# Kinder Morgan, Inc. (KMI) — Narrative, third quarter 2026 ## Business *From the FY2025 Form 10-K (fiscal year ended December 31, 2025), accession 0001506307-26-000011, updated where noted by the third-quarter 2026 Form 10-Q, accession 0001506307-26-000132.* Kinder Morgan is one of the largest energy infrastructure companies in North America. It is paid mainly for moving and storing other parties' energy products: it collects transportation, storage, terminaling and other midstream fees from producers, utilities, LNG exporters, refiners, industrial users and marketers. It also earns sales revenue from marketing natural gas, NGL and crude oil, and from its own production of crude oil, CO2 and renewable natural gas. At December 31, 2025 it owned an interest in or operated about 78,000 miles of pipelines, 136 terminals, about 706 Bcf of working natural gas storage capacity, and RNG generation capacity of about 6.9 Bcf a year of gross production. No single external customer accounted for 10% or more of consolidated revenues in 2025, 2024 or 2023. The company states its strategy as owning stable, fee-based transportation and storage assets central to growing North American markets or to U.S. exports; raising use of existing assets while controlling costs; being disciplined about capital spent on expansions and acquisitions; and keeping a strong balance sheet while returning value to stockholders. The company reports four business segments. Natural Gas Pipelines is by far the largest: in 2025 its Segment EBDA was $6,080 million, against $1,157 million for Products Pipelines, $1,143 million for Terminals and $612 million for CO2. - **Natural Gas Pipelines.** This segment holds interstate and intrastate pipelines, underground storage, LNG liquefaction and terminal facilities, and NGL fractionation, with both FERC-regulated and non-regulated assets. It includes about 42,000 miles of wholly owned natural gas pipelines and equity interests in entities with about 25,000 more miles. Its main systems are Tennessee Gas Pipeline (TGP, 100%), El Paso Natural Gas/Mojave (100%), Colorado Interstate Gas (100%), NGPL (37.5%), Southern Natural Gas (SNG, 50%), Florida Gas Transmission through Citrus (50%), and the Texas intrastate network (KM Texas and Tejas, 100%). Midstream gathering and processing runs through KinderHawk in the Haynesville and Hiland Midstream in the Williston Basin. Interstate pipeline and storage revenue comes mainly from long-term fixed-fee contracts: customers pay most of the fee to reserve capacity whether or not they use it. At year-end 2025 the remaining weighted average life of natural gas transportation contracts was about seven years, and for LNG regasification, liquefaction and related storage contracts about 12 years. Gathering and processing revenue is mostly fee-based but depends on producer drilling and volumes. Some of those contracts are percent-of-proceeds, percent-of-index or keep-whole, which carry commodity exposure. - **Products Pipelines.** This segment covers refined products, crude oil and condensate pipelines and their terminals, a condensate processing facility (splitter) and transmix processing. Major assets include the Pacific system (SFPP, 99.5%, about 2,800 miles), CALNEV, West Coast Terminals, the Products (SE) pipeline (51%), Central Florida pipeline, Southeast Terminals, and the Bakken and Eagle Ford crude and condensate systems. Rates are mostly regulated tariffs adjusted each year by a FERC index tied to the Producer Price Index, and volumes follow fuel demand. - **Terminals.** This segment runs 47 liquids terminals (78.7 MMBbl of capacity), 24 bulk terminals handling petroleum coke, metals and ores, and 16 Jones Act-qualified product tankers. Liquids contracts are largely take-or-pay, with about two years of weighted average remaining term at year-end 2025. Bulk contracts average about five years and often carry minimum volume guarantees. Tanker charters average about three years, with major oil companies, refiners and the U.S. Military Sealift Command. The company describes itself as one of the largest independent liquids terminal operators in the U.S. - **CO2.** This segment produces CO2 from interests in McElmo Dome (45%), Doe Canyon Deep (87%) and Bravo Dome (11%), and moves it through pipelines such as Cortez and Central Basin to enhanced oil recovery operations. It also owns and operates oil fields, chiefly SACROC (97% working interest) and Yates (50%), and RNG, LNG and landfill gas-to-electricity facilities, grouped as Energy Transition Ventures. CO2 sales contracts are typically priced off crude oil, with about six years of remaining average life. Crude oil and NGL sales are partly hedged. At year-end 2025 the company had 11,028 full-time employees, about 867 of them covered by collective bargaining agreements expiring between 2026 and 2029. **Growth projects and portfolio changes in 2025.** The company bought a North Dakota natural gas gathering and processing system from Outrigger Energy II LLC for $648 million (February 2025). In December 2025 it sold its 25% non-operated equity interest in EagleHawk for $382 million. Projects placed in service in 2025 included the second phase of the TGP/SNG Evangeline Pass project serving Venture Global's Plaquemines LNG facility ($661 million KMI share), the Altamont Green River pipeline ($263 million) and the Tejas South to North expansion ($145 million). The largest projects under construction at that point were: - South System Expansion 4 on SNG: about 1.3 Bcf/d, $1,830 million, in service in phases in late 2028 and late 2029. - Trident Intrastate pipeline from Katy, Texas to the Port Arthur LNG and industrial corridor: about 2.0 Bcf/d, $1,799 million, first phase expected in the first quarter of 2027. - Mississippi Crossing: up to 2.1 Bcf/d, $1,703 million, expected in the second quarter of 2028. - Florida Gas Transmission Phase IX and South Florida projects: about 0.8 Bcf/d combined, $700 million. - KinderHawk Plantation North expansion: $516 million, expected in the fourth quarter of 2026. **Changes during 2026 (from the third-quarter 10-Q).** On May 1, 2026 the company completed its purchase of the Monument Pipeline from ARM Energy Holdings for $503 million, including working capital adjustments. Monument is a natural gas pipeline system of about 225 miles serving Houston and the surrounding area, with transportation and storage customers among gas utilities, LNG shippers and industrial users, and it was added to Natural Gas Pipelines. On September 1, 2026 the company sold certain terminals and terminal assets in the Tampa, Florida area, described below under the current quarter. ## Risk factors *From the FY2025 Form 10-K, Item 1A, accession 0001506307-26-000011. The third-quarter 2026 10-Q (accession 0001506307-26-000132, Part II, Item 1A) reports no material changes to these risk factors.* **Business risks** - **Supply of and demand for the products it handles.** Throughput depends on continued production of natural gas, crude oil and other products in the regions its assets serve, and on demand where they deliver. Low commodity prices, higher production costs, policy changes or a shift away from hydrocarbons, including energy-transition pressure, could reduce volumes, weaken contract renewals and hurt customers' ability to pay. - **Project execution.** Growth depends on building and expanding assets. Permitting and right-of-way problems, public opposition, higher material costs (including from steel tariffs), cost overruns, weather and contractor delays have caused, and may again cause, delays or cancellations. Joint-venture projects mean shared control. - **Competition.** Rival pipelines, terminals, and other transport such as barge, rail and truck could leave capacity unused and make it harder to re-contract expiring capacity at good rates. Carbon capture developers could compete for CO2 enhanced oil recovery customers. - **Commodity price volatility.** Parts of the business, especially the CO2 segment's oil, NGL and CO2 sales, certain midstream assets and some Products Pipelines assets, depend on crude oil, NGL and natural gas prices. Steep or prolonged declines could cut cash flow and hit carrying values, including goodwill assigned to CO2 reserves. Hedging reduces but does not remove this exposure. It also caps upside, adds accounting volatility, and leaves losses if production falls short of hedged volumes. - **Operational hazards.** Leaks, ruptures, explosions, equipment failure, third-party damage, marine accidents and natural disasters could cause injury or death, environmental damage, fines, lost revenue and reputational harm. Assets near populated areas or at marine terminals carry larger consequences. Insurance does not cover all losses, and coverage may become costlier or unavailable. - **Counterparty credit.** Customers, hedge counterparties and joint-venture partners, some highly leveraged, could default or file for bankruptcy. FERC rules can limit the collateral the company may require, and parent-company credit ratings may not stand behind subsidiary customers. - **Cybersecurity and attacks.** Pipelines are named targets of terrorism and cyber sabotage. A breach or failure of IT or operational control systems, the company's or vendors', could disrupt operations and bring costs, regulation and litigation. Attempted intrusions have increased. - **Physical climate and land access.** Hurricanes, flooding, subsidence and coastal erosion threaten Gulf Coast and low-lying assets. Most pipelines sit on land owned by others under rights-of-way. Losing those rights, or having them repriced, could force relocations or raise costs. - **Oil and gas development.** Without successful development, CO2-segment production, reserves and cash flow decline. - **People.** Many employees are eligible to retire, so the company has to keep and recruit skilled staff and transfer their knowledge. **Financing risks** - **Leverage.** At year-end 2025 the company had about $31.8 billion of consolidated debt, excluding fair value adjustments, plus a cross guarantee under which the parent and substantially all wholly owned U.S. subsidiaries guarantee each other's debt. About $3.5 billion was effectively variable-rate and $1.1 billion of senior notes matured within 12 months. Higher rates raise refinancing and interest costs. A downgrade, which would carry over to guaranteeing subsidiaries, could limit access to capital. Debt covenants restrict additional debt, liens, asset sales and mergers. **Regulatory risks** - **Rate regulation.** FERC, the California Public Utilities Commission (CPUC) and other regulators set or review tariffs, and shippers have challenged the company's rates. Successful challenges could force refunds and lower future rates. The five-yearly reset of FERC's oil pipeline index is usually litigated, and changes to it affect Products Pipelines revenue. - **Shifting and overlapping regulation.** Federal deregulation, such as the EPA's announced February 2026 rescission of the greenhouse gas endangerment finding, is likely to be challenged in court. Meanwhile states, notably California with its climate-disclosure and emissions-reporting laws, are tightening requirements, which makes compliance more complex and costly. - **Environmental and pipeline safety.** Strict, joint and several liability under CERCLA and similar laws can apply to legacy contamination. PHMSA integrity rules, including reconfirming maximum allowable operating pressure by 2035 and proposed leak-detection and repair-criteria rules, will keep compliance spending substantial. - **Trade policy.** Tariffs on steel and other materials raise construction and maintenance costs. Their legal durability is uncertain: a federal appeals court ruled many tariffs invalid in August 2025, and that ruling is stayed pending Supreme Court review. - **Climate regulation.** Greenhouse gas rules at the state, federal and foreign level, including EU methane limits on imported gas and oil from 2030, could raise operating costs and reduce demand for hydrocarbons. Recovering those costs through rates is uncertain. - **Upstream regulation.** Limits on drilling, hydraulic fracturing or access to federal lands could reduce volumes on its systems. - **Jones Act.** The tanker fleet depends on Jones Act compliance, including at least 75% U.S.-citizen ownership. A repeal would open the trade to foreign competition. **Stockholder risks** - **Dividend guidance.** Dividend guidance rests on estimates. The board could cut the dividend to fund the business, or borrow to pay it, which would add to debt. - **Foreign ownership.** To protect Jones Act status, the charter allows the company to redeem shares held by non-U.S. citizens above 22%, which may weigh on the stock's marketability abroad. ## Management's discussion — fiscal 2025 *From the FY2025 Form 10-K, Item 7, accession 0001506307-26-000011.* 2025 was a year of earnings growth led by natural gas. Revenues rose 12% to $16,937 million, from $15,100 million in 2024. Natural gas sales grew $1,609 million on higher prices and volumes, and services revenue grew $507 million on higher volumes, expansion projects placed in service, higher rates and the Outrigger Energy assets. Lower product sales, down $423 million, partly offset this. Because most commodity sales are matched by purchases, costs of sales rose by a similar amount, up $1,192 million. Operating income rose 8% to $4,724 million. Net income attributable to Kinder Morgan rose 17% to $3,056 million, and basic and diluted EPS was $1.37 against $1.17. Other, net was $146 million higher, mainly because of the gain on the EagleHawk sale. Interest, net fell $43 million because of lower rates on fixed-to-variable swaps. Management also measures results on an adjusted basis, removing "Certain Items" such as unrealized hedge marks and divestiture gains. Certain Items totalled $(157) million in 2025, including a $123 million gain on the EagleHawk sale. Adjusted Net Income Attributable to Kinder Morgan was $2,899 million against $2,571 million, Adjusted EPS was $1.30 against $1.15, and Adjusted EBITDA was $8,391 million against $7,938 million, up $453 million. Management attributes the improvement to Natural Gas Pipelines and Terminals, partly offset by CO2. By segment: - **Natural Gas Pipelines.** Segment EBDA rose $687 million to $6,080 million, and Adjusted Segment EBDA rose $475 million to $5,914 million. Midstream rose $495 million (28%) on Texas intrastate expansions and wider sales margins, the Outrigger assets and higher KinderHawk gathering rates. East rose $161 million (6%) on TGP expansions, weather- and LNG-driven demand, and higher equity earnings from MEP, Citrus and NGPL. West rose $31 million (3%). Transport volumes averaged 46,603 BBtu/d, against 44,252. - **Products Pipelines.** Segment EBDA was $1,157 million, against $1,164 million. Crude and Condensate fell $44 million (16%) as legacy Bakken crude contracts expired ahead of the Double H conversion to NGL service, and because of narrower spreads and a planned ten-year turnaround at the condensate splitter. West Coast Refined Products rose $24 million and Southeast Refined Products rose $13 million. - **Terminals.** Segment EBDA rose $44 million to $1,143 million. Higher Jones Act charter rates added $45 million and Houston Ship Channel liquids rates added $23 million. Bulk fell $20 million after LyondellBasell's 2025 closure of its Houston refinery hurt petroleum coke handling. - **CO2.** Segment EBDA fell $73 million to $612 million, and Adjusted Segment EBDA fell $39 million to $608 million. Lower realized CO2 prices and volumes, and a $40 million field-sale gain in 2024 that did not recur, drove the decline. Net oil production averaged 25.76 MBbl/d, against 26.31, at a realized $67.51 per barrel. **Liquidity and capital.** Cash from operations was $5,917 million in 2025, against $5,635 million. The company issued $1,850 million and repaid $1,500 million of senior notes. Year-end cash was $63 million, with about $3,477 million available under its $3.5 billion credit facility, which also backs a $3.5 billion commercial paper program. Capital expenditures were $3,026 million, and total capital investments, including joint-venture contributions and the Outrigger acquisition, were $3,988 million. Dividends declared were $1.17 per share, up 2%. The company said it did not expect to need equity markets to fund discretionary investment. About $1.5 billion remained under the $3 billion buy-back authorization. S&P upgraded the long-term rating to BBB+ on January 13, 2026. **2026 outlook as given in February 2026.** The company expected to declare dividends of $1.19 per share, up 2%, and, excluding the divested EagleHawk interest, to invest almost $3.3 billion in expansion projects and joint-venture contributions. It identified no impairment triggering events during 2025. ## Current quarter — third quarter 2026 *From the third-quarter 2026 Form 10-Q, accession 0001506307-26-000132, and the earnings release furnished as Exhibit 99.1 to the Form 8-K filed October 21, 2026, accession 0001506307-26-000130.* The company called it a record third quarter. Revenues rose 9% to $4,531 million, from $4,146 million. Net income attributable to Kinder Morgan rose 22% to $764 million, from $628 million, and EPS was $0.34 against $0.28. Revenue growth came from higher product sales (up $267 million, on commodity prices), services revenue (up $148 million, on volumes and expansion projects, mainly in Natural Gas Pipelines) and natural gas sales (up $39 million). Hedge effects of $85 million partly offset these gains. Operations and maintenance expense jumped $163 million, mainly because of $138 million of legal, environmental and other expense accruals in the West Coast Refined Products business. The company treated those accruals as a Certain Item, and the filings do not tie them to a specific matter. A $71 million net gain on the Tampa terminals sale went the other way. Interest, net fell $26 million on higher capitalized interest and swap benefits. The quarter's effective tax rate was 19.4%, against 22.0%. On the adjusted basis, Adjusted Net Income Attributable to Kinder Morgan was $792 million against $648 million, Adjusted EPS was $0.35 against $0.29, and Adjusted EBITDA was $2,180 million against $1,991 million, up 9%. Management credits favorable contributions from all four segments. For the nine months, revenues were $13,836 million against $12,429 million, net income attributable to Kinder Morgan was $2,607 million against $2,060 million, EPS was $1.17 against $0.92, and Adjusted EBITDA was $6,918 million against $6,120 million. By segment: - **Natural Gas Pipelines.** Segment EBDA was $1,501 million against $1,391 million, and Adjusted Segment EBDA was $1,489 million against $1,403 million. Midstream rose $65 million (13%) on KinderHawk volumes, Texas intrastate demand and the Monument acquisition. West rose $31 million on capacity sales, expansions and park-and-loan activity. East rose $14 million on weather-driven demand and expansions, partly offset by lower short-term firm pricing. Transport volumes were 49,273 BBtu/d, against 47,918 (up 3%, on LNG deliveries on TGP and Texas intrastate demand), and gathering volumes rose 14% to 4,722 BBtu/d. - **Products Pipelines.** Segment EBDA fell to $172 million from $288 million because of the $138 million accrual. Adjusted Segment EBDA rose to $313 million from $288 million, helped by Southeast Refined Products (up $33 million on transmix pricing and butane blending). Pacific operations had lower rates and volumes. Refined product volumes fell 3%, and crude and condensate volumes fell 11% on lower Bakken gathering and the Double H conversion to NGL service. - **Terminals.** Segment EBDA was $385 million against $274 million, and Adjusted Segment EBDA was $314 million against $274 million. Liquids rose $21 million on expansions and the absence of a 2025 equity investment impairment, partly offset by a customer's 2025 refinery closure at the Houston Ship Channel. Liquids utilization slipped to 92.6% from 94.6%. Bulk rose $14 million on petroleum coke and coal, and Jones Act tankers rose $7 million on charter rates. - **CO2.** Segment EBDA was $172 million against $135 million, and Adjusted Segment EBDA was $184 million against $136 million. Higher realized CO2 prices, crude volumes and RNG production drove the gain. SACROC oil production rose to 20.05 MBbl/d from 18.01, and Energy Transition Ventures EBDA was $24 million against $7 million. **Portfolio and projects.** On September 1, 2026 the company sold three dry bulk terminals in Tampa, Florida to affiliates of Watco Companies LLC. The earnings release calls it a $139 million transaction paid in cash and additional preferred equity interests in Watco. The 10-Q puts net consideration after working capital adjustments at $136 million: $81 million in cash plus $55 million of additional interests in an equity investment. The sale produced a $71 million net gain, including a $9 million goodwill reduction. The growth story this quarter is the backlog. Expansion backlog stood at $14.4 billion at quarter-end, up $4.7 billion from the second quarter after $5.4 billion of additions net of $700 million placed in service. Of the total, $13.2 billion is natural gas, the largest natural gas backlog in the company's history, and more than 75% supports power generation and local distribution company demand. The company expects the $13.7 billion portion excluding CO2 enhanced oil recovery and gathering and processing projects to earn a first-full-year Project EBITDA multiple of about 5.7 times. The two largest additions are SNG's Southeast Connector (KMI share $3.1 billion) and NGPL's Permian Link (KMI share about $1.6 billion). Each is designed to move more than 2.5 Bcf/d, and both are expected to begin service in 2030. In refined products, the company joined Phillips 66 and HF Sinclair in August in the Western Gateway Pipeline to Arizona and California, with a 35.1% interest. **Balance sheet and cash flow.** In the quarter the company issued $1,750 million of senior notes due 2036 and 2056, for net proceeds of $1,730 million. Earlier in 2026 it extended its $3.5 billion revolving credit facility to May 2031, and in March Moody's upgraded its long-term rating to Baa1 with a stable outlook. At September 30, 2026: - Cash was $918 million, up $855 million from year-end, largely unused proceeds from the August notes. - Debt principal was $33,171 million, of which $1,726 million is due within a year. - Nothing was drawn on the credit facility or commercial paper, and about $3,490 million was available. - The release reports Net Debt of $32,229 million and Net Debt-to-Adjusted EBITDA of 3.5 times, against 3.8 times at year-end 2025. Nine-month cash from operations was $5,041 million, against $4,225 million. Capital expenditures were $2,831 million and dividends paid were $1,984 million, leaving free cash flow after dividends of $226 million. Liabilities recorded for legal and environmental matters rose to $397 million from $261 million at year-end. **Guidance.** The 2026 budget calls for net income attributable to Kinder Morgan of $3.1 billion, Adjusted EPS of $1.36, Adjusted EBITDA of $8.6 billion, dividends of $1.19 per share, and year-end Net Debt-to-Adjusted EBITDA of 3.8 times. With third-quarter results, the company said it expects to beat budget by more than 6% on Adjusted EBITDA and more than 13% on Adjusted EPS, and to end the year at 3.6 times leverage. The 10-Q puts 2026 investment in expansion projects, acquisitions and joint-venture contributions at $4.2 billion. That figure includes the Monument Pipeline acquisition, carried at $505 million in the 10-Q's capital investment table, which the almost $3.3 billion expected in February for expansion projects and joint-venture contributions did not. Total expected 2026 capital investments, including sustaining capital, are $5,340 million. **Litigation developments in the quarter.** - **Pension plan class action.** On August 10, 2026 the U.S. District Court for the Southern District of Texas largely rejected the Magistrate Judge's recommendation. It awarded equitable relief on three ERISA claims and ordered the legacy Coastal/ANR benefit formula reformed broadly in line with the plaintiffs' request. Plaintiffs had estimated the relief they seek at more than $150 million. The company has appealed to the Fifth Circuit and sought a stay. - **SFPP CPUC rate case.** On July 10, 2026 an administrative law judge in SFPP's consolidated CPUC rate case issued an interim proposed decision that SFPP's connected destination terminals fall under CPUC jurisdiction. SFPP disputes the decision. The company does not expect the matter to have a material impact. - **Freeport LNG.** The Winter Storm Uri lawsuit (about $104 million claimed) remains on remand to the trial court. ## Subsequent events *From the third-quarter 2026 Form 10-Q, accession 0001506307-26-000132, and the Form 8-K filed October 21, 2026, accession 0001506307-26-000130.* - **Dividend.** On October 21, 2026 the board declared a quarterly dividend of $0.2975 per share for the quarter ended September 30, 2026 ($1.19 annualized, 2% above the third quarter of 2025). It is payable November 16, 2026 to holders of record on November 2, 2026. - **No other post-quarter transactions.** The 10-Q, filed October 23, 2026, reports no acquisitions, divestitures, borrowings or debt issuances after September 30, 2026. The third-quarter deals and financings above (the Tampa terminals sale, the August senior notes and the project sanctions) all fall on or before quarter-end. As of October 22, 2026 there were 2,227,715,229 Class P shares outstanding.