ) | | (3,831 | ) | | (244 | ) | | 6,742 |
| | — |
|
| Loans to related party | | — |
| | — |
| | (8 | ) | | — |
| | — |
| | (8 | ) |
| Net cash used in investing activities | | (2,412 | ) | | (7 | ) |
| (4,457 | ) |
| (386 | ) |
| 6,448 |
|
| (814 | ) |
| | | | | | | | | | | | | |
| Cash flows from financing activities | | | | | | | | | | | | |
| Issuances of debt | | 1,342 |
| | — |
| | — |
| | 57 |
| | — |
| | 1,399 |
|
| Payments of debt | | (1,666 | ) | | (1,300 | ) | | (2 | ) | | (22 | ) | | — |
| | (2,990 | ) |
| Debt issue costs | | (2 | ) | | — |
| | — |
| | — |
| | — |
| | (2 | ) |
| Cash dividends - common shares | | (455 | ) | | — |
| | — |
| | — |
| | — |
| | (455 | ) |
| Repurchases of common shares | | (2 | ) | | — |
| | — |
| | — |
| | — |
| | (2 | ) |
| Funding from affiliates | | 3,855 |
| | 1,705 |
| | 1,010 |
| | 172 |
| | (6,742 | ) | | — |
|
| Contributions from investment partner | | — |
| | — |
| | 38 |
| | — |
| | — |
| | 38 |
|
| Distributions to parents | | — |
| | (1,132 | ) | | (1,313 | ) | | (2,812 | ) | | 5,257 |
| | — |
|
| Distribution to noncontrolling interests - KML distribution of the TMPL sale proceeds | | — |
| | — |
| | — |
| | — |
| | (879 | ) | | (879 | ) |
| Distributions to noncontrolling interests - other | | — |
| | — |
| | — |
| | — |
| | (14 | ) | | (14 | ) |
| Other, net | | (3 | ) | | — |
| | — |
| | — |
| | — |
| | (3 | ) |
| Net cash provided by (used in) financing activities | | 3,069 |
| | (727 | ) |
| (267 | ) |
| (2,605 | ) |
| (2,378 | ) |
| (2,908 | ) |
| | | | | | | | | | | | | |
| Effect of exchange rate changes on cash, cash equivalents and restricted deposits | | — |
| | — |
| | — |
| | 26 |
| | — |
| | 26 |
|
| | | | | | | | | | | | | |
| Net (decrease) increase in Cash, Cash Equivalents and Restricted Deposits | | (6 | ) | | 3 |
|
| — |
|
| (3,063 | ) |
| 5 |
|
| (3,061 | ) |
| Cash, Cash Equivalents, and Restricted Deposits, beginning of period | | 8 |
| | — |
| | — |
| | 3,328 |
| | (5 | ) | | 3,331 |
|
| Cash, Cash Equivalents, and Restricted Deposits, end of period | | $ | 2 |
| | $ | 3 |
|
| $ | — |
|
| $ | 265 |
|
| $ | — |
|
| $ | 270 |
|
Condensed Consolidating Statements of Cash Flows for the Three Months Ended March 31, 2018 (In Millions) (Unaudited) |
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | Parent
Issuer and
Guarantor | | Subsidiary
Issuer and
Guarantor -
KMP | | Subsidiary
Guarantors | | Subsidiary
Non-Guarantors | | Consolidating Adjustments | | Consolidated KMI |
| Net cash (used in) provided by operating activities | | $ | (302 | ) | | $ | 838 |
| | $ | 2,356 |
| | $ | 263 |
| | $ | (2,181 | ) | | $ | 974 |
|
| | | | | | | | | | | | | |
| Cash flows from investing activities | | | | | | | | | | | | |
| Acquisitions of assets and investments | | — |
| | — |
| | (20 | ) | | — |
| | — |
| | (20 | ) |
| Capital expenditures | | (19 | ) | | — |
| | (451 | ) | | (237 | ) | | — |
| | (707 | ) |
| Proceeds from sales of equity investments | | — |
| | — |
| | 33 |
| | — |
| | — |
| | 33 |
|
| Sales of property, plant and equipment, net of removal costs | | 2 |
| | — |
| | — |
| | (1 | ) | | — |
| | 1 |
|
| Contributions to investments | | — |
| | — |
| | (64 | ) | | (2 | ) | | — |
| | (66 | ) |
| Distributions from equity investments in excess of cumulative earnings | | 559 |
| | — |
| | 42 |
| | — |
| | (559 | ) | | 42 |
|
| Funding (to) from affiliates | | (3,074 | ) | | 34 |
| | (1,388 | ) | | (248 | ) | | 4,676 |
| | — |
|
| Loans to related party | | — |
| | — |
| | (8 | ) | | — |
| | — |
| | (8 | ) |
| Net cash (used in) provided by investing activities | | (2,532 | ) | | 34 |
|
| (1,856 | ) |
| (488 | ) | | 4,117 |
| | (725 | ) |
| | | | | | | | | | | | | |
| Cash flows from financing activities | | | | | | | | | | | | |
| Issuances of debt | | 5,961 |
| | — |
| | — |
| | 78 |
| | — |
| | 6,039 |
|
| Payments of debt | | (3,929 | ) | | (975 | ) | | (777 | ) | | (3 | ) | | — |
| | (5,684 | ) |
| Debt issue costs | | (17 | ) | | — |
| | — |
| | (4 | ) | | — |
| | (21 | ) |
| Cash dividends - common shares | | (277 | ) | | — |
| | — |
| | — |
| | — |
| | (277 | ) |
| Cash dividends - preferred shares | | (39 | ) | | — |
| | — |
| | — |
| | — |
| | (39 | ) |
| Repurchases of common shares | | (250 | ) | | — |
| | — |
| | — |
| | — |
| | (250 | ) |
| Funding from affiliates | | 1,444 |
| | 1,402 |
| | 1,639 |
| | 191 |
| | (4,676 | ) | | — |
|
| Contribution from investment partner | | — |
| | — |
| | 38 |
| | — |
| | — |
| | 38 |
|
| Contributions from parents | | — |
| | — |
| | 3 |
| | — |
| | (3 | ) | | — |
|
| Contributions from noncontrolling interests | | — |
| | — |
| | — |
| | — |
| | 3 |
| | 3 |
|
| Distributions to parents | | — |
| | (1,289 | ) | | (1,403 | ) | | (62 | ) | | 2,754 |
| | — |
|
| Distributions to noncontrolling interests | | — |
| | — |
| | — |
| | — |
| | (17 | ) | | (17 | ) |
| Other, net | | (1 | ) | | — |
| | — |
| | — |
| | — |
| | (1 | ) |
| Net cash provided by (used in) financing activities | | 2,892 |
| | (862 | ) | | (500 | ) |
| 200 |
|
| (1,939 | ) | | (209 | ) |
| | | | | | | | | | | | | |
| Effect of exchange rate changes on cash, cash equivalents and restricted deposits | | — |
| | — |
| | — |
| | (3 | ) | | — |
| | (3 | ) |
| | | | | | | | | | | | | |
| Net increase (decrease) in Cash, Cash Equivalents and Restricted Deposits | | 58 |
|
| 10 |
|
| — |
|
| (28 | ) |
| (3 | ) | | 37 |
|
| Cash, Cash Equivalents, and Restricted Deposits, beginning of period | | 3 |
| | 1 |
| | — |
| | 323 |
| | (1 | ) | | 326 |
|
| Cash, Cash Equivalents, and Restricted Deposits, end of period | | $ | 61 |
|
| $ | 11 |
|
| $ | — |
|
| $ | 295 |
|
| $ | (4 | ) | | $ | 363 |
|
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 our accompanying interim consolidated financial statements and related notes included elsewhere in this report, and in conjunction with (i) our consolidated financial statements and related notes and (ii) our management’s discussion and analysis of financial condition and results of operations included in our 20182019 Form 10-K.
Sale of Trans MountainU.S. Portion of Cochin Pipeline System and Its Expansion ProjectKML
On August 31, 2018, KML completedDecember 16, 2019, we closed on two cross-conditional transactions resulting in the sale of the TMPL, the TMEP, Puget Sound pipeline system and Kinder Morgan Canada Inc., the Canadian employer of our staff that operate the business, which were indirectly acquired by the Government of Canada through Trans Mountain Corporation (a subsidiary of the Canada Development Investment Corporation) for net cash consideration of C$4.4 billion (U.S.$3.4 billion), net of working capital adjustments (TMPL Sale). During the three months ended March 31, 2019, KML settled the remaining C$37.0 million (U.S.$28 million) of working capital adjustments, which amount is included in the accompanying consolidated statement of cash flows within “Sales of assets and equity investments, net of working capital settlements” for the three months ended March 31, 2019 and for which we had substantially accrued for as of December 31, 2018.
On January 3, 2019, KML distributed the net proceeds from the TMPL Sale to its shareholders as a return of capital. Public owners of KML’s restricted voting shares, reflected as noncontrolling interests by us, received approximately $0.9 billion (C$1.2 billion), and most of our approximate 70%U.S. portion of the netCochin Pipeline and all the outstanding equity of KML, including our 70% interest, to Pembina Pipeline Corporation (Pembina) (together, the “KML and U.S. Cochin Sale”). We received approximately 25 million shares of Pembina common equity for our interest in KML. On January 9, 2020, we sold our Pembina shares and received proceeds of $1.9 billion (C$2.5 billion) (after Canadianapproximately $907 million ($764 million after tax) which were used to repay maturing debt. The assets sold were part of our outstanding commercial paper borrowingsNatural Gas Pipelines and Terminals business segments.
COVID-19
The COVID-19 pandemic-related reduction in energy demand and the sharp decline in commodity prices related to the combined impact of $0.4 billion,falling demand and recent increases in Februaryproduction from Organization of Petroleum Exporting Countries (OPEC) members and other international suppliers has caused significant disruptions and volatility in the global marketplace during the first quarter of 2020, which have adversely affected our business. In response to COVID-19, governments around the world have implemented increasingly stringent measures to help reduce the spread of the virus, including stay-at-home and shelter-in-place orders, travel restrictions and other measures. These measures have adversely affected the economies and financial markets of the U.S. and many other countries, resulting in an economic downturn that has negatively impacted global demand and prices for the products handled by our pipelines, terminals, shipping vessels and other facilities. There is significant uncertainty regarding the length and impact of the virus on the energy industry and potential impacts to our business. For further discussion, see Part II, Item 1A. “Risk Factors.”
Events as described above resulted in decreases of current and expected long-term crude oil and NGL sale prices we expect to realize along with significant reductions to the market capitalization of many oil and gas producing companies. These events triggered us to review the carrying value of our long-lived assets of our CO2 business segment and conduct interim tests of the recoverability of goodwill for our CO2 and Natural Gas Pipelines Non-Regulated reporting units as of March 31, 2020. Our evaluation resulted in the recognition of a $350 million impairment for long-lived assets in our CO2 business segment and a goodwill impairment of $600 million. For a further discussion of these impairments and our risk for future impairments, see Note 2, “Impairments.”
2020 Outlook
In December 2019, we announced our 2020 budget guidance in which we expected to pay downdeclare dividends of $1.25 per share, a 25% increase from the 2019 declared dividends of $1.00 per share, and to generate approximately $1.3$5.1 billion of maturingDCF, or $2.24 of DCF per share, and $7.6 billion of Adjusted EBITDA. On April 22, 2020, we announced an update to our outlook for 2020 to include estimated impacts of the economic downturn resulting from COVID-19 and unfavorable commodity demand and prices. Because of the current environment, we now expect DCF to be below budget by approximately 10% and Adjusted EBITDA to be below budget by approximately 8%. As a result, we now expect to end 2020 with a Net Debt-to-Adjusted EBITDA ratio of approximately 4.6 times, consistent with our long-term debt.objective of around 4.5 times.
In addition, market conditions have resulted in a number of planned expansion projects no longer meeting our internal return thresholds, and we therefore reduced our budget of $2.4 billion by approximately $700 million. With this reduction, DCF less expansion capital expenditures is improved by approximately $200 million compared to budget, helping to keep our balance sheet strong. In addition, to help preserve flexibility and maintain balance sheet strength, our board of directors declared a dividend of $0.2625 per share, or $1.05 per share annualized. This represents a 5% increase over last quarter rather than the previously budgeted dividend of $0.3125, which would have been a 25% increase. We expect that our 2020 dividend payments as well as our 2020 discretionary spending will be funded with internally generated cash flow.
Considerable uncertainty exists with respect to the future pace and extent of a global economic recovery from the effects of the COVID-19 pandemic. In addition to the below discussions included in “—Results of Operations—Consolidated Earnings
Results” and “—Segment Earnings Results,” the following table provides assumptions and sensitivities for impacts on our business that may be affected by that uncertainty.
|
| | | | | | | | | | | | | | | | |
Remaining 9 Months
Commodity Volume and Price Assumptions | Sensitivity Range | Potential Impact to 2020 Adjusted EBITDA and DCF
(in millions, by segment) |
| | | Natural Gas Pipelines | Products Pipelines | Terminals | CO2 | Total |
| Natural Gas Gathering and Processing Volumes | | | | | |
| 3,325 Bbtu/d | +/- 5% | $ | 23 |
| | | | $ | 23 |
|
| Refined Products Volumes (gasoline, diesel and jet fuel) | | | | | | |
1,452 MBbl/d for Products Pipelines
(the following apply to both the Products Pipelines and Terminals segments)(a) | +/- 5% | | $ | 26 |
| $ | 12 |
| | $ | 38 |
|
| Qtr 2: 40% - 45% reduction from budgeted quarter amount | | | | | | |
| Qtr 3: 10% - 12% reduction from budgeted quarter amount | | | | | | |
| Qtr 4: 5% - 6% reduction from budgeted quarter amount | | | | | | |
| Crude Oil & Condensate Pipeline Volumes | | | | | | |
| 587 MBbl/d | +/- 5% | | $ | 11 |
| | | $ | 11 |
|
| Crude Oil Production Volumes | | | | | | |
| 46 MBbl/d, gross (33 MBbl/d, net) | +/- 5% | | | | $ | 12 |
| $ | 12 |
|
| Crude Oil Price | | | | | | |
| $30/bbl | +/- $1/bbl WTI | $ | 0.2 |
| $ | 0.9 |
| | $ | 0.5 |
| $ | 1.6 |
|
| NGL to Crude Oil Price Ratio | | | | | | |
Natural Gas Pipelines 49% and CO2 25% | +/- 1% | $ | 0.1 |
| | | $ | 0.4 |
| $ | 0.5 |
|
| | | | | | Potential Impact to 2020 DCF
(in millions) |
| 3-Month LIBOR Interest Rate(b) | | | | | Total |
| 0.64% | +/- 10-bp | | | | $ | 2.4 | |
| | | | | | | |
| Purpose of Outlook Assumptions and Sensitivity: | | | | | |
| The above table provides key assumptions used in our 2020 forecast for the remaining 9 months of 2020 to incorporate the estimated impact of COVID-19 and oil price decline. It also provides estimated financial impacts to 2020 Adjusted EBITDA and DCF for potential changes in those assumptions. These sensitivities are general estimates of anticipated impacts on our business segments and overall business of changes relative to our assumptions; the impact of actual changes may vary significantly depending on the affected asset, product and contract. |
Notes:
| |
| (a) | Potential impact to 2020 Adjusted EBITDA for Terminals includes sensitivity to changes in petroleum coke volume. |
| |
| (b) | As of March 31, 2020, we had approximately $8.0 billion of fixed-to-floating interest rate swaps on our long-term debt. In March 2020, we fixed the LIBOR component on $2.5 billion of these swaps through the end of 2020 only. As a result, approximately 17% of the principal amount of our debt balance as of March 31, 2020 was 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 swaps. |
We do not provide budgeted net income attributable to common stockholders or budgeted net income, the GAAP financial measures most directly comparable to the non-GAAP financial measures of DCF and Adjusted EBITDA, respectively, due to the impracticality of quantifying certain components required by GAAP such as: unrealized gains and losses on derivatives marked-to-market and potential changes in estimates for certain contingent liabilities. See “—Results of Operations—Overview—Non-GAAP Financial Measures” below.
Our updated expectations for 2020 discussed above involve risks, uncertainties and assumptions, and are not guarantees of performance. Many of the factors that will determine these expectations are beyond our ability to control or predict, and because of these uncertainties, it is advisable not to put undue reliance on any forward-looking statements. Please read Part II, Item 1A. “Risk Factors” below and “Information Regarding Forward-Looking Statements” at the beginning of this report for more information. Furthermore, we disclaim any obligation, other than as required by applicable law, to publicly update or revise any of our forward-looking statements to reflect future events or developments.
Results of Operations
Overview
OurAs described in further detail below, our management evaluates our performance primarily using the GAAP financial measures of Segment EBDA (as presented in Note 7, “Reportable Segments”), net (loss) income and as discussed below under “—Non-GAAPnet (loss) income attributable to Kinder Morgan, Inc., along with the non-GAAP financial measures of Adjusted Earnings and DCF, both in the aggregate and per share for each, Adjusted Segment EBDA, Adjusted EBITDA, Net Debt and Net Debt to Adjusted EBITDA.
GAAP Financial Measures” DCF
The Consolidated Earnings Results for the three months ended March 31, 2020 and 2019 present Segment EBDA, before certain items.net (loss) income and net (loss) income attributable to Kinder Morgan, Inc. which are prepared and presented in accordance with GAAP. Segment EBDA is a useful measure of our operating performance because it measures the operating results of our segments before DD&A and certain expenses that are generally not controllable by our business segment operating managers, such as general and administrative expenses and corporate charges, interest expense, net, and income taxes. Our general and administrative expenses and corporate charges include such items as unallocated employee benefits, insurance, rentals, unallocated litigation and environmental expenses, and shared corporate services including accounting, information technology, human resources and legal services.
In our discussions of the operating results of individual businesses that follow, we generally identify the important fluctuations between periods that are attributable to dispositions and acquisitions separately from those that are attributable to businesses owned in both periods.
For segment reporting purposes, effective January 1, 2019, certain assets were transferred among our business segments. As a result, individual segment results for the three months ended March 31, 2018 have been reclassified to conform to the current presentation in the following Management Discussion and Analysis tables, which includes increased (decreased) Segment EBDA for the following business segments: Natural Gas Pipelines $(8) million; Products Pipelines $7 million; and Terminals $1 million.
Consolidated Earnings Results
|
| | | | | | | | | | | | | | |
| | Three Months Ended March 31, | | |
| | 2019 | | 2018 | | Earnings
increase/(decrease) |
| | (In millions, except percentages) |
| Segment EBDA(a) | | | | | | | |
| Natural Gas Pipelines | $ | 1,203 |
| | $ | 1,128 |
| | $ | 75 |
| | 7 | % |
| Products Pipelines | 276 |
| | 266 |
| | 10 |
| | 4 | % |
| Terminals | 299 |
| | 296 |
| | 3 |
| | 1 | % |
CO2 | 198 |
| | 199 |
| | (1 | ) | | (1 | )% |
| Kinder Morgan Canada(b) | (2 | ) | | 46 |
| | (48 | ) | | (104 | )% |
| Total Segment EBDA(c) | 1,974 |
| | 1,935 |
| | 39 |
| | 2 | % |
| DD&A | (593 | ) | | (570 | ) | | (23 | ) | | (4 | )% |
| Amortization of excess cost of equity investments | (21 | ) | | (32 | ) | | 11 |
| | 34 | % |
| General and administrative and corporate charges(d) | (161 | ) | | (160 | ) | | (1 | ) | | (1 | )% |
| Interest, net(e) | (460 | ) | | (467 | ) | | 7 |
| | 1 | % |
| Income before income taxes | 739 |
| | 706 |
| | 33 |
| | 5 | % |
| Income tax expense(f) | (172 | ) | | (164 | ) | | (8 | ) | | (5 | )% |
| Net income | 567 |
| | 542 |
| | 25 |
| | 5 | % |
| Net income attributable to noncontrolling interests | (11 | ) | | (18 | ) | | 7 |
| | 39 | % |
| Net income attributable to Kinder Morgan, Inc. | 556 |
| | 524 |
| | 32 |
| | 6 | % |
| Preferred stock dividends | — |
| | (39 | ) | | 39 |
| | 100 | % |
| Net Income Available to Common Stockholders | $ | 556 |
| | $ | 485 |
| | $ | 71 |
| | 15 | % |
_______
| |
(a) | Includes revenues, earnings from equity investments, and other, net, less operating expenses. Operating expenses include costs of sales, operations and maintenance expenses, and taxes, other than income taxes. |
| |
(b) | As a result of the TMPL Sale on August 31, 2018, this segment does not have results of operations on a prospective basis. |
Certain items affecting Total Segment EBDA (see “—Non-GAAP Measures” below)
| |
(c) | 2019 and 2018 amounts include net decreases in earnings of $8 million and $16 million, respectively, related to the combined effect of the certain items impacting Total Segment EBDA. The extent to which these items affect each of our business segments is discussed below in the footnotes to the tables within “—Segment Earnings Results.”
|
| |
(d) | 2019 and 2018 amounts include a net increase in expense of $3 million and a net decrease in expense of $4 million, respectively, related to the combined effect of the certain items related to general and administrative expense and corporate charges disclosed below in “—General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests.”
|
| |
(e) | 2019 and 2018 amounts include a net increase in expense of $2 million and a net decrease in expense of $5 million, respectively, related to the combined effect of the certain items related to interest expense, net disclosed below in “—General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests.”
|
| |
(f) | 2019 and 2018 amounts include a net increase in expense of $2 million and a net decrease in expense of $3 million, respectively, related to the combined net effect of the certain items related to income tax expense representing the income tax provision on certain items plus discrete income tax items. |
The certain item totals reflected in footnotes (c) through (e) to the table above accounted for a $6 million decrease in income before income taxes for the first quarter of 2019, as compared to the same prior year period (representing the difference between decreases of $13 million and $7 million in income before income taxes for the first quarter of 2019 and 2018, respectively). After giving effect to these certain items, which are discussed in more detail in the discussion that follows, the remaining increase of $39 million (5%) from the prior year quarter in income before income taxes is primarily attributable to increased performance from our Natural Gas Pipelines business segment and decreased interest expense, net and decreased general and administrative expense partially offset by lower earnings from our CO2 business segment, lower earnings from our Kinder Morgan Canada business segment as a result of the TMPL Sale and increased DD&A.
Non-GAAP Financial Measures
Our non-GAAP performancefinancial measures are DCF, bothdescribed below should not be considered alternatives to GAAP net (loss) income or other GAAP measures and have important limitations as analytical tools. Our computations of these non-GAAP financial measures may differ from similarly titled measures used by others. You should not consider these non-GAAP financial measures in isolation or as substitutes for an analysis of our results as reported under GAAP. Management compensates for the aggregatelimitations of these non-GAAP financial measures by reviewing our comparable GAAP measures, understanding the differences between the measures and per share,taking this information into account in its analysis and Segment EBDA before certain items. its decision making processes.
Certain items,Items
Certain Items, as adjustments used to calculate our non-GAAP financial measures, are items that are required by GAAP to be reflected in net (loss) income, but typically either (i) do not have a cash impact (for example, asset impairments), or (ii) by their nature are separately identifiable from our normal business operations and in our view are likely to occur only sporadically (for example, certain legal settlements, enactment of new tax legislation and casualty losses). See tables included in “—Consolidated Earnings Results (GAAP)—Certain Items Affecting Consolidated Earnings Results,”“—Non-GAAP Financial Measures—Reconciliation of Net (Loss) Income (GAAP) to Adjusted EBITDA” and “—Non-GAAP Financial Measures—Supplemental Information” below. In addition, Certain Items are described in more detail in the footnotes to tables included in “—Segment Earnings Results” and “—General and Administrative and Corporate Charges, Interest, net, and Noncontrolling Interests” below.
Our non-GAAP performance measures described below should not be considered alternativesAdjusted Earnings
Adjusted Earnings is calculated by adjusting net (loss) income attributable to GAAP net income or other GAAP measures and have important limitations as analytical tools. Our computations of DCF and Segment EBDA before certain items may differ from similarly titled measuresKinder Morgan, Inc. for Certain Items. Adjusted Earnings is used by others. You should not consider these non-GAAP performance measures in isolation or as substitutes for an analysisus and certain external users of our resultsfinancial statements to assess the earnings of our business excluding Certain Items as reported under GAAP. DCF should not beanother reflection of the Company’s ability to generate earnings. We believe the GAAP measure most directly comparable to Adjusted Earnings is net (loss) income attributable to Kinder Morgan, Inc. Adjusted Earnings per share uses Adjusted Earnings and applies the same two-class method used as an alternativein arriving at basic earnings per common share. See “—Non-GAAP Financial Measures—Reconciliation of Net (Loss) Income Attributable to net cash provided by operating activities computed under GAAP. Management compensates for the limitations of these non-GAAP performance 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.Kinder Morgan, Inc. (GAAP) to Adjusted Earnings to DCF” below.
DCF
DCF is calculated by adjusting net (loss) income availableattributable to common stockholders before certain itemsKinder Morgan, Inc. for Certain Items (Adjusted Earnings), and further by DD&A total book and amortization of excess cost of equity investments, income tax expense, cash taxes, sustaining capital expenditures and other items. DCF is a significant performance measure useful to management and external users of our financial statements in evaluating our performance and in measuring and estimating the ability of our assets to generate cash earnings after servicing our debt, and preferred stock dividends, paying cash taxes and expending sustaining capital, that could be used for
discretionary purposes such as common stock dividends, stock repurchases, retirement of debt, or expansion capital expenditures. DCF should not be used as an alternative to net cash provided by operating activities computed under GAAP. We believe the GAAP measure most directly comparable to DCF is net (loss) income availableattributable to common stockholders. A reconciliation of DCF to net income available to common stockholders is provided in the table below.Kinder Morgan, Inc. DCF per common share is DCF divided by average outstanding common shares, including restricted stock awards that participate in common share dividends.
See “—Non-GAAP Financial Measures—Reconciliation of Net (Loss) Income AvailableAttributable to Common StockholdersKinder Morgan, Inc. (GAAP) to DCF
|
| | | | | | | |
| | Three Months Ended March 31, |
| | 2019 | | 2018 |
| | (In millions, except per share amounts) |
| Net Income Available to Common Stockholders | $ | 556 |
| | $ | 485 |
|
| Add/(Subtract): | | | |
| Certain items before book tax(a) | 13 |
| | 51 |
|
| Book tax certain items(b) | 2 |
| | (3 | ) |
| Impact of 2017 Tax Reform(c) | — |
| | (44 | ) |
| Total certain items | 15 |
| | 4 |
|
| | | | |
| Net Income Available to Common Stockholders before certain items | 571 |
| | 489 |
|
| Add/(Subtract): | | | |
| DD&A expense(d) | 708 |
| | 690 |
|
| Total book taxes(e) | 195 |
| | 184 |
|
| Cash taxes(f) | (13 | ) | | (13 | ) |
| Other items(g) | 25 |
| | 11 |
|
| Sustaining capital expenditures(h) | (115 | ) | | (114 | ) |
| DCF | $ | 1,371 |
| | $ | 1,247 |
|
| | | | |
| Weighted average common shares outstanding for dividends(i) | 2,275 |
| | 2,218 |
|
| DCF per common share | $ | 0.60 |
| | $ | 0.56 |
|
| Declared dividend per common share | $ | 0.25 |
| | $ | 0.20 |
|
_______
| |
(a) | Consists of certain items summarized in footnotes (c) through (e) to the “—Results of Operations—Consolidated Earnings Results” table included above, and described in more detail below in the footnotes to tables included in “—Segment Earnings Results” and “—General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests” below.
|
| |
(b) | Represents income tax provision on certain items plus discrete income tax items. |
| |
(c) | 2018 amount represents 2017 Tax Reform provisional adjustments including our share of certain equity investees’ 2017 Tax Reform provisional adjustments related to our FERC-regulated business. |
| |
(d) | Includes DD&A and amortization of excess cost of equity investments. 2019 and 2018 amounts also include $94 million and $88 million, respectively, of our share of certain equity investees’ DD&A, net of the noncontrolling interests’ portion of KML DD&A and consolidating joint venture partners’ share of DD&A. |
| |
(e) | Excludes book tax certain items of $(2) million and $3 million for 2019 and 2018, respectively. 2019 and 2018 amounts also include $25 million and $17 million, respectively, of our share of taxable equity investees’ book taxes, net of the noncontrolling interests’ portion of KML book taxes. |
| |
(f) | 2018 amount includes $(10) million of our share of taxable equity investees’ cash taxes. |
| |
(g) | Includes non-cash pension expense and non-cash compensation associated with our restricted stock program. |
| |
(h) | 2019 and 2018 amounts include $(19) million and $(16) million, respectively, of our share of (i) certain equity investees’; (ii) KML’s; and (iii) certain consolidating joint venture subsidiaries’ sustaining capital expenditures. |
| |
(i) | Includes restricted stock awards that participate in common share dividends. |
Adjusted Earnings to DCF” and “—Adjusted Segment EBDA Beforeto Adjusted EBITDA to DCF” below.
Adjusted Segment EBDA
Adjusted Segment EBDA is calculated by adjusting Segment EBDA for Certain Items
attributable to the segment. Adjusted Segment EBDA before certain items is used by management in its analysis of segment performance and management of our business. General and administrative expenses are generally not under the control of our segment operating managers, and therefore, are not included when we measure business segment operating performance. We believe Adjusted Segment EBDA before certain items is a significanta useful performance metric because it provides usmanagement and external users of our financial statements additional insight into the ability of our segments to generate segment cash earnings on an ongoing basis. We believe it is useful to investors because it is a performance measure that management uses to allocate resources to our segments and assess each segment’s performance. We believe the GAAP measure most directly comparable to Adjusted Segment EBDA before certain items is Segment EBDA. See “—Consolidated Earnings Results (GAAP)—Certain Items Affecting Consolidated Earnings Results” for a reconciliation of Segment EBDA to Adjusted Segment EBDA by business segment.
InAdjusted EBITDA
Adjusted EBITDA is calculated by adjusting EBITDA for Certain Items, our share of unconsolidated joint venture DD&A and income tax expense (net of our partners’ share of consolidating joint venture DD&A and income tax expense), and net income attributable to noncontrolling interests that is further adjusted for KML noncontrolling interests (net of its applicable Certain Items) for the periods presented through KML’s sale on December 15, 2019. Adjusted EBITDA is used by management and external users, in conjunction with our Net Debt (as described further below), to evaluate certain leverage metrics. Therefore, we believe Adjusted EBITDA is useful to investors. We believe the GAAP measure most directly comparable to Adjusted EBITDA is net (loss) income. See “—Adjusted Segment EBDA to Adjusted EBITDA to DCF” and “—Non-GAAP Financial Measures—Reconciliation of Net (Loss) Income (GAAP) to Adjusted EBITDA” below.
Net Debt
Net Debt is a non-GAAP financial measure that is useful to investors and other users of our financial information in evaluating our leverage. Net Debt is calculated by subtracting from debt (i) cash and cash equivalents (which, as of March 31, 2020, the cash and cash equivalents component of Net Debt includes “Restricted deposits” held in escrow that were used on April 1, 2020 for the repayment of senior notes plus associated accrued interest); (ii) the preferred interest in the general partner of KMP (which was redeemed in January 2020); (iii) debt fair value adjustments; and (iv) the foreign exchange impact on Euro-denominated bonds for which we have entered into currency swaps. We believe the most comparable measure to Net Debt is debt net of cash and cash equivalents. Our Net Debt-to-Adjusted EBITDA ratio was 4.3 as of March 31, 2020.
Consolidated Earnings Results (GAAP)
The following tables for eachsummarize the key components of our consolidated earnings results.
|
| | | | | | | | | | | | | | |
| | Three Months Ended March 31, | | |
| | 2020 | | 2019 | | Earnings
increase/(decrease) |
| | (In millions, except percentages) |
| Segment EBDA(a) | | | | | | | |
| Natural Gas Pipelines | $ | 1,196 |
| | $ | 1,203 |
| | $ | (7 | ) | | (1 | )% |
| Products Pipelines | 269 |
| | 276 |
| | (7 | ) | | (3 | )% |
| Terminals | 257 |
| | 299 |
| | (42 | ) | | (14 | )% |
CO2 | (755 | ) | | 198 |
| | (953 | ) | | (481 | )% |
| Kinder Morgan Canada(b) | — |
| | (2 | ) | | 2 |
| | 100 | % |
| Total Segment EBDA | 967 |
| | 1,974 |
| | (1,007 | ) | | (51 | )% |
| DD&A | (565 | ) | | (593 | ) | | 28 |
| | 5 | % |
| Amortization of excess cost of equity investments | (32 | ) | | (21 | ) | | (11 | ) | | (52 | )% |
| General and administrative and corporate charges | (165 | ) | | (161 | ) | | (4 | ) | | (2 | )% |
| Interest, net | (436 | ) | | (460 | ) | | 24 |
| | 5 | % |
| (Loss) income before income taxes | (231 | ) | | 739 |
| | (970 | ) | | (131 | )% |
| Income tax expense | (60 | ) | | (172 | ) | | 112 |
| | 65 | % |
| Net (loss) income | (291 | ) | | 567 |
| | (858 | ) | | (151 | )% |
| Net income attributable to noncontrolling interests | (15 | ) | | (11 | ) | | (4 | ) | | (36 | )% |
| Net (loss) income attributable to Kinder Morgan, Inc. | (306 | ) | | 556 |
| | (862 | ) | | (155 | )% |
_______
| |
| (a) | Includes revenues, earnings from equity investments, and other, net, less operating expenses, loss on impairments and divestitures, net, and other income, net. Operating expenses include costs of sales, operations and maintenance expenses, and taxes, other than income taxes. |
| |
| (b) | 2019 amount represents a final working capital adjustment on the TMPL sale. |
(Loss) income before income taxes decreased $970 million in 2020 compared to 2019. The decrease was due primarily to a non-cash impairment of goodwill associated with our CO2 reporting unit and non-cash impairments of certain oil and gas producing assets in our CO2 business segment, and to a much lesser extent, assets in our Products Pipelines business segment. The decrease was further impacted by lower earnings from all of our business segments under “— Segmentprimarily attributable to the impact of of the KML and U.S. Cochin Sale in the fourth quarter of 2019 as well as sharp declines in commodity prices impacting the Products Pipelines business segment, partially offset by the benefit of expansion projects in our Natural Gas Pipelines business segment and by lower interest expense and DD&A expense.
Certain Items Affecting Consolidated Earnings Results” below,
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended March 31, | | |
| | 2020 | | 2019 | | |
| | GAAP | | Certain Items | | Adjusted | | GAAP | | Certain Items | | Adjusted | | Adjusted amounts
increase/(decrease) to earnings |
| | (In millions) |
| Segment EBDA | | | | | | | | | | | | | |
| Natural Gas Pipelines | $ | 1,196 |
| | $ | (17 | ) | | $ | 1,179 |
| | $ | 1,203 |
| | $ | (2 | ) | | $ | 1,201 |
| | $ | (22 | ) |
| Products Pipelines | 269 |
| | 4 |
| | 273 |
| | 276 |
| | 17 |
| | 293 |
| | (20 | ) |
| Terminals | 257 |
| | — |
| | 257 |
| | 299 |
| | — |
| | 299 |
| | (42 | ) |
CO2 | (755 | ) | | 930 |
| | 175 |
| | 198 |
| | (9 | ) | | 189 |
| | (14 | ) |
| Kinder Morgan Canada | — |
| | — |
| | — |
| | (2 | ) | | 2 |
| | — |
| | — |
|
| Total Segment EBDA(a) | 967 |
| | 917 |
| | 1,884 |
| | 1,974 |
| | 8 |
| | 1,982 |
| | (98 | ) |
| DD&A and amortization of excess cost of equity investments | (597 | ) | | — |
| | (597 | ) | | (614 | ) | | — |
| | (614 | ) | | 17 |
|
| General and administrative and corporate charges(a) | (165 | ) | | 25 |
| | (140 | ) | | (161 | ) | | 3 |
| | (158 | ) | | 18 |
|
| Interest, net(a) | (436 | ) | | 1 |
| | (435 | ) | | (460 | ) | | 2 |
| | (458 | ) | | 23 |
|
| (Loss) income before income taxes | (231 | ) | | 943 |
| | 712 |
| | 739 |
| | 13 |
| | 752 |
| | (40 | ) |
| Income tax expense(b) | (60 | ) | | (96 | ) | | (156 | ) | | (172 | ) | | 2 |
| | (170 | ) | | 14 |
|
| Net (loss) income | (291 | ) | | 847 |
| | 556 |
| | 567 |
| | 15 |
| | 582 |
| | (26 | ) |
| Net income attributable to noncontrolling interests(a) | (15 | ) | | — |
| | (15 | ) | | (11 | ) | | — |
| | (11 | ) | | (4 | ) |
| Net (loss) income attributable to Kinder Morgan, Inc. | $ | (306 | ) | | $ | 847 |
| | $ | 541 |
| | $ | 556 |
| | $ | 15 |
| | $ | 571 |
| | $ | (30 | ) |
_______
| |
| (a) | For a more detailed discussion of these Certain Items, see the footnotes to the tables within “—Segment Earnings Results” and “—General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests” below. |
| |
| (b) | The combined net effect of the Certain Items represents the income tax provision on Certain Items plus discrete income tax items. |
Net (loss) income attributable to Kinder Morgan, Inc. adjusted for Certain Items (Adjusted Earnings) decreased by $30 million in 2020 compared to 2019. Adjusted Segment EBDA before certain itemswas negatively impacted by the KML and Revenues before certain items are calculatedU.S. Cochin Sale and sharp declines in commodity prices impacting our Products Pipelines business segment, partially offset by adjustingearnings from expansion projects in our Natural Gas Pipelines business segment. Reduced DD&A, general and administrative and corporate charges, interest and income tax expense partially offset the decrease in Adjusted Segment EBDA. Reduced general and administrative and corporate charges and interest expense were primarily due to the KML and Cochin Sale.
Non-GAAP Financial Measures
Reconciliation of Net (Loss) Income Attributable to Kinder Morgan, Inc. (GAAP) to Adjusted Earnings to DCF
|
| | | | | | | |
| | Three Months Ended March 31, |
| | 2020 | | 2019 |
| | (In millions) |
| Net (loss) income attributable to Kinder Morgan, Inc. (GAAP) | $ | (306 | ) | | $ | 556 |
|
| Total Certain Items | 847 |
| | 15 |
|
| Adjusted Earnings(a) | 541 |
| | 571 |
|
| DD&A and amortization of excess cost of equity investments for DCF(b) | 691 |
| | 708 |
|
| Income tax expense for DCF(a)(b) | 181 |
| | 195 |
|
| Cash taxes(c) | (3 | ) | | (13 | ) |
| Sustaining capital expenditures(c) | (141 | ) | | (115 | ) |
| Other items(d) | (8 | ) | | 25 |
|
| DCF | $ | 1,261 |
| | $ | 1,371 |
|
Adjusted Segment EBDA and Revenues for the applicable certain item amounts, which are totaled in the tables and described in the footnotes to those tables. Revenues before certain items is providedAdjusted EBITDA to further enhance our analysisDCF
|
| | | | | | | |
| | Three Months Ended March 31, |
| | 2020 | | 2019 |
| | (In millions, except per share amounts) |
| Natural Gas Pipelines | $ | 1,179 |
| | $ | 1,201 |
|
| Products Pipelines | 273 |
| | 293 |
|
| Terminals | 257 |
| | 299 |
|
CO2 | 175 |
| | 189 |
|
| Adjusted Segment EBDA(a) | 1,884 |
| | 1,982 |
|
| General and administrative and corporate charges(a) | (140 | ) | | (158 | ) |
| KMI’s share of joint venture DD&A and income tax expense(a)(e) | 119 |
| | 126 |
|
| Net income attributable to noncontrolling interests (net of KML noncontrolling interests and Certain Items)(a) | (15 | ) | | (3 | ) |
| Adjusted EBITDA | 1,848 |
| | 1,947 |
|
| Interest, net(a) | (435 | ) | | (458 | ) |
| Cash taxes(c) | (3 | ) | | (13 | ) |
| Sustaining capital expenditures(c) | (141 | ) | | (115 | ) |
| KML noncontrolling interests DCF adjustments(f) | — |
| | (15 | ) |
| Other items(d) | (8 | ) | | 25 |
|
| DCF | $ | 1,261 |
| | $ | 1,371 |
|
| | | | |
| Adjusted Earnings per common share | $ | 0.24 |
| | $ | 0.25 |
|
| Weighted average common shares outstanding for dividends(g) | 2,277 |
| | 2,275 |
|
| DCF per common share | $ | 0.55 |
| | $ | 0.60 |
|
| Declared dividends per common share | $ | 0.2625 |
| | $ | 0.25 |
|
_______
| |
| (a) | Amounts are adjusted for Certain Items. |
| |
| (b) | Includes KMI’s share of DD&A or income tax expense from joint ventures as applicable. 2019 amounts are also net of DD&A or income tax expense attributable to KML noncontrolling interests. See tables included in “—Supplemental Information” below. |
| |
| (c) | Includes KMI’s share of cash taxes or sustaining capital expenditures from joint ventures, as applicable. See tables included in “—Supplemental Information” below. |
| |
| (d) | Includes non-cash pension expense and non-cash compensation associated with our restricted stock program. |
| |
| (e) | KMI’s share of unconsolidated joint venture DD&A and income tax expense, net of consolidating joint venture partners’ share of DD&A. |
| |
| (f) | 2019 amount represents the combined net income, DD&A and income tax expense adjusted for Certain Items, as applicable, attributable to KML noncontrolling interests. See table included in “—Supplemental Information” below. |
| |
| (g) | Includes restricted stock awards that participate in common share dividends. |
Reconciliation of Segment EBDA before certain items but is not a performance measure.Net (Loss) Income (GAAP) to Adjusted EBITDA
|
| | | | | | | |
| | Three Months Ended March 31, |
| | 2020 | | 2019 |
| | (In millions) |
| Net (loss) income (GAAP) | $ | (291 | ) | | $ | 567 |
|
| Certain Items: | | | |
| Fair value amortization | (8 | ) | | (8 | ) |
| Legal, environmental and taxes other than income tax reserves | (8 | ) | | 17 |
|
| Change in fair value of derivative contracts(a) | (36 | ) | | 10 |
|
| Loss on impairments and divestitures, net(b) | 371 |
| | 2 |
|
| Loss on impairment of goodwill(c) | 600 |
| | — |
|
| Income tax Certain Items | (96 | ) | | 2 |
|
| Other | 24 |
| | (8 | ) |
| Total Certain Items | 847 |
| | 15 |
|
| DD&A and amortization of excess cost of equity investments | 597 |
| | 614 |
|
| Income tax expense(d) | 156 |
| | 170 |
|
| KMI’s share of joint venture DD&A and income tax expense(d)(e) | 119 |
| | 126 |
|
| Interest, net(d) | 435 |
| | 458 |
|
| Net income attributable to noncontrolling interests (net of KML noncontrolling interests(d)) | (15 | ) | | (3 | ) |
| Adjusted EBITDA | $ | 1,848 |
| | $ | 1,947 |
|
______
| |
| (a) | Gains or losses are reflected in our DCF when realized. |
| |
| (b) | 2020 amount primarily includes: (i) pre-tax non-cash losses of $350 million and $21 million for asset impairments related to oil and gas producing assets in our CO2 business segment driven by low oil price and assets in our Products Pipelines business segment, respectively, and are reported within “Loss on impairments and divestitures, net” on our Consolidated Earnings Results (GAAP) table above. |
| |
| (c) | 2020 amount represents a non-cash impairment of goodwill associated with our CO2 reporting unit. |
| |
| (d) | Amounts are adjusted for Certain Items. See tables included in “—Supplemental Information” and “—General and Administrative and Corporate Charges, Interest, net, and Noncontrolling Interests” below. |
| |
| (e) | KMI’s share of unconsolidated joint venture DD&A and income tax expense, net of consolidating joint venture partners’ share of DD&A. |
Supplemental Information
|
| | | | | | | |
| | Three Months Ended March 31, |
| | 2020 | | 2019 |
| | (In millions) |
| DD&A (GAAP) | $ | 565 |
| | $ | 593 |
|
| Amortization of excess cost of equity investments (GAAP) | 32 |
| | 21 |
|
| DD&A and amortization of excess cost of equity investments | 597 |
| | 614 |
|
| Our share of joint venture DD&A | 94 |
| | 99 |
|
| DD&A attributable to KML noncontrolling interests | — |
| | (5 | ) |
| DD&A and amortization of excess cost of equity investments for DCF | $ | 691 |
| | $ | 708 |
|
| | | | |
| Income tax expense (GAAP) | $ | 60 |
| | $ | 172 |
|
| Certain Items | 96 |
| | (2 | ) |
| Income tax expense(a) | 156 |
| | 170 |
|
| Our share of taxable joint venture income tax expense(a) | 25 |
| | 27 |
|
| Income tax expense attributable to KML noncontrolling interests(a) | — |
| | (2 | ) |
| Income tax expense for DCF(a) | $ | 181 |
| | $ | 195 |
|
| | | | |
| Net income attributable to KML noncontrolling interests | $ | — |
| | $ | 8 |
|
| KML noncontrolling interests associated with Certain Items | — |
| | — |
|
| KML noncontrolling interests(a) | — |
| | 8 |
|
| DD&A attributable to KML noncontrolling interests | — |
| | 5 |
|
| Income tax expense attributable to KML noncontrolling interests(a) | — |
| | 2 |
|
| KML noncontrolling interests DCF adjustments(a) | $ | — |
| | $ | 15 |
|
| | | | |
| Net income attributable to noncontrolling interests (GAAP) | $ | 15 |
| | $ | 11 |
|
| Less: KML noncontrolling interests(a) | — |
| | 8 |
|
| Net income attributable to noncontrolling interests (net of KML noncontrolling interests(a)) | 15 |
| | 3 |
|
| Noncontrolling interests associated with Certain Items | — |
| | — |
|
| Net income attributable to noncontrolling interests (net of KML noncontrolling interests and Certain Items) | $ | 15 |
| | $ | 3 |
|
| | | | |
| Additional joint venture information: | | | |
| Our share of joint venture DD&A | $ | 94 |
| | $ | 99 |
|
| Our share of joint venture income tax expense(a) | 25 |
| | 27 |
|
| Our share of joint venture DD&A and income tax expense(a) | $ | 119 |
| | $ | 126 |
|
| | | | |
| Our share of taxable joint venture cash taxes | $ | (4 | ) | | $ | — |
|
| | | | |
| Our share of joint venture sustaining capital expenditures | $ | (26 | ) | | $ | (19 | ) |
| |
| (a) | Amounts are adjusted for Certain Items. |
Segment Earnings Results
Natural Gas Pipelines
|
| | | | | | | |
| | Three Months Ended March 31, |
| | 2019 | | 2018 |
| | (In millions, except operating statistics) |
| Revenues(a) | $ | 2,201 |
| | $ | 2,126 |
|
| Operating expenses(b) | (1,167 | ) | | (1,201 | ) |
| Other income | 1 |
| | — |
|
| Earnings from equity investments(b) | 159 |
| | 187 |
|
| Other, net | 9 |
| | 16 |
|
| Segment EBDA(b) | 1,203 |
| | 1,128 |
|
| Certain items(b) | (2) |
| | (54 | ) |
| Segment EBDA before certain items | $ | 1,201 |
| | $ | 1,074 |
|
| | | | |
| Change from prior period | Increase/(Decrease) |
| Revenues before certain items | $ | 89 |
| | 4 | % |
| Segment EBDA before certain items | $ | 127 |
| | 12 | % |
| | | | |
| Natural gas transport volumes (BBtu/d)(c) | 36,674 |
| | 32,124 |
|
| Natural gas sales volumes (BBtu/d)(c) | 2,332 |
| | 2,491 |
|
| Natural gas gathering volumes (BBtu/d)(c) | 3,301 |
| | 2,731 |
|
| NGLs (MBbl/d)(c) | 121 |
| | 116 |
|
|
| | | | | | | |
| | Three Months Ended March 31, |
| | 2020 | | 2019 |
| | (In millions, except operating statistics) |
| Revenues | $ | 1,875 |
| | $ | 2,201 |
|
| Operating expenses | (848 | ) | | (1,167 | ) |
| Other income | 1 |
| | 1 |
|
| Earnings from equity investments | 164 |
| | 159 |
|
| Other, net | 4 |
| | 9 |
|
| Segment EBDA | 1,196 |
| | 1,203 |
|
| Certain Items(a)(b) | (17) |
| | (2 | ) |
| Adjusted Segment EBDA | $ | 1,179 |
| | $ | 1,201 |
|
| | | | |
| Change from prior period | Increase/(Decrease) |
| Adjusted revenues | $ | (358 | ) | | (16 | )% |
| Adjusted Segment EBDA | (22 | ) | | (2 | )% |
| | | | |
| Volumetric data(c) | | | |
| Transport volumes (BBtu/d) | 39,095 |
| | 36,044 |
|
| Sales volumes (BBtu/d) | 2,495 |
| | 2,332 |
|
| Gathering volumes (BBtu/d) | 3,361 |
| | 3,301 |
|
| NGLs (MBbl/d) | 30 |
| | 32 |
|
_______
Certain itemsItems affecting Segment EBDA
| |
| (a) | 2019Includes revenue Certain Item amounts of $(24) million and 2018 amounts include a decrease in revenue of $8 million for 2020 and an increase in revenue of $6 million, respectively,2019, respectively. These Certain Item amounts are primarily related to non-cash mark-to-market derivative contracts used to hedge forecasted natural gas and NGL sales in the 2020 and crude oil sales.2019 periods. |
| |
| (b) | In additionIncludes non-revenue Certain Item amounts of $7 million and $(10) million for 2020 and 2019, respectively. 2020 amount is primarily related to the revenueincrease in expense associated with a certain items described in footnote (a) above:EPNG litigation matter. 2019 amount also includesis primarily related to an increase in earnings of $11 million for our share of certain equity investees’ amortization of the impact of the 2017 Tax Reform and a $1 million decrease in earnings from other certain items. 2018 amount also includes (i) an increase in earnings of $44 million for our share of certain equity investees’ 2017 Tax Reform provisional adjustments; (ii) an increase in earnings of $6 million related to the release of certain sales and use tax reserves; and (iii) a $2 million decrease in earnings from other certain items.regulatory liabilities. |
Other
| |
| (c) | Joint venture throughput is reported at our ownership share. Volumes for assets sold are excluded for all periods presented. |
Below are the changes in both Adjusted Segment EBDA before certain items and adjusted revenues, before certain items, in the comparable three monththree-month periods ended March 31, 20192020 and 2018:2019:
Three Months Ended March 31, 20192020 versus Three Months Ended March 31, 20182019
| | | | Segment EBDA before certain items increase/(decrease) | | Revenues before certain items increase/(decrease) | Adjusted Segment EBDA increase/(decrease) | | Adjusted revenues increase/(decrease) |
| | (In millions, except percentages) | (In millions, except percentages) |
| North Region | $ | 57 |
| | 18 | % | | $ | 42 |
| | 10 | % | |
| Midstream | | $ | (43 | ) | | (12 | )% | | $ | (449 | ) | | (33 | )% |
| East Region | | 20 |
| | 4 | % | | 45 |
| | 8 | % |
| West Region | 36 |
| | 14 | % | | 32 |
| | 10 | % | 1 |
| | — | % | | 10 |
| | 3 | % |
| Midstream | 34 |
| | 10 | % | | 15 |
| | 1 | % | |
| South Region | (2 | ) | | (1 | )% | | 4 |
| | 5 | % | |
| Other | 2 |
| | 100 | % | | 2 |
| | 100 | % | |
| Intrasegment eliminations | — |
| | — | % | | (6 | ) | | (60 | )% | — |
| | — | % | | 36 |
| | 95 | % |
| Total Natural Gas Pipelines | $ | 127 |
| | 12 | % | | $ | 89 |
| | 4 | % | $ | (22 | ) | | (2 | )% | | $ | (358 | ) | | (16 | )% |
The changes in Segment EBDA for our Natural Gas Pipelines business segment are further explained by the following discussion of the significant factors driving Adjusted Segment EBDA before certain items in the comparable three monththree-month periods ended March 31, 20192020 and 2018:2019:
North Region’s increaseMidstream’s decrease of $57$43 million (18%(12%) was primarily due to an increasethe sale of the Cochin Pipeline on December 16, 2019 to Pembina, lower volumes on KinderHawk Field Services and Oklahoma assets, lower rates on our North Texas assets and lower sales margins on our Texas intrastate operations. These decreases were partially offset by higher volumes on
the Hiland Midstream assets and higher equity earnings due to the Gulf Coast Express Pipeline being placed in earnings from TGP and Kinder Morgan Louisiana Pipeline LLC (KMLP). TGP contributed increased earnings primarily from expansion projects placed into service in 2018 and higher firm transportationSeptember 2019. Overall Midstream’s revenues decreased primarily due to higher capacity sales. KMLP increased earnings was from the Sabine Pass expansionlower commodity prices which was placed into servicelargely offset by corresponding decreases in December 2018;costs of sales;
WestEast Region’s increase of $36$20 million (14%(4%) was primarily due to higher earnings from EPNG and CIG. EPNG experienced higher volumes in 2019 from increased Permian basin-related activity and associated capacity sales. CIG earnings were higher due to continued growing production in the Denver Julesburg basin;
Midstream’s increase of $34 million (10%) was primarily due to increased earnings from South Texas Midstream and KinderHawk Field Services LLC resulting from increased drilling and production in the Eagle Ford and Haynesville basins, respectively; and
South Region’s decrease of $2 million (1%) was primarily due to a decreaseincreases in earnings from ELC and Southern Gulf LNG Company, L.L.C. as a resultresulting from five of a lossten liquefaction units (part of revenues from an arbitration ruling resultingthe Elba Liquefaction project) being placed into service in a contract termination in 2018the later part of 2019 and first quarter 2020 partially offset by an increasereduced contributions from TGP due to historically mild weather in earnings from an SNG expansion.the Northeast and the impact of the FERC 501-G rate settlement; and
| |
| • | West Region’s increase of $1 million (—%) was primarily due to increases in earnings from EPNG and CIG driven by increased revenues due to expansion in the Permian Basin and the Denver Julesburg basin, respectively, partially offset by decreased equity earnings from Ruby Pipeline Company due to lower transportation revenues. |
Products Pipelines
|
| | | | | | | |
| | Three Months Ended March 31, |
| | 2020 | | 2019 |
| | (In millions, except operating statistics) |
| Revenues | $ | 495 |
| | $ | 424 |
|
| Operating expenses | (221 | ) | | (166 | ) |
| Loss on impairments and divestitures, net | (21 | ) | | — |
|
| Earnings from equity investments | 15 |
| | 18 |
|
| Other, net | 1 |
| | — |
|
| Segment EBDA | 269 |
| | 276 |
|
| Certain Items(a) | 4 |
| | 17 |
|
| Adjusted Segment EBDA | $ | 273 |
| | $ | 293 |
|
| | | | |
| Change from prior period | Increase/(Decrease) |
| Adjusted revenues | $ | 71 |
| | 17 | % |
| Adjusted Segment EBDA | (20 | ) | | (7 | )% |
| | | | |
| Volumetric data(b) | | | |
| Gasoline(c) | 961 |
| | 980 |
|
| Diesel fuel | 358 |
| | 337 |
|
| Jet fuel | 293 |
| | 294 |
|
| Total refined product volumes | 1,612 |
| | 1,611 |
|
| Crude and condensate | 702 |
| | 643 |
|
| Total delivery volumes (MBbl/d) | 2,314 |
| | 2,254 |
|
|
| | | | | | | |
| | Three Months Ended March 31, |
| | 2019 | | 2018 |
| | (In millions, except operating statistics) |
| Revenues | $ | 424 |
| | $ | 442 |
|
| Operating expenses(a) | (166 | ) | | (193 | ) |
| Earnings from equity investments | 18 |
| | 16 |
|
| Other, net | — |
| | 1 |
|
| Segment EBDA(a) | 276 |
| | 266 |
|
| Certain items(a) | 17 |
| | 31 |
|
| Segment EBDA before certain items | $ | 293 |
| | $ | 297 |
|
| | | | |
| Change from prior period | Increase/(Decrease) |
| Revenues | $ | (18 | ) | | (4 | )% |
| Segment EBDA before certain items | $ | (4 | ) | | (1 | )% |
| | | | |
| Gasoline(b) | 980 |
| | 978 |
|
| Diesel fuel | 337 |
| | 342 |
|
| Jet fuel | 294 |
| | 289 |
|
| Total refined product volumes(c) | 1,611 |
| | 1,609 |
|
| Crude and condensate(c) | 643 |
| | 593 |
|
| Total delivery volumes (MBbl/d) | 2,254 |
| | 2,202 |
|
_______
Certain itemsItems affecting Segment EBDA
| |
| (a) | Includes non-revenue Certain Item amounts of $4 million and $17 million for 2020 and 2019, respectively. 2020 amount includes a non-cash loss on impairment of our Belton Terminal of $21 million and a $17 million favorable adjustment for tax reserves, other than income taxes. 2019 amount includes an increase in expense of $17 millionis related to an unfavorable adjustment of tax reserves, other than income taxes. 2018 amount includes an increase in expense of $31 million associated with a certain Pacific operations litigation matter. |
Other
| |
| (b) | Volumes include ethanol pipeline volumes. |
| |
(c) | Joint venture throughput is reported at our ownership share. |
| |
| (c) | Volumes include ethanol pipeline volumes. |
Below are the changes in both Adjusted Segment EBDA before certain items and adjusted revenues, before certain items, in the comparable three monththree-month periods ended March 31, 20192020 and 2018.2019.
Three Months Ended March 31, 20192020 versus Three Months Ended March 31, 20182019
| | | | Segment EBDA before certain items increase/(decrease) | | Revenues before certain items increase/(decrease) | Adjusted Segment EBDA increase/(decrease) | | Adjusted revenues increase/(decrease) |
| | (In millions, except percentages) | (In millions, except percentages) |
| Crude & Condensate | $ | (8 | ) | | (7 | )% | | $ | (23 | ) | | (13 | )% | |
| Crude and Condensate | | $ | (17 | ) | | (15 | )% | | $ | 54 |
| | 34 | % |
| Southeast Refined Products | 4 |
| | 6 | % | | (1 | ) | | (1 | )% | (13 | ) | | (20 | )% | | 10 |
| | 10 | % |
| West Coast Refined Products | — |
| | — | % | | 6 |
| | 4 | % | 10 |
| | 9 | % | | 7 |
| | 4 | % |
| Total Products Pipelines | $ | (4 | ) | | (1 | )% | | $ | (18 | ) | | (4 | )% | $ | (20 | ) | | (7 | )% | | $ | 71 |
| | 17 | % |
The changes in Segment EBDA for our Products Pipelines business segment are further explained by the following discussion of the significant factors driving Adjusted Segment EBDA before certain items in the comparable three monththree-month periods ended March 31, 20192020 and 2018:2019:
Crude &and Condensate’s decrease of $8$17 million (7%(15%) was primarily due to a decrease ofdecreased earnings from Kinder Morgan Crude & Condensate Pipeline (KMCC) and the Bakken Crude assets as a result of unfavorable inventory adjustments driven by declines in commodity prices during the first quarter of 2020. KMCC’s decreased earnings were also impacted by lower contracted rates partially offset by higher volumes. These decreases were partially offset by increased earnings from KMCC - Splitter primarily due to higher volumes driven by the Desalter project which was placed into service in May 2019 and associated processing fees. Overall Crude and Condensate revenues increased primarily due to increased volumes which were largely offset by a corresponding increase in costs of sales;
Southeast Refined Products’ decrease of $13 million (20%) was primarily due to decreased earnings from our Transmix processing operations driven by unfavorable inventory adjustments driven by commodity price declines during the first quarter 2020. The increase in revenues was primarily due to higher commodity sales revenues driven by a new customer contract which was offset by a corresponding increase in costs of sales; and
West Coast Refined Products’ increase of $10 million (9%) was primarily due to increased earnings on Pacific (SFPP) operations driven by an increase in services revenues as a result of unfavorable rates on contract renewals partially offset by increased earnings from Double H pipeline driven by an increase in Bakken crude oil volumes;
Southeast Refined Products’ increase of $4 million (6%) was primarily due to increased equity earnings from Plantation pipeline as a result of increased transportation revenues driven by higher volumes and average tariff rate and an increase in earnings from South East Terminals; and
West Coast Refined Products’ earnings were flat as increased earnings from Calnev due to higher revenues as a result of increased tariff rates on deliveries to Nevada were offset by a decrease in earnings from Pacific operations which was
driven by an increase in environmental reserves partially offset by higher revenues primarily due to higher tariff rates at certain locations.rates.
Terminals
| | | | Three Months Ended March 31, | Three Months Ended March 31, |
| | 2019 | | 2018 | 2020 | | 2019 |
| | (In millions, except operating statistics) | (In millions, except operating statistics) |
Revenues(a) | $ | 509 |
| | $ | 495 |
| $ | 442 |
| | $ | 509 |
|
Operating expenses(b) | (216 | ) | | (207 | ) | (192 | ) | | (216 | ) |
| Earnings from equity investments | 5 |
| | 7 |
| 5 |
| | 5 |
|
| Other, net | 1 |
| | 1 |
| 2 |
| | 1 |
|
Segment EBDA(b) | 299 |
| | 296 |
| 257 |
| | 299 |
|
| Certain items(b) | — |
| | 1 |
| |
| Segment EBDA before certain items | $ | 299 |
| | $ | 297 |
| |
| Certain Items | | — |
| | — |
|
| Adjusted Segment EBDA | | $ | 257 |
| | $ | 299 |
|
| | | | | | | |
| Change from prior period | Increase/(Decrease) | Increase/(Decrease) |
| Revenues before certain items | $ | 15 |
| | 3 | % | |
| Segment EBDA before certain items | $ | 2 |
| | 1 | % | |
| Adjusted revenues | | $ | (67 | ) | | (13 | )% |
| Adjusted Segment EBDA | | (42 | ) | | (14 | )% |
| | | | | | | |
| Volumetric data(a) | | | | |
| Liquids tankage capacity available for service (MMBbl) | 91.9 |
| | 90.5 |
| 79.5 |
| | 79.3 |
|
| Liquids utilization %(c) | 93.9 | % | | 91.4 | % | |
| Liquids utilization %(b) | | 93.7 | % | | 94.0 | % |
| Bulk transload tonnage (MMtons) | 14.7 |
| | 14.4 |
| 13.0 |
| | 13.6 |
|
_______
Certain items affecting Segment EBDAOther
| |
| (a) | 2018 amount includes an increase in revenue of $1 million from an other certain item.Volumes for assets sold are excluded for all periods presented. |
| |
| (b) | In addition to the revenue certain items described in footnote (a) above: 2018 amount also includes an increase in expense of $2 million related to hurricane repair costs. |
Other
| |
(c) | The ratio of our tankage capacity in service to tankage capacity available for service. |
Below are the changes in both Adjusted Segment EBDA before certain items and adjusted revenues, before certain items, in the comparable three monththree-month periods ended March 31, 20192020 and 2018.2019.
Three Months Ended March 31, 20192020 versus Three Months Ended March 31, 20182019
| | | | Segment EBDA before certain items increase/(decrease) | | Revenues before certain items increase/(decrease) | Adjusted Segment EBDA increase/(decrease) | | Adjusted revenues increase/(decrease) |
| | (In millions, except percentages) | (In millions, except percentages) |
| Gulf Liquids | $ | 6 |
| | 8 | % | | $ | 7 |
| | 7 | % | |
| Marine Operations | 3 |
| | 6 | % | | 3 |
| | 4 | % | |
| Alberta Canada | (5 | ) | | (13 | )% | | 6 |
| | 14 | % | $ | (33 | ) | | (100 | )% | | $ | (49 | ) | | (100 | )% |
| Gulf Central | (3 | ) | | (18 | )% | | (2 | ) | | (8 | )% | |
| West Coast | | (6 | ) | | (100 | )% | | (16 | ) | | (100 | )% |
| All others (including intrasegment eliminations) | 1 |
| | 1 | % | | 1 |
| | — | % | (3 | ) | | (1 | )% | | (2 | ) | | — | % |
| Total Terminals | $ | 2 |
| | 1 | % | | $ | 15 |
| | 3 | % | $ | (42 | ) | | (14 | )% | | $ | (67 | ) | | (13 | )% |
The changes in Segment EBDA for our Terminals business segment during the three-month periods ended March 31, 2020 and 2019 are explained by the sale of KML assets to Pembina on December 16, 2019, which accounted for the decrease on our Alberta Canada terminals and on our West Coast terminals.
CO2
|
| | | | | | | |
| | Three Months Ended March 31, |
| | 2020 | | 2019 |
| | (In millions, except operating statistics) |
| Revenues | $ | 309 |
| | $ | 305 |
|
| Operating expenses | (122 | ) | | (117 | ) |
| Loss on impairments and divestitures, net | (950 | ) | | — |
|
| Earnings from equity investments | 8 |
| | 10 |
|
| Segment EBDA | (755 | ) | | 198 |
|
| Certain Items(a)(b) | 930 |
| | (9 | ) |
| Adjusted Segment EBDA | $ | 175 |
| | $ | 189 |
|
| | | | |
| Change from prior period | Increase/(Decrease) |
| Adjusted revenues | $ | (7 | ) | | (2 | )% |
| Adjusted Segment EBDA | (14 | ) | | (7 | )% |
| | | | |
| Volumetric data | | | |
| SACROC oil production | 23.2 |
| | 24.4 |
|
| Yates oil production | 7.0 |
| | 7.3 |
|
| Katz and Goldsmith oil production | 3.4 |
| | 4.1 |
|
| Tall Cotton oil production | 2.4 |
| | 2.6 |
|
| Total oil production, net (MBbl/d)(c) | 36.0 |
| | 38.4 |
|
| NGL sales volumes, net (MBbl/d)(c) | 9.8 |
| | 10.1 |
|
CO2 production, net (Bcf/d) | 0.5 |
| | 0.6 |
|
| Realized weighted-average oil price per Bbl | $ | 54.61 |
| | $ | 48.67 |
|
| Realized weighted-average NGL price per Bbl | $ | 19.74 |
| | $ | 25.98 |
|
_______
Certain Items affecting Segment EBDA
| |
| (a) | Includes revenue Certain Item amounts of $(20) million and $(9) million for 2020 and 2019, respectively, related to unrealized gains associated with derivative contracts used to hedge forecasted commodity sales. |
| |
| (b) | Includes non-revenue Certain Item amount of $950 million for 2020 resulting from a $600 million goodwill impairment on our CO2 reporting unit and non-cash impairments of $350 million on most of our oil and gas producing assets. |
Other
| |
| (c) | Net of royalties and outside working interests. |
Below are the changes in both Adjusted Segment EBDA and adjusted revenues, in the comparable three-month periods ended March 31, 2020 and 2019.
Three Months Ended March 31, 2020 versus Three Months Ended March 31, 2019
|
| | | | | | | | | | | | | |
| | Adjusted Segment EBDA increase/(decrease) | | Adjusted revenues increase/(decrease) |
| | (In millions, except percentages) |
| Source and Transportation activities | $ | (14 | ) | | (18 | )% | | $ | (16 | ) | | (16 | )% |
| Oil and Gas Producing activities | — |
| | — | % | | 5 |
| | 2 | % |
| Intrasegment eliminations | — |
| | — | % | | 4 |
| | 57 | % |
Total CO2 | $ | (14 | ) | | (7 | )% | | $ | (7 | ) | | (2 | )% |
The changes in Segment EBDA for our CO2 business segment are further explained by the following discussion of the significant factors driving Adjusted Segment EBDA before certain items in the comparable three monththree-month periods ended March 31, 20192020 and 2018:
increase of $6 million (8%) from our Gulf Liquids terminals primarily driven by a customer rebate adversely impacting revenue recognized in the prior period and annual rate escalations on existing storage contracts;
increase of $3 million (6%) from our Marine Operations primarily due to fewer dry dock days on the Florida, one of our Jones Act tankers, and higher charter rates;
decrease of $5 million (13%) from our Alberta Canada terminals primarily due to an increase in operating expenses associated with lease fees at our Edmonton South Terminal following the TMPL Sale partially offset by an increase in earnings due to the commencement of operations at our Base Line Terminal joint venture; and
decrease of $3 million (18%) from our Gulf Central terminals primarily related to the termination of a customer contract in August 2018.
CO2
|
| | | | | | | |
| | Three Months Ended March 31, |
| | 2019 | | 2018 |
| | (In millions, except operating statistics) |
| Revenues(a) | $ | 305 |
| | $ | 304 |
|
| Operating expenses | (117 | ) | | (115 | ) |
| Earnings from equity investments | 10 |
| | 10 |
|
| Segment EBDA(a) | 198 |
| | 199 |
|
| Certain items(a) | (9 | ) | | 38 |
|
| Segment EBDA before certain items | $ | 189 |
| | $ | 237 |
|
| | | | |
| Change from prior period | Increase/(Decrease) |
| Revenues before certain items | $ | (46 | ) | | (13 | )% |
| Segment EBDA before certain items | $ | (48 | ) | | (20 | )% |
| | | | |
| SACROC oil production (net) | 24.4 |
| | 24.6 |
|
| Yates oil production | 7.3 |
| | 7.7 |
|
| Katz and Goldsmith oil production | 4.1 |
| | 5.2 |
|
| Tall Cotton oil production | 2.6 |
| | 2.1 |
|
| Total oil production (net)(MBbl/d)(b) | 38.4 |
| | 39.6 |
|
| NGL sales volumes (MBbl/d)(b) | 10.1 |
| | 10.2 |
|
Southwest Colorado CO2 production (gross)(Bcf/d) | 1.3 |
| | 1.3 |
|
Southwest Colorado CO2 production (net)(Bcf/d) | 0.6 |
| | 0.6 |
|
| Realized weighted-average oil price per Bbl(c) | $ | 48.67 |
| | $ | 59.72 |
|
| Realized weighted-average NGL price per Bbl(d) | $ | 25.98 |
| | $ | 30.39 |
|
_______
Certain items affecting Segment EBDA
| |
(a) | 2019 and 2018 amounts include unrealized gains of $9 million and unrealized losses of $38 million, respectively, related to derivative contracts used to hedge forecasted commodity sales. |
Other
| |
(b) | Net after royalties and outside working interests. |
| |
(c) | Includes all crude oil production properties. |
| |
(d) | Includes all NGL sales. |
Below are the changes in both Segment EBDA before certain items and revenues before certain items, in the comparable three month periods ended March 31, 2019 and 2018.
Three Months Ended March 31, 2019 versus Three Months Ended March 31, 2018
|
| | | | | | | | | | | | | |
| | Segment EBDA before certain items increase/(decrease) | | Revenues before certain items increase/(decrease) |
| | (In millions, except percentages) |
| Oil and Gas Producing Activities | $ | (51 | ) | | (31 | )% | | $ | (51 | ) | | (20 | )% |
| Source and Transportation Activities | 3 |
| | 4 | % | | 3 |
| | 3 | % |
| Intrasegment eliminations | — |
| | — | % | | 2 |
| | 22 | % |
Total CO2 | $ | (48 | ) | | (20 | )% | | $ | (46 | ) | | (13 | )% |
The changes in Segment EBDA for our CO2 business segment are further explained by the following discussion of the significant factors driving Segment EBDA before certain items in the comparable three month periods ended March 31, 2019 and 2018:
decrease of $51 million (31%) from our Oil and Gas Producing activities primarily due to decreased revenues of $51 million driven by lower crude oil and NGL prices of $44 million and lower volumes of $7 million; and2019:
| |
| • | increasedecrease of $3$14 million (4%(18%) from our Source and Transportation activities primarily due to a decrease of $19 million related to lower CO2 sales volumes partially offset by higher CO2 sales driven by higher contract sales prices and lower operating expenses; and
|
| |
| • | flat (—%) from our Oil and Gas Producing activities due to increased revenues of $3$5 million driven by higher volumes.realized crude oil prices which increased revenues by $13 million and was offset by lower volumes which reduced revenues by $8 million, and higher operating expenses of $5 million. |
Kinder Morgan Canada
|
| | | | | | | |
| | Three Months Ended March 31, |
| | 2019 | | 2018 |
| | (In millions, except operating statistics) |
| Revenues | $ | — |
| | $ | 61 |
|
| Operating expenses | — |
| | (24 | ) |
| Loss on divestiture(a) | (2 | ) | | — |
|
| Other, net | — |
| | 9 |
|
| Segment EBDA(a) | $ | (2 | ) | | $ | 46 |
|
| Certain items(a) | 2 |
| | — |
|
| Segment EBDA before certain items | $ | — |
| | $ | 46 |
|
| | | | |
| Change from prior period | Increase/(Decrease) |
| Revenues | $ | (61 | ) | | (100 | )% |
| Segment EBDA before certain items | $ | (46 | ) | | (100 | )% |
| | | | |
| Transport volumes (MBbl/d)(b) | — |
| | 288 |
|
_______
Certain items affecting Segment EBDA
| |
(a) | 2019 amount represents a true-up of the working capital adjustment on the TMPL sale. |
Other
| |
(b) | Represents TMPL average daily volumes. |
For the comparable three month periods of 2019 and 2018, the Kinder Morgan Canada business segment had decreases in Segment EBDA of $46 million (100%) due to the TMPL Sale on August 31, 2018. Subsequent to the TMPL Sale, this business segment does not have results of operations.
General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests
|
| | | | | | | | | | | | | | |
| | Three Months Ended March 31, | | |
| | 2019 | | 2018 | | Increase/(decrease) |
| | (In millions, except percentages) |
| General and administrative and corporate charges(a) | $ | 161 |
| | $ | 160 |
| | $ | 1 |
| | 1 | % |
| Certain items(a) | (3 | ) | | 4 |
| | (7 | ) | | (175 | )% |
| General and administrative and corporate charges before certain items(a) | $ | 158 |
| | $ | 164 |
| | $ | (6 | ) | | (4 | )% |
| | | | | | | | |
| Interest, net(b) | $ | 460 |
| | $ | 467 |
| | $ | (7 | ) | | (1 | )% |
| Certain items(b) | (2 | ) | | 5 |
| | (7 | ) | | (140 | )% |
| Interest, net, before certain items(b) | $ | 458 |
| | $ | 472 |
| | $ | (14 | ) | | (3 | )% |
| | | | | | | | |
| Net income attributable to noncontrolling interests | $ | 11 |
| | $ | 18 |
| | $ | (7 | ) | | (39 | )% |
| Net income attributable to noncontrolling interests before certain items | $ | 11 |
| | $ | 18 |
| | $ | (7 | ) | | (39 | )% |
|
| | | | | | | | | | | | | | |
| | Three Months Ended March 31, | | Earnings increase/(decrease) |
| | 2020 | | 2019 | |
| | (In millions, except percentages) |
| General and administrative (GAAP) | $ | (153 | ) | | $ | (154 | ) | | $ | 1 |
| | 1 | % |
| Corporate charges | (12 | ) | | (7 | ) | | (5 | ) | | (71 | )% |
| Certain Items(a) | 25 |
| | 3 |
| | 22 |
| | 733 | % |
| General and administrative and corporate charges(b) | $ | (140 | ) | | $ | (158 | ) | | $ | 18 |
| | 11 | % |
| | | | | | | | |
| Interest, net (GAAP) | $ | (436 | ) | | $ | (460 | ) | | $ | 24 |
| | 5 | % |
| Certain Items(c) | 1 |
| | 2 |
| | (1 | ) | | (50 | )% |
| Interest, net(b) | $ | (435 | ) | | $ | (458 | ) | | $ | 23 |
| | 5 | % |
| | | | | | | | |
| Net income attributable to noncontrolling interests (GAAP) | $ | (15 | ) | | $ | (11 | ) | | $ | (4 | ) | | (36 | )% |
Certain items
| |
| (a) | 20192020 amount includes an increase in expense of $3$23 million related to other certain items. 2018 amount includes (i) a decrease in expense of $12 million related to anassociated with the non-cash fair value adjustment of tax reserves, other than income taxes; (ii) an increase in expense of $6 million related to certain corporate litigation matters; and (iii) an increase in expense of $2 million related to other certain items.the dividend accrual on the Pembina common stock. |
| |
| (b) | 2019Amounts are adjusted for Certain Items. |
| |
| (c) | 2020 and 20182019 amounts include (i) decreases in interest expense of $8 million and $10 million, respectively,for each period related to non-cash debt fair value adjustments associated with acquisitions and (ii) increases in expense of $10$11 million and $5$10 million, respectively, related to non-cash mismatches between the change in fair value of interest rate swaps and change in fair value of hedged debt. |
The decrease in generalGeneral and administrative expenses and corporate charges before certain items of $6adjusted for Certain Items decreased $18 million in the first quarter of 20192020 when compared with the same quarter in the prior year wasto 2019 primarily due to higher capitalized costs of $18 million driven by the 2019 construction of Gulf Coast Express and Permian Highway facilities and lower expenses of $7$14 million due to the sale of TMPLKML, lower pension costs of $12 million, a $4 million project write-off in 2019 and lower benefit-related costs in our Terminals segment, partially offset by higher pension and benefit-relatedlower capitalized costs of $17 million.$15 million primarily due to our Gulf Coast project being placed in service in September 2019 and our Elba Liquefaction project which was partially placed in service in later part of 2019 and during first quarter 2020.
In the table above, we report our interest expense as “net,” meaning that we have subtracted interest income and capitalized interest from our total interest expense to arrive at one interest amount. Our consolidated interest expense, net of interest
income before certain itemsadjusted for the first quarter of 2019Certain Items, decreased $23 million in 2020 when compared with the same quarter in the prior year decreased $14 million. The decrease in interest expense wasto 2019 primarily due to lower weighted average long-term ratesdebt balances and lower debt balancesLIBOR rates partially offset by higher LIBOR rates which impacted our short-term debtlower capitalized interest and interest rate swap agreements.income.
We use interest rate swap agreements to convert a portion of the underlying cash flows related to 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, 20192020 and December 31, 2018,2019, approximately 31%17% and 27% of the principal amount of our debt balances 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 swaps. For more information on our interest rate swaps, see Note 5 “Risk Management—Interest Rate Risk Management” to our consolidated financial statements.
Net income attributable to noncontrolling interests represents the allocation of our consolidated net income attributable to all outstanding ownership interests in our consolidated subsidiaries that are not owned by us. Net income attributable to noncontrolling interests before certain items for the first quarter of 20192020 when compared with the same quarter in the prior year decreased $7 million primarily due to the TMPL Sale.2019 increased $4 million.
Income Taxes
Our tax expense for the three months ended March 31, 20192020 was approximately $172$60 million as compared with $164$172 million for the same period of 2018.2019. The $8$112 million increasedecrease in tax expense was due primarily due to an increase(i) lower pre-tax book income in pre-tax earnings.2020 as a result of the impairment of certain CO2 business segment assets, (ii) lower foreign income taxes as a result of the KML and U.S. Cochin Sale in 2019, and (iii) the refund of alternative minimum tax sequestration credits in 2020.
Liquidity and Capital Resources
General
As of March 31, 2019,2020, we had $221$360 million of “Cash and cash equivalents,” a decreasean increase of $3,059$175 million (93%(95%) from December 31, 20182019. The 2018 TMPL Sale mentioned aboveAs of March 31, 2020, our “Restricted deposits” includes $535 million held in “—General and Basis of Presentation—Sale of Trans Mountain Pipeline System and Its Expansion Project” was the primary source of cashescrow for maturing senior notes that matured on handApril 1, 2020. Additionally, as of DecemberMarch 31, 2018. We2020, we had borrowing capacity of approximately $3.9 billion under our $4 billion revolving credit facility (discussed below in “—Short-term Liquidity”). As discussed further below, we believe our cash flows from operating activities, cash position and remaining borrowing capacity on our credit facility (discussed below in “—Short-term Liquidity”), and cash flows from operating activities are more than adequate to allow us to manage our day-to-day cash requirements and anticipated obligations as discussed further below.obligations.
We have consistently generated substantial cash flow from operations, providing a source of funds of $635$893 million and $974$635 million in the first three months of 20192020 and 2018,2019, respectively. The period-to-period decreaseincrease is discussed below in “—Cash Flows—Operating Activities.” Generally, weWe primarily rely on cash provided from operations to fund our operations as well as our debt service, sustaining capital expenditures, dividend payments and our growth capital expenditures. We also generallyexpect the negative impact of the decline in commodity prices and refined product demand to continue in the near term, which will negatively affect our operating cash flows; however, we continue to expect that our short-term liquidity needs will be met primarily through retained cash from operations, short-term borrowings or by issuing new long-term debt to refinance certain of our maturing long-term debt obligations. Moreover,
Due to the significant uncertainty regarding the length and impact of the virus on the energy industry and potential impacts to our business, and to preserve flexibility and to continue strengthening our cash position, on April 22, 2020, we announced a 5% increase in our dividend for the first quarter of 2020 over the fourth quarter of 2019, a reduction in our planned 25% growth, and a reduction of approximately $700 million in our estimated capital expansion for 2020 as a resultnumber of planned expansion projects no longer meet our current common stock dividend policy and our continued focus on disciplined capital allocation,internal return thresholds. As a result, we do not expect the need to access the equity capital markets to fund our other growth projects for 2020. At some point we would expect to access the foreseeable future.debt capital markets to refinance maturing long-term debt, but given our revolver availability relative to debt maturing in the next eighteen months, we have significant flexibility on that timing.
To refinance construction costs of its recent expansions, on February 24, 2020, TGP, a wholly owned subsidiary, issued in a private placement $1,000 million aggregate principal amount of its 2.90% senior notes due 2030 and received net proceeds of $994 million. We used the proceeds to repay maturing debt. Additionally, during the first quarter of 2020, we opportunistically repurchased approximately 3.6 million of our Class P shares for approximately $50 million at an average price including commissions of $13.94 per share.
Short-term Liquidity
As of March 31, 2019,2020, our principal sources of short-term liquidity are (i) cash from operations; and (ii) our $4.5$4.0 billion revolving credit facilitiesfacility and associated $4.0 billion commercial paper program; and (iii) KML’s 4-year, C$500 million unsecured revolving credit facility (for KML’s working capital needs).program. The loan commitments under our revolving credit facilitiesfacility can be used for working capital and other general corporate purposes and, additionally for us, as a backup to our
commercial paper program. Letters of credit reduce borrowings allowed under our and KML’s respective credit facilities. Issuances of commercial paper alsoborrowings reduce borrowings allowed under our credit facility. We provide for liquidity by maintaining a sizable amount of excess borrowing capacity under our credit facility and, as previously discussed, have consistently generated strong cash flows from operations. We do not anticipate any significant limitations from the impacts of COVID-19 with respect to our ability to access funding through our credit facility.
As of March 31, 2019,2020, our $2,502$3,540 million of short-term debt consisted primarily of (i) $38 million outstanding borrowings under KML’s $500 million revolving credit facility; (ii) $109 million outstanding under our $4.0 billion commercial paper program; and (iii) $2,200 million of senior notes that mature in the next twelve months. Wemonths, including $535 million that was repaid on April 1, 2020 with cash held in escrow as of March 31, 2020 and reported within “Restricted deposits” in the accompanying consolidated balance sheet. During 2020, we used the proceeds from the sale of the Pembina common equity that we received for the sale of KML to reduce debt. Otherwise, as our debt becomes due, we intend to refinancefund our short-term debt primarily through credit facility borrowings, commercial paper borrowings, cash flows from operations, and/or by issuing new long-term debt or paying down short-term debt using cash retained from operations.debt. Our short-term debt balance as of December 31, 20182019 was $3,388$2,477 million.
We had working capital (defined as current assets less current liabilities) deficits of $2,747$2,512 million and $1,835$1,862 million as of March 31, 20192020 and December 31, 2018,2019, respectively. Our current liabilities may include short-term borrowings, which we may periodically replace with long-term financing and/or pay down using retained cash from operations. The overall $912$650 million (50%(35%) unfavorable change from year-end 20182019 was primarily due to a decrease(i) an increase of approximately $1,100 million in cashsenior notes that mature in the next twelve months; and (ii) $925 million related to the sale of $3,059 millionPembina common equity in January 2020; partially offset by (i) an increase in restricted deposits primarily related to cash held in escrow of $535 million for debt that matured on April 1, 2020 discussed above; (ii) an increase in cash and cash equivalents of $175 million; (iii) a decreasefavorable fair value adjustment of $364 million on derivative contracts in 2020; (iv) net repayments of short-term debt of $37 million; and distributions payable of $1,762 million and(v) a net decrease in accounts payable, accrued interest and accrued taxes. 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 our cash and cash equivalent balances as a result of excess cash from operations after payments for investing and financing activities.
Counterparty Creditworthiness
Some of our customers or other counterparties may experience severe financial problems that may have a significant impact on their creditworthiness. These financial problems may arise from our current global economic conditions, continued volatility of commodity prices or otherwise. In such situations, we utilize, to the extent allowable under applicable contracts, tariffs and regulations, prepayments and other security requirements, such as letters of credit, to enhance our credit position relating to amounts owed from these counterparties. While we believe we have taken reasonable measures to protect against counterparty credit risk, we cannot provide assurance that one or more of our customers or other counterparties will not become financially distressed and will not default on their obligations to us or that such a default or defaults will not have a material adverse effect on our business, financial position, future results of operations, or future cash flows. See “Part II, Item 1A. Risk Factors —Financial distress experienced by our customers or other counterparties could have an adverse impact on us in the event they are unable to pay us for the products or services we provide or otherwise fulfill their obligations to us.”
Capital Expenditures
We account for our capital expenditures in accordance with GAAP. We also distinguish between capital expenditures that are maintenance/sustaining capital expenditures and those that are expansion capital expenditures (which we also refer to as discretionary capital expenditures). Expansion capital expenditures are those expenditures that increase throughput or capacity from that which existed immediately prior to the addition or improvement, and are not deducted in calculating DCF (see “Results of Operations—Overview—Non-GAAP Financial Measures—DCF”). 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 that maintain throughput or capacity. The distinction between maintenance and expansion capital expenditures is a physical determination rather than an economic one, irrespective of the amount by which the throughput or capacity is increased.
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 expansion capital expenditures 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 a maintenance/sustaining or as an expansion capital expenditure is made on a project level. The classification of our capital expenditures as expansion capital expenditures or as maintenance capital expenditures is made consistent with our accounting policies and is generally a straightforward process, but in certain circumstances can be a matter of management judgment and discretion. The classification has an impact on DCF because capital expenditures that are classified as expansion capital expenditures are not deducted from DCF, while those classified as maintenance capital expenditures are.
Our capital expenditures for the three months ended March 31, 2019,2020, and the amount we expect to spend for the remainder of 20192020 to sustain and grow our businesses are as follows: |
| | | | | | | | | | | |
| | Three Months Ended March 31, 2019 | | 2019 Remaining | | Total 2019 |
| | (In millions) |
| Sustaining capital expenditures(a)(b) | $ | 115 |
| | $ | 597 |
| | $ | 712 |
|
| KMI Discretionary capital investments(b)(c)(d) | $ | 594 |
| | $ | 2,367 |
| | $ | 2,961 |
|
| KML Discretionary capital investments(b) | $ | 2 |
| | $ | 25 |
| | $ | 27 |
|
|
| | | | | | | | | | | |
| | Three Months Ended March 31, 2020 | | 2020 Remaining | | Total 2020(a) |
| | (In millions) |
| Sustaining capital expenditures(b)(c) | $ | 141 |
| | $ | 524 |
| | $ | 665 |
|
| Discretionary capital investments(c)(d)(e) | 542 |
| | 1,151 |
| | 1,693 |
|
_______
| |
| (a) | Three months ended March 31, 2019, 2019 Remaining, and Total 2019 amountsAmounts include $19 million, $104 million, and $123 million, respectively, for our proportionate share of (i) certain equity investee’s, (ii) KML’s; and (iii) certain consolidating joint venture subsidiaries’ sustaining capital expenditures.reductions due to revised outlook, as discussed above in “—General.”
|
| |
| (b) | Three months ended March 31, 2020, 2020 Remaining, and Total 2020 amounts include $26 million, $89 million, and $115 million, respectively, for our proportionate share of certain equity investees’ and certain consolidating joint venture subsidiaries’ sustaining capital expenditures. |
| |
| (c) | Three months ended March 31, 20192020 amount excludes $148include $43 million of net changes from accrued capital expenditures, contractor retainage, and other. |
| |
(c)(d) | Three months ended March 31, 20192020 amount includes $286$174 million of our contributions to certain unconsolidated joint ventures for capital investments. |
| |
(d)(e) | Amounts include our actual or estimated contributions to certain equity investees, net of actual or estimated contributions from certain partners in non-wholly owned consolidated subsidiaries for capital investments. |
Off Balance Sheet Arrangements
Other than commitments for the purchase of property, plant and equipment discussed following, thereThere 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, 20182019 in our 20182019 Form 10-K.
Commitments for the purchase of property, plant and equipment as of March 31, 2019 and December 31, 2018 were $443 million and $304 million, respectively.
Cash Flows
Operating Activities
The net decrease of $339 million in cashCash provided by operating activities increased $258 million in the three months ended March 31, 2020 compared to the respective 2019 period primarily due to:
a $211 million increase in cash resulting from $134 million of net income tax payments in the 2020 period compared to $345 million of net income tax payments in the 2019 period, both primarily for foreign income taxes mostly associated with the TMPL sale. The income tax payment for the 2020 period also included a $20 million refund received related to alternative minimum tax sequestration credits; and
a $47 million increase in cash from other operating activities in the 2020 period compared to the 2019 period.
Investing Activities
Cash provided by investing activities increased $1,149 million for the three months ended March 31, 20192020 compared to the respective 20182019 period was primarily attributable to:
$340a $923 million of foreign income tax payments made in the 2019 period associated with the TMPL Sale.
Investing Activities
The $89 million net increase in cash usedprimarily due to $907 million of proceeds received from the sale of the Pembina shares in investing activities for the three months ended March 31, 2019 compared to the respective 2018 period was primarily attributable to:2020 period;
a $265$180 million increasedecrease in cash used for contributions to equity investments primarily due to higherdriven by lower contributions we made to Gulf Coast Express Pipeline LLC and Permian Highway Pipeline LLC and Citrus Corporation in the 20192020 period compared with the 2018 period;2019 period, partially offset by contributions made to SNG in the 2020 period; and
a $153$114 million decrease in capital expenditures in the 20192020 period over the comparative 20182019 period primarily due to lower expenditures in our Terminals business segment and no expenditures in our Kinder Morgan Canada business segment due toon the TMPL sale.Elba Liquefaction expansion.
Financing Activities
The net increase of $2,699 million in cashCash used inby financing activities decreased $2,421 million for the three months ended March 31, 20192020 compared to the respective 20182019 period was primarily attributable to:
a $1,927$1,742 million net increasedecrease in cash used related to debt activity as a result of $149 million of net debt issuances in the 2020 period compared to $1,593 million of net debt payments in the 2019 period compared to net debt issuances in the 2018 period. See Note 3 “Debt”“Debt” for further information regarding our debt activity;
an $879 million increase in cash reflecting distribution of the TMPL sale proceeds to the owners of KML restricted shareholdersvoting shares in the 2019 period. See Note 2 “Divestitures” for further information regarding this activity; and
period; partially offset by,a $178$114 million increase in dividend payments to our common shareholders; partially offset by,and
a $248$48 million decreaseincrease in cash used due to lessan increase in common shares repurchased under our common share buy-back program in the 20192020 period compared to the 2018 period; and2019 period.
a $39 million decrease in cash used reflecting dividends paid to our mandatory convertible preferred shareholders in the 2018 period. All mandatory convertible preferred shares were converted into common shares in the fourth quarter of 2018.
Dividends
KMI Common Stock Dividends
We expect to declare common stock dividends of $1.00$1.05 per share on our common stock for 2019.2020. The table below reflects our 2020 common stock dividends declared:
|
| | | | | | | | | | |
| Three months ended | | Total quarterly dividend per share for the period | | Date of declaration | | Date of record | | Date of dividend |
| December 31, 2018 | | $ | 0.20 |
| | January 16, 2019 | | January 31, 2019 | | February 15, 2019 |
| March 31, 2019 | | 0.25 |
| | April 17, 2019 | | April 30, 2019 | | May 15, 2019 |
|
| | | | | | | | | | |
| Three months ended | | Total quarterly dividend per share for the period | | Date of declaration | | Date of record | | Date of dividend |
| December 31, 2019 | | $ | 0.25 |
| | January 22, 2020 | | February 3, 2020 | | February 18, 2020 |
| March 31, 2020 | | 0.2625 |
| | April 22, 2020 | | May 4, 2020 | | May 15, 2020 |
The actual amount of common stock dividends to be paid on our capital stock will depend on many factors, including our financial condition and results of operations, liquidity requirements, business prospects, capital requirements, legal, regulatory and contractual constraints, tax laws, Delaware laws and other factors. See Item 1A. “Risk Factors—The guidance we provide for our anticipated dividends is based on estimates. Circumstances may arise that lead to conflicts between using funds to pay anticipated dividends or to invest in our business.” of our 20182019 Form 10-K. All of these matters will be taken into consideration by our board of directors in declaring dividends.
Our common stock dividends are not cumulative. Consequently, if dividends on our common stock are not paid at the intended levels, our common stockholders are not entitled to receive those payments in the future. Our common stock dividends generally are expected to be paid on or about the 15th day of each February, May, August and November.
Summarized Combined Financial Information for Guarantee of Securities of Subsidiaries
KML Distributions
KML hasKMI and certain subsidiaries (Subsidiary Issuers) are issuers of certain debt securities. KMI and substantially all of KMI’s wholly owned domestic subsidiaries (Subsidiary Guarantors), are parties to a dividend policy pursuantcross guarantee agreement whereby each party to which it may pay a quarterly dividend on its restricted voting shares in an amount based on a portion of its distributable cash flow. The payment of dividends is not guaranteed,the agreement unconditionally guarantees, jointly and the amount and timing of any dividends payable will be at the discretion of KML’s board of directors. KML intends to pay quarterly dividends, if any, on or about the 45th day (or next business day) following the end of each calendar quarter to holders of its restricted voting shares of record as of the close of business on or about the last business day of the month following the end of each calendar quarter.
On January 3, 2019, KML distributed approximately $0.9 billion of the net proceeds from the TMPL Sale to its Restricted Voting Shareholders as a return of capital.
On January 16, 2019, KML’s board of directors suspended KML’s dividend reinvestment plan, effective withseverally, the payment of specified indebtedness of each other party to the fourth quarter 2018 dividend on February 15, 2019,agreement. Accordingly, with the exception of certain subsidiaries identified as Subsidiary Non-Guarantors, the parent issuer, subsidiary issuers and Subsidiary Guarantors (the “Obligated Group”) are all guarantors of each series of our guaranteed debt (Guaranteed Notes). As a result of the cross guarantee agreement, a holder of any of the Guaranteed Notes issued by KMI or subsidiary issuers are in lightthe same position with respect to the net assets, and income of KML’s reduced needKMI and the Subsidiary Issuers and Guarantors. The only amounts that are not available to the holders of each of the Guaranteed Notes to satisfy the repayment of such securities are the net assets, and income of the Subsidiary Non-Guarantors.
In lieu of providing separate financial statements for capital.
On April 17, 2019, KML’s board of directors declared a dividendsubsidiary issuers and guarantors, we have presented the accompanying supplemental summarized combined income statement and balance sheet information for the quarterly period endedObligated Group based on Rule 13-01 of the SEC’s Regulation S-X that we early adopted effective January 1, 2020. Also, see Exhibit 10.1 to
this Report “Cross Guarantee Agreement, dated as of November 26, 2014, among Kinder Morgan, Inc. and certain of its subsidiaries, with schedules updated as of March 31, 2019 of C$0.1625 per restricted voting share, payable on May 15, 20192020.”
All significant intercompany items among the Obligated Group have been eliminated in the supplemental summarized combined financial information. The Obligated Group’s investment balances in Subsidiary Non-guarantors have been excluded from the supplemental summarized combined financial information. Significant intercompany balances and activity for the Obligated Group with other related parties, including Subsidiary Non-Guarantors, (referred to KML restricted voting shareholders of recordas “affiliates”) are presented separately in the accompanying supplemental summarized combined financial information.
Excluding fair value adjustments, as of March 31, 2020 and December 31, 2019, the closeObligated Group had $32,649 million and $32,409 million, respectively, of business on April 30, 2019.Guaranteed Notes outstanding.
KML Dividends on its Series 1 Preferred SharesSummarized combined Balance Sheet and Series 3 Preferred Shares
KML also pays dividends on its 12,000,000 Series 1 Preferred Shares and 10,000,000 Series 3 Preferred Shares, which are fixed, cumulative, preferential, and payable quarterly in the annual amount of C$1.3125 per share and C$1.3000 per share, respectively, on the 15th day of February, May, August and November, as and when declared by KML’s board of directors,Income Statement information for the initial fixed rate period to but excluding November 15, 2022 and February 15, 2023, respectively.Obligated Group follows (in millions):
|
| | | | | | | |
| Summarized Combined Balance Sheet Information | March 31, 2020 | | December 31, 2019 |
| ASSETS | | | |
| Current assets | $ | 2,762 |
| | $ | 1,918 |
|
| Current assets - affiliates | 1,288 |
| | 1,146 |
|
| Noncurrent assets | 63,206 |
| | 63,298 |
|
| Noncurrent assets - affiliates | 449 |
| | 441 |
|
| Total Assets | $ | 67,705 |
| | $ | 66,803 |
|
| LIABILITIES, REDEEMABLE NONCONTROLLING INTEREST AND STOCKHOLDERS’ EQUITY | |
| | |
|
| Current liabilities | $ | 5,210 |
| | $ | 4,569 |
|
| Current liabilities - affiliates | 1,175 |
| | 1,139 |
|
| Noncurrent liabilities | 33,105 |
| | 33,612 |
|
| Noncurrent liabilities - affiliates | 1,429 |
| | 1,325 |
|
| Total Liabilities | 40,919 |
| | 40,645 |
|
| Redeemable Noncontrolling Interest | 793 |
| | 803 |
|
| Kinder Morgan, Inc.’s stockholders’ equity | 25,993 |
| | 25,355 |
|
| Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity | $ | 67,705 |
| | $ | 66,803 |
|
|
| | | |
| Summarized Combined Income Statement Information | Three Months Ended March 31, 2020 |
| Revenues | $ | 2,856 |
|
| Operating income | 462 |
|
| Net income | 147 |
|
Item 3. Quantitative and Qualitative Disclosures About Market Risk.
There have been no materialFor a discussion of changes in market risk exposures that would affect the quantitative and qualitative disclosures presented as of December 31, 20182019, in Item 7A in our 20182019 Form 10-K. For10-K, see Item 2, “Management's Discussion and Analysis of Financial Condition and Results of Operations—General and Basis of Presentation—2020 Outlook”and Item 1, Note 5 “Risk Management” to our consolidated financial statements for more information on our risk management activities, see Item 1, Note 5 “Risk Management” to our consolidated financial statements.both of which are incorporated in this item by reference.
Item 4. Controls and Procedures.
As of March 31, 2019,2020, 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, 20192020 that materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
PART II. OTHER INFORMATION
Item 1. Legal Proceedings.
See Part I, Item 1, Note 119 to our consolidated financial statements entitled “Litigation,“Litigation, Environmental and Other Contingencies”Contingencies” which is incorporated in this item by reference.
Item 1A. Risk Factors.
ThereOther than the following risk factors regarding COVID-19 and the following updated risk factors, there have been no material changes in the risk factors disclosed in Part I, Item 1A in our 20182019 Form 10-K.
The COVID-19 pandemic has adversely affected, and could continue to adversely affect, our business.
The ongoing pandemic involving COVID-19, a highly transmissible and pathogenic coronavirus, has negatively impacted the global economy and in turn reduced demand and pricing for crude oil, natural gas, NGL, refined petroleum products, CO2, steel, chemicals and other products that we handle, which has adversely affected our business. In response to COVID-19, governments around the world have implemented increasingly stringent measures to help reduce the spread of the virus, including stay-at-home and shelter-in-place orders, travel restrictions and other measures. These measures have adversely affected the economies and financial markets of the U.S. and many other countries, resulting in an economic downturn that has negatively impacted global demand and prices for the products handled by our pipelines, terminals, shipping vessels and other facilities. Continuing uncertainty regarding the global impact of COVID-19 is likely to result in continued weakness in demand and prices for the products on which our business depends.
If the COVID-19 outbreak should worsen, we may also experience further disruptions to commodities markets, supply chains and the availability and efficiency of our workforce, which could adversely affect our ability to conduct our business and operations and limit our ability to execute on our business plan. In addition, measures taken by regulatory authorities attempting to mitigate the economic consequences of COVID-19 may not be effective or may have unintended harmful consequences. For example, the Texas Railroad Commission recently held a hearing to consider the possibility of requiring Texas producers to cut crude oil production to balance supply and demand for crude oil. Although no action was taken, we cannot predict whether regulatory authorities will decide to implement crude oil production cuts or other measures, or how such measures will affect our business. There are still too many variables and uncertainties regarding COVID-19 — including the ultimate geographic spread of the virus, the duration and severity of the outbreak and the extent of travel restrictions and business closures imposed in affected countries — to reasonably predict the potential impact of COVID-19 on our business and operations. COVID-19 may materially adversely affect our business, results of operations, financial condition and cash flows. Even after the COVID-19 pandemic has subsided, we may experience materially adverse impacts to our business due to the global economic recession that is likely to result from the measures taken to combat the virus.
Our businesses are dependent on the supply of and demand for the products that we handle.
Our pipelines, terminals and other assets and facilities, including the availability of expansion opportunities, depend in part on continued production of natural gas, crude oil and other products in the geographic areas that they serve. Our business also depends in part on the levels of demand for natural gas, crude oil, NGL, refined petroleum products, CO2, steel, chemicals and other products in the geographic areas to which our pipelines, terminals, shipping vessels and other facilities deliver or provide service, and the ability and willingness of our shippers and other customers to supply such demand. For example, without additions to crude oil and gas reserves, production will decline over time as reserves are depleted, and production costs may rise. Producers may reduce or shut down production during times of lower product prices or higher production costs to the extent they become uneconomic. Producers in areas served by us may not be successful in exploring for and developing additional reserves, and our pipelines and related facilities may not be able to maintain existing volumes of throughput.
Commodity prices and tax incentives may not remain at levels that encourage producers to explore for and develop additional reserves, produce existing marginal reserves or renew transportation contracts as they expire. Additionally, demand for such products can decline due to situations over which we have no control, such as the COVID-19 pandemic and various measures that federal, state and local authorities have implemented in order to prevent further spread of COVID-19, including stay-at-home orders, or to respond to the economic consequences of COVID-19. See “—The COVID-19 pandemic has adversely affected, and could continue to adversely affect, our business.”
In addition to economic disruptions resulting from events such as COVID-19, conditions in the business environment generally, such as declining or sustained low commodity prices, supply disruptions, or higher development or production costs, could result in a slowing of supply to our pipelines, terminals and other assets. Also, sustained lower demand for hydrocarbons, or changes in the regulatory environment or applicable governmental policies, including in relation to climate change or other environmental concerns, may have a negative impact on the supply of crude oil and other products. In recent years, a number of initiatives and regulatory changes relating to reducing greenhouse gas emissions have been undertaken by federal, state and municipal governments and crude oil and gas industry participants. In addition, public sentiment surrounding the potential risks posed by climate change and emerging technologies have resulted in an increased demand for energy efficiency and a transition to energy provided from renewable energy sources, rather than fossil fuels, and fuel-efficient alternatives such as hybrid and electric vehicles. These factors could result in not only increased costs for producers of hydrocarbons but also an overall decrease in the demand for hydrocarbons. Each of the foregoing could negatively impact our business directly as well as our shippers and other customers, which in turn could negatively impact our prospects for new contracts for transportation, terminaling or other midstream services, or renewals of existing contracts or the ability of our customers and shippers to honor their contractual commitments. Furthermore, such unfavorable conditions may compound the adverse effects of larger disruptions such as COVID-19. See “—Financial distress experienced by our customers or other counterparties could have an adverse impact on us in the event they are unable to pay us for the productsor services we provide or otherwise fulfill their obligations to us” below.
We cannot predict the impact of future economic conditions, fuel conservation measures, alternative fuel requirements, governmental regulation or technological advances in fuel economy and energy generation devices, all of which could reduce the production of and/or demand for the products we handle. In addition, irrespective of supply of or demand for products we handle, implementation of new regulations or changes to existing regulations affecting the energy industry could have a material adverse effect on us.
The volatility of crude oil, NGL and natural gas prices could adversely affect our CO2 business segment and businesses within our Natural Gas Pipelines and Products Pipelines business segments.
The revenues, cash flows, profitability and future growth of some of our businesses (and the carrying values of certain of their respective assets, which include related goodwill) depend to a large degree on prevailing crude oil, NGL and natural gas prices. Our CO2 business segment and certain midstream businesses within our Natural Gas Pipelines business segment depend to a large degree, and certain businesses within our Product Pipelines business segment depend to a lesser degree, on prevailing crude oil, NGL and natural gas prices. For the estimated impacts from sensitivities to changes in commodity prices to Adjusted EBITDA and DCF for the remainder of 2020, please refer to Part I, Item 2.“Management’s Discussion and Analysis of Financial Condition and Results of Operations—General and Basis of Presentation—2020 Outlook.”
Prices for crude oil, NGL and natural gas are subject to large fluctuations in response to relatively minor changes in the supply of and demand for crude oil, NGL and natural gas, uncertainties within the market and a variety of other factors beyond our control. These factors include, among other things (i) weather conditions and events such as hurricanes in the U.S.; (ii) domestic and global economic conditions; (iii) the activities of the OPEC and other countries that are significant producers of crude oil; (iv) governmental regulation; (v) political instability in crude oil producing countries; (vi) the foreign supply of and demand for crude oil and natural gas; (vii) the price of foreign imports; (viii) the proximity and availability of storage and transportation infrastructure and processing and treating facilities; and (ix) the availability and prices of alternative fuel sources. We use hedging arrangements to partially mitigate our exposure to commodity prices, but these arrangements also are subject to inherent risks. We are also subject, indirectly, to volatility of commodity prices, through many of our customers’ direct exposure to such volatility. Please read “—Our use of hedging arrangements does not eliminate our exposure to commodity price risks and could result in financial losses or volatility in our income.”
As COVID-19 spread internationally and global economic activity slowed, future economic activity was forecasted to slow with a resulting forecast of a decline in crude oil and gas demand. In an attempt to stabilize the market, OPEC proposed production cuts in early March 2020; however, member producers failed to agree and some producers instead announced planned production increases, after which crude oil prices declined sharply. By mid-March 2020, crude oil prices had declined to less than $25 per barrel, the lowest price since April 1999. Member producers reached agreement on production cuts by
mid-April; however, crude oil prices continued to decline following announcement of the agreement. Producers in the U.S. and globally have not reduced crude oil production at a rate sufficient to match the sharp slowdown in economic activity caused by measures to control the spread of COVID-19, resulting in an oversupply of crude oil that recently caused crude oil prices per barrel to fall below zero. Sharp declines in the prices of crude oil, NGL or natural gas, or a prolonged unfavorable price environment, may result in a commensurate reduction in our revenues, income and cash flows from our businesses that produce, process, or purchase and sell crude oil, NGL, or natural gas, and could have a material adverse effect on the carrying value (which includes assigned goodwill) of our CO2 business segment’s proved reserves, certain assets in certain midstream businesses within our Natural Gas Pipelines business segment, and certain assets within our Products Pipelines business segment. If prices fall substantially or remain low for a sustained period and we are not sufficiently protected through hedging arrangements, we may be unable to realize a profit from these businesses and would operate at a loss.
In recent decades, there have been periods worldwide of both overproduction and underproduction of hydrocarbons, and periods of both increased and relaxed energy conservation efforts. Such conditions have resulted in periods of excess supply of, and reduced demand for, crude oil on a worldwide basis and for natural gas on a domestic basis. These periods have been followed by periods of short supply of, and increased demand for, crude oil and natural gas. The cycles of excess or short supply of crude oil or natural gas have placed pressures on prices and resulted in dramatic price fluctuations even during relatively short periods of seasonal market demand. These fluctuations impact the accuracy of assumptions used in our budgeting process. For more information about our energy and commodity market risk, see Part I, Item 3. “Quantitative and Qualitative Disclosures About Market Risk.” For estimated impacts from sensitivities to changes in commodity prices to Adjusted EBITDA and DCF for the remainder of 2020, please refer to Part I, Item 2.“Management’s Discussion and Analysis of Financial Condition and Results of Operations—General and Basis of Presentation—2020 Outlook.”
Our operating results may be adversely affected by unfavorable economic and market conditions.
As described above, COVID-19’s global spread and the measures that governments have implemented to control the spread of the virus have resulted in a downturn of economic activity on a global scale. Such slowdowns are affecting numerous industries, including the crude oil and gas industry, the steel industry and in specific segments and markets in which we operate, resulting in reduced demand and increased price competition for our products and services. In addition, uncertain or changing economic conditions within one or more geographic regions may affect our operating results within the affected regions. Sustained unfavorable commodity prices, volatility in commodity prices or changes in markets for a given commodity might also have a negative impact on many of our customers, which could impair their ability to meet their obligations to us. See “—Financial distress experienced by our customers or other counterparties could have an adverse impact on us in the event they are unable to pay us for the products or services we provide or otherwise fulfill their obligations to us.” In addition, decreases in the prices of crude oil, NGL and natural gas are likely to have a negative impact on our operating results and cash flow. See “—The volatility of crude oil, NGL and natural gas prices could adversely affect our CO2 business segment and businesses within our Natural Gas Pipelines and Products Pipelines business segments.”
If economic and market conditions (including volatility in commodity markets) globally, in the U.S. or in other key markets become more volatile or continue to deteriorate, we may experience material impacts on our business, financial condition and results of operations.
Financial distress experienced by our customers or other counterparties could have an adverse impact on us in the event they are unable to pay us for the products or services we provide or otherwise fulfill their obligations to us.
We are exposed to the risk of loss in the event of nonperformance by our customers or other counterparties, such as hedging counterparties, joint venture partners and suppliers. The global economic slowdown caused by COVID-19’s spread, combined with the recent extreme drop in crude oil prices, has significantly impacted the financial condition of many companies, particularly exploration and production companies, including some of our customers or counterparties. Many of our counterparties finance their activities through cash flow from operations or debt or equity financing, and some of them may be highly leveraged and may not be able to access additional capital to sustain their operations in the future. Our counterparties are subject to their own operating, market, financial and regulatory risks, and some are experiencing, or may experience in the future, severe financial problems that have had or may have a significant impact on their creditworthiness. Crude oil, NGL and natural gas prices were all lower on average in 2019 compared to 2018, and natural gas prices have continued to decline so far in 2020. Further deterioration in crude oil prices, or a continuation of the existing low natural gas or NGL price environment, would likely cause severe financial distress to some of our customers with direct commodity price exposure and may result in additional customer bankruptcies. Further, the security that is permitted to be obtained from such customers may be limited by FERC regulation. While certain of our customers are subsidiaries of an entity that has an investment grade credit rating, in many cases the parent entity has not guaranteed the obligations of the subsidiary and, therefore, the parent’s credit ratings may have no bearing on such customers’ ability to pay us for the services we provide or otherwise fulfill their obligations to us.
Furthermore, financially distressed customers might be forced to reduce or curtail their future use of our products and services, which also could have a material adverse effect on our results of operations, financial condition, and cash flows.
We cannot provide any assurance that such customers and key counterparties will not become financially distressed or that such financially distressed customers or counterparties will not default on their obligations to us or file for bankruptcy protection. If one of such customers or counterparties files for bankruptcy protection, we likely would be unable to collect all, or even a significant portion, of amounts owed to us. Similarly, our contracts with such customers may be renegotiated at lower rates or terminated altogether. Significant customer and other counterparty defaults and bankruptcy filings could have a material adverse effect on our business, financial position, results of operations or cash flows.
Our use of hedging arrangements does not eliminate our exposure to commodity price risks and could result in financial losses or volatility in our income.
We engage in hedging arrangements to reduce our direct exposure to fluctuations in the prices of crude oil, natural gas and NGL, including differentials between regional markets. These hedging arrangements expose us to risk of financial loss in some circumstances, including when production is less than expected, when the counterparty to the hedging contract defaults on its contract obligations, or when there is a change in the expected differential between the underlying price in the hedging agreement and the actual price received. In addition, these hedging arrangements may limit the benefit we would otherwise receive from increases in prices for crude oil, natural gas and NGL. Furthermore, our hedging arrangements cannot hedge against any decrease in the volumes of products we handle. See “—Our businesses are dependent on the supply of and demand for the products that we handle.”
The markets for instruments we use to hedge our commodity price exposure generally reflect then-prevailing conditions in the underlying commodity markets. As our existing hedges expire, we will seek to replace them with new hedging arrangements. To the extent then-existing underlying market conditions are unfavorable, new hedging arrangements available to us will reflect such unfavorable conditions.
The accounting standards regarding hedge accounting are very complex, and even when we engage in hedging transactions (for example, to mitigate our exposure to fluctuations in commodity prices or currency exchange rates or to balance our exposure to fixed and variable interest rates) that are effective economically, these transactions may not be considered effective for accounting purposes. Accordingly, our consolidated financial statements may reflect some volatility due to these hedges, even when there is no underlying economic impact at the dates of those consolidated financial statements. In addition, it may not be possible for us to engage in hedging transactions that completely eliminate our exposure to commodity prices; therefore, our consolidated financial statements may reflect a gain or loss arising from an exposure to commodity prices for which we are unable to enter into a completely effective hedge. For more information about our hedging activities, see Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates—Hedging Activities” of our 2019 Form 10-K and Note 5 “Risk Management” to our consolidated financial statements included in Part I of this Form 10-Q.
A breach of information security or failure of one or more key information technology or operational (IT) systems, or those of third parties, may adversely affect our business, results of operations or business reputation.
Our business is dependent upon our operational systems to process a large amount of data and complex transactions. Some of the operational systems we use are owned or operated by independent third-party vendors. The various uses of these IT systems, networks and services include, but are not limited to, controlling our pipelines and terminals with industrial control systems, collecting and storing information and data, processing transactions, and handling other processing necessary to manage our business.
While we have implemented and maintain a cybersecurity program designed to protect our IT and data systems from such attacks, we can provide no assurance that our cybersecurity program will be effective. In compliance with state and local stay-at-home orders issued in connection with COVID-19, a number of our employees have transitioned to working from home. As a result, more of our employees are working from locations where our cybersecurity program may be less effective and IT security may be less robust. We have experienced an increase in the number of attempts by external parties to access our networks or our company data without authorization. The risk of a disruption or breach of our operational systems, or the compromise of the data processed in connection with our operations, through an act of terrorism or cyber sabotage event has increased as attempted attacks have advanced in sophistication and number around the world.
If any of our systems are damaged, fail to function properly or otherwise become unavailable, we may incur substantial costs to repair or replace them and may experience loss or corruption of critical data and interruptions or delays in our ability to
perform critical functions, which could adversely affect our business and results of operations. A significant failure, compromise, breach or interruption in our systems, which may result from problems such as malware, computer viruses, hacking attempts or third-party error or malfeasance, could result in a disruption of our operations, customer dissatisfaction, damage to our reputation and a loss of customers or revenues. Efforts by us and our vendors to develop, implement and maintain security measures, including malware and anti-virus software and controls, may not be successful in preventing these events from occurring, and any network and information systems-related events could require us to expend significant resources to remedy such event. In the future, we may be required to expend additional resources to continue to enhance our information security measures and/or to investigate and remediate information security vulnerabilities.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.
| Our Purchases of Our Class P Shares | | | Period | | Total number of securities purchased(a) | | Average price paid per security | | Total number of securities purchased as part of publicly announced plans(a) | | Maximum number (or approximate dollar value) of securities that may yet be purchased under the plans or programs | | Total number of securities purchased(a) | | Average price paid per security(b) | | Total number of securities purchased as part of publicly announced plans(a) | | Maximum number (or approximate dollar value) of securities that may yet be purchased under the plans or programs |
| January 1 to January 31, 2019 | | 140,500 |
| | $ | 15.32 |
| | 140,500 |
| | $ | 1,474,909,370 |
| |
| February 1 to February 28, 2019 | | — |
| | $ | — |
| | — |
| | $ | 1,474,909,370 |
| |
| March 1 to March 31, 2019 | | — |
| | $ | — |
| | — |
| | $ | 1,474,909,370 |
| |
| January 1 to January 31, 2020 | | | — |
| | $ | — |
| | — |
| | $ | 1,474,909,370 |
|
| February 1 to February 29, 2020 | | | — |
| | $ | — |
| | — |
| | $ | 1,474,909,370 |
|
| March 1 to March 31, 2020 | | | 3,588,486 |
| | $ | 13.93 |
| | 3,588,486 |
| | $ | 1,424,909,386 |
|
| | | | | | | | | | | | | | | | | |
| Total | | 140,500 |
| | $ | 15.32 |
| | 140,500 |
| | $ | 1,474,909,370 |
| | 3,588,486 |
| | $ | 13.93 |
| | 3,588,486 |
| | $ | 1,424,909,386 |
|
_______
| |
| (a) | On July 19, 2017, our board of directors approved a $2 billion common share buy-back program that began in December 2017. After repurchase, the shares are canceled and no longer outstanding. |
| |
| (b) | Amount excludes any commission or other costs to repurchase shares. |
Item 3. Defaults Upon Senior Securities.
None.
Item 4. Mine Safety Disclosures.
The Company does not own or operate mines for which reporting requirements apply under the mine safety disclosure requirements of the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank), except for one terminal that is in temporary idle status with the Mine Safety and Health Administration. The Company has not received any specified health and safety violations, orders or citations, related assessments or legal actions, mining-related fatalities, or similar events requiring disclosure pursuant to the mine safety disclosure requirements of Dodd-Frank for the quarter ended March 31, 2019.2020.
Item 5. Other Information.
None.
Item 6. Exhibits.
Exhibit NumberDescription |
| | | |
| 10.1 |
| | |
| | |
10.2 |
| * | |
| | | |
| 31.1 |
| | |
| | | |
| 31.2 |
| | |
| | | |
| 32.1 |
| | |
| | | |
| 32.2 |
| | |
| | | |
| 101 |
| | Interactive data files pursuant to Rule 405 of Regulation S-T:S-T formatted in iXBRL (Inline Extensible Business Reporting Language): (i) our Consolidated Statements of Operations for the three months ended March 31, 2020 and 2019; (ii) our Consolidated Statements of Comprehensive (Loss) Income for the three months ended March 31, 20192020 and 2018; (ii) our Consolidated Statements of Comprehensive Income for the three months ended March 31, 2019 and 2018;2019; (iii) our Consolidated Balance Sheets as of March 31, 20192020 and December 31, 2018;2019; (iv) our Consolidated Statements of Cash Flows for the three months ended March 31, 20192020 and 2018;2019; (v) our Consolidated Statements of Stockholders’ Equity for the three months ended March 31, 20192020 and 2018;2019; and (vi) the notes to our Consolidated Financial Statements. |
| | |
| 104 |
| | Cover Page Interactive Data File pursuant to Rule 406 of Regulation S-T formatted in iXBRL (Inline Extensible Business Reporting Language) and contained in Exhibit 101. |
_______
*Asterisk indicates exhibits incorporated by reference as indicated; all other exhibits are filed herewith.
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, INC. |
| | | Registrant |
|
| | | | | |
| Date: | April 22, 201928, 2020 | | By: | | /s/ David P. Michels |
| | | | | | David P. Michels Vice President and Chief Financial Officer (principal financial and accounting officer) |
