DEC 10-K & 10-Q changes, risk factors and insider trading
Diversified Energy Co · NYSE · Crude Petroleum & Natural Gas · CIK 1922446 · All filings on SEC.gov
At a glance
What changed in the latest 10-K
Comparison not available: Not available: fewer than two 10-K filings on EDGAR to compare (only one so far)..
What changed in the latest 10-Q
Risk Factors
New heading “We have limited historical experience as an operator of development programs.”
New heading “Our development activities are subject to risks and uncertainties that are not present, or are present to a lesser degree, in our existing producing asset base.”
New heading “Estimates of reserves, drilling inventory and future development opportunities are inherently uncertain and may prove to be inaccurate.”
Largest changes
“Our development activities are subject to risks and uncertainties that are not present, or are present to a lesser degree, in our existing producing asset base.”see in full comparison
“Estimates of reserves, drilling inventory and future development opportunities are inherently uncertain and may prove to be inaccurate.”see in full comparison
“We have limited historical experience as an operator of development programs.”see in full comparison
“Any of these events may result in increases in costs, delays in production, lower-than-expected recoveries, impairment of capital invested in development projects and reduced returns.”see in full comparison
“Success in development programs depends upon effective well planning, capital allocation, execution of drilling and completion operations, reservoir evaluation, leasing, permitting, and project management. Executing these operations will require us to engage and rely upon drilling contractors, completion crews and other oilfield services providers, whose availability, performance and pricing are outside our control. …”see in full comparison
“Actual drilling results may differ materially from our expectations. Wells that we believe are commercially attractive based on seismic interpretation or geologic analysis may fail to achieve anticipated production rates, recoveries or economic returns. New information obtained through drilling and production activities may require us to revise reserve estimates, development plans, drilling inventories and expected future cash flows.”see in full comparison
Full comparison: every changed paragraph (25)
There have been no material changes to the Company’s “Risk Factors” previously disclosed in Part I, Item 1A of our annualAnnual reportReport on Form 10-K for the year ended December 31, 2025.2025, Forexcept aas detailedprovided discussion of the risks that affect our business, please refer to Part I, Item 1A “Risk Factors” in our annual report on Form 10-K for the year ended December 31, 2025.below.
We have limited historical experience as an operator of development programs.
We have initiated an operated development program which will require us to devote additional financial, technical and operational resources to drilling and completion activities. Development activities generally require us to commit capital substantially in advance of realizing production and cash flows, which may increase the variability of returns compared to our historical acquisition strategy.
Although we have drilled wells in various basins in the past and we have highly skilled personnel with significant drilling and completion experience through prior acquisitions, including our Chief Operating Officer, who previously oversaw the drilling program at Maverick Natural Resources, our historical business model has primarily focused on the acquisition, optimization and operation of existing producing assets.
Success in development programs depends upon effective well planning, capital allocation, execution of drilling and completion operations, reservoir evaluation, leasing, permitting, and project management. Executing these operations will require us to engage and rely upon drilling contractors, completion crews and other oilfield services providers, whose availability, performance and pricing are outside our control. Our development activities may not achieve expected results, and our returns could be adversely affected if development costs increase, reserve estimates are revised downward, or wells fail to perform as anticipated. In addition, we cannot provide assurance that unproved property acquired by us will be profitably developed, that wells drilled in connection with our development activities will be productive, or that we will recover all or any portion of our investment in such unproved property or wells.
Our development activities are subject to risks and uncertainties that are not present, or are present to a lesser degree, in our existing producing asset base.
Historically, a substantial portion of our business has consisted of acquiring and operating existing producing assets. As we increase our investment in drilling and development activities, we are exposed to additional risks, including:
•dry holes, or wells that are productive but do not produce sufficient volumes to recover drilling and completion and operating costs, or to achieve targeted returns;
•drilling or completion delays, or the curtailment or cancellation of planned activity;
•cost overruns and increases in drilling and completion costs;
•shortages of or delays in obtaining qualified personnel or equipment, including rigs, pressure pumping crews, tubulars, sand, water, chemicals and other equipment or critical services;
•unexpected geological conditions;
•drilling hazards and mechanical failures;
•well control incidents, blowouts, fires and environmental events;
•leasing or title problems;
•delays in obtaining permits and regulatory approvals, and environmental, health and safety requirements applicable to drilling and completion operations;
•adverse weather and surface access constraints;
•inability to secure or dispose of water used in drilling and completion operations; and
•insufficient takeaway, gathering or processing capacity.
Any of these events may result in increases in costs, delays in production, lower-than-expected recoveries, impairment of capital invested in development projects and reduced returns.
Estimates of reserves, drilling inventory and future development opportunities are inherently uncertain and may prove to be inaccurate.
The identification of drilling locations and estimates of reserves, estimated ultimate recovery, production profiles and future economic returns depend upon complex geological, geophysical, engineering and economic analyses. These analyses require assumptions regarding reservoir characteristics, hydrocarbon recovery, well performance, commodity prices, capital costs and operating expenses.
In evaluating undeveloped acreage, we may rely on seismic data, well logs, core information, production data from offset operators, geologic models, type curves and other technical information. The interpretation of such information is inherently uncertain.
Actual drilling results may differ materially from our expectations. Wells that we believe are commercially attractive based on seismic interpretation or geologic analysis may fail to achieve anticipated production rates, recoveries or economic returns. New information obtained through drilling and production activities may require us to revise reserve estimates, development plans, drilling inventories and expected future cash flows.
Because drilling and completion occurs over an extended period, the economics of our development activities are subject to changes in commodity prices between the time we commit capital and the time any resulting production is sold. If we are unable to execute drilling and completion programs successfully, such failure could materially and adversely affect our business, results of operations, and financial condition.
Management's Discussion & Analysis (MD&A)
New heading “(a)The basis for converting oil and NGL volumes (MBbls) to natural gas equivalent volumes (MMcfe) is determined by using the ratio of one Bbl of oil or NGLs to six Mcf of natural gas.”
New heading “Loss on Debt Extinguishment”
New heading “Results of Operations for the Six Months Ended June 30, 2026 Compared to the Six Months Ended June”
New heading “Production Volumes”
New heading “(a)The basis for converting oil and NGL volumes (MBbls) to natural gas equivalent volumes (MMcfe) is determined by using the ratio of one Bbl of oil or NGLs to six Mcf of natural gas.”
New heading “Commodity Pricing”
New heading “Commodity Revenue”
New heading “Commodity Derivatives”
New heading “Gain (Loss) on Derivatives”
New heading “(a)Represents the cash settlement of derivatives that were settled during the period.”
New heading “(b)Represents the change in fair value of derivatives, net of the carrying value of derivatives that were settled during the period.”
New heading “Operating Expenses”
New heading “Lease Operating Expense (“LOE”): LOE includes costs incurred to maintain producing properties. Such costs include direct and contract labor, repairs and maintenance, water hauling, compression, automobile, insurance, and materials and supplies expenses.”
New heading “Production Taxes: Production taxes include severance and property taxes. Severance taxes are generally paid on produced natural gas, NGLs and oil production at fixed rates established by federal, state, or local taxing authorities. Property taxes are generally based on the taxing jurisdictions’ valuation of our natural gas and oil properties and midstream assets.”
New heading “Midstream Operating Expense: Midstream operating expenses are costs incurred to operate our owned midstream assets inclusive of employee and benefit expenses.”
New heading “Transportation Expense: Transportation expenses are costs incurred from third-party systems to gather, process and transport our natural gas, NGLs and oil.”
New heading “Accretion of Asset Retirement Obligation (“Accretion”): Accretion represents the change in the carrying amount of the asset retirement obligation over time. This expense reflects the gradual recognition of the future costs associated with retiring natural gas and oil wells.”
New heading “General & Administrative Expense (“G&A”): G&A includes overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our operations, franchise taxes, audit and other professional fees, legal compliance, equity compensation, and non-recurring costs primarily related to acquisitions.”
New heading “Depreciation, Depletion & Amortization Expense (“DD&A”): DD&A expenses are non-cash charges that allocate the cost of assets and natural resources over their useful lives, reflecting their wear and tear, usage, or consumption.”
New heading “Gain (Loss) on Natural Gas and Oil Properties and Equipment: Gains and (losses) on natural gas and oil properties and equipment represent the difference between cash proceeds and recorded basis of sales of natural gas and oil properties and equipment.”
New heading “Other Income (Expense)”
New heading “Interest Expense”
New heading “(a)The future maturities presented reflect scheduled principal amortization under the terms of each instrument and does not reflect the effect of the anticipated repayment dates of the ABS Notes, which occur between May 2029 and May 2031.”
Removed heading “Ended March 31, 2025”
Largest changes
“Lease Operating Expense (“LOE”): LOE includes costs incurred to maintain producing properties. Such costs include direct and contract labor, repairs and maintenance, water hauling, compression, automobile, insurance, and materials and supplies expenses.”see in full comparison
“Production Taxes: Production taxes include severance and property taxes. Severance taxes are generally paid on produced natural gas, NGLs and oil production at fixed rates established by federal, state, or local taxing authorities. Property taxes are generally based on the taxing jurisdictions’ valuation of our natural gas and oil properties and midstream assets.”see in full comparison
“General & Administrative Expense (“G&A”): G&A includes overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our operations, franchise taxes, audit and other professional fees, legal compliance, equity compensation, and non-recurring costs primarily related to acquisitions.”see in full comparison
Commodity prices fluctuate due to a range of factors outside of our control or ability to predict. Thesesee in full comparisonfactorsinclude, but are not limited to, increased natural gas, NGLs and oil production levels that exceed market demand, adverse or unseasonable weather conditions, geopolitical developments, macroeconomic events, and intensifying competition from other energy sources. Collectively, these dynamics impact supply and demand, whichin turnultimately determine the realized sales prices for our production. In addition to these market-driven factors,the prices we realize forourproductionrealized prices are affected by our derivativeactivities andactivities, commodity trades executed by non-physical trading entities,asandwellgeographicas locational differencesvariances in marketprices,pricing, including basis differentials.WeInwill continueresponse toevaluatethese ongoing and evolving conditions, we continuously monitor the commodity priceenvironmentenvironment. This disciplined approach is designed to preserve adequate liquidity, uphold our financial flexibility, andadjustprotectthelong-termpaceshareholder value across a range ofourpricingactivity in order to maintain appropriate liquidity and financial flexibility.scenarios.
“Accretion of Asset Retirement Obligation (“Accretion”): Accretion represents the change in the carrying amount of the asset retirement obligation over time. This expense reflects the gradual recognition of the future costs associated with retiring natural gas and oil wells.”see in full comparison
“Gain (Loss) on Natural Gas and Oil Properties and Equipment: Gains and (losses) on natural gas and oil properties and equipment represent the difference between cash proceeds and recorded basis of sales of natural gas and oil properties and equipment.”see in full comparison
Full comparison: every changed paragraph (109)
In this discussion and analysis of financial condition and results of operations, we address topics such as acquisitions, tax matters, derivatives, stockholders’ equity, asset retirement obligations, and debt.borrowings. For more detailed information on these areas, refer to Notes
Notes 2, 3, 6, 7, 9, and 10 within the Notes to the Condensed Consolidated Financial Statements. These notes provide comprehensive disclosures and explanations that support the analysis presented in this section.
•In July 2026, we completed the acquisition of the equity interests of certain affiliates of Camino Natural Resources, LLC (“Camino”) that owned certain producing properties and undeveloped acreage for a gross purchase price of approximately $1.2 billion before customary purchase price adjustments. Refer to Note 14 for additional information regarding the Camino acquisition.
•In June 2026, we divested certain non-core Barnett assets for net proceeds of $116 million after customary purchase price adjustments. The proceeds received exceeded the carrying amount of the net assets divested resulting in a gain on natural gas and oil properties and equipment of $19 million.
•In May 2026, we formed DP Red River LLC, a limited-purpose, bankruptcy-remote, wholly-owned subsidiary (“ABS XII”), to issue asset-backed securities with a total principal amount of $850 million (the “ABS XII Notes”).
•In May 2026, the Company entered into an agreement to acquire the securities of certain affiliates of Camino Natural Resources, LLC (“Camino”) owning certain producing properties and undeveloped acreage for an estimated gross purchase price of $1.2 billion before customary purchase price adjustments. Simultaneously, the Company entered into an agreement with Carlyle Global Credit Investment Management, LLC (“Carlyle”) in which Carlyle agreed to fund 60% of the purchase price for the producing properties in exchange for a 60% ownership interest in a newly formed special purpose vehicle (“SPV”), with the Company retaining a 40% ownership interest in the SPV. At closing, the producing assets are expected to be contributed to an indirect subsidiary of the SPV, which will be controlled by Carlyle. The acquisition of the producing assets will be funded by an ABS collateralized by the acquired assets, the funds contributed by Carlyle and borrowings under the Company’s Credit Facility.
The acquisition of the undeveloped acreage will be funded by borrowings under the Company’s Credit Facility and the Company will retain 100% of the ownership in the undeveloped acreage. The transaction is expected to close in the third quarter of 2026, subject to customary closing conditions.
•In April 2026, thewe Company completed the previously announced transaction to acquireacquired certain oil and natural gas wells, leasehold interests and related assets from Sheridan forHolding aCompany grossIII, purchaseLLC price(“Sheridan”). We paid net consideration of $248$236 millionmillion, beforeinclusive of customary purchase price adjustments.
•In April 2026, the Companywe completed the semi-annual borrowing base redetermination of the revolving Credit Facility. The borrowing base under the facility was increased from $825 million to $900 million as a result of the increase in collateral from certain assets acquired in the Sheridan acquisition.
•In February 2026, the Company issued a $200 million tap-on offering, increasing the aggregate principal amount of the outstanding Nordic Bonds to $500 million. The Bonds were issued at a 3.5% discount, resulting in net proceeds of $193 million before transaction costs and other fees. The proceeds were used to repay existing indebtedness and for general corporate purposes.
•For the threesix months ended MarchJune 31,30, 2026, the Companywe repurchased 5,033,3645,978,251 shares, representing approximately 7%8% of the shares outstanding.outstanding as of June 30, 2026.
Our business continued to be influenced by a range of external factors in 2026, including commodity price volatility, geopolitical developments, regulatory changes, and evolving supply and demand dynamics. We are a U.S. domestic energy producer focused primarily on the production of natural gas. TheDuring ongoingthe conflictsecond quarter, Henry Hub natural gas prices remained volatile but averaged approximately $2.90 per MMBtu, compared with an average of approximately $5.04 per MMBtu in Iran,the first quarter, reflecting lower prices as winter-driven demand eased, partially offset by strong LNG export demand and colder-than-averagethe weather drove an average Henry Hub priceonset of approximatelysummer $5.04cooling per MMBtu for the quarter.demand.
Geopolitical conflicts,tensions, such asincluding the U.S.-Iranconflict conflict,involving Iran, the Russia-Ukraine warwar, and othercontinued instability in the Middle East and Venezuela, continuedcontributed to disruptvolatility in global energy flowsmarkets and underscored the strategic importance of U.S. energy productionproduction. andIn exports.particular, uncertainty surrounding transit through the Strait of Hormuz contributed to market instability during the quarter.
Domestically, policy shifts continued to support U.S. energy development and LNG export growth, although tariffs on certain imported steel, aluminum and derivative products introduced additional uncertainty around the cost of some equipment and materials.
Domestically, policy shifts created a more favorable operating environment, although new tariffs on imported energy equipment and materials introduced some uncertainty for the industry. Our vertically integrated model helps insulate us from certain direct impacts, and our hedging program playscontinues ato keyplay an important role in mitigating commodity price risk and supporting cash flow stability.durability.
We also continued to monitor inflationary pressures, labor availability and supply chain conditions affecting the broader industry.
We also monitored inflationary pressures and supply chain challenges, which affected operating costs across the industry. Despite ongoing market volatility and policy uncertainty, we remain focused on optimizing our asset base, managing costs,costs and enhancing operational efficiency. Our integrated model and strategic positioning continue to enablesupport usour ability to navigate market fluctuations and capitalize on long-term opportunities in the oil and natural gas and oil sector.
Results of Operations for the Three Months Ended MarchJune 31,30, 2026 Compared to the Three Months Ended
Ended March 31, 2025
(a)The basis for converting oil and NGL volumes (MBbls) to natural gas equivalent volumes (MMcfe) is determined by using the ratio of one Bbl of oil or NGLs to six Mcf of natural gas.
The increase in production volumes for the three months ended MarchJune 31,30, 2026 compared to the three months ended MarchJune 31,30, 2025 was primarily related to the MaverickCanvas and SummitSheridan acquisitions in the first quarter of 2025 and the Canvas acquisition in the fourth quarter of 2025,2025 and second quarter of 2026, respectively, as well as our continued non-operated development investment. These increases were partially offset by normal production declines.
Commodity prices fluctuate due to a variety of factors we can neither control nor predict, including increased production in excess of demand of natural gas, NGLs or oil, weather conditions, political and economic events, and competition from other energy sources.
Commodity prices fluctuate due to a range of factors outside of our control or ability to predict. These factorsinclude, but are not limited to, increased natural gas, NGLs and oil production levels that exceed market demand, adverse or unseasonable weather conditions, geopolitical developments, macroeconomic events, and intensifying competition from other energy sources. Collectively, these dynamics impact supply and demand, which in turnultimately determine the realized sales prices for our production. In addition to these market-driven factors, the prices we realize for our productionrealized prices are affected by our derivative activities andactivities, commodity trades executed by non-physical trading entities, asand wellgeographic as locational differencesvariances in market prices,pricing, including basis differentials. WeIn will continueresponse to evaluatethese ongoing and evolving conditions, we continuously monitor the commodity price environmentenvironment. This disciplined approach is designed to preserve adequate liquidity, uphold our financial flexibility, and adjustprotect thelong-term paceshareholder value across a range of ourpricing activity in order to maintain appropriate liquidity and financial flexibility.scenarios.
Commodity revenue of $556 million for the three months ended MarchJune 31,30, 2026 increased $227 million, or 69%,28% compared to $329 million for the three months ended MarchJune 31,30, 2025. The increase in commodity revenue was primarily related to the 22%17% increase in average realized sales prices, excluding the impact of derivatives settled in cash, and the 39%9% increase in sold volumes primarily due to the acquisitions and non-operated development as discussed above. The average realized sales price after derivatives settlements increased due to an increase in liquids exposure from the Maverick and Canvas acquisitions, which resulted in a higher overall realized price.
To manage our cash flows in a volatile commodity price environment, we utilize commodity derivative contracts that allowenable us to fixsecure thefixed per unitper-unit sales prices for a portion of our production. As of MarchJune 31,30, 2026, approximately 82%86% of our production was fixed through commodity derivative contracts over the next twelve months. The tables below set forth the impact of commodity derivatives settlements on commodity revenue:
The change in this metric was driven by an increase in the fair value of unsettled derivatives due to lower forward commodity prices primarily for natural gas. This increase was partially offset by a decrease in the value of unsettledsettled derivatives, which resulted in a loss of $398 million in 2026 compared to a loss of $232 million in 2025, a change of $166 million,derivatives due to higherincreased forwardoil commodity prices.prices Additionally,during the value of settled derivatives also decreased, resulting in an additional $98 million in losses on settled derivatives in 2026 compared to 2025 as a result of increased commodity pricing.period.
The increase in LOE was primarily driven by the acquisition of Canvas in the fourth quarter of 2025. While the total expense increased, LOE per Mcfe remained consistent.
The increase in LOE was driven by the acquisitions of Summit and Maverick in the first quarter of 2025 and the Canvas acquisition in the fourth quarter of 2025. Specifically, the increase in LOE per Mcfe was primarily related to a greater exposure to liquids production. Areas with higher liquids output tend to incur elevated operating costs, although they also benefit from higher realized prices. In the first quarter of 2026, the Company’s liquids production grew by 115% compared to the first quarter of 2025, primarily driven by the acquisition of Maverick.
The increase in production taxes and production taxes per Mcfe was primarily related to an increase in severance and property taxes as a result of an increase in revenue due to higher commodity prices and the additional value of addedfor oil revenue,and as well as additional property taxes on assets acquired.NGLs.
The decrease in midstream operating expense per Mcfe was primarily related to maintaining a consistent level of midstream assets while increasingcontinuing to increase overall production for the firstsecond quarter of 2026, following the acquisitionsacquisition of Summit and Maverick in the first quarter of 2025 and the Canvas acquisition in the fourth quarter of 2025.2025 and Sheridan in the second quarter of 2026. By keeping midstream operations relatively unchanged and expanding production volumes, the per unit cost of midstream operations declined.
The increase in transportation expense was driven by the Summit and Maverick acquisitions in the first quarter of 2025 and the Canvas acquisition in the fourth quarter of 2025. The decrease in transportation expense per Mcfe was primarily related to additional liquids production.production, Transportationas transportation costs are primarily associated with the movement of natural gas volumes. Following the acquisition of Maverick, the proportion of liquids in the Company’s overall production mix has risen significantly. Specifically, the liquids share increased to 29% in the first quarter of 2026 from 18% in the first quarter of 2025.
Accretion of Asset Retirement Obligation (“Accretion”): Accretion represents the change in the carrying amount of the asset retirement obligation (“ARO”) over time. This expense reflects the gradual recognition of the future costs associated with retiring natural gas and oil wells.
The increase in accretion was primarily related to the expandedCanvas obligationand asSheridan a result of the Maverick acquisitionacquisitions in the firstfourth quarter of 2025,2025 asand wellsecond asquarter normalof revisions.2026, respectively.
The increasedecrease in G&A and G&A per Mcfe was the result of thesignificant increasetransaction-related incosts scale, including increased headcount, due tofrom the Summitclosing andof the Maverick acquisitionsacquisition in the first quarter of 20252025, andreflecting the Canvasfull impact of the administrative synergies realized from this acquisition in the fourth quarter of 2025. The decrease in G&A per Mcfe was primarily related to recognizing administrative synergies and leveraging our existing infrastructure, which offset the acquisition-related increases.2026.
The increase in DD&A was primarily related to an increase in our DD&A rate, as well as a 39%9% increase in production over the period. The increase in production and the DD&A rate was due to the SummitCanvas and MaverickSheridan acquisitions in the first quarter of 2025, as well as the Canvas acquisition in the fourth quarter of 2025,2025 and second quarter of 2026, respectively, as thesewell ledas tocontinued annon-operated increase in our depreciable base.development.
The increasedecrease in this metric was primarily related to increaseddecreased acreage sales,sale asactivity, wepartially strategicallyoffset pursueby the divestituregain on sale recognized from the sale of selectthe non-core,Barnett undeveloped acreage within our operating portfolio.assets. For the three months ended MarchJune 31,30, 2026, we recognized a gain of $101$24 million from acreage sales compared to $2$62 million for three months ended MarchJune 31,30, 2025. The sale of the Barnett assets resulted in a gain of $19 million for the three months ended June 30, 2026. Additionally, the disposal of various property, plant and equipment in the normal course of business resulted in a loss on natural gas and oil properties and equipment of $3$7 million for the three months ended MarchJune 31,30, 2026, compared to $0.3 million for the three months ended March 31, 2025.2026.
The increase in interest expense was primarily related to the issuance of the ABS XXI Notes and the assumption of the Maverick ABS Notes as a result of the Maverick acquisition, the issuance of the Nordic Bonds in AprilNovember 2025,2025 and the issuance of the ABS XIXII Notes as a result of the Canvas acquisition in NovemberMay 2025.2026. This increase was partially offset by lower outstanding balances on our existing ABS structures.structures and Credit Facility.
As of MarchJune 31,30, 2026 and December 31, 2025, total borrowings were $2.9approximately billion$3 and $3.0 billion, respectively.billion. For the three months ended MarchJune 31,30, 2026, the weighted average interest rate on borrowings was 7.76%7.47% compared to 7.93%8.04% for the three months ended MarchJune 31,30, 2025. As of MarchJune 31,30, 2026, 72%76% of our borrowings resided in non-recourse, fixed-rate, hedge-protected, amortizing structures compared to 76%71% as of MarchJune 31,30, 2025.
Loss on Debt Extinguishment
In May 2026, the proceeds from the ABS XII Notes were used to repay the outstanding principal of the ABS Maverick Notes and ABS VI Notes, thereby retiring the ABS Maverick Notes and ABS VI Notes from the Company’s outstanding debt resulting in a loss on the early retirement of debt of $21 million. Additionally, in June 2026, proceeds from the Barnett assets divestiture were used to repay the outstanding principal of the ABS IV Notes, thereby retiring the ABS IV Notes from the Company’s outstanding debt and resulting in a loss on the early retirement of debt of $2 million.
Results of Operations for the Six Months Ended June 30, 2026 Compared to the Six Months Ended June
30, 2025
Production Volumes
(a)The basis for converting oil and NGL volumes (MBbls) to natural gas equivalent volumes (MMcfe) is determined by using the ratio of one Bbl of oil or NGLs to six Mcf of natural gas.
The increase in production volumes for the six months ended June 30, 2026 compared to the six months ended June 30, 2025 was primarily related to the Maverick acquisition in the first quarter of 2025, the Canvas acquisition in the fourth quarter of 2025, and the Sheridan acquisitions in the second quarter of 2026, as well as our continued non-operated development investment, partially offset by normal production declines.
Commodity Pricing
The following table summarizes our average realized sales prices and benchmark prices for the periods presented:
Commodity Revenue
The following table reconciles the change in commodity revenue (excluding the impact of derivatives settled in cash) by reflecting the effect of changes in volume and in the underlying prices:
The increase in commodity revenue was primarily related to the 20% increase in average realized sales prices, excluding the impact of derivatives settled in cash, and the 22% increase in sold volumes.
Commodity Derivatives
To manage our cash flows in a volatile commodity price environment, we utilize commodity derivative contracts that enable us to secure fixed per-unit sales prices for a portion of our production. As of June 30, 2026, approximately 86% of our production was fixed through commodity derivative contracts over the next twelve months. The tables below set forth the impact of commodity derivatives settlements on commodity revenue:
Gain (Loss) on Derivatives
The table below sets forth the impact of settlements and fair value adjustments on derivatives for the periods presented:
(a)Represents the cash settlement of derivatives that were settled during the period.
(b)Represents the change in fair value of derivatives, net of the carrying value of derivatives that were settled during the period.
The change in this metric was primarily driven by a decrease in the value of settled derivatives due to increased natural gas and oil commodity prices during the period. This decrease was partially offset by an increase in the value of unsettled derivatives during the period based on forward commodity pricing movement.
Operating Expenses
Lease Operating Expense (“LOE”): LOE includes costs incurred to maintain producing properties. Such costs include direct and contract labor, repairs and maintenance, water hauling, compression, automobile, insurance, and materials and supplies expenses.
The increase in LOE was primarily driven by the acquisitions of Maverick in the first quarter of 2025, Canvas in the fourth quarter of 2025, and Sheridan in the second quarter of 2026. Specifically, the increase in LOE per Mcfe was primarily related to a greater exposure to liquids production. Areas with higher liquids output tend to incur elevated operating costs, although they also benefit from higher realized prices.
DEC insider buying and selling (Form 4)
Since 2026-04-11, insiders reported open-market purchases in 0 Form 4 filings and open-market sales in 0 filings. Totals add up every open-market (code P and S) line in those filings, using the prices reported in the filings. Awards, option exercises, tax withholding and gifts are listed below but not counted.
| Trade date | Insider | Transaction | Shares | Price | Value |
|---|---|---|---|---|---|
| 2026-09-30 | Turner David Jackson Jr. |
Grant/award | 230 | — | — |
| 2026-09-30 | Klaber Kathryn Z |
Grant/award | 209 | — | — |
| 2026-09-30 | Thomas Martin Keith |
Grant/award | 209 | — | — |
| 2026-09-30 | Oliver Kirk R |
Grant/award | 118 | — | — |
| 2026-08-05 | Turner David Jackson Jr. |
Grant/award | 1,072 | — | — |
| 2026-06-30 | Turner David Jackson Jr. |
Grant/award | 207 | — | — |
| 2026-06-30 | Oliver Kirk R |
Grant/award | 118 | — | — |
| 2026-06-30 | Klaber Kathryn Z |
Grant/award | 207 | — | — |
| 2026-06-30 | Thomas Martin Keith |
Grant/award | 207 | — | — |
| 2026-06-30 | Johnson David Edward |
Grant/award | 276 | — | — |
| 2026-06-01 | Oliver Kirk R |
Grant/award | 5,908 | — | — |
Well-known investors holding DEC (13F)
| Investor | Quarter | Shares | Reported value | % of their 13F | Change vs prior quarter |
|---|---|---|---|---|---|
| Citadel Advisors (Ken Griffin) | 2026-06-30 | 1,388,337 | $19.2M | 0.01% | Reduced 9% |
| AQR Capital Management (Cliff Asness) | 2026-06-30 | 453,500 | $6.3M | 0.0% | Added 169% |
| Millennium Management (Israel Englander) | 2026-06-30 | 267,785 | $3.7M | 0.0% | Reduced 60% |
| D. E. Shaw & Co. | 2026-06-30 | 126,277 | $1.8M | 0.0% | Reduced 56% |
| Two Sigma Investments | 2026-06-30 | 115,577 | $1.6M | 0.0% | Reduced 87% |
| Point72 Asset Management (Steve Cohen) | 2026-06-30 | 106,198 | $1.5M | 0.0% | Reduced 70% |