Targa Resources Corp.: Form 10-K for the period ended Dec 31, 2025

CONSOLIDATED BALANCE SHEETS

(In millions)

ASSETS

See notes to consolidated financial statements.

CONSOLIDATED STATEMENTS OF OPERATIONS

(In millions, except per share amounts)

See notes to consolidated financial statements.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(In millions)

See notes to consolidated financial statements.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)

See notes to consolidated financial statements.

CONSOLIDATED STATEMENTS OF CHANGES IN OWNERS’ EQUITY

(In millions, except shares in thousands)

See notes to consolidated financial statements.

CONSOLIDATED STATEMENTS OF CHANGES IN OWNERS’ EQUITY

(In millions, except shares in thousands)

See notes to consolidated financial statements.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Except as noted within the context of each footnote disclosure, the dollar amounts presented in the tabular data within these footnote disclosures are stated in millions of dollars.

Note 1 — Organization and Operations

Our Organization

Targa Resources Corp. (NYSE: TRGP) owns, operates, acquires, and develops a diversified portfolio of complementary domestic infrastructure assets.

In this Annual Report, unless the context requires otherwise, references to “we,” “us,” “our,” “the Company,” “Targa” or “TRGP” are intended to mean our consolidated business and operations. TRGP controls the general partner of and owns all of the outstanding common units representing limited partner interests in Targa Resources Partners LP, referred to herein as the “Partnership”. Targa consolidates the Partnership and its subsidiaries under accounting principles generally accepted in the United States of America (“GAAP”), and the accompanying consolidated financial statements have been prepared under the rules and regulations of the SEC. Targa’s consolidated financial statements include differences from the consolidated financial statements of the Partnership. The most noteworthy differences are:

• the inclusion of the TRGP senior revolving credit facility;
• the inclusion of the TRGP senior unsecured notes;
• the inclusion of the TRGP commercial paper notes; and
• the impacts of TRGP’s treatment as a corporation for U.S. federal income tax purposes.

Our Operations

The Company is primarily engaged in the business of:

• gathering, compressing, treating, processing, transporting, and purchasing and selling natural gas;
• transporting, storing, fractionating, treating, and purchasing and selling NGLs and NGL products, including services to LPG exporters; and
• gathering, storing, terminaling, and purchasing and selling crude oil.

See “Note 22 – Segment Information” for certain financial information regarding our business segments.

Note 2 — Basis of Presentation

These accompanying financial statements and related notes present our consolidated financial position as of December 31, 2025 and 2024, and the results of operations, comprehensive income (loss), cash flows, and changes in owners’ equity for the years ended December 31, 2025, 2024 and 2023. We have prepared these consolidated financial statements in accordance with GAAP. All significant intercompany balances and transactions have been eliminated in consolidation. Certain amounts in prior periods have been reclassified to conform to the current year presentation.

Note 3 — Significant Accounting Policies

Consolidation Policy

Our consolidated financial statements include the accounts of all entities that we control and our proportionate interest in the accounts of certain gas gathering and processing facilities in which we own an undivided interest and are responsible for our proportionate share of the costs and expenses of the facilities. Third party ownership interests in our controlled subsidiaries are presented as noncontrolling interests within the equity section of our Consolidated Balance Sheets, except in the case of undivided interest ownership. In our Consolidated Statements of Operations and Consolidated Statements of Comprehensive Income (Loss), noncontrolling interests reflect the attribution of results to third-party investors. All intercompany balances and transactions have been eliminated in consolidation.

As of December 31, 2025, our consolidated joint ventures include the following:

Gathering and Processing Segment

• 60% ownership interest in Centrahoma Processing LLC;
• 72.8% undivided interest in the assets of Targa Pipeline Mid-Continent WestTex LLC; and
• 76.8% ownership interest in Venice Energy Services Company, LLC.

Logistics and Transportation Segment

• 80% ownership interest in Targa Train 7 LLC.

We apply the equity method of accounting to investments over which we exercise significant influence over the operating and financial policies of our investee, but do not exercise control. We evaluate our equity investments for impairment when evidence indicates the carrying amount of our investment is no longer recoverable. Evidence of a loss in value might include, but would not necessarily be limited to, absence of an ability to recover the carrying amount of the investment or inability of the equity method investee to sustain an earnings capacity that would justify the carrying amount of the investment. When the estimated fair value of an equity investment is less than its carrying value and the loss in value is determined to be other than temporary, we recognize the excess of the carrying value over the estimated fair value as a non-cash pre-tax impairment loss within Equity earnings (loss) in our Consolidated Statements of Operations.

As of December 31, 2025, our investments in unconsolidated affiliates include the following:

Gathering and Processing Segment

• 50% ownership interest in Little Missouri 4 LLC (“Little Missouri 4”).

Logistics and Transportation Segment

• 50% ownership interest in Cayenne Pipeline, LLC (“Cayenne”);
• 38.8% ownership interest in Gulf Coast Fractionators (“GCF”); and
• 17.5% non-operated ownership interest in Blackcomb and Traverse pipelines, which are currently under construction, held by Blackcomb as defined in “Note 4 – Acquisitions and Joint Ventures”.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in these financial statements and accompanying notes. Estimates and judgments are based on information available at the time such estimates and judgments are made. Changes in facts and circumstances may result in revised estimates and actual results could differ materially from those estimates. Estimates and judgments are used in, among other things, (i) estimating unbilled revenues, product purchases, property, plant and equipment, operating and general and administrative cost accruals, (ii) developing fair value assumptions, including estimates of future cash flows and discount rates, (iii) analyzing long-lived assets for possible impairment, (iv) estimating the useful lives of assets and (v) estimating contingencies, guarantees and indemnifications.

Cash and Cash Equivalents

Cash and cash equivalents include all cash on hand, demand deposits, and short-term, highly liquid investments that are readily convertible into cash, and have original maturities of three months or less.

Allowance for Credit Losses

Estimated losses on accounts receivable are provided through an allowance for credit losses. We estimate the allowance for credit losses through various procedures, including extensive review of our trade receivable balances by counterparty, assessing economic events and conditions, our historical experience with counterparties, the counterparty’s financial condition and the amount and age of past due accounts.

We continuously evaluate our ability to collect amounts owed to us. Receivables are considered past due if full payment is not received by the contractual due date. Our evaluation procedures also include performing account reconciliations, dispute resolution and payment confirmation.

As the financial condition of any counterparty changes, circumstances develop or additional information becomes available, adjustments to our allowance may be required.

Inventories

Our inventories consist primarily of NGL product inventories, which are valued at the lower of cost or net realizable value, using the average cost method. Most NGL product inventories turn over monthly, but some inventory, primarily propane, is acquired and held during the year to meet anticipated heating season requirements of our customers. Commodity inventories that are not physically or contractually available for sale under normal operations (“deadstock”) are included in Property, plant and equipment.

Product Exchanges

Exchanges of NGL products are executed to satisfy timing and logistical needs of the exchange parties. Volumes received and delivered under exchange agreements are recorded as inventory. If the locations of receipt and delivery are in different markets, an exchange differential may be billed or owed. The exchange differential is recorded as either accounts receivable or accrued liabilities.

Derivative Instruments

We utilize derivative instruments to manage the volatility of our cash flows due to fluctuating energy commodity prices. For balance sheet classification purposes, we analyze the fair values of the derivative instruments on a contract by contract basis and report the related fair values and any related collateral by counterparty on a gross basis. Cash flows from derivative instruments designated as hedges are recognized in the same financial statement line item as the cash flows from the respective item being hedged.

We formally document all relationships between hedging instruments and hedged items, as well as its risk management objectives and strategy for undertaking the hedge. This documentation includes the specific identification of the hedging instrument and the hedged item, the nature of the risk being hedged and the manner in which the hedging instrument’s effectiveness will be assessed. At the inception of the cash flow hedging relationship and on an ongoing basis, we assess whether the derivatives used in hedging transactions are highly effective in achieving the offset of changes in cash flows attributable to the hedged risk.

We record all derivative instruments at fair value with the exception of those that we apply the normal purchases and normal sales election.

The table below summarizes the accounting treatment for our derivative instruments, and the impact on our consolidated financial statements:

Recognition and Measurement

We will discontinue cash flow hedge accounting on a prospective basis when a hedge instrument is terminated, ceases to be highly effective or the forecasted transaction is no longer probable to occur. Gains and losses deferred in AOCI related to cash flow hedges for which hedge accounting has been discontinued remain deferred until the forecasted transaction occurs. If it is probable that a hedged forecasted transaction will not occur, deferred gains or losses on the hedging instrument in AOCI are reclassified to earnings immediately.

Fair Value Measurements

We categorize the inputs to the fair value measurements of financial assets and liabilities at each balance sheet reporting date using a three-tier fair value hierarchy that prioritizes the significant inputs used in measuring fair value:

• Level 1 – observable inputs such as quoted prices in active markets;
• Level 2 – inputs other than quoted prices in active markets that we can directly or indirectly observe to the extent that the markets are liquid for the relevant settlement periods; and
• Level 3 – unobservable inputs in which little or no market data exists, therefore we must develop our own assumptions.

For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivatives valued using indicative price quotations whose contract length extends into unobservable periods.

Swaps that do not have observable market prices or implied volatilities for substantially the full term of the derivative asset or liability are reported at fair value using Level 3 inputs. The fair value of these swaps is determined using a discounted cash flow valuation technique based on a commodity forward curve, which is based on observable or public data sources and extrapolated when observable prices are not available.

Property, Plant and Equipment

Property, plant and equipment is recorded at acquisition cost less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful lives of the assets. The determination of the useful lives of property, plant and equipment requires us to make various assumptions, including our expected use of the asset and the supply of, and demand for, hydrocarbons in the markets served, normal wear and tear of the facilities, and the extent and frequency of maintenance programs. Upon disposition or retirement of property, plant and equipment, any gain or loss is recorded to Other operating (income) expense in the Consolidated Statements of Operations.

Expenditures for routine maintenance and repairs are expensed as incurred. Expenditures to refurbish an asset that increases its existing service potential or prevents environmental contamination are capitalized and depreciated over the remaining useful life of the asset or major asset component. Certain costs directly related to the construction of assets, including internal labor costs, interest and engineering costs, are capitalized.

Impairment of Long-Lived Assets

We evaluate long-lived assets, including intangible assets, for impairment when events or changes in circumstances indicate our carrying amount of an asset may not be recoverable, including changes to our estimates that could have an impact on our assessment of asset recoverability. Asset recoverability is measured by comparing the carrying value of the asset or asset group with its expected future pre-tax undiscounted cash flows. Individual assets are grouped at the lowest level for which the related identifiable cash flows are largely independent of the cash flows of other assets and liabilities. These cash flow estimates require us to make judgments and assumptions related to operating and cash flow results, economic obsolescence, the business climate, contractual, legal and other factors.

If the carrying amount exceeds the expected future undiscounted cash flows, we recognize a non-cash pre-tax impairment loss equal to the excess of net book value over fair value. The estimated cash flows used to assess recoverability of our long-lived assets and measure fair value of our asset groups are derived from current business plans, which are developed using near-term price and volume projections reflective of the current environment and management's projections for long-term average prices and volumes. In addition to near and long-term price assumptions, other key assumptions include volume projections, operating costs, timing of incurring such costs, and the use of an appropriate terminal value and discount rate. Any changes we make to these projections and assumptions could result in significant revisions to our evaluation of recoverability of our long-lived assets and the recognition of additional impairments. We believe our estimates and models used to determine fair value are similar to what a market participant would use.

Goodwill

Goodwill is a residual intangible asset that results when the cost of an acquisition exceeds the fair value of the net identifiable assets of the acquired business. Goodwill is not subject to amortization but is tested for impairment at least annually. This test requires us to attribute goodwill to an appropriate reporting unit, which is an operating segment or one level below an operating segment (also known as a component). We evaluate goodwill for impairment on November 30 of each year, or whenever impairment indicators are present. If applicable, prior to us conducting the goodwill impairment test, we complete a review of the carrying values of our long-lived assets, including property, plant and equipment and other intangible assets. If it is determined that the carrying values are not recoverable, we reduce the carrying values of the long-lived assets pursuant to our policy on impairment of long-lived assets.

As part of our goodwill impairment test, we may first assess qualitative factors to determine if the quantitative goodwill impairment test is necessary. If we choose to bypass this qualitative assessment or determine that a goodwill impairment test is required, our annual goodwill impairment test is performed by comparing the fair value of a reporting unit with its carrying amount (including attributed goodwill). We recognize an impairment loss in our Consolidated Statements of Operations and a corresponding reduction of goodwill on our Consolidated Balance Sheets for the amount by which the carrying amount exceeds the reporting unit’s fair value. The goodwill impairment loss will not exceed the total amount of goodwill allocated to that reporting unit. Additionally, when measuring goodwill, we consider income tax effects from any tax-deductible goodwill on the carrying amount of the reporting unit, if applicable.

Intangible Assets

Our intangible assets include producer dedications under long-term contracts and customer relationships associated with business and asset acquisitions. The fair value of these acquired intangible assets were determined at the date of acquisition based on the present values of estimated future cash flows. We amortize the costs of our assets in a manner that closely resembles the expected benefit pattern of the intangible assets or on a straight-line basis, where such pattern is not readily determinable, over the periods in which we benefit from services provided to customers.

Asset Retirement Obligations

Asset retirement obligations (“AROs”) are legal obligations associated with the retirement of tangible long-lived assets that result from their acquisition, construction, development and/or normal operation. We record a liability and increase the basis in the underlying asset for the present value of each expected ARO when there is a legal obligation to settle under existing or enacted law, statute, written or oral contract or by legal construction.

For certain assets, we cannot reasonably estimate the fair value of the ARO because the associated assets have indeterminate lives based on our expected continued use of the assets with proper maintenance. Assets with indeterminate useful lives include: (i) assets constructed on land owned by Targa, and (ii) active pipelines. Our intent and practice is to maintain our assets to prolong their useful lives. Management expects demand for hydrocarbons, both domestically and internationally, to exist for the foreseeable future. We record AROs for these assets in the period in which sufficient information becomes available for us to reasonably estimate the settlement dates.

Our obligations are estimated based on discounted cash flow (“DCF”) estimates. Over time, the ARO liability is accreted to its present value as a period cost and the capitalized amount is depreciated over the asset’s respective useful life. At least annually, we review the projected timing and amount of AROs and reflect revisions as an increase or decrease in the carrying amount of the liability and the basis in the underlying asset. Upon settlement, we recognize any difference between the recorded amount and the actual settlement cost as a gain or loss.

Debt Issuance Costs

Costs incurred in connection with the issuance of long-term debt and any original issue discount or premium are deferred and charged to interest expense over the term of the related debt. Debt issuance costs related to revolving credit facilities are amortized on a straight-line basis and those related to long-term debt are amortized using the effective-interest method. Debt issuance costs related to revolving credit facilities are presented as other long-term assets, and debt issuance costs related to long-term debt obligations with scheduled maturities are reflected as a deduction to the carrying amount of long-term debt on the Consolidated Balance Sheets. Gains or losses on debt repurchases, redemptions and debt extinguishments include the write-off of any associated unamortized debt issuance costs.

Accounts Receivable Securitization Facility

Proceeds from the sale or contribution of certain receivables under the Partnership’s accounts receivable securitization facility (the “Securitization Facility”) are treated as collateralized borrowings in our financial statements. Proceeds and repayments under the Securitization Facility are reflected as cash flows from financing activities in our Consolidated Statements of Cash Flows.

Commercial Paper Program

Under the terms of the unsecured commercial paper note program (the “Commercial Paper Program”), we may issue, from time to time, unsecured commercial paper notes with varying maturities of less than one year. Amounts available under the Commercial Paper Program may be issued, repaid, and re-issued from time to time, with the maximum aggregate face or principal amount outstanding at any one time not to exceed $3.5 billion, subject to documentation requirements of the Commercial Paper Program. We maintain a minimum available borrowing capacity under the $3.5 billion TRGP senior revolving credit facility (the “TRGP Revolver” as defined in “Note 8 – Debt Obligations”) equal to the aggregate amount outstanding under the Commercial Paper Program to support our issued commercial paper notes. The Commercial Paper Program is guaranteed by each subsidiary that guarantees the TRGP Revolver.

The outstanding borrowings of the commercial paper program are classified as noncurrent because we have the intent and ability to refinance the borrowings on a long-term basis through the TRGP Revolver. We confirm, on a quarterly basis, that there is sufficient liquidity under the TRGP Revolver to refinance outstanding borrowings of the Commercial Paper Program and such liquidity is not overcommitted for other anticipated uses.

As the outstanding borrowings of the Commercial Paper Program are included as part of long-term debt (i.e., classified as noncurrent), we report Commercial Paper Program borrowings and repayments gross on the Consolidated Statements of Cash Flows (consistent with the presentation of cash flows associated with the revolving credit facility).

Environmental Liabilities and Other Loss Contingencies

We accrue a liability for loss contingencies, including environmental remediation costs arising from claims, assessments, litigation, fines, penalties and other sources, when the loss is probable and reasonably estimable.

Income Taxes

We file many income tax returns with the U.S. Department of the Treasury, as well as numerous states. We are required to estimate our income taxes in each of the jurisdictions in which we operate. This process involves estimating our actual current tax payable and related tax expense, together with assessing temporary differences resulting from differing treatment of certain items, such as depreciation, for tax and accounting purposes. These differences can result in deferred tax assets and liabilities, which are reported on a net basis by jurisdiction within our Consolidated Balance Sheets. We report these timing differences based on statutory tax rates applicable to the scheduled timing difference reversal periods.

We assess the likelihood that we will recover our deferred tax assets from future taxable income. We establish a valuation allowance if we believe that it is more likely than not (a likelihood of more than 50 percent) that some portion or all of the deferred tax assets will not be realized. Any change in the valuation allowance would impact our income tax provision and net income in the period in which such a determination is made. We consider all available evidence to determine whether, based on the weight of the evidence, we need a valuation allowance. Evidence used includes information about our current financial position and our results of operations for the current and preceding years, as well as all currently available information about future years, including our anticipated future performance, the reversal of deferred tax liabilities and tax planning strategies.

Dividends

Common dividends declared are recorded as a reduction of retained earnings to the extent that retained earnings were available at the close of the prior quarter, with any excess recorded as a reduction of additional paid-in capital.

Comprehensive Income

Comprehensive income includes net income and other comprehensive income (loss) (“OCI”), which includes changes in the fair value of derivative instruments that are designated as cash flow hedges.

Revenue Recognition

Our operating revenues are primarily derived from the following activities:

• sales of natural gas, NGLs, condensate and crude oil;
• services related to compressing, gathering, treating, and processing of natural gas; and
• services related to NGL fractionation, terminaling and storage, transportation and treating.

We have multiple types of contracts with commercial counterparties, and many of these contracts contain embedded fees with settlement provisions that deduct these fees from the sales price paid by Targa in exchange for commodities. The commercial relationship of the counterparty in such contracts is inherently one of a supplier, rather than a customer, and therefore, such contracts are excluded from the provisions of the revenue recognition guidance in Topic 606, Revenue from Contracts with Customers. Any cash inflows or fees that are realized on these supply type contracts are reported as a reduction of Product purchases and fuel.

Our revenues, therefore, are measured based on consideration specified in a contract with parties designated as customers. We recognize revenue when we satisfy a performance obligation by transferring control over a commodity or service to a customer. Sales and other taxes we collect, that are both imposed on and concurrent with revenue-producing activities, are excluded from revenues.

We generally report sales revenues on a gross basis in our Consolidated Statements of Operations, as we typically act as the principal in the transactions where we receive and control commodities. However, buy-sell transactions that involve purchases and sales of inventory with the same counterparty, which are legally contingent or in contemplation of one another, as well as other instances where we do not control the commodities, but rather are acting as an agent to the supplier, are reported as a single revenue transaction on a combined net basis.

Our commodity sales contracts typically contain multiple performance obligations, whereby each distinct unit of commodity to be transferred to the customer is a separate performance obligation. Under such contracts, revenue is recognized at the point in time each unit is transferred to the customer because the customer is able to direct the use of, and obtain substantially all of the remaining benefits from, the commodity at that time. In certain instances, it may be determinable that the customer receives and consumes the benefits of each unit as it is transferred. Under such contracts, we have a single performance obligation comprised of a series of distinct units of commodity; and in such instance, revenue is recognized over time using the units delivered output method, as each distinct unit is transferred to the customer. Our commodity sales contracts are typically priced at a market index, but may also be set at a fixed price. When our sales are priced at a market index, we apply the allocation exception for variable consideration and allocate the market price to each distinct unit when it is transferred to the customer. The fixed price in our commodity sales contracts generally represents the standalone selling price, and therefore, when each distinct unit is transferred to the customer, we recognize revenue at the fixed price.

Our service contracts typically contain a single performance obligation. The underlying activities performed by us are considered inputs to an integrated service and not separable because such activities in combination are required to successfully transfer the single overall service that the customer has contracted for and expects to receive. Therefore, the underlying activities in such contracts are not considered to be distinct services. However, in certain instances, the customer may contract for additional distinct services and therefore additional performance obligations may exist. In such instances, the transaction price is allocated to the multiple performance obligations based on their relative standalone selling prices. The performance obligation(s) in our service contracts is a series of distinct days of the applicable service over the life of the contract (fundamentally a stand-ready service), whereby we recognize revenue over time using an output method of progress based on the passage of time (i.e., each day of service). This output method is appropriate because it directly relates to the value of service transferred to the customer to date, relative to the remaining days of service promised under the contract.

The transaction price for our service contracts is typically comprised of variable consideration, which is primarily dependent on the volume and composition of the commodities delivered and serviced. The variable consideration is generally commensurate with our efforts to perform the service and the terms of the variable payments relate specifically to our efforts to satisfy each day of distinct service. Therefore, the variable consideration is typically not estimated at contract inception, but rather the allocation exception for variable consideration is applied, whereby the variable consideration is allocated to each day of service and recognized as revenue when each day of service is provided. When we are entitled to noncash consideration in the form of commodities, the variability related to the form of consideration (market price) and reasons other than form (volume and composition) are interrelated to the service, and therefore, we measure the noncash consideration at the point in time when the volume, mix and market price related to the commodities retained in-kind are known. This results in the recognition of revenue based on the market price of the commodity when the service is performed. In addition, if the transaction price includes a fixed component (i.e., a fixed capacity reservation fee), the fixed component is recognized ratably on a straight-line basis over the contract term, as each day of service has elapsed, which is consistent with the output method of progress selected for the performance obligation.

Our customers are typically billed on a monthly basis, or earlier, if final delivery and sale of commodities is made prior to month-end, and payment is typically due within 10 to 30 days. As a practical matter, we define the unit of account for revenue recognition purposes based on the passage of time ranging from one month to one quarter, rather than each day. This is because the financial reporting outcome is the same regardless of whether each day or month/quarter is treated as the distinct service in the series. That is, at the end of each month or quarter, the variability associated with the amount of consideration for which we are entitled to, is resolved, and can be included in that month or quarter’s revenue.

We have certain long-term contractual arrangements under which we have received consideration, but for which all conditions for revenue recognition have not been met. These arrangements result in deferred revenue, which will be recognized over the periods that performance will be provided.

We also have certain contracts that contain provisions in which customers provide contributions in aid of construction in exchange for Targa constructing assets to fulfill the services in the contract. In general, these arrangements result in deferred revenue, which will be recognized over the contract term.

We classify our contract assets as receivables because we generally have an unconditional right to payment for the commodities sold or services performed at the end of the reporting period.

We enter into various contractual arrangements that result in the transfer of assets for no upfront compensation or cash payments, resulting in more favorable long-term contractual terms. The fair value of the assets transferred is reflected as long-term contract assets. These deferred amounts are amortized over the term of the related contract into the appropriate revenue or cost of sales accounts.

Share-Based Compensation

We award share-based compensation to employees and non-employee directors in the form of restricted stock, restricted stock units and performance share units. Compensation expense on our equity-classified awards is recorded at grant-date fair value. Compensation expense is recognized in general and administrative expense over the requisite service period of each award, and forfeitures are recognized as they occur. We may purchase a portion of the shares issued to satisfy employees’ tax withholding obligations on vested awards. These shares are recorded in treasury stock, at cost, and cash paid is classified as a financing activity in our Consolidated Statements of Cash Flows. All excess tax benefits and tax deficiencies related to share-based compensation are recognized as income tax benefit or expense in our Consolidated Statements of Operations, with the tax effects of exercised or vested awards treated as discrete items in the reporting period which they occur. Excess tax benefits are classified as an operating activity in our Consolidated Statements of Cash Flows.

Earnings per Share

We calculate basic earnings (loss) per common share (“EPS”) using the two-class method, which is an earnings allocation formula that determines net income (loss) per share for each class of common stock and participating security according to dividends declared and participation rights in undistributed earnings. Our participating securities consist of unvested restricted stock units that vest no later than three years following grant date as well as certain four-year retention awards that participate in nonforfeitable dividends with the common equity owners.

EPS is net income (loss) attributable to common shareholders less earnings allocated to participating securities divided by the sum of the weighted-average number of common shares outstanding. Earnings are allocated to common stock and participating securities based on the amount of dividends paid in the current period plus an allocation of the undistributed earnings to the extent that each security participates in earnings. Diluted EPS includes any dilutive effect of unvested restricted stock, restricted stock units and performance share units. The dilutive effect is calculated through the application of the two-class method. During a period of net loss or negative undistributed earnings, the two-class method is not applicable.

Leases

We recognize the following for all leases (with the exception of short-term leases) at the commencement date:

• A lease liability, which is a lessee’s obligation to make lease payments arising from a lease.
• A right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term.

We determine if an arrangement is or contains a lease at inception. Leases with an initial term of twelve months or less are considered short-term leases, which are excluded from the balance sheet. Right-of-use assets and lease liabilities are recognized at the commencement date based on the present value of future lease payments over the lease term. The right-of-use asset also includes any lease prepayments and excludes lease incentives. We made an accounting policy election to combine lease and non-lease components for both arrangements in which Targa is the lessee or lessor. As most of the Company’s leases do not provide an implicit interest rate, we use our incremental borrowing rate as the discount rate to compute the present value of our lease liability. The discount rate applied is determined based on information available on the date of adoption for all leases existing as of that date, and on the date of lease commencement for all subsequent leases.

Our lease arrangements may include variable lease payments based on an index or market rate, or may be based on performance. For variable lease payments based on an index or market rate, we estimate and apply a rate based on information available at the commencement date. Variable lease payments based on performance are excluded from the calculation of the right-of-use asset and lease liability, and are recognized in our Consolidated Statements of Operations when the contingency underlying such variable lease payments is resolved. Our lease terms may include options to extend or terminate the lease. Such options are included in the measurement of our right-of-use asset and liability at commencement, provided we determine that we are reasonably certain to exercise the option.

45Q Tax Credits

We earn tax credits under Internal Revenue Code Section 45Q through our carbon capture and sequestration activities. We recognize 45Q tax credits by analogy to the grant model within International Accounting Standard 20, Accounting for Government Grants and Disclosure Assistance, as other operating income in our Consolidated Statements of Operations based on the volume of captured carbon sequestered and dollar value of the tax credit during the period in which captured carbon is sequestered underground. We recognize realized 45Q tax credits as a reduction to income taxes payable to the extent that we can use the tax credits to reduce Targa’s quarterly estimated cash tax payments. We recognize realized 45Q tax credits in excess of Targa’s quarterly estimated tax liability as long-term assets until they are monetized or are otherwise realized.

Recent Accounting Pronouncements

Recently Adopted Accounting Pronouncements

Improvements to Income Tax Disclosures

In December 2023, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures. The amendments in this Update require, among other items, that public entities disclose, on an annual basis, (i) specific categories of income taxes in the rate reconciliation, and (ii) a disaggregation of income taxes paid by federal, state, and foreign taxes.

The amendments are required to be applied prospectively with retrospective application permitted. We adopted this ASU on January 1, 2025, and applied the amendments to all prior periods presented in our consolidated financial statements. See “Note 19 – Income Taxes”.

Recently issued accounting pronouncements not yet adopted

Disaggregation of Income Statement Expenses

In November 2024, the FASB issued ASU 2024-03, Comprehensive income (Topic 220): Disaggregation of Income Statement Expenses. The amendments in this Update require, among other items, that public entities disclose, on an annual and interim basis, in tabular format in the footnotes to the financial statements, disaggregated information about specific categories underlying certain income statement expense line items that contain any of the following expense categories (i) purchases of inventory, (ii) employee compensation, (iii) depreciation, (iv) intangible asset amortization, and (v) depletion. Additionally, the amendments require disclosure of the total amount of selling expenses and an annual disclosure of the definition of selling expenses.

These amendments are effective for fiscal years beginning after December 15, 2026, and for interim periods within fiscal years beginning after December 15, 2027, with early adoption permitted. The disclosures may be applied either prospectively or retrospectively to any or all prior periods presented in the financial statements. We are evaluating the effect of the amendments on our notes to consolidated financial statements and expect to disclose the required information for fiscal years beginning in the annual report on Form 10-K for the year ending December 31, 2027 and for interim periods beginning in the quarterly report on Form 10-Q for the quarter ending March 31, 2028. The impact of the adoption will be limited to disclosure in the notes to consolidated financial statements.

Targeted Improvements to the Accounting for Internal-Use Software

In September 2025, the FASB issued ASU 2025-06, Intangibles—Goodwill and Other—Internal-Use Software (Subtopic 350-40): Targeted Improvements to the Accounting for Internal-Use Software. The amendments in this Update, among other items, remove all references to prescriptive and sequential software development stages and require entities to start capitalizing software costs when (i) management has authorized and committed to funding the software project, and (ii) it is probable that the project will be completed and the software will be used to perform the function intended.

These amendments are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2027, with early adoption permitted. The amendments permit the use of prospective, modified retrospective, or full retrospective transition approaches. We are evaluating the effect of the amendments on our consolidated financial statements and related disclosures. We expect to apply the amendments for interim periods beginning in the quarterly report on Form 10-Q for the quarter ending March 31, 2028 and for fiscal years beginning in the annual report on Form 10-K for the year ending December 31, 2028.

Accounting for Government Grants Received by Business Entities

In December 2025, the FASB issued ASU 2025-10, Government Grants (Topic 832): Accounting for Government Grants Received by Business Entities. The amendments in this Update, among other items, establish guidance on the recognition, measurement and presentation of government grants received by a business entity.

These amendments are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2028, with early adoption permitted. The amendments permit the use of modified prospective, modified retrospective, or retrospective approaches. We are evaluating the effect of the amendments on our consolidated financial statements and related disclosures. We expect to apply the amendments for interim periods beginning in the quarterly report on Form 10-Q for the quarter ending March 31, 2029 and for fiscal years beginning in the annual report on Form 10-K for the year ending December 31, 2029.

Note 4 — Acquisitions and Joint Ventures

In January 2023, we completed the acquisition of Blackstone Energy Partners’ 25% interest in the Grand Prix Pipeline LLC (the “Grand Prix Transaction”) for aggregate consideration of $1.05 billion in cash and a final closing adjustment of $41.9 million. Following the closing of the Grand Prix Transaction, we own 100% of the interest in Grand Prix. The change in our ownership interests was accounted for as an equity transaction representing the acquisition of noncontrolling interests. The amount of the redemption price in excess of the carrying amount, net of tax, was $490.7 million, which was accounted for as a premium on repurchase of noncontrolling interests, and resulted in a reduction to Net income (loss) attributable to common shareholders.

In December 2023, we completed the acquisition of the remaining 50% membership interest in Carnero G&P LLC (“Carnero”) from our joint venture partner for cash consideration of $27.0 million (the “Carnero Acquisition”). The change in our ownership interests was accounted for as an equity transaction representing the acquisition of noncontrolling interests. The amount of the consideration in excess of the carrying amount, net of tax, was $20.1 million, which was accounted for as a premium on repurchase of noncontrolling interests, and resulted in a reduction to Net income (loss) attributable to common shareholders.

In July 2024, we entered into a joint venture (“Blackcomb Joint Venture”) which will construct the Blackcomb pipeline. The Blackcomb Joint Venture is owned 70.0% by WPC, 17.5% by Targa, and 12.5% by MPLX LP. WPC is a joint venture owned 50.6% by WhiteWater, 30.4% by MPLX LP, and 19.0% by Enbridge Inc. The Blackcomb pipeline is designed to transport up to 2.5 Bcf/d of natural gas through approximately 365 miles of 42-inch pipeline from the Permian Basin in West Texas to the Agua Dulce area in South Texas, pending the receipt of customary regulatory and other approvals.

In April 2025, WhiteWater announced the Blackcomb Joint Venture reached a final investment decision to construct the Traverse pipeline. The bi-directional Traverse pipeline is designed to transport up to 2.5 Bcf/d of natural gas through approximately 160 miles of pipeline between the Agua Dulce area and the Katy area, pending the receipt of customary regulatory and other approvals. Both the Blackcomb and Traverse pipelines will be operated by an affiliate of WhiteWater. For additional information see “Note 7 – Investments in Unconsolidated Affiliates”.

In December 2024, we completed the acquisition of the remaining 12% membership interest in Cedar Bayou Fractionators, L.P. (“CBF”) from our joint venture partner for cash consideration of $111.6 million (the “CBF Acquisition”). The change in our ownership interests was accounted for as an equity transaction representing the acquisition of noncontrolling interests. The amount of the consideration in excess of the carrying amount, net of tax, was $32.9 million, which was accounted for as a premium on repurchase of noncontrolling interests, and resulted in a reduction to Net income (loss) attributable to common shareholders.

In March 2025, we completed the acquisition of Blackstone’s 45% interest in Targa Badlands LLC (“Targa Badlands”) for aggregate consideration of $1.8 billion in cash, with an additional $0.4 million of capitalized transaction costs (the “Badlands Transaction”). As a result of the acquisition, we own 100% of the interests in and earnings of Targa Badlands effective January 1, 2025. The change in our ownership interest was accounted for as an equity transaction representing the acquisition of noncontrolling interests. The amount of the redemption price in excess of the carrying amount, net of tax, was $70.5 million, which was accounted for as a premium on repurchase of noncontrolling interests, and resulted in a reduction to Net income (loss) attributable to common shareholders.

In December 2025, we completed the purchase of all of the membership interests in Dovetail Midstream, LLC (“Dovetail”), a wholly-owned subsidiary of Riley Exploration Permian, Inc (“Riley”), and on December 24, 2025, we completed the purchase of certain compressor assets from Riley for aggregate cash consideration of approximately $122.8 million for both the membership interests in Dovetail and certain compressor assets, subject to customary closing adjustments (together, the “Dovetail Acquisition”). The assets acquired in the Dovetail Acquisition primarily consist of compression and natural gas gathering infrastructure in Eddy County, New Mexico. Subject to certain volume-based performance thresholds, additional cash of up to $60.0 million may be payable to Riley over a five-year period. As part of the acquisition, we acquired approximately $55.1 million of Property, plant and equipment, net and recorded approximately $67.2 million of goodwill, which is fully deductible for federal income tax purposes.

The Dovetail Acquisition was accounted for under the acquisition method in accordance with ASC 805, Business Combinations, which requires, among other things, assets acquired and liabilities assumed to be recorded at their fair value on the acquisition date. The valuation of the acquired assets and liabilities was prepared using fair value methods and assumptions, including projections of future production volumes, commodity prices, and other cash flows, market-participant assumptions (e.g., discount rate and exit multiple), tangible asset replacement costs, and other management estimates. The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs, as defined in “Note 14 – Fair Value Measurements”. These inputs require judgments and estimates at the time of valuation. We are in the process of finalizing valuations related to property, plant and equipment, other assets, and contingent consideration. The final valuation will be completed no later than one year from the acquisition date.

The value of property, plant and equipment was determined using the cost approach and was primarily comprised of Gathering and Processing assets that will be depreciated on a straight-line basis over the useful lives of the assets. The associated useful lives of property, plant and equipment were based on the period over which the assets are expected to contribute directly or indirectly to our future cash flows.

In December 2025, we completed the purchase of certain midstream assets from Nile Midstream, LLC and Four Winds Midstream, LLC, both wholly-owned subsidiaries of Blackbeard Holdings, LLC, for aggregate cash consideration of $90.3 million, inclusive of capitalized transaction costs (the “Nile Acquisition”), subject to customary closing adjustments. The assets acquired in the Nile Acquisition primarily consist of compression and pipeline infrastructure. We allocated substantially all of the consideration paid to property, plant and equipment.

On January 6, 2026, we completed the acquisition of Stakeholder Midstream, LLC for a purchase price of $1.25 billion (the “Stakeholder Acquisition”), subject to customary closing adjustments. We acquired a portfolio of complementary Permian Basin midstream infrastructure assets, including approximately 480 miles of natural gas pipelines, approximately 180 MMcf/d of cryogenic natural gas processing and sour treating capacity, carbon capture activities generating 45Q tax credits, and a small crude oil gathering system. The acquisition has an effective date of January 1, 2026. We used $650.0 million in borrowings from the Commercial Paper Program and $600.0 million from the Securitization Facility to fund the Stakeholder Acquisition. At the time of this filing, it is impracticable to disclose all the information required by ASC 805, Business Combinations, as we are in the process of evaluating the purchase accounting implications of the transaction.

Note 5 — Property, Plant and Equipment and Intangible Assets

Property, Plant and Equipment and Intangible Assets

(1) The December 31, 2025 balance includes $133.1 million of gathering systems assets and $12.1 million of construction in progress from the Dovetail Acquisition and the Nile Acquisition. See “Note 4 – Acquisitions and Joint Ventures”.

For each of the years ended December 31, 2025, 2024 and 2023 depreciation expense was $1,189.3 million, $1,049.8 million and $945.6 million, respectively.

Intangible Assets

Intangible assets consist of customer contracts and customer relationships acquired in prior business combinations. The fair value of these acquired intangible assets were determined at the date of acquisition based on the present values of estimated future cash flows. Amortization expense attributable to these assets is recorded over the periods in which we benefit from services provided to customers.

For each of the years ended December 31, 2025, 2024 and 2023 amortization expense was $326.0 million, $373.2 million and $384.0 million, respectively.

The estimated annual amortization expense for intangible assets is approximately $279.8 million, $252.2 million, $234.0 million, $214.1 million and $184.3 million for each of the years 2026 through 2030. As of December 31, 2025, the weighted average amortization period for our intangible assets was approximately 9 years.

The following table shows the changes in our intangible assets for the periods presented:

F-22

Note 6 — Goodwill

As of December 31, 2025, we had $112.3 million of goodwill included in Other long-term assets on the Consolidated Balance Sheets primarily related to the Dovetail Acquisition in 2025, as discussed in “Note 4 – Acquisitions and Joint Ventures”, and the March 2017 acquisition of gas gathering and processing and crude oil gathering assets in the Permian Basin. The goodwill resulting from the Dovetail Acquisition was attributed to the Permian Delaware reporting unit within our Gathering and Processing segment.

The future cash flows and resulting fair values of these reporting units are sensitive to changes in crude oil, natural gas and NGL prices. The direct and indirect effects of significant declines in commodity prices from the date of acquisition would likely cause the fair values of these reporting units to fall below their carrying values, and could result in an impairment of goodwill.

As described in “Note 3 – Significant Accounting Policies”, we evaluate goodwill for impairment at least annually on November 30, or more frequently if we believe necessary based on events or changes in circumstances. For our 2025, 2024 and 2023 annual evaluations, we performed a qualitative assessment, which indicated that it is not more likely than not that the fair values of the Permian Midland and Permian Delaware reporting units were less than their carrying amounts, and therefore, a quantitative goodwill impairment test was not necessary. Our qualitative assessment considered, among other things, the overall financial performance and future outlook of the Permian Midland and Permian Delaware reporting units, industry and market considerations, and other relevant entity-specific events.

The fair value measurements utilized for the evaluation of goodwill for impairment are based on inputs that are not observable in the market and therefore represent Level 3 inputs, as defined in “Note 14 – Fair Value Measurements”. These inputs require significant judgments and estimates at the time a fair value assessment is required.

Note 7 — Investments in Unconsolidated Affiliates

Our investments in unconsolidated affiliates consist of the following:

Gathering and Processing Segment

• 50% operated ownership interest in Little Missouri 4.

Logistics and Transportation Segment

• 38.8% operated ownership interest in GCF;
• 50% operated ownership interest in Cayenne; and
• 17.5% non-operated ownership interest in Blackcomb and Traverse pipelines, which are currently under construction, held by the Blackcomb Joint Venture.

The terms of these joint venture agreements do not afford us the degree of control required for consolidating the entities in our consolidated financial statements, but do afford us the significant influence required to employ the equity method of accounting.

See “Note 4 – Acquisitions and Joint Ventures” for additional information related to our Blackcomb investment.

The following table shows the activity related to our investments in unconsolidated affiliates for the periods presented:

(1) In January 2023, we reached an agreement with our partners to reactivate the GCF facility. GCF commenced operations in the first quarter of 2025.

(2) Includes capitalized interest of $5.6 million related to our contributions to Blackcomb.

Note 8 — Debt Obligations

(1) As of December 31, 2025, the Partnership had no amount drawn under its $600.0 million accounts receivable securitization facility (the “Securitization Facility”), resulting in $600.0 million of remaining availability.

(2) We guarantee all of the Partnership’s outstanding senior unsecured notes.

(3) On November 12, 2025, we completed an underwritten public offering of (i) $750.0 million aggregate principal amount of our 4.350% Senior Unsecured Notes due 2029 and (ii) $1.0 billion aggregate principal amount of our 5.400% Senior Unsecured Notes due 2036, resulting in net proceeds of approximately $1.7 billion. We used a portion of the net proceeds to reduce borrowings under the Commercial Paper Program in November 2025. On January 15, 2026, we used borrowings under the Commercial Paper Program and available cash to fund the redemption of all of the Partnership’s 6.875% Senior Unsecured Notes due 2029.

(4) On February 18, 2025, we entered into a new $3.5 billion TRGP senior revolving credit facility (the “TRGP Revolver”), which matures in February 2030. In connection with our entry into the TRGP Revolver, we terminated our previous TRGP senior revolving credit facility (the “Previous TRGP Revolver”). We maintain an unsecured commercial paper note program (the “Commercial Paper Program”), the borrowings of which are supported through maintaining a minimum available borrowing capacity under the TRGP Revolver equal to the aggregate amount outstanding under the Commercial Paper Program at any one time not to exceed $3.5 billion. The TRGP Revolver had no borrowings outstanding and the Commercial Paper Program had $161.0 million of borrowings outstanding, resulting in approximately $3.3 billion of available liquidity as of December 31, 2025, after accounting for outstanding letters of credit.

(5) On June 18, 2025, we completed an underwritten public offering of (i) $750.0 million aggregate principal amount of our 4.900% Senior Unsecured Notes due 2030 and (ii) $750.0 million aggregate principal amount of our 5.650% Senior Unsecured Notes due 2036, resulting in net proceeds of approximately $1.5 billion. We used a portion of the net proceeds to reduce borrowings under the Securitization Facility and Commercial Paper Program. On July 15, 2025, we used borrowings under the Securitization Facility and Commercial Paper Program to fund the redemption of all of the Partnership’s 6.500% Senior Unsecured Notes due 2027.

(6) On February 24, 2025, we completed an underwritten public offering of (i) $1.0 billion aggregate principal amount of our 5.550% Senior Unsecured Notes due 2035 and (ii) $1.0 billion aggregate principal amount of our 6.125% Senior Unsecured Notes due 2055, resulting in net proceeds of approximately $2.0 billion.

The following table shows the range of interest rates and weighted average interest rate incurred on our variable-rate debt obligations during the year ended December 31, 2025:

Compliance with Debt Covenants

As of December 31, 2025, we were in compliance with the covenants contained in our various debt agreements.

We and certain of our subsidiaries are parties to a parent guarantee whereby each party to the agreement unconditionally guarantees, jointly and severally, the payment of all of the obligations of the Partnership and Targa Resources Partners Finance Corporation (together with the Partnership, the “Partnership Issuers”) under the respective indentures governing the Partnership Issuers’ senior unsecured notes.

Debt Obligations

Partnership’s Accounts Receivable Securitization Facility

The Securitization Facility provides up to $600.0 million of borrowing capacity at SOFR rates plus a margin. On July 28, 2025, the Partnership amended the Securitization Facility to, among other things, extend the termination date of the Securitization Facility to August 31, 2026. Under the Securitization Facility, certain Partnership subsidiaries sell or contribute certain qualifying receivables, without recourse, to another of its consolidated subsidiaries (Targa Receivables LLC or “TRLLC”), a special purpose consolidated subsidiary created for the sole purpose of the Securitization Facility. TRLLC, in turn, sells an undivided percentage ownership in the eligible receivables to third-party financial institutions. Sold or contributed receivables up to the amount of the outstanding debt under the Securitization Facility are not available to satisfy the claims of the creditors of the selling or contributing subsidiaries or the Partnership. Any excess receivables are eligible to satisfy the claims.

TRGP Revolver

On February 18, 2025, we entered into a Credit Agreement with Bank of America, N.A., as the Administrative Agent and Swing Line Lender, the letter of credit issuers party thereto and the other lenders party thereto. The TRGP Revolver provides for a revolving credit facility in an initial aggregate principal amount up to $3.5 billion (with an option to increase such maximum aggregate principal amount by up to $500.0 million in the future, subject to the terms of the TRGP Revolver) and a swing line sub-facility of up to $150.0 million. We recorded $8.9 million of debt issuance costs related to the TRGP Revolver in Other long-term assets on our Consolidated Balance Sheets. The TRGP Revolver matures on February 18, 2030. We will be able to extend the maturity date, subject to the required lenders’ consent, by one year up to two times.

The revolving credit facility bears interest at the Company’s option at: (a) the Base Rate (as such term is defined in the TRGP Revolver), which is the highest of Bank of America’s prime rate, the federal funds rate plus 0.5% and the Term SOFR (as such term is defined in the TRGP Revolver) rate plus 1.0% (subject in each case to a floor of 0.0%), plus an applicable margin ranging from 0.0% to 0.625%, dependent on the Company’s non-credit-enhanced senior unsecured long-term debt ratings (or, if no such debt is outstanding at such time, then the corporate, issuer or similar rating with respect to the Company that has been most recently announced) (the “Debt Rating”), or (b) Term SOFR (which is subject to a floor of 0.0% and includes, for Term SOFR loans, a SOFR adjustment of plus 0.10%) plus an applicable margin ranging from 1.00% to 1.625%, dependent on the Company’s Debt Rating.

The Company is required to pay a commitment fee equal to an applicable rate ranging from 0.10% to 0.275% (dependent on the Company’s Debt Rating), in each case times the actual daily unused portion of the revolving credit facility.

The obligations under the TRGP Revolver are guaranteed by Targa Resources GP LLC, Targa Energy GP LLC, Targa Resources LLC, Targa Resources Partners LP, Targa Energy LP, Targa GP Inc., Targa LP Inc., and Targa Resources Finance Corporation. The TRGP Revolver shall also be guaranteed by each existing and future direct and indirect wholly-owned subsidiary of the Company that is an obligor on or otherwise guarantees the obligations in respect of the existing notes indebtedness of Targa Resources Partners LP.

The TRGP Revolver requires the Company to maintain a Consolidated Leverage Ratio (as such term is defined in the TRGP Revolver), determined as of the last day of each quarter for the four-fiscal quarter period ending on the date of determination, of no more than 5.50 to 1.00. For any four-fiscal-quarter-period during which a material acquisition occurs, the total leverage ratio may, at the Company’s option, be determined on a pro forma basis as though such event had occurred as of the first day of such four-fiscal-quarter-period.

The TRGP Revolver restricts the Company’s ability to make dividends to stockholders if an event of default (as defined in the TRGP Revolver) exists or would result from such distribution. In addition, the TRGP Revolver contains various covenants that may limit, among other things, the Company’s ability to grant liens, merge or consolidate, and engage in transactions with affiliates and the ability of the Company’s non-guarantor subsidiaries to incur indebtedness.

The TRGP Revolver also contains various customary events of default, the occurrence of which could result in a termination of the lenders’ commitments and the acceleration of all of our obligations thereunder.

Previous TRGP Revolver

In February 2022, the Company entered into the Previous TRGP Revolver with Bank of America, N.A., as the Administrative Agent, Collateral Agent and Swing Line Lender, the Letter of Credit issuers party thereto and the lenders party thereto. The Previous TRGP Revolver provided for a revolving credit facility in an initial aggregate principal amount up to $2.75 billion and a swing line sub-facility of up to $100.0 million. The Previous TRGP Revolver was scheduled to mature on February 17, 2027. In connection with our entry into the TRGP Revolver, we terminated the Previous TRGP Revolver. As a result of the termination of the Previous TRGP Revolver, we recorded a loss due to debt extinguishment of $0.6 million.

The revolving credit facility bore interest at the Company’s option at: (a) the Base Rate (as such term is defined in the Previous TRGP Revolver), which is the highest of Bank of America’s prime rate, the federal funds rate plus 0.5% and the Term SOFR (as such term is defined in the Previous TRGP Revolver) rate plus 1.0% (subject in each case to a floor of 0.0%), plus an applicable margin ranging from 0.125% to 0.75%, dependent on the Company’s non-credit-enhanced senior unsecured long-term debt ratings (or, if no such debt was outstanding at such time, then the corporate, issuer or similar rating with respect to the Company that had been most recently announced) (the “Debt Rating”), or (b) Term SOFR (which included, for Term SOFR loans, a SOFR adjustment of plus 0.10%) plus an applicable margin ranging from 1.125% to 1.75%, dependent on the Company’s Debt Rating.

Commercial Paper Program

In July 2022, we established the Commercial Paper Program. Under the terms of the Commercial Paper Program, we may issue, from time to time, unsecured commercial paper notes with varying maturities of less than one year. Amounts available under the Commercial Paper Program may be issued, repaid and re-issued from time to time, with the maximum aggregate face or principal amount outstanding at any one time not to exceed $3.5 billion, subject to documentation requirements of the Commercial Paper Program. We maintain a minimum available borrowing capacity under the TRGP Revolver equal to the aggregate amount outstanding under the Commercial Paper Program to support our issued commercial paper notes. The Commercial Paper Program is guaranteed by each subsidiary that guarantees the TRGP Revolver. The commercial paper notes are presented in Long-term debt on our Consolidated Balance Sheets.

TRGP’s Senior Unsecured Notes

All series of our senior unsecured notes (the “TRGP Notes”) rank pari passu with our existing and future senior indebtedness, including debt issued under the TRGP Revolver and the Commercial Paper Program, and rank senior in right of payment to any of our future subordinated indebtedness. The TRGP Notes are unconditionally guaranteed by certain of our subsidiaries that guarantee the TRGP Revolver. Each guarantee ranks equally in right of payment with all of such guarantor’s existing and future unsecured senior debt and other unsecured guarantees of senior debt. The notes and the guarantees are effectively junior to any secured indebtedness of ours or any guarantor to the extent of the value of the assets securing such indebtedness and structurally subordinated to all indebtedness and other obligations of our subsidiaries that do not guarantee the notes. Interest on all issues of TRGP Notes is payable semi-annually.

The indenture governing the TRGP Notes restricts (i) our ability and the ability of our subsidiaries to incur liens and (ii) TRGP’s ability to merge or consolidate with or sell, lease, convey, transfer or otherwise dispose of all or substantially all of its assets to another company. These covenants are subject to a number of important exceptions and qualifications.

We may redeem the TRGP Notes, in whole or in part, at any time prior to the applicable par call date at a redemption price equal to the principal amount plus an applicable make-whole premium, plus accrued and unpaid interest, to the redemption date, as specified in the indenture of each series. After the applicable par call date, the TRGP Notes may be redeemed at a price equal to par, plus accrued and unpaid interest to the redemption date, as specified in the indenture of each series.

In the future, we may redeem, purchase or exchange certain of our outstanding debt through redemption calls, cash purchases and/or exchanges for other debt, in open market purchases, privately negotiated transactions or otherwise. Such calls, repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

Partnership’s Senior Unsecured Notes

All series of the Partnership’s senior unsecured notes are pari passu with the Partnership’s existing and future senior indebtedness. They are senior in right of payment to any of the Partnership’s future subordinated indebtedness and are unconditionally guaranteed by the Partnership’s restricted subsidiaries. These notes are effectively subordinated to all secured indebtedness under the Securitization Facility, which is secured by accounts receivable pledged under the facility, to the extent of the value of the collateral securing that indebtedness. Interest on all issues of senior unsecured notes is payable semi-annually in arrears.

The Partnership’s senior unsecured notes and associated indenture agreements restrict, among other things, (i) the Partnership’s ability and the ability of certain of its subsidiaries to incur liens and (ii) the Partnership’s ability to merge or consolidate with or sell, lease, convey, transfer or otherwise dispose of all or substantially all of its assets to another company. These covenants are subject to a number of important exceptions and qualifications.

The Partnership may redeem its senior unsecured notes, in whole or in part, at any time prior to their applicable maturity at a redemption price equal to the principal amount plus an applicable make-whole premium, plus accrued and unpaid interest and liquidation damages, if any, to the redemption date, as specified in the indenture of each series.

The Partnership may also redeem up to 35% of the aggregate principal amount of each series of its senior unsecured notes at the redemption dates and prices set forth in the indenture governing such series plus accrued and unpaid interest and liquidation damages, if any, to the redemption date with the net cash proceeds of one or more equity offerings, provided that: (i) at least 65% of the aggregate principal amount of each such notes (excluding notes held by the Partnership and its subsidiaries) remains outstanding immediately after the occurrence of such redemption; and (ii) the redemption occurs within 180 days of the date of the closing of such equity offering.

In the future, we or the Partnership may redeem, purchase or exchange certain of our and the Partnership’s outstanding debt through redemption calls, cash purchases and/or exchanges for other debt, in open market purchases, privately negotiated transactions or otherwise. Such calls, repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

Senior Unsecured Notes Issuances

In January 2023, we completed an underwritten public offering of (i) $900.0 million aggregate principal amount of our 6.125% Senior Unsecured Notes due 2033 (the “6.125% Notes due 2033”) and (ii) $850.0 million aggregate principal amount of our 6.500% Senior Unsecured Notes due 2053 (the “6.500% Notes due 2053”) (collectively, the “January 2023 Senior Unsecured Notes”), resulting in net proceeds of approximately $1.7 billion. The January 2023 Senior Unsecured Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by our subsidiaries that guarantee the TRGP Revolver, so long as such subsidiary guarantors satisfy certain conditions. The January 2023 Senior Unsecured Notes were issued pursuant to the Indenture, dated as of April 6, 2022, as supplemented by that certain Fifth Supplemental Indenture, dated as of January 9, 2023, among us, such subsidiary guarantors and U.S. Bank Trust Company, National Association, as trustee. We used a portion of the net proceeds from the issuance to fund the Grand Prix Transaction and the remaining proceeds for general corporate purposes, including to reduce borrowings under the Previous TRGP Revolver and the Commercial Paper Program.

In November 2023, we completed an underwritten public offering of (i) $1.0 billion aggregate principal amount of our 6.150% Senior Unsecured Notes due 2029 (the “6.150% Notes due 2029”) and (ii) $1.0 billion aggregate principal amount of our 6.500% Senior Unsecured Notes due 2034 (the “6.500% Notes due 2034”) (collectively, the “November 2023 Senior Unsecured Notes”), resulting in net proceeds of approximately $2.0 billion. The November 2023 Senior Unsecured Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by our subsidiaries that guarantee the TRGP Revolver, so long as such subsidiary guarantors satisfy certain conditions. The November 2023 Senior Unsecured Notes were issued pursuant to the Indenture, dated as of April 6, 2022, as supplemented by that certain Seventh Supplemental Indenture, dated as of November 9, 2023, among us, such subsidiary guarantors and U.S. Bank Trust Company, National Association, as trustee. We used a portion of the net proceeds to repay $1.0 billion in borrowings under the $1.5 billion unsecured term loan facility due July 2025 (the “Term Loan Facility”) and the remaining net proceeds for general corporate purposes, including to repay borrowings under the Commercial Paper Program.

In August 2024, we completed an underwritten public offering of $1.0 billion aggregate principal amount of our 5.500% Senior Unsecured Notes due 2035 (the “5.500% Notes due 2035”), resulting in net proceeds of approximately $990.1 million. The 5.500% Notes due 2035 are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by our subsidiaries that guarantee the TRGP Revolver, so long as such subsidiary guarantors satisfy certain conditions. The 5.500% Notes due 2035 were issued pursuant to the Indenture, dated as of April 6, 2022, as supplemented by that certain Ninth Supplemental Indenture, dated as of August 9, 2024, among us, each subsidiary guarantor and U.S. Bank Trust Company, National Association, as trustee. We used a portion of the net proceeds from the issuance to repay borrowings under the Commercial Paper Program, a portion of which were incurred to repay the remaining balance under the Term Loan Facility, and for general corporate purposes.

In February 2025, we completed an underwritten public offering of (i) $1.0 billion aggregate principal amount of our 5.550% Senior Unsecured Notes due 2035 (the “5.550% Notes due 2035”) and (ii) $1.0 billion aggregate principal amount of our 6.125% Senior Unsecured Notes due 2055 (the “6.125% Notes due 2055”) (collectively, the “February 2025 Senior Unsecured Notes”), resulting in net proceeds of approximately $2.0 billion. The February 2025 Senior Unsecured Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by our subsidiaries that guarantee the TRGP Revolver, so long as such subsidiary guarantors satisfy certain conditions. The February 2025 Senior Unsecured Notes were issued pursuant to the Indenture, dated as of April 6, 2022, as supplemented by that certain Tenth Supplemental Indenture, dated as of February 27, 2025, among us, each subsidiary guarantor and U.S. Bank Trust Company, National Association, as trustee. In connection with the offering, we recorded debt issuance costs of $20.4 million and discount of $6.1 million as reductions to the carrying value of the February 2025 Senior Unsecured Notes in Long-term debt on our Consolidated Balance Sheets. We used a portion of the net proceeds from the debt issuance to fund the Badlands Transaction and the remaining net proceeds for general corporate purposes, including to repay borrowings under the Commercial Paper Program.

In June 2025, we completed an underwritten public offering of (i) $750.0 million aggregate principal amount of our 4.900% Senior Unsecured Notes due 2030 (the “4.900% Notes due 2030”) and (ii) $750.0 million aggregate principal amount of our 5.650% Senior Unsecured Notes due 2036 (the “5.650% Notes due 2036”) (collectively, the “June 2025 Senior Unsecured Notes”), resulting in net proceeds of approximately $1.5 billion. The June 2025 Senior Unsecured Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by our subsidiaries that guarantee the TRGP Revolver, so long as such subsidiary guarantors satisfy certain conditions. The June 2025 Senior Unsecured Notes were issued pursuant to the Indenture, dated as of April 6, 2022, as supplemented by that certain Eleventh Supplemental Indenture, dated as of June 18, 2025, among us, each subsidiary guarantor and U.S. Bank Trust Company, National Association, as trustee. In connection with the offering, we recorded debt issuance costs of $13.6 million and discount of $3.2 million as reductions to the carrying value of the June 2025 Senior Unsecured Notes in Long-term debt on our Consolidated Balance Sheets. We used a portion of the net proceeds from the debt issuance to reduce borrowings under the Securitization Facility and Commercial Paper Program in June 2025. On July 15, 2025, we used borrowings under the Securitization Facility and Commercial Paper Program to fund the redemption of all of the Partnership’s 6.500% Senior Unsecured Notes due 2027 (the “6.500% Notes due 2027”).

In November 2025, we completed an underwritten public offering of (i) $750.0 million aggregate principal amount of our 4.350% Senior Unsecured Notes due 2029 (the “4.350% Notes due 2029”) and (ii) $1.0 billion aggregate principal amount of our 5.400% Senior Unsecured Notes due 2036 (the “5.400% Notes due 2036”) (collectively, the “November 2025 Senior Unsecured Notes”), resulting in net proceeds of approximately $1.7 billion. The November 2025 Senior Unsecured Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by our subsidiaries that guarantee the TRGP Revolver, so long as such subsidiary guarantors satisfy certain conditions. The November 2025 Senior Unsecured Notes were issued pursuant to the Indenture, dated as of April 6, 2022, as supplemented by that certain Twelfth Supplemental Indenture, dated as of November 12, 2025, among us, each subsidiary guarantor and U.S. Bank Trust Company, National Association, as trustee. In connection with the offering, we recorded debt issuance costs of $13.8 million and discount of $1.3 million as reductions to the carrying value of the November 2025 Senior Unsecured Notes in Long-term debt on our Consolidated Balance Sheets. We used a portion of the net proceeds from the debt issuance to reduce borrowings under the Commercial Paper Program in November 2025. On January 15, 2026, we used borrowings under the Commercial Paper Program and available cash to fund the redemption of all of the Partnership’s 6.875% Senior Unsecured Notes due 2029 (the “6.875% Notes due 2029”).

Debt Repurchases & Extinguishments

In November 2023, in connection with the November 2023 Senior Unsecured Notes, we repaid borrowings under the Term Loan Facility and the Commercial Paper Program. As a result of the repayment of borrowings under the Term Loan Facility, we recorded a loss of $2.1 million due to a write-off of debt issuance costs.

In May 2024, we repaid the Term Loan Facility, which bore interest at the Company’s option at: (a) the Base Rate (as defined in the Term Loan Facility), which was the highest of the (i) federal funds rate plus 0.5%, (ii) Mizuho’s prime rate, and (iii) the Term SOFR (as defined in the Term Loan Facility) rate plus 1.0% (subject in each case to a floor of 0.0%), plus an applicable margin ranging from 0.125% to 0.75% dependent on the Company’s non-credit-enhanced senior unsecured long-term debt ratings (or, if no such debt is outstanding at such time, then the Debt Rating), or (b) Term SOFR plus 0.10% plus an applicable margin ranging from 1.125% to 1.75% dependent on the Debt Rating. As a result of the repayment, we recorded a loss due to debt extinguishment of $0.8 million.

On July 15, 2025, we completed the redemption of all of the Partnership’s 6.500% Notes due 2027 and recorded a debt extinguishment loss of $1.9 million due to a write-off of debt issuance costs.

On January 15, 2026, we completed the redemption of all of the Partnership’s 6.875% Notes due 2029 and recognized a debt extinguishment loss of $10.1 million, comprised of $7.8 million related to the redemption premium paid and $2.3 million from the write-off of debt issuance costs.

The following table shows the contractually scheduled maturities of our debt obligations outstanding at December 31, 2025, for the next five years, and in total thereafter:

Financing for Stakeholder Acquisition

On January 6, 2026, we used $650.0 million in borrowings from the Commercial Paper Program and $600.0 million from the Securitization Facility to fund the Stakeholder Acquisition. See “Note 4 – Acquisitions and Joint Ventures” for further details on the Stakeholder Acquisition.

Note 9 — Other Long-term Liabilities

Other long-term liabilities are comprised of the noncurrent portion of the following obligations as of the periods presented:

See “Note 18 – Revenue” for additional disclosures related to Deferred revenue.

Asset Retirement Obligations

Our AROs primarily relate to certain processing facilities, compressor stations and inactive pipelines. The following table shows changes in our ARO liability for the periods presented:

Note 10 — Leases

We have non-cancellable operating leases primarily associated with our compressors, office facilities, rail assets, land, storage and terminal assets. We have finance leases primarily associated with our compressors, vehicles, generators, substations and tractors. Our leases have remaining lease terms of 1 to 10 years, some of which include options to extend the lease term for up to 20 years.

The following table shows balances of right-of-use assets and liabilities of finance leases and operating leases, and their locations on our Consolidated Balance Sheets as of the periods presented:

Operating lease costs and short-term lease costs are included in Operating expenses or General and administrative expense in our Consolidated Statements of Operations, depending on the nature of the leases. Finance lease costs are included in Depreciation and amortization expense and Interest expense, net in our Consolidated Statements of Operations. The following table shows components of lease expense for the periods presented:

The following table shows other supplemental information related to our leases for the periods presented:

The weighted-average remaining lease terms for operating leases and finance leases are 5 years and 4 years, respectively. The weighted-average discount rates for operating leases and finance leases are 5.0% and 4.9%, respectively.

The following table presents the maturities of our lease liabilities under non-cancellable leases as of December 31, 2025:

Note 11 — Common Stock and Related Matters

Public Offerings of Common Stock

In March 2025, we filed with the SEC a universal shelf registration statement on Form S-3 that registers the issuance of certain debt and equity securities from time to time in one or more offerings (the “March 2025 Shelf”). The March 2025 Shelf will expire in March 2028.

Common Share Repurchase Program

In May 2023, our Board of Directors approved a share repurchase program (the “2023 Share Repurchase Program”) for the repurchase of up to $1.0 billion of our outstanding common stock. During the first quarter of 2025, we exhausted the 2023 Share Repurchase Program.

In July 2024, our Board of Directors approved a share repurchase program (the “2024 Share Repurchase Program”) for the repurchase of up to $1.0 billion of our outstanding common stock. In addition, in August 2025, our Board of Directors approved a new share repurchase program (the “2025 Share Repurchase Program” and, together with the 2024 Share Repurchase Program, the “Share Repurchase Programs”) for the repurchase of up to $1.0 billion of our outstanding common stock. We are not obligated to repurchase any specific dollar amount or number of shares under the Share Repurchase Programs and may discontinue these programs at any time.

For the year ended December 31, 2025, we repurchased 3,765,272 shares of our common stock at a weighted average price per share of $170.45 for a total net cost of $641.8 million. For the year ended December 31, 2024, we repurchased 5,933,050 shares of our common stock at a weighted average price per share of $127.20 for a total net cost of $754.7 million. For the year ended December 31, 2023, we repurchased 4,870,559 shares of our common stock at a weighted average price per share of $76.72 for a total net cost of $373.7 million.

As of December 31, 2025, there was $1,373.6 million remaining under the Share Repurchase Programs.

Common Stock Dividends

In April 2025, we declared an increase to our quarterly common dividend to $1.00 per common share, or $4.00 per common share annualized, effective for the first quarter of 2025.

The following table details the dividends declared and/or paid by us to common shareholders for the years ended December 31, 2025, 2024 and 2023:

(In millions, except per share amounts)

Note 12 — Earnings per Common Share

Restricted Stock Unit awards (“RSUs”) that vest no later than three years following the RSUs’ grant date participate in quarterly cash dividend payments. As these RSUs and certain four-year retention awards participate in nonforfeitable dividends with the common equity owners of the Company, they are considered participating securities.

We calculate earnings per share using the two-class method. Earnings are allocated to common stock and participating securities based on the amount of dividends paid in the current period plus an allocation of the undistributed earnings to the extent that each security participates in earnings.

The following table sets forth a reconciliation of net income and weighted average shares outstanding used in computing basic and diluted net income per common share for the periods presented:

(In millions, except per share amounts)

(1) Represents premiums paid on the Badlands Transaction, the CBF Acquisition, the Carnero Acquisition, and the Grand Prix Transaction. See “Note 4 – Acquisitions and Joint Ventures”.

(2) Represents the distributed and undistributed earnings of the Company attributable to the participating securities. The dilutive effect of the reallocation of participating securities to diluted net income attributable to common shareholders was immaterial.

The following potential common stock equivalents are excluded from the determination of diluted earnings per share because the inclusion of such shares would have been anti-dilutive (in millions on a weighted-average basis):

Note 13 — Derivative Instruments and Hedging Activities

The primary purpose of our commodity risk management activities is to manage our exposure to commodity price risk and reduce volatility in our operating cash flow due to fluctuations in commodity prices. We have entered into derivative instruments to hedge the commodity price risks associated with a portion of our expected (i) natural gas, NGL, and condensate equity volumes in our Gathering and Processing operations that result from percent-of-proceeds processing arrangements, (ii) future commodity purchases and sales in our Logistics and Transportation segment and (iii) natural gas transportation basis risk in our Logistics and Transportation segment. The hedge positions associated with (i) and (ii) above will move favorably in periods of falling commodity prices and unfavorably in periods of rising commodity prices and are primarily designated as cash flow hedges for accounting purposes.

The hedges generally match the NGL product composition and the NGL delivery points of our physical equity volumes. Our natural gas hedges are a mixture of specific gas delivery points and Henry Hub. The NGL hedges may be transacted as specific NGL hedges or as baskets of ethane, propane, normal butane, isobutane and natural gasoline based upon our expected equity NGL composition. We believe this approach avoids uncorrelated risks resulting from employing hedges on crude oil or other petroleum products as “proxy” hedges of NGL prices. Our natural gas and NGL hedges are settled using published index prices for delivery at various locations.

We hedge a portion of our condensate equity volumes using crude oil hedges that are based on NYMEX futures contracts for West Texas Intermediate light, sweet crude, which approximates the prices received for condensate. This exposes us to a market differential risk if NYMEX futures do not move in exact parity with the sales price of our underlying condensate equity volumes.

We also enter into derivative instruments to help manage other short-term commodity-related business risks and take advantage of market opportunities. We have not designated these derivatives as hedges and record changes in fair value and cash settlements to revenues in current earnings.

At December 31, 2025, the notional volumes of our commodity derivative contracts were:

Our derivative contracts are subject to netting arrangements that permit our contracting subsidiaries to net cash settle offsetting asset and liability positions with the same counterparty within the same Targa entity. The master netting provisions reduced our maximum loss due to counterparty credit risk by $6.2 million as of December 31, 2025. The range of losses attributable to our individual counterparties would be between $0.1 million and $14.9 million, depending on the counterparty in default. We record derivative assets and liabilities on our Consolidated Balance Sheets on a gross basis, without considering the effect of master netting arrangements.

The following table reflects the fair value of our derivative instruments and their location on our Consolidated Balance Sheets as of the periods presented:

The following tables reflect the pro forma impact of reporting derivatives on our Consolidated Balance Sheets on a net basis as of the periods presented:

Some of our hedges are futures contracts executed through brokers that clear the hedges through an exchange. We maintain a margin deposit with the brokers in an amount sufficient to cover the fair value of our open futures positions. The margin deposit is considered collateral, which is included within Other current assets on our Consolidated Balance Sheets and is not offset against the fair value of our derivative instruments. Our derivative instruments other than our futures contracts are executed under International Swaps and Derivatives Association agreements (“ISDAs”), which govern the key terms with our counterparties. Our ISDAs contain credit-risk related contingent features and are not secured. As of December 31, 2025, we have outstanding net derivative positions that contain credit-risk related contingent features that are in a net liability position of $104.1 million. We have not been required to post any collateral related to these positions due to our credit rating. If our credit rating was to be downgraded one notch below investment grade by both Moody’s and S&P, as defined in our ISDAs, we estimate that as of December 31, 2025, we would not be required to post collateral to any counterparty and that no counterparty could request immediate, full settlement per the terms of our ISDAs.

The fair value of our derivative instruments, depending on the type of instrument, was determined by the use of present value methods or standard option valuation models with assumptions about commodity prices based on those observed in underlying markets. The estimated fair value of our derivative instruments was a net liability of $66.9 million as of December 31, 2025. The estimated fair value is net of an adjustment for credit risk based on the default probabilities as indicated by market quotes for our counterparties’ credit default swap rates. The credit risk adjustment was immaterial for all periods presented. Our futures contracts that are cleared through an exchange are margined daily and do not require any credit adjustment.

The following tables reflect amounts recorded in OCI and amounts reclassified from OCI to revenue for the periods presented:

As of December 31, 2025, we expect to reclassify commodity hedge related net deferred gains of $120.7 million included in Accumulated OCI into earnings before income taxes over the next twelve months. However, actual amounts reclassified into earnings could be greater or less than the net amount reported in Accumulated OCI. As of December 31, 2025, the maximum length of time over which we have hedged our exposure to the variability in future cash flows is through 2028.

Our consolidated earnings are also affected by the use of the mark-to-market method of accounting for derivative instruments that do not qualify for hedge accounting or that have not been designated as hedges. The changes in fair value of these instruments are recorded on our Consolidated Balance Sheets and through earnings in our Consolidated Statements of Operations rather than being deferred until the anticipated transaction settles. The use of mark-to-market accounting for financial assets and liabilities (“financial instruments”) can cause non-cash earnings volatility due to changes in the underlying commodity price indices. For the year ended December 31, 2025, we had unrealized mark-to-market losses primarily driven by unfavorable movement in natural gas forward basis prices.

See “Note 14 – Fair Value Measurements” and “Note 22 – Segment Information” for additional disclosures related to derivative instruments and hedging activities.

Note 14 — Fair Value Measurements

Under GAAP, our Consolidated Balance Sheets reflect a mixture of measurement methods for financial instruments. Derivative financial instruments are reported at fair value on our Consolidated Balance Sheets. Other financial instruments are reported at historical cost or amortized cost on our Consolidated Balance Sheets. The following are additional qualitative and quantitative disclosures regarding fair value measurements of our financial instruments.

Fair Value of Derivative Financial Instruments

Our derivative instruments consist of financially settled commodity swaps, futures, option contracts and fixed-price forward commodity contracts with certain counterparties. We determine the fair value of our derivative instruments using present value methods or standard option valuation models with assumptions about commodity prices based on those observed in underlying markets. We have consistently applied these valuation techniques in all periods presented and we believe we have obtained the most accurate information available for the types of derivative instruments we hold.

The fair values of our derivative instruments are sensitive to changes in forward pricing on natural gas, NGLs and crude oil. The derivatives at December 31, 2025 represent a net liability position of $66.9 million and reflects the present value, adjusted for counterparty credit risk, of the amount we expect to receive or pay in the future on our derivative instruments. If forward pricing on natural gas, NGLs and crude oil were to increase by 10%, the result would be a fair value reflecting a net liability of $235.6 million. If forward pricing on natural gas, NGLs and crude oil were to decrease by 10%, the result would be a fair value reflecting a net asset of $101.8 million.

Fair Value of Other Financial Instruments

Due to their cash or near-cash nature, the carrying value of other financial instruments included in working capital (i.e., cash and cash equivalents, accounts receivable, accounts payable) approximates their fair value. Debt is primarily the other financial instrument for which carrying value could vary significantly from fair value. We determined the supplemental fair value disclosures for our current and long-term debt as follows:

• the TRGP Revolver, Commercial Paper Program and Securitization Facility are based on carrying value, which approximates fair value as their interest rates are based on prevailing market rates; and
• the TRGP senior unsecured notes and the Partnership’s senior unsecured notes are based on quoted market prices derived from trades of the debt.

Contingent consideration liabilities related to business acquisitions are carried at fair value.

Fair Value Hierarchy

The following table shows a breakdown by fair value hierarchy category for (i) financial instruments measurements included on our Consolidated Balance Sheets at fair value and (ii) supplemental fair value disclosures for other financial instruments as of the periods presented:

(1) The fair value of derivative contracts in this table is presented on a different basis than the Consolidated Balance Sheets presentation as disclosed in “Note 13 – Derivative Instruments and Hedging Activities”. The above fair values reflect the total value of each derivative contract taken as a whole, whereas the Consolidated Balance Sheets presentation is based on the individual maturity dates of estimated future settlements. As such, an individual contract could have both an asset and liability position when segregated into its current and long-term portions for Consolidated Balance Sheets classification purposes.

(2) We have a contingent consideration liability related to the Dovetail Acquisition, which is carried at fair value. See “Note 4 - Acquisitions and Joint Ventures”.

Additional Information Regarding Level 3 Fair Value Measurements Included on Our Consolidated Balance Sheets

We report certain of our swaps at fair value using Level 3 inputs due to such derivative instruments not having observable market prices or implied volatilities for substantially the full term of the derivative asset or liability. For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivative instruments valued using indicative price quotations whose contract length extends into unobservable periods. The fair value of these swaps was determined using a discounted cash flow valuation technique based on a commodity forward curve, which is based on observable or public data sources and extrapolated when observable prices are not available. The significant unobservable inputs used in the fair value measurements of our Level 3 derivatives were the forward natural gas pricing inputs, for which a significant portion of the derivative instruments’ term is beyond available forward pricing.

The fair value of the Dovetail Acquisition contingent consideration was determined using a Monte Carlo simulation model. Significant inputs used in the fair value measurement include forecasted volumes, term of the earn-out period, risk-adjusted discount rate, and volatility associated with the underlying assets. The inputs are not observable; therefore, the entire valuation of the contingent consideration is categorized in Level 3. Subsequent changes in the fair value of this liability are included in Other income (expense) in our Consolidated Statements of Operations.

The following table summarizes the changes in fair value of our financial instruments classified as Level 3 in the fair value hierarchy for the period presented:

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Nonfinancial assets and liabilities, such as long-lived assets, are measured at fair value on a nonrecurring basis at acquisition or whenever impairment indicators are present. For disclosures related to valuation techniques used in the Dovetail Acquisition, see “Note 4 – Acquisitions and Joint Ventures”.

The techniques used to fair value assets and liabilities on a nonrecurring basis may produce a fair value calculation that may not be indicative or reflective of future fair values. Furthermore, while we believe our valuation techniques are appropriate and consistent with other market participants, the use of different techniques or assumptions to determine fair value of certain financial and nonfinancial assets and liabilities could result in a different fair value measurement at the reporting date.

Note 15 — Related Party Transactions

Transactions with Unconsolidated Affiliates

The following table summarizes increases (decreases) for the line items presented below in our Consolidated Statements of Operations as a result of transactions with unconsolidated affiliates:

Note 16 — Commitments

Future non-cancelable commitments comprise of operating and capital expenditures related to certain contractual obligations are presented below for each of the next five fiscal years and in aggregate thereafter as of December 31, 2025:

(1) Leases related to land sites and rights of way provide for surface and underground access for gathering, processing and distribution assets that are located on property not owned by us. These agreements expire at various dates, with varying terms, some of which are perpetual.

The following table shows total operating expenses incurred under the above non-cancelable commitments for the periods presented:

Note 17 — Contingencies

Legal Proceedings

We and the Partnership are parties to various legal, administrative and regulatory proceedings that have arisen in the ordinary course of our business. We and the Partnership are also parties to various proceedings with governmental environmental agencies, including, but not limited to the U.S. Environmental Protection Agency (the “EPA”), Texas Commission on Environmental Quality, Oklahoma Department of Environmental Quality, New Mexico Environment Department, Louisiana Department of Environmental Quality and North Dakota Department of Environmental Quality, which assert monetary sanctions for alleged violations of environmental regulations, including air emissions, discharges into the environment and reporting deficiencies, related to events that have arisen at certain of our facilities in the ordinary course of our business.

On July 24, 2023, we received a Notice of Violation (the “New Mexico NOV”) from the New Mexico Environment Department (the “NMED”), Air Quality Bureau, relating to alleged air permit violations at the Red Hills gas processing facility. The alleged air permit violations occurred primarily between August 1, 2021 and June 30, 2022, while the facility was owned by Lucid Energy Delaware, LLC (“Lucid”), a subsidiary we acquired in July 2022 and renamed Targa Northern Delaware LLC. On December 5, 2024, we received a proposed Administrative Compliance Order (the “ACO”) from the NMED relating to the violations identified in the New Mexico NOV and certain other alleged violations. The ACO includes a proposed civil penalty of approximately $47.8 million and requires certain capital improvements to address the operations and excess air emissions at the Red Hills processing facility. These capital improvements, totaling approximately $140 million, were substantially completed by December 31, 2024.

On January 3, 2025, we filed a Request for Hearing with the NMED with respect to the ACO. We have cooperated with the NMED in identifying and correcting legacy environmental issues since our acquisition of Lucid, and we expect to continue to engage with the NMED to resolve this matter and certain additional matters identified during our negotiations with the NMED. Although this matter is ongoing and we cannot predict its ultimate outcome, we believe we have valid defenses to many of the NMED allegations and intend to vigorously defend this matter.

On October 26, 2023, we received a final judgment in a lawsuit alleging a breach of contract related to the major winter storm in February 2021. The damages awarded against us are approximately $6.9 million, not including pre-judgment interest. Both parties appealed the judgment. On December 9, 2025, the Fifth Circuit Court of Appeals (i) reversed the trial court’s summary judgment in favor of Targa and remanded the case to trial court for further proceedings and (ii) upheld the $6.9 million jury verdict in favor of MIECO. Targa has filed a motion for reconsideration, and the appeal remains pending at the Fifth Circuit Court of Appeals.

In April 2024, we received an administrative Notice of Violation (the “EPA NOV”) from the EPA and a request for the production of documents from the United States Attorney’s Office for North Dakota relating to alleged violations of the Clean Air Act (“CAA”), at certain Targa Badlands LLC compressor stations. The EPA NOV and subpoena stem from inspections the EPA conducted at the compressor stations on June 15, 2023, as well as related records reviews. In October 2024, we began negotiations with the U.S. Attorney’s Office with respect to resolution of a single-count information alleging a violation of the CAA related to untimely installation of monitoring equipment at one compressor station, which carries a maximum fine of $500,000, and we entered into a Plea Agreement on December 16, 2024 reflecting these terms. In July 2025, we entered into a Consent Agreement and Final Order with the EPA that resolves the allegations contained in the EPA NOV by requiring, among other things, payment of an administrative penalty in the amount of approximately $3.2 million. On December 5, 2025, Targa Badlands was sentenced under the Plea Agreement, which, among other things, imposed the maximum fine of $500,000.

Note 18 — Revenue

Fixed consideration allocated to remaining performance obligations

The following table presents the estimated minimum revenue related to unsatisfied performance obligations at the end of the reporting period, and is comprised of fixed consideration primarily attributable to contracts with minimum volume commitments, for which a guaranteed amount of revenue can be calculated. These contracts are comprised primarily of gathering and processing, fractionation, export, terminaling and storage agreements, with remaining contract terms ranging from 1 to 15 years.

Based on the optional exemptions that we elected to apply, the amounts presented in the table above exclude remaining performance obligations for (i) variable consideration for which the allocation exception is met and (ii) contracts with an original expected duration of one year or less.

Deferred Revenue

Deferred revenue as of December 31, 2025 and 2024 was $135.7 million and $119.9 million, respectively. Deferred revenue includes contributions in aid of construction received from customers related to owned property, plant, and equipment for which revenue is recognized over the expected contract term. Deferred revenue also includes consideration received in 2015 and 2017 amendments to a gas gathering and processing agreement. The deferred revenue related to these amendments is being recognized through the end of the agreement’s term in 2035.

For the years ended December 31, 2025, 2024 and 2023, we recognized revenue of $20.5 million, $19.6 million and $17.4 million, respectively, from prior period deferral.

The following table shows the components of deferred revenue as of the periods presented:

The following table shows the changes in deferred revenue for the periods presented:

(1) Represents amount reclassified from deferred revenue to Accrued liabilities in 2024 as a result of a legal ruling associated with an agreement, dated December 27, 2015, for crude oil and condensate between Targa Channelview LLC, then a subsidiary of the Company, and Noble Americas Corp. On April 26, 2024, we made a cash payment of $184.8 million which included cumulative interest of $55.8 million to Vitol in satisfaction of the legal ruling.

For additional information on our revenue recognition policy, see “Note 3 – Significant Accounting Policies”, and for disclosures related to disaggregated revenue, see “Note 22 – Segment Information”.

Note 19 — Income Taxes

The following table shows components of the federal and state income tax provisions for the periods presented:

Our deferred income tax assets and liabilities as of the periods presented consist of recognition differences related to certain types of costs as follows:

(1) Our deferred tax liability attributable to investments reflects the differences between the book and tax carrying values of our investment in the Partnership.

We are subject to tax in the U.S. and various state jurisdictions, and we are subject to periodic audits and reviews by taxing authorities. As of December 31, 2025, examinations by the Internal Revenue Service (“IRS”) are currently in process for the 2022 taxable year of certain wholly-owned and consolidated subsidiaries that are treated as partnerships for U.S. federal income tax purposes. We are responding to information requests from the IRS with respect to these audits. We do not expect there to be any audit adjustments that would materially change our taxable income.

Federal statutes of limitations for returns filed in 2022 (for calendar year 2021) have expired. The statute of limitations expired on substantially all 2021 state income tax returns that were filed prior to October 15, 2022. For Texas, the statute of limitations has expired for 2021 returns (for calendar year 2020). However, tax authorities could review and adjust carryover attributes (e.g., net operating losses (“NOLs”)) generated in a closed tax year if utilized in an open tax year.

As of December 31, 2025, we have total U.S. federal NOL carryforwards of $4.4 billion and tax credit carryforwards of $3.8 million. The NOL carryforwards do not expire, but are limited to offsetting 80% of taxable income per year. The tax credit carryforwards expire in 2044. As of December 31, 2025 and 2024, our tax effected valuation allowance was $5.9 million. Of this valuation allowance, $5.2 million is federal and the remaining $0.7 million is state.

The following table shows our income taxes paid net of refunds received for the periods presented:

The following table shows the reconciliation between our Income tax provision (benefit) computed at the United States statutory rate on income before income taxes and the income tax provision (benefit) in our Consolidated Statements of Operations for the periods presented:

(1) State taxes in Texas and New Mexico made up the majority (greater than 50 percent) of the tax effect in this category.

We have not identified any uncertain tax positions. We believe that our income tax filing positions and deductions will be sustained on audit and do not anticipate any adjustments that will result in a material adverse effect on our financial condition, results of operations or cash flow. Therefore, no reserves for uncertain income tax positions have been recorded.

On July 4, 2025, President Trump signed the One Big Beautiful Bill Act (the “OBBBA”) into law. Among other things, the OBBBA indefinitely extends the 100% first-year depreciation allowance on qualified property placed in service after January 19, 2025, includes favorable modifications to the business interest expense limitation, and otherwise extends and enhances certain key provisions of the Tax Cuts & Jobs Act. The OBBBA has multiple effective dates with respect to its various provisions, with certain provisions effective in 2025. The impacts of OBBBA are reflected in our results for the year, and there was no material impact to our effective tax rate. We expect certain provisions may change the timing of cash tax payments in future periods.

The U.S. Department of the Treasury and the IRS have issued guidance on the application of the corporate alternative minimum tax (the “CAMT”), which is a 15% minimum tax imposed on certain financial income of “applicable corporations,” including proposed regulations issued in September 2024, which may be relied upon until final regulations are released. Based on our interpretation of the Inflation Reduction Act of 2022 (the “IRA”), the CAMT and related guidance, the impact from the OBBBA, and several operational, economic, accounting and regulatory assumptions, we do not anticipate paying CAMT in the near term.

Note 20 — Supplemental Cash Flow Information

(1) Interest capitalized on major projects was $77.3 million, $74.8 million and $41.1 million for the years ended December 31, 2025, 2024 and 2023.

Note 21 — Compensation Plans

2010 Targa Resources Corp. Stock Incentive Plan

In December 2010, we adopted the Targa Resources Corp. 2010 Stock Incentive Plan (the “2010 TRGP Plan”) for employees, consultants and non-employee directors of the Company. In May 2017, the 2010 TRGP Plan was amended and restated. In August 2023, the 2010 TRGP Plan was amended and restated for a second time. Total authorized shares of common stock under the plan is 15,000,000, comprised of 5,000,000 shares originally available and an additional 10,000,000 shares that became available in May 2017. The 2010 TRGP Plan allows for the grant of (i) incentive stock options qualified as such under U.S. federal income tax laws (“Incentive Options”), (ii) stock options that do not qualify as Incentive Options (“Non-statutory Options,” and together with Incentive Options, “Options”), (iii) stock appreciation rights granted in conjunction with Options or Phantom Stock Awards, (iv) restricted stock awards, (v) phantom stock awards, (vi) bonus stock awards, (vii) performance unit awards, or (viii) any combination of such awards.

Unless otherwise specified, the compensation costs for the awards listed below were recognized as expense over related vesting periods based on the grant-date fair values, reduced by forfeitures incurred.

Restricted Stock Awards – Restricted stock entitles the recipient to cash dividends. Dividends on unvested restricted stock will be accrued when declared and recorded as short-term or long-term liabilities, dependent on the time remaining until payment of the dividends, and paid in cash when the award vests. Upon issuance, the restricted stock awards will be included in the outstanding shares of our common stock. The Compensation Committee of the Targa board of directors (the “Compensation Committee”) awarded our common stock to our outside directors. In 2025, 2024 and 2023, we issued 9,479, 23,984 and 23,518 shares of director grants with weighted average grant-date fair values of $209.18, $85.70 and $74.13, respectively.

Restricted Stock Units Awards – RSUs are similar to restricted stock, except that shares of common stock are not issued until the RSUs vest. The vesting periods generally vary from one to six years. In March 2023, the Compensation Committee amended the Restricted Stock Units Grant Agreements that govern the RSUs that vest no later than three years following the RSUs’ grant date. The amendment resulted in quarterly cash dividend payments to RSU holders beginning with the common stock dividend paid in May 2023. In 2025, 2024 and 2023, we issued 348,443, 415,467 and 587,326 shares of RSUs with weighted average grant-date fair values of $173.24, $117.95 and $78.69, respectively.

The following table shows activity related to the restricted stock awards and RSUs under the 2010 TRGP Plan for the period presented:

Performance Share Units

During 2025, 2024 and 2023, we granted 77,114, 131,816 and 140,020 performance share units (“PSUs”) to executive management for the 2025, 2024 and 2023 compensation cycles that will vest/have vested in January 2028, January 2027 and January 2026. The PSUs granted under the 2010 TRGP Plan are three-year equity-settled awards linked to the performance of shares of our common stock. The awards also include dividend equivalent rights (“DERs”) that are based on the notional dividends accumulated during the vesting period.

The vesting of the PSUs is dependent on the satisfaction of a combination of certain service-related conditions and the Company’s total shareholder return (“TSR”) relative to the TSR of the members of a specified comparator group of publicly-traded midstream companies (the “LTIP Peer Group”) measured over designated periods. For the PSUs granted in 2023, 2024 and 2025, the TSR performance factor is determined by the Compensation Committee based on relative TSR over a cumulative three-year performance period. The Compensation Committee determines a guideline performance percentage for the performance period and the percentage may then be decreased or increased by the Compensation Committee at its discretion. The grantee will become vested in a number of PSUs equal to the target number awarded multiplied by the TSR performance factor, and vested PSUs will be settled by the issuance of Company common stock. The value of DERs will be paid in cash when the awards vest.

Compensation cost for equity-settled PSUs was recognized as an expense over the performance period based on fair value at the grant date. The compensation cost will be reduced if forfeitures occur. Fair value was calculated using a simulated share price that incorporates peer ranking. DERs associated with equity-settled PSUs were accrued over the performance period as a reduction of owners’ equity. We evaluated the grant date fair value using a Monte Carlo simulation model and historical volatility assumption with an expected term of three years. The expected volatilities were 32%, 34% and 38% for PSUs granted in 2025, 2024 and 2023.

The following table shows activity related to the PSUs under the 2010 TRGP Plan for the period presented:

Stock Compensation Expense

Stock compensation expense under our plans totaled $69.5 million, $63.2 million and $62.4 million for the years ended December 31, 2025, 2024 and 2023, respectively. As of December 31, 2025, we have $105.2 million of unrecognized compensation expense associated with share-based awards and an approximate remaining weighted average vesting period of 2.3 years related to our various compensation plans.

The fair values of share-based awards vested in 2025, 2024 and 2023 were $83.8 million, $87.2 million and $96.8 million, respectively. Cash dividends paid for the vested awards were $3.2 million, $5.3 million and $8.3 million for the years ended December 31, 2025, 2024 and 2023, respectively.

In relation to our equity compensation plans, we recognized $13.9 million, $14.2 million and $17.0 million in windfall tax benefits for the years ended December 31, 2025, 2024 and 2023, respectively.

Subsequent Events

In January 2026, the Compensation Committee made the following awards under the 2010 TRGP Plan:

• 10,829 shares of restricted stock to our outside directors that will vest in January 2027;
• 92,281 shares of RSUs to executive management for the 2026 compensation cycle that will vest in January 2029; and
• 92,281 shares of PSUs to executive management for the 2026 compensation cycle that will vest in January 2029.

In January 2026, the following shares vested:

• 9,479 shares of director grants with no shares withheld to satisfy tax withholding obligations;
• 130,113 shares of RSUs with 51,815 shares withheld to satisfy tax withholding obligations; and
• 325,284 shares of 2023 PSUs with 124,769 shares withheld to satisfy tax withholding obligations.

Targa 401(k) Plan

We have a 401(k) plan whereby we match 100% of up to 5% of an employee’s contribution (subject to certain limitations in the plan). We also contribute an amount equal to 3% of each employee’s eligible compensation to the plan as a retirement contribution and may make additional contributions at our sole discretion. All Targa contributions are made 100% in cash. We made contributions to the 401(k) plan totaling $39.8 million, $35.1 million and $32.3 million during the years ended December 31, 2025, 2024 and 2023, respectively.

Note 22 — Segment Information

We operate in two primary segments: (i) Gathering and Processing, and (ii) Logistics and Transportation (also referred to as the Downstream Business). Our reportable segments include operating segments that have been aggregated based on the nature of the products and services provided.

Our Gathering and Processing segment includes assets used in the gathering and/or purchase and sale of natural gas produced from oil and gas wells, removing impurities and processing this raw natural gas into merchantable natural gas by extracting NGLs; and assets used for the gathering and terminaling and/or purchase and sale of crude oil. The Gathering and Processing segment’s assets are located in the Permian Basin of West Texas and Southeast New Mexico (including the Midland, Central and Delaware Basins); the Eagle Ford Shale in South Texas; the Barnett Shale in North Texas; the Anadarko, Ardmore, and Arkoma Basins in Oklahoma (including the SCOOP and STACK) and South Central Kansas; the Williston Basin in North Dakota (including the Bakken and Three Forks plays); and the onshore and near offshore regions of the Louisiana Gulf Coast.

Our Logistics and Transportation segment includes the activities and assets necessary to convert mixed NGLs into NGL products and also includes other assets and value-added services such as transporting, storing, fractionating, terminaling, and marketing of NGLs and NGL products, including services to LPG exporters and certain natural gas supply and marketing activities in support of our other businesses. The Logistics and Transportation segment also includes our NGL pipeline system, which connects our gathering and processing positions in the Permian Basin, Southern Oklahoma and North Texas with our Downstream facilities in Mont Belvieu, Texas. Our Downstream facilities are located predominantly in Mont Belvieu and Galena Park, Texas, and in Lake Charles, Louisiana.

Other contains the unrealized mark-to-market gains/losses related to derivative contracts that were not designated as cash flow hedges. Elimination of inter-segment transactions are reflected in the corporate and eliminations column.

The Company’s chief operating decision maker (“CODM”) is the Chief Executive Officer. The Company’s CODM assesses the segments’ performance by using each segment’s operating margin. The CODM uses segment operating margin for the annual budget and forecasting process and to make informed decisions about the allocation of resources.

The following tables show reportable segment information for the periods presented:

(1) “Other segment items” represents Product purchases and fuel.

(2) Assets in the Corporate and Eliminations column primarily include tax-related assets, cash, prepaids and debt issuance costs for our revolving credit facilities.

The following table shows our consolidated revenues disaggregated by product and service for the periods presented:

(1) Represents derivative activities that are not designated as hedging instruments under ASC 815.

The following table shows a reconciliation of reportable segment Operating margin to Income (loss) before income taxes for the periods presented:

F-47

The nature of our business activities subjects us to certain hazards and risks. You should consider carefully the following risk factors together with all the other information contained in this report. If any of the following risks were to occur, then our business, financial condition, cash flows and results of operations could be materially adversely affected.

Summary Risk Factors

Risks Related to our Results of Operations

• Our cash flow is affected by supply and demand for natural gas, NGL products and crude oil and by natural gas, NGL, crude oil and condensate prices, and decreases in commodity prices and/or activity levels could adversely affect our results of operations and financial condition.
• A reduction in demand for NGL products by the petrochemical, refinery or other industries or by the fuel or export markets, or a significant increase in NGL product supply relative to this demand, could materially adversely affect our business, results of operations and financial condition.
• The natural decline in production in our operating regions and in other regions from which we source NGL supplies means our long-term success depends on our ability to obtain new sources of supplies of natural gas, NGLs and crude oil, which depends on certain factors beyond our control. Any decrease in supplies of natural gas, NGLs or crude oil could adversely affect our business and operating results.
• Our industry is highly competitive and increased competitive pressure could adversely affect our business and operating results.
• Our business is highly competitive, which may affect our ability to hire, train or retain officers and employees needed to manage and operate our business.
• If third-party pipelines and other facilities interconnected to our natural gas and crude oil gathering systems, terminals and processing facilities or to our NGL pipelines, fractionators and storage facilities become partially or fully unavailable to transport natural gas, NGLs and crude oil, our revenues could be adversely affected.
• We do not own most of the land on which our pipelines, terminals and compression facilities are located, which could disrupt our operations.
• Weather events may damage our assets, limit our ability or increase the costs to operate our business and adversely impact our customers on whom we rely on for throughput as well as third party vendors from whom we receive goods, which developments could cause us to incur significant costs and adversely affect our business, results of operations and financial condition.
• Our business involves many hazards and operational risks, some of which may not be insured or fully covered by insurance. If a significant accident or event occurs for which we are not fully insured, if we fail to recover all anticipated insurance proceeds for significant accidents or events for which we are insured, or if we fail to rebuild facilities damaged by such accidents or events, our operations and financial results could be adversely affected.
• Unexpected volume changes due to production variability or to gathering, plant or pipeline system disruptions may increase our exposure to commodity price movements.
• Portions of our pipeline systems may require increased expenditures for maintenance and repair owing to the age of some of our systems, which expenditures or resulting loss of revenue due to pipeline age or condition which could have an adverse effect on our business and results of operations.
• Terrorist attacks and the threat of terrorist attacks have resulted in increased costs to our business. Continued global and domestic hostilities may adversely impact our results of operations.
• We face opposition to operation and expansion of our pipelines and facilities from various individuals and groups.
• We may incur significant costs and liabilities resulting from performance of pipeline integrity testing programs and related repairs, as well as from initiatives relating to pipeline safety that require the use of new or more stringent safety controls or result in more rigorous enforcement of applicable legal requirements.
• We are subject to cybersecurity risks. A cyber incident could occur and result in information theft, data corruption, operational disruption, disclosure of business sensitive, confidential or personally identifiable information, misdirected wire transfers, reputational harm, and financial loss.
• The widespread outbreak of illnesses or any other public health crises that impacts operations and/or the global demand for energy commodities may have material adverse effects on our business, financial position, results of operations and/or cash flows.

Risks Related to our Capital Projects and Future Growth

• Our expansion or modification of existing assets or the construction of new assets may not result in revenue increases and are subject to regulatory, environmental, political, legal and economic risks, which could adversely affect our results of operations and financial condition.
• If we do not develop growth projects and/or make acquisitions for expanding existing assets or constructing new assets on economically acceptable terms, or fail to efficiently and effectively integrate developed or acquired assets with our asset base, our future growth will be limited. In addition, any acquisitions we complete are subject to substantial risks that could adversely affect our financial condition and results of operations. In addition, we may not achieve the expected results of any acquisitions and any adverse conditions or developments related to such acquisitions may have a negative impact on our operations and financial condition.
• We may be unable to cause our joint ventures to take or not to take certain actions unless some or all of our joint venture participants agree.

Risks Related to our Financial Condition

• If we fail to maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. In addition, potential changes in accounting standards might cause us to revise our financial results and disclosure in the future.
• We are exposed to credit risks of our customers, and any material nonpayment or nonperformance by our key customers could adversely affect our cash flow and results of operations.
• Inflation and changes in monetary policy may result in increases to the cost of our goods, services and personnel, which in turn cause our capital expenditures and operating costs to rise.
• Changes in future business conditions could have a negative impact on the demand for our services and could cause recorded long-lived assets to become further impaired, and our financial condition and results of operations could suffer if there is a negative impact on the demand for our services and an additional impairment of long-lived assets.
• Our hedging activities may not be effective in reducing the variability of our cash flows and may, in certain circumstances, increase the variability of our cash flows. Moreover, our hedges may not fully protect us against volatility in basis differentials. Finally, the percentage of our expected equity commodity volumes that are hedged decreases substantially over time.
• If we fail to balance our purchases and sales of the commodities we handle, our exposure to commodity price risk will increase.
• The amounts we pay in dividends may vary from anticipated amounts and circumstances may arise that lead to conflicts between using funds to pay anticipated dividends or for other uses in our business.
• Our future tax liability may be greater than expected if our NOL carryforwards are limited, we do not generate expected deductions, tax authorities successfully challenge certain of our tax positions or from changes in tax laws.
• Changes in tax laws or the interpretation thereof or the imposition of new or increased taxes may adversely affect our financial condition, results of operations and cash flows.
• Derivatives legislation and its implementing regulations could have a material adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.

Risks Related to the Ownership of our Common Stock

• Future sales of our common stock could lower our stock price, and any additional capital raised by us through the sale of equity or convertible securities may dilute your ownership in us.
• Our amended and restated certificate of incorporation and amended and restated bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our common stock.
• We may issue preferred stock whose terms could adversely affect the voting power or value of our common stock.

Risks Related to our Indebtedness

• Increases in interest rates, due to associated Federal Reserve policies or otherwise, could adversely affect our cost of capital, which could increase our funding costs and reduce the overall profitability of our business.
• We have a substantial amount of indebtedness which may adversely affect our financial position and we may still be able to incur substantially more debt, which could collectively increase the risks associated with compliance with our financial covenants.
• The terms of our debt agreements may restrict our current and future operations, particularly our ability to respond to changes in business or to take certain actions, including to pay dividends to our stockholders.

Risks Related to Regulatory Matters

• Our and our customers’ operations are subject to a number of risks related to the potential threat of climate change, including evolving regulations for methane and other GHG emissions from the oil and gas sector, that could result in increased operating costs, limit the areas in which oil and natural gas production may occur, reduce demand for the products and services we provide, and reduce our or our customers’ ability to access capital.
• Stakeholder and market attention to sustainability matters may impact the disclosure obligations of our business.
• We could incur significant costs in complying with more stringent occupational safety and health requirements.
• State laws and regulations limiting hydraulic fracturing activities could result in restrictions, delays or cancellations in drilling and completing new oil and natural gas wells by our customers, which could adversely impact our revenues by decreasing the volumes of natural gas, NGLs or crude oil through our facilities and reducing the utilization of our assets.
• Our operations are subject to environmental laws and regulations and a failure to comply or an accidental release into the environment may cause us to incur significant costs and liabilities.
• A change in the jurisdictional characterization of some of our assets by federal, state, tribal or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our assets, which may (i) cause our revenues to decline and operating expenses to increase or (ii) delay or increase the cost of expansion projects.
• Should we fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.
• We are subject to cybersecurity and data privacy laws and regulations, and we may become subject to litigation and directives relating to our processing of personal information.

Risks Related to our Results of Operations

Our cash flow is affected by supply and demand for natural gas, NGL products and crude oil and by natural gas, NGL, crude oil and condensate prices, and decreases in commodity prices and/or activity levels could adversely affect our results of operations and financial condition.

Our operations can be affected by the level of natural gas, NGL and crude oil prices and the relationship between these prices. The prices of natural gas, NGLs and crude oil have been historically volatile, and we expect this volatility to continue which impacts production activity levels. Our future cash flows may be materially adversely affected if we experience significant, prolonged price deterioration that also decreases production activity levels in our areas of operation. The markets and prices for natural gas, NGLs and crude oil depend upon factors beyond our control. These factors include supply and demand for these commodities, which fluctuates with changes in market and economic conditions, and other factors, including:

• the impact of seasonality and weather, including severe weather conditions and other natural disasters, such as flooding, droughts and winter storms, the frequency, severity and impact of which could be increased by the effects of climate change;
• general economic conditions and economic conditions impacting our primary markets, including the impact of proposed tariffs, inflation and increases in interest rates and associated changes in monetary policy;
• the economic conditions of our customers;
• the level of domestic crude oil and natural gas production and consumption;
• the availability of imported natural gas, liquefied natural gas, NGLs and crude oil;
• actions taken by major foreign oil and gas producing nations;
• the availability of local, intrastate and interstate transportation systems and storage for residue natural gas and NGLs;
• the availability of domestic storage for crude oil;
• the availability and marketing of competitive fuels and/or feedstocks;
• the impact of energy conservation efforts, including the promotion of the transition to a low carbon economy;
• stockholder activism and activities by non-governmental organizations to limit certain sources of funding for the energy sector or restrict the exploration, development and production of crude oil and natural gas; and
• the extent and nature of governmental regulation and taxation, including those related to the prorationing of oil and gas production.

Our commercial agreements across our Gathering and Processing and Logistics and Transportation businesses with our customers are predominantly fee-based arrangements, whereby we charge a fee for unit of throughput. Some of the commercial agreements in our natural gas gathering and processing business are percent-of-proceeds arrangements that expose us to commodity price risk. Certain of these have commodity price protection features. Under our percentage-of-proceeds arrangements, we generally process natural gas from producers and remit to the producers an agreed percentage of the proceeds from the sale of residue gas and NGL products at market prices or a percentage of residue gas and NGL products at the tailgate of our processing facilities. In some percent-of-proceeds arrangements, we remit to the producer a percentage of an index-based price for residue gas and NGL products, less agreed adjustments, rather than remitting a portion of the actual sales proceeds. Under these types of arrangements, our revenues and cash flows increase or decrease, whichever is applicable, as the prices of natural gas, NGLs and crude oil fluctuate, to the extent our exposure to these prices is unhedged. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”

A reduction in demand for NGL products by the petrochemical, refinery or other industries or by the fuel or export markets, or a significant increase in NGL product supply relative to this demand, could materially adversely affect our business, results of operations and financial condition.

The NGL products we produce have a variety of applications, including heating fuels, petrochemical feedstocks and refining blend stocks. A reduction in demand for NGL products, whether because of general or industry-specific economic conditions, government regulations, global competition, reduced demand by consumers for products made with NGL products (for example, reduced petrochemical demand observed due to lower activity in the automobile and construction industries), reduced demand for propane or butane exports whether for price or other reasons, increased competition from petroleum-based feedstocks due to pricing differences, mild winter weather for some NGL applications or other reasons, could result in a decline in the volume of NGL products we handle or reduce the fees we charge for our services. Also, increased supply of NGL products could reduce the value of NGLs handled by us and reduce the margins realized. Our NGL products and their demand are affected as follows:

Ethane. Ethane is typically supplied as purity ethane and as part of an ethane-propane mix. Ethane is primarily used in the petrochemical industry as feedstock for ethylene, one of the basic building blocks for a wide range of plastics and other chemical products. Although ethane is typically extracted as part of the mixed NGL stream at gas processing plants, if natural gas prices increase significantly in relation to NGL product prices or if the demand for ethylene falls, it may be more profitable for natural gas processors to leave the ethane in the natural gas stream, thereby reducing the volume of NGLs delivered for fractionation and marketing.

Propane. Propane is used as a petrochemical feedstock in the production of ethylene and propylene, as a heating, engine and industrial

fuel, and in agricultural applications such as crop drying. Changes in demand for ethylene and propylene could adversely affect demand for propane. The demand for propane as a heating fuel is significantly affected by weather conditions. The volume of propane sold is increasingly driven by international exports supplying a growing global demand for the product. Domestically in the U.S., propane is at its highest during the six-month peak heating season of October through March. Demand for our propane may be reduced during periods of slow global economic growth and warmer-than-normal weather.

Normal Butane. Normal butane is used in the production of isobutane, as a refined petroleum product blending component, as a fuel gas (either alone or in a mixture with propane) and in the production of ethylene and propylene. Changes in the composition of refined petroleum products resulting from governmental regulation, changes in feedstocks, products and economics, and demand for heating fuel, ethylene and propylene could adversely affect demand for normal butane. The volume of butane sold is increasingly driven by international exports supplying a growing demand for the product.

Isobutane. Isobutane is predominantly used in refineries to produce alkylates to enhance octane levels. Accordingly, any action that reduces demand for motor gasoline or demand for isobutane to produce alkylates for octane enhancement might reduce demand for isobutane.

Natural Gasoline. Natural gasoline is used as a blending component for certain refined petroleum products and as a feedstock used in the production of ethylene and propylene. Changes in the mandated composition of motor gasoline resulting from governmental regulation, and in demand for ethylene and propylene, could affect demand for natural gasoline.

NGLs and products produced from NGLs also compete with products from global markets. Any reduced demand or increased supply for ethane, propane, normal butane, isobutane or natural gasoline in the markets we access for any of the reasons stated above could adversely affect both demand for the services we provide and NGL prices, which could negatively impact our results of operations and financial condition.

The natural decline in production in our operating regions and in other regions from which we source NGL supplies means our long-term success depends on our ability to obtain new sources of supplies of natural gas, NGLs and crude oil, which depends on certain factors beyond our control. Any decrease in supplies of natural gas, NGLs or crude oil could adversely affect our business and operating results.

Our gathering systems are connected to crude oil and natural gas wells from which production will naturally decline over time, which means that the cash flows associated with these sources of natural gas and crude oil will likely also decline over time. Our logistics assets are similarly impacted by declines in NGL supplies in the regions in which we operate as well as other regions from which we source NGLs. To maintain or increase throughput levels on our gathering systems and the utilization rate at our processing plants and our treating and fractionation facilities, we must continually obtain new natural gas, NGL and crude oil supplies. A material decrease in natural gas or crude oil production from producing areas on which we rely, as a result of depressed commodity prices or otherwise, could result in a decline in the volume of natural gas or crude oil that we gather and process, NGLs that we transport or NGL products delivered to our fractionation facilities. Our ability to obtain additional sources of natural gas, NGLs and crude oil depends, in part, on the level of successful drilling and production activity near our gathering systems and, in part, on the level of successful drilling and production in other areas from which we source NGL and crude oil supplies. We have no control over the level of such activity in the areas of our operations, the amount of reserves associated with the wells or the rate at which production from a well will decline. In addition, we have no control over producers or their drilling, completion or production decisions, which are affected by, among other things, prevailing and projected energy prices, demand for hydrocarbons, the level of reserves, geological considerations, governmental regulations, the availability of drilling rigs, other production and development costs and the availability and cost of capital.

Fluctuations in energy prices can greatly affect production rates and investments by third parties in the development of new oil and natural gas reserves. Even if new natural gas or crude oil reserves are discovered in areas served by our assets, producers may choose not to develop those reserves. In response to depressed commodity prices, operators may engage in curtailment or shut-ins or substantially reduce their estimated capital expenditures, rig count and completion crews. Reductions in exploration and production activity, competitor actions or shut-ins by producers in the areas in which we operate may prevent us from obtaining supplies of natural gas or crude oil to replace the natural decline in volumes from existing wells, which could result in reduced volumes through our facilities and reduced utilization of our gathering, treating, processing, transportation and fractionation assets.

Our industry is highly competitive and increased competitive pressure could adversely affect our business and operating results.

We compete with similar enterprises in our respective areas of operation. Some of our competitors are large crude oil, natural gas and NGL companies that have greater financial resources and access to supplies of natural gas, NGLs and crude oil than we do. Some of these competitors may expand or construct gathering, processing, storage, terminaling and transportation systems that would create additional competition for the services we provide to our customers. In addition, customers who are significant producers of natural gas may develop their own gathering, processing, storage, terminaling and transportation systems in lieu of using those operated by us. Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain current revenues and cash flows could be adversely affected by the activities of our competitors and our customers. All of these competitive pressures could have a material adverse effect on our business, results of operations and financial condition.

Our business is highly competitive, which may affect our ability to hire, train or retain officers and employees needed to manage and operate our business.

We operate in areas in which industry activity has increased rapidly. As a result, demand for qualified personnel in these areas, particularly those related to our Permian and Badlands assets, and the cost to attract and retain such personnel, has increased over the past few years due to competition, and may increase substantially in the future. Moreover, our competitors may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer.

In addition, there is substantial competition for experienced supervisory and managerial personnel in the midstream industry. We may not be able to retain our existing executive officers or fill new positions or vacancies created by expansion or turnover, and we have not entered into employment agreements with any of our named executive officers nor do we maintain “key man” life insurance on the lives of any of our named executive officers.

Any delay or inability to secure the officers and employees necessary for us to continue or complete our current and planned development projects, or any significant increases in costs with respect to the hiring, training or retention of qualified personnel, could have a material adverse effect on our business, financial condition and results of operations.

If third-party pipelines and other facilities interconnected to our natural gas and crude oil gathering systems, terminals and processing facilities or to our NGL pipelines, fractionators and storage facilities become partially or fully unavailable to transport natural gas, NGLs and crude oil, our revenues could be adversely affected.

We depend upon third-party pipelines, storage and other facilities that provide delivery options to and from our gathering and processing facilities and our NGL pipelines, fractionators and storage facilities. Since we do not own or operate these pipelines or other facilities, their continuing operation in their current manner is not within our control. If any of these third-party facilities become partially or fully unavailable, or if the quality specifications for their facilities change so as to restrict our ability to utilize them, our revenues could be adversely affected.

We do not own most of the land on which our pipelines, terminals and compression facilities are located, which could disrupt our operations.

We do not own most of the land on which our pipelines, terminals and compression facilities are located, and we are therefore subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if we do not have valid rights of way or leases or if such rights of way or leases lapse or terminate. We sometimes obtain the rights to land owned by third parties and governmental agencies for a specific period of time. Additionally, the federal Tenth Circuit Court of Appeals has held that tribal ownership of even a very small fractional interest in an allotted land, that is, tribal land owned or at one time owned by an individual Indian landowner, bars condemnation of any interest in the allotment. Consequently, the inability to condemn such allotted lands under circumstances where an existing pipeline rights of way may soon lapse or terminate serves as an additional impediment for pipeline operators. We cannot guarantee that we will always be able to renew existing rights of way or obtain new rights of way without experiencing significant costs. Any loss of rights with respect to our real property, through our inability to renew rights of way contracts or leases, or otherwise, could cause us to cease operations on the affected land, increase costs related to continuing operations elsewhere and reduce our revenue.

Weather events may damage our assets, limit our ability or increase the costs to operate our business and adversely impact our customers on whom we rely on for throughput as well as third party vendors from whom we receive goods, which developments could cause us to incur significant costs and adversely affect our business, results of operations and financial condition.

Weather events in the areas in which we or our customers operate can cause disruptions and in some cases suspension of our operations and development activities. For example, unseasonably wet weather, extended periods of below freezing weather, or hurricanes, among other disruptive weather patterns, may cause a loss of throughput from temporary cessation of activities or lost, damaged or ineffective equipment. Our planning for normal climatic variation, insurance programs and emergency recovery plans may inadequately mitigate the effects of such weather conditions, and not all such effects can be predicted, eliminated or insured against. Potential climatic changes may have significant physical effects, such as increased frequency and severity of storms, floods, droughts, extreme temperatures, wildfires and wintry conditions and could have an adverse effect on our infrastructure or continued operations as well as the operations of our oil and gas exploration and production customers that deliver natural gas to us for processing and throughput, our third party vendors that supply us with goods, utilities necessary for our, our suppliers’, or our customers’ continued operations, and third party insurance providers that make insuring products available to defray our costs or offset any damages and losses we incur. Any unusual or prolonged severe weather events or increased frequency thereof, such as freezing weather or rain, earthquakes, hurricanes, droughts, extreme temperatures, wildfires or floods in our oil and gas exploration and production customers’ or our third party vendors’ areas of operations or markets, whether due to climatic change or otherwise, could have a material adverse effect on our business, results of operations and financial condition.

Our operations along the Gulf Coast, in offshore waters and at major river crossings in particular could be adversely impacted by changing climatic conditions, as rising sea levels, subsidence and erosion are potential causes for serious damage to our pipelines and other facilities, which could affect our ability to provide services. These damages could result in leakage, migration, releases or spills from our operations to surface or subsurface soils, surface water, groundwater or to the Gulf of America and could result in liability, remedial obligations or otherwise have a negative impact on continued operations. Additionally, rising sea levels, subsidence and erosion processes could impact our oil and gas exploration and production customers who operate along the Gulf Coast, and they may be unable to utilize our services. Adverse climatic impacts, whether inland or along the coast or offshore, could also affect our third-party suppliers, which could limit their ability to provide us with the necessary products and services enabling us to maintain operation of our pipelines and other facilities. Moreover, we could incur significant costs to weatherize or upgrade weatherization of our facility equipment in anticipation of future weather events. As a result, we may incur significant costs to repair, preserve or make more efficient our pipeline infrastructure and other facilities. Such costs could adversely affect our business, financial condition, results of operations and cash flows.

Our business involves many hazards and operational risks, some of which may not be insured or fully covered by insurance. If a significant accident or event occurs for which we are not fully insured, if we fail to recover all anticipated insurance proceeds for significant accidents or events for which we are insured, or if we fail to rebuild facilities damaged by such accidents or events, our operations and financial results could be adversely affected.

Our operations are subject to many hazards inherent in gathering, compressing, treating, processing, transporting, purchasing and selling natural gas; transporting, storing, fractionating, treating and purchasing and selling NGLs and NGL products, including services to LPG exporters; and gathering, storing, terminaling and purchasing and selling crude oil, including:

• damage to pipelines and plants, related equipment and surrounding properties caused by hurricanes, earthquakes, tornadoes, floods, fires, extreme temperatures, and other natural disasters, explosions, cyberattacks, and acts of terrorism;
• inadvertent damage from third parties, including from motor vehicles and construction, farm or utility equipment;
• damage that is the result of our negligence or any of our employees’ negligence;
• leaks of natural gas, NGLs, crude oil and other hydrocarbons or losses of natural gas or NGLs as a result of the malfunction of equipment or facilities;
• spills or other unauthorized releases of natural gas, NGLs, crude oil, other hydrocarbons or waste materials that contaminate the environment, including soils, surface water and groundwater, and otherwise adversely impact natural resources; and
• other hazards that could also result in personal injury, loss of life, pollution and/or suspension of operations.

These risks could result in substantial losses due to personal injury, loss of life, severe damage to and destruction of property and equipment, and pollution or other environmental or natural resource damage, and may result in delay, curtailment or suspension of our related operations. A natural disaster or other hazard affecting the areas in which we operate could have a material adverse effect on our operations. We are not fully insured against all risks inherent to our business. Additionally, while we are insured against pollution resulting from environmental accidents that occur on a sudden and accidental basis, we may not be insured against all environmental accidents that might occur, some of which may result in toxic tort claims. If a significant accident or event occurs that is not fully insured, if we fail to recover all anticipated insurance proceeds for significant accidents or events for which we are insured, or if we fail to rebuild facilities damaged by such accidents or events, our operations and financial condition could be adversely affected. In addition, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies have increased substantially, and could escalate further. For example, following the occurrence of severe hurricanes along the U.S. Gulf Coast, insurance premiums, deductibles and co-insurance requirements increased substantially, and terms were generally less favorable than terms that could be obtained prior to such hurricanes, with some coverage unavailable at any cost. Further, due to the impacts of recent weather events, certain major insurance companies are either reducing, or no longer offering, certain coverages in Texas, among other states. If a significant accident or event occurs for which we are not fully insured or if we fail to acquire insurance for certain of our operations generally, our operations and financial results could be adversely affected.

Unexpected volume changes due to production variability or to gathering, plant or pipeline system disruptions may increase our exposure to commodity price movements.

We sell processed natural gas at plant tailgates or at pipeline pooling points. Sales made to natural gas marketers and end-users may be interrupted by disruptions to volumes anywhere along the system. We attempt to balance sales with volumes supplied from processing operations, but unexpected volume variations due to production variability or to gathering, plant or pipeline system disruptions may expose us to volume imbalances, which, in conjunction with movements in commodity prices, could materially impact our income from operations and cash flow.

Portions of our pipeline systems may require increased expenditures for maintenance and repair owing to the age of some of our systems, which expenditures or resulting loss of revenue due to pipeline age or condition which could have an adverse effect on our business and results of operations.

Some portions of the pipeline systems that we operate have been in service for several decades prior to our purchase of them. Consequently, there may be historical occurrences or latent issues regarding our pipeline systems that our executive management may be unaware of and that may have a material adverse effect on our business and results of operations. The age and condition of some of our pipeline systems could also result in increased maintenance or repair expenditures, and any downtime associated with increased maintenance and repair activities could materially reduce our revenue. Any significant increase in maintenance and repair expenditures or loss of revenue due to the age or condition of some portions of our pipeline systems could adversely affect our business and results of operations.

Terrorist attacks and the threat of terrorist attacks have resulted in increased costs to our business. Continued global and domestic hostilities may adversely impact our results of operations.

The long-term impact of terrorist attacks and the threat of future terrorist attacks on our industry in general and on us in particular is not known at this time. However, resulting regulatory requirements and/or related business decisions associated with security are likely to increase our costs. Increased security measures taken by us as a precaution against possible terrorist attacks have resulted in increased costs to our business. Uncertainty surrounding continued global and domestic hostilities may affect our operations in unpredictable ways, including disruptions of crude oil supplies and markets for our products, and the possibility that infrastructure facilities could be direct targets, or indirect casualties, of an act of terror.

Changes in the insurance markets attributable to terrorist attacks may make certain types of insurance more difficult for us to obtain. Moreover, the insurance that may be available to us may be significantly more expensive than our existing insurance coverage or coverage may be reduced or unavailable. Instability in the financial markets as a result of terrorism or war could also affect our ability to raise capital.

We face opposition to operation and expansion of our pipelines and facilities from various individuals and groups.

We have experienced, and may encounter from time to time, opposition to the operation and expansion of our pipelines and facilities from governmental officials, non-governmental environmental organizations and groups, landowners, tribal groups, local groups and other advocates. In some instances, we encounter opposition which disfavors hydrocarbon-based energy supplies regardless of practical implementation or financial considerations. Opposition to our operation and expansion can take many forms, including the delay, denial or termination of required governmental permits or approvals, organized protests, attempts to block or sabotage our operations, intervention in regulatory or administrative proceedings involving our assets or lawsuits or other actions designed to prevent, disrupt, delay or terminate the operation or expansion of our assets and business. Similar actions pursued against our oil and gas customers could result in interruptions or limitations to their businesses, which could reduce demand for our services. Any such event that restricts, delays or prevents the expansion of our or our customers’ businesses, interrupts the revenues generated by our or our customers’ operations or causes us or our customers to make significant expenditures not covered by insurance could adversely affect our business, results of operations, and financial condition, as well as reduce the demand for our services. Regulatory attention to environmental justice matters at the federal and state level may also provide communities opposed to our operations with greater opportunities to challenge or delay the permitting approval process.

We may incur significant costs and liabilities resulting from performance of pipeline integrity testing programs and related repairs, as well as from initiatives relating to pipeline safety that require the use of new or more stringent safety controls or result in more rigorous enforcement of applicable legal requirements.

Pursuant to the authority under the NGPSA and HLPSA, PHMSA has established rules requiring pipeline operators to develop and implement integrity management programs for certain natural gas and hazardous liquids pipelines located where a pipeline leak or rupture could affect higher and moderate consequence risk areas, known as HCAs and MCAs, which are areas where a release could have the most significant adverse consequences. Among other things, these regulations require operators of covered pipelines to:

• perform ongoing assessments of pipeline integrity;
• identify and characterize applicable threats to pipeline segments that could impact an HCA, MCA or Class 3 or 4 area;
• maintain processes for data collection, integration and analysis;
• repair and remediate pipelines as necessary; and
• implement preventive and mitigating actions.

The Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (“2011 Pipeline Safety Act”), the Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016 (“2016 Pipeline Safety Act”) and the Protecting Our Infrastructure of Pipelines and Enhancing Safety (“PIPES”) Act of 2020, require PHMSA to impose more stringent pipeline safety standards on pipeline operators. As a result of those legislative enactments, PHMSA has issued several significant rulemakings. In August 2022, PHMSA finalized the last of three rules known collectively as the “Gas Mega Rule,” which collectively, among other items, imposed safety regulations on previously unregulated onshore gas gathering lines, required updated inspection and maintenance plans for the elimination of hazardous leaks and minimization of natural gas released from pipeline facilities and adjusted and strengthened repair, maintenance and integrity management assessment criteria for pipelines in HCAs and non-HCAs. The rule has been subject to litigation, and in August 2024, the D.C. Circuit Court agreed with the challengers that PHMSA had failed to conduct an adequate cost-benefit analysis of four of the new standards, vacating those aspects of the rules. In January 2025, PHMSA finalized a rule that enhances the safety requirements for gas distribution pipelines and requires updates to distribution integrity management programs, emergency response plans, operation and maintenance manuals and other safety practices. However, the current administration withdrew the final rule and, accordingly, it has not been codified. The integrity-related requirements and other provisions of the 2011 Pipeline Safety Act, the 2016 Pipeline Safety Act, and the PIPES Act of 2020, as well as any implementation of PHMSA rules thereunder, could require us to pursue additional capital projects or conduct integrity or maintenance programs on an accelerated basis and incur increased operating costs that could have a material adverse effect on our costs of transportation services as well as our business, results of operations and financial condition.

In addition, certain states, including Texas, Louisiana, Oklahoma, New Mexico, and North Dakota, where we conduct operations, have adopted regulations similar to existing PHMSA regulations for certain intrastate natural gas and hazardous liquids pipelines. We plan to continue our pipeline integrity inspection programs to assess and maintain the integrity of our pipelines. The results of these inspections may cause us to incur material and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines.

The imposition of new or enhanced safety requirements, or any issuance or reinterpretation of guidance by PHMSA or any other state or federal agencies with respect thereto, may require us to install new or modified safety controls, pursue additional capital projects or conduct maintenance programs on an accelerated basis, any or all of which could result in increased operating costs that could have an adverse effect on our results of operations or financial position.

We are subject to cybersecurity risks. A cyber incident could occur and result in information theft, data corruption, operational disruption, disclosure of business sensitive, confidential or personally identifiable information, misdirected wire transfers, reputational harm, and financial loss.

The oil and natural gas industry has become increasingly dependent on digital technologies to conduct business. For example, we depend on digital technologies to operate our facilities, serve our customers and record financial data. At the same time, cyber incidents, including deliberate attacks, have increased. Our technologies, systems, networks, including our operational technology systems, and those of our business partners may become the target of cyberattacks or security breaches. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of cybersecurity threats. Our technologies, systems and networks, and those of our vendors, suppliers, customers and other business partners, may become the target of cyberattacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or could adversely disrupt our business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period. Our systems for protecting against cybersecurity risks may not be sufficient, and no security measure is infallible. As cyber incidents continue to evolve, we will be required to expend additional resources to enhance our security posture and cybersecurity defenses or to investigate and remediate any vulnerability to or consequences of cyber incidents. Advances in computer capabilities, rapid changes and innovation in the field of artificial intelligence, cryptography, inadequate facility security or other developments may result in a compromise or breach of the technology we use to safeguard confidential, personal, or otherwise protected information. As the breadth and complexity of the technologies we use continue to grow, including as a result of the use of artificial intelligence, mobile devices, cloud computing, open source software, social media and the increased reliance on devices connected to the internet, the potential risk of security breaches and cybersecurity attacks also increases. Despite ongoing efforts to improve our ability to protect data from compromise, we may not be able to protect all data across our diverse systems. Our efforts to improve security and protect data may also identify previously undiscovered instances of security breaches or other cyber incidents. Our insurance coverages may not be sufficient to cover all the losses we may experience as a result of a cyber incident.

The widespread outbreak of illnesses or any other public health crises that impacts operations and/or the global demand for energy commodities may have material adverse effects on our business, financial position, results of operations and/or cash flows.

We face risks related to major public health crises that are outside of our control and could significantly disrupt our operations and demand for our services, which could adversely affect our financial condition.

Risks Related to our Capital Projects and Future Growth

Our expansion or modification of existing assets or the construction of new assets may not result in revenue increases and are subject to regulatory, environmental, political, legal and economic risks, which could adversely affect our results of operations and financial condition.

The construction of additions or modifications to our existing systems and the construction of new midstream assets involve numerous regulatory, environmental, political and legal uncertainties beyond our control and may require the expenditure of significant amounts of capital. If we undertake these projects, they may not be completed on schedule, at the budgeted cost or at all. For example, the construction of additional systems may be delayed or require greater capital investment if the commodity prices of certain supplies, such as steel pipe, increase due to imposed tariffs. Moreover, our revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if we build a new pipeline, fractionation facility or gas processing plant, the construction may occur over an extended period of time and we will not receive any material increases in revenues until the project is completed. Moreover, we may construct pipelines or facilities to capture anticipated future growth in production in a region in which such growth does not materialize. For example, we do not possess reserves estimation expertise, and we typically do not obtain independent evaluations of natural gas or crude oil reserves connected to our gathering systems. As a result, the total reserves or estimated life of the reserves connected to our gathering systems could be less than we anticipate. Thus, new pipelines or facilities may receive lower volumes than we anticipate and may not be able to attract enough throughput to achieve our expected investment return, which could adversely affect our results of operations and financial condition. In addition, the construction of additions to our existing gathering and transportation assets may require us to obtain new rights of way prior to constructing new pipelines. We may be unable to obtain or renew such rights of way to connect new natural gas and crude oil supplies to our existing gathering lines or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for us to obtain new rights of way or to renew existing rights of way. If the cost of renewing or obtaining new rights of way increases, our cash flows could be adversely affected.

If we do not develop growth projects and/or make acquisitions for expanding existing assets or constructing new assets on economically acceptable terms, or fail to efficiently and effectively integrate developed or acquired assets with our asset base, our future growth will be limited. In addition, any acquisitions we complete are subject to substantial risks that could adversely affect our financial condition and results of operations. In addition, we may not achieve the expected results of any acquisitions and any adverse conditions or developments related to such acquisitions may have a negative impact on our operations and financial condition.

Our ability to grow depends, in part, on our ability to develop growth projects and/or make acquisitions that result in an increase in cash generated from operations. If we are unable to develop accretive growth projects or make accretive acquisitions because we are unable to (i) develop growth projects economically or identify attractive acquisition candidates and negotiate acceptable acquisition agreements, (ii) obtain financing for these projects or acquisitions on economically acceptable terms, or (iii) compete successfully for growth projects or acquisitions, then our future growth may be limited.

Any growth project or acquisition involves potential risks, including, among other things:

• operating a significantly larger combined organization and adding new or expanded operations;
• difficulties in the assimilation of the assets and operations of the growth projects or acquired businesses, especially if the assets developed or acquired are in a new business segment and/or geographic area;
• the risk that crude oil and natural gas reserves expected to support the acquired assets may not be of the anticipated magnitude or may not be developed as anticipated;
• the failure to realize expected volumes, revenues, profitability or growth or any expected synergies and cost savings;
• coordinating geographically disparate organizations, systems and facilities;
• the assumption of environmental and other unknown liabilities;
• limitations on rights to indemnity from the seller in an acquisition or the contractors and suppliers in growth projects;
• the failure to attain or maintain compliance with environmental and other governmental regulations;
• inaccurate assumptions about the overall costs of equity or debt or the tightening of capital markets and access to new capital;
• the diversion of management’s and employees’ attention from other business concerns;
• challenges associated with joint venture relationships and minority investments, including dependence on joint venture partners, controlling shareholders or management who may have business interests, strategies or goals that are inconsistent with ours; and
• customer or key employee losses at the acquired businesses or to a competitor.

If these risks materialize, any growth project or acquired assets may inhibit our growth, fail to deliver expected benefits and/or add further unexpected costs. Challenges may arise whenever businesses with different operations or management are combined, and we may experience unanticipated delays in realizing the benefits of a growth project or acquisition if we fail to successfully integrate such businesses with our operations. If we consummate any future growth project or acquisition, our capitalization and results of operations may change significantly and you may not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in evaluating future growth projects or acquisitions.

A reduction in divestitures of energy assets by industry participants or a decrease in opportunities for industry expansion could limit our opportunities for future growth projects or acquisitions and could adversely affect our operations.

Growth projects may increase our concentration in a line of business or geographic region and acquisitions may significantly increase our size and diversify the geographic areas in which we operate. In addition, we may not achieve the desired effect from any future growth projects or acquisitions.

We may be unable to cause our joint ventures to take or not to take certain actions unless some or all of our joint venture participants agree.

We participate in several joint ventures whose corporate governance structures require at least a majority in interest vote to authorize many basic activities and require a greater voting interest (sometimes up to 100%) to authorize more significant activities. Examples of these more significant activities include, among others, large expenditures or contractual commitments, the construction or acquisition of assets, borrowing money or otherwise raising capital, making distributions, transactions with affiliates of a joint venture participant, litigation and transactions not in the ordinary course of business. Without the concurrence of joint venture participants holding sufficient voting interests, we may be unable to cause our joint ventures to take or not take certain actions, even though taking or preventing those actions may be in the best interests of the particular joint venture or us.

In addition, subject to certain conditions, any joint venture owner may sell, transfer or otherwise modify its ownership interest in a joint venture, whether in a transaction involving third parties or the other joint owners. Any such transaction could result in our partnering with different or additional parties.

As is common in the midstream industry, we may operate one or more of our properties with one or more joint venture partners where we own a minority interest and/or contract with a third party to control operations. These relationships could require us to share operational and other control, such that we may no longer have the flexibility to control completely the development of these properties. If we do not timely meet our financial commitments in such circumstances, our rights to participate may be adversely affected. If a joint venture partner is unable or fails to pay its portion of development costs or if a third-party operator does not operate in accordance with our expectations, our costs of operations could be increased. We could also incur liability as a result of actions taken by a joint venture partner or third-party operator. Disputes between us and the other party may result in litigation or arbitration that would increase our expenses, delay or terminate projects and distract our officers and directors from focusing their time and effort on our business.

Risks Related to our Financial Condition

If we fail to maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. In addition, potential changes in accounting standards might cause us to revise our financial results and disclosure in the future.

Effective internal controls are necessary for us to provide timely and reliable financial reports and effectively prevent fraud. If we cannot provide timely and reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We continue to enhance our internal controls and financial reporting capabilities. These enhancements require a significant commitment of resources, personnel and the development and maintenance of formalized internal reporting procedures to ensure the reliability of our financial reporting. Our efforts to update and maintain our internal controls may not be successful, and we may be unable to maintain adequate controls over our financial processes and reporting now or in the future, including future compliance with the obligations under Section 404 of the Sarbanes-Oxley Act of 2002.

Any failure to maintain effective controls or difficulties encountered in the effective improvement of our internal controls could prevent us from timely and reliably reporting our financial results and may harm our operating results. Ineffective internal controls could also cause investors to lose confidence in our reported financial information. In addition, the Financial Accounting Standards Board or the SEC could enact new accounting standards that might impact how we are required to record revenues, expenses, assets and liabilities. Any significant change in accounting standards or disclosure requirements could have a material effect on our results of operations, financial condition and ability to comply with our debt obligations.

We are exposed to credit risks of our customers, and any material nonpayment or nonperformance by our key customers could adversely affect our cash flow and results of operations.

Many of our customers may experience financial problems that could have a significant effect on their creditworthiness, especially in a depressed commodity price environment. A decline in natural gas, NGL and crude oil prices may adversely affect the business, financial condition, results of operations, creditworthiness, cash flows and prospects of some of our customers. Severe financial problems encountered by our customers could limit our ability to collect amounts owed to us, or to enforce performance of obligations under contractual arrangements. In addition, many of our customers finance their activities through cash flow from operations, the incurrence of debt or the issuance of equity. The combination of reduction of cash flow resulting from a decline in commodity prices, a reduction in borrowing bases under reserve-based credit facilities and the lack of availability of debt or equity financing may result in a significant reduction of our customers’ liquidity and limit their ability to make payment or perform on their obligations to us. Additionally, a decline in the share price of some of our public customers may place them in danger of becoming delisted from a public securities exchange, limiting their access to the public capital markets and further restricting their liquidity. Furthermore, some of our customers may be highly leveraged and subject to their own operating and regulatory risks, which increases the risk that they may default on their obligations to us. To the extent one or more of our key customers is in financial distress or commences bankruptcy proceedings, contracts with these customers may be subject to renegotiation or rejection under applicable provisions of the United States Bankruptcy Code. Furthermore, some bankruptcy courts have found that, in certain cases, oil, gas and water gathering agreements do not create covenants running with the land under governing law and are thus subject to rejection in Chapter 11 proceedings. Whether a particular contract is subject to rejection depends on the wording of the contract, the governing law and the forum where a particular bankruptcy case is filed. Financial problems experienced by our customers could result in the impairment of our long-lived assets, reduction of our operating cash flows and may also reduce or curtail their future use of our products and services, which could reduce our revenues. Any material nonpayment or nonperformance by our key customers or our derivative counterparties could reduce our ability to pay cash dividends to our stockholders.

Inflation and changes in monetary policy may result in increases to the cost of our goods, services and personnel, which in turn cause our capital expenditures and operating costs to rise.

Inflationary pressures have been volatile and have resulted in and may result in additional increases to the costs of our goods, services and personnel, which in turn cause our capital expenditures and operating costs to rise. To the extent elevated inflation levels exist, we may experience further cost increases for our operations, including services, labor and equipment cost increases, and any subsequent increases in benchmark interest rates could have the effect of raising the cost of capital and depressing economic growth, either of which (or the combination thereof) could negatively impact the financial and operating results of our business. Additionally, there is uncertainty about the trade policies of the new Presidential administration, particularly when pertaining to treaties, tariffs and other limitations on international trade. We may experience increases in operating costs as a result of such policies.

Higher oil and natural gas prices may cause the costs of materials and services to continue to rise. We cannot predict any future trends in the rate of inflation and U.S. international trade policies, or any resultant changes in monetary policy, and a significant increase in inflation, to the extent we are unable to recover higher costs through higher prices and revenues, and/or higher interest rates would negatively impact our business, financial condition and results of operations.

Changes in future business conditions could have a negative impact on the demand for our services and could cause recorded long-lived assets to become further impaired, and our financial condition and results of operations could suffer if there is a negative impact on the demand for our services and an additional impairment of long-lived assets.

We evaluate long-lived assets, including related intangibles, for impairment when events or changes in circumstances indicate, in management’s judgment, that the carrying value of such assets may not be recoverable. Asset recoverability is measured by comparing the carrying value of the asset or asset group with its expected future pre-tax undiscounted cash flows. These cash flow estimates require us to make projections and assumptions for many years into the future for pricing, demand, competition, operating cost and other factors. Global oil and natural gas commodity prices, particularly crude oil, remain volatile. Decreases in commodity prices have previously had, and could continue to have, a negative impact on the demand for our services and our market capitalization.

Should energy industry conditions deteriorate, there is a possibility that long-lived assets may be impaired in a future period. Any impairment charges that we may take in the future could be material to our financial statements. We cannot accurately predict the amount and timing of any impairment of long-lived assets.

Our hedging activities may not be effective in reducing the variability of our cash flows and may, in certain circumstances, increase the variability of our cash flows. Moreover, our hedges may not fully protect us against volatility in basis differentials. Finally, the percentage of our expected equity commodity volumes that are hedged decreases substantially over time.

We have entered into derivative transactions related to only a portion of our equity volumes, future commodity purchases and sales, and transportation basis risk. As a result, we will continue to have direct commodity price risk to the unhedged portion. Our actual future volumes may be significantly higher or lower than we estimated at the time we entered into the derivative transactions for that period. If the actual amount is higher than we estimated, we will have greater commodity price risk than we intended. If the actual amount is lower than the amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale of the underlying physical commodity. The percentages of our expected equity volumes that are covered by our hedges decrease over time. To the extent we hedge our commodity price risk, we may forego the benefits we would otherwise experience if commodity prices were to change in our favor. The derivative instruments we utilize for these hedges are based on posted market prices, which may be higher or lower than the actual natural gas, NGL and condensate prices that we realize in our operations. These pricing differentials may be substantial and could materially impact the prices we ultimately realize. Market and economic conditions may adversely affect our hedge counterparties’ ability to meet their obligations. Given volatility in the financial and commodity markets, we may experience defaults by our hedge counterparties. In addition, our exchange traded futures are subject to margin requirements, which creates variability in our cash flows as commodity prices fluctuate.

As a result of these and other factors, our hedging activities may not be as effective as we intend in reducing the variability of our cash flows, and in certain circumstances may actually increase the variability of our cash flows. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”

If we fail to balance our purchases and sales of the commodities we handle, our exposure to commodity price risk will increase.

We may not be successful in balancing our purchases and sales of the commodities we handle. In addition, a producer could fail to deliver promised volumes to us or deliver in excess of contracted volumes, or a purchaser could purchase less than contracted volumes. Any of these actions could cause an imbalance between our purchases and sales. If our purchases and sales are not balanced, we will face increased exposure to commodity price risks and could have increased volatility in our operating income.

The amounts we pay in dividends may vary from anticipated amounts and circumstances may arise that lead to conflicts between using funds to pay anticipated dividends or for other uses in our business.

The determination of the amounts of cash dividends, if any, to be declared and paid will depend upon our financial condition, results of operations, cash flow, the level of our capital expenditures, future business prospects and any other matters that our board of directors, in consultation with management, deems relevant. Many of these matters are affected by factors beyond our control and therefore, the actual amount of cash that is available for dividends to our stockholders may vary from anticipated amounts.

Additionally, as events present themselves or become reasonably foreseeable, our board of directors, which determines our business strategy and our dividends, may decide to address those matters by utilizing capital that may otherwise be used for our dividend. If we issue additional shares of common or preferred stock or we incur debt, the payment of dividends on those additional shares or interest on that debt could increase the risk that we will be unable to maintain or increase our cash dividend levels.

Further, dividends to our common stockholders are not cumulative. Consequently, if dividends on our shares of common stock are not paid with respect to any fiscal quarter, our stockholders will not be entitled to receive that quarter’s payments in the future.

Our future tax liability may be greater than expected if our NOL carryforwards are limited, we do not generate expected deductions, tax authorities successfully challenge certain of our tax positions or from changes in tax laws.

As of December 31, 2025, we have U.S. federal NOL carryforwards of $4.4 billion, which do not expire under current tax laws. Subject to the CAMT discussed below, we expect to be able to utilize these NOL carryforwards and generate deductions to offset all or a portion of our future taxable income. This expectation is based upon assumptions we have made regarding, among other things, our income, capital expenditures and net working capital, and the current expectation that our NOL carryforwards will not become subject to future limitations under Section 382 of the Internal Revenue Code of 1986, as amended (“Section 382”).

While we expect to be able to utilize our NOL carryforwards and generate deductions to offset all or a portion of our future taxable income (subject to the CAMT discussed below), in the event that deductions are not generated as expected, one or more of our tax positions are successfully challenged by the IRS (in a tax audit or otherwise) or our NOL carryforwards are subject to future limitations under Section 382, our future tax liability may be greater than expected.

Changes in tax laws or the interpretation thereof or the imposition of new or increased taxes may adversely affect our financial condition, results of operations and cash flows.

U.S. federal and state legislation is periodically proposed that would, if enacted into law, make significant changes to tax laws and could materially increase our tax obligations, adversely affecting our financial condition, results of operations and cash flows. For example, on August 16, 2022, President Biden signed into law the IRA which includes, among other things, the CAMT. Under the CAMT, a 15% minimum tax will be imposed on certain financial statement income of “applicable corporations.” The IRA treats a corporation as an applicable corporation in any taxable year in which the “average annual adjusted financial statement income” of such corporation for the three taxable year period ending prior to such taxable year exceeds $1 billion.

Based on our current interpretation of the IRA, the CAMT and related guidance, the impact from the OBBBA, and several operational, economic, accounting and regulatory assumptions, we do not anticipate paying CAMT in the near term.

The foregoing analysis is based upon our current interpretation of the provisions contained in the IRA, the CAMT and related guidance. In the future, the U.S. Department of the Treasury and the IRS are expected to release regulations and additional interpretive guidance relating to such legislation, and any significant variance from our current interpretation could result in a change in our analysis of the application of the CAMT to us.

Derivatives legislation and its implementing regulations could have a material adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.

The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), enacted in July 2010, established federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The Dodd-Frank Act required the CFTC and the SEC to promulgate rules and regulations implementing the Dodd-Frank Act, and most of these regulations have been finalized.

In October 2020, the CFTC adopted new rules that will place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. The new rules required general compliance by January 1, 2022 for covered future positions and by January 1, 2023 for covered swaps positions. We have not experienced a material impediment to, and do not expect these regulations to materially impede, our hedging activity at this time.

The CFTC has designated certain interest rate swaps and credit default swaps for mandatory clearing and the associated rules also will require us, in connection with covered derivative activities, to comply with clearing and trade-execution requirements or take steps to qualify for an exemption to such requirements. Although we qualify for the end-user exception from the mandatory clearing requirements for swaps entered to hedge our commercial risks, the application of the mandatory clearing and trade execution requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging. The CFTC and the federal banking regulators have adopted regulations requiring certain counterparties to swaps to post initial and variation margin. However, our current hedging activities would qualify for the non-financial end user exemption from the margin requirements.

The Dodd-Frank Act and any new regulations could increase the cost of derivative contracts or potentially reduce the availability of derivatives to protect against risks we encounter. If we reduce our use of derivatives as a result of the Dodd-Frank Act and regulations implementing the Dodd-Frank Act, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures.

Any of these consequences could have a material adverse effect on us, our financial condition and our results of operations.

The European Union (the “EU”) and other non-U.S. jurisdictions are also implementing regulations with respect to the derivatives market. To the extent we enter into swaps with counterparties in foreign jurisdictions or counterparties with other businesses that subject them to regulation in foreign jurisdictions, we may be impacted by such regulations. The implementing regulations adopted by the EU and by other non-U.S. jurisdictions could have a material adverse effect on us, our financial condition and our results of operations.

Risks Related to the Ownership of our Common Stock

Future sales of our common stock could lower our stock price, and any additional capital raised by us through the sale of equity or convertible securities may dilute your ownership in us.

We or our stockholders may sell shares of common stock in subsequent public offerings and/or private transactions. We may also issue additional shares of common stock or convertible securities. As of December 31, 2025, we had 214,662,156 outstanding shares of common stock. We cannot predict the size of future issuances of our common stock or the effect, if any, that future issuances and sales of shares of our common stock will have on the market price of our common stock. Sales of substantial amounts of our common stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our common stock.

Our amended and restated certificate of incorporation and amended and restated bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our common stock.

Our amended and restated certificate of incorporation authorizes our board of directors to issue preferred stock without stockholder approval. If our board of directors elects to issue preferred stock, it could be more difficult for a third party to acquire us. In addition, some provisions of our amended and restated certificate of incorporation and amended and restated bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our stockholders, including provisions which require:

• a classified board of directors, so that only approximately one-third of our directors are elected each year;
• limitations on the removal of directors; and
• limitations on the ability of our stockholders to call special meetings and establish advance notice provisions for stockholder proposals and nominations for elections to the board of directors to be acted upon at meetings of stockholders.

Delaware law prohibits us from engaging in any business combination with any “interested stockholder,” meaning generally that a stockholder who beneficially owns more than 15% of our stock cannot acquire us for a period of three years from the date this person became an interested stockholder, unless various conditions are met, such as approval of the transaction by our board of directors.

We may issue preferred stock whose terms could adversely affect the voting power or value of our common stock.

Our amended and restated certificate of incorporation authorizes us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designations and powers, preferences, including preferences over our common stock respecting dividends and distributions, rights, qualifications, limitations and restrictions as our board of directors may determine. The terms of one or more classes or series of preferred stock could adversely impact the voting power or value of our common stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of our common stock.

Risks Related to Our Indebtedness

Increases in interest rates, due to associated Federal Reserve policies or otherwise, could adversely affect our cost of capital, which could increase our funding costs and reduce the overall profitability of our business.

We have significant exposure to increases in interest rates. As of December 31, 2025, certain of our and the Partnership’s debt were at variable interest rates. As a result of the variable interest rates on our debt, our results of operations could be adversely affected by increases in interest rates, due to associated Federal Reserve policies or otherwise. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”

Additionally, like all equity investments, an investment in our equity securities is subject to certain risks. In exchange for accepting these risks, investors may expect to receive a higher rate of return than would otherwise be obtainable from lower-risk investments. Accordingly, as interest rates rise, the ability of investors to obtain higher risk-adjusted rates of return by purchasing government-backed debt securities may cause a corresponding decline in demand for riskier investments generally, including yield-based equity investments. Reduced demand for our common stock resulting from investors seeking other more favorable investment opportunities may cause the trading price of our common stock to decline.

We have a substantial amount of indebtedness which may adversely affect our financial position and we may still be able to incur substantially more debt, which could collectively increase the risks associated with compliance with our financial covenants.

Our substantial level of indebtedness increases the possibility that we may be unable to generate cash sufficient to pay, when due, the principal of, interest on or other amounts due in respect of indebtedness. This substantial indebtedness, combined with lease and other financial obligations and contractual commitments, could have other important consequences to us, including the following:

• our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;
• satisfying our obligations with respect to indebtedness may be more difficult and any failure to comply with the obligations of any debt instruments could result in an event of default under the agreements governing such indebtedness;
• we will need a portion of cash flow to make interest payments on debt, reducing the funds that would otherwise be available for operations and future business opportunities;
• our debt level may influence how counterparties view our creditworthiness, which could limit our ability to enter into commercial transactions at favorable rates or require us to post additional collateral in commercial transactions;
• our debt level will make us more vulnerable to competitive pressures or a downturn in our business or the economy generally; and
• our debt level may limit flexibility in planning for, or responding to, changing business and economic conditions.

Our long-term unsecured debt is currently rated by Fitch, Moody’s and S&P. As of December 31, 2025, Targa’s senior unsecured debt was rated “BBB” by Fitch, “Baa2” by Moody’s and “BBB” by S&P. Any future downgrades in our credit ratings could negatively impact our cost and terms of raising capital, and a downgrade could also adversely affect our ability to effectively execute aspects of our strategy and to access capital in the public markets.

Our International Swaps and Derivatives Association agreements (“ISDAs”) contain credit-risk related contingent features. As of December 31, 2025, we have outstanding net derivative positions that contain credit-risk related contingent features that are in a net liability position of $104.1 million. Our derivative positions are unsecured. If our credit rating was to be downgraded one notch below investment grade by both Moody’s and S&P, as defined in our ISDAs, we estimate that as of December 31, 2025, we would not be required to post collateral to any counterparties per the terms of our ISDAs.

Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing or delaying business activities, investments or capital expenditures, acquisitions, selling assets, restructuring or refinancing debt, or seeking additional equity capital, and such results may adversely affect our ability to make cash dividends. We may not be able to affect any of these actions on satisfactory terms, or at all.

We may be able to incur substantial additional indebtedness in the future. The TRGP Revolver provides an available commitment of $3.5 billion, with a requirement to maintain a minimum available borrowing capacity equal to the aggregate amount outstanding under the Commercial Paper Program, and allows us to request increases in commitments up to an additional $500.0 million. Although our debt agreements contain restrictions on the incurrence of additional indebtedness, these restrictions are subject to a number of significant qualifications and exceptions, and any indebtedness incurred in compliance with these restrictions could be substantial. If we incur additional debt, this could increase the risks associated with compliance with our financial covenants.

The terms of our debt agreements may restrict our current and future operations, particularly our ability to respond to changes in business or to take certain actions, including to pay dividends to our stockholders.

The agreements governing our outstanding indebtedness contain, and any future indebtedness we incur will likely contain, a number of restrictive covenants that impose significant operating and financial restrictions, including restrictions on our ability to engage in acts that may be in our best long-term interests, such as:

• incur or guarantee additional indebtedness;
• pay dividends on our equity securities or to our equity holders or redeem, repurchase or retire our equity securities or subordinated indebtedness during an event of default;
• sell or transfer substantially all of our assets or certain accounts receivables of Targa Receivables LLC;
• engage in affiliate transactions;
• consolidate or merge;
• incur liens; and
• change business activities conducted by us.

A downgrade in our credit rating could also result in our indebtedness agreements imposing additional restrictive covenants that may place further operating and financial limitations on our business. In addition, certain of our debt agreements require us to satisfy and maintain specified financial ratios and other financial condition tests. Our ability to meet those financial ratios and tests can be affected by events beyond our control, and we cannot assure you that we will meet those ratios and tests.

A breach of any of these covenants could result in an event of default under our debt agreements. Upon the occurrence of such an event of default, all amounts outstanding under the applicable debt agreements could be declared to be immediately due and payable and all applicable commitments to extend further credit could be terminated. If we are unable to repay the accelerated debt under the Securitization Facility, the lenders under the Securitization Facility could proceed against the collateral granted to them to secure the indebtedness. We have pledged the accounts receivables of Targa Receivables LLC under the Securitization Facility. If the indebtedness under our debt agreements is accelerated, we cannot assure you that we will have sufficient assets to repay the indebtedness. The operating and financial restrictions and covenants in these debt agreements and any future financing agreements may adversely affect our ability to finance future operations or capital needs or to engage in other business activities.

Risks Related to Regulatory Matters

Our and our customers’ operations are subject to a number of risks related to the potential threat of climate change, including evolving regulations for methane and other GHG emissions from the oil and gas sector, that could result in increased operating costs, limit the areas in which oil and natural gas production may occur, reduce demand for the products and services we provide, and reduce our or our customers’ ability to access capital.

Numerous proposals have been made and could continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHGs. As a result, our operations as well as the operations of our oil and natural gas exploration and production customers, are subject to a series of regulatory, political, litigation, and financial risks associated with the production and processing of fossil fuels and emission of GHGs.

In the United States, no comprehensive climate change legislation has been implemented at the federal level. Notwithstanding the EPA’s recent proposal to revoke the “Endangerment Finding,” which supports the majority of EPA’s GHG-related regulations, the EPA under previous presidential administrations adopted a number of rules that included, among other things, efforts concerning the reduction, monitoring and reporting of GHG emissions. In August 2022, the IRA was signed into law, which amended the CAA to impose a first-time fee on the emission of excess methane above statutory methane emissions thresholds from sources required to report their GHG emissions to the EPA, including those sources in the onshore petroleum and natural gas production and gathering and boosting source categories. In November 2024, the EPA issued a final rule implementing the methane emissions fee, although in February 2025, Congress repealed the rule under the Congressional Review Act. Additionally, in the OBBBA, Congress delayed the implementation of the methane emission fee until 2034. We cannot predict if the current Presidential administration and/or Congress may take further actions with respect to the IRA or methane emissions fee, the future implementation of which is uncertain at this time. However, compliance with this and other air pollution control and permitting requirements has the potential to increase our and our customers’ operating costs and delay development of our projects, which could adversely affect our business and results of operations.

In recent years, there has been considerable focus on the regulation of methane emissions from the oil and gas sector. In response to President Biden’s executive order calling on the EPA to revisit federal regulations regarding methane, the EPA finalized more stringent methane rules for new, modified, and reconstructed facilities, known as OOOOb, as well as standards for existing sources known as OOOOc, in December 2023. However, in March 2025, the EPA announced plans to reconsider OOOOb and OOOOc, in line with the current Presidential administration’s deregulatory agenda. Additionally, in November 2025, the EPA finalized an interim rule extending the compliance deadlines for certain provisions provided in OOOOb and OOOOc. Litigation challenging the EPA’s final interim rule extending such compliance deadlines for new and existing oil and gas sources remains pending.

Various states and groups of states have also adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on areas of coverage similar to what the federal government has or may consider, including GHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions.

Governmental, scientific, and public concern from sources across the world over the potential threat of climate change arising from GHG emissions has resulted in increasing political risks in the United States. For instance, the prior Presidential administration issued several executive orders focused on addressing climate change, including items that may impact costs to produce, or demand for, oil and gas. The use of executive orders in the United States to advance political objectives of Presidential administrations increases regulatory uncertainty for us. Other administrations may issue executive orders that are more favorable to the development and consumption of hydrocarbons. Regulations may be focused on addressing climate change and may impact the costs to produce, or demand for, oil and gas. In April 2024, the BLM finalized a rule that would limit flaring from well sites on federal lands, as well as require an operator to submit a waste minimization plan or a self-certification statement committing the operator to capturing 100% of the gas produced from a well and pay royalties on lost gas as part of the permit application process. This rule is currently subject to litigation and its implementation has been halted in North Dakota, Texas, Utah, Montana and Wyoming. Additionally, the BLM has halted enforcement of various regulatory compliance deadlines associated with the rule until the end of 2026. Any regulatory changes that restrict or require modifications to our or our suppliers’ existing operations or future expansions plans could reduce the demand for the products and services we provide, increase our operating costs and may have a negative impact on our financial condition.

Litigation risks exist from certain cities, local governments, and other plaintiffs who may bring suit against large oil and natural gas companies in state or federal court, alleging, among other things, that such companies created public nuisances by producing fuels that contributed to global warming effects, such as rising sea levels, and therefore are responsible for roadway and infrastructure damages as a result, or alleging that the companies have been aware of the adverse effects of climate change for some time but defrauded their investors or consumers by failing to adequately disclose those impacts. Should we be targeted by such litigation, involvement in such a case could have adverse financial and reputational impacts and an unfavorable ruling could significantly impact our operations and adversely impact our financial condition.

Additionally, from time to time, certain stockholders and bondholders currently invested in fossil fuel energy companies but concerned about the potential effects of climate change may elect in the future to shift some or all of their investments into non-fossil fuel energy related sectors. Institutional investors who provide financing to fossil fuel energy companies have been attentive to sustainability lending, requesting additional action relating to the management of GHG emissions, and some of them may elect not to provide funding for fossil fuel energy companies, although this trend has waned in recent times. Any material reduction in the capital available to the fossil fuel industry could make it more difficult to secure funding for exploration, development, production, transportation, and processing activities, which could impact our and our suppliers’ and customers’ businesses and operations. In October 2023, the State of California adopted several laws that require disclosure of various climate risks, targets, and metrics. However, these laws are currently subject to litigation. To the extent implemented, laws such as these or similar laws may result in increased legal, accounting and financial compliance costs for us and our suppliers and customers to comply, including the implementation of significant additional internal controls processes and procedures regarding matters that have not been subject to such controls in the past, and impose increased oversight obligations on our management and board of directors. We may also face increased litigation risks related to disclosures made pursuant to these requirements.

Increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods, rising sea levels and other extreme weather events, as well as chronic shifts in temperature and precipitation patterns. For further discussion, please see Weather events may damage our assets, limit our ability or increase the costs to operate our business and adversely impact our customers on whom we rely on for throughput as well as third party vendors from whom we receive goods, which developments could cause us to incur significant costs and adversely affect our business, results of operations and financial condition.

Stakeholder and market attention to sustainability matters may impact the disclosure obligations of our business.

Companies across industries face scrutiny from a variety of stakeholders related to their sustainability practices. Societal expectations regarding sustainability initiatives and disclosures and potential consumer use of substitutes to energy commodities may result in increased costs, reduced demand for our customers’ products and our services, reduced profits, increased investigations and litigation, and negative impacts on our stock price and access to capital markets. Attention to climate change, for example, may result in demand shifts for our or our customers’ hydrocarbon products and additional governmental investigations and private litigation against us or those customers.

As part of our ongoing effort to enhance our sustainability practices, our Board of Directors has established a Sustainability Committee. Committee members oversee management’s implementation of sustainability policies and procedures in coordination with other committees of the Board as appropriate. We also have a vice president of sustainability, who reports directly to our CEO and also regularly provides reports on relevant sustainability matters to our Board of Directors. We published our 2024 Sustainability Report, which provides updates on our performance related to certain sustainability topics and certain sustainability goals, such as reductions in methane intensity in line with the ONE Future goals. While we may elect to seek out various additional voluntary sustainability targets now or in the future, such targets are often aspirational. Moreover, despite our governance oversight in place, many of our sustainability targets and goals are ambitious, and we may not be able to adequately identify sustainability-related risks and opportunities and, further, may not be able to meet our sustainability targets and goals in the manner or on such a timeline as initially contemplated, or at all, including as a result of unforeseen costs or technical difficulties associated with achieving such results. Moreover, even if we are to achieve our targets and goals or complete other sustainability initiatives, there is no guarantee that doing so will have the desired effect. Sustainability-related actions or statements that we may make or take are sometimes based on expectations, assumptions, or third-party information that we currently believe to be reasonable, but which may subsequently be determined to be erroneous or be subject to misinterpretation. For example, methodologies regarding the monitoring and calculation of climate risks and GHG emissions are evolving, and it is possible that stakeholders, either currently or at some point in future, may not agree with our approach. Moreover, to the extent we elected to pursue such targets and were able to achieve the desired target levels, such achievement may have been accomplished as a result of entering into various contractual arrangements, including the purchase of various credits or offsets that may be deemed to mitigate our sustainability impact instead of actual changes in our sustainability performance. However, we cannot guarantee that there will be sufficient offsets for purchase or that, notwithstanding our reliance on any reputable third party registries, that the offsets we do purchase will successfully achieve the emissions reductions they represent. Notwithstanding our election to pursue aspirational targets now or in the future, we may receive pressure from investors, lenders or other groups to adopt more aggressive climate or other sustainability-related goals, but we cannot guarantee that we will be able to pursue or implement such goals because of potential costs or technical or operational obstacles. If we fail to, or are perceived to fail to, comply with or advance certain sustainability initiatives (including the timeline and manner in which we complete such initiatives), we may be subject to various adverse impacts, including reputational damage and potential stakeholder engagement and/or litigation, even if such initiatives are currently voluntary.

In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings and proxy voting recommendation processes for evaluating companies on their approach to sustainability matters. Additionally, we and other companies in our industry publish sustainability reports that are made available to investors. Such ratings, proxy advisory services, and reports are used by some investors to inform their investment and voting decisions. Certain lenders may decide not to provide funding to us or our customers’ companies based on sustainability concerns, which could adversely affect our financial condition and access to capital for potential growth projects. Investors, lenders, and other stakeholders that focus on issues related to environmental justice and natural capital may result in increased scrutiny of our processes on such issues.

Certain public statements with respect to sustainability matters, such as emissions reduction goals, other environmental targets, or other commitments addressing certain social issues are becoming increasingly subject to heightened scrutiny from public and governmental authorities, as well as other parties, related to the risk of potential “greenwashing,” i.e., misleading information or false claims overstating potential sustainability benefits. For example, the SEC has taken enforcement action against companies for sustainability-related misconduct, including alleged greenwashing. Regulators, such as the SEC and various state agencies, as well as non-governmental organizations and other private actors have also filed lawsuits under various securities and consumer protection laws alleging that certain sustainability statements, goals, or standards were misleading, false, or otherwise deceptive. As a result, we may face increased litigation risks from private parties and governmental authorities related to our sustainability efforts. In addition, any alleged claims of greenwashing against us or others in our industry may lead to further negative sentiment and diversion of investments. Many of our customers and suppliers may be subject to similar expectations and challenges, which may augment or create additional risks, including risks that may not be known to us.

We could incur significant costs in complying with more stringent occupational safety and health requirements.

We are subject to stringent federal and state laws and regulations, including the federal Occupational Safety and Health Act and comparable state statutes, whose purpose is to protect the health and safety of workers, both generally and within the pipeline industry. In addition, the federal Occupational Safety and Health Administration’s (“OSHA”) hazard communication standard, the EPA community right-to-know regulations under Title III of the Federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We and the entities in which we own an interest are subject to OSHA Process Safety Management regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. Failure to comply with these laws and regulations or any newly adopted laws or regulations may result in assessment of sanctions including administrative, civil and criminal penalties, the imposition of investigatory, remedial and corrective action obligations or the incurrence of capital expenditures, any of which could have a material adverse effect on our business, financial condition and results of operations.

State laws and regulations limiting hydraulic fracturing activities could result in restrictions, delays or cancellations in drilling and completing new oil and natural gas wells by our customers, which could adversely impact our revenues by decreasing the volumes of natural gas, NGLs or crude oil through our facilities and reducing the utilization of our assets.

While we do not conduct hydraulic fracturing, many of our oil and gas exploration and production customers do perform such activities. Hydraulic fracturing is typically regulated by state oil and gas commissions and many states have adopted legal requirements that have imposed new or more stringent permitting, public disclosure or well construction requirements on hydraulic fracturing activities, including in states where we or our customers conduct operations. States could further elect to suspend or prohibit hydraulic fracturing activities in the future. While governments may also seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular, non-governmental organizations may also seek to restrict hydraulic fracturing through ballot initiatives, such as those that have been pursued in Colorado. New or more stringent laws, regulations or regulatory or ballot initiatives relating to the hydraulic fracturing process could lead to our customers reducing crude oil and natural gas drilling activities using hydraulic fracturing techniques, while increased public opposition to activities using such techniques may result in operational delays, restrictions, cessations, or increased litigation. Any one or more of such developments could reduce demand for our gathering, processing and fractionation services and have a material adverse effect on our business, financial condition and results of operations.

Our operations are subject to environmental laws and regulations and a failure to comply or an accidental release into the environment may cause us to incur significant costs and liabilities.

Our operations are subject to numerous federal, tribal, state and local environmental laws and regulations governing occupational health and safety, the discharge of pollutants into the environment or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations that are applicable to our operations enforced by various governmental authorities, such as the EPA and BLM, and analogous state agencies. For more information regarding the regulation of our operations, see “Item 1. Business—Regulation of Operations, Environmental and Occupational Health and Safety Matters.”

The risk of incurring environmental costs and liabilities in connection with our operations is significant due to our handling of natural gas, NGLs, crude oil and other petroleum products, because of air emissions and product-related discharges arising out of our operations, and as a result of historical industry operations and waste disposal practices. For example, an accidental release from one of our facilities could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury, natural resource and property damages and fines or penalties for related violations of environmental laws or regulations.

Moreover, stricter laws, regulations or enforcement policies could significantly increase our operational or compliance costs and the cost of any remediation that may become necessary. For example, in March 2023, the EPA issued its Good Neighbor Plan rule, which imposes emissions-related requirements on fossil fuel-fired power plants and other industrial users in 22 states, including Texas and Louisiana, which could reduce demand for our products and accelerate the transition away from oil and gas to other sources of energy. The Good Neighbor Plan was to have become effective in 2026, but in June 2024, was stayed by the U.S. Supreme Court. However, following the change in Presidential administrations, the EPA has announced its intention to revisit the Good Neighbor Plan. We cannot predict what actions the current Presidential administration will take with respect to the Good Neighbor Plan and any such actions and their timing remain uncertain.

There continues to be uncertainty on the federal government’s applicable jurisdictional reach under the Clean Water Act over waters of the United States, including wetlands, as the EPA and the U.S. Army Corps of Engineers (“Corps”) have pursued multiple rulemakings since 2015 in an attempt to determine the scope of such reach. Following legal challenges, the implementation of the most recent September 2023 rule currently varies by state. However, in November 2025, the EPA and the Corps proposed a rule to further update and narrow the September 2023 definition of WOTUS, guided by the Sackett v. EPA decision. To the extent any judicial ruling or administrative rulemaking or other action further changes the scope of the Clean Water Act’s jurisdiction in areas where we or our customers conduct operations, we could face increased delays, restrictions or cessation of the development of projects, longer permitting timelines, or increased compliance expenditures or mitigation costs for our and our oil and natural gas customers’ operations, which may reduce the rate of production of natural gas or crude oil from operators with whom we have a business relationship and, in turn, have a material adverse effect on our business, results of operations and cash flows.

Separately, Nationwide Permit (“NWP”) 12, which is available under the Clean Water Act for certain oil and gas activities, has been subject to legal challenges and regulatory revision in recent years. The Corps has been engaged in a formal review of NWP 12 as a result of these actions. However, while this review is ongoing, the Corps has resumed permitting decisions. Although we cannot predict what actions the new Presidential administration may take to revise NWP 12, any disruption in our ability to obtain coverage under NWP 12 or other general permits may result in increased costs and project delays if we are forced to seek individual permits from the Corps. This in turn could have an adverse effect on our business, financial condition and results of operation.

A change in the jurisdictional characterization of some of our assets by federal, state, tribal or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our assets, which may (i) cause our revenues to decline and operating expenses to increase or (ii) delay or increase the cost of expansion projects.

With the exception of the Driver Residue Pipeline, TPL SouthTex Transmission Company LP, Buffalo Run Pipeline LLC, Bull Run Pipeline LLC, and Targa SouthTex Mustang Transmission Ltd., which are each subject to FERC regulation under the NGPA or limited FERC regulation under the NGA, and Forza Pipeline LLC which will be subject to FERC jurisdiction under the NGA, our natural gas pipeline operations are generally exempt from FERC regulation, but FERC regulation still affects our non-FERC jurisdictional businesses and the markets for products derived from these businesses, including certain FERC reporting and posting requirements in a given year. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of substantial, ongoing litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress.

Targa NGL, Targa Gulf Coast, Grand Prix Pipeline, Targa San Andres Crude, and Targa Badlands have pipelines that are considered common carrier pipelines subject to regulation by FERC under the ICA. The ICA requires that we maintain tariffs on file with FERC for each of these common carrier pipelines that have not been granted a waiver. With respect to pipelines that have been granted a waiver of the ICA and related regulations by FERC, should a particular pipeline’s circumstances change, FERC could, either at the request of other entities or on its own initiative, assert that such pipeline no longer qualifies for a waiver. In the event that FERC were to determine that one or more of these pipelines no longer qualified for a waiver, we would likely be required to file a tariff with FERC for the applicable pipeline(s), provide a cost justification for the transportation charge, and provide regulated services to all potential shippers without undue discrimination. Such a change in the jurisdictional status of transportation on these pipelines could adversely affect our results of operations.

The classification of some of our gathering facilities, transportation pipelines, and purchase and sale transactions as FERC-jurisdictional or non-jurisdictional may be subject to change based on future determinations by FERC, the courts or Congress, in which case, our operating costs could increase and we could be subject to enforcement actions under the EP Act of 2005.

Various federal agencies within the U.S. Department of the Interior, particularly the BLM, Office of Natural Resources Revenue (formerly the Minerals Management Service) and the Bureau of Indian Affairs, along with the Three Affiliated Tribes, promulgate and enforce regulations pertaining to operations on the Fort Berthold Indian Reservation, on which we operate a significant portion of our Badlands gathering and processing assets. The Three Affiliated Tribes is a sovereign nation having the right to enforce certain laws and regulations independent from federal, state and local statutes and regulations. These tribal laws and regulations include various taxes, fees and other conditions that apply to lessees, operators and contractors conducting operations on Native American tribal lands. Lessees and operators conducting operations on tribal lands can generally be subject to the Native American tribal court system. One or more of these factors may increase our costs of doing business on the Fort Berthold Indian Reservation and may have an adverse impact on our ability to effectively transport products within the Fort Berthold Indian Reservation or to conduct our operations on such lands.

Other FERC regulations may indirectly impact our businesses and the markets for products derived from these businesses. FERC’s policies and practices across the range of its natural gas and liquids regulatory activities, including, for example, its policies on open access transportation, gas quality, ratemaking, capacity release and market center promotion, may indirectly affect the natural gas and liquids markets. In recent years, FERC has pursued pro-competitive policies in its regulation of interstate natural gas and liquids pipelines. However, we cannot assure you that FERC will continue this approach as it considers matters such as pipeline rates and rules and policies that may affect rights of access to transportation capacity. For more information regarding the regulation of our operations, see “Item 1. Business—Regulation of Operations.”

Should we fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.

Under the EP Act of 2005, FERC has civil penalty authority under the NGA and NGPA to impose penalties for violations of the NGA or NGPA up to a maximum amount that is adjusted annually for inflation, which for 2026 equals approximately $1.6 million (which amount may be updated for inflation in 2026) per violation per day, as well as authority to order disgorgement of profits associated with any violation. While our systems other than the Driver Residue Pipeline, TPL SouthTex Transmission Company LP, TPL SouthTex Pipeline Company LLC, Buffalo Run Pipeline LLC, Bull Run Pipeline LLC, Targa SouthTex Mustang Transmission Ltd., and Forza Pipeline LLC have not been regulated by FERC under the NGA or NGPA, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional facilities to FERC annual reporting and daily scheduled flow and capacity posting requirements. In addition, FERC has civil penalty authority under the ICA to impose penalties for violations under the ICA up to a maximum amount that is adjusted annually for inflation, which for 2026 was up to approximately $16,590 (which amount may be updated for inflation in 2026) per violation per day, and failure to comply with the ICA and regulations implementing the ICA could subject us to civil penalty liability. For more information regarding regulation of our operations, see “Item 1. Business—Regulation of Operations.” Additional rules and legislation pertaining to those and other matters may be considered or adopted by FERC from time to time.

We are subject to cybersecurity and data privacy laws and regulations, and we may become subject to litigation and directives relating to our processing of personal information.

The jurisdictions in which we operate (including the United States) have laws governing how we must respond to a cyber incident that results in the unauthorized access, disclosure, or loss of personal information. Additionally, laws and regulations governing data privacy and unauthorized disclosure of personal information and imposing certain cybersecurity-related requirements pose increasingly complex compliance challenges. For example, Texas has enacted data privacy legislation. Some or all of such legislation will elevate our compliance costs over time. Our business involves collection, use, and other processing of personal information and personally identifiable information of our employees, investors, contractors, suppliers, and customer contacts. As legislation continues to develop and cyber incidents continue to evolve, we will likely be required to expend significant resources to continue to modify or enhance our protective measures to comply with such legislation and to detect, investigate and remediate vulnerabilities to cyber incidents. Any failure by us, or a company we acquire, to comply with such laws and regulations could result in reputational harm, loss of goodwill, penalties, liabilities, remediation costs, or mandated changes in our business practices. Each has the potential to materially impact our financial condition.

Description of Processes for Assessing, Identifying, and Managing Cybersecurity Risks

Cybersecurity risk is an area of focus for Targa, particularly as our operations become increasingly dependent on digital technologies. Across the world, cybersecurity incidents are occurring more frequently, use increasingly sophisticated methods and could pose serious risks to the Company’s data integrity, reputation, operations and revenue. The Company has a cybersecurity program, which uses technology and processes to help mitigate cybersecurity risks, with our Security Operations team working to monitor, assess, identify, and respond to potential cybersecurity incidents that threaten the Company.

We utilize the National Institute of Standards and Technology Cybersecurity Framework as well as supplemental guidance for information and operational technologies to assess current risks against deployed current countermeasures. We seek to follow federal and state statutory and regulatory guidance and have adopted internal policies and standards that we believe are in alignment with these requirements. Our cybersecurity program covers Targa’s general corporate information and operational technology systems, which support our various lines of business.

Our cybersecurity program also follows defense in depth principles, which aim to implement various layered access control, detection, prevention, and response measures. Targa has formal disaster recovery and business continuity plans, as well as a Cyber Incident Response Plan, which is periodically tested using tabletop exercises.

We regularly engage with independent third parties to assess our vulnerabilities and help us mitigate cybersecurity-related risks. Targa’s security posture is also tested by internal Targa personnel and independent third parties to gauge its effectiveness.

Our cybersecurity program includes a formally documented process for oversight of cybersecurity risks associated with our third-party service providers. This process begins prior to engagement. Third-party service providers are evaluated using independent assessment tools to gauge their security posture.

The above cybersecurity risk management processes are integrated into our overall risk management program. While we seek to continually evaluate cybersecurity risks based upon emerging threats as a part of the Company’s risk management processes, overall cybersecurity risks to the Company are also evaluated annually by independent consultants and learnings are incorporated into the overall Company risk matrices.

Our Code of Conduct communicates our expectation that employees and contractors will maintain the security of our information technology systems. All employees are presented with Code of Conduct training annually. Each employee’s and contractor’s ability to recognize and report cyber threats is an important component of our cybersecurity program. We focus on increasing employee awareness of phishing attempts and train employees to be aware of cyber risks.

We recognize that cybersecurity risks continue to emerge and evolve. Assessment and enhancement of our security posture in predicting and responding to the changing threat landscape are core goals of our cybersecurity program. Targa maintains relationships with various cybersecurity industry subject matter experts, governmental agencies, law enforcement research and benchmarking organizations, and industry peers as part of our effort to improve our program based on threat information and available countermeasures.

We continue to make investments in new technologies to protect our facilities, users, and stakeholders, and to protect the personally identifiable information we maintain.

Board of Directors’ Oversight of Risks from Cybersecurity Risks

Cybersecurity risks are overseen at the board level through the Audit Committee. As part of this oversight, the Audit Committee, with several key members of management, meets quarterly to discuss ongoing initiatives and seek to ensure coordination between enterprise stakeholders. At these meetings, our Vice President of Security Operations and Senior Vice President of Technology, who oversee the Company’s cybersecurity program, review with our Audit Committee current and emerging cybersecurity-related threats as well as key performance indicators for cybersecurity process maturity, operational performance, and enterprise performance in countering these threats. Our Vice President of Security Operations and Senior Vice President of Technology also annually review our Company's cybersecurity program with our full board. Based on the information provided through these various processes, our board evaluates the risks facing us and provides guidance as to the appropriate risk management strategy.

Management’s Role in Assessing and Managing Cybersecurity Risks

The Vice President of Security Operations and Senior Vice President of Technology are primarily responsible for assessing and managing Targa’s material risks from cybersecurity threats, and work to monitor the effectiveness of our cybersecurity detection and response processes in countering current threats and to provide updates to our executive team. Our Vice President of Security Operations has more than 25 years of experience working in the field of cybersecurity, including numerous years directing enterprise-level cybersecurity programs.

No Previous Material Cybersecurity Incidents

As of the date of this report, though the Company and our service providers have experienced certain cybersecurity incidents, we are not aware of any previous cybersecurity incidents that have materially affected or are reasonably likely to materially affect the Company. We acknowledge that cybersecurity threats are continually evolving, and the possibility of future cybersecurity incidents remains. Despite the security and risk management measures that we have implemented and any additional measures we may implement or adopt in the future, our facilities and systems, and those of our third-party service providers, vendors, suppliers, customers and other business partners, have been and are vulnerable to security breaches, computer viruses, lost or misplaced data, programming errors, scams, burglary, human errors, acts of vandalism, misdirected wire transfers, or other malicious or criminal activities. A successful attack on our information or operational technology systems could have material consequences to the Company. While we devote resources to our security measures to protect our systems and information, these measures cannot provide absolute security. See “Item 1A. Risk Factors” for additional information about the risks to our business associated with a breach or compromise to our information technology systems.

A description of our properties is contained in “Item 1. Business” in this Annual Report.

Our principal executive offices are located at 811 Louisiana Street, Suite 2100, Houston, Texas 77002 and our telephone number is 713-584-1000.

The information required for this item is provided in “Note 17 – Contingencies,” under the heading “Legal Proceedings” included in the Notes to Consolidated Financial Statements included under Part II, Item 8 of this Annual Report, which is incorporated by reference into this item.

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and the notes included in Part IV of this Annual Report. Additional sections in this Annual Report should be helpful to the reading of our discussion and analysis, including the following: (i) a description of our business strategy found in “Item 1. Business–Overview”; (ii) a description of recent developments, found in “Item 1. Business–Recent Developments”; and (iii) a description of risk factors affecting us and our business, found in “Item 1A. Risk Factors.” Discussions of 2023 items and year-to-year comparisons between 2024 and 2023 that are not included in this Annual Report can be found in Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our Annual Report on Form 10-K for the year ended December 31, 2024.

General Trends and Outlook

We expect our results of operations to continue to be affected by the following key trends: commodity prices, volume throughput and demand for our products and services, contract terms and mix, the impact of our hedging activities, the cost to operate and support assets, volatile capital markets and competition. These expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about or interpretations of available information prove to be incorrect, our actual results may vary materially from our expected results.

Commodity Prices

There has been, and we believe there will continue to be, volatility in commodity prices and in the relationships among natural gas, NGL and crude oil prices. The volatility and uncertainty of natural gas, NGL and crude oil prices impact drilling, completion and other investment decisions by producers and ultimately supply to our systems. See “Item 1A. Risk Factors – Our cash flow is affected by supply and demand for natural gas, NGL products, and crude oil, and by natural gas, NGL, crude oil and condensate prices, and decreases in supply, demand or these prices could adversely affect our results of operations and financial condition.”

Our operating income generally improves in an environment of higher natural gas, NGL and condensate prices. Our processing profitability is largely dependent upon pricing and the supply of and market demand for natural gas, NGLs and condensate, both of which are beyond our control. In a declining commodity price environment, without taking into account our hedges, we will realize a reduction in cash flows under our percent-of-proceeds contracts proportionate to average price declines. While we have a significant level of margin that we derive from fee-based arrangements across our operations and particularly for our assets in the Downstream Business, our contract mix, along with our commodity hedging program, serves to mitigate the impact of commodity price movements on our cash flows. For additional information regarding our hedging activities, see “Item 7A. Quantitative and Qualitative Disclosures about Market Risk — Commodity Price Risk.”

The following table presents selected average annual and quarterly industry index prices for natural gas, selected NGL products and crude oil for the periods presented:

(1) Natural gas prices are based on average first of month prices from Henry Hub Inside FERC commercial index prices.

(2) “Illustrative Targa NGL” pricing is weighted using average quarterly prices from Mont Belvieu Non-TET monthly commercial index and represents the following composition for the periods noted:

2025: 44% ethane, 32% propane, 11% normal butane, 4% isobutane and 9% natural gasoline

2024: 44% ethane, 32% propane, 11% normal butane, 4% isobutane and 9% natural gasoline

(3) Crude oil prices are based on average quarterly prices of West Texas Intermediate crude oil as measured on the NYMEX.

Volumes and Demand for our Services

Fluctuations in energy prices can greatly affect production rates and investments by third parties in the development and production of new oil and natural gas reserves. Our operations are affected by the level of crude, natural gas and NGL prices, the relationship among these prices and related activity levels from our customers. In our gathering and processing operations, plant inlet volumes, crude oil volumes and capacity utilization rates generally are driven by wellhead production and our competitive and contractual position on a regional basis and more broadly by the impact of prices for crude oil, natural gas and NGLs on exploration and production activity in the areas of our operations. Drilling and production activity generally decreases as crude oil and natural gas prices decrease below commercially acceptable levels. Producers generally focus their drilling activity on certain basins depending on commodity price fundamentals. Our asset systems are predominantly located in some of the most economic basins in the United States.

The factors that impact the gathering and processing volumes also impact the total volumes that flow to our Downstream Business. Accordingly, increased producer activity will drive demand for our midstream services and may result in incremental growth capital expenditures. Demand for our transportation, fractionation and other fee-based services is largely correlated with producer activity levels. Demand for our international export, storage and terminaling services has remained relatively constant, as demand for these services is based on a number of domestic and international factors.

Contract Terms, Contract Mix and the Impact of Commodity Prices

Across our operations and particularly in our Downstream Business, we benefit from long-term fee-based arrangements for our services. Our Gathering and Processing segment contract mix also has components of fee-based margin, such as fee floors and other fee-based services which mitigate against low commodity prices. The significant level of margin we derive from fee-based arrangements combined with our hedging arrangements helps to mitigate our exposure to commodity price movements. Volatility in commodity prices can have a significant impact on our profitability, especially those percent-of-proceeds contracts that create direct exposure to changes in energy prices by paying us for gathering and processing services with a portion of proceeds from the commodities handled (“equity volumes”).

Contract terms in the Gathering and Processing segment are based upon a variety of factors, including natural gas and crude quality, geographic location, competitive dynamics and the pricing environment at the time the contract is executed, and customer requirements. Our gathering and processing contract mix and, accordingly, our exposure to crude, natural gas and NGL prices may change as a result of producer preferences, competition and changes in production as wells decline at different rates or are added, our expansion into regions where different types of contracts are more common and other market factors.

The contract terms and contract mix of our Downstream Business can also have a significant impact on our results of operations. Transportation and fractionation services are supported by fee-based contracts whose rates and terms are driven by NGL supply and transportation and fractionation capacity. Export services are supported by fee-based contracts whose rates and terms are driven by global LPG supply and demand fundamentals. The Logistics and Transportation segment includes predominantly fee-based contracts.

Impact of Our Commodity Price Hedging Activities

We have hedged the commodity price risk associated with a portion of our expected natural gas, NGL and condensate equity volumes, future commodity purchases and sales, and transportation basis risk by entering into financially settled derivative transactions. These transactions include swaps, futures, and purchased puts (or floors) and calls (or caps) to hedge additional expected equity commodity volumes without creating volumetric risk. We intend to continue managing our exposure to commodity prices in the future by entering into derivative transactions. We actively manage the Downstream Business product inventory and other working capital levels to reduce exposure to changing prices. For additional information regarding our hedging activities, see “Item 7A. Quantitative and Qualitative Disclosures About Market Risk–Commodity Price Risk.”

Operating Expenses

Variable costs such as service and repairs can impact our results. Continued expansion of existing assets will also give rise to additional operating expenses, which will affect our results. The employees supporting our operations are employees of Targa Resources LLC, a Delaware limited liability company, and a wholly-owned subsidiary of ours.

Volatile Capital Markets and Competition

We continuously consider and enter into discussions regarding potential growth projects and acquisitions and may contemplate external funding for potential growth projects and acquisitions. Any limitations on our access to capital may impair our ability to execute this strategy. If the cost of such capital becomes too expensive, our ability to develop or acquire strategic and accretive assets may be limited. We may not be able to raise the necessary funds on satisfactory terms, if at all. The primary factors influencing our cost of borrowing include interest rates, credit spreads, covenants, underwriting or loan origination fees and similar charges we pay to lenders. These factors may impair our ability to execute our growth and acquisition strategy.

Current economic conditions and competition for asset purchases and development opportunities could limit our ability to fully execute our growth strategy. Increased volatility in commodity prices and the broader market could negatively impact the ability of companies in the oil and gas industry to seek financing and access the capital markets on favorable terms or at all. We believe we have sufficient access to financial resources and liquidity necessary to meet our requirements for working capital, debt service payments and capital expenditures in 2026 and beyond. For additional information regarding our financing activities, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Our Liquidity and Capital Resources.”

How We Evaluate Our Operations

The profitability of our business is a function of the difference between: (i) the revenues we receive from our operations, including fee-based revenues from services and revenues from the natural gas, NGLs, crude oil and condensate we sell, and (ii) the costs associated with conducting our operations, including the costs of wellhead natural gas, crude oil and mixed NGLs that we purchase as well as operating, general and administrative costs and the impact of our commodity hedging activities. Because commodity price movements tend to impact both revenues and costs, increases or decreases in our revenues alone are not necessarily indicative of increases or decreases in our profitability. Our contract portfolio, the prevailing pricing environment for natural gas, NGLs and crude oil, the impact of our commodity hedging program and its ability to mitigate exposure to commodity price movements, and the volumes of natural gas, NGLs and crude oil throughput on our systems are important factors in determining our profitability. Our profitability is also affected by the NGL content in gathered wellhead natural gas, supply and demand for our products and services, utilization of our assets and changes in our customer mix.

Our profitability is also impacted by fee-based contracts. Our growing capital expenditures for pipelines and gathering and processing assets underpinned by fee-based margin, expansion of our Downstream facilities, continued focus on adding fee-based margin to our existing and future gathering and processing contracts, as well as third-party acquisitions of businesses and assets, will continue to increase the number of our contracts that are fee-based. Fixed fees for services such as gathering and processing, transportation, fractionation, storage, terminaling and crude oil gathering are not directly tied to changes in market prices for commodities. Nevertheless, a change in market dynamics such as available commodity throughput does affect profitability.

Management uses a variety of financial measures and operational measurements to analyze our performance. These include: (i) throughput volumes, facility efficiencies and fuel consumption, (ii) operating expenses, (iii) capital expenditures and (iv) the following non-GAAP measures: adjusted EBITDA, adjusted cash flow from operations, adjusted free cash flow and adjusted operating margin (segment).

Throughput Volumes, Facility Efficiencies and Fuel Consumption

Our profitability is impacted by our ability to add new sources of natural gas and crude oil supplies to offset the natural decline of existing volumes from oil and natural gas wells that are connected to our gathering and processing systems. This is achieved by connecting new wells and adding new volumes in existing areas of production, as well as by capturing natural gas and crude oil supplies currently gathered by third parties. Similarly, our profitability is impacted by our ability to add new sources of mixed NGL supply, connected by third-party transportation and our NGL pipeline system, to our Downstream Business fractionation facilities and at times to our export facilities. We fractionate NGLs generated by our gathering and processing plants, as well as by contracting for mixed NGL supply from third-party facilities.

In addition, we seek to increase adjusted operating margin by limiting volume losses, reducing fuel consumption and by increasing efficiency. With our gathering systems’ extensive use of remote monitoring capabilities, we monitor the volumes received at the wellhead or central delivery points along our gathering systems, the volume of natural gas received at our processing plant inlets and the volumes of NGLs and residue natural gas recovered by our processing plants. We also monitor the volumes of NGLs received, stored, fractionated and delivered across our logistics assets. This information is tracked through our processing plants and Downstream Business facilities to determine customer settlements for sales and volume related fees for service and helps us increase efficiency and reduce fuel consumption.

As part of monitoring the efficiency of our operations, we measure the difference between the volume of natural gas received at the wellhead or central delivery points on our gathering systems and the volume received at the inlet of our processing plants as an indicator of fuel consumption and line loss. We also track the difference between the volume of natural gas received at the inlet of the processing plant and the NGLs and residue gas produced at the outlet of such plant to monitor the fuel consumption and recoveries of our facilities. Similar tracking is performed for our crude oil gathering and logistics assets and our NGL pipelines. These volume, recovery and fuel consumption measurements are an important part of our operational efficiency analysis and safety programs.

Operating Expenses

Operating expenses are costs associated with the operation of specific assets. Labor, contract services, repair and maintenance and ad valorem taxes comprise the most significant portion of our operating expenses. These expenses remain relatively stable and independent of the volumes through our systems, but may increase with system expansions and inflation, and will fluctuate depending on the scope of the activities performed during a specific period.

Capital Expenditures

Our capital expenditures are classified as growth capital expenditures and maintenance capital expenditures. Growth capital expenditures improve the service capability of our existing assets, extend asset useful lives, increase capacities from existing levels, add capabilities, and reduce costs or enhance revenues. Maintenance capital expenditures are those expenditures that are necessary to maintain the service capability of our existing assets, including the replacement of system components and equipment, which are worn, obsolete or completing their useful life and expenditures to remain in compliance with environmental laws and regulations.

Capital spend associated with growth and maintenance projects is closely monitored. Return on investment is analyzed before a capital project is approved, spend is closely monitored throughout the development of the project, and the subsequent operational performance is compared to the assumptions used in the economic analysis performed for the capital investment approval.

Non-GAAP Measures

We utilize non-GAAP measures to analyze our performance. Adjusted EBITDA, adjusted cash flow from operations, adjusted free cash flow and adjusted operating margin (segment) are non-GAAP measures. The GAAP measures most directly comparable to these non-GAAP measures are income (loss) from operations, Net income (loss) attributable to Targa Resources Corp. and segment operating margin. These non-GAAP measures should not be considered as an alternative to GAAP measures and have important limitations as analytical tools. Investors should not consider these measures in isolation or as a substitute for analysis of our results as reported under GAAP. Additionally, because our non-GAAP measures exclude some, but not all, items that affect income and segment operating margin, and are defined differently by different companies within our industry, our definitions may not be comparable with similarly titled measures of other companies, thereby diminishing their utility. Management compensates for the limitations of our non-GAAP measures as analytical tools by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these insights into our decision-making processes.

Adjusted Operating Margin

We define adjusted operating margin for our segments as revenues less product purchases and fuel. It is impacted by volumes and commodity prices as well as by our contract mix and commodity hedging program.

Gathering and Processing adjusted operating margin consists primarily of:

• service fees related to natural gas and crude oil gathering, treating and processing; and
• revenues from the sale of natural gas, condensate, crude oil and NGLs less producer settlements, fuel and transport and our equity volume hedge settlements.

Logistics and Transportation adjusted operating margin consists primarily of:

• service fees (including the pass-through of energy costs included in certain fee rates);
• system product gains and losses; and
• NGL and natural gas sales, less NGL and natural gas purchases, fuel, third-party transportation costs and the net inventory change.

The adjusted operating margin impacts of mark-to-market hedge unrealized changes in fair value are reported in Other.

Adjusted operating margin for our segments provides useful information to investors because it is used as a supplemental financial measure by management and by external users of our financial statements, including investors and commercial banks, to assess:

• the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;
• our operating performance and return on capital as compared to other companies in the midstream energy sector, without regard to financing or capital structure; and
• the viability of capital expenditure projects and acquisitions and the overall rates of return on alternative investment opportunities.

Management reviews adjusted operating margin and operating margin for our segments monthly as a core internal management process. We believe that investors benefit from having access to the same financial measures that management uses in evaluating our operating results. The reconciliation of our adjusted operating margin to the most directly comparable GAAP measure is presented under “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – By Reportable Segment.”

Adjusted EBITDA

We define adjusted EBITDA as Net income (loss) attributable to Targa Resources Corp. before interest, income taxes, depreciation and amortization, and other items that we believe should be adjusted consistent with our core operating performance. The adjusting items are detailed in the adjusted EBITDA reconciliation table and its footnotes. Adjusted EBITDA is used as a supplemental financial measure by us and by external users of our financial statements such as investors, commercial banks and others to measure the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness and pay dividends to our investors.

Adjusted Cash Flow from Operations and Adjusted Free Cash Flow

We define adjusted cash flow from operations as adjusted EBITDA less cash interest expense on debt obligations and cash tax (expense) benefit. We define adjusted free cash flow as adjusted cash flow from operations less maintenance capital expenditures and growth capital expenditures, net of any reimbursements of project costs and contributions from noncontrolling interests and including contributions to investments in unconsolidated affiliates. Adjusted cash flow from operations and adjusted free cash flow are performance measures used by us and by external users of our financial statements, such as investors, commercial banks and research analysts, to assess our ability to generate cash earnings (after servicing our debt and funding capital expenditures) to be used for corporate purposes, such as payment of dividends, retirement of debt or redemption of other financing arrangements.

Our Non-GAAP Financial Measures

The following table reconciles the non-GAAP financial measures used by management to the most directly comparable GAAP measures for the periods presented:

(In millions)

(1) Represents adjustments related to our subsidiaries with noncontrolling interests, including depreciation and amortization expense as well as earnings for certain plants within our WestTX joint venture not subject to noncontrolling interest accounting.

(2) Litigation and environmental reserves includes charges related to specific litigation and environmental compliance matters that are nonrecurring in nature and outside the ordinary course of our business and/or not reflective of our ongoing core operations. We may incur such charges from time to time, and we believe it is useful to exclude these charges as we do not consider them reflective of our ongoing core operations.

(3) Excludes amortization recognized in interest expense. The year ended December 31, 2024 includes $55.8 million of interest expense on a 2024 legal ruling associated with an agreement, dated December 27, 2015, for crude oil and condensate between Targa Channelview LLC, then a subsidiary of the Company, and Noble Americas Corp (the “Splitter Agreement”).

(4) Represents capital expenditures, net of any reimbursements of project costs and contributions from noncontrolling interests and includes contributions to investments in unconsolidated affiliates.

Consolidated Results of Operations

The following table and discussion is a summary of our consolidated results of operations for the periods presented:

(In millions)

(1) Adjusted EBITDA, adjusted cash flow from operations and adjusted free cash flow are non-GAAP financial measures and are discussed under “Management’s Discussion and Analysis of Financial Condition and Results of Operations–How We Evaluate Our Operations.”

NM Due to a low denominator, the noted percentage change is disproportionately high and as a result, considered not meaningful.

2025 Compared to 2024

The increase in commodity sales reflected higher natural gas prices ($766.2 million), higher NGL and natural gas volumes ($518.7 million) and the favorable impact of hedges ($85.0 million), partially offset by lower NGL and condensate prices ($860.2 million).

The increase in fees from midstream services was primarily due to higher gas gathering and processing fees, and higher export volumes, partially offset by lower transportation and fractionation fees. Lower transportation and fractionation fees were due to a planned turnaround at a portion of our facilities in Mont Belvieu, Texas.

The decrease in product purchases and fuel reflected lower NGL prices, partially offset by higher natural gas prices, and higher NGL and natural gas volumes.

The increase in operating expenses was primarily due to higher labor, taxes and maintenance costs as a result of system expansions.

See “—Results of Operations—By Reportable Segment” for additional information on a segment basis.

The increase in depreciation and amortization expense was primarily due to the impact of system expansions on our asset base.

The increase in general and administrative expense was primarily due to higher compensation and benefits.

The increase in other operating (income) expense was primarily due to recognition of Section 45Q tax credits earned through our carbon capture and sequestration activities.

The increase in interest expense, net, was primarily due to higher borrowings in 2025, partially offset by the recognition of cumulative interest on a legal ruling associated with the Splitter Agreement in 2024.

The increase in income tax (expense) benefit was primarily due to the increase in pre-tax book income and a decrease in income allocated to noncontrolling interest that is not taxable to the Company.

The decrease in net income attributable to noncontrolling interests was primarily due to the Badlands Transaction in the first quarter of 2025 and the acquisition of the remaining membership interest in CBF (the “CBF Acquisition”) in the fourth quarter of 2024.

The premium on repurchase of noncontrolling interests, net of tax was due to the Badlands Transaction in 2025 and the CBF Acquisition in 2024.

Results of Operations—By Reportable Segment

The following table presents our operating margins by reportable segment:

(In millions)

Gathering and Processing Segment

(In millions, except operating statistics and price amounts)

(1) Segment operating statistics include the effect of intersegment amounts, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator is the total volume sold during the period and the denominator is the number of calendar days during the period.

(2) Plant natural gas inlet represents our undivided interest in the volume of natural gas passing through the meter located at the inlet of a natural gas processing plant, other than Badlands.

(3) Plant natural gas inlet volumes and gross NGL production volumes include producer take-in-kind volumes, while natural gas sales and NGL sales exclude producer take-in-kind volumes.

(4) Permian Midland includes operations in WestTX, of which we own a 72.8% undivided interest, and other plants that are owned 100% by us. Operating results for the WestTX undivided interest assets are presented on a pro-rata net basis in our reported financials.

(5) Operations include facilities that are not wholly-owned by us. For more information regarding our joint ventures and jointly owned facilities, see “Item 1. Business—Our Business Operations.”

(6) Badlands natural gas inlet represents the total wellhead volume and includes the Targa volumes processed at the LM4 plant.

(7) Average realized prices, net of fees, include the effect of realized commodity hedge gain/loss attributable to our equity volumes. The price is calculated using total commodity sales plus the hedge gain/loss as the numerator and total sales volume as the denominator, net of fees.

The following table presents the realized commodity hedge gain (loss) attributable to our equity volumes that are included in the adjusted operating margin of the Gathering and Processing segment:

(In millions, except volumetric data and price amounts)

(1) The price spread is the differential between the contracted derivative instrument pricing and the price of the corresponding settled commodity transaction.

2025 Compared to 2024

The increase in adjusted operating margin was predominantly due to higher natural gas inlet volumes in the Permian, partially offset by lower volumes in other areas. The increase in natural gas inlet volumes in the Permian was attributable to the addition of the Roadrunner II plant during the second quarter of 2024, the Greenwood II plant during the fourth quarter of 2024, the Bull Moose plant during the first quarter of 2025, the Pembrook II plant during the third quarter of 2025, the Bull Moose II plant during the fourth quarter of 2025, and continued strong producer activity.

The increase in operating expenses was primarily due to higher volumes and multiple plant additions in the Permian.

Logistics and Transportation Segment

(In millions, except operating statistics)

(1) Segment operating statistics include intersegment amounts, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator is the total volume sold during the period and the denominator is the number of calendar days during the period.

(2) Represents the total quantity of mixed NGLs that earn a transportation margin.

(3) Export volumes represent the quantity of NGL products delivered to third-party customers at our Galena Park Marine Terminal that are destined for international markets.

2025 Compared to 2024

The increase in adjusted operating margin was due to higher pipeline transportation and fractionation margin and higher marketing margin. Pipeline transportation and fractionation volumes benefited from higher supply volumes primarily from our Permian Gathering and Processing systems, the addition of Train 9 during the second quarter of 2024, the addition of the Daytona NGL Pipeline during the third quarter of 2024, and the addition of Train 10 during the fourth quarter of 2024. Marketing margin increased due to greater optimization opportunities.

The increase in operating expenses was predominantly due to system expansions and planned maintenance.

Other

(In millions)

Other contains the results of commodity derivative activity mark-to-market gains/losses related to derivative contracts that were not designated as cash flow hedges. We have entered into derivative instruments to hedge the commodity price associated with a portion of our future commodity purchases and sales and natural gas transportation basis risk within our Logistics and Transportation segment. See further details of our risk management program in “Item 7A. – Quantitative and Qualitative Disclosures About Market Risk.”

Our Liquidity and Capital Resources

As of December 31, 2025, inclusive of our consolidated joint venture accounts, we had $166.1 million of Cash and cash equivalents on our Consolidated Balance Sheets. On a consolidated basis, our main sources of liquidity and capital resources are internally generated cash flows from operations, borrowings under the TRGP Revolver, the Commercial Paper Program, the Securitization Facility, and access to debt and equity capital markets. We have the ability to supplement these sources of liquidity with joint venture arrangements and proceeds from asset sales. Our exposure to adverse credit conditions includes our credit facilities, cash investments, hedging abilities, customer performance risks and counterparty performance risks.

We believe our sources of liquidity and capital resources are sufficient to meet our anticipated cash requirements for at least the next twelve months to satisfy our obligations, including our day-to-day operations, growth capital expenditures, dividend payments, maintenance capital expenditures, debt service and other anticipated obligations. Our ability to generate cash is subject to a number of factors, some of which are beyond our control. These include commodity prices and ongoing efforts to manage operating costs and maintenance capital expenditures, as well as general economic, financial, competitive, legislative, regulatory and other factors. For additional discussion on recent factors impacting our liquidity and capital resources, see “Recent Developments.”

Short-term Liquidity

Our principal sources of short-term liquidity consist of internally generated cash flow, borrowings available under the TRGP Revolver, as well as our right to request additional commitment increases under the TRGP Revolver, the Commercial Paper Program, the Securitization Facility, proceeds from debt and equity offerings, and joint ventures and/or asset sales. Based on anticipated levels of operations and absent any disruptive events, we believe our liquidity is sufficient to finance our operations, capital expenditures, quarterly cash dividends and obligations, as discussed further below, for at least the next twelve months.

Our short-term liquidity on a consolidated basis as of January 31, 2026 was:

(In millions)

(1) Includes cash held in our consolidated joint venture accounts.

Other potential capital resources associated with our existing arrangements include our right to request an additional $500.0 million in commitment increases under the TRGP Revolver, subject to the terms therein. The TRGP Revolver matures on February 18, 2030. The maturity date is extendable, subject to the lenders’ consent, by one year up to two times.

In July 2025, the Partnership amended the Securitization Facility to, among other things, extend the facility termination date to August 31, 2026.

On January 6, 2026, we used $650.0 million in borrowings from the Commercial Paper Program and $600.0 million from the Securitization Facility to fund the Stakeholder Acquisition.

A portion of our capital resources are allocated to letters of credit to satisfy certain counterparty credit requirements. As of December 31, 2025, we had $20.0 million in letters of credit outstanding under the TRGP Revolver. The letters of credit also reflect certain counterparties’ views of our financial condition and ability to satisfy our performance obligations, as well as commodity prices and other factors.

Working Capital

Working capital is the amount by which current assets exceed current liabilities. On a consolidated basis, at the end of any given month, accounts receivable and payable tied to commodity sales and purchases are relatively balanced, with receivables from customers being offset by plant settlements payable to producers. The factors that typically cause overall variability in our reported total working capital are: (i) our cash position; (ii) liquids inventory levels, which we closely manage, as well as liquids valuations; (iii) changes in payables and accruals related to major growth capital projects; (iv) changes in the fair value of the current portion of derivative contracts; (v) monthly swings in borrowings under the Securitization Facility; and (vi) major structural changes in our asset base or business operations, such as certain organic growth capital projects and acquisitions or divestitures.

Our working capital as of December 31, 2025 decreased $307.8 million compared to December 31, 2024. The decrease was primarily due to higher current debt obligations as a result of the reclassification of the 6.875% Notes due 2029 from Long-term debt in our Consolidated Balance Sheets in November 2025, higher payable balances due to capital spending on growth projects and lower trade receivables resulting from lower NGL prices. The decrease was partially offset by a lower outstanding balance on the Securitization Facility, lower product purchases and fuel payables resulting from lower NGL prices and a higher NGL inventory balance. See discussion below about our financing activities.

Long-term Financing

Our long-term financing consists of potentially raising funds through long-term debt obligations, the issuance of common stock, preferred stock, or joint venture arrangements. The majority of our debt is fixed rate borrowings; however, we have some exposure to the risk of changes in interest rates, primarily as a result of the variable rate borrowings under the TRGP Revolver, Securitization Facility, and Commercial Paper Program. We may enter into interest rate hedges with the intent to mitigate the impact of changes in interest rates on cash flows. As of December 31, 2025, we did not have any interest rate hedges.

In February 2025, we entered into the TRGP Revolver, which provides for a revolving credit facility in an initial aggregate principal amount up to $3.5 billion (with an option to increase such maximum aggregate principal amount by up to $500.0 million in the future, subject to the terms of the TRGP Revolver) and a swing line sub-facility of up to $150.0 million. In connection with our entry into the TRGP Revolver, we terminated the Previous TRGP Revolver.

In February 2025, we completed an underwritten public offering of the 5.550% Notes due 2035 and the 6.125% Notes 2055, resulting in net proceeds of approximately $2.0 billion. We used a portion of the net proceeds from the debt issuance to fund the Badlands Transaction and for general corporate purposes, including to repay borrowings under the Commercial Paper Program.

In June 2025, we completed an underwritten public offering of the 4.900% Notes due 2030 and the 5.650% Notes due 2036, resulting in net proceeds of approximately $1.5 billion. We used a portion of the net proceeds from the debt issuance to fund the redemption of all of the Partnership’s 6.500% Notes due 2027 in July 2025, and the remaining net proceeds for general corporate purposes, including to repay borrowings under the Commercial Paper Program.

In November 2025, we completed an underwritten public offering of the 4.350% Notes due 2029 and the 5.400% Notes due 2036, resulting in net proceeds of approximately $1.7 billion. We used a portion of the net proceeds from the debt issuance to fund the redemption of all of the Partnership’s 6.875% Notes due 2029 in January 2026, and the remaining net proceeds for general corporate purposes, including to repay borrowings under the Commercial Paper Program.

In the future, we or the Partnership may redeem, purchase or exchange certain of our and/or the Partnership’s outstanding debt through redemption calls, cash purchases and/or exchanges for other debt, in open market purchases, privately negotiated transactions or otherwise. Such calls, repurchases, exchanges or redemptions, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

To date, our debt balances and our subsidiaries’ debt balances have not adversely affected our operations, ability to grow or ability to repay or refinance indebtedness.

For information about our debt obligations, see “Note 8 – Debt Obligations” to our Consolidated Financial Statements. For information about our interest rate risk, see “Item 7A. Quantitative and Qualitative Disclosures About Market Risk—Interest Rate Risk.”

Compliance with Debt Covenants

As of December 31, 2025, both we and the Partnership were in compliance with the covenants contained in our various debt agreements.

Cash Flow Analysis

Cash Flows from Operating Activities

(In millions)

The primary drivers of cash flows from operating activities are: (i) the collection of cash from customers from the sale of NGLs and natural gas, as well as fees for processing, gathering, export, fractionation, terminaling, storage and transportation; (ii) the payment of amounts related to the purchase of NGLs and natural gas; and (iii) the payment of other expenses, primarily field operating costs, general and administrative expense and interest expense. In addition, we use derivative instruments to manage our exposure to commodity price risk. Changes in the prices of the commodities we hedge impact our derivative settlements as well as our margin deposit requirements on unsettled futures contracts.

The increase in net cash provided by operating activities was primarily due to higher collections from customers resulting from increased revenues in 2025 compared to 2024, partially offset by an increase in payments for product purchases, operating costs and interest on debt. In addition, during 2024 we made a nonrecurring one-time payment associated with the Splitter Agreement.

Cash Flows from Investing Activities

(In millions)

The increase in net cash used in investing activities was due to higher outlays for major growth capital projects in 2025 primarily related to construction activities, outlays for the acquisitions completed in 2025, and an increase in contributions to unconsolidated affiliates.

Cash Flows from Financing Activities

(In millions)

The decrease in net cash used in financing activities was due to higher proceeds from debt financings in 2025, lower distributions to noncontrolling interests subsequent to the CBF Acquisition in the fourth quarter of 2024 and the Badlands Transaction in the first quarter of 2025 and lower repurchases of common stock, partially offset by higher repurchases of noncontrolling interests due to the Badlands Transaction and higher dividends paid in 2025.

Summarized Combined Financial Information for Guarantee of Securities of Subsidiaries

Our subsidiaries that guarantee our obligations under the TRGP Revolver (the “Obligated Group”) also fully and unconditionally guarantee, jointly and severally, the payment of TRGP’s senior unsecured notes, subject to certain limited exceptions.

In lieu of providing separate financial statements for the Obligated Group, we have presented the following supplemental summarized Combined Balance Sheet and Statement of Operations information for the Obligated Group based on Rule 13-01 of the SEC’s Regulation S-X.

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 our non-guarantor subsidiaries have been excluded from the supplemental summarized combined financial information. Significant intercompany balances and activity for the Obligated Group with other related parties, including our non-guarantor subsidiaries (referred to as “affiliates”), are presented separately in the following supplemental summarized combined financial information.

Summarized Combined Balance Sheet and Statement of Operations information for the Obligated Group as of the end of the most recent period presented follows:

(In millions)

ASSETS

Common Stock Dividends

The following table details the dividends declared and/or paid by us to common shareholders for 2025:

(In millions, except per share amounts)

The actual amount we declare as dividends in the future depends on our consolidated financial condition, results of operations, cash flow, the level of our capital expenditures, future business prospects, compliance with our debt covenants and any other matters that our Board of Directors deems relevant.

Capital Expenditures

The following table details cash outlays for capital projects for the periods presented:

(In millions)

(1) Growth capital expenditures, net of contributions from noncontrolling interests and including contributions to investments in unconsolidated affiliates, were $3,343.5 million and $3,000.4 million for the years ended December 31, 2025 and 2024.

(2) Maintenance capital expenditures, net of contributions from noncontrolling interests, were $226.4 million and $231.9 million for the years ended December 31, 2025 and 2024.

The increase in growth capital expenditures was primarily due to expansions in our Gathering and Processing and Downstream Business.

Off-Balance Sheet Arrangements

As of December 31, 2025, there were $65.2 million in surety bonds outstanding related to various performance obligations. These are in place to support various performance obligations as required by (i) statutes within the regulatory jurisdictions where we operate and (ii) counterparty support. Obligations under these surety bonds are not normally called, as we typically comply with the underlying performance requirement.

We have invested in entities that are not consolidated in our financial statements. For information on our obligations with respect to these investments, as well as our obligations with respect to related letters of credit, see “Note 7 – Investments in Unconsolidated Affiliates” and “Note 8 – Debt Obligations” to our Consolidated Financial Statements.

Contractual Obligations

We believe we have sufficient liquidity to fund our operations and meet our short-term and long-term cash obligations. The following table is a summary of our material future contractual cash obligations as of December 31, 2025:

(in millions)

(1) Represents scheduled future maturities of long-term debt obligation and excludes the Securitization Facility. See “Note 8 - Debt Obligations” to our Consolidated Financial Statements for more information.

(2) Represents interest expense on long-term debt obligations based on both fixed debt interest rates and prevailing December 31, 2025 rates for floating debt. See “Note 8 - Debt Obligations” to our Consolidated Financial Statements for more information.

(3) Includes minimum payments on operating lease obligations for compressors, office space and railcars. See “Note 10 - Leases” to our Consolidated Financial Statements for more information.

(4) Includes minimum payments on finance lease obligations for compressors, vehicles, generators, substations and tractors. See “Note 10 - Leases” to our Consolidated Financial Statements for more information.

(5) Land site lease and rights of way provide for surface and underground access for gathering, processing and distribution assets that are located on property not owned by us. These agreements expire at various dates with varying terms, some of which are perpetual. See “Note 16 - Commitments” to our Consolidated Financial Statements for more information.

(6) Includes commitments for pipeline capacity payments for firm transportation and throughput and deficiency agreements, purchase of natural gas and NGLs, capital expenditures, operating expenses and service contracts. Contracts that will be settled at future spot prices are valued using prices as of December 31, 2025.

Critical Accounting Policies and Estimates

The accounting policies and estimates discussed below are considered by management to be critical to an understanding of our financial statements because their application requires the most significant judgments from management in estimating matters for financial reporting that are inherently uncertain. See the description of our accounting policies in the notes to the financial statements for additional information about our critical accounting policies and estimates.

Business Acquisitions

For business acquisitions, we recognize the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at their estimated fair values on the acquisition date. Goodwill results when the cost of a business acquisition exceeds the fair value of the net identifiable assets of the acquired business. Determining fair value requires management’s judgment and involves the use of significant estimates and assumptions with respect to projections of future production volumes, pricing and cash flows, benchmark analysis of comparable public companies, discount rates, expectations regarding customer contracts and relationships, and other management estimates. The judgments made in the determination of the estimated fair value assigned to the assets acquired, liabilities assumed and any noncontrolling interest in the investee, the duration of each liability, and any resulting goodwill can materially impact the financial statements in periods after acquisition.

Depreciation of Property, Plant and Equipment and Amortization of Intangible Assets

Depreciation of our property, plant and equipment is computed using the straight-line method over the estimated useful lives of the assets. Our estimate of depreciation incorporates assumptions regarding the useful economic lives and residual values of our assets. The determination of useful lives of property, plant and equipment requires us to make various assumptions, including our expected use of the asset and the supply of and demand for hydrocarbons in the markets served, normal wear and tear of facilities, and the extent and frequency of maintenance programs.

We amortize the costs of our intangible assets in a manner that closely resembles the expected benefit pattern of the intangible assets or on a straight-line basis where such pattern is not readily determinable, over the periods in which we benefit from services provided to customers. At the time assets are placed in service or acquired, we believe such assumptions are reasonable; however, circumstances may develop that would cause us to change these assumptions, which would change our depreciation/amortization amounts prospectively.

Impairment of Long-Lived Assets, including Intangible Assets

We evaluate long-lived assets, including intangible assets, for impairment when events or changes in circumstances indicate our carrying amount of an asset may not be recoverable, including changes to our estimates that could have an impact on our assessment of asset recoverability. Asset recoverability is measured by comparing the carrying value of the asset or asset group with its expected future pre-tax undiscounted cash flows. Individual assets are grouped at the lowest level for which the related identifiable cash flows are largely independent of the cash flows of other assets and liabilities. These cash flow estimates require us to make judgments and assumptions related to operating and cash flow results, economic obsolescence, the business climate, contractual, legal and other factors.

If the carrying amount exceeds the expected future undiscounted cash flows, we recognize a non-cash pre-tax impairment charge equal to the excess of net book value over fair value. The estimated cash flows used to assess recoverability of our long-lived assets and measure fair value of our asset groups are derived from current business plans, which are developed using near-term price and volume projections reflective of the current environment and management's projections for long-term average prices and volumes. In addition to near and long-term price assumptions, other key assumptions include volume projections, operating costs, timing of incurring such costs and the use of an appropriate terminal value and discount rate. Any changes we make to these projections and assumptions could result in significant revisions to our evaluation of recoverability of our long-lived assets and the recognition of additional impairments.

Price Risk Management (Hedging)

Our net income and cash flows are subject to volatility stemming from changes in commodity prices and interest rates. In an effort to reduce the volatility of our cash flows, we have entered into derivative financial instruments to hedge the commodity price associated with a portion of our expected natural gas, NGL, and condensate equity volumes, future commodity purchases and sales, and transportation basis risk.

One of the factors that can affect our operating results each period is the price assumptions used to value our derivative financial instruments, which are reflected at their fair values on the balance sheet. We determine the fair value of our derivative instruments using present value methods or standard option valuation models with assumptions about commodity prices based on those observed in underlying markets. Changes in the methods or assumptions we use to calculate the fair value of our derivative instruments could have a material effect on our consolidated financial statements.

Recent Accounting Pronouncements

For a discussion of recent accounting pronouncements that will affect us, see “Note 3 – Significant Accounting Policies” to our Consolidated Financial Statements.

Our principal market risks are our exposure to changes in commodity prices, particularly to the prices of natural gas, NGLs and crude oil, changes in interest rates, as well as nonperformance by our risk management counterparties and customers.

Risk Management

We evaluate counterparty risks related to our commodity derivative contracts and trade credit. All of our commodity derivatives are with major financial institutions or major energy companies. Should any of these financial counterparties not perform, we may not realize the benefit of some of our hedges under lower commodity prices, which could have a material adverse effect on our results of operations. We sell our natural gas, NGLs and condensate to a variety of purchasers. Non-performance by a trade creditor could result in losses.

The prices for natural gas, NGLs and crude oil are volatile. In an effort to reduce the variability of our cash flows, we have entered into derivative instruments to hedge the commodity price associated with a portion of our expected natural gas, NGL and condensate equity volumes, future commodity purchases and sales, and transportation basis risk through 2029. Market conditions may also impact our ability to enter into future commodity derivative contracts.

Commodity Price Risk

A portion of our revenues are derived from percent-of-proceeds contracts under which we receive a portion of the proceeds from the sale of commodities as payment for services. The prices of natural gas, NGLs and crude oil are subject to fluctuations in response to changes in supply, demand, market uncertainty and a variety of additional factors beyond our control. We monitor these risks and enter into hedging transactions designed to mitigate the impact of commodity price fluctuations on our business. Both the realized settlements for a derivative instrument designated as a hedge and the related cash flows are classified in the same category as the item being hedged within the Consolidated Statement of Operations and within the Consolidated Statements of Cash Flows.

The primary purpose of our commodity risk management activities is to hedge some of the exposure to commodity price risk and reduce fluctuations in our operating cash flow due to fluctuations in commodity prices. In an effort to reduce the variability of our cash flows, as of December 31, 2025, we have hedged the commodity price associated with a portion of our expected (i) natural gas, NGL, and condensate equity volumes in our Gathering and Processing operations that result from our percent-of-proceeds processing arrangements, (ii) future commodity purchases and sales in our Logistics and Transportation segment and (iii) natural gas transportation basis risk in our Logistics and Transportation segment. We hedge a higher percentage of our expected equity volumes in the current year compared to future years, for which we hedge incrementally lower percentages of expected equity volumes. We also enter into commodity financial instruments to help manage other short-term commodity-related business risks of our ongoing operations and in conjunction with marketing opportunities available to us in the operations of our logistics and transportation assets. With swaps, we typically receive an agreed fixed price for a specified notional quantity of commodities and we pay the hedge counterparty a floating price for that same quantity based upon published index prices. Since we receive from our customers substantially the same floating index price from the sale of the underlying physical commodity, these transactions are designed to effectively lock-in the agreed fixed price in advance for the volumes hedged. In order to avoid having a greater volume hedged than our actual equity volumes, we typically limit our use of swaps to hedge the prices of less than our expected equity volumes. We may utilize purchased puts (or floors) and calls (or caps) to hedge additional expected equity commodity volumes without creating volumetric risk. We may buy calls in connection with swap positions to create a price floor with upside. We intend to continue to manage our exposure to commodity prices in the future by entering into derivative transactions using swaps, collars, purchased puts (or floors), futures or other derivative instruments as market conditions permit.

When entering into new hedges, we intend to generally match the NGL product composition and the NGL and natural gas delivery points to those of our physical equity volumes. The NGL hedges cover specific NGL products based upon the expected equity NGL composition. We believe this strategy avoids uncorrelated risks resulting from employing hedges on crude oil or other petroleum products as “proxy” hedges of NGL prices. The fair values of our natural gas and NGL hedges are based on published index prices for delivery at various locations, which closely approximate the actual natural gas and NGL delivery points. A portion of our condensate sales are hedged using crude oil hedges that are based on NYMEX futures contracts for West Texas Intermediate light, sweet crude.

A majority of these commodity price hedges are documented pursuant to a standard International Swaps and Derivatives Association (“ISDA”) form with customized credit and legal terms. The principal counterparties (or, if applicable, their guarantors) have investment grade credit ratings. While we have no current obligation to post cash, letters of credit or other additional collateral to secure these hedges so long as we maintain our current credit rating, we could be obligated to post collateral to secure the hedges in the event of an adverse change in our creditworthiness where a counterparty’s exposure to our credit increases over the term of the hedge as a result of higher commodity prices. A purchased put (or floor) transaction does not expose our counterparties to credit risk, as we have no obligation to make future payments beyond the premium paid to enter into the transaction; however, we are exposed to the risk of default by the counterparty, which is the risk that the counterparty will not honor its obligation under the put transaction.

We also enter into commodity price hedging transactions using futures contracts on futures exchanges. Exchange traded futures are subject to exchange margin requirements, so we may have to increase our cash deposit due to a rise in natural gas, NGL or crude oil prices. Unlike bilateral hedges, we are not subject to counterparty credit risks when using futures on futures exchanges.

These contracts may expose us to the risk of financial loss in certain circumstances. Generally, our hedging arrangements provide us protection on the hedged volumes if prices decline below the prices at which these hedges are set. If prices rise above the prices at which they have been hedged, we will receive less revenue on the hedged volumes than we would receive in the absence of hedges (other than with respect to purchased calls).

To analyze the risk associated with our derivative instruments, we utilize a sensitivity analysis. The sensitivity analysis measures the change in fair value of our derivative instruments based on a hypothetical 10% change in the underlying commodity prices, but does not reflect the impact that the same hypothetical price movement would have on the related hedged items. The financial statement impact on the fair value of a derivative instrument resulting from a change in commodity price would normally be offset by a corresponding gain or loss on the hedged item under hedge accounting. The fair values of our derivative instruments are also influenced by changes in market volatility for option contracts and the discount rates used to determine the present values.

The following table shows the effect of hypothetical price movements on the estimated fair value of our derivative instruments as of December 31, 2025:

(In millions)

The table above contains all derivative instruments outstanding as of the stated date for the purpose of hedging commodity price risk, which we are exposed to due to our equity volumes and future commodity purchases and sales, as well as basis differentials related to our gas transportation arrangements.

Our operating revenues increased (decreased) by $(160.3) million and $(245.4) million during the years ended December 31, 2025 and 2024, respectively, as a result of transactions accounted for as derivatives. The estimated fair value of our risk management position has moved from a net liability position of $172.2 million at December 31, 2024 to a net liability position of $66.9 million at December 31, 2025. The net liability position on our derivative contracts is primarily attributable to unfavorable movement in natural gas forward basis prices.

Interest Rate Risk

We are exposed to the risk of changes in interest rates, primarily as a result of variable rate borrowings under the TRGP Revolver, the Commercial Paper Program and the Securitization Facility. As of December 31, 2025, we do not have any interest rate hedges. However, we may enter into interest rate hedges in the future with the intent to mitigate the impact of changes in interest rates on cash flows. To the extent that interest rates increase, interest expense for the TRGP Revolver, the Commercial Paper Program and the Securitization Facility will also increase. As of December 31, 2025, we had $161.0 million in outstanding variable rate borrowings. A hypothetical change of 100 basis points in the rate of our variable interest rate debt would impact our consolidated annual interest expense by $1.6 million based on our December 31, 2025 debt balances.

Counterparty Credit Risk

We are subject to risk of losses resulting from nonpayment or nonperformance by our counterparties. The credit exposure related to commodity derivative instruments is represented by the fair value of the asset position (i.e. the fair value of expected future receipts) at the reporting date. Our futures contracts have limited credit risk since they are cleared through an exchange and are margined daily. Should the creditworthiness of one or more of the counterparties decline, our ability to mitigate nonperformance risk is limited to a counterparty agreeing to either a voluntary termination and subsequent cash settlement or a novation of the derivative contract to a third party. In the event of a counterparty default, we may sustain a loss and our cash receipts could be negatively impacted. We have master netting provisions in the ISDA agreements with our derivative counterparties. These netting provisions allow us to net settle asset and liability positions with the same counterparties within the same Targa entity, and reduce our maximum loss due to counterparty credit risk by $6.2 million as of December 31, 2025. The range of losses attributable to our individual counterparties as of December 31, 2025 would be between $0.1 million and $14.9 million, depending on the counterparty in default.

Customer Credit Risk

We extend credit to customers and other parties in the normal course of business. We have established various procedures to manage our credit exposure, including performing initial and subsequent credit risk analyses, setting maximum credit limits and terms and requiring credit enhancements when necessary. We use credit enhancements including (but not limited to) letters of credit, prepayments, parental guarantees and rights of offset to limit credit risk to ensure that our established credit criteria are followed and financial loss is mitigated or minimized.

We have an active credit management process, which is focused on controlling loss exposure due to bankruptcies or other liquidity issues of counterparties. Our allowance for credit losses was $0.7 million and $2.5 million as of December 31, 2025 and 2024, respectively.

During the years ended December 31, 2025 and 2024, no customer comprised 10% or greater of our consolidated revenues.

Evaluation of Disclosure Controls and Procedures

Management, with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the design and effectiveness of our disclosure controls and procedures, as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) as of the end of the period covered in this Annual Report. Based on such evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as of December 31, 2025, our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC and (ii) accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow for timely decisions regarding required disclosure.

Internal Control Over Financial Reporting

(a) Management’s Report on Internal Control Over Financial Reporting

Our Management’s Report on Internal Control Over Financial Reporting is included on page F-2 of this Annual Report and is incorporated herein by reference. Management concluded that our internal control over financial reporting was effective as of December 31, 2025.

(b) Changes in Internal Control Over Financial Reporting

There have been no changes in our internal control over financial reporting during the quarter ended December 31, 2025, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.