Riley Exploration Permian, Inc.
For the period ended Jun 30, 2026. Filed Aug 5, 2026.
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A company's report for each of its first three quarters. The financial statements are not audited. It shows how the business has moved since the last annual report, and what management says changed.
Jun 30, 2026 · Filed Aug 5, 2026
REPX$41.23+2.8%Stored close · as of Nov 6, 2026
What changed in Management’s Discussion and Analysis?
Read the current filingPrevious report: 10-Q
Period ended 2026-03-31; filed 2026-05-06.
0001001614-26-000022
Item 2. Management's Discussion and Analysis of Financial Condition and Results of OperationsCurrent report: 10-Q
Period ended 2026-06-30; filed 2026-08-05.
0001001614-26-000051
Item 2. 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 83 previous paragraphs and 98 current paragraphs.
47 unchanged; 24 reworded; 26 added; 12 removed; 0 previous and 1 current paragraphs rearranged.
Tables are not compared: 14 previous and 17 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 (26)
Current report
During the second quarter of 2026, certain portions of our New Mexico operations continued to experience production interruptions and curtailments resulting from third-party midstream and gas processing constraints. Following the unplanned outage at a third-party gas processing facility that began in late March 2026, we continued to experience periodic processing limitations, maintenance-related curtailments, and reduced gas takeaway capacity affecting a portion of our New Mexico production during the quarter. These events resulted in the temporary shut-in of certain wells and reduced production from impacted areas. The temporary shut-in was substantially resolved by the end of May with production resuming to normal levels for June.
Current report
The effects of these disruptions were partially mitigated by the limited geographic scope of the affected production, our ability to restore certain wells to production as processing capacity became available, and strong operating performance from our Texas assets. As a result, while the curtailments negatively impacted certain production volumes during the quarter, they did not materially affect our overall financial condition or liquidity.
Current report
Oil revenues increased by $96.3 million. Our realized oil prices increased by $32.11 per Bbl, which was the result of a $31.08 increase in the average WTI price. Average daily oil volumes increased by 40%, primarily due to new wells turned to sales and the contribution of the Silverback Acquisition.
Current report
NGL revenues decreased by $3.4 million. Our realized NGL prices before GP&T costs increased by $2.98 per Bbl which was the result of an increase in the average Mont Belvieu prices realized. Our realized NGL prices net of GP&T costs decreased by $5.46 primarily due to higher allocated GP&T costs when realized natural gas prices are negative.
Current report
Six months ended June 30, 2026, compared to six months ended June 30, 2025
Current report
Oil revenues
Current report
Oil revenues increased by $122.7 million. Our realized oil prices increased by $15.81 per Bbl, which was the result of a $16.17 increase in the average WTI price. Daily oil volumes increased by 34%, primarily due to new wells turned to sales and the Silverback Acquisition.
Current report
Natural gas revenues
Current report
Natural gas revenues decreased by $20.4 million driven by negative realized natural gas prices that more than offset an increase in production volumes. Our realized natural gas prices before GP&T costs decreased $3.75 per Mcf, which was the result of an increase in negative Permian basis differentials due to regional pipeline constraints, partially offset by a $0.15 increase in the average Henry Hub price.
Current report
NGL revenues
Current report
NGL revenues decreased by $10.4 million. Our realized NGL prices before GP&T costs decreased by $2.24, per Bbl which was the result of a decrease in the average Mont Belvieu prices realized. Our realized NGL prices net of GP&T costs decreased by $8.49 primarily due to higher allocated GP&T costs when realized natural gas prices are negative.
Current report
The Company’s LOE increased by $10.6 million for the three months ended June 30, 2026, compared to the three months ended June 30, 2025, primarily due to a $6.4 million increase related to the Silverback Acquisition, a $3.0 million increase in workover expenses to return wells to production and a $1.2 million increase in Champions' third-party water disposal costs to align with our increased drilling pace.
Current report
The Company’s LOE increased by $16.3 million for the six months ended June 30, 2026, compared to the six months ended June 30, 2025, primarily due to a $10.8 million increase related to the Silverback Acquisition, a $3.1 million increase in workover expenses to return wells to production and a $1.1 million increase in Champions' third-party water disposal costs to align with our increased drilling pace.
Current report
Production and ad valorem taxes increased by $5.3 million for the three months ended June 30, 2026, compared to the three months ended June 30, 2025, primarily due to higher revenues from increased production volumes, including an increase in volumes from the Silverback Acquisition and higher oil prices.
Current report
DD&A expense increased by $5.1 million and $11.7 million, respectively, for the three and six months ended June 30, 2026, compared to the three and six months ended June 30, 2025, primarily due to higher production volumes, including an increase in volumes from the Silverback Acquisition which increased depletion expense by approximately $2.4 million and $6.8 million, respectively.
Current report
Impairments of Oil and Natural Gas Properties
Current report
There was no impairment loss during the three and six months ended June 30, 2026. There was a non-cash impairment loss on proved properties of $1.2 million during the three and six months ended June 30, 2025, which related to a decrease in fair value of certain properties in New Mexico outside of the Company's core acreage in the Red Lake field.
Current report
Transaction Costs
Current report
Transaction costs represent costs incurred on successful or unsuccessful commercial transactions, business combinations or unsuccessful asset acquisitions. There were no transaction costs during the three and six months ended June 30, 2026. During the three and six months ended June 30, 2025, transaction costs of $1.9 million primarily related to the Silverback Acquisition.
Current report
Gain (Loss) on Derivatives, net
Current report
Our working capital deficit increased by $90 million primarily due to higher working capital required to fund our drilling program, revenue payable from higher oil prices and changes in our derivative assets and liabilities.
Current report
The increase in net cash provided by operating activities was primarily due to higher revenues from increased production and higher oil prices, along with an increase in advances from joint interest owners, partially offset by higher operating expenses associated with increased production and derivative settlement losses resulting from higher oil prices.
Current report
(1)These additions and corresponding assets were sold as part of the sale of our midstream assets to Targa in 2025.
Current report
Capital expenditures for oil and natural gas properties increased by $55.9 million due to an increase in drilling and completion activity and an increase in infrastructure investments. Funds held in escrow relate to the Silverback Acquisition, which closed on July 1, 2025.
Current report
Net borrowings increased by $14 million, partially offset by the repurchase of common shares of $5 million and an increase in repurchases of common shares for tax withholding of 1.5 million.
Current report
On April 30, 2026, the Company entered into the eighteenth amendment to the Credit Facility, which increased the Company’s borrowing base from $400 million to $425 million and documented the Company's election to maintain commitments thereunder at $400 million. In addition, the eighteenth amendment shortens the springing maturity of the Credit Facility in advance of the Senior Notes from 181 days to 91 days, effectively extending the maturity date for the Credit Facility to January 2028, given the April 2028 stated maturity of the Senior Notes.
Removed paragraphs (12)
Previous report
Beginning on March 28, 2026, and continuing subsequent to the balance sheet date, an unplanned outage at a third-party gas processing facility in New Mexico operated by one of our midstream counterparties required us to shut in a significant portion of our New Mexico production. The duration of the outage remains uncertain; however, the impact on the three months ended March 31, 2026 was not material.
Previous report
Based on the limited geographic scope of affected production, the continued strong performance of our Texas operations, and our reallocation of capital to accelerated drilling and completion activity in Texas, we do not currently expect the outage to have a material impact on our second quarter or full-year 2026 production volumes, revenues, or results of operations.
Previous report
Oil revenues increased by $26.4 million, as higher volumes more than offset the impact of lower prices. Oil production volume increased by 29% from wells acquired in the Silverback Acquisition and new wells turned to sales. Realized oil price decreased by $1.23 per Bbl, as lower West Texas Sour pricing more than offset a $0.96 increase in the average WTI price.
Previous report
NGL revenues decreased by $7.0 million, as lower prices and higher GP&T costs more than offset higher volumes. Realized NGL prices before GP&T costs decreased by $7.31 per Bbl, primarily due to lower Mont Belvieu pricing. Higher GP&T costs resulted from increased volumes, as well as from higher allocations of the GP&T costs from lower realized natural gas revenues before GP&T costs. NGL production volumes increased 80% due to new wells turned to sales, increased processing capacity from our midstream partner in our Champions field and from wells acquired in the Silverback Acquisition.
Previous report
The Company’s LOE increased by $5.7 million for the three months ended March 31, 2026, compared to the three months ended March 31, 2025. The LOE increase of approximately $4.5 million and workover expense increase of approximately $1.2 million were driven primarily by the Silverback Acquisition. The LOE increase was due to higher field payroll and other variable costs driven by increased production volumes.
Previous report
DD&A expense increased by $6.6 million for the three months ended March 31, 2026, compared to the three months ended March 31, 2025, primarily due to higher production volumes, which increased depletion expense by approximately $5.7 million, in addition to the inclusion of the Silverback Acquisition, which increased depletion expense by approximately $3.5 million. These increases were partially offset by a lower depletion rate in our Red Lake field, which decreased depletion expense by approximately $2.6 million due to reserve estimate revisions.
Previous report
Loss on Derivatives, net
Previous report
Our working capital deficit increased by $113 million primarily due to a $75 million increase in current derivative liabilities for our unrealized positions due to the increased crude oil pricing, an increase of $11 million related to prepayments from partners and a $4.5 million increase in the current liability for the earnout payments related to the Silverback Acquisition, both of which are included in other current liabilities. Excluding the impact of derivatives, the increased working capital deficit corresponds with increased development activity, which should convert to operating cash flow over time.
Previous report
The decrease in net cash provided by operating activities was primarily attributable to derivative settlements received in the prior year versus paid in the current year and an increase in accounts receivable, both driven by higher crude oil prices. This was partially offset by an increase in advances from joint interest owners.
Previous report
Capital expenditures for oil and natural gas properties increased by $13.4 million due to an increase in wells drilled and completed. The Company had proceeds from the sale of non-operated wells in 2026.
Previous report
The Company decreased net debt repayments by $13.0 million, partially offset by repurchased common shares of $4.0 million.
Previous report
The borrowing base under the Company's Credit Facility was $400 million with outstanding borrowings of $107 million at March 31, 2026, and $293 million of available borrowing capacity.
Reworded paragraphs (24)
Previous wording
Commodity prices remain volatile. General domestic and international economic, market and political conditions, including military conflicts, global economic growth, unpredictability of tariffs, actions of OPEC+ countries, and changes to the current political environment could prolong market volatility and cause a decline in commodity prices.
Current wording
Commodity prices remain volatile. General domestic and international economic, market and political conditions, including military conflicts, global economic growth, unpredictability of new tariffs, actions of OPEC+ countries and changes to the current political environment could prolong market volatility and continue to cause a decline in commodity prices.
Previous wording
The Company cannot estimate the length or gravity of the future impact these conditions will have on the Company's results of operations, financial position, liquidity and the value of the oil and natural gas reserves.
Current wording
The Company cannot estimate the length or gravity of the future impact these events will have on the Company's results of operations, financial position, liquidity and the value of oil and natural gas reserves.
Previous wording
We expect our reliance on this counterparty to diminish once additional processing and takeaway capacity becomes available from the new high-pressure gathering and trunk line infrastructure currently being constructed by Targa in Eddy County, New Mexico under the A&R Gas Purchase Agreement. See Note 15 – Commitments and Contingencies for further discussion of the Gas Purchase Agreement. The in-service date of the new Targa pipeline system is currently expected to occur before the end of 2026. We will continue to monitor the situation.
Current wording
We continue to monitor the reliability and capacity of third-party midstream infrastructure serving our New Mexico acreage. To mitigate the risk of future processing and takeaway constraints of the nature experienced during the period, Targa is constructing new gathering and high-pressure trunkline infrastructure in Eddy County, New Mexico pursuant to the A&R Gas Purchase Agreement. Upon completion, this infrastructure is expected to provide increased gathering, processing, and takeaway capacity that reduces our reliance on the affected third-party processing facilities. The in-service date of the new Targa pipeline system is currently expected to occur in the fourth quarter of 2026. See Note 15 – Commitments and Contingencies for additional information.
Previous wording
Comparison for the three months ended March 31, 2026, and 2025:
Current wording
Comparison for the three and six months ended June 30, 2026, and 2025:
Previous wording
(2)The Company's calculation of the effects of derivative settlements includes gains (losses) on the settlement of our commodity derivative contracts. These realized gains (losses), along with unrealized gains (losses) from changes in the fair value of derivatives, are included under other expense on the Company’s condensed consolidated statements of operations.
Current wording
(2)The Company's calculation of the effects of derivative settlements includes gains (losses) on the settlement of our commodity derivative contracts. These gains (losses), along with unrealized gains (losses) from changes in the fair value of derivatives, are included under other income (expense) on the Company’s condensed consolidated statements of operations.
Previous wording
The Company’s total oil and natural gas sales, net increased $11.4 million, or 11%. The following tables summarize the effects of price, volume and GP&T cost changes on our revenues from oil, natural gas and NGLs:
Current wording
The Company’s total oil and natural gas sales, net increased by $80.5 million or 94%. The following tables summarize the effects of price, volume and GP&T costs changes on our revenues from oil, natural gas and NGLs:
Previous wording
Natural gas revenues decreased by $7.9 million, as lower prices and higher GP&T costs more than offset higher volumes. Despite a $0.57 per Mcf increase in the average Henry Hub price, realized natural gas prices before GP&T costs decreased by $2.92, which was the result of an increase in the negative basis differentials due to regional pipeline constraints. Natural gas production volumes increased by 70% due to acquired wells from the Silverback Acquisition, increased processing capacity from our midstream partner in our Champions field and new wells turned to sales.
Current wording
Natural gas revenues decreased by $12.5 million driven by negative realized natural gas prices that more than offset an increase in production volumes. Our realized natural gas prices before GP&T costs decreased by $4.80 per Mcf, which was the result of an increase in negative Permian basis differentials due to regional pipeline constraints in addition to a $0.24 decrease in the average Henry Hub price.
Previous wording
The following table presents the Company's operating costs and expenses and other expenses:
Current wording
The following table presents the Company's operating costs and expenses and other (income) expenses:
Previous wording
Production and ad valorem taxes increased by $2.4 million for the three months ended March 31, 2026, compared to the three months ended March 31, 2025, primarily due to increased production in both our Champions and Red Lake fields, with higher production in Red Lake due to the Silverback Acquisition, and an increase in crude oil prices, as well as the reversal of a previously accrued liability related to the Environmental Protection Agency’s waste emission charge that was nullified in the first quarter of 2025.
Current wording
Production and ad valorem taxes increased by $7.7 million for the six months ended June 30, 2026, compared to the six months ended June 30, 2025, primarily due to higher revenues from increased production volumes, including an increase in volumes from the Silverback Acquisition and higher oil prices, partially offset by the reversal of $0.8 million for a previously accrued liability related to the Environmental Protection Agency’s waste emission charge that was nullified in the first quarter of 2025.
Previous wording
Total G&A expense increased by $1.6 million for the three months ended March 31, 2026, compared to the three months ended March 31, 2025. Administrative costs increased by $0.7 million primarily due to increased employee headcount. Stock-based compensation expensed increased by $0.9 million due to an increase in outstanding equity awards.
Current wording
Total G&A expense increased by $3.8 million and $5.4 million for the three and six months ended June 30, 2026, compared to the three and six months ended June 30, 2025, respectively, primarily due to increased headcount and higher incentive compensation.
Previous wording
Interest expense, net decreased by $0.3 million for the three months ended March 31, 2026, compared to the three months ended March 31, 2025, primarily due to a lower total debt balance along with lower interest rates on borrowings under our Credit Facility.
Current wording
Interest expense, net decreased by $0.4 million and $0.7 million, respectively, for the three and six months ended June 30, 2026, compared to the three and six months ended June 30, 2025, respectively, primarily due to lower interest rates on the Credit Facility and a lower principal balance on the Senior Notes.
Previous wording
The Company recognizes settlements and changes in the fair value of our derivative contracts as a single component within other expense in our condensed consolidated statements of operations. We have oil and natural gas derivative contracts, including fixed price swaps, basis swaps and collars, that settle against various indices. The following table presents the components of the Company's loss on derivatives, net:
Current wording
The Company recognizes settlements and changes in the fair value of our derivative contracts as a single component within other income (expense) in our condensed consolidated statements of operations. We have oil and natural gas derivative contracts, including fixed price swaps, basis swaps and collars, that settle against various indices. The following table presents the components of the Company's gain (loss) on derivatives, net:
Previous wording
Cash gains or losses on settled derivative contracts relate to contracts that settle during the period and are a function of the difference in settled versus contractual prices and the associated hedged volumes for each underlying commodity. Non-cash gains or losses on derivatives relate to unsettled contracts and are a function of changes in derivative fair values associated with fluctuations in the forward price curves for the commodities relative to contractual pricing and the associated hedged volumes for each underlying commodity for our derivative contracts outstanding.
Current wording
Cash gains or losses on settled derivative contracts related to contracts that settle during the period and are a function of the difference in settled versus contractual prices and the associated hedged volumes for each underlying commodity. Non-cash gains or losses on derivatives relate to unsettled contracts and are a function of changes in derivative fair values associated with fluctuations in the forward price curves for the commodities relative to contractual pricing and the associated hedged volumes for each underlying commodity for our derivative contracts outstanding.
Previous wording
The decrease in current income tax expense was primarily attributable to higher capital spending during the three months ended March 31, 2026, compared to the three months ended March 31, 2025. The deferred income tax benefit increased primarily due to a higher non-cash loss on derivatives over the same period.
Current wording
The increase in deferred income tax expense during the three months ended June 30, 2026, is primarily due to a higher non-cash benefit on derivatives. The decrease in current income tax expense was primarily attributable to higher capital spending during the six months ended June 30, 2026, compared to the six months ended June 30, 2025.
Previous wording
The business of exploring for, developing and producing oil and natural gas is capital intensive. Because oil, natural gas and NGL reserves are a depleting resource, we must make capital investments, like all upstream operators, to sustain and grow production. The Company’s principal liquidity requirements are to finance our operations, fund capital expenditures, fund acquisitions and joint venture commitments, pay dividends and satisfy any indebtedness obligations. Cash flows are subject to a number of variables, including the level of oil and natural gas production and prices, and the significant capital expenditures required to more fully develop the Company’s oil and natural gas properties. Historically, our primary sources of capital funding and liquidity have been our cash on hand, cash flow from operations, borrowings under our Credit Facility and the issuance of our Senior Notes. At times and as needed, we may also issue debt or equity securities, including through transactions under our shelf registration statement filed with the SEC. We estimate the combination of the sources of capital discussed above will continue to be adequate to meet our short and long-term liquidity needs.
Current wording
The business of exploring for, developing and producing oil and natural gas is capital intensive. Because oil, natural gas and NGL reserves are a depleting resource, like all upstream operators, we must make capital investments to sustain and grow production. The Company’s principal liquidity requirements are to finance our operations, fund capital expenditures, fund acquisitions and joint venture commitments, pay dividends and satisfy any indebtedness obligations. Cash flows are subject to a number of variables, including the level of oil and natural gas production and prices, and the significant capital expenditures required to more fully develop the Company’s oil and natural gas properties. Historically, our primary sources of capital funding and liquidity have been our cash on hand, cash flow from operations, borrowings under our Credit Facility and the issuance of our Senior Notes. At times and as needed, we may also issue debt or equity securities, including through transactions under our shelf registration statement filed with the SEC. We estimate the combination of the sources of capital discussed above will continue to be adequate to meet our short and long-term liquidity needs.
Previous wording
Working capital represents the funds available to meet day-to-day operational needs and is the difference in our current assets and our current liabilities. Working capital is an indication of liquidity and potential need for short-term funding. The change in our working capital requirements is driven generally by changes in accounts receivable, accounts payable, commodity prices, credit extended to, and the timing of collections from customers, the level and timing of spending for expansion activity, and the timing of debt maturities. Our working capital fluctuates as our drilling and completion activity changes with periods of higher and lower activity. We utilize our Credit Facility and cash on hand to manage the timing of cash flows and fund short-term working capital deficits. At March 31, 2026, we had $293 million of undrawn capacity under our Credit Facility. The following table presents the components of working capital:
Current wording
Working capital represents the funds available to meet day-to-day operational needs and is the difference in our current assets and our current liabilities. Working capital is an indication of liquidity and potential need for short-term funding. The change in our working capital requirements is driven generally by changes in accounts receivable, accounts payable, commodity prices, credit extended to, and the timing of collections from customers, the level and timing of spending for expansion activity, and the timing of debt maturities. Our working capital fluctuates as our drilling and completion activity changes with periods of higher and lower activity. We utilize our Credit Facility and cash on hand to manage the timing of cash flows and fund short-term working capital deficits. At June 30, 2026, we had $262 million of undrawn capacity under our Credit Facility. The following table presents the components of working capital:
Previous wording
Net cash provided by operating activities were $47.2 million for the three months ended March 31, 2026, compared to $50.4 million for the three months ended March 31, 2025, and primarily consisted of the following:
Current wording
Net cash provided by operating activities were $110.7 million for the six months ended June 30, 2026, compared to $84.0 million for the six months ended June 30, 2025, and primarily consisted of the following:
Previous wording
(1)Operating expenses include LOE, production and ad valorem taxes, administrative costs and other minor operating expenses.
Current wording
(1)Operating expenses include LOE, production and ad valorem taxes, administrative costs, transaction costs and other miscellaneous operating expenses.
Previous wording
Net cash flows used in investing activities were $28.8 million for the three months ended March 31, 2026, compared to $25.4 million for the three months ended March 31, 2025, and primarily consisted of the following:
Current wording
Net cash flows used in investing activities were $101.7 million for the six months ended June 30, 2026, compared to $70.5 million for the six months ended June 30, 2025, and primarily consisted of the following:
Previous wording
Net cash flows used in financing activities were $20.4 million for the three months ended March 31, 2026, compared to $29.2 million for the three months ended March 31, 2025, and primarily consisted of the following:
Current wording
Net cash flows used in financing activities were $6.2 million for the six months ended June 30, 2026, compared to $12.7 million for the six months ended June 30, 2025, and primarily consisted of the following:
Previous wording
The Senior Notes had a principal balance of $140 million as of March 31, 2026.
Current wording
The Credit Facility and Senior Notes had a principal balance of $138 million and $135 million, respectively, as of June 30, 2026.
Previous wording
For the three months ended March 31, 2026, the Company recognized quarterly dividends totaling approximately $8.6 million, with $8.4 million paid in cash and $0.2 million accrued for the holders of unvested restricted stock awards.
Current wording
For the six months ended June 30, 2026, the Company recognized quarterly dividends totaling approximately $17.3 million, with $17.0 million paid in cash and $0.3 million accrued for the holders of unvested restricted stock awards.
Previous wording
As of March 31, 2026, the Company had a remaining volume commitment of five years with Targa, formerly Stakeholder, in Texas. The Company also had natural gas delivery commitments under the A&R Tolling Agreement and a remaining equity commitment under the Second Amendment to the A&R LLC Agreement to fund our portion of the capital budget for the RPC Power joint venture. The Company also entered into the A&R Gas Purchase Agreement that required an acreage dedication and a minimum volume commitment to Targa for a significant portion of our natural gas production in New Mexico. This agreement is expected to commence before the end of 2026. In addition, the Company entered into the Waterbridge Agreement, which includes minimum produced water volume commitments for a portion of our New Mexico operations and is expected to be in service in September 2026. See Note 15 - Commitments and Contingencies for additional information.
Current wording
As of June 30, 2026, the Company had a remaining volume commitment that expires the earlier of achieving a specified quantity of cumulative volumes delivered or by the contract expiration date in 2031 with Targa, formerly Stakeholder Midstream, LLC, in Texas. The Company also had natural gas delivery commitments under the A&R Tolling Agreement and a remaining equity commitment under the Second Amendment to the A&R LLC Agreement to fund our portion of the capital budget for the RPC Power joint venture. The Company also entered into the A&R Gas Purchase Agreement that required an acreage dedication and a minimum volume commitment to Targa for a significant portion of our natural gas production in New Mexico. This agreement is expected to commence in the fourth quarter of 2026. In addition, the Company entered into the Waterbridge Agreement, which includes minimum produced water volume commitments for a portion of our New Mexico operations and is expected to be in service in the fourth quarter of 2026. See Note 15 - Commitments and Contingencies for additional information.
Previous wording
The Company's critical accounting estimates are described in "Critical Accounting Estimates" within "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" in the 2025 Annual Report. The accounting estimates used in preparing our interim condensed consolidated financial statements for thethree months ended March 31, 2026, are the same as those described in the 2025 Annual Report.
Current wording
The Company's critical accounting estimates are described in "Critical Accounting Estimates" within "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" and Note 1 of the Notes to the Consolidated Financial Statements in the 2025 Annual Report. The accounting estimates used in preparing our interim condensed consolidated financial statements for thesix months ended June 30, 2026, are the same as those described in the 2025 Annual Report.
Rearranged current paragraphs (1)
Current report — wording carried from elsewhere
The Company’s total oil and natural gas sales, net increased by $91.9 million or 49%. The following tables summarize the effects of price, volume and GP&T costs changes on our revenues from oil, natural gas and NGLs: