EPD Enterprise Products 10-Q 2026-09-30 section summaries

Enterprise Products Partners L.P. (EPD) — Q3 and nine months ended September 30, 2026

Results

Revenue grew sharply, but higher commodity-linked product sales also increased costs. Consequently, revenue growth outpaced growth in segment gross operating margin and operating income. Segment gross operating margin is management’s core segment-profit measure and is presented before noncontrolling interests.

Q3 cost of sales was not specified in the chunk summaries; total costs and expenses are shown.

Commodity prices and sales volumes drove much of the revenue increase, with the associated cost of purchased products also rising. Other net income was $46M in both Q3 and 9M 2026, compared with $2M and $4M, respectively, in the prior periods. Tax provisions were $17M in Q3 and $51M for 9M, versus a $13M tax benefit and a $27M provision, respectively, a year earlier.

Segment results

Crude Oil segment margin was nearly flat despite higher revenue. Revenue growth rates also differed between Q3 and 9M: NGL was up 71.6% in Q3 versus 24.0% for 9M; Crude Oil, 22.9% versus 39.0%; Natural Gas, 27.5% versus a 8.4% decline; and Petrochemical & Refined Products, 87.6% versus 39.5%.

Cash flow and capital allocation

Asset-sale proceeds included the $595M second installment received in January 2026 from the sale of a 40% undivided interest in the Bahia NGL Pipeline to ExxonMobil; total consideration was approximately $655M. Repurchases covered 10.214M units in 9M 2026, versus 7.913M a year earlier; phantom-award vesting issued 5.042M net new units, partly offsetting buybacks. The remaining buyback authorization was $3.2B. The Board declared a Q3 distribution of $0.56 per common unit ($2.24 annualized), with a total payment of $1.2B, including $12M for phantom-award distribution equivalents.

Balance sheet, debt and units

Total equity less goodwill and intangible assets was $25.486B at September 30, 2026; total equity includes noncontrolling interests. Consolidated debt carrying value was $32.5B, compared with $34.1B at year-end; debt principal included $31.460B of senior debt and $2.282B of junior subordinated notes. Commercial paper outstanding was $660M, versus none at year-end. Maturities included $660M for the remainder of 2026, $1.575B in 2027, $1.800B in 2028 and $27.207B thereafter. Revolving facilities were undrawn at quarter-end, and EPD was in compliance with debt covenants. EPO’s $1.5B 364-day and $1.0B incremental revolvers mature March 26, 2027; EPD guarantees EPO’s consolidated debt.

Cash, cash equivalents and restricted cash ended 9M 2026 at $339M, down $906M during the period. Trade receivables increased to $10.613B from $6.494B, and accrued product payables to $13.074B from $8.183B; changes in operating accounts used $433M of cash. Floating-rate exposure includes commercial paper and junior subordinated notes, some of which switch from fixed to SOFR-based rates in 2027–2028.

Business, exposures and commitments

EPD operates an integrated U.S. midstream network across natural gas, NGLs, crude oil, petrochemicals and refined products. It has no employees and relies on EPCO and other providers for management and operating services. EPCO and affiliates held 702.6M common units, or 32.6%, at quarter-end; 50.9M units were pledged under their separate credit facilities. The filing cautions that related-party terms may be less favorable than unaffiliated-party terms. EPCO-related service costs were $423M in Q3 and $1.263B for 9M 2026, versus $397M and $1.180B in the prior periods.

Commodity derivative assets and liabilities were $760M and $748M, respectively, at September 30, versus $460M and $363M at year-end. Commodity cash-flow hedges generated OCI losses of $247M in Q3 and $548M for 9M; net losses reclassified to earnings were $30M and $169M, respectively. EPD expects to reclassify $142M of net commodity derivative losses over the next 12 months. No interest-rate derivatives were outstanding. Commodity prices and derivative margin requirements can affect earnings and restricted cash.

Estimated fixed future consideration under contracts with minimum-volume commitments and similar provisions was $25.815B, including $1.178B for the remainder of 2026 and $4.663B in 2027; this excludes revenue from other arrangements. June 2026 compressor lease modifications added approximately $345M of operating lease liabilities and $177M of finance lease liabilities. Asset-retirement obligations rose to $363M from $290M, including $63M of upward revisions to estimated cash flows and $13M of accretion.

Enterprise Products Partners (EPD) — Q3 and nine months ended September 30, 2026

Consolidated results

Revenue growth was driven primarily by marketing and higher commodity prices, rather than an equivalent increase in margins or cash generation. In Q3, higher prices and volumes added $4.6 billion to marketing revenue ($2.8 billion from price and $1.8 billion from volume); crude marketing added another $1.2 billion. For 9M, marketing revenue for crude oil, NGLs, petrochemicals and refined products rose $11.9 billion ($7.1 billion from price and $4.8 billion from volume), partly offset by a $431 million decline in natural-gas marketing revenue. Higher commodity-linked sales costs largely pass through. Other operating costs rose $150 million in Q3 and $355 million in 9M, mainly from compensation, chemicals, taxes and maintenance; depreciation, amortization and accretion increased $69 million and $212 million, respectively, as newer assets entered service.

Interest expense rose despite unchanged weighted-average borrowing rates (4.62% in Q3 and 4.66% for 9M). Debt-principal interest was $397 million versus $396 million in Q3 and $1.200 billion versus $1.154 billion for 9M. New notes increased interest while 2026 note retirements partly offset the effect; lower capitalized interest also raised reported expense.

Segment performance

Revenue reflects commodity sales as well as services; gross operating margin (GOM) is a non-GAAP measure, includes equity earnings of unconsolidated affiliates, and is before noncontrolling-interest allocations.

Total segment GOM was $2.743 billion versus $2.383 billion in Q3 and $8.389 billion versus $7.318 billion for 9M. After shipper make-up-rights adjustments, GOM was $2.735 billion versus $2.385 billion in Q3 and $8.350 billion versus $7.293 billion for 9M.

NGL GOM growth reflected higher processing and marketing margins, pipeline and storage contributions, and Mont Belvieu fractionation volumes; Frac 14 entered service in Q4 2025. NGL pipeline transportation averaged 4,978 MBPD versus 4,694 MBPD in Q3, and fee-based gas processing averaged 8,196 MMcf/d versus 7,454 MMcf/d. Crude GOM was slightly lower in Q3: stronger marketing was offset by higher costs and lower transportation-related revenue, while Seaway contributed $4 million of Q3 growth and $28 million of 9M growth. Natural Gas GOM gains included marketing, gathering and transportation growth, partly offset by higher gathering costs; pipeline transportation averaged 22,695 BBtus/d versus 21,027 BBtus/d in Q3. Petrochemical GOM benefited from higher propylene, ethylene-export and refined-products margins. Planned maintenance reduced 9M octane-enhancement margins.

Cash flow, distributions and investment

Operating cash flow increased $722 million, supported by higher earnings, partly offset by $264 million of adverse operating-account changes, primarily marketing working capital, commodity-price movements, inventory timing and derivative margin deposits. Lower investing outflow reflected $1.1 billion less property, plant and equipment investment and asset-sale proceeds, including a $595 million installment from the Bahia NGL Pipeline sale. Financing outflow increased as debt transactions shifted to a net outflow, including $1.63 billion of senior-note repayments.

Q3 Operational DCF was $2.311 billion versus $1.819 billion; DCF was $2.312 billion versus $1.825 billion. For 9M, Operational DCF was $6.734 billion versus $5.742 billion and DCF was $7.334 billion versus $5.777 billion. The 9M DCF included $600 million of asset-sale and other proceeds, compared with $21 million in 2025. Distribution coverage improved to 1.9x from 1.5x in Q3 and 2.0x from 1.6x for 9M; retained DCF was $1.092 billion versus $635 million and $3.691 billion versus $2.225 billion, respectively.

The declared Q3 distribution was $0.56 per common unit ($2.24 annualized), totaling $1.2 billion. EPD repurchased 2,922,742 units in Q3 and 10,213,672 in 9M, at total costs including fees of $112 million and $387 million. The $5.0 billion buyback authorization had $3.2 billion remaining.

Liquidity, debt and growth plans

At September 30, 2026, consolidated liquidity was $4.8 billion, comprising $232 million of unrestricted cash and $4.5 billion of available revolving-credit capacity, net of $660 million of commercial paper outstanding. EPO’s debt principal totaled $33.742 billion, with an average maturity of approximately 16.6 years. EPO added a $1.0 billion variable-rate revolver in July, bringing aggregate credit-agreement capacity to $5.2 billion; neither that facility nor the March 2026 $1.5 billion 364-day facility had borrowings outstanding. The Partnership guaranteed $34.0 billion of EPO debt, including accrued interest.

Approximately $6.3 billion of major growth projects were scheduled through Q1 2029. Plans include four 300 MMcf/d Permian gas-processing trains, each capable of extracting over 40 MBPD of NGLs, and 150 MBPD Frac 15, expected in service in Q1 2028. Forecast 2026 organic investment, net of noncontrolling-interest contributions, was $4.1–$4.6 billion. Investment plans depend on cash generation and access to capital, and are exposed to commodity prices, demand, customer credit, costs, labor and materials availability, weather and regulation.

The obligor group reported $56.0 billion of investments in non-obligor subsidiaries at September 30, 2026, with $5.6 billion of related equity earnings for 9M. Its standalone 9M net loss excluding those earnings was $618 million, underscoring the importance of subsidiary earnings to consolidated economics; those subsidiary assets and earnings are not directly available to guaranteed-debt holders.

Market-risk management

EPD is exposed to interest-rate and commodity-price risk. It uses derivatives predominantly for non-trading purposes to hedge anticipated purchases and sales, processing margins, inventory fair values, and power purchases for certain Southeast Texas operations. Its sensitivity analysis estimates the effect of a hypothetical 10% price or rate movement on derivative fair value only; it excludes changes in the corresponding hedged exposures. The extent of any offset depends on hedge effectiveness, derivatives remaining open for their expected terms, and forecast transactions occurring as expected.

Commodity-derivative fair-value sensitivity

Derivative fair value, asset/(liability), in $ millions

The crude oil marketing portfolio moved from a net derivative asset at year-end 2025 to a substantial net liability by September 30, 2026, with the liability increasing by October 15. At both later dates, a 10% price increase would have deepened that liability.

The sensitivity tables exclude CME-cleared derivatives subject to CME Rule 814. These contracts are treated as having zero fair value at the balance-sheet date because daily variation-margin settlement occurs, but remain outstanding and exposed to future price movements until contractual settlement. Derivatives cleared on other exchanges, such as ICE, are reported gross; therefore, the tables do not represent all outstanding commodity exposure.

Interest-rate exposure

EPD may use swaps, forward-starting swaps, swaptions, treasury locks, and similar instruments to manage borrowing costs and cost of capital. It had no material interest-rate hedges outstanding as of the filing date.

Management concluded that disclosure controls and procedures were effective as of the end of Q3 2026. No changes during the quarter materially affected, or were reasonably likely to materially affect, internal control over financial reporting. The CEO and CFO certifications under Sections 302 and 906 of the Sarbanes-Oxley Act are included in Exhibits 31 and 32.

This section does not identify specific risk factors or present financial metrics. It directs investors to the risk factors in Part I, Item 1A of EPD’s 2025 Form 10-K, which should be considered together with the information in that annual report and this quarterly report. The identified risks could cause actual results to differ materially from the company’s forward-looking statements.

Trading arrangements

During the three months ended September 30, 2026, no Enterprise GP director or officer adopted or terminated a Rule 10b5-1 or non-Rule 10b5-1 trading arrangement.

Executive retention agreement

On November 2, 2026, Enterprise GP Chief Operating Officer Graham W. Bacon entered into a retention agreement with EPCO. The agreement provides for three cash payments of $1.0 million each, potentially totaling $3.0 million, following continuous active full-time employment during calendar years 2027, 2028, and 2029, respectively. Each payment is subject to satisfactory performance, determined in the Chairman of EPCO’s good-faith discretion.

Specified qualifying involuntary terminations—including death, disability, retirement on or after January 1, 2028, or termination other than for cause—may qualify Bacon for a prorated payment for the applicable retention period. The performance requirement must be met through the date of termination. The payments are in addition to discretionary incentive compensation. EPCO is the contracting party, but all or part of the associated compensation may be allocated to Enterprise Products Partners under the ASA.