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Diversified Energy Co (DEC)

CIK: 0001922446. SIC: 1311 Crude Petroleum & Natural Gas. Latest 10-K as of: 2026-02-26.

SIC breadcrumb: Mining > SIC Major Group 13 > SIC 1311 Crude Petroleum & Natural Gas

SEC company page: https://www.sec.gov/edgar/browse/?CIK=1922446. Latest filing source: 0001922446-26-000020.

Selected Fundamentals

MetricValueUnitFYFiled
Revenue1,829,142,000USD20252026-02-26
Net income341,115,000USD20252026-02-26
Assets6,168,959,000USD20252026-02-26

Financials

Annual standardized facts from SEC companyfacts as of latest extracted filing date 2026-02-26. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0001922446.json. Derived margins, ratios, and free cash flow are computed from the extracted annual SEC facts.

Flow metrics use full-year FY periods from 10-K/10-K/A filings; balance-sheet metrics use FY-end instants. Free cash flow = operating cash flow - capital expenditures. Missing metrics are omitted rather than fabricated.

Metric202320242025
Revenue1,948,780,000757,290,0001,829,142,000
Net income748,706,000-104,365,000341,115,000
Operating income1,108,982,000-97,098,000535,017,000
Diluted EPS15.76-2.174.58
Operating cash flow291,431,000220,650,000464,619,000
Capital expenditures74,252,00052,100,000184,600,000
Dividends paid168,041,00083,864,00085,005,000
Assets3,956,810,0006,168,959,000
Liabilities3,544,853,0005,173,969,000
Stockholders' equity400,078,000984,058,000
Cash and cash equivalents3,753,0005,990,00029,697,000
Free cash flow217,179,000168,550,000280,019,000

Ratios

ROE and ROA use period-end equity/assets. Liabilities / equity uses total liabilities divided by stockholders' equity. Current ratio uses current assets divided by current liabilities when both are reported.

Metric202320242025
Net margin38.42%-13.78%18.65%
Operating margin56.91%-12.82%29.25%
Return on equity-26.09%34.66%
Return on assets-2.64%5.53%
Liabilities / equity8.865.26
Current ratio0.390.60

Financial Charts

Quarterly

Quarterly standardized facts from SEC companyfacts as of latest extracted filing date 2026-05-06. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0001922446.json.

Flow metrics use discrete quarter-length periods from 10-Q/10-Q/A filings. Q4 revenue and net income are derived only when annual FY and nine-month YTD facts exist for the same fiscal year; derived Q4 values are labeled. EPS Q4 is not derived.

QuarterEnd DateRevenueNet IncomeDiluted EPSMethod
2026-Q12026-03-3127,144,000-160,617,000-2.13reported discrete quarter

Quarterly Charts

Macro Cross-References

Latest quarter (10-Q)

Latest 10-Q source: 0001922446-26-000039.

Extracted structurally from real Item 2 body heading to real Item 3/4 boundary. Confidence: high. Filing date: 2026-05-06. Report date: 2026-03-31.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of

Operations

The following discussion and analysis of financial condition and results of operations should be read in conjunction with the

Condensed Consolidated Financial Statements and the notes thereto included in this report. Unless the context otherwise indicates,

references to “Diversified,” the “Company,” “our,” “we” and “us” (i) for periods until the completion of the U.S. Domestication,

refer to Diversified Energy Company PLC and its consolidated subsidiaries, collectively, and (ii) for periods at or after the completion

of the U.S. Domestication, refer to Diversified Energy Company and its consolidated subsidiaries, collectively. For certain industry

specific terms used in this Quarterly Report on Form 10-Q, please refer to the Glossary of Terms.

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. For more detailed information on these areas, refer to 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.

Recent Developments

•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, the Company completed the previously announced transaction to acquire certain oil and natural gas wells,

leasehold interests and related assets from Sheridan for a gross purchase price of $248 million before customary purchase price

adjustments.

•In April 2026, the Company 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 three months ended March 31, 2026, the Company repurchased 5,033,364 shares, representing approximately 7% of the

shares outstanding.

Market Conditions

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 natural gas. The ongoing conflict in Iran, strong LNG export demand and colder-than-average weather drove an average

Henry Hub price of approximately $5.04 per MMBtu for the quarter.

Geopolitical conflicts, such as the U.S.-Iran conflict, the Russia-Ukraine war and other instability in the Middle East and Venezuela,

continued to disrupt global energy flows and underscored the strategic importance of U.S. energy production and exports.

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 direct impacts, and our

hedging program plays a key role in mitigating commodity price risk and supporting cash flow stability.

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, and enhancing

operational efficiency. Our integrated model and strategic positioning continue to enable us to navigate market fluctuations and

capitalize on long-term opportunities in the natural gas and oil sector.

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MD&A

Diversified Energy

Results of Operations for the Three Months Ended March 31, 2026 Compared to the Three Months

Ended March 31, 2025

Production Volumes

For the Three Months Ended March 31,

2026

2025

Change

% Change

Net production

Natural gas (MMcf)

76,838

63,468

13,370

21%

NGLs (MBbls)

2,554

1,593

961

60%

Oil (MBbls)

2,608

783

1,825

233%

Total production (MMcfe)

107,810

77,724

30,086

39%

Average daily production (MMcfepd)

1,198

864

334

39%

% Natural gas (Mcfe basis)

71%

82%

The increase in production volumes for the three months ended March 31, 2026 compared to the three months ended March 31, 2025

was primarily related to the Maverick and Summit acquisitions in the first quarter of 2025 and the Canvas acquisition in the fourth

quarter of 2025, partially offset by normal production declines.

Commodity Pricing

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.

These factors impact supply and demand, which in turn determine the sales prices for our production. In addition to these factors, the

prices we realize for our production are affected by our derivative activities and commodity trades by non-physical trading entities, as

well as locational differences in market prices, including basis differentials. We will continue to evaluate the commodity price

environment and adjust the pace of our activity in order to maintain appropriate liquidity and financial flexibility.

The following table summarizes our average realized sales prices and benchmark prices for the periods presented:

For the Three Months Ended March 31,

2026

2025

Change

% Change

Average realized sales prices (before derivative settlements)

Natural gas (Mcf)

$4.09

$3.60

$0.49

14%

NGLs (Bbls)

23.87

30.19

(6.32)

(21%)

Oil (Bbls)

69.44

67.45

1.99

3%

Total (Mcfe)

$5.16

$4.24

$0.92

22%

Average realized sales prices (after derivative settlements)

Natural gas (Mcf)

$2.44

$2.95

$(0.51)

(17%)

NGLs (Bbls)

21.81

24.46

(2.65)

(11%)

Oil (Bbls)

62.38

65.29

(2.91)

(4%)

Total (Mcfe)

$3.76

$3.57

$0.19

5%

Average benchmark prices

Henry Hub (Mcf)

$5.04

$3.65

$1.39

38%

Mont Belvieu (Bbls)

31.69

41.77

(10.08)

(24%)

WTI (Bbls)

71.93

71.42

0.51

1%

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Diversified Energy

Commodity Revenue

The following table reconciles the change in commodity revenue (excluding the impact of hedges settled in cash) by reflecting the

effect of changes in volume and in the underlying prices:

(In thousands)

Natural Gas

NGLs

Oil

Total

Commodity revenue for the three months ended March 31, 2025

$228,510

$48,094

$52,815

$329,419

Volume increase (decrease)

48,132

29,013

123,096

200,241

Price increase (decrease)

37,507

(16,148)

5,188

26,547

Net increase (decrease)

85,639

12,865

128,284

226,788

Commodity revenue for the three months ended March 31, 2026

$314,149

$60,959

$181,099

$556,207

Commodity revenue of $556 million for the three months ended March 31, 2026 increased $227 million, or 69%, compared to $329

million for the three months ended March 31, 2025. The increase in commodity revenue was primarily related to the 22% increase in

average realized sales prices, excluding the impact of derivatives settled in cash, and the 39% increase in sold volumes primarily due

to acquisitions 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.

Commodity Derivatives

To manage our cash flows in a volatile commodity price environment, we utilize commodity derivative contracts that allow us to fix

the per unit sales prices for our production. As of March 31, 2026, approximately 82% 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:

(In thousands, except per unit

data)

For the Three Months Ended March 31, 2026

Natural Gas

NGLs

Oil

Total Commodity

Revenue

Realized $

Revenue

Realized $

Revenue

Realized $

Revenue

Realized $

per Mcf

per Bbl

per Bbl

per Mcfe

Excluding hedge impact

$314,149

$4.09

$60,959

$23.87

$181,099

$69.44

$556,207

$5.16

Gain (loss) on commodity

derivatives settlements

(126,833)

(1.65)

(5,253)

(2.06)

(18,413)

(7.06)

(150,499)

(1.40)

Including hedge impact

$187,316

$2.44

$55,706

$21.81

$162,686

$62.38

$405,708

$3.76

(In thousands, except per unit

data)

For the Three Months Ended March 31, 2025

Natural Gas

NGLs

Oil

Total Commodity

Revenue

Realized $

Revenue

Realized $

Revenue

Realized $

Revenue

Realized $

per Mcf

per Bbl

per Bbl

per Mcfe

Excluding hedge impact

$228,510

$3.60

$48,094

$30.19

$52,815

$67.45

$329,419

$4.24

Gain (loss) on commodity

derivatives settlements

(41,448)

(0.65)

(9,133)

(5.73)

(1,690)

(2.16)

(52,271)

(0.67)

Including hedge impact

$187,062

$2.95

$38,961

$24.46

$51,125

$65.29

$277,148

$3.57

Gain (Loss) on Derivatives

The table below sets forth the impact of settlements and fair value adjustments on derivatives for the periods presented:

For the Three Months Ended March 31,

(In thousands)

2026

2025

$ Change

% Change

Net gain (loss) on commodity derivatives settlements

$(150,499)

$(52,271)

$(98,228)

188%

Net gain (loss) on interest rate swaps

20

35

(15)

(43%)

Total gain (loss) on settled derivatives(a)

$(150,479)

$(52,236)

$(98,243)

188%

Gain (loss) on fair value adjustments of unsettled derivatives(b)

(397,904)

(232,048)

(165,856)

71%

Total gain (loss) on derivatives

$(548,383)

$(284,284)

$(264,099)

93%

(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.

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The change in this metric was driven by a decrease in the value of unsettled 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, due to higher forward commodity prices. Additionally, the

value of settled derivatives also decreased, resulting in an additional $98 million in losses on settled derivatives in 2026 compared to

2025

[Excerpt truncated for page length; source filing is linked above.]

Latest 10-K MD&A

Extracted structurally from real Item 7 body heading to real Item 7A/8 boundary. Confidence: high. Filing date: 2026-02-26. Report date: 2025-12-31.

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of

Operations

The following discussion and analysis of financial condition and results of operations should be read in conjunction with the

Consolidated Financial Statements and the notes thereto included in this report. Unless the context otherwise indicates, references to

“Diversified,” the “Company,” “our,” “we” and “us” (i) for periods until the completion of the U.S. Domestication, refer to

Diversified Energy Company PLC and its consolidated subsidiaries, collectively, and (ii) for periods at or after the completion of the

U.S. Domestication, refer to Diversified Energy Company and its consolidated subsidiaries, collectively. For certain industry specific

terms used in this Annual Report on Form 10-K, please refer to the Glossary of Terms.

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. For more detailed information on these areas, refer to Notes

38

Table of Contents

Form 10-K

Diversified Energy Company

3, 4, 8, 11, 13, and 15 within the Notes to the Consolidated Financial Statements. These notes provide comprehensive disclosures and

explanations that support the analysis presented in this section.

Market Conditions

Our business was influenced by a range of external factors in 2025, including commodity price volatility, geopolitical developments,

regulatory changes, and evolving supply and demand dynamics. As a U.S. domestic energy producer focused primarily on natural gas,

we benefited from strong LNG export demand and colder-than-average weather, which supported an average Henry Hub price of

approximately $3.43 per MMBtu for the year. Prices fluctuated from an average high of $4.42 per MMBtu in December to an average

low of $2.84 per MMBtu in October. Year-end inventories were above the five-year average, contributing to price stability despite

ongoing global tensions.

Geopolitical conflicts, such as the Russia-Ukraine war and instability in the Middle East and Venezuela, continued to disrupt global

energy flows and underscored the strategic importance of U.S. energy production and exports. 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 helped insulate us from direct impacts, and our hedging program played a key role in

mitigating commodity price risk and supporting cash flow stability.

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, and enhancing

operational efficiency. Our integrated model and strategic positioning continue to enable us to navigate market fluctuations and

capitalize on long-term opportunities in the natural gas and oil sector.

Results of Operations for the Year Ended December 31, 2025 Compared to the Year Ended December 31,

2024

Production Volumes

For the Year Ended December 31,

2025

2024

Change

% Change

Net production

Natural gas (MMcf)

295,723

244,298

51,425

21%

NGLs (MBbls)

8,821

5,980

2,841

48%

Oil (MBbls)

7,935

1,568

6,367

406%

Total production (MMcfe)

396,259

289,586

106,673

37%

Average daily production (MMcfepd)

1,086

791

295

37%

% Natural gas (Mcfe basis)

75%

84%

The increase in production volumes for the year ended December 31, 2025 compared to the year ended December 31, 2024 was

primarily related to the Maverick and Canvas acquisitions in 2025, as well as full year production for Oaktree, Crescent Pass, and East

Texas II acquisitions completed in 2024, partially offset by normal production declines.

Commodity Pricing

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.

These factors impact supply and demand, which in turn determine the sales prices for our production. In addition to these factors, the

prices we realize for our production are affected by our derivative activities and commodity trades by non-physical trading entities, as

well as locational differences in market prices, including basis differentials. We will continue to evaluate the commodity price

environment and adjust the pace of our activity in order to maintain appropriate liquidity and financial flexibility.

The following table summarizes our average realized sales prices and benchmark prices for the periods presented:

For the Year Ended December 31,

2025

2024

Change

% Change

Average realized sales prices (before derivative settlements)

Natural gas (Mcf)

$2.81

$1.90

$0.91

48%

NGLs (Bbls)

23.57

25.17

(1.60)

(6%)

Oil (Bbls)

63.10

74.71

(11.61)

(16%)

Total (Mcfe)

$3.88

$2.53

$1.35

53%

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Form 10-K

Diversified Energy Company

For the Year Ended December 31,

2025

2024

Change

% Change

Average realized sales prices (after derivative settlements)

Natural gas (Mcf)

$2.80

$2.57

$0.23

9%

NGLs (Bbls)

23.34

24.32

(0.98)

(4%)

Oil (Bbls)

66.80

69.54

(2.74)

(4%)

Total (Mcfe)

$3.94

$3.05

$0.89

29%

Average benchmark prices

Henry Hub (Mcf)

$3.43

$2.27

$1.16

51%

Mont Belvieu (Bbls)

35.03

38.16

(3.13)

(8%)

WTI (Bbls)

64.81

75.72

(10.91)

(14%)

Commodity Revenue

The following table reconciles the change in commodity revenue (excluding the impact of hedges settled in cash) by reflecting the

effect of changes in volume and in the underlying prices:

(In thousands)

Natural Gas

NGLs

Oil

Total

Commodity revenue for the year ended December 31, 2024

$464,600

$150,513

$117,146

$732,259

Volume increase (decrease)

97,708

71,508

475,679

644,895

Price increase (decrease)

267,939

(14,153)

(92,119)

161,667

Net increase (decrease)

365,647

57,355

383,560

806,562

Commodity revenue for the year ended December 31, 2025

$830,247

$207,868

$500,706

$1,538,821

Commodity revenue of $1,539 million for the year ended December 31, 2025 increased $807 million, or 110%, compared to $732

million for the year ended December 31, 2024. The increase in commodity revenue was primarily related to the 53% increase in

average realized sales prices, excluding the impact of derivatives settled in cash, and the 37% increase in sold volumes primarily due

to acquisitions as discussed above.

Commodity Derivatives

To manage our cash flows in a volatile commodity price environment, we utilize derivative hedging contracts that allow us to fix the

per unit sales prices for our production. As of December 31, 2025, approximately 80% of our production was fixed through derivative

hedging contracts over the next twelve months. The tables below set forth the commodity hedge impact on commodity revenue,

excluding and including cash received for commodity hedge settlements:

(In thousands, except per unit

data)

For the Year Ended December 31, 2025

Natural Gas

NGLs

Oil

Total Commodity

Revenue

Realized $

Revenue

Realized $

Revenue

Realized $

Revenue

Realized $

per Mcf

per Bbl

per Bbl

per Mcfe

Excluding hedge impact

$830,247

$2.81

$207,868

$23.57

$500,706

$63.10

$1,538,821

$3.88

Commodity hedge impact

(3,683)

(0.01)

(1,998)

(0.23)

29,390

3.70

23,709

0.06

Including hedge impact

$826,564

$2.80

$205,870

$23.34

$530,096

$66.80

$1,562,530

$3.94

(In thousands, except per unit

data)

For the Year Ended December 31, 2024

Natural Gas

NGLs

Oil

Total Commodity

Revenue

Realized $

Revenue

Realized $

Revenue

Realized $

Revenue

Realized $

per Mcf

per Bbl

per Bbl

per Mcfe

Excluding hedge impact

$464,600

$1.90

$150,513

$25.17

$117,146

$74.71

$732,259

$2.53

Commodity hedge impact

164,452

0.67

(5,055)

(0.85)

(8,108)

(5.17)

151,289

0.52

Including hedge impact

$629,052

$2.57

$145,458

$24.32

$109,038

$69.54

$883,548

$3.05

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Diversified Energy Company

Gain (Loss) on Derivatives

The table below sets forth the impact of settlements and fair value adjustments on derivatives for the periods presented:

For the Year Ended December 31,

(In thousands)

2025

2024

$ Change

% Change

Net gain (loss) on commodity derivatives settlements

$23,709

$151,289

$(127,580)

(84%)

Net gain (loss) on interest rate swaps

135

190

(55)

(29%)

Total gain (loss) on settled derivatives(a)

$23,844

$151,479

$(127,635)

(84%)

Gain (loss) on fair value adjustments of unsettled derivatives(b)

193,843

(189,030)

382,873

(203%)

Total gain (loss) on derivatives

$217,687

$(37,551)

$255,238

(680%)

(a)Represents the cash settlement of derivatives that settled during the period.

(b)Represents the change in fair value of derivatives net of removing the carrying value of derivatives that settled during the period.

The change in this metric was primarily related to an increase in the value of unsettled derivatives, which had a gain of $194 million in

2025 compared to a loss of $189 million in 2024, a change of $383 million, as a result of decreases along the forward commodity

curve. This change was partially offset by a $128 million decrease in gains on settled derivatives as a result of increased commodity

pricing.

Operating Expenses

For the Year Ended December 31,

(In thousands, except per unit data)

2025

Per

Mcfe

2024

Per

Mcfe

Total Change

Per Mcfe

Change

Lease operating expenses

$457,593

$1.15

$231,651

$0.80

$225,942

98%

$0.35

44%

Production taxes

86,709

0.22

36,043

0.12

50,666

141%

0.10

83%

Midstream operating expenses

79,185

0.20

72,098

0.25

7,087

10%

(0.05)

(20%)

Transportation expenses

115,267

0.29

90,461

0.31

24,806

27%

(0.02)

(6%)

Accretion of asset retirement obligation

48,607

0.12

28,464

0.10

20,143

71%

0.02

20%

General and administrative expense

167,626

0.42

129,745

0.45

37,881

29%

(0.03)

(7%)

Depreciation, depletion and amortization

412,506

1.04

291,995

1.01

120,511

41%

0.03

3%

(Gain) loss on oil and gas property and equipment

(73,368)

(0.19)

(26,069)

(0.09)

(47,299)

181%

(0.10)

111%

Total operating expenses

1,294,125

3.25

854,388

2.95

439,737

51%

0.30

10%

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 driven by the acquisitions of Maverick and Canvas. 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 2025, the Company’s liquids production grew by 122% compared to 2024,

primarily driven by the acquisitions of Maverick and Canvas.

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.

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 added oil revenue, as well as additional

property taxes on assets acquired during the year.

Midstream Operating Expense: Midstream operating expenses are costs incurred to operate our owned midstream assets inclusive of

employee and benefit expenses.

The decrease in midstream operating expense per Mcfe was primarily related to maintaining a consistent level of midstream assets

while increasing overall production in 2025, following the acquisitions of Summit, Maverick, and Canvas. By keeping midstream

operations relatively unchanged and expanding production volumes, the per unit cost of midstream operations declined.

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Transportation Expense: Transportation expenses are costs incurred from third-party systems to gather, process and transport our

natural gas, NGLs and oil.

The increase in transportation expense was driven by the acquisitions of Maverick and Canvas. The decrease in transportation expense

per Mcfe was primarily related to additional liquids production. Transportation costs are primarily associated with the movement of

natural gas volumes. Following the acquisitions of Maverick and Canvas, the proportion of liquids in the Company’s overall

production mix has risen significantly. Specifically, the liquids share increased to 25% in 2025 from 16% in 2024.

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 expanded obligation as a result of the Summit, Maverick, and Canvas

acquisitions during 2025, as well as normal revisions.

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.

The increase in G&A was the result of the increase in scale, including increased headcount, due to the Summit, Maverick, and Canvas

acquisitions. 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.

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.

The increase in DD&A was primarily related to an increase in our DD&A rate, as well as a 37% increase in production over the

period. The increase in production and the DD&A rate was due to the Summit, Maverick, and Canvas acquisitions, as these led to an

increase in our depreciable base.

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.

The increase in this metric was primarily related to increased acreage sales, as we strategically pursue the divestiture of select non-

core, undeveloped acreage within our operating portfolio. In 2025, we recognized a gain of $95 million from acreage sales compared

to $27 million in 2024. 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 $22 million in 2025, compared to $0.9 million in 2024.

Other Income (Expense)

For the Year Ended December 31,

(In thousands)

2025

2024

$ Change

% Change

Interest expense

$(209,967)

$(136,801)

$(73,166)

53%

Loss on debt extinguishment

(26,971)

(16,377)

(10,594)

65%

Other income (expense)

3,270

2,338

932

40%

Total other income (expense)

$(233,668)

$(150,840)

$(82,828)

55%

Interest Expense

For the Year Ended December 31,

(In thousands)

2025

2024

$ Change

% Change

Interest incurred

Borrowings

$216,132

$138,829

$77,303

56%

Other

1,432

554

878

158%

Total interest incurred

217,564

139,383

78,181

56%

LESS: Capitalized interest

7,597

2,582

5,015

194%

Interest expense

$209,967

$136,801

$73,166

53%

The increase in interest expense was primarily related to the issuance of the ABS X Notes, the assumption of the Maverick ABS Notes

as a result of the Maverick acquisition, the issuance of the Nordic Bonds, and the issuance of the ABS XI Notes in connection with the

Canvas acquisition. The increase was partially offset by lower outstanding balances on our existing ABS structures.

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Diversified Energy Company

As of December 31, 2025 and 2024, total borrowings were $3.0 billion and $1.7 billion, respectively. For the year ended

December 31, 2025, the weighted average interest rate on borrowings was 7.61% compared to 7.37% for the year ended December 31,

2024. As of December 31, 2025, 73% of our borrowings resided in non-recourse, fixed-rate, hedge-protected, amortizing structures

compared to 83% as of December 31, 2024.

Loss on Debt Extinguishment

In February 2025, the proceeds from the ABS X Notes were used to repay the outstanding principal of the ABS I & II Notes and Term

Loan I, retiring these from our outstanding debt and resulting in a loss on debt extinguishment of $27 million. In 2024, the loss on debt

extinguishment was primarily driven by the use of proceeds from the ABS VIII Notes to repay the outstanding principal of the ABS

III & V Notes, retiring these from our outstanding debt and resulting in a loss on debt extinguishment of $11 million.

Income Tax Benefit (Expense)

The differences between the statutory U.S. federal income tax rate and the effective tax rates are summarized as follows:

For the Year Ended December 31,

(in thousands)

2025

2024

U.S. federal statutory tax rates

$(63,283)

21.0%

$52,067

21.0%

State and local income tax, net of federal (national) income tax effect

(12,558)

4.2%

9,201

3.7%

Foreign tax effects

Statutory tax rate difference between United Kingdom and United States

(3,586)

1.2%

(3,109)

(1.3)%

Equity in earnings of foreign subsidiary

(18,825)

6.2%

(16,324)

(6.6)%

Nontaxable dividend income

25,777

(8.6)%

21,681

8.7%

Other foreign tax effects

(2,408)

0.8%

(2,432)

(1.0)%

Tax credits

Marginal well credits

106,319

(35.3)%

91,831

37.0%

Nontaxable or nondeductible items

Other nondeductible items

(244)

0.1%

(906)

(0.3)%

Other adjustments

Other adjustments to deferred taxes

9,358

(3.1)%

(7,164)

(2.8)%

Income tax benefit (expense) / Effective tax rate(a)

$40,550

(13.5)%

$144,845

58.4%

(a)The impact and the presentation of the federal tax credits on our effective tax rate can be positive or negative based on the

Company’s annual pre-tax income or loss.

The effective tax rates for the years ended December 31, 2025 and 2024 were (13.5%) and 58.4%, respectively. The effective tax rates

can be materially impacted by the recognition of the marginal well tax credit available to qualified producers as reflected in our 2025

effective tax rate. The federal government provides these credits to incentivize companies to continue operating lower-output wells

during periods of low prices. This support helps sustain production, preserve the jobs associated with these operations, and ensures

that communities continue to receive state and local tax income. Such revenue is vital for funding schools, law enforcement, social

initiatives, and other essential public services.

State and local income taxes are more than 50% comprised of Oklahoma and West Virginia.

The provision for income taxes in the Consolidated Statement of Operations is summarized below:

For the Year Ended December 31,

(In thousands)

2025

2024

$ Change

% Change

Income (loss) before taxation

$301,349

$(247,938)

$549,287

(222%)

Effective tax rate

(13.5%)

58.4%

Income tax benefit (expense)

$40,550

$144,845

$(104,295)

(72%)

Tax benefit of $41 million for the year ended December 31, 2025 decreased $104 million, or 72%, compared to a benefit of $145

million for the year ended December 31, 2024. The change in this metric was primarily related to the change in the income or loss

before taxation and a change in the effective tax rate.

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Diversified Energy Company

Results of Operations for the Year Ended December 31, 2024 Compared to the Year Ended December 31,

2023

Production Volumes

For the Year Ended December 31,

2024

2023

Change

% Change

Net production

Natural gas (MMcf)

244,298

256,378

(12,080)

(5%)

NGLs (MBbls)

5,980

5,832

148

3%

Oil (MBbls)

1,568

1,377

191

14%

Total production (MMcfe)

289,586

299,632

(10,046)

(3%)

Average daily production (MMcfepd)

791

821

(30)

(4%)

% Natural gas (Mcfe basis)

84%

86%

The decrease in production volumes for the year ended December 31, 2024 compared to the year ended December 31, 2023 was

primarily related to the sale of our equity interest in DP Lion Equity Holdco in December 2023 along with normal declines partially

offset by increased production as a result of the Oaktree, Crescent Pass, and East Texas II acquisitions in 2024.

Commodity Pricing

The following table summarizes our average realized sales prices and benchmark prices for the periods presented:

For the Year Ended December 31,

2024

2023

$ Change

% Change

Average realized sales prices (before derivative settlements)

Natural gas (Mcf)

$1.90

$2.17

$(0.27)

(12%)

NGLs (Bbls)

25.17

24.23

0.94

4%

Oil (Bbls)

74.71

75.46

(0.75)

(1%)

Total (Mcfe)

$2.53

$2.68

$(0.15)

(6%)

Average realized sales prices (after derivative settlements)

Natural gas (Mcf)

$2.57

$2.86

$(0.29)

(10%)

NGLs (Bbls)

24.32

26.05

(1.73)

(7%)

Oil (Bbls)

69.54

68.44

1.10

2%

Total (Mcfe)

$3.05

$3.27

$(0.22)

(7%)

Average benchmark prices

Henry Hub (Mcf)

$2.27

$2.74

$(0.47)

(17%)

Mont Belvieu (Bbls)

38.16

34.11

4.05

12%

WTI (Bbls)

75.72

77.62

(1.90)

(2%)

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Diversified Energy Company

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:

(In thousands)

Natural Gas

NGLs

Oil

Total

Commodity revenue for the year ended December 31, 2023

$557,167

$141,321

$103,911

$802,399

Volume increase (decrease)

(26,214)

3,586

14,413

(8,215)

Price increase (decrease)

(66,353)

5,606

(1,178)

(61,925)

Net increase (decrease)

(92,567)

9,192

13,235

(70,140)

Commodity revenue for the year ended December 31, 2024

$464,600

$150,513

$117,146

$732,259

Commodity revenue of $732 million for the year ended December 31, 2024 decreased $70 million, or 9%, compared to $802 million

for the year ended December 31, 2023. The decrease in commodity revenue was primarily related to the 6% decrease in average

realized sales prices, excluding the impact of derivatives settled in cash, and the 3% decrease in sold volumes.

Commodity Derivatives

As of December 31, 2024, approximately 86% of our production was fixed through derivative hedging contracts over the next twelve

months. The tables below set forth the commodity derivative impact on commodity revenue, excluding and including cash received for

commodity derivative settlements:

For the Year Ended December 31, 2024

Natural Gas

NGLs

Oil

Total Commodity

(In thousands, except per unit

data)

Revenue

Realized $

Revenue

Realized $

Revenue

Realized $

Revenue

Realized $

per Mcf

per Bbl

per Bbl

per Mcfe

Excluding hedge impact

$464,600

$1.90

$150,513

$25.17

$117,146

$74.71

$732,259

$2.53

Commodity hedge impact

164,452

0.67

(5,055)

(0.85)

(8,108)

(5.17)

151,289

0.52

Including hedge impact

$629,052

$2.57

$145,458

$24.32

$109,038

$69.54

$883,548

$3.05

For the Year Ended December 31, 2023

Natural Gas

NGLs

Oil

Total Commodity

(In thousands, except per unit

data)

Revenue

Realized $

Revenue

Realized $

Revenue

Realized $

Revenue

Realized $

per Mcf

per Bbl

per Bbl

per Mcfe

Excluding hedge impact

$557,167

$2.17

$141,321

$24.23

$103,911

$75.46

$802,399

$2.68

Commodity hedge impact

177,139

0.69

10,594

1.82

(9,669)

(7.02)

178,064

0.59

Including hedge impact

$734,306

$2.86

$151,915

$26.05

$94,242

$68.44

$980,463

$3.27

Gain (Loss) on Derivatives

The table below sets for the impact of settlements and fair value adjustments on derivatives for the periods presented:

For the Year Ended December 31,

(In thousands)

2024

2023

$ Change

% Change

Net gain (loss) on commodity derivatives settlements

$151,289

$178,064

$(26,775)

(15%)

Net gain (loss) on interest rate swaps

190

(2,722)

2,912

(107%)

Gain (loss) on foreign currency hedges

—

(521)

521

(100%)

Total gain (loss) on settled derivatives(a)

$151,479

$174,821

$(23,342)

(13%)

Gain (loss) on fair value adjustments of unsettled derivatives(b)

(189,030)

905,695

(1,094,725)

(121%)

Total gain (loss) on derivatives

$(37,551)

$1,080,516

$(1,118,067)

(103%)

(a)Represents the cash settlement of derivatives that settled during the period.

(b)Represents the change in fair value of derivatives net of removing the carrying value of derivatives that settled during the period.

The change in this metric was primarily related to losses of $189 million stemming from fair value adjustments on unsettled

derivatives, which were influenced by an increase along the forward commodity curve. The losses were offset by $151 million in gains

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Diversified Energy Company

incurred from settled derivative contracts, as commodity market prices dropped below the predetermined thresholds set in our

derivative arrangements.

Operating Expenses

For the Year Ended December 31,

(In thousands, except per unit data)

2024

Per

Mcfe

2023

Per

Mcfe

Total Change

Per Mcfe

Change

Lease operating expenses

$231,651

$0.80

$213,078

$0.71

$18,573

9%

$0.09

13%

Production taxes

36,043

0.12

61,474

0.21

(25,431)

(41%)

(0.09)

(43%)

Midstream operating expenses

72,098

0.25

71,307

0.24

791

1%

0.01

4%

Transportation expenses

90,461

0.31

96,218

0.32

(5,757)

(6%)

(0.01)

(3%)

Accretion of asset retirement obligation

28,464

0.10

23,903

0.08

4,561

19%

0.02

25%

General and administrative expense

129,745

0.45

128,626

0.43

1,119

1%

0.02

5%

Depreciation, depletion and amortization

291,995

1.01

273,316

0.91

18,679

7%

0.10

11%

(Gain) loss on oil and gas property and equipment

(26,069)

(0.09)

(28,124)

(0.09)

2,055

(7%)

—

—%

Total operating expenses

$854,388

$2.95

$839,798

$2.81

$14,590

2%

$0.14

5%

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 per Mcfe was primarily related to the Oaktree, Crescent Pass, and East Texas II acquisitions in 2024.

Specifically, these acquisitions resulted in a greater exposure to liquids production, which tend to incur elevated operating costs.

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.

The decrease in production taxes per Mcfe was primarily related to a decrease in severance and property taxes as a result of a decrease

in revenue due to lower production and commodity prices, as well as lower valuations for property taxes experienced during the year.

Midstream Operating Expense: Midstream operating expenses are costs incurred to operate our owned midstream assets inclusive of

employee and benefit expenses.

The increase in midstream operating expense per Mcfe was primarily related to growth in our midstream operations due to Central

Region expansion through the acquisitions of Oaktree, Crescent Pass, and East Texas II.

Transportation Expense: Transportation expenses are costs incurred from third-party systems to gather, process and transport our

natural gas, NGLs and oil.

The decrease in transportation expense per Mcfe was primarily related to decreases in commodity price-linked components of third-

party midstream rates and costs.

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 inclusion of assets from the Oaktree, Crescent Pass, and East Texas II

acquisitions, along with normal declines in production from mature wells.

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.

The increase in G&A per MCFe was primarily related to additional administrative costs and professional services to support our

ongoing growth through acquisitions. Additionally, we also experienced increased costs associated with litigation expense. These

increases were partially offset by a reduction in legal and consulting services.

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Diversified Energy Company

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.

The increase in DD&A was primarily related to an increase in our DD&A rate, which was partially offset by a 3% decrease in

production over the period. The increase in our DD&A rate was due to the decrease in our estimated proved reserves relative to our

depreciable base, driven primarily by changes in commodity prices year-over-year as well as the sale of equity interest in DP Lion

Equity Holdco LLC in December 2023. The decrease in proved reserves was partially offset by the acquisition of the Oaktree,

Crescent Pass, and East Texas II assets in 2024.

Gain (Loss) on Natural Gas and Oil Properties and Equipment: Gains and (losses) on natural gas and oil properties and equipment

represents the difference between cash proceeds and recorded basis of sales of natural gas and oil properties and equipment.

The change in this metric was primarily related to non-core acreage and asset sales. In 2024, we recognized a gain of $27 million from

acreage sales compared to $24 million in 2023. This increase was offset by the disposal of various property, plant and equipment in

the normal course of business, which resulted in a loss on natural gas and oil properties and equipment of $0.9 million in 2024,

compared to a gain of $4.6 million in 2023.

Other Income (Expense)

For the Year Ended December 31,

(In thousands)

2024

2023

$ Change

% Change

Gain (loss) on sale of equity interest

—

11,065

(11,065)

(100%)

Interest expense

(136,801)

(130,859)

(5,942)

5%

Loss on debt extinguishment

(16,377)

—

(16,377)

100%

Other income (expense)

2,338

385

1,953

507%

Total other income (expense)

$(150,840)

$(119,409)

$(31,431)

26%

Gain (Loss) on Sale of Equity Interest

The change in this metric is related to the divestiture of 80% of the equity ownership in DP Lion Equity Holdco LLC to outside

investors, which generated cash proceeds of $30 million. The consideration exceeded the fair value of the Company’s portion of the

assets and liabilities divested resulting in a gain on sale of the equity interest of $11 million.

Interest Expense

For the Year Ended December 31,

(In thousands)

2024

2023

$ Change

% Change

Interest incurred

Borrowings

$138,829

$133,142

$5,687

4%

Other

554

606

(52)

(9%)

Total interest incurred

139,383

133,748

5,635

4%

LESS: Capitalized interest

2,582

2,889

(307)

(11%)

Interest expense

$136,801

$130,859

$5,942

5%

The increase in interest expense was primarily related to interest on the new ABS IX Notes, Oaktree Seller’s Note, and Term Loan II.

The increase was partially offset by lower outstanding balances on our existing ABS structures.

As of December 31, 2024 and 2023, total borrowings were $1.7 billion and $1.3 billion, respectively. For the year ended

December 31, 2024, the weighted average interest rate on borrowings was 7.37% compared to 6.03% for the year ended December 31,

2023. As of December 31, 2024, 83% of our borrowings resided in fixed-rate, hedge-protected, amortizing structures compared to

87% as of December 31, 2023.

Loss on Debt Extinguishment

The change in this metric was primarily related to losses recognized on the early retirement of debt in 2024. During the year, we

repaid the ABS III and ABS V notes using proceeds from new ABS VIII issuance, resulting in a loss of $10.6 million. We also repaid

the ABS Facility Warehouse Notes using proceeds from the ABS IX issuance, resulting in a loss of $1.6 million. Additionally, the

amendment and expansion of Term Loan II led to a further loss of $2.5 million. The amendment to the Credit Facility also resulted in

a loss of $1.6 million

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Diversified Energy Company

Other Income (Expense)

The change in this metric was primarily related to $1.1 million in dividend distributions received from our investment in DP Lion

Equity Holdco during 2024, whereas no such distributions were received in 2023.

Income Tax Benefit (Expense)

The differences between the statutory U.S. federal income tax rate and the effective tax rates are summarized as follows:

For the Year Ended December 31,

(in thousands)

2024

2023

U.S. federal statutory tax rates

$52,067

21.0%

$(207,810)

21.0%

State and local income tax, net of federal (national) income tax effect

9,201

3.7%

(29,698)

3.0%

Foreign tax effects

Statutory tax rate difference between United Kingdom and United States

(3,109)

(1.3)%

(3,270)

0.3%

Equity in earnings of foreign subsidiary

(16,324)

(6.6)%

(27,241)

2.8%

Nontaxable dividend income

21,681

8.7%

32,357

(3.3)%

Tax credits

Marginal well credits

91,831

37.0%

—

—%

Changes in valuation allowances

—

—%

1,504

(0.2)%

Nontaxable or nondeductible items

Other nondeductible items

(906)

(0.3)%

(2,039)

0.3%

Other adjustments

Other adjustments to deferred taxes

(7,164)

(2.8)%

(1,282)

0.1%

Income tax benefit (expense) / Effective tax rate(a)

$144,845

58.4%

$(239,184)

24.2%

(a)The impact and the presentation of the federal tax credits on our effective tax rate can be positive or negative based on the

Company’s annual pre-tax income or loss.

The effective tax rates for the years ended December 31, 2024 and 2023 were 58.4% and 24.2%, respectively. The effective tax rate

can be materially impacted by the recognition of the marginal well tax credit available to qualified producers as reflected in our 2024

effective tax rate. A marginal well tax credit was not available for the 2023 tax year. The federal government provides these credits to

incentivize companies to continue operating lower-output wells during periods of low prices. This support helps sustain production,

preserve the jobs associated with these operations, and ensures that communities continue to receive state and local tax income. Such

revenue is vital for funding schools, law enforcement, social initiatives, and other essential public services.

State and local income taxes are more than 50% comprised of Oklahoma and West Virginia.

The provision for income taxes in the Consolidated Statement of Operations is summarized below:

For the Year Ended December 31,

(In thousands)

2024

2023

$ Change

% Change

Income (loss) before taxation

$(247,938)

$989,573

$(1,237,511)

(125%)

Effective tax rate

58.4%

24.2%

Income tax benefit (expense)

$144,845

$(239,184)

$384,029

(161%)

Tax benefit of $145 million for the year ended December 31, 2024 changed $384 million, or 161%, compared to an expense of $239

million for the year ended December 31, 2024. The change in this metric was primarily related to the change in the income or loss

before taxation and a change in the effective tax rate.

Liquidity and Capital Resources

Overview

Our primary sources of liquidity are cash generated from operating activities and available capacity under our Credit Facility. As of

December 31, 2025, we had approximately $335 million of liquidity, consisting of $30 million of cash on hand and $305 million of

availability under our Credit Facility. As of February 25, 2026 we had approximately $577 million of liquidity, consisting of $31

million of cash on hand and $546 million of availability under our Credit Facility.

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Diversified Energy Company

When we acquire assets, we typically complement our Credit Facility with long-term, fixed-rate, fully-amortizing, asset-backed debt

secured by certain natural gas and oil assets. The asset-backed debt is non-recourse back to the Company. This financing strategy

aligns with the long-life nature of our assets, offering us lower borrowing rates and a clear path to reduce leverage through scheduled

principal payments. For larger acquisitions that require greater capital outlays, we have in the past and may in the future raise funds

through equity offerings to maintain an appropriate leverage profile.

We closely monitor our working capital to ensure it remains sufficient for business operations, as well as for payment of dividends to

shareholders and repurchases of common stock. Alongside managing working capital, we take a disciplined approach to controlling

operating costs and allocating capital resources. This approach ensures that capital investments generate returns that support our

strategic initiatives.

Capital expenditures were $185 million for the year ended December 31, 2025, compared to $52 million for the year ended

December 31, 2024. The increase in capital expenditures was primarily related to the development of new wells via a non-operated

development agreement that came with the undeveloped locations acquired in the Maverick acquisition. We expect to meet our capital

expenditure needs for the foreseeable future from our operating cash flows and our existing cash and cash equivalents. Our future

capital requirements will depend on several factors, including the pace of our growth, fluctuations in commodity prices, and future

acquisitions.

The majority of our capital expenditures are directed towards upstream and midstream operations, including pipelines and

compression. The remaining expenditures focus on production optimization, technology, plugging requirements, fleet, reducing

emissions, and, when prudent, development activities aimed at replacing production. Our strategy to acquire and operate mature wells

with shallow decline rates allows us to avoid the large capital expenditures associated with drilling and completion activities of

development focused companies.

Looking ahead, we aim to create stable cash flows by maintaining our hedging strategy and capitalizing on market opportunities to

enhance the hedged commodity prices of our production. We plan to preserve our strategic advantages through purposeful growth,

supported by a disciplined capital expenditure program. We believe this approach will help ensure we secure low-cost financing for

acquisitive growth while maintaining appropriate leverage and sufficient liquidity.

With respect to other known current obligations, we believe that our sources of liquidity and capital resources will be sufficient to

meet our existing business needs for at least the next 12 months. However, our ability to satisfy our working capital requirements, debt

service obligations, and planned capital expenditures will depend upon our future operating performance, which will be affected by

prevailing economic conditions in the natural gas and oil industry and other financial and business factors, some of which are beyond

our control.

Liquidity

As of December 31,

(In thousands)

2025

2024

2023

Cash and cash equivalents

$29,697

$5,990

$3,753

Available borrowings under the Credit Facility(a)

304,912

86,690

134,817

Liquidity

$334,609

$92,680

$138,570

(a)Represents available borrowings under the Credit Facility of $340 million as of December 31, 2025 less outstanding letters of

credit of $35 million as of such date. Represents available borrowings under the Credit Facility of $101 million as of

December 31, 2024 less outstanding letters of credit of $14 million as of such date. Represents available borrowings under the

Credit Facility of $146 million as of December 31, 2023 less outstanding letters of credit of $11 million as of such date.

Debt

As of December 31, 2025, 2024, and 2023, we had $3.0 billion, $1.7 billion and $1.3 billion in total debt outstanding, respectively.

Asset Retirement Obligations

As of December 31, 2025, 2024, and 2023, we had $864 million, $619 million and $463 million in total asset retirement obligations on

a discounted basis, respectively.

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Diversified Energy Company

Cash Flows

For the Year Ended December 31,

(In thousands)

2025

2024

$ Change

% Change

Net cash provided by operating activities

$464,619

$220,650

$243,969

111%

Net cash (used in) investing activities

(820,168)

(266,762)

(553,406)

207%

Net cash provided by financing activities

448,400

58,366

390,034

668%

Net change in cash, cash equivalents and restricted cash

$92,851

$12,254

$80,597

658%

Net Cash Provided by Operating Activities

The change in net cash provided by operating activities was primarily related to an increase in production, as a result of current year

acquisitions, and higher prices for the natural gas, NGL, and oil volumes sold.

Net Cash (Used in) Investing Activities

The change in net cash used in investing activities was primarily related to the acquisitions of Summit, Maverick, and Canvas in the

current year, in addition to increased drilling capital spend related to participating in the development of certain non-operated wells

acquired with Maverick. These increases were partially offset by increased cash proceeds from the sale of undeveloped acreage.

Net Cash Provided by Financing Activities

The increase in net cash provided by financing activities was primarily related to an increase in ABS activity during the year,

associated with both acquisitions and refinancings, as well as proceeds from the April Nordic Bonds issuance and the February equity

issuance. These increases were partially offset by cash outflows related to hedge modifications associated with the ABS refinancings.

For the Year Ended December 31,

(In thousands)

2024

2023

$ Change

% Change

Net cash provided by operating activities

$220,650

$291,431

$(70,781)

(24%)

Net cash (used in) investing activities

(266,762)

(246,714)

(20,048)

8%

Net cash provided by (used in) financing activities

58,366

(67,440)

125,806

187%

Net change in cash, cash equivalents and restricted cash

$12,254

$(22,723)

$34,977

154%

Net Cash Provided by Operating Activities

The change in net cash provided by operating activities was primarily related to lower prices for the natural gas, NGL, and oil volumes

sold.

Net Cash (Used in) Investing Activities

The change in net cash used in investing activities was primarily related to a net increase in cash outflows for acquisitions, divestitures

and disposal activity, which was partially offset by a decrease in cash outflows for capital expenditures, due to decreased development

activity in 2024.

Net Cash Provided by (Used in) Financing Activities

The increase in net cash provided by (used in) financing activities was primarily related to an increase in ABS activity during the year,

associated with both acquisitions and refinancings, which provided net proceeds. Also contributing to the increase was a reduction in

dividends paid in 2024. Partially offsetting these increases was a decrease in equity proceeds as a result of the 2023 equity issuance.

Off-Balance Sheet Arrangements

We may enter into off-balance sheet arrangements and transactions that give rise to material off-balance sheet obligations. As of

December 31, 2025 and December 31, 2024, our material off-balance sheet arrangements and transactions include operating service

arrangements of $371 million and letters of credit outstanding against our Credit Facility of $35 million. Refer to Contractual

Obligations for additional information.

There are no other transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably

likely to materially affect our liquidity or availability of capital resources.

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Diversified Energy Company

Contractual Obligations

We have various contractual obligations in the normal course of our operations and financing activities. Significant contractual

obligations as of December 31, 2025 were as follows:

(In thousands)

2026

2027

2028

2029

2030

Thereafter

Total

Recorded contractual obligations

Accounts payable

$81,814

$—

$—

$—

$—

$—

$81,814

Accrued liabilities

193,742

—

—

—

—

—

193,742

Borrowings

236,553

217,426

197,691

969,696

253,467

1,110,412

2,985,245

Operating leases

2,191

680

337

344

351

298

4,201

Finance leases

26,560

22,135

17,354

11,922

4,497

272

82,740

Asset retirement obligation(a)

26,476

28,356

25,724

51,076

19,445

3,484,077

3,635,154

Other liabilities(b)

118,477

26,869

—

—

—

—

145,346

Off-Balance Sheet contractual obligations

Firm transportation(c)

58,590

35,432

26,118

20,613

8,358

221,534

370,645

Total contractual obligations

$744,403

$330,898

$267,224

$1,053,651

$286,118

$4,816,593

$7,498,887

(a)Represents our asset retirement obligation on an undiscounted basis. On a discounted basis the liability is $889 million as of

December 31, 2025 as presented in the Consolidated Balance Sheets.

(b)Represents taxes payable, deferred tax liability, and other current and noncurrent liabilities.

(c)Represents reserved capacity to transport gas from production locations through pipelines to the ultimate sales meters.

For more detailed information on asset retirement obligations, leases, debt, accounts payable and accrued liabilities, and other

liabilities, refer to Notes 13, 14, 15, 16, and 17 within the Notes to the Consolidated Financial Statements.

Litigation and Regulatory Proceedings & Environmental Matters

For Information regarding legal proceedings and environmental matters refer to Note 19 to the Notes to the Consolidated Financial

Statements.

Critical Accounting Estimates & Judgments

The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions. The accounting

estimates and assumptions that involve a significant level of estimation uncertainty and have or are reasonably likely to have a

material impact on our financial condition or results of operations are discussed below.

For discussion regarding our significant accounting policies, refer to Note 2 in the Notes to the Consolidated Financial Statements for

additional information regarding our significant accounting policies, estimates, and judgments.

Natural Gas and Oil Reserves

Estimates of proved natural gas and oil reserves are used in calculating DD&A of proved natural gas and oil property costs, the present

value of estimated future net revenues, estimates of future taxable income used in assessing the realizability of deferred tax assets, and

the estimated timing of cash outflows underlying asset retirement obligations. There are numerous uncertainties inherent in the

estimation of proved natural gas and oil reserves and in the projection of future rates of production.

The process of estimating proved natural gas and oil reserves requires that our independent and internal reserve engineers exercise

judgment on the future production rates. The accuracy of any reserve estimate is a function of the quality of data available and of

engineering and geological interpretation and judgment. In addition, estimates of reserves may be revised based on actual production,

results of subsequent exploration and development activities, recent commodity prices, operating costs and other factors. These

revisions could materially affect our financial statements. The volatility of commodity prices results in increased uncertainty inherent

in these estimates and assumptions. Changes in natural gas, oil or NGL prices could result in actual results differing significantly from

our estimates. See Supplemental Natural Gas & Oil Information included in Item 8 of Part II of this report for further information.

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Impairment of Proved Properties

We assess our proved natural gas and oil properties for impairment on an asset group basis whenever events and circumstances

indicate that there could be a possible decline in the recoverability of the net book value of such property. We estimate the expected

future net cash flows of our proved natural gas and oil properties and compare these undiscounted cash flows to the net book value of

the proved natural gas and oil properties to determine if the net book value is recoverable. If the net book value exceeds the estimated

undiscounted future net cash flows, we will recognize an impairment to reduce the net book value of the proved natural gas and oil

properties to fair value. The assumptions used to determine fair value include, but are not limited to, future commodity prices, future

production estimates, operating costs, and discount rates, which are based on a weighted average cost of capital. Fair value estimates

are based on projected financial information which we believe to be reasonably likely to occur, as of the date that the impairment is

measured.

Business Combinations

We account for business combinations using the acquisition method, which is the only method permitted under FASB ASC Topic 805,

Business Combinations and involves the use of significant judgment. Under the acquisition method of accounting, a business

combination is accounted for at a purchase price based on the fair value of the consideration given. The assets and liabilities acquired

are measured at their fair values, and the purchase price is allocated to the assets and liabilities based upon these fair values. The

excess, if any, of the consideration given to acquire an entity over the net amounts assigned to its assets acquired and liabilities

assumed is recognized as goodwill. The excess, if any, of the fair value of assets acquired and liabilities assumed over the cost of an

acquired entity is recognized immediately to earnings as a gain on bargain purchase.

The Company’s principal assets are its natural gas and oil properties, which are accounted for under the successful efforts accounting

method. The Company determines the fair value of acquired proved natural gas and oil properties based on the discounted future net

cash flows expected to be generated from these assets. Discounted cash flow models by operating area are prepared using the

estimated future revenues and operating costs for all proved developed properties and undeveloped properties comprising the proved

reserves. Significant inputs associated with the calculation of discounted future net cash flows include estimates of (i) future

production volumes based on estimated reserves, (ii) future operating and development costs, (iii) future commodity prices escalated

by an inflationary rate after five years, adjusted for differentials, and (iv) a market-based weighted average cost of capital by operating

area. The Company utilizes NYMEX strip pricing, adjusted for differentials, to value the reserves. The NYMEX strip pricing inputs

used are classified as Level 1 fair value assumptions and all other inputs are classified as Level 3 fair value assumptions. The discount

rates utilized are derived using a weighted average cost of capital computation, which includes an estimated cost of debt and equity for

market participants with similar geographies and asset development type by operating area. Additionally, the fair value of unproved oil

and gas properties is determined using a market approach, which considers recent comparable transactions for similar assets. More

information regarding conclusions reached with respect to this judgment is included in Note 2 to the Notes to the Consolidated

Financial Statements.

Income Taxes

The amount of income taxes recorded requires interpretations of complex rules and regulations of federal and state tax jurisdictions.

We recognize current tax expense based on estimated taxable income for the current period and the applicable statutory tax rates. We

routinely assess potential uncertain tax positions and, if required, estimate and establish accruals for such amounts. We have

recognized deferred tax assets and liabilities for temporary differences, operating losses and other tax carryforwards. In assessing the

need for a valuation allowance or adjustments to existing valuation allowances, we consider a variety of positive and negative

evidence, which may include a projection of income exclusive of existing timing differences. Our judgment regarding the realizability

of deferred tax assets is thus partially affected by estimates of future financial results.

Management monitors company-specific, natural gas and oil industry and worldwide economic factors and assesses the likelihood that

our net deferred tax assets will be utilized prior to their expiration. Refer to Note 4 in the Notes to the Consolidated Financial

Statements for additional discussion.

Asset Retirement Obligations

We accrue a liability for asset retirement obligations based on an estimate of the amount and timing of settlement. For oil and gas

wells, the fair value of our plugging and abandonment obligations is recorded at the time the obligation is incurred, which is typically

at the time the well is drilled.

Calculating our asset retirement obligations is a "critical accounting estimate" because we must assess the expected amount and timing

of asset retirement obligation settlement. In addition, we must determine the estimated present value of future liabilities. Future results

of operations for any quarterly or annual period could be materially affected by changes in our assumptions. If the expected amount

and timing of our asset retirement obligations change, we will be required to adjust the carrying value of our liabilities in future

periods. An estimate of the sensitivity to changes in our assumptions is not practicable given the numerous assumptions that can

materially affect our estimates. Refer to Note 13 in the Notes to the Consolidated Financial Statements for additional discussion.

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Recently Issued Accounting Pronouncements

Refer to Note 2 in the Notes to the Consolidated Financial Statements for information regarding recent accounting pronouncements

applicable to our Consolidated Financial Statements.