Diversified Energy Co PLC

(Unaudited)

(AMOUNTS IN THOUSANDS, EXCEPT PER SHARE AND

PER UNIT DATA)

We use APMs to improve the comparability of information

between reporting periods and to more accurately evaluate

cash flows, either by adjusting for uncontrollable or

transactional factors that are not comparable period-over-

period, or by aggregating measures, to aid the users of this

Annual Report & Form 20-F in understanding the activity

taking place across the Group. APMs are used by the

Directors for planning and reporting and should not be

considered an IFRS replacement. The measures are also

used in discussions with the investment analyst community

and credit rating agencies.

Adjusted EBITDA

As used herein, EBITDA represents earnings before interest, taxes, depletion, depreciation and amortization. adjusted EBITDA

includes adjusting for items that are not comparable period-over-period, namely, accretion of asset retirement obligation,

other (income) expense, loss on joint and working interest owners receivable, (gain) loss on bargain purchases, (gain) loss on

fair value adjustments of unsettled financial instruments, (gain) loss on natural gas and oil property and equipment, costs

associated with acquisitions, other adjusting costs, non-cash equity compensation, (gain) loss on foreign currency hedge, net

(gain) loss on interest rate swaps and items of a similar nature.

Adjusted EBITDA should not be considered in isolation or as a substitute for operating profit or loss, net income or loss, or

cash flows provided by operating, investing and financing activities. However, we believe such measure is useful to an investor

in evaluating our financial performance because it (1) is widely used by investors in the natural gas and oil industry as an

indicator of underlying business performance; (2) helps investors to more meaningfully evaluate and compare the results of

our operations from period to period by removing the often-volatile revenue impact of changes in the fair value of derivative

instruments prior to settlement; (3) is used in the calculation of a key metric in one of our Credit Facility financial covenants;

and (4) is used by us as a performance measure in determining executive compensation. When evaluating this measure, we

believe investors also commonly find it useful to evaluate this metric as a percentage of our total revenue, inclusive of settled

hedges, producing what we refer to as our adjusted EBITDA margin.

(a)Excludes$24.2 million and$2 million in proceeds received for leasehold sales during the years ended December 31, 2023 and 2022.

(b)Other adjusting costs for theyear ended December 31, 2023 were primarily associated with legal and professional fees related to the U.S.

listing, legal fees for certain litigation, and expenses associated with unused firm transportation agreements. Other adjusting costs for the

year ended December 31, 2022 primarily consisted of$28 million in contract terminations which may allow the Group to obtain more

favorable pricing in the future and$31 million in costs associated with deal breakage and/or sourcing costs for acquisitions.

Net Debt

As used herein, net debt represents total debt as recognized on the balance sheet less cash and restricted cash. Total debt

includes our borrowings under the Credit Facility and borrowings under or issuances of, as applicable, our subsidiaries’

securitization facilities. We believe net debt is a useful indicator of our leverage and capital structure.

Net Debt-to-Adjusted EBITDA

As used herein, net debt-to-adjusted EBITDA, or “leverage” or “leverage ratio,” is measured as net debt divided by adjusted

EBITDA. We believe that this metric is a key measure of our financial liquidity and flexibility and is used in the calculation of a

key metric in one of our Credit Facility financial covenants.

(a)Pro forma adjusted EBITDA includes adjustments for theyear ended December 31, 2023 for the Tanos II Acquisition to pro forma its results

for the full twelve months of operations. Similar adjustments were made for theyear ended December 31, 2022 for the East Texas Assets and

ConocoPhillips acquisitions.

(b)Does not include adjustments for working capital which are often customary in the market.

Total Revenue, Inclusive of Settled Hedges

As used herein, total revenue, inclusive of settled hedges, includes the impact of derivatives settled in cash. We believe that

total revenue, inclusive of settled hedges is a useful because it enables investors to discern our realized revenue after adjusting

for the settlement of derivative contracts.

Adjusted EBITDA Margin

As used herein, adjusted EBITDA margin is measured as adjusted EBITDA, as a percentage of total revenue, inclusive of settled

hedges. adjusted EBITDA margin includes the direct operating cost and the portion of general and administrative cost it takes

to produce each Mcfe. This metric includes operating expense, employees, administrative costs and professional services and

recurring allowance for credit losses, which include fixed and variable costs components. We believe that adjusted EBITDA

margin is a useful measure of our profitability and efficiency as well as our earnings quality because it measures the Group on a

more comparable basis period-over-period, given we are often involved in transactions that are not comparable

between periods.

(a)Net gain (loss) on commodity derivative settlements represents cash (paid) or received on commodity derivative contracts. This excludes

settlements on foreign currency and interest rate derivatives as well as the gain (loss) on fair value adjustments for unsettled financial

instruments for each of the periods presented.

Free Cash Flow

As used herein, free cash flow represents net cash provided by operating activities less expenditures on natural gas and oil

properties and equipment and cash paid for interest. We believe that free cash flow is a useful indicator of our ability to

generate cash that is available for activities other than capital expenditures. The Directors believe that free cash flow provides

investors with an important perspective on the cash available to service debt obligations, make strategic acquisitions and

investments and pay dividends.

Adjusted Operating Cost per Mcfe

Adjusted operating cost per Mcfe is a metric that allows us to measure the direct operating cost and the portion of general

and administrative cost it takes to produce each Mcfe. This metric, similar to adjusted EBITDA margin, includes operating

expense employees, administrative costs and professional services and recurring allowance for credit losses, which include

fixed and variable cost components.

Employees, administrative costs and professional services

As used herein, employees, administrative costs and professional services represents total administrative expenses excluding

cost associated with acquisitions, other adjusting costs and non-cash expenses. We use employees, administrative costs and

professional services because this measure excludes items that affect the comparability of results or that are not indicative of

trends in the ongoing business.

PV-10

PV-10 is a non-IFRS measure because it excludes the effects of applicable income tax. The Directors believe that the

presentation of the non-IFRS financial measure of PV-10 provides useful information to investors because it is widely used by

professional analysts and sophisticated investors in evaluating natural gas and oil companies. PV-10 is not a measure of

financial or operating performance under IFRS. PV-10 should not be considered as an alternative to the standardized measure

as defined under IFRS. Refer to Supplemental Natural Gas and Oil Information for a reconciliation of PV-10 to the

standardized measure of discounted future net cash flows, its most directly comparable IFRS measure. PV-10 differs from the

standardized measure of discounted future net cash flows because it does not include the effects of income taxes. Neither

PV-10 nor the standardized measure represents an estimate of fair market value of our natural gas and oil properties.

(a)Our estimated net proved reserves were determined using average first-day-of-the-month prices for the prior 12 months in accordance with

SEC guidance. For natural gas volumes, the average Henry Hub spot price of$2.64,$6.36 and$3.60 per MMBtu as of December 31, 2023,

2022 and 2021, respectively, was adjusted for gravity, quality, local conditions, gathering and transportation fees, and distance from market.

For NGLs and oil volumes, the average WTI price of$78.21,$94.14 and$66.55 per Bbl as of December 31, 2023,2022 and 2021, respectively,

was similarly adjusted for gravity, quality, local conditions, gathering and transportation, fees and distance from market. All prices are held

constant throughout the lives of the properties.

(b)The PV-10 of our proved reserves as of December 31, 2023,2022 and 2021 was prepared without giving effect to taxes or hedges. PV-10 is a

non-GAAP and non-IFRS financial measure and generally differs from Standardized Measure, the most directly comparable GAAP measure,

because it does not include the effects of income taxes on future net cash flows. We believe that the presentation of PV-10 is relevant and

useful to our investors as supplemental disclosure to the Standardized Measure because it presents the discounted future net cash flows

attributable to our reserves prior to taking into account future corporate income taxes and our current tax structure. While the Standardized

Measure is free cash dependent on the unique tax situation of each company, PV-10 is based on a pricing methodology and discount factors

that are consistent for all companies. Because of this, PV-10 can be used within the industry and by creditors and securities analysts to

evaluate estimated net cash flows from proved reserves on a more comparable basis. Investors should be cautioned that neither PV-10 nor

the Standardized Measure represents an estimate of the fair market value of our proved reserves.