NGL Energy Partners LP

Previous wording

The following is a discussion of NGL Energy Partners LP’s (“we,” “us,” “our,” or the “Partnership”) financial condition and results of operations as of and for the three months and nine months ended December 31, 2024. The discussion should be read in conjunction with the unaudited condensed consolidated financial statements and notes thereto included in this Quarterly Report on Form 10-Q (“Quarterly Report”), as well as Part II, Item 7–“Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the fiscal year ended March 31, 2024 (“Annual Report”) filed with the Securities and Exchange Commission (“SEC”) on June 6, 2024.

Current wording

The following is a discussion of NGL Energy Partners LP’s (“we,” “us,” “our,” or the “Partnership”) financial condition and results of operations as of and for the three months ended June 30, 2025. The discussion should be read in conjunction with the unaudited condensed consolidated financial statements and notes thereto included in this Quarterly Report on Form 10-Q (“Quarterly Report”), as well as Part II, Item 7–“Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the fiscal year ended March 31, 2025 (“Annual Report”) filed with the Securities and Exchange Commission (“SEC”) on May 29, 2025.

Previous wording

(1) Total produced water barrels processed during the three months ended December 31, 2024 and 2023 were 241,343,277 and 218,646,417, respectively. These amounts do not include 16,410,749 barrels and 20,992,750 barrels for the three months ended December 31, 2024 and 2023, respectively, related to payments made by certain producers for committed volumes not delivered, as discussed further below. In addition, water pipeline revenue, which is included in Other Revenues, includes payments from a producer for 9,938,582 committed barrels not delivered during the three months ended December 31, 2024.

Current wording

(4) Total produced water barrels processed during the three months ended June 30, 2025 and 2024 were 252,216,853 and 224,348,310, respectively. These amounts do not include 16,367,740 barrels and 11,699,806 barrels for the three months ended June 30, 2025 and 2024, respectively, related to payments made by certain producers for committed volumes not delivered, as discussed further below. In addition, water pipeline revenue, which is included in Other Revenues, includes payments from a producer for 9,446,030 committed barrels not delivered during the three months ended June 30, 2025.

Previous wording

(2) Excluding payments made by certain producers for committed volumes not delivered, service fees for produced water processed ($/barrel) would have been $0.60/barrel and $0.61/barrel during the three months ended December 31, 2024 and 2023, respectively.

Current wording

(5) Excluding payments made by certain producers for committed volumes not delivered, service fees for produced water processed ($/barrel) would have been $0.61/barrel and $0.61/barrel during the three months ended June 30, 2025 and 2024, respectively.

Previous wording

Water Disposal Service Fee Revenues. The increase was due primarily to an increase in produced water volumes processed from contracted customers and higher fees charged for interruptible spot volumes. These increases were partially offset by the expiration of certain higher fee per barrel contracts which were replaced with lower fee per barrel contracts with an extended term and higher volumes received under contracts with lower fees per barrel. There was also a decrease in payments made by certain producers for committed volumes not delivered.

Current wording

Water Disposal Service Fee Revenues. The increase was due primarily to an increase in produced water volumes processed from contracted customers. There was also an increase in payments made by certain producers for committed volumes not delivered.

Previous wording

Recovered Crude Oil Revenues. The decrease was due primarily to lower realized crude oil prices received from the sale of skim oil barrels, partially offset by an increase in skim oil barrels sold due to more skim oil recovered from receiving more water in higher oil cut basins.

Current wording

Recovered Crude Oil Revenues. The decrease was due primarily to lower realized crude oil prices received from the sale of skim oil barrels, partially offset by an increase in skim oil barrels sold due to more skim oil recovered from receiving more produced water.

Previous wording

Recycled Water Revenues. Revenue from recycled water includes the sale of produced water and recycled water for use in our customers’ completion activities. The decrease was due primarily to a decrease in recycled water volumes related to timing of water to be used in completions.

Current wording

Recycled Water Revenues. Revenue from recycled water includes the sale of produced water and recycled water for use in our customers’ completion activities. The decrease was due primarily to lower pricing for recycled water, partially offset by higher recycled water volumes related to timing of water to be used in completions.

Previous wording

Other Revenues. Other revenues primarily include reimbursements from construction projects, booster operating fees and generator rentals, water pipeline revenues, solids disposal revenues, land surface use revenues and brackish non-potable water revenues. The increase was due primarily to higher water pipeline revenue, including payments from a producer for committed volumes not delivered, due to our expanded Lea County Express Pipeline system (“LEX II”) commencing operations during the current quarter. This increase was partially offset by lower land surface use revenues, mining revenues and lease revenue from certain surface use and compensation agreements primarily due to the sale of our ranches in April 2024 (see Note 16 to our unaudited condensed consolidated financial statements included in this Quarterly Report). We also had lower reimbursements from construction projects, booster operating fees and generator rentals.

Current wording

Other Revenues. Other revenues primarily include reimbursements from construction projects, booster operating fees and generator rentals, water pipeline revenues, solids disposal revenues and brackish non-potable water revenues. The increase was due primarily to higher water pipeline revenue, including payments from a producer for committed volumes not delivered, due to our expanded Lea County Express Pipeline system (“LEX II”) commencing operations during the three months ended December 31, 2024. This increase was partially offset by lower reimbursements from construction projects, booster operating fees and generator rentals.

Previous wording

Cost of Sales-Excluding Impact of Derivatives. The decrease was due primarily to lower recycling costs and a decrease in disposal fees paid to third-parties, partially offset by costs incurred that will be reimbursed by producers for generator and fuel costs at various booster stations.

Current wording

Cost of Sales-Excluding Impact of Derivatives. The decrease was due primarily to lower costs incurred that will be reimbursed by producers for generator and fuel costs at various booster stations.

Previous wording

Operating and General and Administrative Expenses. The decrease was due primarily to lower utilities expense due to a negotiated long-term utility contract with lower rates, lower chemical expense due to purchasing fewer chemicals and using them more efficiently and lower repairs and maintenance expense due to the timing of repairs and tank cleaning. These decreases were partially offset by higher royalty expense due to volumes related to the LEX II pipeline commencing operations and increased volumes at certain other saltwater disposal wells.

Current wording

Operating and General and Administrative Expenses. The increase was due primarily to higher royalty expense due to volumes related to the LEX II pipeline commencing operations and increased volumes at certain other saltwater disposal wells and higher utilities expense due to increased produced water volumes processed, partially offset by lower bad debt expense.

Previous wording

Depreciation and Amortization Expense. The increase was due primarily to depreciation of newly developed facilities and infrastructure, partially offset by certain long-term assets being fully amortized, impaired or sold during the fiscal year ended March 31, 2024 and nine months ended December 31, 2024.

Current wording

Depreciation and Amortization Expense. The increase was due primarily to depreciation of newly developed facilities and infrastructure, partially offset by certain long-term assets being fully amortized, impaired or sold during the fiscal year ended March 31, 2025 and three months ended June 30, 2025.

Previous wording

Loss on Disposal or Impairment of Assets, Net. During the nine months ended December 31, 2024, we recorded a net loss of $11.0 million primarily related to the write down of the value of certain saltwater disposal wells as well as abandonment of certain capital projects and the retirement of certain other assets. We also recorded a $3.4 million loss from the settlement of a dispute related to a force majeure event, which resulted in the plugging and abandoning of a disposal well in a prior period. In addition, we recorded a net gain of $10.5 million primarily related to the sale of certain assets (see Note 16 to our unaudited condensed consolidated financial statements included in this Quarterly Report) and a gain of $2.0 million from insurance recoveries for certain saltwater disposal facilities and boosters damaged in a prior period. During the nine months ended December 31, 2023, we recorded a net loss of $17.1 million primarily related to the sale of certain assets and a net loss of $7.9 million related to the abandonment of certain capital projects and the retirement of certain assets. In addition, we recorded a gain of $3.2 million from insurance recoveries for certain saltwater disposal facilities and boosters damaged in a prior period.

Current wording

Loss (Gain) on Disposal or Impairment of Assets, Net. During the three months ended June 30, 2025, we recorded a net loss of $3.1 million primarily related to the write down of the value of certain saltwater disposal wells as well as abandonment of certain capital projects and the retirement of certain other assets. We also recorded a net loss of $1.2 million primarily related to the sale of certain assets (see Note 15 to our unaudited condensed consolidated financial statements included in this Quarterly Report). In addition, we recorded a gain of $0.7 million from insurance recoveries for certain saltwater disposal facilities and boosters damaged in a prior period. During the three months ended June 30, 2024, we recorded a net gain of $10.4 million primarily related to the sale of certain assets and a gain of $0.3 million from insurance recoveries for certain saltwater disposal facilities and boosters damaged in a prior period. In addition, we recorded a net loss of $0.1 million primarily related to the write down of the value of certain saltwater disposal wells as well as abandonment of certain capital projects and the retirement of certain assets.

Previous wording

Crude Oil Sales and Cost of Sales-Excluding Impact of Derivatives. The decreases in sales and cost of sales, excluding the impact of derivatives, were due primarily to lower sales volumes due to lower production on acreage dedicated to us in the DJ Basin during the three months ended December 31, 2024, compared to the three months ended December 31, 2023. Lower crude oil prices also contributed to the decrease.

Current wording

Crude Oil Sales and Cost of Sales-Excluding Impact of Derivatives. The decreases in sales and cost of sales, excluding the impact of derivatives, were due primarily to lower sales volumes because of lower production on acreage dedicated to us in the DJ Basin during the three months ended June 30, 2025, compared to the three months ended June 30, 2024. Lower crude oil prices also significantly contributed to the decrease.

Previous wording

During the three months ended December 31, 2024, the crude oil product margin decreased primarily due to lower volumes as discussed further above. The increase in the crude oil product margin per barrel for the three months ended December 31, 2024 was favorably impacted from the sale of the remaining pipeline transportation deficiency credits included in gross margin. When the impact of the sale of the pipeline transportation deficiency credits is removed, crude oil product margin per barrel realized is consistent during the three months ended December 31, 2024, compared to the three months ended December 31, 2023. Crude oil product margin calculations do not include gains and losses from derivatives that may offset the movement in the physical margin.

Current wording

During the three months ended June 30, 2025, the crude oil product margin decreased primarily due to lower volumes and lower prices as discussed further above. The increase in the crude oil product margin per barrel for the three months ended June 30, 2025 was favorably impacted from the sale of lower-priced inventory into a market of rising prices, compared to the opposite occurring in the prior period when higher-priced inventory was sold into a market of declining prices. Crude oil product margin calculations do not include gains and losses from derivatives that may offset the movement in the physical margin.

Previous wording

During the three months ended December 31, 2024, physical volumes on the Grand Mesa Pipeline averaged approximately 61,000 barrels per day, compared to approximately 70,000 barrels per day during the three months ended December 31, 2023. Lower contracted volumes were shipped on the Grand Mesa Pipeline due to lower production on acreage dedicated to us in the DJ Basin.

Current wording

During the three months ended June 30, 2025, physical volumes on the Grand Mesa Pipeline averaged approximately 55,000 barrels per day, compared to approximately 63,000 barrels per day during the three months ended June 30, 2024. Lower contracted volumes were shipped on the Grand Mesa Pipeline due to lower production on acreage dedicated to us in the DJ Basin.

Previous wording

Operating and General and Administrative Expenses. The increase was primarily due to a higher incentive compensation expense accrual during the three months ended December 31, 2024. This increase was partially offset by lower utilities expense on the Grand Mesa Pipeline and at our Cushing terminal from lower volumes flowing through the system and lower corporate cost allocations during the three months ended December 31, 2024, compared to the three months ended December 31, 2023.

Current wording

Operating and General and Administrative Expenses. The decrease was primarily due to lower incentive compensation expense accrued during the three months ended June 30, 2025, lower repairs and maintenance expense and lower utilities expense on the Grand Mesa Pipeline from lower volumes flowing through the system during the three months ended June 30, 2025, compared to the three months ended June 30, 2024. These decreases were partially offset by higher ad valorem taxes.

Previous wording

The following table summarizes the operating results of our Liquids Logistics segment for the periods indicated:

Current wording

The following table summarizes the operating results of our Liquids Logistics segment for the periods indicated. As discussed above, the operating results of our refined products and biodiesel businesses have been classified as discontinued operations and prior periods have been retrospectively adjusted.

Previous wording

(2) Cost and product margin (loss) per gallon excludes the impact of derivatives.

Current wording

(3) Cost and product margin per gallon excludes the impact of derivatives.

Previous wording

Butane Sales and Cost of Sales-Excluding Impact of Derivatives. The increases in sales and cost of sales, excluding the impact of derivatives, were primarily due to increased commodity prices during the three months ended December 31, 2024 compared to prices during the three months ended December 31, 2023. These increases were offset by lower volumes due to a weaker gasoline blending season and a weaker spot market during the three months ended December 31, 2024.

Current wording

Butane Sales and Cost of Sales-Excluding Impact of Derivatives. The increases in sales and cost of sales, excluding the impact of derivatives, during the three months ended June 30, 2025 compared to the three months ended June 30, 2024 were due primarily to a new contract to supply product to a third-party to export out of our Chesapeake terminal.

Previous wording

Other Products Sales and Cost of Sales-Excluding Impact of Derivatives. The decreases in sales and cost of sales, excluding the impact of derivatives, were primarily due to a decrease in commodity prices, primarily biodiesel prices and prices for RINs during the nine months ended December 31, 2024. This was partially offset by an increase in natural gasoline and isobutane sales due to stronger spot markets and consistent supply of asphalt during the nine months ended December 31, 2024.

Current wording

Other Products Sales and Cost of Sales-Excluding Impact of Derivatives. The decreases in sales and cost of sales, excluding the impact of derivatives, were due to a decrease in commodity prices during the three months ended June 30, 2025 compared with the three months ended June 30, 2024. Volumes increased due to strong spot markets for natural gasoline and isobutane and consistent supply of asphalt during the three months ended June 30, 2025.

Previous wording

Service Sales and Cost of Sales. The sales includes storage, terminaling and transportation services income. Revenues and cost of sales during the three months ended December 31, 2024 were consistent with the three months ended December 31, 2023.

Current wording

Service Sales and Cost of Sales. The sales includes storage, terminaling and transportation services income. Sales and cost of sales during the three months ended June 30, 2025 decreased due to the Wholesale Propane Disposition and the expiration of a throughput contract during the prior fiscal year.

Previous wording

Service Revenues. These revenues relate to billings to the noncontrolling interest holders for usage of the airplanes acquired in June and October 2024.

Current wording

Service Revenues. These revenues relate to billings to the noncontrolling interest holders for usage of the airplanes.

Previous wording

General and Administrative Expenses. The expenses during the three months ended December 31, 2024 decreased due to business insurance expense being lower for the period, as we paid an insurance company during the three months ended December 31, 2023 for the release of any supplementary calls related to our former crude marine business and a reduction in current year automobile claims. In addition, legal expenses were lower as several large cases ended and lease expense decreased due to subleasing part of our office space in Denver, Colorado and reducing our office space in Tulsa, Oklahoma.

Current wording

General and Administrative Expenses. The expenses during the three months ended June 30, 2025 were consistent with the prior year period.

Previous wording

We define EBITDA as net income (loss) attributable to NGL Energy Partners LP, plus interest expense, income tax expense (benefit), and depreciation and amortization expense. We define Adjusted EBITDA as EBITDA excluding net unrealized gains and losses on derivatives, lower of cost or net realizable value adjustments, gains and losses on disposal or impairment of assets, gains and losses on early extinguishment of liabilities, equity-based compensation expense, revaluation of liabilities and other. EBITDA and Adjusted EBITDA should not be considered as alternatives to net income, income before income taxes, cash flows from operating activities, or any other measure of financial performance calculated in accordance with GAAP, as those items are used to measure operating performance, liquidity or the ability to service debt obligations. We believe that EBITDA provides additional information to investors for evaluating our ability to make quarterly distributions to our unitholders and is presented solely as a supplemental measure. We believe that Adjusted EBITDA provides additional information to investors for evaluating our financial performance without regard to our financing methods, capital structure and historical cost basis. Further, EBITDA and Adjusted EBITDA, as we define them, may not be comparable to EBITDA, Adjusted EBITDA, or similarly titled measures used by other entities.

Current wording

We define EBITDA as net income (loss) attributable to NGL Energy Partners LP, plus interest expense, income tax expense (benefit), and depreciation and amortization expense. We define Adjusted EBITDA as EBITDA excluding net unrealized gains and losses on derivatives, lower of cost or net realizable value adjustments, gains and losses on disposal or impairment of assets, gains and losses on early extinguishment of liabilities, revaluation of liabilities and other. EBITDA and Adjusted EBITDA should not be considered as alternatives to net income, income from continuing operations before income taxes, cash flows from operating activities, or any other measure of financial performance calculated in accordance with GAAP, as those items are used to measure operating performance, liquidity or the ability to service debt obligations. We believe that EBITDA provides additional information to investors for evaluating our ability to make quarterly distributions to our unitholders and is presented solely as a supplemental measure. We believe that Adjusted EBITDA provides additional information to investors for evaluating our financial performance without regard to our financing methods, capital structure and historical cost basis. Further, EBITDA and Adjusted EBITDA, as we define them, may not be comparable to EBITDA, Adjusted EBITDA, or similarly titled measures used by other entities.

Previous wording

For purposes of our Adjusted EBITDA calculation, we make a distinction between realized and unrealized gains and losses on derivatives. During the period when a derivative contract is open, we record changes in the fair value of the derivative as an unrealized gain or loss. When a derivative contract matures or is settled, we reverse the previously recorded unrealized gain or loss and record a realized gain or loss. In our Crude Oil Logistics segment, we purchase certain crude oil barrels using the West Texas Intermediate (“WTI”) calendar month average (“CMA”) price and sell the crude oil barrels using the WTI CMA price plus the Argus CMA Differential Roll Component (“CMA Differential Roll”) per our contracts. To eliminate the volatility of the CMA Differential Roll, we entered into derivative instrument positions in January 2021 to secure a margin of approximately $0.20 per barrel on 1.5 million barrels per month from May 2021 through December 2023. Due to the nature of these positions, the cash flow and earnings recognized on a GAAP basis differed from period to period depending on the current crude oil price and future estimated crude oil price which were valued utilizing third-party market quoted prices. We recognized in Adjusted EBITDA the gains and losses from the derivative instrument positions entered into in January 2021 to properly align with the physical margin we hedged each month through the term of this transaction. This representation aligns with management’s evaluation of the transaction. The derivative instrument positions we entered into related to the CMA Differential Roll expired as of December 31, 2023, and we have not entered into any new derivative instrument positions related to the CMA Differential Roll.

Current wording

For purposes of our Adjusted EBITDA calculation, we make a distinction between realized and unrealized gains and losses on derivatives. During the period when a derivative contract is open, we record changes in the fair value of the derivative as an unrealized gain or loss. When a derivative contract matures or is settled, we reverse the previously recorded unrealized gain or loss and record a realized gain or loss.

Previous wording

(5) Amounts represent accretion expense for asset retirement obligations, expenses incurred related to legal and advisory costs associated with acquisitions and dispositions and unrealized gains/losses on investments and marketable securities.

Current wording

(3) Amounts represent accretion expense for asset retirement obligations, expenses incurred related to legal and advisory costs associated with acquisitions and dispositions, unrealized gains and losses on investments and marketable securities and a loss from a legal dispute.

Previous wording

Our principal sources of liquidity and capital resource requirements are cash flows from our operations, borrowings under the $600.0 million asset-based revolving credit facility (“ABL Facility”), issuing long-term notes, common and/or preferred units, loans from financial institutions, asset securitizations or asset sales. We expect our primary cash outflows to be related to capital expenditures, interest, repayment of debt maturities and distributions.

Current wording

Our principal sources of liquidity and capital resource requirements are cash flows from our operations, borrowings under our asset-based revolving credit facility (“ABL Facility”), issuing long-term notes, common and/or preferred units, loans from financial institutions, asset securitizations or asset sales. We expect our primary cash outflows to be related to capital expenditures, interest, repayment of debt maturities and distributions.

Previous wording

Commitments under the ABL Facility are $600.0 million, subject to a borrowing base, and includes a sub-limit for letters of credit of $200.0 million. At December 31, 2024, $226.0 million was outstanding under the ABL Facility and we had letters of credit outstanding of $87.6 million. The ABL Facility is scheduled to mature at the earliest of (a) February 2, 2029 or (b) 91 days prior to the earliest maturity date in respect to any of our indebtedness in an aggregate principal amount of $50.0 million or greater, subject to certain exceptions.

Current wording

Total commitments under the ABL Facility are $475.0 million, subject to a borrowing base, and includes a sub-limit for letters of credit of $200.0 million. At June 30, 2025, $37.0 million was outstanding under the ABL Facility, letters of credit outstanding were $51.8 million and we had a borrowing base of $313.6 million. The ABL Facility is scheduled to mature at the earliest of (a) February 2, 2029 or (b) 91 days prior to the earliest maturity date in respect to any of our indebtedness in an aggregate principal amount of $50.0 million or greater, subject to certain exceptions.

Previous wording

As of December 31, 2024, our current assets exceeded our current liabilities by approximately $169.4 million.

Current wording

As of June 30, 2025, our current assets exceeded our current liabilities by approximately $116.8 million.

Previous wording

On February 2, 2024, we closed on our private offering of $900.0 million of the 2029 Senior Secured Notes and $1.3 billion of the 2032 Senior Secured Notes. Interest on the 2029 Senior Secured Notes and 2032 Senior Secured Notes is payable on February 15, May 15, August 15 and November 15 of each year, beginning on May 15, 2024.

Current wording

On February 2, 2024, we closed on our private offering of $900.0 million of 8.125% senior secured notes due 2029 (“2029 Senior Secured Notes”) that mature on February 15, 2029 and $1.3 billion of 8.375% senior secured notes due 2032 (“2032 Senior Secured Notes”) that mature on February 15, 2032. Interest on the 2029 Senior Secured Notes and 2032 Senior Secured Notes is payable on February 15, May 15, August 15 and November 15 of each year.

Previous wording

On February 2, 2024, we entered into a new seven-year $700.0 million senior secured Term Loan B. The Term Loan B matures on February 2, 2031 and will amortize in equal quarterly installments in aggregate annual amounts equal to 1.0% of the original principal amount beginning with the quarter ended June 30, 2024, with the balance payable on maturity.

Current wording

On February 2, 2024, we entered into a new seven-year $700.0 million Term Loan B. The Term Loan B matures on February 2, 2031 and will amortize in equal quarterly installments in aggregate annual amounts equal to 1.0% of the original principal amount, with the balance payable on maturity. The amount outstanding at June 30, 2025 is $691.3 million.

Previous wording

(1) Amounts for the three months and nine months ended December 31, 2024 are related to a transaction classified as an acquisition of assets in a prior period.

Current wording

(1) Amount for the three months ended June 30, 2024 is related to a transaction classified as an acquisition of assets in a prior period.

Previous wording

Capital expenditures for the fiscal year ending March 31, 2025 are expected to be approximately $210 million.

Current wording

Capital expenditures for the fiscal year ending March 31, 2026 are expected to be approximately $105 million.

Previous wording

On April 4, 2024, the board of directors of our GP declared a cash distribution of 55.4% of the outstanding distribution arrearages through the quarter ended March 31, 2024 to the holders of the Class B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (“Class B Preferred Units”), the Class C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (“Class C Preferred Units”) and the 9.00% Class D Preferred Units (“Class D Preferred Units”). The total distribution of $120.0 million was made on April 18, 2024 to the holders of record at the close of trading on April 12, 2024.

Current wording

On June 18, 2025, the board of directors of our GP declared a cash distribution for the quarter ended June 30, 2025 to the holders of the Class B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (“Class B Preferred Units”), the Class C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (“Class C Preferred Units”) and the 9.00% Class D Preferred Units (“Class D Preferred Units”). The total distribution of $26.2 million was made on July 15, 2025 to the holders of record at the close of trading on July 1, 2025.

Previous wording

Our contractual obligations primarily consist of purchase commitments, outstanding debt principal and interest obligations, operating lease obligations, pipeline commitments, asset retirement obligations and other commitments.

Current wording

Our contractual obligations primarily consist of purchase commitments, outstanding debt principal and interest obligations, operating lease obligations, asset retirement obligations and other commitments.

Previous wording

The following table summarizes the sources (uses) of cash and cash equivalents for the periods indicated (see the footnotes to our unaudited condensed consolidated financial statements included in this Quarterly Report for the footnotes referenced in the table):

Current wording

The following table summarizes the sources (uses) of cash and cash equivalents for the periods indicated related to continuing operations (see the footnotes to our unaudited condensed consolidated financial statements included in this Quarterly Report for the footnotes referenced in the table):

Previous wording

Operating Activities. The decrease in net cash provided by operating activities during the nine months ended December 31, 2024 was due primarily to lower earnings from operations as well as fluctuations in working capital, particularly accounts receivable and accounts payable, due to lower crude oil volumes and lower crude oil prices and the timing of invoices and payments on construction projects, partially offset by increased purchases and sales of natural gas liquids due to seasonal demand and fluctuations in inventory due to increased purchases and sales of natural gas liquids.

Current wording

Operating Activities-Continuing Operations. The increase in net cash provided by operating activities during the three months ended June 30, 2025 was due primarily to higher earnings from operations as well as fluctuations in working capital, particularly accounts receivable and accounts payable, due to lower crude oil volumes and lower crude oil prices, lower purchases and sales of natural gas liquids due to the Wholesale Propane Disposition and the timing of invoices and payments on construction projects as well as fluctuations in inventory due to building our natural gas liquids inventories in anticipation of the butane blending and heating seasons. Also, on June 13, 2024, we paid LCT Capital, LLC (“LCT”) $63.3 million related to the legal judgment against us, of which $27.2 million represented interest and $0.1 million of costs awarded to LCT.