PLAINS GP HOLDINGS LP
For the period ended Dec 31, 2024. Filed Feb 28, 2025.
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A company's yearly report to the SEC, with audited financial statements. It is the fullest account a company gives of its business, its finances and the risks it sees.
FY2024 · Filed Feb 28, 2025
PAGP$25.78-2.3%Stored close · as of Nov 6, 2026
What changed in Management’s Discussion and Analysis?
Read the current filingPrevious report: 10-K
Period ended 2023-12-31; filed 2024-02-29.
0001581990-24-000008
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of OperationsCurrent report: 10-K
Period ended 2024-12-31; filed 2025-02-28.
0001581990-25-000006
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of OperationsThe baseline is this issuer’s latest earlier reporting period of the same form that was filed before the current report. A previous 10-Q is a different quarter, not a year-over-year comparison. Amendments are excluded.
Compared 218 previous paragraphs and 224 current paragraphs.
130 unchanged; 71 reworded; 22 added; 17 removed; 0 previous and 1 current paragraphs rearranged.
Tables are not compared: 15 previous and 16 current tables excluded. Dates, whitespace, punctuation and numbering changes are ignored; changes to financial figures remain significant.
A changed paragraph is not evidence that risk increased or decreased. An unchanged paragraph does not establish that risk stayed the same.
Added paragraphs (22)
Current report
Product sales revenues and purchases increased for the year ended December 31, 2024 compared to the year ended December 31, 2023 primarily due to higher crude oil sales volumes.
Current report
The net loss on asset sales and asset impairments for the year ended December 31, 2024 was primarily due to non-cash charges related to the write-down of certain of our long-lived U.S. terminal assets included in our NGL segment due to asset impairments and accelerated depreciation in the fourth quarter of 2024.
Current report
In the fourth quarter of 2024, we recognized a gain of $15 million related to our acquisition of the remaining 50% interest in Midway Pipeline LLC.
Current report
The net unfavorable income tax variance for the year ended December 31, 2024 compared to the year ended December 31, 2023 was primarily due to higher income tax expense in 2024 associated with Canadian withholding tax on dividends from our Canadian entities to other Plains entities driven by timing of dividend payments, including proceeds from asset divestitures, partially offset by the impact of lower earnings at PAA on income tax attributable to PAGP.
Current report
Non-GAAP Financial Performance Measures
Current report
(1)Represents “Interest expense, net” as reported on our Consolidated Statements of Operations.
Current report
(2)Represents components of significant segment expenses.
Current report
Net Revenues and Equity Earnings. Our results were favorably impacted by (i) volume growth across our pipeline systems driven by increased production in the Permian Basin region, as well as increased movements from the Rocky Mountain region to Cushing, Oklahoma, (ii) the benefit of tariff escalations and (iii) contributions from acquisitions, including increases in ownership of certain pipeline systems.
Current report
(2)Represents components of significant segment expenses.
Current report
NGL Segment Adjusted EBITDA for the year ended December 31, 2024 decreased compared to the year ended December 31, 2023, primarily due to the impact of lower realized frac spreads, partially offset by higher propane and butane sales volumes.
Current report
In the first quarter of 2025, we completed two additional bolt-on acquisitions for $636 million (approximately $580 million net to our interest), which included (i) a Delaware Basin crude oil gathering business and (ii) an Eagle Ford Basin gathering system. We used a portion of the net proceeds from our January 2025 senior notes offering to fund these acquisitions.
Current report
During the year ended December 31, 2024, PAA had net repayments under its commercial paper program of $40 million. The net repayments resulted primarily from cash flow from operating activities and proceeds from the issuance of $650 million, 5.70% senior notes in June 2024, which offset borrowings during the year related to funding needs for capital investments, inventory purchases, repayment of $750 million, 3.60% senior notes due November 2024 and other general partnership purposes.
Current report
Issuances of PAA Senior Notes. PAA did not issue any senior unsecured notes during 2023. During 2024, PAA issued senior unsecured notes as summarized in the table below (in millions):
Current report
(1)Face value of notes less the applicable premium or discount (before deducting for initial purchaser discounts, commissions and offering expenses).
Current report
(2)Face value of notes less the applicable premium or discount, initial purchaser discounts, commissions and offering expenses.
Current report
(3)PAA used the net proceeds from the offering, along with other cash on hand, to repay on November 1, 2024 the principal amount of its $750 million, 3.60% senior notes due November 2024. Prior to such repayment, PAA used a portion of the net proceeds from the offering to repay outstanding borrowings under its commercial paper program and for general partnership purposes.
Current report
In January 2025, PAA also completed the offering of $1 billion, 5.95% senior notes due June 2035 at a public offering price of 99.761%. Interest payments are due on June 15 and December 15 of each year, commencing on June 15, 2025. PAA used the net proceeds from this offering of approximately $988 million, after deducting the underwriting discount and offering expenses, to (i) fund the acquisitions completed during the first quarter of 2025, (ii) fund the repurchase in January 2025 of 12.7 million PAA Series A preferred units, including accrued and unpaid distributions and (iii) repay outstanding borrowings under its credit facilities and commercial paper program, and, pending such uses, for general partnership purposes. See Note 7 and Note 11 to our Consolidated Financial Statements for additional information regarding our recently completed acquisitions and PAA’s Series A preferred units, respectively.
Current report
Preferred Unit Repurchase
Current report
On January 31, 2025, PAA repurchased 12.7 million units, or 18%, of its outstanding Series A preferred units at the issue price of $26.25 per unit for a purchase price of approximately $333 million, plus accrued and unpaid distributions through January 30, 2025 of approximately $10 million. PAA used a portion of the net proceeds from its January 2025 senior notes offering to fund this repurchase. See Note 11 to our Consolidated Financial Statements for more information regarding PAA’s Series A preferred units.
Current report
We maintain insurance coverage, which is subject to certain exclusions and deductibles, in the event of such liabilities. In November 2022, we submitted claims to several of our insurance carriers seeking reimbursement for a payment made in October of 2022 to settle a class action lawsuit stemming from the Line 901 incident. As of December 31, 2023, we had recognized a receivable of approximately $225 million, of which we had classified $175 million as a short-term asset with the remaining $50 million recognized as a long-term asset. As of December 31, 2023, we believed that our claim for reimbursement was probable of recovery despite the ongoing arbitration proceedings. However, at that time we also noted that various factors could impact the timing and amount of recovery of our insurance receivable, including future developments that adversely impacted our assessment of the strength of our coverage claims, the outcome of any dispute resolution proceedings with respect to our coverage claims (including arbitration proceedings) and the extent to which insurers may become insolvent in the future. Due to these factors, we noted that we could not provide complete assurance that actual receivable amounts recovered would not vary significantly from our estimated amounts.
Current report
A binding arbitration hearing with respect to our insurance claim against insurers representing $175 million of our total $225 million reimbursement claim concluded in early October 2024, and the arbitration panel’s final and binding decision was returned in January 2025. The panel ruled that a substantial portion of our claims subject to the proceeding were not covered
Current report
under the applicable policy and therefore we were not entitled to reimbursement of our $175 million claim against the applicable insurers. With respect to our remaining $50 million claim against different insurance carriers, we now regard collection of those claims as being less than “probable.” As a result, we wrote off the entire $225 million receivable in the fourth quarter of 2024 and will recognize any future collections as and if they are received. See Note 18 to our Consolidated Financial Statements for further discussion regarding the Line 901 incident and our related insurance receivable.
Removed paragraphs (17)
Previous report
Additionally, net income for 2023 includes favorable impacts from gains on asset sales and the mark-to-market adjustment of the Preferred Distribution Rate Reset Option compared to losses in the 2022 period, which were partially offset by the benefit to the 2022 period of a gain recognized associated with the remeasurement of our previously held 65% interest in Cactus II to fair value in connection with our acquisition of an additional 5% interest in Cactus II in November 2022.
Previous report
Product sales revenues and purchases decreased for the year ended December 31, 2023 compared to the year ended December 31, 2022 primarily due to lower commodity prices in 2023. The impact of fluctuations of derivative mark-to-market valuations also resulted in lower product sales revenues in 2023 compared to 2022.
Previous report
Depreciation and Amortization
Previous report
Depreciation and amortization expense increased for the year ended December 31, 2023 compared to the year ended December 31, 2022 largely driven by acquisitions, including an additional interest in Cactus II and the remaining 43% in OMOG. See Note 7 to our Consolidated Financial Statements for additional information.
Previous report
The net loss on asset sales and asset impairments for 2022 was primarily comprised of (i) a $330 million non-cash impairment charge recognized in the fourth quarter of 2022 related to certain crude oil assets in California, partially offset by (ii) gains recognized from the sale of land and related assets in Long Beach, California, as well as Line 901 and the Sisquoc to Pentland portion of Line 903, a portion of which relates to the transfer of an asset retirement obligation to the purchaser.
Previous report
Interest Expense, Net
Previous report
The decrease in interest expense for the year ended December 31, 2023 compared to the year ended December 31, 2022 was primarily due to a lower weighted average debt balance during the 2023 period largely driven by the repayment of $750 million of senior notes in March 2022, $400 million of senior notes in January 2023 and $700 million of senior notes in October 2023.
Previous report
See Note 10 to our Consolidated Financial Statements for additional information regarding our debt and related activities during the periods presented.
Previous report
The net favorable income tax variance for the year ended December 31, 2023 compared to the year ended December 31, 2022 was primarily due to lower year-over-year income within our Canadian operations as impacted by fluctuations of derivative mark-to-market valuations. The favorable variance was partially offset by the tax impact of the Keyera Fort Saskatchewan divestiture and the impact of higher earnings at PAA on income attributable to PAGP.
Previous report
See Note 7 to our Consolidated Financial Statements for additional information regarding the Keyera Fort Saskatchewan divestiture.
Previous report
Performance Measures
Previous report
Net Revenues and Equity Earnings. Our results were favorably impacted by (i) higher volumes across our pipeline systems, primarily driven by increased production and new well connections, (ii) tariff escalations and (iii) contributions from acquisitions. These benefits were partially offset by the impact of minimum volume commitment deficiency payments received in 2022.
Previous report
NGL Segment Adjusted EBITDA for the year ended December 31, 2023 was in line with results for the year ended December 31, 2022, primarily due to (i) favorable NGL basis differentials and (ii) additional market-based opportunities, largely offset by (iii) lower straddle production driven by turnarounds at a third-party facility, (iv) increased field operating costs and (v) the impact of the sale of our ownership interest in the Keyera Fort Saskatchewan facility in the first quarter of 2023.
Previous report
The 2023 period was impacted by net positive changes in working capital items, largely associated with (i) lower NGL inventory driven by both the impact of the price environment and NGL supply volumes during the year, including the impact of changes in margin balances required as part of our hedging activities, and (ii) timing of payments associated with the settlement of certain obligations.
Previous report
(2)Represents pipeline projects with takeaway capacity out of the Permian Basin, including investments for our proportionate share of the projects of Wink to Webster Pipeline and Cactus II Pipeline.
Previous report
We had no net borrowings or repayments under the PAA credit facilities or commercial paper program during the year ended December 31, 2022.
Previous report
In October 2021, we and Oryx Midstream completed the formation of the Permian JV. See Note 7 to our Consolidated Financial Statements for discussion of the methods, assumptions and estimates used in the determination of the fair value of the assets and liabilities acquired and identification of associated intangible assets.
Reworded paragraphs (71)
Previous wording
We are a Delaware limited partnership formed in 2013 that has elected to be taxed as a corporation for United States federal income tax purposes. As of December 31, 2023, our sole cash-generating assets consisted of an approximate 84% limited partner interest in AAP through our ownership of approximately 196.4 million AAP units. We also own a 100% managing member interest in GP LLC. GP LLC is a Delaware limited liability company that holds the non-economic general partner interest in AAP. AAP is a Delaware limited partnership that, as of December 31, 2023, directly owned a limited partner interest in PAA through its ownership of approximately 232.7 million PAA common units (approximately 30% of PAA’s total outstanding common units and Series A preferred units combined). AAP is the sole member of PAA GP, a Delaware limited liability company that directly holds the non-economic general partner interest in PAA.
Current wording
We are a Delaware limited partnership formed in 2013 that has elected to be taxed as a corporation for United States federal income tax purposes. As of December 31, 2024, our sole cash-generating assets consisted of an approximate 85% limited partner interest in AAP through our ownership of approximately 197.5 million AAP units. We also own a 100% managing member interest in GP LLC. GP LLC is a Delaware limited liability company that holds the non-economic general partner interest in AAP. AAP is a Delaware limited partnership that, as of December 31, 2024, directly owned a limited partner interest in PAA through its ownership of approximately 232.9 million PAA common units (approximately 30% of PAA’s total outstanding common units and Series A preferred units combined). AAP is the sole member of PAA GP, a Delaware limited liability company that directly holds the non-economic general partner interest in PAA.
Previous wording
PAA’s business model integrates large-scale supply aggregation capabilities with the ownership and operation of critical midstream infrastructure systems that connect major producing regions to key demand centers and export terminals. As one of the largest midstream service providers in North America, PAA owns an extensive network of pipeline transportation, terminalling, storage and gathering assets in key crude oil and NGL producing basins (including the Permian Basin) and transportation corridors and at major market hubs in the United States and Canada. PAA’s assets and the services it provides are primarily focused on crude oil and NGL.
Current wording
PAA’s business model integrates large-scale supply aggregation capabilities with the ownership and operation of critical midstream infrastructure systems that connect major producing regions to key demand centers and export terminals. As one of the largest crude oil midstream service providers in North America, PAA owns an extensive network of pipeline transportation, terminalling, storage and gathering assets in key crude oil and NGL producing basins (including the Permian Basin) and transportation corridors and at major market hubs in the United States and Canada. PAA’s assets and the services it provides are primarily focused on crude oil and NGL.
Previous wording
The Permian Basin continues to be one of the most prolific basins in the world and was the predominant driver of U.S. production growth in 2023. The remainder of the U.S. unconventional plays continue to see modest growth. We expect the Permian Basin to be a key contributor to global supply for years to come, based on strong economics and the recent wave of consolidation leading to more stable activity levels over a wide range of commodity price environments.
Current wording
The Permian Basin continues to be one of the most prolific basins in the world and was the predominant driver of U.S. production growth in 2024. We expect the Permian Basin to be a key contributor to global supply for years to come, based on strong economics and the recent wave of consolidation leading to more stable activity levels over a wide range of commodity price environments.
Previous wording
We recognized net income of $1.425 billion for the year ended December 31, 2023 compared to net income of $1.163 billion for the year ended December 31, 2022. Our results include the benefit of higher tariff volumes and tariff escalations on our crude oil pipelines in 2023, as well as the impact of acquisitions. In addition, the 2022 comparative period includes higher costs from the increase in the accrual for estimated costs associated with the Line 901 incident.
Current wording
We recognized net income of $1.070 billion for the year ended December 31, 2024 compared to net income of $1.425 billion for the year ended December 31, 2023.
Previous wording
See the “—Results of Operations” section below for further discussion.
Current wording
The decrease in net income was largely driven by higher costs in the 2024 period associated with the Line 901 incident that occurred in May 2015 (including $225 million related to the write-off of a receivable for insurance proceeds in the fourth quarter of 2024 and $120 million related to settlements in the third quarter of 2024), losses on asset sales, asset impairments and other related items (as compared to gains from such items in the 2023 period), and higher income tax expense largely associated with Canadian withholding tax. In addition, net income for the 2023 period included the favorable impact of gains from the mark-to-market adjustment of the Preferred Distribution Rate Reset Option. However, our Segment Adjusted EBITDA increased in 2024 compared to 2023 due to more favorable results from our Crude Oil segment, partially offset by lower contributions from our NGL segment. See the “—Results of Operations” section below for further discussion.
Previous wording
Fluctuations in our consolidated revenues and purchases and related costs are primarily associated with our merchant activities and generally explained in large part by changes in commodity prices. Our crude oil and NGL merchant activities are not directly affected by the absolute level of prices because the commodities that we buy and sell are generally indexed to the same pricing indices. Both product sales revenues and purchases and related costs will fluctuate with market prices; however, the absolute margins related to those sales and purchases will not necessarily have a corresponding increase or decrease. Additionally, product sales revenues include the impact of gains and losses related to derivative instruments used to manage our exposure to commodity price risk associated with such sales and purchases.
Current wording
Fluctuations in our consolidated revenues and purchases and related costs are primarily associated with our merchant activities and are generally explained by changes in commodity prices and the impact of gains and losses related to derivative instruments used to manage our commodity price exposure. Because both product sales revenues and purchases and related costs are generally based off of the same pricing indices, the market price of the commodities will not necessarily have an impact on the absolute margins related to those sales and purchases.
Previous wording
A majority of our sales and purchases are indexed to West Texas Intermediate (“WTI”). The following table presents the range of the NYMEX WTI benchmark price of crude oil over the last two years (in dollars per barrel):
Current wording
A majority of our crude oil sales and purchases are indexed to the prompt month price of the NYMEX Light, Sweet crude oil futures contract (“NYMEX Price”) and our NGL sales are indexed to Mont Belvieu prices. The following table presents the range of the NYMEX Price over the last two years (in dollars per barrel):
Previous wording
Revenues from services increased for the year ended December 31, 2023 compared to the year ended December 31, 2022 primarily due to higher volumes and tariff escalations in 2023, as well as the impact of acquisitions, partially offset by the impact of lower commodity prices in 2023.
Current wording
Revenues from services increased for the year ended December 31, 2024 compared to the year ended December 31, 2023 primarily due to higher pipeline volumes and tariff escalations, as well as the impact of acquisitions.
Previous wording
The increase in general and administrative expenses for the year ended December 31, 2023 compared to the year ended December 31, 2022 was primarily due to (i) higher employee-related costs, including an increase in equity-indexed compensation expense (a portion of which is excluded in the calculation of Adjusted EBITDA and Segment Adjusted EBITDA) due to a higher PAA common unit price and higher number of outstanding units assumed probable of vesting and (ii) higher information systems costs due to ongoing systems integration work, partially offset by (iii) decreases across several categories.
Current wording
The increase in general and administrative expenses for the year ended December 31, 2024 compared to the year ended December 31, 2023 was primarily due to (i) higher employee-related costs, (ii) higher information systems costs due to ongoing systems integration work and (iii) higher office rent due to an operating cost abatement in the prior year.
Previous wording
Gains/(Losses) on Asset Sales and Asset Impairments, Net
Current wording
Gains/(Losses) on Asset Sales, Asset Impairments and Other, Net
Previous wording
The net gain on asset sales and asset impairments for the year ended December 31, 2023 was primarily comprised of a gain of approximately $140 million related to the sale of our Keyera Fort Saskatchewan facility in the first quarter of 2023.
Current wording
The net gain on asset sales and asset impairments for the year ended December 31, 2023 was primarily related to the sale of our ownership interest in the Keyera Fort Saskatchewan facility in the first quarter of 2023.
Previous wording
Gains/(Losses) on Investments in Unconsolidated Entities, Net
Current wording
Gain on Investments in Unconsolidated Entities, Net
Previous wording
In the third quarter of 2023, we recognized a gain of $29 million related to the Permian JV’s acquisition of the remaining 43% interest in OMOG. See Note 7 to our Consolidated Financial Statements for additional information regarding this transaction.
Current wording
In the third quarter of 2023, we recognized a gain of $29 million related to the Permian JV’s acquisition of the remaining 43% interest in OMOG JV Holdings LLC.
Previous wording
During the fourth quarter of 2022, we recognized (i) a gain of $370 million associated with the remeasurement of our previously held 65% interest in Cactus II to fair value in connection with our acquisition of an additional 5% interest in Cactus II in November 2022 and (ii) a loss of $25 million associated with the difference between the fair value and historical book value of assets contributed by the Permian JV in exchange for an additional interest in OMOG. See Note 7 and Note 8 to our Consolidated Financial Statements for additional information regarding these transactions.
Current wording
See Note 7 to our Consolidated Financial Statements for additional information regarding these transactions.
Previous wording
Adjusted EBITDA is defined as earnings before interest expense, income taxes, depreciation and amortization (including our proportionate share of depreciation and amortization, including write-downs related to cancelled projects and impairments, of unconsolidated entities), gains and losses on asset sales and asset impairments and gains or losses on investments in unconsolidated entities, adjusted for certain selected items impacting comparability. Adjusted EBITDA attributable to PAA excludes the portion of Adjusted EBITDA that is attributable to noncontrolling interests in consolidated joint venture entities.
Current wording
Adjusted EBITDA is defined as earnings before (i) interest expense, (ii) income tax (expense)/benefit, (iii) depreciation and amortization (including our proportionate share of depreciation and amortization, including write-downs related to cancelled projects and impairments, of unconsolidated entities), (iv) gains and losses on asset sales, asset impairments and other, net and (v) gains on investments in unconsolidated entities, net, and adjusted for (vi) certain selected items impacting comparability. Adjusted EBITDA attributable to PAA excludes the portion of Adjusted EBITDA that is attributable to noncontrolling interests in consolidated joint venture entities.
Previous wording
(1)We exclude our proportionate share of the depreciation and amortization expense (including write-downs related to cancelled projects and impairments) of unconsolidated entities when reviewing Adjusted EBITDA, similar to our consolidated assets.
Current wording
(2)We exclude our proportionate share of the depreciation and amortization expense (including write-downs related to cancelled projects and impairments) of unconsolidated entities when reviewing Adjusted EBITDA, similar to our consolidated assets.
Previous wording
(2)Represents general and administrative expenses incremental to those of PAA, which are not allocated to our reporting segments in determining Segment Adjusted EBITDA and are excluded in the non-GAAP financial performance measures utilized by management.
Current wording
(3)Represents general and administrative expenses incremental to those of PAA, which are not allocated to our reporting segments in determining Segment Adjusted EBITDA and are excluded in the non-GAAP financial performance measures utilized by management.
Previous wording
(3)For a more detailed discussion of these selected items impacting comparability, see the footnotes to the Segment Adjusted EBITDA Reconciliation table in Note 19 to our Consolidated Financial Statements.
Current wording
(4)For a more detailed discussion of these selected items impacting comparability, see the footnotes to the Segment Adjusted EBITDA Reconciliation table in Note 19 to our Consolidated Financial Statements.
Previous wording
(4)The Preferred Distribution Rate Reset Option of PAA’s Series A preferred units was accounted for as an embedded derivative and recorded at fair value in our Consolidated Financial Statements. The associated gains and losses are not integral to our results and were thus classified as a selected item impacting comparability. See Note 12 to our Consolidated Financial Statements for additional information regarding the Preferred Distribution Rate Reset Option.
Current wording
(5)The Preferred Distribution Rate Reset Option of PAA’s Series A preferred units was accounted for as an embedded derivative and recorded at fair value in our Consolidated Financial Statements. The associated gains and losses are not integral to our results and were thus classified as a selected item impacting comparability. See Note 12 to our Consolidated Financial Statements for additional information regarding the Preferred Distribution Rate Reset Option.
Previous wording
(5)During the periods presented, there were fluctuations in the value of CAD to USD, resulting in the realization of foreign exchange gains and losses on the settlement of foreign currency transactions as well as the revaluation of monetary assets and liabilities denominated in a foreign currency. The associated gains and losses are not integral to our results and were thus classified as a selected item impacting comparability.
Current wording
(6)During the periods presented, there were fluctuations in the value of CAD to USD, resulting in the realization of foreign exchange gains and losses on the settlement of foreign currency transactions as well as the revaluation of monetary assets and liabilities denominated in a foreign currency. The associated gains and losses are not integral to our results and were thus classified as a selected item impacting comparability.
Previous wording
(6)Other income/(expense), net on our Consolidated Statements of Operations, adjusted for selected items impacting comparability (“Adjusted other income/(expense), net”) is included in Adjusted EBITDA and excluded from Segment Adjusted EBITDA.
Current wording
(7)“Other income/(expense), net” on our Consolidated Statements of Operations, adjusted for selected items impacting comparability (“Adjusted other income/(expense), net”) is included in Adjusted EBITDA and excluded from Segment Adjusted EBITDA.
Previous wording
(7)Reflects amounts attributable to noncontrolling interests in the Permian JV, Cactus II and Red River.
Current wording
(8)Reflects amounts attributable to noncontrolling interests in the Permian JV, Cactus II and Red River.
Previous wording
We manage our operations through two operating segments: Crude Oil and NGL. Our CODM (our Chief Executive Officer) evaluates segment performance based on a variety of measures including Segment Adjusted EBITDA, segment volumes and maintenance capital investment.
Current wording
We manage our operations through two operating segments: Crude Oil and NGL. Our Chief Operating Decision Maker (“CODM”) (our Chief Executive Officer) evaluates segment performance based on a variety of measures including Segment Adjusted EBITDA, segment volumes and maintenance capital investment.
Previous wording
We define Segment Adjusted EBITDA as revenues and equity earnings in unconsolidated entities less (a) purchases and related costs, (b) field operating costs and (c) segment general and administrative expenses, plus (d) our proportionate share of the depreciation and amortization expense (including write-downs related to cancelled projects and impairments) of unconsolidated entities, further adjusted (e) for certain selected items including (i) gains and losses on derivative instruments that are related to underlying activities in another period (or the reversal of such adjustments from a prior period), gains and losses on derivatives that are either related to investing activities (such as the purchase of linefill) or purchases of long-term inventory, and inventory valuation adjustments, as applicable, (ii) long-term inventory costing adjustments, (iii) charges for obligations that are expected to be settled with the issuance of equity instruments, (iv) amounts related to deficiencies associated with minimum volume commitments, net of the applicable amounts subsequently recognized into revenue and (v) other items that our CODM believes are integral to understanding our core segment operating performance and (f) to exclude the portion of all preceding items that is attributable to noncontrolling interests in consolidated joint venture entities (“Segment amounts attributable to noncontrolling interests in consolidated joint ventures”). See Note 19 to our Consolidated Financial Statements for a reconciliation of Segment Adjusted EBITDA to Net income attributable to PAGP.
Current wording
We define Segment Adjusted EBITDA as revenues and equity earnings in unconsolidated entities less (a) significant segment expenses including: (i) purchases and related costs, (ii) field operating costs and (iii) segment general and administrative expenses, plus (b) our proportionate share of the depreciation and amortization expense (including write-downs related to cancelled projects and impairments) of unconsolidated entities, further adjusted (c) for certain selected items including (i) gains and losses on derivative instruments that are related to underlying activities in another period (or the reversal of such adjustments from a prior period), gains and losses on derivatives that are either related to investing activities (such as the purchase of linefill) or purchases of long-term inventory, and inventory valuation adjustments, as applicable, (ii) long-term inventory costing adjustments, (iii) charges for obligations that are expected to be settled with the issuance of equity instruments, (iv) amounts related to deficiencies associated with minimum volume commitments, net of the applicable amounts subsequently recognized into revenue and (v) other items that our CODM believes are integral to understanding our core segment operating performance and (d) to exclude the portion of all preceding items that is attributable to noncontrolling interests in consolidated joint venture entities (“Segment amounts attributable to noncontrolling interests in consolidated joint ventures”). See Note 19 to our Consolidated Financial Statements for a reconciliation of Segment Adjusted EBITDA to Net income attributable to PAGP.
Previous wording
Our Crude Oil segment operations generally consist of gathering and transporting crude oil using pipelines, gathering systems, trucks and at times on barges or railcars, in addition to providing terminalling, storage and other related services utilizing our integrated assets across the United States and Canada. Our assets serve third parties and are also supported by our merchant activities. Our merchant activities include the purchase of crude oil supply and the movement of this supply on our assets or third-party assets to sales locations, including our terminals, third-party connecting carriers, regional hubs or to refineries. Our merchant activities are subject to our risk management policies and may include the use of derivative instruments to manage exposure to commodity price risk and, at times, to provide upside opportunities.
Current wording
Our Crude Oil segment operations generally consist of gathering and transporting crude oil using pipelines (including gathering systems), trucks and, at times, on barges or railcars, in addition to providing terminalling, storage and other related services utilizing our integrated assets across the United States and Canada. Our assets provide services to third parties as well as to our merchant activities. Our merchant activities include the purchase of crude oil supply and the movement of this supply on our assets or third-party assets to sales locations, including our terminals, third-party connecting carriers, regional hubs or to refineries. Our merchant activities are governed by our risk management policies.
Previous wording
Our Crude Oil segment generates revenue through a combination of tariffs, pipeline capacity agreements and other transportation fees, month-to-month and multi-year storage and terminalling agreements and the sale of gathered and bulk-purchased crude oil. Tariffs and other fees on our pipeline systems are typically based on volumes transported and vary by receipt point and delivery point. Fees for our terminalling and storage services are based on capacity leases and throughput volumes. Generally, results from our merchant activities are impacted by (i) increases or decreases in our lease gathering crude oil purchases volumes and (ii) volatility in commodity prices, as well as grade and regional differentials and time spreads. The segment results also include the direct fixed and variable field costs of operating the crude oil assets, as well as an allocation of indirect operating costs.
Current wording
Our Crude Oil segment generates revenue through a combination of tariffs, pipeline capacity agreements and other transportation fees, month-to-month and multi-year storage and terminalling agreements and the sale of gathered and bulk-purchased crude oil. Tariffs and other fees on our pipeline systems are typically based on volumes transported and vary by receipt point and delivery point. Fees for our terminalling and storage services are based on capacity leases and throughput volumes. Generally, results from our merchant activities are impacted by (i) increases or decreases in our lease gathering crude oil purchases volumes and (ii) volatility in commodity price differentials, particularly grade and location differentials, as well as time spreads. The segment results also include the direct fixed and variable field costs of operating the crude oil assets, as well as an allocation of indirect operating costs.
Previous wording
(2)Segment general and administrative expenses reflect direct costs attributable to each segment and an allocation of other expenses to the segments. The proportional allocations by segment require judgment by management and are based on the business activities that exist during each period.
Current wording
(3)Segment general and administrative expenses reflect direct costs attributable to each segment and an allocation of other expenses to the segments. The proportional allocations by segment require judgment by management and are based on the business activities that exist during each period.
Previous wording
(3)Represents adjustments included in the performance measure utilized by our CODM in the evaluation of segment results. See Note 19 to our Consolidated Financial Statements for additional discussion of such adjustments.
Current wording
(4)Represents adjustments included in the performance measure utilized by our CODM in the evaluation of segment results. See Note 19 to our Consolidated Financial Statements for additional discussion of such adjustments.
Previous wording
(4)Average daily volumes in thousands of barrels per day calculated as the total volumes (attributable to our interest for assets owned by unconsolidated entities or through undivided joint interests) for the year divided by the number of days in the year. Volumes associated with acquisitions represent total volumes for the number of days we actually owned the assets divided by the number of days in the period.
Current wording
(5)Average daily volumes in thousands of barrels per day calculated as the total volumes (attributable to our interest for assets owned by unconsolidated entities or through UJIs) for the year divided by the number of days in the year. Volumes associated with acquisitions represent total volumes for the number of days we actually owned the assets divided by the number of days in the period.
Previous wording
(5)Includes volumes (attributable to our interest) from assets owned by unconsolidated entities.
Current wording
(6)Includes volumes (attributable to our interest) from assets owned by unconsolidated entities.
Previous wording
(6)Average monthly capacity in millions of barrels per day calculated as total volumes for the year divided by the number of months in the year.
Current wording
(7)Average monthly capacity in millions of barrels per day calculated as total volumes for the year divided by the number of months in the year.
Previous wording
(7)Of this amount, approximately 1,147 and 1,073 thousand barrels per day were purchased in the Permian Basin for the years ended December 31, 2023 and 2022, respectively.
Current wording
(8)Of this amount, approximately 1,278 and 1,147 thousand barrels per day were purchased in the Permian Basin for the years ended December 31, 2024 and 2023, respectively.
Previous wording
Crude Oil Segment Adjusted EBITDA increased for the year ended December 31, 2023 compared to the year ended December 31, 2022 primarily due to higher tariff volumes, tariff escalations and contributions from acquisitions. These items were partially offset by fewer market-based opportunities for our merchant activities.
Current wording
Crude Oil Segment Adjusted EBITDA increased for the year ended December 31, 2024 compared to the year ended December 31, 2023 primarily due to higher tariff volumes on our pipelines, tariff escalations and contributions from acquisitions, partially offset by fewer market-based opportunities.
Previous wording
Additionally, our results for the year ended December 31, 2023 reflect net fewer market-based opportunities compared to 2022 as the 2022 period includes the benefit of the sale of excess linefill and inventory in a higher crude oil price environment.
Current wording
Additionally, our results for the year ended December 31, 2024 compared to 2023 reflect fewer crude oil market-based opportunities.
Previous wording
Field Operating Costs. For the year ended December 31, 2023 compared to the year ended December 31, 2022, we had higher expenses associated with (i) utilities costs due to a combination of higher volumes and prices and an increase in the amount of drag reducing agents used, (ii) incremental consolidated operating costs in connection with acquisitions, (iii) employee-related costs primarily resulting from higher average headcount and salaries and (iv) unrealized mark-to-market losses on power hedges (which impact our field operating costs but are excluded from Segment Adjusted EBITDA and thus are reflected as an “Adjustment” in the table above). The unfavorable variance for the year ended December 31, 2023 compared to 2022 was partially offset by a decrease in additional estimated costs recognized associated with the Line 901 incident (which impact field operating costs but are excluded from Segment Adjusted EBITDA and thus are reflected as an “Adjustment” in the table above).
Current wording
Field Operating Costs. For the year ended December 31, 2024 compared to the year ended December 31, 2023, we recognized higher expenses associated with (i) an increase in costs associated with settlements related to the Line 901 incident that occurred in May 2015 (which impact field operating costs, but are excluded from Segment Adjusted EBITDA, and thus are reflected as a component of “Other segment items” in the table above), (ii) an increase in estimated costs for long-term environmental remediation obligations, (iii) property taxes due to the impact of favorable adjustments in 2023 and (iv) incremental operating costs and employee-related costs associated with acquisitions, partially offset by (v) unrealized mark-to-market gains on power hedges (which impact our field operating costs but are excluded from Segment Adjusted EBITDA and thus are reflected as a component of “Other segment items” in the table above) and (vi) decreased costs resulting from lower third-party trucked volumes.
Previous wording
Maintenance capital consists of capital expenditures for the replacement and/or refurbishment of partially or fully depreciated assets in order to maintain the operating and/or earnings capacity of our existing assets. The increase in maintenance capital spending for the year ended December 31, 2023 compared to the year ended December 31, 2022 was primarily due to ongoing facility maintenance investments, tractor trailer leases, integrity projects and tank maintenance.
Current wording
Maintenance capital consists of capital expenditures for the replacement and/or refurbishment of partially or fully depreciated assets in order to maintain the operating and/or earnings capacity of our existing assets. The increase in maintenance capital spending for the year ended December 31, 2024 compared to the year ended December 31, 2023 was primarily due to (i) an increase in integrity management, maintenance and repairs and replacement projects and (ii) more trucking lease buyouts.
Previous wording
Our NGL segment operations involve natural gas processing and NGL fractionation, storage, transportation and terminalling. Our NGL revenues are primarily derived from a combination of (i) providing gathering, fractionation, storage, and/or terminalling services to third-party customers for a fee, and (ii) extracting NGL mix from the gas stream processed at our Empress straddle plant facility as well as acquiring NGL mix, which is then transported, stored and fractionated into finished products and sold to customers. Our management of our commodity exposure is subject to our risk management policies and may include the use of derivative instruments to mitigate the risk of such exposure and, at times, to provide upside opportunities.
Current wording
Our NGL segment operations involve natural gas processing and NGL fractionation, storage, transportation and terminalling. Our NGL revenues are primarily derived from a combination of (i) providing gathering, fractionation, storage, and/or terminalling services to third-party customers for a fee, and (ii) our merchant activities of extracting NGL mix from the gas stream processed at our Empress straddle plant facility as well as acquiring NGL mix, which is then transported, stored and fractionated into finished products and sold to customers. The commodity exposure associated with our merchant activities is governed by our risk management policies.
Previous wording
Generally, our segment results are impacted by (i) increases or decreases in our NGL sales volumes, (ii) volatility in commodity prices, the differential between the price of natural gas and the extracted NGL (“frac spread”), as well as location differentials and time spreads, and (iii) the volume of natural gas transported on third-party assets through our Empress straddle plant.
Current wording
Generally, our segment results are impacted by (i) increases or decreases in our NGL sales volumes, (ii) volatility in commodity price differentials, primarily the differential between the price of natural gas and the extracted NGL (“frac spread”), as well as location differentials and time spreads, (iii) the quality and volume of natural gas transported on third-party assets through our Empress straddle plant and (iv) our share of the NGL received from a third-party straddle plant.
Previous wording
(2)Segment general and administrative expenses reflect direct costs attributable to each segment and an allocation of other expenses to the segments. The proportional allocations by segment require judgment by management and are based on the business activities that exist during each period.
Current wording
(3)Segment general and administrative expenses reflect direct costs attributable to each segment and an allocation of other expenses to the segments. The proportional allocations by segment require judgment by management and are based on the business activities that exist during each period.
Previous wording
(3)Represents adjustments included in the performance measure utilized by our CODM in the evaluation of segment results. See Note 19 to our Consolidated Financial Statements for additional discussion of such adjustments.
Current wording
(4)Represents adjustments included in the performance measure utilized by our CODM in the evaluation of segment results. See Note 19 to our Consolidated Financial Statements for additional discussion of such adjustments.
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Rearranged current paragraphs (1)
Current report — wording carried from elsewhere
(1)PAA repaid these senior notes with proceeds from its 5.70% senior notes issued in June 2024, cash on hand. and borrowings under its commercial paper program.